[Federal Register Volume 74, Number 68 (Friday, April 10, 2009)]
[Proposed Rules]
[Pages 16448-16731]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-5711]
[[Page 16447]]
-----------------------------------------------------------------------
Part II
Environmental Protection Agency
-----------------------------------------------------------------------
40 CFR Parts 86, 87, 89, et al.
Mandatory Reporting of Greenhouse Gases; Proposed Rule
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 /
Proposed Rules
[[Page 16448]]
-----------------------------------------------------------------------
ENVIRONMENTAL PROTECTION AGENCY
40 CFR Parts 86, 87, 89, 90, 94, 98, 600, 1033, 1039, 1042, 1045,
1048, 1051, 1054, and 1065
[EPA-HQ-OAR-2008-0508; FRL-8782-1]
RIN 2060-A079
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed rule.
-----------------------------------------------------------------------
SUMMARY: EPA is proposing a regulation to require reporting of
greenhouse gas emissions from all sectors of the economy. The rule
would apply to fossil fuel suppliers and industrial gas suppliers, as
well as to direct greenhouse gas emitters. The proposed rule does not
require control of greenhouse gases, rather it requires only that
sources above certain threshold levels monitor and report emissions.
DATES: Comments must be received on or before June 9, 2009. There will
be two public hearings. One hearing was held on April 6 and 7, 2009, in
the Washington, DC, area (One Potomac Yard, 2777 S. Crystal Drive,
Arlington, VA 22202). One hearing will be on April 16, 2009 in
Sacramento, CA (Sacramento Convention Center, 1400 J Street,
Sacramento, CA 95814). The April 16, 2009 hearing will begin at 9 a.m.
local time.
ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2008-0508, by one of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: [email protected].
Fax: (202) 566-1741.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mailcode 6102T, Attention Docket ID No. EPA-HQ-OAR-2008-0508,
1200 Pennsylvania Avenue, NW., Washington, DC 20460.
Hand Delivery: EPA Docket Center, Public Reading Room, EPA
West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC
20004. Such deliveries are only accepted during the Docket's normal
hours of operation, and special arrangements should be made for
deliveries of boxed information.
Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2008-0508. EPA's policy is that all comments received will be included
in the public docket without change and may be made available online at
http://www.regulations.gov, including any personal information
provided, unless the comment includes information claimed to be CBI or
other information whose disclosure is restricted by statute. Do not
submit information that you consider to be CBI or otherwise protected
through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site is an ``anonymous access'' system, which
means EPA will not know your identity or contact information unless you
provide it in the body of your comment. If you send an e-mail comment
directly to EPA without going through http://www.regulations.gov your
e-mail address will be automatically captured and included as part of
the comment that is placed in the public docket and made available on
the Internet. If you submit an electronic comment, EPA recommends that
you include your name and other contact information in the body of your
comment and with any disk or CD-ROM you submit. If EPA cannot read your
comment due to technical difficulties and cannot contact you for
clarification, EPA may not be able to consider your comment. Electronic
files should avoid the use of special characters, any form of
encryption, and be free of any defects or viruses.
Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some
information is not publicly available, e.g., CBI or other information
whose disclosure is restricted by statute. Certain other material, such
as copyrighted material, will be publicly available only in hard copy.
Publicly available docket materials are available either electronically
in http://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC.
This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday
through Friday, excluding legal holidays. The telephone number for the
Public Reading Room is (202) 566-1744, and the telephone number for the
Air Docket is (202) 566-1742.
FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division,
Office of Atmospheric Programs (MC-6207J), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address:
[email protected]. For technical information, contact the
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: [email protected]. To obtain information about the public
hearings or to register to speak at the hearings, please go to http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively,
contact Carole Cook at 202-343-9263.
SUPPLEMENTARY INFORMATION:
Additional Information on Submitting Comments: To expedite review
of your comments by Agency staff, you are encouraged to send a separate
copy of your comments, in addition to the copy you submit to the
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC,
20460, telephone (202) 343-9263, e-mail [email protected].
Regulated Entities. The Administrator determines that this action
is subject to the provisions of CAA section 307(d). See CAA section
307(d)(1)(V) (the provisions of section 307(d) apply to ``such other
actions as the Administrator may determine.''). This is a proposed
regulation. If finalized, these regulations would affect owners and
operators of fuel and chemicals suppliers, direct emitters of GHGs and
manufacturers of mobile sources and engines. Regulated categories and
entities would include those listed in Table 1 of this preamble:
Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
Examples of affected
Category NAICS facilities
------------------------------------------------------------------------
General Stationary Fuel .............. Facilities operating
Combustion Sources. boilers, process
heaters, incinerators,
turbines, and internal
combustion engines:
211 Extractors of crude
petroleum and natural
gas.
321 Manufacturers of lumber
and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries,
and manufacturers of
coal products.
[[Page 16449]]
316, 326, 339 Manufacturers of rubber
and miscellaneous
plastic products.
331 Steel works, blast
furnaces.
332 Electroplating,
plating, polishing,
anodizing, and
coloring.
336 Manufacturers of motor
vehicle parts and
accessories.
221 Electric, gas, and
sanitary services.
622 Health services.
611 Educational services.
Electricity Generation......... 221112 Fossil-fuel fired
electric generating
units, including units
owned by Federal and
municipal governments
and units located in
Indian Country.
Adipic Acid Production......... 325199 Adipic acid
manufacturing
facilities.
Aluminum Production............ 331312 Primary Aluminum
production facilities.
Ammonia Manufacturing.......... 325311 Anhydrous and aqueous
ammonia manufacturing
facilities.
Cement Production.............. 327310 Owners and operators of
Portland Cement
manufacturing plants.
Electronics Manufacturing...... 334111 Microcomputers
manufacturing
facilities.
334413 Semiconductor,
photovoltaic (solid-
state) device
manufacturing
facilities.
334419 LCD unit screens
manufacturing
facilities.
.............. MEMS manufacturing
facilities.
Ethanol Production............. 325193 Ethyl alcohol
manufacturing
facilities.
Ferroalloy Production.......... 331112 Ferroalloys
manufacturing
facilities.
Fluorinated GHG Production..... 325120 Industrial gases
manufacturing
facilities.
Food Processing................ 311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
Glass Production............... 327211 Flat glass
manufacturing
facilities.
327213 Glass container
manufacturing
facilities.
327212 Other pressed and blown
glass and glassware
manufacturing
facilities.
HCFC-22 Production and HFC-23 325120 Chlorodifluoromethane
Destruction. manufacturing
facilities.
Hydrogen Production............ 325120 Hydrogen manufacturing
facilities.
Iron and Steel Production...... 331111 Integrated iron and
steel mills, steel
companies, sinter
plants, blast
furnaces, basic oxygen
process furnace shops.
Lead Production................ 331419 Primary lead smelting
and refining
facilities.
331492 Secondary lead smelting
and refining
facilities.
Lime Production................ 327410 Calcium oxide, calcium
hydroxide, dolomitic
hydrates manufacturing
facilities.
Magnesium Production........... 331419 Primary refiners of
nonferrous metals by
electrolytic methods.
331492 Secondary magnesium
processing plants.
Nitric Acid Production......... 325311 Nitric acid
manufacturing
facilities.
Oil and Natural Gas Systems.... 486210 Pipeline transportation
of natural gas.
221210 Natural gas
distribution
facilities.
325212 Synthetic rubber
manufacturing
facilities.
Petrochemical Production....... 32511 Ethylene dichloride
manufacturing
facilities.
325199 Acrylonitrile, ethylene
oxide, methanol
manufacturing
facilities.
325110 Ethylene manufacturing
facilities.
325182 Carbon black
manufacturing
facilities.
Petroleum Refineries........... 324110 Petroleum refineries.
Phosphoric Acid Production..... 325312 Phosphoric acid
manufacturing
facilities.
Pulp and Paper Manufacturing... 322110 Pulp mills.
322121 Paper mills.
322130 Paperboard mills.
Silicon Carbide Production..... 327910 Silicon carbide
abrasives
manufacturing
facilities.
Soda Ash Manufacturing......... 325181 Alkalies and chlorine
manufacturing
facilities.
Sulfur Hexafluoride (SF6) from 221121 Electric bulk power
Electrical Equipment. transmission and
control facilities.
Titanium Dioxide Production.... 325188 Titanium dioxide
manufacturing
facilities.
Underground Coal Mines......... 212113 Underground anthracite
coal mining
operations.
212112 Underground bituminous
coal mining
operations.
Zinc Production................ 331419 Primary zinc refining
facilities.
331492 Zinc dust reclaiming
facilities, recovering
from scrap and/or
alloying purchased
metals.
Landfills...................... 562212 Solid waste landfills.
221320 Sewage treatment
facilities.
322110 Pulp mills.
322121 Paper mills.
322122 Newsprint mills.
322130 Paperboard mills.
311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
Wastewater Treatment........... 322110 Pulp mills.
322121 Paper mills.
322122 Newsprint mills.
322130 Paperboard mills.
[[Page 16450]]
311611 Meat processing
facilities.
311411 Frozen fruit, juice,
and vegetable
manufacturing
facilities.
311421 Fruit and vegetable
canning facilities.
325193 Ethanol manufacturing
facilities.
324110 Petroleum refineries.
Manure Management.............. 112111 Beef cattle feedlots.
112120 Dairy cattle and milk
production facilities.
112210 Hog and pig farms.
112310 Chicken egg production
facilities.
112330 Turkey Production.
112320 Broilers and Other Meat
type Chicken
Production.
Suppliers of Coal and Coal- 212111 Bituminous, and lignite
based Products. coal surface mining
facilities.
212113 Anthracite coal mining
facilities.
212112 Underground bituminous
coal mining
facilities.
Suppliers of Coal Based Liquids 211111 Coal liquefaction at
Fuels. mine sites.
Suppliers of Petroleum Products 324110 Petroleum refineries.
Suppliers of Natural Gas and 221210 Natural gas
NGLs. distribution
facilities.
211112 Natural gas liquid
extraction facilities.
Suppliers of Industrial GHGs... 325120 Industrial gas
manufacturing
facilities.
Suppliers of Carbon Dioxide 325120 Industrial gas
(CO2). manufacturing
facilities.
Mobile Sources................. 336112 Light-duty vehicles and
trucks manufacturing
facilities.
333618 Heavy-duty, non-road,
aircraft, locomotive,
and marine diesel
engine manufacturing.
336120 Heavy-duty vehicle
manufacturing
facilities.
336312 Small non-road, and
marine spark-ignition
engine manufacturing
facilities.
336999 Personal watercraft
manufacturing
facilities.
336991 Motorcycle
manufacturing
facilities.
------------------------------------------------------------------------
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
regulated by this action. Table 1 of this preamble lists the types of
facilities that EPA is now aware could be potentially affected by this
action. Other types of facilities not listed in the table could also be
subject to reporting requirements. To determine whether your facility
is affected by this action, you should carefully examine the
applicability criteria found in proposed 40 CFR part 98, subpart A. If
you have questions regarding the applicability of this action to a
particular facility, consult the person listed in the preceding FOR
FURTHER INFORMATION CONTACT section.
Many facilities that would be affected by the proposed rule have
GHG emissions from multiple source categories listed in Table 1 of this
preamble. Table 2 of this preamble has been developed as a guide to
help potential reporters subject to the mandatory reporting rule
identify the source categories (by subpart) that they may need to (1)
consider in their facility applicability determination, and (2) include
in their reporting. For each source category, activity, or facility
type (e.g., electricity generation, aluminum production), Table 2 of
this preamble identifies the subparts that are likely to be relevant.
The table should only be seen as a guide. Additional subparts may be
relevant for a given reporter. Similarly, not all listed subparts would
be relevant for all reporters.
Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
Source category (and main applicable Subparts recommended for review
subpart) to determine applicability
------------------------------------------------------------------------
General Stationary Fuel Combustion General Stationary Fuel
Sources. Combustion.
Electricity Generation................. General Stationary Fuel
Combustion, Electricity
Generation, Suppliers of CO2,
Electric Power Systems.
Adipic Acid Production................. Adipic Acid Production, General
Stationary Fuel Combustion.
Aluminum Production.................... General Stationary Fuel
Combustion.
Ammonia Manufacturing.................. General Stationary Fuel
Combustion, Hydrogen, Nitric
Acid, Petroleum Refineries,
Suppliers of CO2.
Cement Production...................... General Stationary Fuel
Combustion, Suppliers of CO2.
Electronics Manufacturing.............. General Stationary Fuel
Combustion.
Ethanol Production..................... General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Ferroalloy Production.................. General Stationary Fuel
Combustion.
Fluorinated GHG Production............. General Stationary Fuel
Combustion.
Food Processing........................ General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Glass Production....................... General Stationary Fuel
Combustion.
HCFC-22 Production and HFC-23 General Stationary Fuel
Destruction. Combustion.
Hydrogen Production.................... General Stationary Fuel
Combustion, Petrochemicals,
Petroleum Refineries,
Suppliers of Industrial GHGs,
Suppliers of CO2.
Iron and Steel Production.............. General Stationary Fuel
Combustion, Suppliers of CO2.
Lead Production........................ General Stationary Fuel
Combustion.
Lime Manufacturing..................... General Stationary Fuel
Combustion.
[[Page 16451]]
Magnesium Production................... General Stationary Fuel
Combustion.
Nitric Acid Production................. General Stationary Fuel
Combustion, Adipic Acid.
Oil and Natural Gas Systems............ General Stationary Fuel
Combustion, Petroleum
Refineries, Suppliers of
Petroleum Products, Suppliers
of Natural Gas and NGL,
Suppliers of CO2.
Petrochemical Production............... General Stationary Fuel
Combustion, Ammonia, Petroleum
Refineries.
Petroleum Refineries................... General Stationary Fuel
Combustion, Hydrogen,
Landfills, Wastewater
Treatment, Suppliers of
Petroleum Products.
Phosphoric Acid Production............. General Stationary Fuel
Combustion.
Pulp and Paper Manufacturing........... General Stationary Fuel
Combustion, Landfills,
Wastewater Treatment.
Silicon Carbide Production............. General Stationary Fuel
Combustion.
Soda Ash Manufacturing................. General Stationary Fuel
Combustion.
Sulfur Hexafluoride (SF6) from General Stationary Fuel
Electrical Equipment. Combustion.
Titanium Dioxide Production............ General Stationary Fuel
Combustion.
Underground Coal Mines................. General Stationary Fuel
Combustion, Suppliers of Coal.
Zinc Production........................ General Stationary Fuel
Combustion.
Landfills.............................. General Stationary Fuel
Combustion, Ethanol, Food
Processing, Petroleum
Refineries, Pulp and Paper.
Wastewater Treatment................... General Stationary Fuel
Combustion, Ethanol, Food
Processing, Petroleum
Refineries, Pulp and Paper.
Manure Management...................... General Stationary Fuel
Combustion.
Suppliers of Coal...................... General Stationary Fuel
Combustion, Underground Coal
Mines.
Suppliers of Coal-based Liquid Fuels... Suppliers of Coal, Suppliers of
Petroleum Products.
Suppliers of Petroleum Products........ General Stationary Fuel
Combustion, Oil and Natural
Gas Systems.
Suppliers of Natural Gas and NGLs...... General Stationary Fuel
Combustion, Oil and Natural
Gas Systems, Suppliers of CO2.
Suppliers of Industrial GHGs........... General Stationary Fuel
Combustion, Hydrogen
Production, Suppliers of CO2.
Suppliers of Carbon Dioxide (CO2)...... General Stationary Fuel
Combustion, Electricity
Generation, Ammonia, Cement,
Hydrogen, Iron and Steel,
Suppliers of Industrial GHGs.
Mobile Sources......................... General Stationary Fuel
Combustion.
------------------------------------------------------------------------
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
A/C air conditioning
AERR Air Emissions Reporting Rule
ANPR advance notice of proposed rulemaking
ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BLS Bureau of Labor Statistics
CAA Clean Air Act
CAFE Corporate Average Fuel Economy
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CDX central data exchange
CEMS continuous emission monitoring system(s)
CERR Consolidated Emissions Reporting Rule
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CHP combined heat and power
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DE destruction efficiency
DOD U.S. Department of Defense
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
DE destruction efficiency
DRE destruction or removal efficiency
ECOS Environmental Council of the States
EGUs electrical generating units
EIA Energy Information Administration
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EU European Union
FTP Federal Test Procedure
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC-22 chlorodifluoromethane (or CHClF2)
HCFCs hydrochlorofluorocarbons
HCl hydrogen chloride
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
ISO International Organization for Standardization
kg kilograms
LandGEM Landfill Gas Emissions Model
LCD liquid crystal display
LDCs local natural gas distribution companies
LEDs light emitting diodes
LNG liquified natural gas
LPG liquified petroleum gas
MEMS microelectricomechanical system
mmBtu/hr millions British thermal units per hour
MMTCO2e million metric tons carbon dioxide equivalent
MSHA Mine Safety and Health Administration
MSW municipal solid waste
MW megawatts
N2O nitrous oxide
NAAQS national ambient air quality standard
NACAA National Association of Clean Air Agencies
NAICS North American Industry Classification System
NEI National Emissions Inventory
NESHAP national emission standards for hazardous air pollutants
NF3 nitrogen trifluoride
NGLs natural gas liquids
NIOSH National Institute for Occupational Safety and Health
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act of 1995
O3 ozone
ODS ozone-depleting substance(s)
OMB Office of Management and Budget
ORIS Office of Regulatory Information Systems
PFCs perfluorocarbons
PIN personal identification number
POTWs publicly owned treatment works
PSD Prevention of Significant Deterioration
PV photovoltaic
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
RFA Regulatory Flexibility Act
RFS Renewable Fuel Standard
RGGI Regional Greenhouse Gas Initiative
[[Page 16452]]
RIA regulatory impact analysis
SAE Society of Automotive Engineers
SAR IPCC Second Assessment Report
SBREFA Small Business Regulatory Enforcement Fairness Act
SF6 sulfur hexafluoride
SFTP Supplemental Federal Test Procedure
SI international system of units
SIP State Implementation Plan
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TOC total organic carbon
TRI Toxic Release Inventory
TSCA Toxics Substances Control Act
TSD technical support document
U.S. United States
UIC underground injection control
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
USDA U.S. Department of Agriculture
USGS U.S. Geological Survey
VMT vehicle miles traveled
VOC volatile organic compound(s)
WBCSD World Business Council for Sustainable Development
WCI Western Climate Initiative
WRI World Resources Institute
XML eXtensible Markup Language
Table of Contents
I. Background
A. What Are GHGs?
B. What Is Climate Change?
C. Statutory Authority
D. Inventory of U.S. GHG Emissions and Sinks
E. How does this proposal relate to U.S. government and other
climate change efforts?
F. How does this proposal relate to EPA's Climate Change ANPR?
G. How was this proposed rule developed?
II. Summary of Existing Federal, State, and Regional Emission
Reporting Programs
A. Federal Voluntary GHG Programs
B. Federal Mandatory Reporting Programs
C. EPA Emissions Inventories
D. Regional and State Voluntary Programs for GHG Emissions
Reporting
E. State and Regional Mandatory Programs for GHG Emissions
Reporting and Reduction
F. How the Proposed Mandatory GHG Reporting Program is Different
From the Federal and State Programs EPA Reviewed
III. Summary of the General Requirements of the Proposed Rule
A. Who must report?
B. Schedule for Reporting
C. What do I have to report?
D. How do I submit the report?
E. What records must I retain?
IV. Rationale for the General Reporting, Recordkeeping and
Verification Requirements That Apply to All Source Categories
A. Rationale for Selection of GHGs To Report
B. Rationale for Selection of Source Categories To Report
C. Rationale for Selection of Thresholds
D. Rationale for Selection of Level of Reporting
E. Rationale for Selecting the Reporting Year
F. Rationale for Selecting the Frequency of Reporting
G. Rationale for the Emissions Information to Report
H. Rationale for Monitoring Requirements
I. Rationale for Selecting the Recordkeeping Requirements
J. Rationale for Verification Requirements
K. Rationale for Selection of Duration of the Program
V. Rationale for the Reporting, Recordkeeping and Verification
Requirements for Specific Source Categories
A. Overview of Reporting for Specific Source Categories
B. Electricity Purchases
C. General Stationary Fuel Combustion Sources
D. Electricity Generation
E. Adipic Acid Production
F. Aluminum Production
G. Ammonia Manufacturing
H. Cement Production
I. Electronics Manufacturing
J. Ethanol Production
K. Ferroalloy Production
L. Fluorinated GHG Production
M. Food Processing
N. Glass Production
O. HCFC-22 Production and HFC-23 Destruction
P. Hydrogen Production
Q. Iron and Steel Production
R. Lead Production
S. Lime Manufacturing
T. Magnesium Production
U. Miscellaneous Uses of Carbonates
V. Nitric Acid Production
W. Oil and Natural Gas Systems
X. Petrochemical Production
Y. Petroleum Refineries
Z. Phosphoric Acid Production
AA. Pulp and Paper Manufacturing
BB. Silicon Carbide Production
CC. Soda Ash Manufacturing
DD. Sulfur Hexafluoride (SF6) from Electrical
Equipment
EE. Titanium Dioxide Production
FF. Underground Coal Mines
GG. Zinc Production
HH. Landfills
II. Wastewater Treatment
JJ. Manure Management
KK. Suppliers of Coal
LL. Suppliers of Coal-Based Liquid Fuels
MM. Suppliers of Petroleum Products
NN. Suppliers of Natural Gas and Natural Gas Liquids
OO. Suppliers of Industrial GHGs
PP. Suppliers of Carbon Dioxide (CO2)
QQ. Mobile Sources
VI. Collection, Management, and Dissemination of GHG Emissions Data
A. Purpose
B. Data Collection
C. Data Management
D. Data Dissemination
VII. Compliance and Enforcement
A. Compliance Assistance
B. Role of the States
C. Enforcement
VIII. Economic Impacts of the Proposed Rule
A. How are compliance costs estimated?
B. What are the costs of this proposed rule?
C. What are the economic impacts of the proposed rule?
D. What are the impacts of the proposed rule on small entities?
E. What are the benefits of the proposed rule for society?
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
B. Paperwork Reduction Act
C. Regulatory Flexibility Act (RFA)
D. Unfunded Mandates Reform Act (UMRA)
E. Executive Order 13132: Federalism
F. Executive Order 13175: Consultation and Coordination With
Indian Tribal Governments
G. Executive Order 13045: Protection of Children From
Environmental Health Risks and Safety Risks
H. Executive Order 13211: Actions That Significantly Affect
Energy Supply, Distribution, or Use
I. National Technology Transfer and Advancement Act
J. Executive Order 12898: Federal Actions To Address
Environmental Justice in Minority Populations and Low-Income
Populations
I. Background
The proposed rule would require reporting of annual emissions of
carbon dioxide (CO2), methane (CH4), nitrous
oxide (N2O), sulfur hexafluoride (SF6),
hydrofluorocarbons (HFCs), perfluorochemicals (PFCs), and other
fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated
ethers (HFEs)). The proposed rule would apply to certain downstream
facilities that emit GHGs (primarily large facilities emitting 25,000
tpy of CO2 equivalent GHG emissions or more) and to upstream
suppliers of fossil fuels and industrial GHGs, as well as to
manufacturers of vehicles and engines. Reporting would be at the
facility level, except certain suppliers and vehicle and engine
manufacturers would report at the corporate level.
This preamble is broken into several large sections, as detailed
above in the Table of Contents. Throughout the preamble we explicitly
request comment on a variety of issues. The paragraph below describes
the layout of the preamble and provides a brief summary of each
section. We also highlight particular issues on which, as indicated
later in the preamble, we would specifically be interested in receiving
comments.
The first section of this preamble contains the basic background
information about greenhouse gases and climate change. It also
describes the origin of this proposal, our legal authority and how this
proposal relates to other efforts to address emissions of greenhouse
gases. In this section we
[[Page 16453]]
would be particularly interested in receiving comment on the
relationship between this proposal and other government efforts.
The second section of this preamble describes existing Federal,
State, Regional mandatory and voluntary GHG reporting programs and how
they are similar and different to this proposal. Again, similar to the
previous section, we would like comments on the interrelationship of
this proposal and existing GHG reporting programs.
The third section of this preamble provides an overview of the
proposal itself, while the fourth section provides the rationale for
each decision the Agency made in developing the proposal, including key
design elements such as: (i) Source categories included, (ii) the level
of reporting, (iii) applicability thresholds, (iv) reporting and
monitoring methods, (v) verification, (vi) frequency and (vii) duration
of reporting. Furthermore, in this section, EPA explains the
distinction between upstream and downstream reporters, describes why it
is necessary to collect data at multiple points, and provides
information on how different data would be useful to inform different
policies. As stated in the fourth section, we solicit comment on each
design element of the proposal generally.
The fifth section of this preamble looks at the same key design
elements for each of the source categories covered by the proposal.
Thus, for example, there is a specific discussion regarding appropriate
applicability thresholds, reporting and monitoring methodologies and
reporting and recordkeeping requirements for each source category. Each
source category describes the proposed options for each design element,
as well as the other options considered. In addition to the general
solicitation for comment on each design element generally and for each
source category, throughout the fifth section there are specific issues
highlighted on which we solicit comment. Please refer to the specific
source category of interest for more details.
The sixth section of this preamble explains how EPA would collect,
manage and disseminate the data, while the seventh section describes
the approach to compliance and enforcement. In both sections the role
of the States is discussed, as are requests for comment on that role.
Finally, the eighth section provides the summary of the impacts and
costs from the Regulatory Impact Analysis and the last section walks
through the various statutory and executive order requirements
applicable to rulemakings.
A. What Are GHGs?
The proposed rule would cover the major GHGs that are directly
emitted by human activities. These include CO2,
CH4, N2O, HFCs, PFCs, SF6, and other
specified fluorinated compounds (e.g., HFEs) used in boutique
applications such as electronics and anesthetics. These gases influence
the climate system by trapping in the atmosphere heat that would
otherwise escape to space. The GHGs vary in their capacity to trap
heat. The GHGs also vary in terms of how long they remain in the
atmosphere after being emitted, with the shortest-lived GHG remaining
in the atmosphere for roughly a decade and the longest-lived GHG
remaining for up to 50,000 years. Because of these long atmospheric
lifetimes, all of the major GHGs become well mixed throughout the
global atmosphere regardless of emission origin.
Global atmospheric CO2 concentration increased about 35
percent from the pre-industrial era to 2005. The global atmospheric
concentration of CH4 has increased by 148 percent from pre-
industrial levels, and the N2O concentration has increased
18 percent. The observed increase in concentration of these gases can
be attributed primarily to human activities. The atmospheric
concentration of industrial fluorinated gases--HFCs, PFCs,
SF6--and other fluorinated compounds are relatively low but
are increasing rapidly; these gases are entirely anthropogenic in
origin.
Due to sheer quantity of emissions, CO2 is the largest
contributor to GHG concentrations followed by CH4.
Combustion of fossil fuels (e.g., coal, oil, gas) is the largest source
of CO2 emissions in the U.S. The other GHGs are emitted from
a variety of activities. These emissions are compiled by EPA in the
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory) and
reported to the UNFCCC \1\ on an annual basis.\2\ A more detailed
discussion of the Inventory is provided in Section I.D below.
---------------------------------------------------------------------------
\1\ For more information about the UNFCCC, please refer to:
http://www.unfccc.int. See Articles 4 and 12 of the UNFCCC treaty.
Parties to the Convention, by ratifying, ``shall develop,
periodically update, publish and make available * * * national
inventories of anthropogenic emissions by sources and removals by
sinks of all greenhouse gases not controlled by the Montreal
Protocol, using comparable methodologies * * *''.
\2\ The U.S. submits the Inventory of U.S. Greenhouse Gas
Emissions and Sinks to the Secretariat of the UNFCCC as an annual
reporting requirement. The UNFCCC treaty, ratified by the U.S. in
1992, sets an overall framework for intergovernmental efforts to
tackle the challenge posed by climate change. The U.S. has submitted
the GHG inventory to the United Nations every year since 1993. The
annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is
consistent with national inventory data submitted by other UNFCCC
Parties, and uses internationally accepted methods for its emission
estimates.
---------------------------------------------------------------------------
Because GHGs have different heat trapping capacities, they are not
directly comparable without translating them into common units. The
GWP, a metric that incorporates both the heat-trapping ability and
atmospheric lifetime of each GHG, can be used to develop comparable
numbers by adjusting all GHGs relative to the GWP of CO2.
When quantities of the different GHGs are multiplied by their GWPs, the
different GHGs can be compared on a CO2e basis. The GWP of
CO2 is 1.0, and the GWP of other GHGs are expressed relative
to CO2. For example, CH4 has a GWP of 21, meaning
each metric ton of CH4 emissions would have 21 times as much
impact on global warming (over a 100-year time horizon) as a metric ton
of CO2 emissions. The GWPs of the other gases are listed in
the proposed rule, and range from the hundreds up to 23,900 for
SF6.\3\ Aggregating all GHGs on a CO2e basis at
the source level allows a comparison of the total emissions of all the
gases from one source with emissions from other sources.
---------------------------------------------------------------------------
\3\ EPA has chosen to use GWPs published in the IPCC SAR
(furthermore referenced as ``SAR GWP values''). The use of the SAR
GWP values allows comparability of data collected in this proposed
rule to the national GHG inventory that EPA compiles annually to
meet U.S. commitments to the UNFCCC. To comply with international
reporting standards under the UNFCCC, official emission estimates
are to be reported by the U.S. and other countries using SAR GWP
values. The UNFCCC reporting guidelines for national inventories
were updated in 2002 but continue to require the use of GWPs from
the SAR. The parties to the UNFCCC have also agreed to use GWPs
based upon a 100-year time horizon although other time horizon
values are available. For those fluorinated compounds included in
this proposal that not listed in the SAR, EPA is using the most
recent available GWPs, either the IPCC Third Assessment Report or
Fourth Assessment Report. For more specific information about the
GWP of specific GHGs, please see Table A-1 in the proposed 40 CFR
part 98, subpart A.
---------------------------------------------------------------------------
For additional information about GHGs, climate change, climate
science, etc. please see EPA's climate change Web site found at http://www.epa.gov/climatechange/.
B. What Is Climate Change?
Climate change refers to any significant changes in measures of
climate (such as temperature, precipitation, or wind) lasting for an
extended period. Historically, natural factors such as volcanic
eruptions and changes in the amount of energy released from the sun
have affected the earth's climate. Beginning in the late 18th century,
human activities associated with the industrial revolution
[[Page 16454]]
have also changed the composition of the earth's atmosphere and very
likely are influencing the earth's climate.\4\ The heating effect
caused by the buildup of GHGs in our atmosphere enhances the Earth's
natural greenhouse effect and adds to global warming. As global
temperatures increase other elements of the climate system, such as
precipitation, snow and ice cover, sea levels, and weather events,
change. The term ``climate change,'' which encompasses these broader
effects, is often used instead of ``global warming.''
---------------------------------------------------------------------------
\4\ IPCCC: Climate Change 2007: The Physical Science Basis,
February 2, 2007 (http://www.ipcc.ch/).
---------------------------------------------------------------------------
According to the IPCC, warming of the climate system is
``unequivocal,'' as is now evident from observations of increases in
global average air and ocean temperatures, widespread melting of snow
and ice, and rising global average sea level. Global mean surface
temperatures have risen by 0.74 [deg]C (1.3 [deg]F) over the last 100
years. Global mean surface temperature was higher during the last few
decades of the 20th century than during any comparable period during
the preceding four centuries. U.S. temperatures also warmed during the
20th and into the 21st century; temperatures are now approximately 0.56
[deg]C (1.0 [deg]F) warmer than at the start of the 20th century, with
an increased rate of warming over the past 30 years. Most of the
observed increase in global average temperatures since the mid-20th
century is very likely due to the observed increase in anthropogenic
GHG concentrations.
According to different scenarios assessed by the IPCC, average
global temperature by end of this century is projected to increase by
1.8 to 4.0 [deg]C (3.2 to 7.2 [deg]F) compared to the average
temperature in 1990. The uncertainty range of this estimate is 1.1 to
6.4 [deg]C (2.0 to 11.5 [deg]F). Future projections show that, for most
scenarios assuming no additional GHG emission reduction policies,
atmospheric concentrations of GHGs are expected to continue climbing
for most if not all of the remainder of this century, with associated
increases in average temperature. Overall risk to human health, society
and the environment increases with increases in both the rate and
magnitude of climate change.
For additional information about GHGs, climate change, climate
science, etc. please see EPA's climate change Web site found at http://www.epa.gov/climatechange/.
C. Statutory Authority
On December 26, 2007, President Bush signed the FY2008 Consolidated
Appropriations Act which authorized funding for EPA to ``develop and
publish a draft rule not later than 9 months after the date of
enactment of this Act, and a final rule not later than 18 months after
the date of enactment of this Act, to require mandatory reporting of
GHG emissions above appropriate thresholds in all sectors of the
economy of the United States.'' Consolidated Appropriations Act, 2008,
Public Law 110-161, 121 Stat 1844, 2128 (2008).
The accompanying joint explanatory statement directed EPA to ``use
its existing authority under the Clean Air Act'' to develop a mandatory
GHG reporting rule. ``The Agency is further directed to include in its
rule reporting of emissions resulting from upstream production and
downstream sources, to the extent that the Administrator deems it
appropriate.'' EPA has interpreted that language to confirm that it may
be appropriate for the Agency to exercise its CAA authority to require
reporting of the quantity of fuel or chemical that is produced or
imported from upstream sources such as fuel suppliers, as well as
reporting of emissions from facilities (downstream sources) that
directly emit GHGs from their processes or from fuel combustion, as
appropriate. The joint explanatory statement further states that
``[t]he Administrator shall determine appropriate thresholds of
emissions above which reporting is required, and how frequently reports
shall be submitted to EPA. The Administrator shall have discretion to
use existing reporting requirements for electric generating units''
under section 821 of the 1990 CAA Amendments.
EPA is proposing this rule under its existing CAA authority. EPA
also proposes that the rule require the reporting of the GHG emissions
resulting from the quantity of fossil fuel or industrial gas that is
produced or imported from upstream sources such as fuel suppliers, as
well as reporting of GHG emissions from facilities (downstream sources)
that directly emit GHGs from their processes or from fuel combustion,
as appropriate. This proposed rule would also establish appropriate
thresholds and frequency for reporting.
Section 114(a)(1) of the CAA authorizes the Administrator to, inter
alia, require certain persons (see below) on a one-time, periodic or
continuous basis to keep records, make reports, undertake monitoring,
sample emissions, or provide such other information as the
Administrator may reasonably require. This information may be required
of any person who (i) owns or operates an emission source, (ii)
manufactures control or process equipment, (iii) the Administrator
believes may have information necessary for the purposes set forth in
this section, or (iv) is subject to any requirement of the Act (except
for manufacturers subject to certain title II requirements). The
information may be required for the purposes of developing an
implementation plan, an emission standard under sections 111, 112 or
129, determining if any person is in violation of any standard or
requirement of an implementation plan or emissions standard, or
``carrying out any provision'' of the Act (except for a provision of
title II with respect to manufacturers of new motor vehicles or new
motor vehicle engines).\5\ Section 208 of the CAA provides EPA with
similar broad authority regarding the manufacturers of new motor
vehicles or new motor vehicle engines, and other persons subject to the
requirements of parts A and C of title II.
---------------------------------------------------------------------------
\5\ Although there are exclusions in section 114(a)(1) regarding
certain title II requirements applicable to manufacturers of new
motor vehicle and motor vehicle engines, section 208 authorizes the
gathering of information related to those areas.
---------------------------------------------------------------------------
The scope of the persons potentially subject to a section 114(a)(1)
information request (e.g., a person ``who the Administrator believes
may have information necessary for the purposes set forth in'' section
114(a)) and the reach of the phrase ``carrying out any provision'' of
the Act are quite broad. EPA's authority to request information reaches
to a source not subject to the CAA, and may be used for purposes
relevant to any provision of the Act. Thus, for example, utilizing
sections 114 and 208, EPA could gather information relevant to carrying
out provisions involving research (e.g., section 103(g)); evaluating
and setting standards (e.g., section 111); and endangerment
determinations contained in specific provisions of the Act (e.g., 202);
as well as other programs.
Given the broad scope of sections 114 and 208 of the CAA, it is
appropriate for EPA to gather the information required by this rule
because such information is relevant to EPA's carrying out a wide
variety of CAA provisions. For example, emissions from direct emitters
should inform decisions about whether and how to use section 111 to
establish NSPS for various source categories emitting GHGs, including
whether there are any additional categories of sources that should be
listed under section 111(b). Similarly, the information required of
manufacturers of mobile
[[Page 16455]]
sources should support decisions regarding treatment of those sources
under sections 202, 213 or 231 of the CAA. In addition, the information
from fuel suppliers would be relevant in analyzing whether to proceed,
and particular options for how to proceed, under section 211(c)
regarding fuels, or to inform action concerning downstream sources
under a variety of Title I or Title II provisions. For example, the
geographic distribution, production volumes and characteristics of
various fuel types and subtypes may also prove useful is setting NSPS
or Best Available Control Technology limits for some combustion
sources. Transportation distances from fuel sources to end users may be
useful in evaluating cost effectiveness of various fuel choices,
increases in transportation emissions that may be associated with
various fuel choices, as well as the overall impact on energy usage and
availability. The data overall also would inform EPA's implementation
of section 103(g) of the CAA regarding improvements in nonregulatory
strategies and technologies for preventing or reducing air pollutants.
This section, which specifically mentions CO2, highlights
energy conservation, end-use efficiency and fuel-switching as possible
strategies for consideration and the type of information collected
under this rule would be relevant. The above discussion is not a
comprehensive listing of all the possible ways the information
collected under this rule could assist EPA in carrying out any
provision of the CAA. Rather it illustrates how the information request
fits within the parameters of EPA's CAA authority.
D. Inventory of U.S. GHG Emissions and Sinks
The Inventory of U.S. Greenhouse Gas Emissions and Sinks
(Inventory), prepared by EPA's Office of Atmospheric Programs in
coordination with the Office of Transportation and Air Quality, is an
impartial, policy-neutral report that tracks annual GHG emissions. The
annual report presents historical U.S. emissions of CO2,
CH4, N2O, HFCs, PFCs, and SF6.
The U.S. submits the Inventory to the Secretariat of the UNFCCC as
an annual reporting requirement. The UNFCCC treaty, ratified by the
U.S. in 1992, sets an overall framework for intergovernmental efforts
to tackle the challenge posed by climate change. The U.S. has submitted
the GHG inventory to the United Nations every year since 1993. The
annual Inventory is consistent with national inventory data submitted
by other UNFCCC Parties, and uses internationally accepted methods for
its emission estimates.
In preparing the annual Inventory, EPA leads an interagency team
that includes DOE, USDA, DOT, DOD, the State Department, and others.
EPA collaborates with hundreds of experts representing more than a
dozen Federal agencies, academic institutions, industry associations,
consultants, and environmental organizations. The Inventory is peer-
reviewed annually by domestic experts, undergoes a 30-day public
comment period, and is also peer-reviewed annually by UNFCCC review
teams.
The most recent GHG inventory submitted to the UNFCCC, the
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006 (April
2008), estimated that total U.S. GHG emissions were 7,054.2 million
metric tons of CO2e in 2006. Overall emissions have grown by
15 percent from 1990 to 2006. CO2 emissions have increased
by 18 percent since 1990. CH4 emissions have decreased by 8
percent since 1990, while N2O emissions have decreased by 4
percent since 1990. Emissions of HFCs, PFCs, and SF6 have
increased by 64 percent since 1990. The combustion of fossil fuels
(i.e., petroleum, coal, and natural gas) was the largest source of GHG
emissions in the U.S., and accounted for approximately 80 percent of
total CO2e emissions.
The Inventory is a comprehensive top-down national assessment of
national GHG emissions, and it uses top-down national energy data and
other national statistics (e.g., on agriculture). To achieve the goal
of comprehensive national emissions coverage for reporting under the
UNFCCC, most GHG emissions in the report are calculated via activity
data from national-level databases, statistics, and surveys. The use of
the aggregated national data means that the national emissions
estimates are not broken-down at the geographic or facility level. In
contrast, this reporting rule focuses on bottom-up data and individual
sources above appropriate thresholds. Although it would provide more
specific data, it would not provide full coverage of total annual U.S.
GHG emissions, as is required in the development of the Inventory in
reporting to the UNFCCC.
The mandatory GHG reporting rule would help to improve the
development of future national inventories for particular source
categories or sectors by advancing the understanding of emission
processes and monitoring methodologies. Facility, unit, and process
level GHG emissions data for industrial sources would improve the
accuracy of the Inventory by confirming the national statistics and
emission estimation methodologies used to develop the top-down
inventory. The results can indicate shortcomings in the national
statistics and identify where adjustments may be needed.
Therefore, although the data collected under this rule would not
replace the system in place to produce the comprehensive annual
national Inventory, it can serve as a useful tool to better improve the
accuracy of future national-level inventories.
At the same time, EPA solicits comment on whether the submission of
the Inventory to the UNFCCC could be utilized to satisfy the
requirements of the rule promulgated by EPA pursuant to the FY2008
Consolidated Appropriations Act.
For more information about the Inventory, please refer to the
following Web site: http://www.epa.gov/climatechange/emissions/usinventoryreport.html.
E. How does this proposal relate to U.S. government and other climate
change efforts?
The proposed mandatory GHG reporting program would provide EPA,
other government agencies, and outside stakeholders with economy-wide
data on facility-level (and in some cases corporate-level) GHG
emissions. Accurate and timely information on GHG emissions is
essential for informing some future climate change policy decisions.
Although additional data collection (e.g., for other source categories
such as indirect emissions or offsets) may be required as the
development of climate policies evolves, the data collected in this
rule would provide useful information for a variety of policies. For
example, through data collected under this rule, EPA would gain a
better understanding of the relative emissions of specific industries,
and the distribution of emissions from individual facilities within
those industries. The facility-specific data would also improve our
understanding of the factors that influence GHG emission rates and
actions that facilities are already taking to reduce emissions. In
addition, the data collected on some source categories such as
landfills and manure management, which can be covered by the CAA, could
also potentially help inform offset program design by providing
fundamental data on current baseline emissions for these categories.
Through this rulemaking, EPA would be able to track the trend of
emissions from industries and facilities within
[[Page 16456]]
industries over time, particularly in response to policies and
potential regulations. The data collected by this rule would also
improve the U.S. government's ability to formulate a set of climate
change policy options and to assess which industries would be affected,
and how these industries would be affected by the options. Finally,
EPA's experience with other reporting programs is that such programs
raise awareness of emissions among reporters and other stakeholders,
and thus contribute to efforts to identify reduction opportunities and
carry them out.
The goal is to have this GHG reporting program supplement and
complement, rather than duplicate, U.S. government and other GHG
programs (e.g., State and Regional based programs). As discussed in
Section I.D of this preamble, EPA anticipates that facility-level GHG
emissions data would lead to improvements in the quality of the
Inventory.
As discussed in Section II of this preamble, a number of EPA
voluntary partnership programs include a GHG emissions and/or
reductions reporting component (e.g., Climate Leaders, the Natural Gas
STAR program). Because this mandatory reporting program would have much
broader coverage than the voluntary programs, it would help EPA learn
more about emissions from facilities not currently included in these
programs and broaden coverage of these industries.
Also discussed in Section II of this preamble, DOE EIA implements a
voluntary GHG registry under section 1605(b) of the Energy Policy Act.
Under EIA's ``1605(b) program,'' reporters can choose to prepare an
entity-wide GHG inventory and identify specific GHG reductions made by
the entity.\6\ EPA's proposed mandatory GHG program would have a much
broader set of reporters included, primarily at the facility \7\ rather
than entity-level, but this proposed rule is not designed with the
specific intent of reporting of emission reductions, as is the 1605(b)
program.
---------------------------------------------------------------------------
\6\ Under the 1605(b) program an ``entity'' is defined as ``the
whole or part of any business, institution, organization or
household that is recognized as an entity under any U.S. Federal,
State or local law that applies to it; is located, at least in part,
in the U.S.; and whose operations affect U.S. greenhouse gas
emissions.'' (http://www.pi.energy.gov/enhancingGHGregistry/)
\7\ For the purposes of this proposal, facility means any
physical property, plant, building, structure, source, or stationary
equipment located on one or more contiguous or adjacent properties
in actual physical contact or separated solely by a public roadway
or other public right-of-way and under common ownership or common
control, that emits or may emit any greenhouse gas. Operators of
military installations may classify such installations as more than
a single facility based on distinct and independent functional
groupings within contiguous military properties.
---------------------------------------------------------------------------
Again, in Section II, existing State and Regional GHG reporting and
reduction programs are summarized. Many of those programs may be
broader in scope and more aggressive in implementation. States
collecting that additional information may have determined that types
of data not collected by this proposal are necessary to implement a
variety of climate efforts. While EPA's proposal was specifically
developed in response to the Appropriations Act, we also acknowledge,
similar to the States, there may be a need to collect additional data
from sources subject to this rule as well as other sources depending on
the types of policies the Agency is developing and implementing (e.g.,
indirect emissions and offsets). Addressing climate change may require
a suite of policies and programs and this proposal for a mandatory
reporting program is just one effort to collect information necessary
to inform those policies. There may well be subsequent efforts
depending on future policy direction and/or requests from Congress.
F. How does this proposal relate to EPA's Climate Change ANPR?
On July 30, 2008, EPA published an ANPR on ``Regulating Greenhouse
Gas Emissions under the Clean Air Act'' (73 FR 44354). The ANPR
presented information relevant to, and solicited public comment on,
issues regarding the potential regulation of GHGs under the CAA,
including EPA's response to the U.S. Supreme Court's decision in
Massachusetts v. EPA. 127 S.Ct. 1438 (2007). EPA's proposing the
mandatory GHG reporting rule does not indicate that EPA has made any
final decisions related to the questions identified in the ANPR. Any
information collected under the mandatory GHG reporting program would
assist EPA and others in developing future climate policy.\8\
---------------------------------------------------------------------------
\8\ At this time, a regulation requiring the reporting of GHG
emissions and emissions-related data under CAA sections 114 and 208
does not trigger the need for EPA to develop or revise regulations
under any other section of the CAA, including the PSD program. See
memorandum entitled ``EPA's Interpretation of Regulations that
Determine Pollutants Covered By Federal Prevention of Significant
Deterioration (PSD) Permit Program'' (Dec. 18, 2008). EPA is
reconsidering this memorandum and will be seeking public comment on
the issues raised in it. That proceeding, not this rulemaking, would
be the appropriate venue for submitting comments on the issue of
whether monitoring regulations under the CAA should trigger the PSD
program.
---------------------------------------------------------------------------
G. How was this proposed rule developed?
In response to the FY2008 Consolidated Appropriations Amendment,
EPA has developed this proposed rulemaking. The components of this
development are explained in the following subsections.
1. Identifying the Goals of the GHG Reporting System
The mandatory reporting program would provide comprehensive and
accurate data which would inform future climate change policies.
Potential future climate policies include research and development
initiatives, economic incentives, new or expanded voluntary programs,
adaptation strategies, emission standards, a carbon tax, or a cap-and-
trade program. Because we do not know at this time the specific
policies that may be adopted, the data reported through the mandatory
reporting system should be of sufficient quality to support a range of
approaches. Also, consistent with the Appropriations Act, the reporting
rule proposes to cover a broad range of sectors of the economy.
To these ends, we identified the following goals of the mandatory
reporting system:
Obtain data that is of sufficient quality that it can be
used to support a range of future climate change policies and
regulations.
Balance the rule coverage to maximize the amount of
emissions reported while excluding small emitters.
Create reporting requirements that are consistent with
existing GHG reporting programs by using existing GHG emission
estimation and reporting methodologies to reduce reporting burden,
where feasible.
2. Developing the Proposed Rule
In order to ensure a comprehensive consideration of GHG emissions,
EPA organized the development of the proposal around seven categories
of processes that emit GHGs: Downstream sources of emissions: (1)
Fossil Fuel Combustion: Stationary, (2) Fossil Fuel Combustion: Mobile,
(3) Industrial Processes, (4) Fossil Fuel Fugitive \9\ Emissions, (5)
Biological Processes and Upstream sources of emissions: (6) Fuel
[[Page 16457]]
Suppliers, and (7) Industrial GHG Suppliers.
---------------------------------------------------------------------------
\9\ The term ``fugitive'' often refers to emissions that cannot
reasonably pass through a stack, chimney, vent or other functionally
equivalent opening. This definition of fugitives is used throughout
the preamble, except in Section W Oil and Natural Gas Systems, which
uses a slightly modified definition based on the Intergovernmental
Panel on Climate Change.
---------------------------------------------------------------------------
For each category, EPA evaluated the requirements of existing GHG
reporting programs, obtained input from stakeholders, analyzed
reporting options, and developed the general reporting requirements and
specific requirements for each of the GHG emitting processes.
3. Evaluation of Existing GHG Reporting Programs
A number of State and regional GHG reporting systems currently are
in place or under development. EPA's goal is to develop a reporting
rule that, to the extent possible and appropriate, would rely on
similar protocols and formats of the existing programs and, therefore,
reduce the burden of reporting for all parties involved. Therefore,
each of the work groups performed a comprehensive review of existing
voluntary and mandatory GHG reporting programs, as well as guidance
documents for quantifying GHG emissions from specific sources. These
GHG reporting programs and guidance documents included the following:
International programs, including the IPCC, the EU
Emissions Trading System, and the Environment Canada reporting rule;
U.S. national programs, such as the U.S. GHG inventory,
the ARP, voluntary GHG partnership programs (e.g., Natural Gas STAR),
and the DOE 1605(b) voluntary GHG registry;
State and regional GHG reporting programs, such as TCR,
RGGI, and programs in California, New Mexico, and New Jersey;
Reporting protocols developed by nongovernmental
organizations, such as WRI/WBCSD; and
Programs from industrial trade organizations, such as the
American Petroleum Institute's Compendium of GHG Estimation
Methodologies for the Oil and Gas Industry and the Cement
Sustainability Initiative's CO2 Accounting and Reporting
Standard for the Cement Industry, developed by WBCSD.
In reviewing these programs, we analyzed the sectors covered,
thresholds for reporting, approach to indirect emissions reporting, the
monitoring or emission estimating methods used, the measures to assure
the quality of the reported data, the point of monitoring, data input
needs, and information required to be reported and/or retained. We
analyzed these provisions for suitability to a mandatory, Federal GHG
reporting program, and compiled the information. The full review of
existing GHG reporting programs and guidance may be found in the docket
at EPA-HQ-OAR-2008-0508-054. Section II of this preamble summarizes the
fundamental elements of these programs.
4. Stakeholder Outreach To Identify Reporting Issues
Early in the development process, we conducted a proactive
communications outreach program to inform the public about the rule
development effort. We solicited input and maintained an open door
policy for those interested in discussing the rulemaking. Since January
2008, EPA staff held more than 100 meetings with over 250 stakeholders.
These stakeholders included:
Trade associations and firms in potentially affected
industries/sectors;
State, local, and Tribal environmental control agencies
and regional air quality planning organizations;
State and regional organizations already involved in GHG
emissions reporting, such as TCR, CARB, and WCI;
Environmental groups and other nongovernmental
organizations.
We also met with DOE and USDA which have programs relevant
to GHG emissions.
During the meetings, we shared information about the statutory
requirements and timetable for developing a rule. Stakeholders were
encouraged to provide input on key issues. Examples of topics discussed
were, existing GHG monitoring and reporting programs and lessons
learned, thresholds for reporting, schedule for reporting, scope of
reporting, handling of confidential data, data verification, and the
role of States in administering the program. As needed, the technical
work groups followed up with these stakeholder groups on a variety of
methodological, technical, and policy issues. EPA staff also provided
information to Tribes through conference calls with different Indian
working groups and organizations at EPA and through individual calls
with Tribal board members of TCR.
For a full list of organizations EPA met with during development of
this proposal, see the memo found at EPA-HQ-OAR-2008-0508-055.
II. Summary of Existing Federal, State, and Regional Emission Reporting
Programs
A number of voluntary and mandatory GHG programs already exist or
are being developed at the State, Regional, and Federal levels. These
programs have different scopes and purposes. Many focus on GHG emission
reduction, whereas others are purely reporting programs. In addition to
the GHG programs, other Federal emission reporting programs and
emission inventories are relevant to the proposed GHG reporting rule.
Several of these programs are summarized in this section.
In developing the proposed rule, we carefully reviewed the existing
reporting programs, particularly with respect to emissions sources
covered, thresholds, monitoring methods, frequency of reporting and
verification. States may have, or intend to develop, reporting programs
that are broader in scope or are more aggressive in implementation
because those programs are either components of established reduction
programs (e.g., cap and trade) or being used to design and inform
specific complementary measures (e.g., energy efficiency). EPA has
benefitted from the leadership the States have shown in developing
these programs and their experiences. Discussions with States that have
already implemented programs have been especially instructive. Where
possible, we built upon concepts in existing Federal and State programs
in developing the mandatory GHG reporting rule.
A. Federal Voluntary GHG Programs
EPA and other Federal agencies operate a number of voluntary GHG
reporting and reduction programs that EPA reviewed when developing this
proposal, including Climate Leaders, several Non-CO2
voluntary programs, the CHP partnership, the SmartWay Transport
Partnership program, the National Environmental Performance Track
Partnership, and the DOE 1605(b) voluntary GHG registry. There are
several other Federal voluntary programs to encourage emissions
reductions, clean energy, or energy efficiency, and this summary does
not cover them all. This summary focuses on programs that include
voluntary GHG emission inventories or reporting of GHG emission
reduction activities for sectors covered by this proposed rulemaking.
Climate Leaders.\10\ Climate Leaders is an EPA partnership program
that works with companies to develop GHG reduction strategies. Over 250
industry partners in a wide range of sectors have joined. Partner
companies complete a corporate-wide inventory of GHG emissions and
develop an inventory management plan using Climate Leaders protocols.
Each company sets GHG reductions goals and submits to EPA an
[[Page 16458]]
annual GHG emissions inventory documenting their progress. The annual
reporting form provides corporate-wide emissions by type of emissions
source.
---------------------------------------------------------------------------
\10\ For more information about the Climate Leaders program
please see: http://www.epa.gov/climateleaders/.
---------------------------------------------------------------------------
Non-CO2 Voluntary Partnership Programs.\11\ Since the
1990s, EPA has operated a number of non-CO2 voluntary
partnership programs aimed at reducing emissions from GHGs such as
CH4, SF66, and PFCs. There are four
sector-specific voluntary CH4 reduction programs: Natural
Gas STAR, Landfill Methane Outreach Program, Coalbed Methane Outreach
Program and AgSTAR. In addition, there are sector-specific voluntary
emission reduction partnerships for high GWP gases. The Natural Gas
STAR partnership encourages companies across the natural gas and oil
industries to adopt practices that reduce CH4 emissions. The
Landfill Methane Outreach Program and Coalbed Methane Outreach Program
encourage voluntary capture and use of landfill and coal mine
CH4, respectively, to generate electricity or other useful
energy. These partnerships focus on achieving CH4
reductions. Industry partners voluntarily provide technical information
on projects they undertake to reduce CH4 emissions on an
annual basis, but they do not submit CH4 emissions
inventories. AgSTAR encourages beneficial use of agricultural
CH4 but does not have partner reporting requirements.
---------------------------------------------------------------------------
\11\ For more information about the Non-CO2 Voluntary
Partnership Programs please see: http://www.epa.gov/nonco2/voluntaryprograms.html.
---------------------------------------------------------------------------
There are two sector specific partnerships to reduce SF6
emissions: The SF6 Emission Reduction Partnership for
Electric Power Systems, with over 80 participating utilities, and an
SF6 Emission Reduction Partnership for the Magnesium
Industry. Partners in these programs implement practices to reduce
SF6 emissions and prepare corporate-wide annual inventories
of SF6 emissions using protocols and reporting tools
developed by EPA. There are also two partnerships focused on PFCs. The
Voluntary Aluminum Industrial Partnership promotes technically feasible
and cost effective actions to reduce PFC emissions. Industry partners
track and report PFC emissions reductions. Similarly, the Semiconductor
Industry Association and EPA formed a partnership to reduce PFC
emissions. A third party compiles data from participating semiconductor
companies and submits an aggregate (not company-specific) annual PFC
emissions report.
CHP Partnership.\12\ The CHP Partnership is an EPA partnership that
cuts across sectors. It encourages use of CHP technologies to generate
electricity and heat from the same fuel source, thereby increasing
energy efficiency and reducing GHG emissions from fuel combustion.
Corporate and institutional partners provide data on existing and new
CHP projects, but do not submit emissions inventories.
---------------------------------------------------------------------------
\12\ For more information about the CHP Partnership please see:
http://www.epa.gov/chp/.
---------------------------------------------------------------------------
SmartWay Transport Partnership.\13\ The SmartWay Transport
Partnership program is a voluntary partnership between freight industry
stakeholders and EPA to promote fuel efficiency improvements and GHG
emissions reductions. Over 900 companies have joined including freight
carriers (railroads and trucking fleets) and shipping companies.
Carrier and shipping companies commit to measuring and improving the
efficiency of their freight operations using EPA-developed tools that
quantify the benefits of a number of fuel-saving strategies. Companies
report progress annually. The GHG data that carrier companies report to
EPA is discussed further in Section V.QQ.4b of this preamble.
---------------------------------------------------------------------------
\13\ For more information about SmartWay please see: http://www.epa.gov/smartway/.
---------------------------------------------------------------------------
National Environmental Performance Track Partnership.\14\ The
Performance Track Partnership is a voluntary partnership that
recognizes and rewards private and public facilities that demonstrate
strong environmental performance beyond current requirements.
Performance Track is designed to augment the existing regulatory system
by creating incentives for facilities to achieve environmental results
beyond those required by law. To qualify, applicants must have
implemented an independently-assessed environmental management system,
have a record of sustained compliance with environmental laws and
regulations, commit to achieving measurable environmental results that
go beyond compliance, and provide information to the local community on
their environmental activities. Members are subject to the same legal
requirements as other regulated facilities. In some cases, EPA and
states have reduced routine reporting or given some flexibility to
program members in how they meet regulatory requirements. This approach
is recognized by more than 20 states that have adopted similar
performance-based leadership programs.
---------------------------------------------------------------------------
\14\ For more information about Performance Track please see:
http://www.epa.gov/perftrac/index.htm.
---------------------------------------------------------------------------
1605(b) Voluntary Registry.\15\ The DOE EIA established a voluntary
GHG registry under section 1605(b) of the Energy Policy Act of 1992.
The program was recently enhanced and a final rule containing general
reporting guidelines was published on April 21, 2006 (71 FR 20784). The
rule is contained in 10 CFR part 300. Unlike EPA's proposal which
requires of reporting of GHG emissions from facilities over a specific
threshold, the DOE 1605(b) registry allows anyone (e.g., a public
entity, private company, or an individual) to report on their emissions
and their emission reduction projects to the registry. Large emitters
(e.g., anyone that emits over 10,000 tons of CO2e per year)
that wish to register emissions reductions must submit annual company-
wide GHG emissions inventories following technical guidelines published
by DOE and must calculate and report net GHG emissions reductions. The
program offers a range of reporting methodologies from stringent direct
measurement to simplified calculations using default factors and allows
the reporters to report using the methodological option they choose. In
addition, as mentioned above, unlike EPA's proposal, sequestration and
offset projects can also be reported under the 1605(b) program. There
is additional flexibility offered to small sources who can choose to
limit annual inventories and emission reduction reports to just a
single type of activity rather than reporting company-wide GHG
emissions, but must still follow the technical guidelines. Reported
data are made available on the Web in a public use database.
---------------------------------------------------------------------------
\15\ For more information about DOE's 1605(b) programs please
see: http://www.pi.energy.gov/enhancingGHGregistry/.
---------------------------------------------------------------------------
Summary. These voluntary programs are different in nature from the
proposed mandatory GHG emissions reporting rule. Industry participation
in the programs and reporting to the programs is entirely voluntary. A
small number of sources report, compared to the number of facilities
that would likely be affected by the proposed mandatory GHG reporting
rule. Most of the EPA voluntary programs do not require reporting of
annual emissions data, but are instead intended to encourage GHG
reduction projects/activities and track partner's successes in
implementing such projects. For the programs that do include annual
emissions reporting (e.g., Climate Leaders, DOE 1605(b)) the scope and
level of detail are different. For example, Climate Leaders annual
reports are generally corporate-wide and do not contain the facility
and process-
[[Page 16459]]
level details that would be needed by a mandatory program to verify the
accuracy of the emissions reports.
At the same time, aspects of the voluntary programs serve as useful
starting points for the mandatory GHG reporting rules. GHG emission
calculation principles and protocols have been developed for various
types of emission sources by Climate Leaders, the DOE 1605(b) program,
and some partnerships such as the SF6 reduction partnerships
and SmartWay. Under these protocols, reporting companies monitor
process or operating parameters to estimate GHG emissions, report
annually, and retain records to document their GHG estimates. Through
the voluntary programs, EPA, DOE, and participating companies have
gained understanding of processes that emit GHGs and experience in
developing and reviewing GHG emission inventories.
B. Federal Mandatory Reporting Programs
Sulfur Dioxide (SO2) and Nitrogen Oxides (NOX) Trading Programs.
The ARP and the NOX Budget Trading Program are cap-and-trade
programs designed to reduce emissions of SO2 and
NOX\16\. As a part of those programs facilities with EGUs
that serve a generator larger than 25 MW are required to report
emissions. The 40 CFR part 75 CEMS rule establishes monitoring and
reporting requirements under these programs. The regulations in 40 CFR
part 75 require continuous monitoring and quarterly and annual
emissions reporting of CO2 mass emissions,\17\
SO2 mass emissions, NOX emission rate, and heat
input. Part 75 contains specifications for the types of monitoring
systems that may be used to determine CO2 emissions and sets
forth operations, maintenance, and QA/QC requirement for each system.
In some cases, EGUs are allowed to use simplified procedures other than
CEMS (e.g., monitoring fuel feed rates and conducting periodic sampling
and analyses of fuel carbon content) to determine CO2
emissions. Under the regulations, affected EGUs must submit detailed
quarterly and annual CO2 emissions reports using
standardized electronic reporting formats. If CEMS are used, the
quarterly reports include hourly CEMS data and other information used
to calculate emissions (e.g., monitor downtime). If alternative
monitoring programs are used, detailed data used to calculate
CO2 emissions must be reported.
---------------------------------------------------------------------------
\16\ For more information about these cap and trade programs see
http://www.epa.gov/airmarkt/.
\17\ The requirements regarding CO2 emissions
reporting apply only to ARP sources and are pursuant to section 821
of the CAA Amendments of 1990, Public Law 101-549.
---------------------------------------------------------------------------
The joint explanatory statement accompanying the FY2008
Consolidated Appropriations Amendment specified that EPA could use the
existing reporting requirements for electric generating units under
section 821 of the 1990 CAA Amendments.\18\ As described in Sections
V.C. and V.D. of this preamble, because the part 75 regulations already
require reporting of high quality CO2 data from EGUs, the
GHG reporting rule proposes to use the same CO2 data rather
than require additional reporting of CO2 from EGUs. They
would, however, have to include reporting of the other GHG emissions,
such as CH4 and N2O, at their facilities.
---------------------------------------------------------------------------
\18\ The joint explanatory statement refers to ``Section 821 of
the Clean Air Act'' but section 821 was part of the 1990 CAA
Amendments not codified into the CAA itself.
---------------------------------------------------------------------------
TRI. TRI requires facility-level reporting of annual mass emissions
of approximately 650 toxic chemicals.\19\ If they are above established
thresholds, facilities in a wide range of industries report including
manufacturing industries, metal and coal mining, electric utilities,
and other industrial sectors. Facilities must submit annual reports of
total stack and fugitive emissions of the listed toxic chemicals using
a standardized form which can be submitted electronically. No
information is reported on the processes and emissions points included
in the total emissions. The data reported to TRI are not directly
useful for the GHG rule because TRI does not include GHG emissions and
does not identify processes or emissions sources. However, the TRI
program is similar to the proposed GHG reporting rule in that it
requires direct emissions reporting from a large number of facilities
(roughly 23,000) across all major industrial sectors. Therefore, EPA
reviewed the TRI program for ideas regarding program structure and
implementation.
---------------------------------------------------------------------------
\19\ For more information about TRI and what chemicals are on
the list, please see: http://www.epa.gov/tri/.
---------------------------------------------------------------------------
Vehicle Reporting. EPA's existing criteria pollutant emissions
certification regulations, as well as the fuel economy testing
regulations which EPA administers as part of the CAFE program, require
vehicle manufacturers to measure and report CO2 for
essentially all of their light duty vehicles. In addition, many engine
manufacturers currently measure CO2 as an integral part of
calculating emissions of criteria pollutants, and some report
CO2 emissions to EPA in some form.
C. EPA Emissions Inventories
U.S. Inventory of Greenhouse Gas Emissions and Sinks. As discussed
in Section I.D of this preamble, EPA prepares the U.S. Inventory of
Greenhouse Gas Emissions and Sinks every year. The details of this
Inventory, the methodologies used to calculate emissions and its
relationship to this proposal are discussed in Section I.D of this
preamble.
NEI. \20\ EPA compiles the NEI, a database of air emissions
information provided primarily by State and local air agencies and
Tribes. The database contains information on stationary and mobile
sources that emit criteria air pollutants and their precursors, as well
as hazardous air pollutants. Stationary point source emissions that
must be inventoried and reported are those that emit over a threshold
amount of at least one criteria pollutant. Many States also inventory
and report stationary sources that emit amounts below the thresholds
for each pollutant. The NEI includes over 60,000 facilities. The
information that is required consists of facility identification
information; process information detailing the types of air pollution
emission sources; air pollution emission estimates (including annual
emissions); control devices in place; stack parameters; and location
information. The NEI differs from the proposed GHG reporting rule in
that the NEI contains no GHG data, and the data are reported primarily
by State agencies rather than directly reported by industries.\21\
However, in developing the proposed rule, EPA used the NEI to help
determine sources that might need to report under the GHG reporting
rule. We considered the types of facility, process and activity data
reported in NEI to support the emissions data as a possible model for
the types of data to be reported under the GHG reporting rule. We also
considered systems that could be used to link data reported under the
GHG rule with data for the same facilities in the NEI.
---------------------------------------------------------------------------
\20\ For more information about the NEI please see: http://www.epa.gov/ttn/chief/net/.
\21\ As discussed in section IV of the preamble, tropospheric
ozone (O3) is a GHG. The precursors to tropospheric
O3 (e.g., NOX, VOCs, etc) are reported to the NEI by
States and then EPA models tropospheric O3 based on that
precursor data.
---------------------------------------------------------------------------
D. Regional and State Voluntary Programs for GHG Emissions Reporting
A number of States have demonstrated leadership and developed
corporate voluntary GHG reporting programs individually or joined with
other States to develop GHG reporting programs as part of their
approaches to addressing GHG emissions. EPA has
[[Page 16460]]
benefitted from this leadership and the States' experiences;
discussions with those that have already implemented programs have been
especially instructive. Section V of the preamble describes the
proposed methods for each source category. The different options
considered have been particularly informed by the States' expertise.
This section of the preamble summarizes two prominent voluntary
efforts. In developing the greenhouse rules, EPA reviewed the relevant
protocols used by these programs as a starting point. We recognize that
these programs may have additional monitoring and reporting
requirements than those outlined in the proposed rule in order to
provide distinct program benefits.
CCAR.\22\ CCAR is a voluntary GHG registry already in use in
California. CCAR has released several methodology documents including a
general reporting protocol, general certification (verification)
protocol, and several sector-specific protocols. Companies submit
emissions reports using a standardized electronic system. Emission
reports may be aggregated at the company level or reported at the
facility level.
---------------------------------------------------------------------------
\22\ For more information about CCAR please see: http://www.climateregistry.org/.
---------------------------------------------------------------------------
TCR.\23\ TCR is a partnership formed by U.S. and Mexican States,
Canadian provinces, and Tribes to develop standard GHG emissions
measurement and verification protocols and a reporting system capable
of supporting mandatory or voluntary GHG emission reporting rules and
policies for its member States. TCR has released a General Reporting
Protocol that contains procedures to measure and calculate GHG
emissions from a wide range of source categories. They have also
released a general verification protocol, and an electronic reporting
system. Founding reporters (companies and other organizations that have
agreed to voluntarily report their GHG emissions) implemented a pilot
reporting program in 2008. Annual reports would be submitted covering
six GHGs. Corporations must report facility-specific emissions, broken
out by type of emission source (e.g., stationary combustion,
electricity use, direct process emissions) within the facility.
---------------------------------------------------------------------------
\23\ For more information about TCR please see: http://www.theclimateregistry.org/.
---------------------------------------------------------------------------
E. State and Regional Mandatory Programs for GHG Emissions Reporting
and Reduction
Several individual States and regional groups of States have
demonstrated leadership and are developing or have developed mandatory
GHG reporting programs and GHG emissions control programs. This section
of the preamble summarizes two regional cap-and-trade programs and
several State mandatory reporting rules. We recognize that, like the
current voluntary regional and State programs, State and regional
mandatory reporting programs may evolve or develop to include
additional monitoring and reporting requirements than those included in
the proposed rule. In fact, these programs may be broader in scope or
more aggressive in implementation because the programs are either
components of established reduction programs (e.g., cap and trade) or
being used to design and inform specific complementary measures (e.g.,
energy efficiency).
RGGI.\24\ RGGI is a regional cap-and-trade program that covers
CO2 emissions from EGUs that serve a generator greater than
25 MW in member States in the mid-Atlantic and Northeast. The program
goal is to reduce CO2 emissions to 10 percent below 1990
levels by the year 2020. RGGI will utilize the CO2 reported
to and verified by EPA under 40 CFR part 75 to determine compliance of
the EGUs in the cap-and-trade program. In addition, the EGUs in RGGI
that are not currently reporting to EPA under the ARP and NOX Budget
program (e.g., co-generation facilities) will start reporting their
CO2 data to EPA for QA/QC, similar to the sources already
reporting. Certain types of offset projects will be allowed, and GHG
offset protocols have been developed. The States participating in RGGI
have adopted State rules (based on the model rule) to implement RGGI in
each State. The RGGI cap-and-trade program took effect on January 1,
2009.
---------------------------------------------------------------------------
\24\ For more information about RGGI please see: http://www.rggi.org/.
---------------------------------------------------------------------------
WCI.\25\ WCI is another regional cap-and-trade program being
developed by a group of Western States and Canadian provinces. The goal
is to reduce GHG emissions to 15 percent below 2005 levels by the year
2020. Draft options papers and program scope papers were released in
early 2008, public comments were reviewed, and final program design
recommendations were made in September 2008. Other elements of the
program, such as reporting requirements, market operations, and offset
program development continues. Several source categories are being
considered for inclusion in the cap and trade framework. The program
might be phased in, starting with a few source categories and adding
others over time. Points of regulation for some source categories,
calculation methodologies, and other reporting program elements are
under development. The WCI is also analyzing alternative or
complementary policies other than cap-and-trade that could help reach
GHG reduction goals. Options for rule implementation and for
coordination with other rules and programs such as TCR are being
investigated.
---------------------------------------------------------------------------
\25\ For more information about WCI please see: http://www.westernclimateinitiative.org/.
---------------------------------------------------------------------------
A key difference between the Federal mandatory GHG reporting rule
and the RGGI and WCI programs is that the Federal mandatory GHG rule is
solely a reporting requirement. It does not in any way regulate GHG
emissions or require any emissions reductions.
State Mandatory GHG Reporting Rules. Seventeen States have
developed, or are developing, mandatory GHG reporting rules.\26\ The
docket contains a summary of these State mandatory rules (EPA-HQ-OAR-
2008-0508-056). Final rules have not yet been developed by some of the
States, so details of some programs are unknown. Reporting requirements
have taken effect in twelve States as of 2009; the rest start between
2010 and 2012. Reporting is typically annual, although some States
require quarterly reporting for EGUs, consistent with RGGI and the ARP.
---------------------------------------------------------------------------
\26\ These include: California, Colorado, Connecticut, Delaware,
Hawaii, Iowa, Maine, Maryland, Massachusetts, New Jersey, New
Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia,
and Wisconsin.
---------------------------------------------------------------------------
State rules differ with regard to which facilities must report and
which GHGs must be reported. Some States require all facilities that
must obtain Title V permits to report GHG emissions. Others require
reporting for particular sectors (e.g., large EGUs, cement plants,
refineries). Some State rules apply to any facility with stationary
combustion sources that emit a threshold level of CO2. Some
apply to any facility, or to facilities within listed industries, if
their emissions exceed a specified threshold level of CO2e.
Many of the State rules apply to six GHGs (CO2,
CH4, N2O, HFCs, PFCs, SF6); others
apply only to CO2 or a subset of the six gases. Most require
reporting at the facility level, or by unit or process within a
facility.
The level of specificity regarding GHG monitoring and calculation
methods varies. Some of the States refer to use of protocols
established by TCR or CCAR. Others look to industry-specific protocols
(such as methods developed by the American Petroleum Institute), to
accepted international methodologies such as IPCC, and/or to emission
factors in EPA's Compilation of Air Pollutant
[[Page 16461]]
Emission Factors (known as AP-42 \27\) or other EPA guidance.
---------------------------------------------------------------------------
\27\ See Compilation of Air Pollutant Emission Factors, Fifth
Edition: http://www.epa.gov/ttn/chief/ap42/index.html_ac/index.html.
---------------------------------------------------------------------------
California Mandatory GHG Reporting Rule.\28\ CARB's mandatory
reporting rule is an example of a State rule that covers multiple
source categories and contains relatively detailed requirements,
similar to this proposal developed by EPA. According to the CARB
proposed rule (originally proposed October 19, 2007, and revised on
December 5, 2007), monitoring must start on January 1, 2009, and the
first reports will be submitted in 2010. The rule requires facility-
level reporting of all GHGs, except PFCs, from cement manufacturing
plants, electric power generation and retail, cogeneration plants,
petroleum refineries, hydrogen plants, and facilities with stationary
combustion sources emitting greater than 25,000 tons CO2 per
year. California requires 40 CFR part 75 data for EGUs. The California
rule contains specific GHG estimation methods that are largely
consistent with CCAR protocols, and also rely on American Petroleum
Institute protocols and IPCC/EU protocols for certain types of sources.
California continues to participate in other national and regional
efforts, such as TCR and WCI, to assist with developing consistent
reporting tools and procedures on a national and regional basis.
---------------------------------------------------------------------------
\28\ For more information about CA mandatory reporting program
please see: http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm.
---------------------------------------------------------------------------
F. How the Proposed Mandatory GHG Reporting Program Is Different From
the Federal and State Programs EPA Reviewed
The various existing State and Federal programs EPA reviewed are
diverse. They apply to different industries, have different thresholds,
require different pollutants and different types of emissions sources
to be reported, rely on different monitoring protocols, and require
different types of data to be reported, depending on the purposes of
each program. None of the existing programs require nationwide,
mandatory GHG reporting by facilities in a large number of sectors, so
EPA's proposed mandatory GHG rule development effort is unique in this
regard.
Although the mandatory GHG rule is unique, EPA carefully considered
other Federal and State programs during development of the proposed
rule. Documentation of our review of GHG monitoring protocols for each
source category used by Federal, State, and international voluntary and
mandatory GHG programs, and our review of State mandatory GHG rules can
be found at EPA-HQ-OAR-2008-0508-056. The proposed monitoring and GHG
calculation methodologies for many source categories are the same as,
or similar to, the methodologies contained in State reporting programs
such as TCR, CCAR, and State mandatory GHG reporting rules and similar
to methodologies developed by EPA voluntary programs such as Climate
Leaders. The reporting requirements set forth in 40 CFR part 75 are
also being used for this proposed rule. Similarity in proposed methods
would help maximize the ability of individual reporters to submit the
emissions calculations to multiple programs, if desired. EPA also
continues to work closely with States and State-based groups to ensure
that the data management approach in this proposal would lead to
efficient submission of data to multiple programs. Section V of this
preamble includes further information on the selection of monitoring
methods for each source category.
The intent of this proposed rule is to collect accurate and
consistent GHG emissions data that can be used to inform future
decisions. One goal in developing the rule is to utilize and be
consistent with the GHG protocols and requirements of other State and
Federal programs, where appropriate, to make use of existing
cooperative efforts and reduce the burden to facilities submitting
reports to other programs. However, we also need to be sure the
mandatory reporting rule collects facility-specific data of sufficient
quality to achieve the Agency's objectives for this rule. Therefore,
some reporting requirements of this proposed rule are different from
the State programs. The remaining sections of this preamble further
describe the proposed rule requirements and EPA's rationale for all of
the requirements.
EPA seeks comment on whether the conclusions drawn during its
review of existing programs are accurate and invites data to
demonstrate if, and if so how, the goals and objectives of this
proposed mandatory reporting system could be met through existing
programs. In particular, comments should address how existing programs
meet the breadth of sources reporting, thresholds for reporting,
consistency and stringency of methods for reporting, level of
reporting, frequency of reporting and verification of reports included
in this proposal.
III. Summary of the General Requirements of the Proposed Rule
The proposed rule would require reporting of annual emissions of
CO2, CH4, N2O, SF6, HFCs,
PFCs, and other fluorinated gases (as defined in proposed 40 CFR part
98, subpart A). The rule would apply to certain downstream facilities
that emit GHGs, upstream suppliers of fossil fuels and industrial GHGs,
and manufacturers of vehicles and engines.\29\ We are proposing that
reporting be at the facility \30\ level, except that certain suppliers
of fossil fuels and industrial gases and manufacturers of vehicles and
engines would report at the corporate level.
---------------------------------------------------------------------------
\29\ We are proposing to incorporate the reporting requirements
for manufacturers of motor vehicles and engines into the existing
reporting requirements of 40 CFR parts 86, 89, 90, 91, 92, 94, 1033,
1039, 1042, 1045, 1048, 1051, and 1054.
\30\ For the purposes of this proposal, facility means any
physical property, plant, building, structure, source, or stationary
equipment located on one or more contiguous or adjacent properties
in actual physical contact or separated solely by a public roadway
or other public right-of-way and under common ownership or common
control, that emits or may emit any greenhouse gas. Operators of
military installations may classify such installations as more than
a single facility based on distinct and independent functional
groupings within contiguous military properties.
---------------------------------------------------------------------------
A. Who must report?
Owners and operators of the following facilities and supply
operations would submit annual GHG emission reports under the proposal:
A facility that contains any of the source categories listed
below in any calendar year starting in 2010. For these facilities, the
GHG emission report would cover all sources in any source category for
which calculation methodologies are provided in proposed 40 CFR part
98, subparts B through JJ.
--Electricity generating facilities that are subject to the ARP, or
that contain electric generating units that collectively emit 25,000
metric tons of CO2e or more per year.\31\
---------------------------------------------------------------------------
\31\ This does not include portable equipment or generating
units designated as emergency generators in a permit issued by a
state or local air pollution control agency. As described in section
V.C of the preamble we are taking comment on whether or not a permit
should be required.
---------------------------------------------------------------------------
--Adipic acid production.
--Aluminum production.
--Ammonia manufacturing.
--Cement production.
--Electronics--Semiconductor, MEMS, and LCD (LCD) manufacturing
facilities with an annual production capacity that exceeds any of the
thresholds listed in this paragraph--Semiconductors:
[[Page 16462]]
1,080 m\2\ silicon, MEMS: 1,202 m\2\ silicon, LCD: 235,700 m\2\ LCD.
--Electric power systems that include electrical equipment with a
total nameplace capacity that exceeds 17,820 lbs (7,838 kg) of
SF6 or PFCs.
--HCFC-22 production.
--HFC-23 destruction processes that are not colocated with a HCFC-
22 production facility and that destroy more than 2.14 metric tons of
HFC-23 per year.
--Lime manufacturing.
--Nitric acid production.
--Petrochemical production.
--Petroleum refineries.
--Phosphoric acid production.
--Silicon carbide production.
--Soda ash production.
--Titanium dioxide production.
--Underground coal mines that are subject to quarterly or more
frequent sampling by MSHA of ventilation systems.
--Municipal landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e or more per year.
--Manure management systems that emit CH4 and
N2O in amounts equivalent to 25,000 metric tons
CO2e or more per year.
Any facility that emits 25,000 metric tons CO2e or
more per year in combined emissions from stationary fuel combustion
units, miscellaneous use of carbonates and all of the source categories
listed below that are located at the facility in any calendar year
starting in 2010. For these facilities, the GHG emission report would
cover all source categories for which calculation methodologies are
provided in proposed 40 CFR part 98, subparts B through JJ of the rule.
--Electricity Generation \32\
---------------------------------------------------------------------------
\32\ This does not include portable equipment or generating
units designated as emergency generators in a permit issued by a
state or local air pollution control agency. As described in section
V.C of the preamble we are taking comment on whether or not a permit
should be required.
---------------------------------------------------------------------------
--Electronics--Photovoltaic Manufacturing
--Ethanol Production
--Ferroalloy Production
--Fluorinated Greenhouse Gas Production
--Food Processing
--Glass Production
--Hydrogen Production
--Iron and Steel Production
--Lead Production
--Magnesium Production
--Oil and Natural Gas Systems
--Pulp and Paper Manufacturing
--Zinc Production
--Industrial Landfills
--Wastewater
Any facility that in any calendar year starting in 2010 meets
all three of the conditions listed in this paragraph. For these
facilities, the GHG emission report would cover emissions from
stationary fuel combustion sources only. For 2010 only, the facilities
can submit an abbreviated emissions report according to proposed 40 CFR
98.3(d).
--The facility does not contain any source in any source category
designated in the above two paragraphs;
--The aggregate maximum rated heat input capacity of the stationary
fuel combustion units at the facility is 30 mmBtu/hr or greater; and
--The facility emits 25,000 metric tons CO2e or more per
year from all stationary fuel combustion sources.\33\
---------------------------------------------------------------------------
\33\ This does not include portable equipment or generating
units designated as emergency generators in a permit issued by a
state or local air pollution control agency. As described in section
V. C of the preamble we are taking comment on whether or not a
permit should be required.
---------------------------------------------------------------------------
Any supplier of any of the products listed below in any
calendar year starting in 2010. For these suppliers, the GHG emissions
report would cover all applicable products for which calculation
methodologies are provided in proposed 40 CFR part 98, subparts KK
through PP.
--Coal.
--Coal-based liquid fuels.
--Petroleum products.
--Natural gas and NGLs.
--Industrial GHGs: All producers of industrial GHGs, importers and
exporters of industrial GHGs with total bulk imports or total bulk
exports that exceed 25,000 metric tons CO2e per year.
--CO2: All producers of CO2, importers and
exporters of CO2 or a combination of CO2 and
other industrial GHGs with total bulk imports or total bulk exports
that exceed 25,000 metric tons CO2e per year.
Manufacturers of mobile sources and engines would be required
to report emissions from the vehicles and engines they produce,
generally in terms of an emission rate.\34\ These requirements would
apply to emissions of CO2, CH4, N2O,
and, where appropriate, HFCs. Manufacturers of the following vehicle
and engine types would need to report: (1) Manufacturers of passenger
cars, light trucks, and medium-duty passenger vehicles, (2)
manufacturers of highway heavy-duty engines and complete vehicles, (3)
manufacturers of nonroad diesel engines and nonroad large spark-
ignition engines, (4) manufacturers of nonroad small spark-ignition
engines, marine spark-ignition engines, personal watercraft, highway
motorcycles, and recreational engines and vehicles, (5) manufacturers
of locomotive and marine diesel engines, and (6) manufacturers of jet
and turboprop aircraft engines.
---------------------------------------------------------------------------
\34\ As discussed in Section V.QQ, manufacturers below a size
threshold would be exempt.
---------------------------------------------------------------------------
B. Schedule for Reporting
Facilities and suppliers would begin collecting data on January 1,
2010. The first emissions report would be due on March 31, 2011, for
emissions during 2010.35 36 Reports would be submitted
annually. Facilities with EGUs that are subject to the ARP would
continue to report CO2 mass emissions quarterly, as required
by the ARP, in addition to providing the annual GHG emissions reports
under this rule. EPA is proposing that the rule require the submission
of GHG emissions data on an ongoing, annual basis. The snapshot of
information provided by a one-time information collection request would
not provide the type of ongoing information which could inform the
variety of potential policy options being evaluated for addressing
climate change. EPA is taking comment on other possible options,
including a commitment to review the continued need for the information
at a specific later date, or a sunset provision. Once subject to this
reporting rule, a facility or supply operation would continue to submit
reports even if it falls below the reporting thresholds in future
years.
---------------------------------------------------------------------------
\35\ Unless otherwise noted, years and dates in this notice
refer to calendar years and dates.
\36\ There is a discussion in section I.IV of this preamble that
takes comment on alternative reporting schedules.
---------------------------------------------------------------------------
C. What do I have to report?
The report would include total annual GHG emissions in metric tons
of CO2e aggregated for all the source categories and for all
supply categories for which emission calculation methods are provided
in part 98. The report would also separately present annual mass GHG
emissions for each source category and supply category, by gas.
Separate reporting requirements are provided for vehicle and engine
manufacturers. These sources would be required to report emissions from
the vehicles and engines they produce, generally in terms of an
emission rate.
Within a given source category, the report also would break out
emissions at the level required by the respective subpart (e.g.,
reporting could be
[[Page 16463]]
required for each individual unit for some source categories and for
each process line for other source categories).
In addition to GHG emissions, you would report certain activity
data (e.g., fuel use, feedstock inputs) that were used to generate the
emissions data. The required activity data are specified in each
subpart. For some source categories, additional data would be reported
to support QA/QC and verification.
EPA would protect any information claimed as CBI in accordance with
regulations in 40 CFR part 2, subpart B. However, note that in general,
emission data collected under CAA sections 114 and 208 cannot be
considered CBI.\37\
---------------------------------------------------------------------------
\37\ Although CBI determinations are usually made on a case-by-
case basis, EPA has issued guidance in an earlier Federal Register
notice on what constitutes emissions data that cannot be considered
CBI (956 FR 7042-7043, February 21, 1991).
---------------------------------------------------------------------------
D. How do I submit the report?
The reports would be submitted electronically, in a format to be
specified by the Administrator after publication of the final rule.\38\
To the extent practicable, we plan to adapt existing facility reporting
programs to accept GHG emissions data. We are developing a new
electronic data reporting system for source categories or suppliers for
which it is not feasible to use existing reporting mechanisms.
---------------------------------------------------------------------------
\38\ For more information about the reporting format please see
section VI of this preamble.
---------------------------------------------------------------------------
Each report would contain a signed certification by a Designated
Representative of the facility. On behalf of the owner or operator, the
Designated Representative would certify under penalty of law that the
report has been prepared in accordance with the requirements of 40 CFR
part 98 and that the information contained in the report is true and
accurate, based on a reasonable inquiry of individuals responsible for
obtaining the information.
E. What records must I retain?
Each facility or supplier would also have to retain and make
available to EPA upon request the following records for five years in
an electronic or hard-copy format as appropriate:
A list of all units, operations, processes and activities
for which GHG emissions are calculated;
The data used to calculate the GHG emissions for each
unit, operation, process, and activity, categorized by fuel or material
type;
Documentation of the process used to collect the necessary
data for the GHG emissions calculations;
The GHG emissions calculations and methods used;
All emission factors used for the GHG emissions
calculations;
Any facility operating data or process information used
for the GHG emissions calculations;
Names and documentation of key facility personnel involved
in calculating and reporting the GHG emissions;
The annual GHG emissions reports;
A log book documenting any procedural changes to the GHG
emissions accounting methods and any changes to the instrumentation
critical to GHG emissions calculations;
Missing data computations;
A written QAPP;
Any other data specified in any applicable subpart of
proposed 40 CFR part 98. Examples of such data could include the
results of sampling and analysis procedures required by the subparts
(e.g., fuel heat content, carbon content of raw materials, and flow
rate) and other data used to calculate emissions.
IV. Rationale for the General Reporting, Recordkeeping and Verification
Requirements That Apply to All Source Categories
This section of the preamble explains the rationales for EPA's
proposals for various aspects of the rule. This section applies to all
of the source categories in the preamble (further discussed in Sections
V.B through V.PP of this preamble) with the exception of mobile sources
(discussed in Section V.QQ of this preamble). The proposals EPA is
making with regard to mobile sources are extensions of existing EPA
programs and therefore the rationales and decisions are discussed
wholly within that section. With respect to the source categories B
through PP, EPA is particularly interested in receiving comments on the
following issues:
(1) Reporting thresholds. EPA is interested in receiving data and
analyses on thresholds. In particular, we solicit comment on whether
the thresholds proposed are appropriate for each source category or
whether other emissions or capacity based thresholds should be applied.
If suggesting alternative thresholds, please discuss whether and how
they would achieve broad emissions coverage and result in a reasonable
number of reporters.
(2) Methodologies. EPA is interested in receiving data, technical
information and analyses relevant to the methodology approach. We
solicit comment on whether the methodologies selected by EPA are
appropriate for each source category or whether alternative approaches
should be adopted. In particular, EPA would like information on the
technical feasibility, costs, and relative improvement in accuracy of
direct measurement at facilities. If suggesting an alternative
methodology (e.g., using established industry default factors or
allowing industry groups to propose an industry specific emission
factor to EPA), please discuss whether and how it provides complete and
accurate emissions data, comparable to other source categories, and
also reflects broadly agreed upon calculation procedures for that
source category.
(3) Frequency and year of reporting. EPA is interested in receiving
data and analyses regarding frequency of reporting and the schedule for
reporting. In particular, we solicit information regarding whether the
frequency of data collection and reporting selected by EPA is
appropriate for each source category or whether alternative frequencies
should be considered (e.g., quarterly or every few years). If
suggesting an alternative frequency, please discuss whether and how it
ensures that EPA and the public receive the data in a timely fashion
that allow it to be relevant for future policy decisions. EPA is
proposing 2010 data collection and 2011 reporting, however, we are
interested in receiving comment on alternative schedules if we are
unable to meet our goal.
(4) Verification. EPA is interested in receiving data and analyses
regarding verification options. We solicit input on whether the
verification approach selected by EPA is appropriate for each source
category or whether an alternative approach should be adopted. If
suggesting an alternative verification approach, please discuss how it
weighs the costs and burden to the reporter and EPA as well as the need
to ensure the data are complete, accurate, and available in the timely
fashion.
(5) Duration of the program. EPA is interested in receiving data
and analyses regarding options for the duration of the GHG emissions
information collection program in this proposed rule. By duration, EPA
means for how many years the program should require the submission of
information. EPA solicits input on whether the duration selected by EPA
is appropriate for each source category or whether an alternative
approach should be adopted. If suggesting an alternative duration,
please discuss how it impacts the need to ensure the data are
sufficient to inform the variety of potential policy decisions
regarding climate change under consideration.
[[Page 16464]]
A. Rationale for Selection of GHGs To Report
The proposed rule would require reporting of CO2,
CH4, N2O, HFCs, PFCs, SF6, and other
fluorinated compounds (e.g., NF3 and HFEs) as defined in the
rule \39\. These are the most abundantly emitted GHGs that result from
human activity. They are not currently controlled by other mandatory
Federal programs and, with the exception of the CO2
emissions data reported by EGUs subject to the ARP \40\, GHG emissions
data are also not reported under other mandatory Federal programs.
CO2 is the largest contributor of GHGs directly emitted by
human activities, and is a significant driver of climate change. The
anthropogenic combined heating effect of CH4,
N2O, HFCs, PFCs, SF6, and the other fluorinated
compounds are also significant: About 40 percent as large as the
CO2 heating effect according to the Fourth Assessment Report
of the IPCC.
---------------------------------------------------------------------------
\39\ The GWPs for the GHGs to be reported are found in Table A-1
of proposed 40 CFR part 98, subpart A.
\40\ Pursuant to regulations established under section 821 of
the CAA Amendments of 1990, hourly CO2 emissions are
monitored and reported quarterly to EPA. EPA performs a series of
QA/QC checks on the data and then makes it available on the Web site
(http://epa.gov/camddataandmaps/) usually within 30 days after
receipt.
---------------------------------------------------------------------------
The IPCC focuses on CO2, CH4, N2O,
HFCs, PFCs, and SF6 for both scientific assessments and
emissions inventory purposes because these are long-lived, well-mixed
GHGs not controlled by the Montreal Protocol as Substances that Deplete
the Ozone Layer. These GHGs are directly emitted by human activities,
are reported annually in EPA's Inventory of U.S. Greenhouse Gas
Emissions and Sinks, and are the common focus of the climate change
research community. The IPCC also included methods for accounting for
emissions from several specified fluorinated gases in the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories.\41\ These gases
include fluorinated ethers, which are used in electronics, anesthetics,
and as heat transfer fluids. Like the other six GHGs for which
emissions would be reported, these fluorinated compounds are long-lived
in the atmosphere and have high GWP. In many cases these fluorinated
gases are used in expanding industries (e.g., electronics) or as
substitutes for HFCs. As such, EPA is proposing to include reporting of
these gases to ensure that the Agency has an accurate understanding of
the emissions and uses of these gases, particularly as those uses
expand.
---------------------------------------------------------------------------
\41\ 2006 IPCC Guidelines for National Greenhouse Gas
Inventories. The National Greenhouse Gas Inventories Programme, H.S.
Eggleston, L. Buendia, K. Miwa, T. Ngara, and K. Tanabe (eds),
hereafter referred to as the ``2006 IPCC Guidelines'' are found at:
http://www.ipcc.ch/ipccreports/methodology-reports.htm. For
additional information on these gases please see Table A-1 in
proposed 40 CFR part 98, subpart A and the Suppliers of Industrial
GHGs TSD (EPA-HQ-OAR-2008-0508-041).
---------------------------------------------------------------------------
There are other GHGs and aerosols that have climatic warming
effects that we are not proposing to include in this rule: Water vapor,
CFCs, HCFCs, halons, tropospheric O3, and black carbon.
There are a number of reasons why we are not proposing to require
reporting of these gases and aerosols under this rule. For example,
these GHGs and aerosols are not covered under any State or Federal
voluntary or mandatory GHG program, the UNFCCC or the Inventory of U.S.
Greenhouse Gas Emissions and Sinks. Nonetheless, we request comment on
the selection of GHGs that are or are not included in the proposed
rule; include data supporting your position on why a GHG should or
should not be included. More detailed discussions for particular
substances that we do not propose including in this rule follow.
Water Vapor. Water vapor is the most abundant naturally occurring
GHG and, therefore, makes up a significant share of the natural,
background greenhouse effect. However, water vapor emissions from human
activities have only a negligible effect on atmospheric concentrations
of water vapor. Significant changes to global atmospheric
concentrations of water vapor occur indirectly through human-induced
global warming, which then increases the amount of water vapor in the
atmosphere because a warmer atmosphere can hold more moisture.
Therefore, changes in water vapor concentrations are not an initial
driver of climate change, but rather an effect of climate change which
then acts as a positive feedback that further enhances warming. For
this reason, the IPCC does not list direct emissions of water vapor as
an anthropogenic forcing agent of climate change, but does include this
water vapor feedback mechanism in response to human-induced warming in
all modeling scenarios of future climate change. Based on this
recognition that anthropogenic emissions of water vapor are not a
significant driver of anthropogenic climate change, EPA's annual
Inventory of U.S. Greenhouse Gas Emissions and Sinks does not include
water vapor, and GHG inventory reporting guidelines under the UNFCCC do
not require data on water vapor emissions.
ODS. The CFCs, HCFCs, and halons are all strong anthropogenic GHGs
that are long-lived in the atmosphere and are adding to the global
anthropogenic heating effect. Therefore, these gases share common
climatic properties with the other GHGs discussed in this preamble. The
production and consumption of these substances (and, hence, their
anthropogenic emissions) are being controlled and phased out, not
because of their effects on climate change, but because they deplete
stratospheric O3, which protects against harmful ultraviolet
B radiation. The control and phase-out of these substances in the U.S.
and globally is occurring under the Montreal Protocol on Substances
that Deplete the Ozone Layer, and in the U.S. under Title VI of the CAA
as well.\42\ Therefore, the climate change research and policy
community typically does not focus on these substances, precisely
because they are essentially already being addressed with non-climate
policy mechanisms. The UNFCCC does not cover these substances, and
instead defers their treatment to the Montreal Protocol.
---------------------------------------------------------------------------
\42\ Under the Montreal Protocol, production and consumption of
CFCs were phased out in developed countries in 1996 (with some
essential use exemptions) and are scheduled for phase-out by 2010 in
developing countries (with some essential use exemptions). For
halons the schedule was 1994 for phase out in developed countries
and 2010 for developing countries; HCFC production was frozen in
2004 in developed countries, and in 2016 production will be frozen
in developing countries; and HCFC consumption phase-out dates are
2030 for developed countries and 2040 in developing countries.
---------------------------------------------------------------------------
Tropospheric Ozone. Increased concentrations of tropospheric
O3 are causing a significant anthropogenic warming effect,
but, unlike the long-lived GHGs, tropospheric O3 has a short
atmospheric lifetime (hours to weeks), and therefore its concentrations
are more variable over space and time. For these reasons, its global
heating effect and relevance to climate change tends to entail greater
uncertainty compared to the well-mixed, long-lived GHGs. Tropospheric
O3 is not addressed under the UNFCCC. Moreover, tropospheric
O3 is already listed as a NAAQS pollutant and its precursors
are reported to States. Tropospheric O3 is subsequently
modeled based on the precursor data reported to the NEI.
Black Carbon. Black carbon is an aerosol particle that results from
incomplete combustion of the carbon contained in fossil fuels, and it
remains in the atmosphere for about a week. There is some evidence that
black carbon emissions may contribute to climate warming by absorbing
incoming and reflected sunlight in the atmosphere and by darkening
clouds, snow and ice. While the net effect of anthropogenic aerosols
has a cooling effect (CCSP 2009), there is considerable uncertainty
[[Page 16465]]
in quantifying the effects of black carbon on radiative forcing and
whether black carbon specifically has direct or indirect warming
effects. The National Academy of Sciences states ``Regulations
targeting black carbon emissions or ozone precursors would have
combined benefits for public health and climate'' \43\ while also
indicating that the level of scientific understanding regarding the
effect of black carbon on climate is ``very low.'' The direct and
indirect radiative forcing properties of multiple aerosols, including
sulphates, organic carbon, and black carbon, are not well understood.
While mobile diesel engines have been the largest black carbon source
in the U.S., these emissions are expected to be reduced significantly
over the next several decades based on CDPFs for new vehicles.
---------------------------------------------------------------------------
\43\ National Academy of Sciences, ``Radiative Forcing of
Climate Change: Expanding the Concept and Addressing
Uncertainties,'' October 2005.
---------------------------------------------------------------------------
B. Rationale for Selection of Source Categories To Report
Section III of this preamble lists the source categories that would
submit reports under the proposed rule. The source categories
identified in this list were selected after considering the language of
the Appropriations Act and the accompanying explanatory statement, and
EPA's experience in developing the U.S. GHG Inventory. The
Appropriations Act referred to reporting ``in all sectors of the
economy'' and the explanatory statement directed EPA to include
``emissions from upstream production and downstream sources to the
extent the Administrator deems it appropriate.'' \44\ In developing the
proposed list, we also used our significant experience in quantifying
GHG emissions from source categories across the economy for the
Inventory of U.S. Greenhouse Gas Emissions and Sinks.
---------------------------------------------------------------------------
\44\ To read the full appropriations language please refer to
the links on this Web site: http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
---------------------------------------------------------------------------
As a starting point, EPA first considered all anthropogenic sources
of GHG emissions. The term ``anthropogenic'' refers to emissions that
are produced as a result of human activities (e.g., combustion of coal
in an electric utility or CH4 emissions from a landfill).
This is in contrast to GHGs that are emitted to the atmosphere as a
result of natural activities, such as volcanoes. Anthropogenic
emissions may be of biogenic origin (manure lagoons) or non-biogenic
origin (e.g., coal mines). Consistent with existing international,
national, regional, and corporate-level GHG reporting programs, this
proposal includes only anthropogenic sources.
As a second step, EPA considered all of the source categories in
the Inventory of U.S. Greenhouse Gas Emissions and Sinks because, as
described in Section I.D of this preamble, it is a top-down assessment
of anthropogenic sources of emissions in the U.S. Furthermore, the
Inventory has been independently reviewed by national and international
experts and is considered to be a comprehensive representation of
national-level GHG emissions and source categories relevant for the
U.S.
As a third step, EPA also carefully reviewed the recently completed
2006 IPCC Guidelines for National Greenhouse Gas Inventories for
additional source categories that may be relevant for the U.S. These
international guidelines are just beginning to be incorporated into
national inventories. The 2006 IPCC Guidelines identified one
additional source category for consideration (fugitive emissions from
fluorinated GHG production).
As a fourth step, once EPA had a complete list of source categories
relevant to the U.S., the Agency systematically reviewed those source
categories against the following criteria to develop the list to the
source categories included in the proposal:
(1) Include source categories that emit the most significant
amounts of GHG emissions, while also minimizing the number of
reporters, and
(2) Include source categories that can be measured with an
appropriate level of accuracy.
To accomplish the first criterion, EPA set reporting thresholds, as
described in Section IV.C of this preamble, that are designed to target
large emitters. When the proposed thresholds are applied, the source
categories included in this proposal meet the criterion of balancing
the emissions coverage with a reasonable number of reporters. For more
detailed information about the coverage of emissions and number of
reporters see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and the RIA
(EPA-HQ-OAR-2008-0508-002).
The second criterion was to require reporting for only those
sources for which measurement capabilities are sufficiently accurate
and consistent. Under this criterion, EPA considered whether or not
facility reporting would be as effective as other means of obtaining
emissions data. For some sources, our understanding of emissions is
limited by lack of knowledge of source-specific factors. In instances
where facility-specific calculations are feasible and result in
sufficiently accurate and consistent estimates, facility-level
reporting would improve current inventory estimates and EPA's
understanding of the types and levels of emissions coming from large
facilities, particularly in the industrial sector. These source
categories have been included in the proposal. For other source
categories, uncertainty about emissions is related more to the
unavailability of emission factors or simple models to estimate
emissions accurately and at a reasonable cost at the facility-level.
Under this criterion, we would require facility-level reporting only if
reporting would provide more accurate estimates than can be obtained by
other means, such as national or regional-level modeling. For an
example, please refer to the discussion below on emissions from
agricultural sources and other land uses.
As the Agency completed its four step evaluation of source
categories to include in the proposal, some source categories were
excluded from consideration and some were added. The reasons for the
additions and deletions are explained below. In general, the proposed
reporting rule covers almost all of the source categories in the
Inventory of U.S. Greenhouse Gas Emissions and Sinks and the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories.
Reporting by direct emitters. Consistent with the appropriations
language regarding reporting of emissions from ``downstream sources,''
EPA is proposing reporting requirements from facilities that directly
emit GHGs above a certain threshold as a result of combustion of fuel
or processes. The majority of the direct emitters included in this
proposal are large facilities in the electricity generation or
industrial sectors. In addition, many of the electricity generation
facilities are already reporting their CO2 emissions to EPA
under existing regulations. As such, these facilities have only a
minimal increase in the amount of data they have to provide EPA on
their CH4 and N2O emissions. The typical
industrial facilities that are required to report under this proposal
have emissions that are substantially higher than the proposed
thresholds and are already doing many of the measurements and
quantifications of emissions required by this proposal through existing
business practices, voluntary programs, or mandatory State-level GHG
reporting programs.
For more information about the thresholds included in this proposal
please refer to Section IV.C of this
[[Page 16466]]
preamble and for more information about the requirements for specific
sources refer to Section V of this preamble.
Reporting by fuel and industrial GHG suppliers. \45\ Consistent
with the appropriations language regarding reporting of emissions from
``upstream production,'' EPA is proposing reporting requirements from
upstream suppliers of fossil fuel and industrial GHGs. In the context
of GHG reporting, ``upstream emissions'' refers to the GHG emissions
potential of a quantity of industrial gas or fossil fuel supplied into
the economy. For fossil fuels, the emissions potential is the amount of
CO2 that would be produced from complete combustion or
oxidation of the carbon in the fuel. In many cases, the fossil fuels
and industrial GHGs supplied by producers and importers are used and
ultimately emitted by a large number of small sources, particularly in
the commercial and residential sectors (e.g., HFCs emitted from home A/
C units or GHG emissions from individual motor vehicles).\46\ To cover
these direct emissions would require reporting by hundreds or thousands
of small facilities. To avoid this impact, the proposed rule does not
include all of those emitters, but instead requires reporting by the
suppliers of industrial gases and suppliers of fossil fuels. Because
the GHGs in these products are almost always fully emitted during use,
reporting these supply data would provide an accurate estimate of
national emissions while substantially reducing the number of
reporters.\47\ For this reason, the proposed rule requires reporting by
suppliers of coal and coal-based products, petroleum products, natural
gas and NGLs, CO2 gas, and other industrial GHGs. We are not
proposing to require reporting by suppliers of biomass-based fuels, or
renewable fuels, due to the fact that GHGs emitted upon combustion of
these fuels are traditionally taken into account at the point of
biomass production. However, we seek comment on this approach and note
that producers of some biomass-based fuels (e.g., ethanol) would be
subject to reporting requirements for their on-site emissions under
this proposal, similar to other fuel producers. For more information
about these source categories please see the source-specific
discussions in Section V of this preamble.
---------------------------------------------------------------------------
\45\ In this context, suppliers include producers, importers,
and exporters of fossil fuels and industrial GHGs.
\46\ While EPA is not proposing any reporting requirements in
this rule for operators of mobile source fleets, we are requesting
comment in Section V.QQ.4.b of the Preamble.
\47\ As an example of estimating the CO2 emissions
that result from the combustion of fossil fuels, please see, 2006
IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2--
Energy, Chapter 1--Introduction (http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html).
---------------------------------------------------------------------------
There is inherent double-reporting of emissions in a program that
includes both upstream and downstream sources. For example, coal mines
would report CO2 emissions that would be produced from
combustion of the coal supplied into the economy, and the receiving
power plants are already reporting CO2 emissions to EPA from
burning the coal to generate electricity. This double-reporting is
nevertheless consistent with the appropriations language, and provides
valuable information to EPA and stakeholders in the development of
climate change policy and programs. Policies such as low-carbon fuel
standards can only be applied upstream, whereas end-use emission
standards can only be applied downstream. Data from upstream and
downstream sources would be necessary to formulate and assess the
impacts of such potential policies. EPA recognizes the double-reporting
and as discussed in Section I.D of this preamble does not intend to use
the upstream and downstream emissions data as a replacement for the
national emissions estimates found in the Inventory.
It is possible to construct a reporting system with no double-
reporting. For example, such a system could include fossil fuel
combustion-related emissions upstream only, based on the fuel
suppliers, supplemented by emissions reported downstream for industrial
processes at select industries (e.g., CO2 process emissions
from the production of cement); fugitive emissions from coal, oil, and
gas operations; biological processes and mobile source manufacturers.
Industrial GHG suppliers could be captured completely upstream, thereby
removing reporting obligations from the use of the industrial gases by
large downstream users (e.g., magnesium production and SF6
in electric power systems). Under this option, the total number of
facilities affected is approximately 32% lower than the proposed
option, and the private sector costs are approximately 26% lower than
the proposed option. The emissions coverage remains largely the same as
the proposed option although it is important to note that some process
related emissions may not be captured due to the fact that downstream
combustion sources would not be covered under this option. A source
with process emission plus combustion emissions would only have to
report their process emission, thus the exclusion of downstream
combustion could result in some sources being under the threshold. For
more information about this analysis and the differences in the number
of reporters and coverage of emissions, please see the RIA (EPA-HQ-OAR-
2008-0508-002).
Emissions from agricultural sources and other land uses. The
proposed rule does not require reporting of GHG emissions from enteric
fermentation, rice cultivation, field burning of agricultural residues,
composting (other than as part of a manure management system),
agricultural soil management, or other land uses and land-use changes,
such as emissions associated with deforestation, and carbon storage in
living biomass or harvested wood products. As discussed in Section V of
this preamble, the proposal does include reporting of emissions from
manure management systems.
EPA reports on the GHG emissions and sinks associated with
agricultural and land-use sources in the Inventory of U.S. Greenhouse
Gas Emissions and Sinks. In the agriculture sector, the U.S. GHG
inventory report estimated that agricultural soil management, which
includes fertilizer application (including synthetic and manure
fertilizers, etc.), contributed N2O emissions of 265 million
metric tons CO2e in 2006 and enteric fermentation
contributed CH4 emissions of 126 million metric tons
CO2e in 2006. These amounts reflect 3.8 percent and 1.8
percent of total GHG emissions from anthropogenic sources in 2006. Rice
cultivation, agricultural field burning, and composting (other than as
part of a manure management system) contributed emissions of 5.9, 1.2,
and 3.3 million metric tons CO2e, respectively in 2006.
Total carbon fluxes, rather than specific emissions from deforestation,
for U.S. forestlands and other land uses and land-use changes were also
reported in the U.S. GHG inventory report.
The challenges to including these direct emission source categories
in the rule are that practical reporting methods to estimate facility-
level emissions for these sources can be difficult to implement and can
yield uncertain results. For more information on uncertainty for these
sources, please refer to the TSD for Biological Process Sources
Excluded from this Rule (EPA-HQ-OAR-2008-0508-045). Furthermore, these
sources are characterized by a large number of small emitters. In light
of these challenges, we have determined that it is impractical to
require reporting of emissions from these sources in the proposed rule
at
[[Page 16467]]
this time for the reasons explained below.
For these sources, currently, there are no direct greenhouse gas
emission measurement methods available except for research methods that
are prohibitively expensive and require sophisticated equipment.
Instead, limited modeling-based methods have been developed for
voluntary GHG reporting protocols which use general emission factors,
and large-scale models have been developed to produce comprehensive
national-level emissions estimates, such as those reported in the U.S.
GHG inventory report.
To calculate emissions using emission factor or carbon stock change
approaches, it would be necessary for landowners to report on
management practices, and a variety of data inputs. Activity data
collection and emission factor development necessary for emissions
calculations at the scale of individual reporters can be complex and
costly.
For example, for calculating emissions of N2O from
agricultural soils, data on nitrogen inputs necessary for accurate
emissions calculations include: Synthetic fertilizer, organic
amendments (manure and sludge), waste from grazing animals, crop
residues, and mineralization of soil organic matter. While some
activity data can be collected with reasonable certainty, the emissions
estimates could still have a high degree of uncertainty because the
emission factors available for individual reporters do not reflect the
variety of conditions (e.g., soil type, moisture) that need to be
considered for accurate estimates.
Without reasonably accurate facility-level emissions factors and
the ability to accurately measure all facility-level calculation
variables at a reasonable cost to reporters, facility-level emissions
reporting would not improve our knowledge of GHG emissions relative to
national or regional-level emissions models and data available from
national databases. While a systematic measurement program of these
sources could improve understanding of the environmental factors and
management practices that influence emissions, this type of measurement
program is technically difficult and expensive to implement, and would
be better accomplished through an empirical research program that
establishes and maintains rigorous measurements over time.
Despite the issues associated with reporting by the agriculture and
land use sectors, threshold analyses were conducted for several source
categories within these sectors as part of their consideration for
inclusion in this rule. For some agricultural source categories, the
number of individual farms covered at various thresholds was estimated.
The resulting analyses showed that for most of these sources no
facilities would exceed any of the thresholds evaluated.
Because facility-level reporting is impracticable, the proposed
rule contains other provisions to improve our understanding of
emissions from these source categories. For example, agricultural soil
management is a significant source of N2O. Activity data,
including synthetic nitrogen-based fertilizer applications, influence
N2O emissions from this agricultural source category. To
gain additional information on synthetic nitrogen-based fertilizers,
EPA is proposing that the industrial facilities reporting under this
rule include information on the production and nitrogen content of
fertilizers as part of their annual reports to EPA. It is estimated
that all of the synthetic nitrogen-based fertilizer produced in the
U.S. is manufactured by industrial facilities that are covered under
this rule due to onsite combustion-related and industrial process
emissions (e.g., ammonia manufacturing facilities). The reporting
requirements are contained in proposed 40 CFR part 98, subpart A.
EPA is requesting comment on this approach. In particular, the
Agency is looking for information on the usefulness of the fertilizer
data for estimating N2O emissions from agricultural soils,
and also on including other possible reporters of synthetic nitrogen-
based fertilizers, such as fertilizer wholesalers or distributors, or
importers in order to develop a better understanding of the source of
N2O emissions from fertilizer use.
For additional background information on emissions from
agricultural sources and other land use, please refer to the TSD for
Biological Process Sources Excluded from this Rule (EPA-HQ-OAR-2008-
0508-045).
C. Rationale for Selection of Thresholds
The proposed rule would establish reporting thresholds at the
facility level.48 49 50 Only those facilities that exceed a
threshold as specified in proposed 40 CFR part 98, subpart A would be
required to submit annual GHG reports.
---------------------------------------------------------------------------
\48\ Facilities reporting under this rule will likely have more
than one source category within their facility (e.g., a petroleum
refinery would have to report on its refinery process, combustion,
landfill and wastewater emissions).
\49\ For the purposes of this rule, facility means any physical
property, plant, building, structure, source, or stationary
equipment located on one or more contiguous or adjacent properties
in actual physical contact or separated solely by a public roadway
or other public right-of-way and under common ownership or common
control, that emits or may emit any greenhouse gas. Operators of
military installations may classify such installations as more than
a single facility based on distinct and independent functional
groupings within contiguous military properties.
\50\ A different threshold approach is proposed for vehicle and
engine manufacturers (when reporting emissions from the vehicles and
engines the produce). Here, EPA proposes to exempt small businesses
from reporting requirements, instead of applying an emission-based
threshold.
---------------------------------------------------------------------------
The thresholds are expressed in several ways (e.g., actual
emissions or capacity). The use of these different types of thresholds
is discussed later in this section, but most correspond to an annual
facility-wide emission level of 25,000 metric tons of CO2e,
and the thresholds result in covering approximately 85-90 percent of
U.S. emissions. That level is largely consistent with many of the
existing GHG reporting programs, including California, which also has a
25,000 metric ton of CO2e threshold. Furthermore, many
industry stakeholders that EPA met with expressed support for a 25,000
metric ton of CO2e threshold because it sufficiently
captures the majority of GHG emissions in the U.S., while excluding
smaller facilities and sources.\51\ The three exceptions to the 25,000
metric ton of CO2e threshold are electricity production at
selected units subject to existing Federal programs, fugitive emissions
from coal mining, and emissions from mobile sources. These thresholds
were selected to be consistent with existing thresholds for reporting
similar data to EPA and the MSHA. The proposed thresholds maximized the
rule coverage with over 85 percent of U.S. emissions reported by
approximately 13,000 reporters, while keeping reporting burden to a
minimum and excluding small emitters.
---------------------------------------------------------------------------
\51\ To view a summary of EPA's outreach efforts please refer to
EPA-HQ-OAR-2008-0508-055.
---------------------------------------------------------------------------
Consideration of alternative emissions thresholds. In selecting the
proposed threshold level, we considered two lower emission threshold
alternatives and one higher alternative. We collected available data on
each industry and analyzed the implication of various thresholds in
terms of number of facilities and level of emissions covered at both
the industry level and the national level. We also performed a similar
analysis for each proposed source category to determine if there were
reasons to develop a different threshold in specific industry sectors.
From these analyses, we concluded that a 25,000 metric ton threshold
suited the needs of the reporting program by providing comprehensive
coverage of
[[Page 16468]]
emissions with a reasonable number of reporters and that having a
uniform threshold was an equitable approach. This conclusion took into
account our finding that a threshold other than 25,000 metric tons of
CO2e might appear to achieve an appropriate balance between
number of facilities and emissions covered for a limited number of
source categories. Our conclusions about the alternative thresholds are
summarized below and in the Thresholds TSD (EPA-HQ-OAR-2008-0508-046),
and the considerations for individual source categories are explained
in Section V of this preamble.
The lower threshold alternatives that we considered were 1,000
metric tons of CO2e per year, and 10,000 metric tons of
CO2e per year. Both broaden national emissions coverage but
do so by disproportionately increasing the number of affected
facilities (e.g., increasing the number of reporters by an order of
magnitude in the case of a 1,000 metric tons CO2e/yr
threshold and doubling the number of reporters in the case of a 10,000
metric tons CO2e/yr threshold). The majority of stakeholders
were opposed to these lower thresholds for that reason--the gains in
emissions coverage are not adequately balanced against the increased
number of affected facilities.
A 1,000 metric ton of CO2e per year threshold would
increase the number of affected facilities by an order of magnitude
over the proposed threshold. The effect of a 1,000 metric ton threshold
would be to change the focus of the program from large to small
emitters. This threshold would impose reporting costs on tens of
thousands of small businesses that in total would amount to less than
10 percent of national GHG emissions.
A 10,000 metric ton of CO2e per year threshold
approximately doubles the number of facilities affected compared to a
25,000 metric ton threshold. The effect of a 10,000 metric ton
threshold would only improve national emissions coverage by
approximately 1 percent. The extra data that would result from a 10,000
metric ton threshold would do little to further the objectives of the
program. EPA believes the 25,000 metric ton threshold more effectively
targets large industrial emitters, which are responsible for some 90
percent of U.S. emissions. Similarly, California's mandatory GHG
reporting program also based their selection of a 25,000 metric ton
threshold on similar results at the State level.\52\
---------------------------------------------------------------------------
\52\ For more information on CA analysis please see http://www.arb.ca.gov/regact/2007/ghg2007/isor.pdf.
---------------------------------------------------------------------------
We also considered 100,000 metric tons of CO2e per year
as an alternative threshold but concluded that it fails to satisfy two
key objectives. First, it may exclude enough emitters in certain source
categories such that the emissions data would not adequately cover key
sectors of the economy. At 100,000 metric tons CO2e per
year, reporting for several large industry sectors would be rather
significantly fragmented, resulting in an incomplete picture of direct
emissions from that sector. For example, at a 100,000 metric ton of
CO2e threshold in ammonia manufacturing, approximately 22
out of 24 facilities would have to report; in nitric acid production,
approximately 40 out of 45 facilities would have to report; in lime
manufacturing, 52 out of 89 facilities would have to report; and in
pulp and paper, 410 out of 425 facilities would have to report. Several
stakeholders we met with stressed this potential fragmentation as a
concern and requested that EPA include all facilities in a particular
sector to simplify compliance, even if there was some uncertainty about
whether all facilities in an industry would technically meet a
particular threshold. For more information about the impact of
thresholds on different industries, please see the source-specific
discussion in Section V of this preamble.
The data collected by this rulemaking is intended to support
analyses of future policy options. Those options may depend on
harmonization with State or even international reporting programs.
Several States and regional GHG programs are using thresholds that are
comparable in scope to a 25,000 metric ton of CO2e per year
threshold.\53\ As noted earlier, California specifically chose a
threshold of 25,000 metric ton of CO2e after analyzing
CO2 data from the air quality management districts because
they concluded that level provided the correct balance of emissions
coverage and number of reporters. Implementing a national reporting
program using a 100,000, 10,000 or 1,000 metric ton of CO2e
per year limit would result in a fragmentary dataset insufficient in
detail or coverage, or a more burdensome reporting requirement, and
these options would be inconsistent with what many other GHG programs
are requiring today.
---------------------------------------------------------------------------
\53\ For more information about what different States are
requiring, see section II of this preamble, the ``Summary of
Existing State GHG Rules'' memorandum and ``Review of Existing
Programs'' memorandum found at EPA-HQ-OAR-2008-0508-056 and 054.
---------------------------------------------------------------------------
In addition to the typical emissions thresholds associated with GHG
reporting and reduction programs (e.g., 25,000 metric tons
CO2e), under the CAA, there are (1) the Title V program that
requires all major stationary sources, including all sources that emit
or have the potential to emit over 100 tons per year of an air
pollutant, to hold an operating permit \54\ and (2) the PSD/NSR program
that requires new major sources and sources that are undergoing major
modifications to obtain a permit. A major source for PSD is defined as
any source that emits or has the potential to emit either 100 or 250
tons per year of a regulated pollutant, dependent on the source
category.\55\ In nonattainment areas, the major source threshold for
NSR is at most 100 tons per year, and is less in some areas depending
on the pollutant and the nonattainment classification of the area.
---------------------------------------------------------------------------
\54\ Other sources required to obtain Title V operating permits
include all sources that are required to have PSD permits,
``affected sources'' under the ARP, and sources subject to NSPS or
NESHAP (although non-major sources under those programs can be
exempted by rule).
\55\ The 100 tons per year level is the level at which existing
sources in 28 industry categories listed in the CAA are classified
as major sources for the PSD program. The 250 tons per year level is
the level at which existing sources in all other categories are
classified as major sources for PSD purposes.
---------------------------------------------------------------------------
EPA performed some preliminary analyses to generally estimate the
existing stock of major sources in order to then estimate the
approximate number of new facilities that could be required to obtain
NSR/PSD permits.\56\ For example, if the 100 and 250 tons per year
thresholds were applied in the context of GHGs, the Agency estimates
the number of PSD permits required to be issued each year would
increase by more than a factor of 10 (i.e., more than 2,000 to 3,000
permits per year). The additional permits would generally be issued to
smaller industrial sources, as well as large office and residential
buildings, hotels, large retail establishments, and similar facilities.
---------------------------------------------------------------------------
\56\ For more information about the major source analysis please
see docket number EPA-HQ-OAR-2008-0318.
---------------------------------------------------------------------------
For more information about the affect of thresholds considered for
this rule on the number of reporters, emissions coverage and costs,
please see Table VIII-2 in Section VIII of this preamble and Table IV-
47 of the RIA found at EPA-HQ-OAR-2008-0508-002.
Determining applicability to the rule. The thresholds listed in
proposed 40 CFR part 98, subpart A fall into three groups: Capacity,
emissions, or ``all in.'' The thresholds developed are generally
equivalent to a threshold of 25,000 metric tons of CO2e per
year of actual emissions.
EPA carefully examined thresholds and source categories that might
be able
[[Page 16469]]
to report utilizing a capacity metric, for example, tons of product
produced per year. A capacity-based threshold could be the least
burdensome alternative for reporting because a facility would not have
to estimate emissions to determine if the rule applies. However, EPA
faced two key challenges in trying to develop capacity thresholds.
First, in most cases we did not have sufficient data to determine an
appropriate capacity threshold. Secondly, for some source categories
defining the appropriate capacity metric was not feasible. For example,
for some source categories, GHG emissions are not related to production
capacity, but are more affected by design and operating factors.
The scope of the proposed emission threshold is emissions from all
applicable source categories located within the physical boundary of a
facility. To determine emissions to compare to the threshold, a
facility that directly emits GHGs would estimate total emissions from
all source categories for which emission estimation methods are
provided in proposed 40 CFR part 98, subparts C through JJ. The use of
total emissions is necessary because some facilities are comprised of
multiple process units or collocated source categories that
individually may not be large emitters, but that emit significant
levels of GHGs collectively. The calculation of total emissions for the
purposes of determining whether a facility exceeds the threshold should
not include biogenic CO2 emissions (e.g., those resulting
from combustion of biofuels). Therefore, these emissions, while
accounted for and reported separately, are not considered in a
facility's emissions totals.
In order to ensure that the reporting of GHG emissions from all
source categories within a facility's boundaries is not unduly
burdensome, EPA has proposed flexibility in two ways. First, a facility
would only have to report on the source categories for which there are
methods provided in this rule. EPA has proposed methods only for source
categories that typically contribute a relatively significant amount to
a facility's total GHG emissions (e.g., EPA has not provided a method
for a facility to account for the CH4 emissions from coal
piles). Second, for small facilities, EPA has proposed simplified
emission estimation methods where feasible (e.g., stationary combustion
equipment under a certain rating can use a simplified mass balance
approach as opposed to more rigorous direct monitoring).
The proposed emissions threshold is based on actual emissions, with
a few exceptions described below. An actual emission metric accounts
for actual operating practices at each facility. A threshold based on
potential emissions would bring in far more facilities including many
small emitters. For example, under a potential emissions threshold, a
facility that operates one shift a day would have to estimate emissions
assuming three shifts per day, and would have to assume continuous use
of feedstocks or fuels that result in the highest rate of GHG emissions
absent enforceable limitations. Such an approach would be inconsistent
with the twin goals of collecting accurate data on actual GHG emissions
to the atmosphere and excluding small emitters from the rule. However,
we note that emissions thresholds in some CAA rules are based on actual
or potential emissions. Moreover, although actual emissions may change
year to year due to fluctuations in the market and other factors,
potential emissions are less subject to yearly fluctuations. We solicit
comment on how considerations of actual and potential emissions should
be incorporated into the proposed threshold.
There is one source category that has a proposed threshold based on
GHG generation instead of emissions--municipal landfills. In this case,
a GHG generation threshold is more appropriate because some landfills
have installed CH4 gas recovery systems. A gas recovery
system collects a percentage of the generated CH4, and
destroys it, through flaring or use in energy recovery equipment. The
use of a threshold based on GHG generation prior to recovery is
proposed because it ensures reporting from landfills that have similar
CH4 emission generating activities (e.g., ensures that
landfills of similar size and management practices are reporting).
As described in Section III of this preamble, in the case of 19
source categories all of the facilities that have that particular
source category within their boundaries would be subject to the
proposed rule. For these facilities, our analysis indicated that all
facilities with that source category emit more than 25,000 metric tons
of CO2e per year or that only a few facilities emit
marginally below this level. These source categories include large
manufacturing operations such as petroleum refineries and cement
production. This simplifies the applicability determination for
facilities with these source categories.
When determining if a facility passes a relevant applicability
threshold, direct emissions from the source categories would be
assessed separately from the emissions from the supplier categories.
For example, a company that produces and supplies coal would be subject
to reporting as a supplier of coal (40 CFR part 98, subpart KK),
because coal suppliers is an ``all in'' supplier category. But the
company would separately evaluate whether or not emissions from their
underground coal mines (40 CFR part 98, subpart FF) would also be
reported.
In addition, the source categories listed in proposed 40 CFR
98.2(a)(1) and (2) and the supply operations listed in proposed 40 CFR
98.2(a)(4) represent EPA's best estimate of the large emitters of GHGs
or large suppliers of fuel and industrial GHGs. In order to ensure that
all large emitters are included in this reporting program, proposed 40
CFR 98.2(a)(3) also covers any facility that emits more than 25,000
metric tons of CO2e per year from stationary fuel combustion
units at source categories that are not listed in proposed 40 CFR
98.2(a)(2). To minimize the reporting burden, such facilities would be
required to submit an annual report that covers stationary combustion
emissions.
Furthermore, we recognize that a potentially large number of
facilities would need to calculate their emissions in order to
determine whether or not they had to report under proposed 40 CFR
98.2(a)(3). Therefore, to further minimize the burden on those
facilities, we are proposing that any facility that has an aggregate
maximum rated heat input capacity of the stationary fuel combustion
units less than 30 mmBtu/hr may presume it has emissions below the
threshold. According to our analysis, a facility with stationary
combustion units that have a maximum rated heat input capacity of less
that 30 mmBtu/hr, operating full time (e.g., 8,760 hours per year) with
all types of fossil fuel would not exceed 25,000 metric tons
CO2e/yr (EPA-HQ-OAR-2008-0508-049). Under this approach, we
estimate that approximately 30,000 facilities would have to assess
whether or not they had to report according to proposed 40 CFR
98.2(a)(3).\57\ Of the 30,000, approximately 13,000 facilities would
likely meet the threshold and have to report. Therefore, an additional
17,000 facilities may have to assess their applicability but
potentially not meet the threshold for reporting. We concluded that is
a reasonable number of assessments in order to ensure all
[[Page 16470]]
large emitters in the U.S. are included in this reporting program. We
are seeking comment on (1) whether the presumption for maximum rated
heat input capacity of 30 mmBtu/hr is appropriate, (2) whether a
different (lower or higher) mmBtu/hr capacity presumption should be set
and (3) whether other capacity thresholds should be developed for
different types of facilities. The comments should contain data and
analysis to support the use of different thresholds.
---------------------------------------------------------------------------
\57\ This estimate is based on the Energy and Environmental
Analysis, ``Characterization of the U.S. Industrial/Commercial
Boiler Population'' (2005) (EPA-HQ-OAR-2008-0508-050). We assumed 3
boilers per manufacturing facility and 1 boiler per commercial
facility. For additional information on the impact to these 30,000
facilities, please see the ICR and RIA (EPA-HQ-OAR-2008-0508-002).
---------------------------------------------------------------------------
We are proposing that once a facility is subject to this reporting
rule, it would continue to submit annual reports even if it falls below
the reporting thresholds in future years. (As discussed in section
IV.K. of this preamble, EPA is proposing that this rule require the
submission of data into the foreseeable future, although EPA is
soliciting comment on other options.) The purpose of the thresholds is
to exclude small sources from reporting. For sources that trigger the
thresholds, it is important for the purpose of policy analysis to be
able to track trends in emissions and understand factors that influence
emission levels. The data would be most useful if the population of
reporting sources is consistent, complete and not varying over time.
The one exception to the proposed requirement to continue
submitting reports even if a facility falls below the reporting
threshold is active underground coal mines. When coal is no longer
produced at a mine, the mine often becomes abandoned. As discussed in
Section V.FF of this preamble, we are proposing to exclude abandoned
coal mines from the proposed rule, and therefore methods are not
proposed for this source category.
We recognize that in some cases, this provision of ``once in,
always in'' could potentially act as a disincentive for some facilities
to reduce their emissions because under this proposal those facilities
that did lower their emissions below the treshold would have to
continue to report. To address this issue in California, CARB's
mandatory reporting rule offers a facility that has emissions under the
threshold for three consecutive years the opportunity to be exempt from
the reporting program. We request comment on whether EPA should develop
a similar process for this reporting program. Comments should include
specifics on how the exemption process could work, e.g., the number of
years a facility is under the threshold before they could be exempt,
the quantity of emissions reductions required before a facility could
be exempt, whether a facility should formally apply to EPA for an
exemption or if it is automatic, etc.
EPA requests comment on the need for developing simplified
emissions calculation tools for certain source categories to assist
potential reporters in determining applicability. These simplified
calculation tools would provide conservatively high emission estimates
as an aid in identifying facilities that could be subject to the rule.
Actual facility applicability would be determined using the methods
presented for each source category in the rule.
For additional information about the threshold analysis EPA
conducted see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and the
individual source category discussions in Section V of this preamble.
In addition, Section V.QQ of this preamble describes the threshold for
vehicle and engine manufacturers, which is a different approach from
what is described in this section.
D. Rationale for Selection of Level of Reporting
EPA is proposing facility-level reporting for most source
categories under this program. Specifically, the owner or operator of a
facility would be required to report its GHG emissions from all source
categories for which there are methods developed and listed in this
proposal. For example, a petroleum refinery would have to report its
emissions resulting from stationary combustion, production processes,
and any fugitive or biological emissions. Facility-level reporting by
owners or operators is consistent with other CAA or State-level
regulatory programs that typically require facility or unit level data
and compliance (e.g., ARP, NSPS, RGGI, and the California and New
Mexico mandatory GHG reporting rules). This approach allows flexibility
for firms to determine whether the owner or operator of the facility
would report and avoid the challenges of establishing complex reporting
rules based on equity or operational control.
In addition to reporting emissions at the total facility level, the
emissions would also be broken out by source category (e.g., a
petroleum refinery would separately identify its emissions for refinery
production processes, wastewater, onsite landfills, and any other
source categories listed in proposed 40 CFR part 98, subpart A that are
located onsite). This would enable EPA to understand what types of
emission sources are being reported, determine that the facility is
reporting for all required source categories, and use the source-
category specific estimates for future policy development. Within each
source category, further breakout of emissions by process or unit may
be specified. Information on process or unit-level reporting and
associated rationale is contained in the source category sections
within Section V of this preamble.
Although many voluntary programs such as Climate Leaders or TCR
have corporate-level reporting systems, EPA concluded that corporate-
level reporting is overly complex under a mandatory system involving
many reporters and thus is not appropriate for this rule, except where
discussed below. Complex ownership structures and the frequent changes
in ownership structure make it difficult to establish accountability
over time and ensure consistent and uniform data collection at the
facility-level. Because the best technical knowledge of emitting
processes and emission levels exists at the facility level, this is
where responsibility for reporting should be placed. Furthermore, the
ability to differentiate and track the level and type of emissions by
facility, unit or process, is essential for development of certain
types of future policy (e.g., NSPS).
The only exception to facility level reporting is for some supplier
source categories (e.g., importers of fuels and industrial GHGs or
manufacturers of motor vehicles and engines). Importers are not
individual facilities in the traditional sense of the word. The type of
information reported by motor vehicle and engine manufacturers is an
extension of long-standing existing reporting requirements (e.g.,
reporting of criteria emissions rates from vehicle and engine
manufacturers) and as such does not necessitate a change in reporting
level. The reporting level for these source categories is specified in
Section V of this preamble.
E. Rationale for Selecting the Reporting Year
EPA is proposing that the monitoring and reporting requirements
would start on January 1, 2010.\58\ The first report to EPA would be
submitted by March 31, 2011, and would cover calendar year 2010. The
year 2011 is therefore referred to as the first reporting year, and
includes 2010 data (there is a discussion later in this section that
takes comment on alternative approaches to the reporting year). EPA is
requesting comment on whether or not we should select an alternative
reporting date that
[[Page 16471]]
corresponds with the requirements of an existing reporting system.
---------------------------------------------------------------------------
\58\ The exception is for vehicle and engine manufacturers when
reporting emissions from the vehicles and engines they produce. For
these sources, reporting requirements would apply beginning with the
2011 model year.
---------------------------------------------------------------------------
For existing facilities that meet the applicability criteria in
proposed 40 CFR part 98, subpart A, monitoring would begin on January
1, 2010. For new facilities that begin operation after January 1, 2010,
monitoring would begin with the first month that the facility is
operating and end on December 31 of that same calendar year in which
they start operating. Each subsequent monitoring year would begin on
January 1 and end on December 31 of each calendar year. EPA is
proposing that new facilities monitor and report emissions for the
first partial year after they begin operating so that EPA has as
complete an inventory as possible of GHG emissions for each calendar
year.
Due to the comprehensive reporting and monitoring requirements in
this proposal, the Agency has concluded that it is not appropriate to
require reporting of historical emissions data for years before 2010.
Compiling, submitting, and verifying historical data according to the
methodologies specified in this rule would create additional burdens on
both the affected facilities and the Agency, and much of the needed
data might not be available. Because Federal policy for GHG emissions
is still being developed, the Agency's focus is on collecting data of
known quality that is generated on a consistent basis. Collecting
historic emissions data would introduce data of unknown quality that
would not be comparable to the data reported under the program for
years 2011 and beyond.
The first year of monitoring for existing facilities would begin on
January 1, 2010. This schedule would give existing facilities lead time
after the date the rule is promulgated to prepare for monitoring and
reporting. Preparation would include studying the final rule,
determining whether it applies to the facility, identifying the
requirements with which the facility must comply, and preparing to
monitor and collect the required data needed to calculate and report
GHG emissions.
A beginning date of January 1, 2010 would allow sufficient time to
begin monitoring and collecting data because many of the parameters
that would need to be monitored under the proposed rule are already
monitored by facilities for process management and accounting reasons
(e.g., feedstock input rates, production output, fuel purchases). In
addition, the monitoring methods specified by the rule are already
well-known and documented; and monitoring devices required by the rule
are routinely available, in ready supply (e.g., flow meters, automatic
data recorders), and in some cases already installed. These same
monitoring devices are already required by other air quality programs
with which many of these same facilities are already complying.
It is reasonable for new sources that start operation after January
1, 2010, to begin monitoring the first month of operation because new
sources would be aware of the rule requirements when they design the
facility and its processes and obtain permits. They can plan the data
collection and reporting processes and install needed monitoring
equipment as they build the facility and begin operating the monitoring
equipment when they begin operating the facility.
We recognize that although the Agency plans to issue the final rule
in sufficient time to begin monitoring on January 1, 2010, we may be
unable to meet that goal. Therefore, we are interested in receiving
comments on alternative effective dates, including the following two
options:
Report 2010 data in 2011 using best available data: Under
this scenario, the rule would be effective January 1, 2010, allowing
affected facilities to use either the methods in proposed 40 CFR part
98 or best available data. As in the current proposal, the report would
be submitted on March 31, 2011, and then full data collection, using
the methods in 40 CFR part 98 would begin in 2011, with that report
sent to EPA on March 31, 2012. Under this approach, EPA solicits
comment on the types of best available data and methods that should be
allowed in 2010, by source category, (e.g., fuel consumption, emissions
by process, default emissions factors, fuel receipts, etc.) as well as
additional basic data that should be reported (e.g., facility name,
location). This approach is similar to the CARB mandatory reporting
rule, which allowed affected facilities to report 2009 emissions in
2010 using best available data, and then requires 2010 data collection
in 2011 using the methods in the rule. The advantages of this approach
are that the dates of the proposal remain intact and EPA receives basic
information, including emissions and fuel data from all affected
facilities in 2011. Furthermore, this approach can ease facilities into
the program by giving them potentially a full year to implement the
required methods and install any necessary equipment. For example, this
option encourages the use of the methods in 40 CFR part 98 but if that
is not possible, it allows the use of best available data (e.g., if a
facility does not have a required flow meter installed for 2010 they
can substitute the data from their fuel receipts in the calculation).
The disadvantage of this approach is that it delays full data
collection using the methods in the rule by 1 year from what is
proposed. Further, in some cases, this approach could lead to data that
is of lesser quality than the data we would receive using the methods
in 40 CFR part 98. In other cases, because sources are already
following the methods in 40 CFR part 98 (e.g., stationary combustion
units in the ARP), the quality of the data would remain unchanged under
this option. Given the objective of this rule to collect comprehensive
and accurate data to inform future policies and the interest in
Congress in developing climate change legislation, any delay in
receiving that data could adversely affect the ability to inform those
policies. That said, the data we would receive in 2011 under this
option would at least provide basic information about the types,
locations, emissions and fuel consumption from facilities in the United
States.
Report 2011 data in 2012: Under this scenario, the rule
would require that affected facilities begin collecting data January 1,
2011 and submit the first reports to EPA on March 31, 2012. The methods
in the proposed rule would remain unchanged and the only difference is
that this option would delay implementation of the rule by one year.
The advantages of this approach are that affected facilities would have
a substantial amount of time to prepare for this reporting rule,
including implementing the method and installing equipment. In
addition, we would have even more time to conduct outreach and guidance
to affected facilities. The disadvantages of this approach are that it
delays implementation of this rule by a year and does not offer a
mechanism for EPA to receive crucial data, even basic data, necessary
to inform future policy and regulatory development. Furthermore, in
some cases affected facilities are already implementing the methods
required by proposed 40 CFR part 98 (e.g., stationary combustion units
in the ARP) or are familiar with the methods, and have all of the
necessary equipment or processes in place to monitor emissions
consistent with the methods in 40 CFR part 98. Therefore, delaying
implementation by a year not only deprives EPA of valuable data to
support future policy development, but at the same time, does not
provide any real advantage to these facilities.
Proposed 40 CFR part 98, subpart A, specifies numerical reporting
thresholds for different direct emitters or supply
[[Page 16472]]
operations. A facility or supply operation that exceeds any of these
reporting thresholds in 2010 would submit a full emissions report in
reporting year 2011, which contains calendar year 2010 data. The
facilities and supply operations that contain many of the source
categories that are listed in 40 CFR part 98, subpart A are larger
facilities that have been participating in a variety of mandatory and
voluntary GHG emissions programs. Therefore, those facilities and
supply operations should be familiar with the methods and able to
comply with the requirements and submit a full report without
significant burden.
As discussed earlier, if a facility does not have any of the source
categories listed in proposed 40 CFR 98.2 (a)(1) or (2), but has
stationary combustion onsite that exceeds the GHG reporting threshold
in 2010, they would still be required to estimate GHG emissions in 2010
and report in 2011. However, because those facilities would not contain
any of the source categories specifically identified in proposed 40 CFR
98.2 (a)(1) or (2) and tend to be smaller facilities in diverse
industrial sectors, they may require some extra time to implement the
requirements of this rule. As such, they would be allowed to use an
abbreviated facility report using simplified emission estimation
methods for the first year (i.e., for calendar year 2010) and would not
be required to complete a full report until the second reporting year
(i.e., 2012).
The abbreviated report would allow the facility to use default
fuel-specific CO2 emission factors. They would not be
required to determine actual fuel carbon content or to use a CEMS to
determine CO2 emissions, as they may otherwise be required
to do with a full report. This provision for abbreviated reporting
requirements has been proposed because there are potentially many
facilities that are not in the listed industries, but are required to
report solely due to stationary combustion sources at their facility.
These include numerous and diverse sources in a wide variety of
industries, some of which may not be as familiar with GHG monitoring
and reporting. Such sources may often need more time to determine if
they are above the threshold and subject to the rule and, if they are,
to implement the full monitoring and reporting systems required.
Therefore, the abbreviated report with simpler estimating methodologies
is being proposed for these sources for the first year of monitoring
and reporting.
EPA proposes that the annual GHG emissions reports would be
submitted no later than March 31 for the previous calendar year's
reporting period. Three months is a reasonable time to compile and
review the information needed for the annual GHG emissions report and
to prepare and submit the report. The data needed to estimate emissions
and compile the report would be collected by the facility on an ongoing
basis throughout the year, so facilities could begin data summary
during the year as the data are collected. For example, they could
compile needed GHG calculation input data (e.g., fuel use or raw
material consumption data) or emission data on a periodic basis (e.g.,
monthly or quarterly) throughout the year and then total it at the end
of the year. Therefore, only the most recently collected information
would need to be compiled and a final set of calculations would need to
be performed before the final report is assembled. Given the nature of
the methodologies contained in the rule, three months is sufficient
time to calculate emissions, quality-assure, certify, and submit the
data.
F. Rationale for Selecting the Frequency of Reporting
EPA is proposing that all affected facilities would have to submit
annual GHG emission reports. Facilities with ARP units that report
CO2 emissions data to EPA on a quarterly basis would
continue to submit quarterly reports as required by 40 CFR part 75, in
addition to providing the annual GHG reports. The annual CO2
mass emissions from the ARP reports would simply be converted to metric
tons and included in the GHG report. This approach should not impose a
significant burden on ARP sources.
We have determined that annual reporting is sufficient for policy
development. It is consistent with other existing mandatory and
voluntary GHG reporting programs at the State and Federal levels (e.g.,
TCR, several individual State mandatory GHG reporting rules, EPA
voluntary partnership programs, the DOE voluntary GHG registry).
However, as future policies develop it may be necessary to reconsider
the reporting frequency and require more or less frequent reporting
(e.g., quarterly or every few years). For example, under future
programs or policy initiatives, particularly if regulatory in nature
(e.g., a cap-and-trade program similar to the ARP) it may be more
appropriate require quarterly reporting.
G. Rationale for the Emissions Information To Report
1. General Content of Reports
Generally, we propose that facilities report emissions for all
source categories at the facility for which methods have been defined
in any subpart of proposed 40 CFR part 98. Facilities would report (1)
total annual GHG emissions in metric tons CO2e and (2)
separately present annual mass emissions of each individual GHG for
each source category at the facility .\59\ Reporting of CO2e
allows a comparison of total GHG emissions across facilities in varying
categories which emit different GHGs. Knowledge of both individual
gases emitted and total CO2e emissions would be valuable for
future policy development and help EPA quantify the relative
contribution of each gas to a source category's emissions, while
maintaining the transparency of reporting total mass of individual
gases released by facility, unit, or process.
---------------------------------------------------------------------------
\59\ Consistent with the IPCC, the CARB reporting rule and the
EU Emission Trading System, the proposed rule requires units to
separately report the biogenic portion of their total annual
CO2 emissions.
---------------------------------------------------------------------------
Emissions would be reported at the level (facility, process, unit)
at which the emission calculation methods are specified in each
applicable subpart. For example, if a pulp and paper mill has three
boilers and a wastewater treatment operation, the facility would report
emissions for each boiler (according to the methodologies presented in
proposed 40 CFR part 98, subpart C), the wastewater treatment operation
(according to proposed 40 CFR part 98, subpart II), and from chemical
recovery units, lime kilns, and makeup chemicals (according to proposed
40 CFR part 98, subpart AA). In addition, the report would include
summary information on certain process operating data that influence
the level of emissions and that are necessary to calculate GHG
emissions and verify those calculations using the methodologies in the
rule. Examples of these data include fuel type and amount, raw material
inputs, or production output. The specific process information to
report varies for each source category and is specified in each
subpart.
Furthermore, in addition to any specific requirements for reporting
emissions from electricity generation in Sections V.C and V.D of this
preamble, EPA is proposing that all facilities and supply operations
affected by this rule would also report the quantity of electricity
generated onsite. The generation of onsite electricity can
[[Page 16473]]
represent a relatively significant fraction of onsite fuel use. We seek
comment on whether this information would be useful to support future
climate policy development, given the other data related to GHG
emissions from electricity generation already collected under other
sections of this proposed rule. At this point, we do not propose
separate reporting of the onsite electricity generation by generation
source (e.g., combined heat and power or renewable or fossil-based) due
to the burden on reporters, but we recognize the potential value of
being able to discern the quantity of electricity being generated from
renewable and non-renewable sources. We are seeking comment on the
value of collecting this data; and if it is collected, whether there is
a need to separately report the kilowatt-hours by type of generation
source.
We are also taking comment on, but not proposing at this time,
requiring facilities and supply operations affected by the proposed
rule to also report the quantity of electricity purchased. For many
industrial facilities, purchased electricity represents a large part of
onsite energy consumption, and their overall GHG emissions footprint
when taking into account the indirect emissions from fossil fuel
combusted for the electricity generated. Together, the reporting of
electricity purchase data and onsite generation could provide a better
understanding of how electricity is used in the economy and the major
industry sectors.
Many existing reporting programs require reporting of indirect
emissions (e.g., Climate Leaders, CARB, TCR, DOE 1605(b) program). In
general, the protocols for these programs follow the methods developed
by WRI/WBCSD for the quantification and reporting of indirect emissions
from the purchase of electricity. The WRI/WBCSD protocol outlines three
scopes to help delineate direct and indirect emission sources, with the
stated goal to improve transparency, and provide utility for different
types of organizations and different types of climate policies and
business goals. Scope 1 includes direct GHG emissions occurring from
sources that are owned or controlled by the business. Scope 2 includes
indirect GHG emissions resulting from the generation of purchased
electricity, heat, and/or steam. Scope 3 is optional and includes other
types of indirect emissions (e.g., from production of purchased
materials, waste disposal or employee transportation).
We are taking comment on, but not proposing at this time, an
approach that would require the reporting of electricity purchase data,
and not indirect emissions, because these data are more readily
available to all facilities. Through the review of existing reporting
programs that require the reporting of indirect emissions data it was
determined that there are multiple ways proposed to calculate indirect
emissions from electricity purchases. This reflects the challenge
associated with determining the specific fossil fuel mix used to
generate the electricity consumed by a facility, and thus the indirect
emissions that should be attributed to the facility. Although indirect
emissions data would not be directly reported under this approach, it
would enable indirect emissions for facilities to be calculated. This
option also would be the least burdensome to reporting facilities since
the data would be easily available.
The information that is proposed to be reported reflects the data
that could support analyses of GHG emissions for future policy
development and ensure the data are accurate and comparable across
source categories. Besides total facility emissions, it benefits
policymakers to understand: (1) The specific sources of the emissions
and the amounts emitted by each unit/process to effectively interpret
the data, and (2) the effect of different processes, fuels, and
feedstocks on emissions. This level of reporting should not be overly
burdensome because many of these data already are routinely monitored
and recorded by facilities for business reasons. The remainder of the
reported data would need to be collected to determine GHG emissions.
The report would contain a signed certification from a
representative designated by the owner or operator of a facility
affected by this rule. This ``Designated Representative'' would act as
a legal representative between the source and the Agency. The use of
the Designated Representative would simplify the administration of the
program while ensuring the accountability of an owner or operator for
emission reports and other requirements of the mandatory GHG reporting
rule. The Designated Representative would certify that data submitted
are complete, true, and accurate. The Designated Representative could
appoint an alternate to act on their behalf, but the Designated
Representative would maintain legal responsibility for the submission
of complete, true, and accurate emissions data and supplemental data.
Besides these general reporting requirements, the specific
reporting requirements for each source category are described in the
methodological discussions in Section V of this preamble.
2. De minimis Reporting for Minor Emission Points
A number of existing GHG reporting programs contain ``de minimis''
provisions. The goal of a de minimis provision is to avoid imposing
excessive reporting costs on minor emission points that can be
burdensome or infeasible to monitor. Existing GHG reporting programs
recognize that it may not be possible or efficient to specify the
reporting methods for every source that must be reported and,
therefore, have some type of provision to reduce the burden for smaller
emissions sources. Depending on the program, the reporter is allowed to
either not report a subset of emissions (e.g., 2 to 5 percent of
facility-level emissions) or use simplified calculation methods for de
minimis sources.
We analyzed the de minimis provisions of existing reporting rules
and concluded that there is no need to exclude a percentage of
emissions from reporting under this proposal. EPA recognizes the
potential burden of reporting emissions for smaller sources. The
proposal addresses this concern in several ways. First, only those
facilities over the established thresholds would be required to report.
Smaller facilities would not be subject to the program. Second, for
those facilities subject to the rule, only emissions from those source
categories for which methods are provided would be reported. Methods
are not proposed for what are typically smaller sources of emissions
(e.g., coal piles on industrial sites). Third, because some facilities
subject to the rule could still have some relatively small sources, the
proposal includes simplified emissions estimation methods for smaller
sources, where appropriate. For example, small stationary combustion
units could use a default emission factor and heat rate to estimate
emissions, and no fuel measurements would be required. Where simplified
methods are proposed, they are described in the relevant discussions in
Section V of this preamble.
Our analysis showed that the GHG reporting programs with de minimis
exclusions are structured differently than our proposed rule. For
example, most rules with de minimis exclusions require corporate level
reporting of all emission sources. Under these programs, some
corporations must report emissions from numerous remote facilities and
must report emissions from small onsite equipment (e.g., lawn mowers).
For these programs, a de minimis exclusion avoids potentially
[[Page 16474]]
unreasonable reporting burdens. The recent trend in these programs,
however, is to require full reporting of all required GHG emissions,
but allow simplified calculation procedures for small sources. In
contrast to these other reporting programs, today's proposed rule would
affect only larger facilities, would require reporting of significant
emission points only, and would contain simplified reporting where
practicable. Accordingly, a de minimis exclusion is not necessary. EPA
requests comment on whether this approach to smaller sources of
emissions is appropriate or if we should include some type of de
minimis provision.
For additional information on the treatment of de minimis in
existing GHG reporting programs, please refer to the ``Reporting
Methods for Small Emission Points (De Minimis Reporting)'' (EPA-HQ-OAR-
2008-0508-048).
3. Recalculation and Missing Data
Most voluntary and mandatory GHG reporting programs include
provisions for operators to revise previously submitted data. For
example, some voluntary programs require reporters to revise their base
year emissions calculations if there is a significant change in the
boundary of a reporter, a change in methodologies or input data, a
calculation error, or a combination of the above that leads to a
significant change in emissions. Recalculation procedures particularly
appear to be central in voluntary GHG reporting programs that are also
tracking emissions reductions.
Moreover, some programs (e.g., ARP) have detailed provisions for
filling in data gaps that are missing in the required report. For
example, in ARP, these procedures apply when CEMS are not functioning
and as a result several hours of the required hourly data are missing.
Note, however, that merely filling in data gaps that are missing or
correcting calculation errors does not relieve an operator from
liability for failure to properly calculate, monitor and test as
required.
For this mandatory GHG reporting program, EPA concluded it was
important to have missing data procedures in order to ensure there is a
complete report of emissions from a particular facility. However,
because this program requires annual reporting rather than quarterly
reporting of hourly data as in ARP, the missing data provision often
require the facility to redo the test or calculation of emissions.
Section V of the preamble details the missing data procedures for
facilities reporting to this program. EPA is seeking comment on whether
to include a provision to require a minimum standard for reported data
(e.g., only 10 percent of the data reported can be generated using
missing data procedures).
In addition to establishing procedures for missing data, there may
be benefit in requiring previously submitted data to be recalculated in
order to ensure that the GHG emissions reported by a facility are as
accurate as possible. The proposed California mandatory GHG reporting
program, for example, allows reporters to revise submitted emissions
data if errors are identified, subject to approval by the program.
EPA is considering whether or not to include provisions to require
facilities to correct previously submitted data under certain
circumstances. However, these benefits must also be weighed against the
additional costs associated with requiring reporters to recalculate and
resubmit previous data, and the magnitude of the emissions changes
expected from such recalculations. Moreover, even if EPA were to allow
recalculation of submitted data or accept data submitted using missing
data procedures, that would not relieve the reporter of their
obligation to report data that are complete, accurate and in accordance
with the requirements of this rule. Although submitting recalculated
data or data using missing data procedures would correct the data that
are wrong, that resubmission or missing data procedures does not
necessarily reverse the potential rule violation and would not relieve
the reporter of any penalties associated with that violation. EPA is
seeking comment on whether the mandatory GHG reporting program should
include provisions to require reporters to submit recalculated data and
under what circumstances such recalculations should be required.
H. Rationale for Monitoring Requirements
In selecting the monitoring requirements for the proposed rule,
EPA's goal is to collect data of sufficient accuracy and quality to be
used to inform future climate policy development and support a range of
possible policies and regulations. Future policies and regulations
could range from research and development initiatives to regulatory
programs (e.g. , cap-and-trade programs). Accurate and timely
information is critical to making policy decisions and developing
programs. However, EPA recognizes that methods that provide the most
accurate data may also entail higher data collection costs. In
selecting a general monitoring approach, EPA considered the relative
accuracy and costs of different approaches, the monitoring methods
already in use within the regulated industries, and consistency with
the monitoring approaches required by various Federal and State
mandatory and voluntary GHG reporting programs. Measurement methods can
range from continuous direct emissions measurements to simple
calculation methods that rely on default factors and assumptions. EPA
considered four broad monitoring approaches for the mandatory GHG rule.
These general approaches (options 1 through 4) and the rationale for
the selected approach are described in this section. After a general
approach was selected, EPA developed the specific proposed monitoring
methods for each source category as described in Section V of this
preamble.
Option 1. Direct Emission Measurement. Option 1 would require
direct measurement of GHGs for all source categories where direct
measurement is feasible. It would require installation of CEMS for
CO2 in the stacks from stationary combustion units and
industrial processes. The approach would be similar to 40 CFR part 75
that require coal-fired EGUs to install, operate, and maintain CEMs for
SO2 and NOX emissions and report hourly emissions
data (although some lower-emitting units have the option to use fuel
sampling and fuel flow rate metering to determine emissions). Like 40
CFR part 75, the direct measurement approach would have detailed
requirements for the CEMS including stringent QA/QC requirements to
monitor accuracy and precision.
Direct measurement is not technically feasible in all cases. For
example, CEMS are not available for many of the GHGs that must be
reported. Direct measurement is also infeasible for emissions that are
not captured and emitted through a stack, such as CH4
emissions from the surface of landfills or fugitive emissions from
selected oil and natural gas operations. For sources where direct
measurement is not technically feasible, this option would require the
use of rigorous methods with a comparable level of accuracy to CEMS.
The direct measurement option has the highest degree of certainty
of the data reported. It is also the most costly because all facilities
where direct measurement is feasible would need to install, operate,
and maintain emission monitors. Most facilities currently do not have
CEMS to measure GHG emissions.
Option 2. Combination of Direct Emission Measurement and Facility-
Specific Calculations. This option
[[Page 16475]]
would require direct measurement of emissions from units at facilities
that already are required to collect and report data using CEMS under
other Federally enforceable programs (e.g., ARP, NSPS, NESHAP, SIPs).
In some cases, this may require upgrading existing CEMS that currently
monitor criteria pollutants to also monitor CO2.
Facilities that do not have units that have CEMS installed would
have the choice to either directly measure emissions or to use
facility-specific GHG calculation methods. The measurement and
calculation methods for each source category would be specified in each
subpart. Depending on the source category, methods could include mass
balance; measurement of the facility's use of fuels, raw materials, or
additives combined with site-specific measured carbon content of these
materials; or other procedures that rely on facility-specific data. For
the supplier source categories (e.g., those that supply fuels or
industrial GHGs), this option would require reporting of production,
import, and export data. The supplier companies already closely track
these data for financial and other reasons.
This option provides a relatively high degree of certainty and
takes advantage of existing practices at facilities. This option is
less costly than option 1 because most facilities are not required to
install CEMS and can, in many cases, make use of data they are already
collecting for other reasons.
Option 3. Simplified Calculation Methods. Under option 3,
facilities would calculate emissions using simple inputs (e.g., total
annual production) that are usually already measured for other reasons,
and EPA-supplied default emission factors (many of which have been
developed by industry consortiums, such as the World Resources
Institute/World Business Council for Sustainable Development (WRI/
WBCSD) (Cement Sustainability Initiative) Protocol). The default
emission factors would represent national average factors. These
methods and emission factors would not take into account facility-
specific differences in processes or in the composition of raw
materials, fuels, or products.
Under this option, the only facilities that would have to use more
rigorous monitoring or site-specific calculations methods are
facilities that are already required to report emissions under 40 CFR
part 75. These facilities would continue to follow the CO2
monitoring and reporting requirements of 40 CFR part 75.
Data collected under this option would have a lower degree of
certainty than options 1 or 2. Furthermore, many facilities are already
calculating GHG emissions to a higher degree of certainty for business
reasons or for other mandatory or voluntary reporting programs, and
option 3 would not make use of such available data. However, the cost
to facilities is lower than under options 1 and 2.
Option 4. Reporter's Choice of Methods. Under this approach,
reporters would have flexibility to select any measurement or
calculation method and any emission factors for determining emissions.
The rule would not prescribe any methods or present any specific
options for determining emissions.
Data collected under this option would not be comparable across a
given industry and across reporters subject to the program, thereby
minimizing the usefulness of the data to support future policymaking.
Although some facilities might choose to use direct measurement because
CEMS are already installed at the facility, other facilities would
select default calculations. This option would be the lowest cost to
reporters.
Proposed Option. For the proposed rule, EPA selected option 2
(combination of direct measurement and facility-specific calculations)
as the general monitoring approach. This option results in relatively
high quality data for use in developing climate policies and supporting
a wide range of potential future policy options. Because we do not yet
know which specific policy options the data may ultimately be used to
support, the reported GHG emission estimates should have a sufficient
degree of certainty such that they could be used to help develop a
potential variety of programs.
Option 2 strikes a balance between data accuracy and cost. It makes
use of existing data and methodologies to the extent feasible, and
avoids the cost of installing and operating CEMS at numerous
facilities. It is consistent with the types of methods contained in
other GHG reporting programs (e.g., TCR, California programs, Climate
Leaders). Because this option specifies methods for each source
category, it should result in data that are comparable across
facilities.
Option 1 (direct emission measurement) was not chosen because the
cost to the reporters if all facilities had to install continuous
emission monitoring systems would be unreasonably high in the absence
of a defined policy that would require this type of monitoring.
However, under the selected option, facilities that already use CEMS
would still be required to use them for purposes of the GHG reporting
rule.
Option 3 (simplified calculation methods) was not chosen because
the data would be less accurate than option 2 and would not make use of
site-specific data that many facilities already have available and
refined calculation approaches that many facilities are already using.
Option 3 would also be inconsistent with several other GHG reporting
programs such as TCR and California programs that contain more site-
specific calculation methods for several of the source categories.
Option 4 (reporter's choice of methods) was not proposed because
the accuracy and reliability of the reported data would be unknown and
would vary from one reporter to the next. Because consistent methods
would not be used under this option, the reported data would not be
comparable across similar facilities. The lack of comparability would
undermine the use of the data to support policy decisions.
EPA requests comments on the selected monitoring approach and on
other potential options and their advantages and disadvantages.
I. Rationale for Selecting the Recordkeeping Requirements
EPA is proposing that each facility that would be required to
submit an annual GHG report would also keep the following records, in
addition to any records prescribed in each applicable subpart:
A list of all units, operations, processes and activities
for which GHG emissions are calculated;
The data used to calculate the GHG emissions for each
unit, operation, process, and activity, categorized by fuel or material
type;
Documentation of the process used to collect the necessary
data for the GHG emissions calculations;
The GHG emissions calculations and methods used;
All emission factors used for the GHG emissions
calculations;
Any facility operating data or process information used
for the GHG emissions calculations;
Names and documentation of key facility personnel involved
in calculating and reporting the GHG emissions;
The annual GHG emissions reports;
A log book documenting any procedural changes to the GHG
emissions accounting methods and any changes to the instrumentation
critical to GHG emissions calculations;
Missing data computations;
A written QAPP;
Any other data specified in any applicable subpart of
proposed 40 CFR part 98. Examples of such data could
[[Page 16476]]
include the results of sampling and analysis procedures required by the
subparts (e.g., fuel heat content, carbon content of raw materials, and
flow rate) and other data used to calculate emissions.
These data are needed to verify the accuracy of reported GHG
emission calculations and, if needed, to reproduce GHG emission
estimates using the methods prescribed in the proposed rule. Since the
above information must be collected in order to calculate GHG
emissions, the added burden of maintaining records of that information
should be minimal.
Each facility would be required to retain all required records for
at least 5 years. Records would be maintained for this period so that a
history of compliance could be demonstrated and questions about past
emission estimates could be resolved, if needed.
The records would be required to be kept in an electronic or hard-
copy format (as appropriate) that is readily accessible within a
reasonable time for onsite inspection and auditing. They would be
recorded in a form that can be easily inspected and reviewed. The
allowance of a variety of electronic and hard copy formats for records
allows flexibility for facilities to use a system that meets their
needs and is consistent with other facility records maintenance
practices, thereby minimizing the recordkeeping burden.
J. Rationale for Verification Requirements
1. General Approach to Verification Proposed in This Rule
GHG emissions reported under this rule would be verified to ensure
accuracy and completeness so that EPA and the public could be confident
in using the data for developing climate policies and potential future
regulations. To ensure the completeness and quality of data reported to
the program, the Agency proposes self-certification with EPA
verification. Under this approach, all reporters subject to this rule
would certify that the information they submit to EPA is truthful,
accurate and complete. EPA would then review the emissions data and
supporting data submitted by reporters to verify that the GHG emission
reports are complete, accurate, and meet the reporting requirements of
this rule.
Given the scope of this rulemaking, this approach is consistent
with many EPA regulatory programs. That said, this proposal does not
preclude that in the future, as climate policies evolve, EPA may
consider third party verification for other programs (e.g., offsets).
Furthermore, many programs in the States and Regions may be broader in
scope and the use of third party verifiers may be appropriate to meet
the needs of those programs.
In addition, under the authorities of CAA sections 114 and 208, EPA
has the authority to independently conduct site visits to observe
monitoring procedures, review records, and verify compliance with this
rule (see Section VII of this preamble for further information on
compliance and enforcement). For vehicle and engine manufacturers, EPA
is not proposing additional verification requirements beyond the
current emissions testing and certification procedures. These
procedures include well-established methods for assuring the
completeness and quality of reported emission test data and EPA is
proposing to include the new GHG reporting requirements as part of
these methods.
2. Options Considered
In selecting this proposed approach to verification, the Agency
reviewed verification requirements and procedures under a number of
existing EPA regulatory programs, as well as existing domestic and
international GHG reporting programs. Additional information on this
review and the verification approaches can be found in a technical
memorandum (``Review of Verification Systems in Environmental Reporting
Programs,'' EPA-HQ-OAR-2008-0508-047). Based on this review, EPA
considered three alternative approaches to verification: (1) Self-
certification without independent verification, (2) self-certification
with third-party verification, and (3) self-certification with EPA
verification.
Option 1. Self-certification without independent verification.
Under this option, the Designated Representative of the reporting
facility would be required to sign and submit a certification statement
as part of each annual emissions report. The certification would affirm
that the report has been prepared in accordance with the requirements
of the GHG reporting rule, and that the emissions data and other
information reported is true and accurate to the best knowledge and
belief of the certifying official. The reasons for requiring self-
certification are contained in Section IV.G of this preamble. Under
option 1, EPA would not independently verify the accuracy and
consistency of the reported data. Furthermore, because this approach
does not include independent verification by EPA or a third party, the
facility would not have to submit the detailed data needed to verify
emissions estimates. Such information would be retained at the
facility. For example, facilities would not be required to submit
detailed monitoring data, activity data (e.g., fuel use, raw material
consumption, production rates), carbon content measurements, or
emission factor data used to calculate emissions.
Option 1 is a low burden option for reporters submitting data for
this rule. Reporters under this option would not have to pay for third-
party verifiers and would not necessarily have to submit the additional
data required under the other options. In addition, EPA would not incur
the expense of conducting verification of the reported data or
certifying independent verifiers to conduct verification activities.
The major disadvantages of this approach are the greater potential for
inconsistent and inaccurate data in the absence of independent
verification and the lower level of confidence that the public,
stakeholders and EPA may have in the data.
Option 2. Self-certification with third-party verification. Under
this approach, reporters would submit the same self-certification
statements as under option 1. In addition, reporters would be required
to hire independent third-party verifiers. The third-party verifiers
would review the emissions report and the underlying monitoring system
records, activity data collection, calculation procedures, and
documentation, and submit a verification statement that the reported
emissions are accurate and free of material misstatement. Under this
approach, records supporting the GHG emissions calculations would be
retained at the facility for compliance purposes and provided to the
verifiers, but not submitted to EPA. In addition, as discussed below,
EPA would have to establish a system to certify the independent
verifiers.
Self-certification with third-party verification provides greater
assurance of accuracy and impartiality than self-certification without
verification. While this option is consistent with some existing
domestic and international GHG reporting programs such as TCR, the
California mandatory reporting rule, CCAR, and the EU Emission Trading
System, the majority of industry stakeholders that met with EPA are
opposed to this approach for this rulemaking, primarily due to the
additional cost. Compared to option 1, the third-party verification
approach places two additional costs on reporters: (1) Reporters would
need to hire and pay verifiers, at a cost of thousands of dollars per
reporting facility, and (2) reporters would incur costs to assemble
[[Page 16477]]
and provide to verifiers detailed supporting data for the emission
estimates.
To ensure consistency and quality of the third-party verifications,
EPA would need to develop verification protocols, establish a system to
qualify and accredit the third-party verifiers, and conduct ongoing
oversight and auditing of verifications to be sure that third-party
verifications continue to be conducted in a consistent and high quality
manner.
As mentioned above, as climate policy evolves, it may be
appropriate for EPA to consider the use of third party verification in
other circumstances (e.g., offsets).
Option 3. Self-certification with EPA verification. Under this
option, reporters would submit the same self-certification as under
option 1. Reporters also would assemble data to support their emissions
estimates, similar to option 2 but submit it to EPA in their annual
emission reports, rather than to a third party verifier. EPA would
review the emissions estimates and the supporting data contained in the
reports, and perform other activities (e.g., comparison of data across
similar facilities, site visits) to verify that the reported emissions
data are accurate and complete.
EPA verification provides greater assurance of accuracy and
impartiality than self-reporting without verification. Compared to a
third-party verification system, there would be a consistent approach
to verification from one centralized verifier rather than a variety of
separate verifiers although this option would require EPA to ensure
consistency if it chose to use its own contractors to support its
verification activities. In addition, a centralized verification system
would provide greater ability to the government to identify trends and
outliers in data and thus assist with targeted enforcement planning.
Finally, an EPA verification approach is consistent with other EPA
emissions reporting programs including EPA's ARP.\60\ The cost to the
reporter is intermediate between options 1 and 2. Although this
approach would not subject reporters to the cost of paying for third-
party verifiers, reporters would have to assemble and submit detailed
supporting data to ensure proper verification by EPA. An EPA
verification program would result in greater costs to the Agency than
options 1 and 2, but due to economies of scale may result in lower
overall costs.
---------------------------------------------------------------------------
\60\ For a description of how verification is conducted in ARP
please see, ``Fundamentals of Successful Monitoring, Reporting, and
Verification under a Cap-and-Trade Program.'' John Schakenbach,
Robert Vollaro, and Reynaldo Forte, U.S. EPA/OAP. Journal of the Air
and Waste Management Association 56:1576-1583. November 2006. (EPA-
HQ-OAR-2008-0508-051.)
---------------------------------------------------------------------------
3. Selection of Self-Certification With EPA Verification as the
Proposed Approach
EPA is proposing self-certification with EPA verification (option
3) because it ensures that data reported under this rule are
consistent, accurate, and complete. In addition, we are seeking comment
on requiring third-party verification for suppliers of petroleum
products, many of whom currently report to EPA under the Office of
Transportation and Air Quality's fuels programs. Third-party
verification could be reasonable in these instances because this rule,
to some extent, would build on existing transportation fuels programs
that already require audits of records maintained by these suppliers by
independent certified public accountants or certified internal
auditors. For more information about the approach to fuel suppliers
please refer to Section V of this preamble.
EPA is successfully using self certification with EPA verification
in a number of other emissions reporting programs. EPA verification
option provides greater assurance of the accuracy, completeness, and
consistency of the reported data than option 1 (no independent
verification) and consistent with feedback from industry stakeholders,
does not require reporters to hire third-party verifiers (option 2). In
addition, EPA verification option does not require the establishment of
an accreditation and approval program for third-party verifiers
although it would require EPA to ensure consistency if it chose to use
its own contractors to support its verification activities.
EPA judged that option 1 (no independent verification) does not
ensure sufficient quality data for the possible future uses of the
data. The potential inconsistency, inaccuracy, and increased
uncertainty of the data collected under option 1 would make the data
less useful for informing decisions on climate policy and supporting
the development of a wide range of potential future policies and
regulations.
We selected EPA verification (option 3) instead of third-party
verification (option 2) because EPA verification is consistent with
other EPA programs, has lower costs to reporters than option 2, and
would result in a consistent verification approach applied to all
submitted data. Even with a verifier accreditation and approval
process, the third-party verification approach could entail a risk of
inconsistent verifications because verification responsibilities are
spread amongst numerous verifiers. Given the potential diversity of
verifiers, the quality and thoroughness of verifications may be
inconsistent and EPA audit and enforcement oversight would become the
predominant factor in ensuring uniformity. Under option 2, EPA would
also need to develop and administer a process to ensure that verifiers
hired by the reporting facilities do not have conflicts of interest.
Such a program could require EPA to review numerous individual conflict
of interest screening determinations made each time a reporter hires a
third-party verifier. Finally, EPA verification would likely avoid any
delays that may be introduced by third-party verification and better
ensure the timely reporting and use of the reported data. Some
reporting programs provide four to six months after the annual
emissions report is submitted for third-party verification. That said,
as mentioned above, depending on the scope or type of program (e.g.,
offsets), EPA may consider the use of third party verification in the
future as policy options evolve.
The Agency recognizes that, in some instances, data submitted by
reporters under this rule may have been independently verified as the
result of other mandatory or voluntary GHG reporting programs or by
other Federal, State or local regulations. Whether or not data have
been independently verified outside of the requirements of this
proposed GHG reporting rule, EPA has concluded for the purposes of this
proposal it is important to apply the same verification requirements to
all affected facilities in order to ensure equity across all reporters
and consistent data collection for policy analysis and public
information.
K. Rationale for Selection of Duration of the Program
EPA is proposing that the rule require the reporting of GHG
emissions data on an ongoing, annual basis. Other approaches that EPA
considered include a one-time collection of information and collection
of a limited duration (e.g., a three-year data collection effort).
EPA does not believe that a one-time data collection effort is
consistent with the legislative history of the FY 2008 Consolidated
Appropriations Act, which instructed EPA to develop a rule to require
the reporting of GHG emissions. Typically, a rule is not required to
undertake a one-time information collection request. Moreover, the
President's FY 2010
[[Page 16478]]
Budget, as well as initial Congressional budgets for the remainder of
FY 2009 indicate that policy makers anticipate that the information
will be collected for multiple years.
For example, on February 6, 2009, Senators Feinstein, Boxer, Snowe
and Klobuchar sent a letter to EPA's Administrator Lisa Jackson and
OMB's Director Peter Orszag stating that this program allowed EPA to
``gather critical baseline data on greenhouse gas emissions, which is
essential information that policymakers need to craft an effective
climate change approach.'' In addition, in recent testimony from John
Stephenson, Director of Natural Resources and Environment at the
Government Accountability Office,\61\ stated that when setting
baselines for past regulatory policies, averaging data ``across several
years also helped to ensure that the baseline reflected changes in
emissions that can result in a given year due to economic and other
conditions.'' The testimony further noted the because EPA's ARP was
able to average several years worth of data when setting the baseline
for SO2 reductions, the program ``achieved greater
assurances that it reduced emissions from historical levels'' as
opposed to the EU who did not have enough data to set accurate
baselines for the first phase of the EU Emissions Trading System.
Furthermore, EPA's experience with certain CAA programs show that a
one-time snapshot of information is not always representative of normal
operations, and hence emissions, of a facility. See, e.g., Final New
Source Review (NSR) Reform Rules, 68 FR 80186, 80199 (2002). Finally,
as discussed earlier, a multi-year reporting program allows EPA to
track trends in emissions and understand factors that influence
emissions levels.
---------------------------------------------------------------------------
\61\ High Quality Greenhouse Gas Emissions Data are a
Cornerstone of Programs to Address Climate Change, Statement of John
Stephenson, Director, Natural Resources and Environment, Government
Accountability Office, February 24, 2009.
---------------------------------------------------------------------------
EPA also considered a multi-year program that would sunset at a
date certain in the future (e.g., three years) absent subsequent
regulatory action by EPA to extend it. EPA decided against this
approach because it would unnecessarily limit the debate about
potential policy options to address climate change. At this time, it
would be premature to guess at what point in the future this
information may be less relevant to decision-making. Rather, a more
prudent approach is to maintain the program until such time in the
future when it is determined that the information for one or more
source categories is no longer relevant to decision-making, or is
adequately provided in the context of regulatory program (e.g., CAA
NSPS). Notably, EPA crafted the requirements in this rule with the
potential monitoring, recordkeeping and reporting requirements for any
future regulations addressing GHG emissions in mind. EPA solicits
comment on all of these possible approaches, including whether EPA
should commit to revisit the continued necessity of the reporting
program at a future date.
V. Rationale for the Reporting, Recordkeeping and Verification
Requirements for Specific Source Categories
Section V of this preamble discusses the source categories covered
by the proposed rule. Each section presents a description of a source
category and the proposed threshold, monitoring methods, missing data
procedures, and reporting and recordkeeping requirements.
A. Overview of Reporting for Specific Source Categories
Once you have determined that your facility exceeds any reporting
threshold specified in 40 CFR 98.2(a), you would have to calculate and
report GHG emissions, or alternate information as required (e.g.,
production and imports for industrial GHG suppliers) for all source
categories at your facility for which there are measurement methods
provided. The threshold determination is separately assessed for
suppliers (fossil fuel suppliers and industrial GHG suppliers) and
downstream source categories.
Facilities, or corporations, where relevant, that trigger only the
threshold for upstream fossil fuel or industrial GHG supply (proposed
40 CFR part 98, subparts KK through PP) need only follow the methods in
those respective sections. Facilities (or corporations) that contain
source categories that also have downstream sources of emissions (e.g.,
proposed 40 CFR part 98, subparts B through JJ), or facilities that are
exclusively downstream sources of emissions may have to monitor and
report GHG emissions using methods presented in multiple sections. For
example, a food processing facility should review Section V.C (General
Stationary Fuel Combustion), Section V.HH (Landfills) and Section V.II
(Wastewater Treatment) in addition to Section V.M (Food Processing) of
this preamble. Table 2 of this preamble (in the SUPPLEMENTARY
INFORMATION section of this preamble) provides a cross walk to aid
facilities in identifying potentially relevant source categories. The
cross-walk table should only be seen as a guide as to the types of
source categories that may be present in any given facility and
therefore the methodological guidance in Section V of this preamble
that should be reviewed. Additional source categories (beyond those
listed in Table 2 of this preamble) may be relevant to a given
reporter. Similarly, not all listed source categories would be relevant
to all reporters. The remainder of this overview summarizes the general
approach to calculating and reporting these downstream sources of
emissions.
Consistent with the requirements in the proposed 40 CFR part 98,
subpart A, facilities would have to report GHG emissions from all
source categories located at their facility--stationary combustion,
process (e.g., iron and steel), fugitive (e.g., oil and gas) or
biologic (e.g., landfills) sources of GHG emissions. The methods
presented typically account for normal operating conditions, as well as
SSM, where significant (e.g., HCFC-22 production and oil and gas
systems). Although SSM is not specifically addressed for many source
categories, emissions estimation methodologies relying on CEMS or mass
balance approaches would capture these different operating conditions.
For many facilities, calculating facility-wide emissions would
simply involve adding GHG emissions calculated under Section V.C of
this preamble (General Stationary Fuel Combustion Sources) and
emissions calculated under the source-specific subpart. For other
facilities, particularly selected sources in Sections V.E through V.JJ
of this preamble that rely on mass balance approaches or the use of
CEMS, the proposed methods would (depending on the operating conditions
and configuration of the plant) capture both combustion and process-
related emissions and there is no need to separately quantify
combustion-related emissions using the methods presented in Section V.C
of this preamble.
Generally, the proposed method depends on the equipment you
currently have installed at the facility.
Sources with CEMS. If you have CEMS that meet the requirements in
proposed 40 CFR part 98, subpart C you would be required to quantify
and report the CO2 emissions that can be monitored using the
existing CEMS. Non-CO2 combustion-related emissions would be
estimated consistent with proposed 40 CFR part 98, subpart C, and other
non-CO2 emissions would be estimated using the source-
specific methods provided.
[[Page 16479]]
(1) Where the CEMS capture both combustion- and process-related
emissions you would be required to follow the calculation procedures,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of proposed 40 CFR part
98, subpart C to estimate emissions from the industrial source. In this
case, use of the additional methods provided in the source-specific
discussions would not be required.
(2) Where the CEMS do not capture both combustion and process-
related emissions, you should refer to the source-specific sections
that provide methods for calculating process emissions. You would also
be required to follow the calculation procedures, monitoring and QA/QC
methods, missing data procedures, reporting requirements, and
recordkeeping requirements of proposed 40 CFR part 98, subpart C to
estimate any stationary fuel combustion emissions from the industrial
source.
Sources without CEMS. If you do not have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, you would
be required to carry out facility-specific calculations to estimate
process emissions. You would also be required to follow the calculation
procedures, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements of proposed 40
CFR part 98, subpart C to estimate any stationary fuel combustion
emissions from the industrial source.
B. Electricity Purchases
At this time, we are not proposing that facilities report
information to us regarding their electricity purchases or indirect
emissions from electricity consumption. However, we carefully
considered proposing that all facilities that report to us also report
their total purchases of electricity. This section describes our
deliberations and outlines potential methods for monitoring and
reporting electricity purchases. We generally seek comment on the value
of collecting information on electricity purchases. Further, we are
specifically interested in receiving feedback on the approach outlined
below.
1. Definition of the Source Category
The electric utility sector is the largest emitter of GHG emissions
in the U.S. The level of GHG emissions associated with electricity use
is determined not just by the fuel and combustion technology onsite at
the power plant, but also by customer demand for electricity.
Accordingly, electricity use and the efficiency of this use indirectly
affect the emissions of CO2, CH4 and
N2O from the combustion of fossil fuel at electric
generating stations.
For many facilities, purchased electricity represents a large part
of onsite energy consumption, and their overall GHG emissions footprint
when taking into account the indirect emissions from fossil fuel
combusted for the electricity generated. Therefore, the reporting of
electricity purchase data from facilities could provide a better
understanding of how electricity is used in the economy and the major
sectors. We would propose not to provide for adjustments to take into
account the purchases of renewable energy credits or other mechanisms.
If included, this source category would include electricity
purchases, but not include electricity generated onsite (i.e.,
facility-operated power plants, emergency back-up generators, or any
portable, temporary, or other process internal combustion engines).
General requirements for all reporters subject to the proposed rule to
report on total kilowatt hours of electricity generated onsite is
discussed in Section IV.G of the preamble. Calculating emissions from
onsite electricity generation is addressed in Sections V.C and V.D of
this preamble.
For additional background information on indirect emissions from
electricity purchases, please refer to the Electricity Purchases TSD
(EPA-HQ-OAR-2008-0508-003).
2. Selection of Reporting Threshold
Three options for reporting thresholds could be considered for the
reporting of indirect emissions from purchased electricity (i.e., GHG
emissions from the production of purchased electricity). These options
would be as follows:
Option 1: Do not require any reporting on electricity purchases or
associated indirect emissions from electricity purchases as part of
this rule.
Option 2: Require reporting on purchased electricity from all
facilities that are already required to report their GHG emissions
under this rule.
Option 3: Require reporting of indirect emissions from purchased
electricity for facilities that exceed a prescribed total facility
emissions threshold (including indirect emissions from the purchased
electricity). Reporting for this option could be proposed either in
terms of electricity purchases or calculated indirect CO2e
emissions based on purchased electricity. This option would require an
additional number of reporters, based on their annual electricity
purchases, to report indirect emissions.
No additional facilities to those already reporting their emissions
data under this rule would be affected by the first or second options.
The number of additional facilities affected by the third proposed
threshold is estimated to be approximately: 250 facilities at a 100,000
metric tons CO2e threshold; 5,000 total facilities at a
25,000 metric tons CO2e threshold; 15,000 total facilities
at a 10,000 metric tons CO2e threshold; and 185,000 total
facilities at a 1,000 metric tons CO2e threshold.
Under all threshold options, reporting of information related to
electricity purchases would apply to entities reporting at the facility
level. This provision would not apply to source categories that we
propose report at the corporate level (e.g., importers and exporters of
industrial GHGs, local distribution companies, etc.). These companies
in many cases may own large facilities such as refineries which already
have a reporting obligation for direct emissions and electricity
purchases.
Given the above considerations, our preferred option would be
option 2. Purchased electricity is considered to be a significant
portion of the GHG emissions of most industrial facilities, therefore
the collection of indirect emissions from purchased electricity could
be seen as an important component of the GHG mandatory reporting rule.
Although such a reporting requirement would not provide EPA with
emissions information, it could provide the necessary underlying data
to develop emissions estimates in the future if this were necessary.
The reporting of electricity purchase data directly instead of
calculated indirect emissions would be preferred due to the
difficulties in identifying the appropriate electrical grid or
electrical plant emission factor for converting a facility's
electricity purchases to GHG emissions. EPA does not have data to
evaluate the uncertainty of applying national, regional or State
emission factors to electricity consumption at a given facility, versus
undertaking detailed studies to determine the actual emissions from
electricity purchases.
Under Option 2, all facilities that are already required to report
their GHG emissions under this rule would also have to quantify and
report their annual electricity purchases. The total purchased
electricity would include electricity purchased from all sources (i.e.,
fossil fuel power plants, green power generating facilities, etc.). It
should be noted that under this approach, data from large sources of
indirect emissions due to electricity
[[Page 16480]]
usage (e.g., non-industrial commercial buildings) would be not be
collected.
3. Selection of Proposed Monitoring Methods
Purchased electricity could be quantified through the use of
purchase receipts or similar records provided by the electricity
provider. The facility could choose to use data from facility
maintained electric meters in addition to or in lieu of data from an
electricity provider (e.g., electricity purchase receipts, etc.),
provided that this data could be demonstrated to accurately reflect
facility electricity purchases. However, purchase receipts or
electricity provider data would be the preferred method of quantifying
a facility's electricity purchases. Because facilities would be
expected to retain these data as part of routine financial records, the
only additional burden of collecting this information would be to
retain the records in a readily available manner.
In identifying the options outlined above, we reviewed five
reporting programs and guidelines: (1) EPA Climate Leaders Program, (2)
the CARB Mandatory Greenhouse Gas Emissions Program, (3) TRI, (4) the
DOE 1605(b) program, and (5) the GHG Protocol developed jointly by WRI
and WBCSD. In general, these protocols follow the methods presented in
WRI/WBCSD for the quantification and reporting of indirect emissions
from the purchase of electricity.
See the Electricity Purchases TSD (EPA-HQ-OAR-2008-0508-003) for
more information.
4. Selection of Procedures for Estimating Missing Data
If we were to collect information on electricity purchases, we
would propose that a facility be required to make all attempts to
collect electricity records from their electricity provider. In the
event that there were missing electricity purchase records, the
facility would estimate its electricity purchases for the missing data
period based on historical data (i.e., previous electricity purchase
records). Any historical data used to estimate missing data should
represent similar circumstances to the period over which data are
missing (e.g., seasonal). If a facility were using electric meter data
and had a missing data period, the facility could use a substitute data
value developed by averaging the quality-assured values metered values
for kilowatt-hours of electricity use immediately before and
immediately after the missing data period.
5. Selection of Data Reporting Requirements
If we were to collect information on electricity purchases, we
would propose that a facility report total annual purchased electricity
in kilowatt-hours for the entire facility.
6. Selection of Records That Must Be Retained
If we were to collect information on electricity purchases, we
would propose that the owner or operator maintain monthly electricity
purchase records for all operations and buildings. If electric meter
data were used, then monthly logs of the electric meter readings would
also be proposed to be maintained.
C. General Stationary Fuel Combustion Sources
1. Definition of the Source Category
Stationary fuel combustion sources are devices that combust solid,
liquid, or gaseous fuel generally for the purposes of producing
electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional use, or reducing the volume of
waste by removing combustible matter. Stationary fuel combustion
sources include, but are not limited to, boilers, combustion turbines,
engines, incinerators, and process heaters. The combustion process may
be used to: (a) Generate steam or produce useful heat or energy for
industrial, commercial, or institutional use; (b) produce electricity;
or (c) reduce the volume of waste by removing combustible matter. As
discussed in Section III of this preamble and proposed 40 CFR part 98,
subpart A, this section applies to facilities with stationary fuel
combustion sources that (a) have emissions greater than or equal to
25,000 metric tons CO2e/yr; or (b) are referred to this
section by other source categories listed in proposed 40 CFR 98.2(a)(1)
or (2).
Combustion of fossil fuels in the U.S. is the largest source of GHG
emissions in the nation, producing three principal greenhouse gases:
CO2, CH4 and N2O. For the purposes of
this rule, CO2, CH4, and N2O would be
reported by stationary fuel combustion sources. The emission rate of
CO2 is directly proportional to the carbon content of the
fuel, and virtually all of the carbon is oxidized to CO2.
The emission rates of CH4 and N2O are much less
predictable, as these gases are by-products of incomplete or
inefficient combustion, and depend on many factors such as combustion
technology and other considerations. The CO2 emissions
generated by fuel combustion far exceed the CH4 and
N2O emissions (CH4 and N2O contribute
less than 1 percent of combined U.S. GHG emissions from stationary
combustion, on a CO2e basis), however, under this proposed
rule, CO2, CH4, and N2O would all be
reported by stationary fuel combustion sources. EPA is proposing to not
require reporting of emissions from portable equipment or generating
units designated as emergency generators in a permit issued by a state
or local air pollution control agency. We request comment on whether or
not a permit should be required for these emergency generators.
A wide and diverse segment of the U.S. economy engages in
stationary combustion, principally the combustion of fossil fuels.
According to the ``Inventory of U.S. Greenhouse Gas Emissions and
Sinks: 1990-2006'', the nationwide GHG emissions from stationary fossil
fuel combustion are approximately 3.75 billion metric tons
CO2e per year. This estimate includes both large and small
stationary sources and represents more than 50 percent of total GHG
emissions in the U.S.
EPA's proposed rule presents methods for calculating GHG emissions
from stationary combustion, both at unspecified facilities as well as
facilities in source categories listed in proposed 40 CFR 98.2(a)(1)
and (2), which are based on the fuel combusted and the size of the
stationary equipment (e.g., the maximum heat input capacity in mmBtu/
hr). EPA already collects CO2 emissions data from
electricity generating units in the ARP,\62\ which combust the vast
majority of coal consumed in the U.S. annually. So, while detailed
requirements are provided for facilities that combust solid fuels,
these methods are likely to affect only a small percentage of
facilities reporting under proposed 40 CFR part 98 (as separate
methods, in proposed 40 CFR 98.40, would be used by electricity
generating units already reporting under the requirements of ARP). In
presenting methodologies in the following sections, EPA further notes
that the majority of reporters under proposed 40 CFR part 98, subpart C
would use the methods prescribed for stationary combustion equipment
combusting natural gas.
---------------------------------------------------------------------------
\62\ It should be noted, as discussed in section V.D, EPA
already collects over 90% of total CO2 emissions from
U.S. coal combustion through the 40 CFR part 75 requirements of ARP.
---------------------------------------------------------------------------
Table C-1 of this preamble illustrates the methods for calculating
CO2 emissions for different types of reporters based on the
fuel being combusted at the facility and the size of the stationary
combustion equipment. The
[[Page 16481]]
calculations for CH4 and N2O that are presented
in subsequent subsections are to be applied to all fuel types and are
not contingent upon the stationary cobustion equipment size.
Table C-1. Four-Tiered Approach for Calculating CO2 Emissions From
Stationary Combustion Sources
------------------------------------------------------------------------
Methodological
Combustion unit size Additional tier required
requirement(s) \a\
------------------------------------------------------------------------
Solid Fossil Fuel (e.g., Coal)
------------------------------------------------------------------------
> 250 mmBtu/hour.............. --Unit has operated 4
more than 1,000 hours
a year \b\.
--Unit has existing,
certified gas
monitors or stack gas
volumetric flow rate
monitor (or both);
and
--Facility has an
established
monitoring
infrastructure and
meets specific QA/QC
requirements.
--Unit does not meet 3
conditions above.
<= 250 mmBtu/hr............... --Unit operates more 4
than 1,000 hours a
year \b\.
--Unit has existing,
certified CO2 or O2
concentration monitor
and stack gas
volumetric flow rate
monitor; and
--Facility has an
established
monitoring
infrastructure and
meets specific QA/QC
requirements.
--Unit does not meet 2
conditions above.
--Monthly measured HHV
is available.
--Unit does not meet 1
conditions above.
--Monthly measured HHV
is not available.
------------------------------------------------------------------------
Gaseous Fossil Fuel (e.g., Natural Gas)
------------------------------------------------------------------------
> 250 mmBtu/hr................ None.................. 3
<= 250 mmBtu/hr............... --Monthly measured HHV 2
is available.
--Monthly measured HHV 1
is not available.
------------------------------------------------------------------------
Fossil Liquid Fuel (e.g., Diesel)
------------------------------------------------------------------------
> 250 mmBtu/hr................ None.................. 3
<= 250 mmBtu/hr............... --Monthly measured HHV 2
is available.
--Monthly measured HHV 1
is not available.
------------------------------------------------------------------------
Biomass or Biomass-Derived Fuels (e.g., wood)
------------------------------------------------------------------------
All Sizes..................... --EPA has provided a 1
default CO2 emission
factor and a default
heating value for the
fuel.
All Sizes..................... --EPA has provided a 2
default CO2 emission
factor for specific
fuel to be used with
that fuel's measured
heating value.
All Sizes..................... --EPA has not provided 3
a default CO2
emission factor for
specific fuel to be
used with that fuel's
measured heating
value.
------------------------------------------------------------------------
MSW
------------------------------------------------------------------------
> 250 tons MSW/day............ --Unit has operated 4
more than 1,000 hours
a year \b\.
--Unit has existing,
certified gas
monitors or stack gas
volumetric flow rate
monitor (or both);
and
--Facility has an
established
monitoring
infrastructure and
meets specific QA/QC
requirements.
--Unit does not meet 2
conditions above.
<= 250 tons MSW/day........... --Unit operates more 4
than 1,000 hours a
year \b\.
--Unit has existing,
certified CO2
concentration monitor
and stack gas
volumetric flow rate
monitor; and
--Facility has an
established
monitoring
infrastructure and
meets specific QA/QC
requirements.
--Unit does not meet 2
conditions above.
------------------------------------------------------------------------
\a\ Minimum tier level to be used by reporters. Reporters required to
use Tier 1, 2, or 3 have the option to use a higher tier methodology.
\b\ Hours of operation in any year since 2005.
Note: Facilities with units reporting CO2 data to ARP should refer to
Section V.D of this preamble (Electricity Generation).
2. Selection of Reporting Threshold
In developing the threshold for facilities with stationary
combustion equipment, EPA considered an emissions-based threshold of
1,000, 10,000, 25,000, and 100,000 metric tons CO2e. Table
C-2 of this preamble illustrates the emissions covered and the number
of facilities that would be covered under these various thresholds. It
should be noted that Table C-2 of this preamble only includes
facilities with stationary combustion equipment that are not covered in
other subparts of the proposed rule. For this reason, the total
emissions presented in Table C-2 of this preamble appear as a lower
total than presented previously (the general discussion in Section C.1
of this preamble), where emissions from all
[[Page 16482]]
stationary combustion equipment are being discussed.
Table C-2. Threshold Analysis for Unspecified Industrial Stationary Fuel Combustion
----------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
national -----------------------------------------------
emissions Total number Million
Threshold level metric tons CO2e/yr (million of metric
metric tons facilities tons CO2e/ Percent Number Percent
CO2e) yr
----------------------------------------------------------------------------------------------------------------
1,000 410 350,000 250 61 32,000 9.1
10,000 410 350,000 230 56 8,000 2.3
25,000 410 350,000 220 54 3,000 0.9
100,000 410 350,000 170 41 1,000 0.3
----------------------------------------------------------------------------------------------------------------
In calculating emissions for this analysis, and for the proposed
threshold, only CO2 from the combustion of fossil fuels, in
combination with all CH4 and N2O emissions, are
considered. CO2 emissions from biomass are not considered as
part of the determination of the threshold level. This treatment of
biomass fuels is consistent with the IPCC Guidelines and the annual
Inventory of U.S. Greenhouse Gas Emissions and Sinks, which account for
the release of these CO2 emissions in accounting for carbon
stock changes from agriculture, forestry, and other land-use.
CH4 and N2O emissions from combustion of biomass
are counted as part of stationary combustion within the IPCC and
national U.S. GHG inventory frameworks.
The purpose of the general stationary combustion source category is
to capture significant emitters of stationary combustion GHG emissions
that are not covered by the specific source categories described
elsewhere in this preamble. Therefore, EPA is proposing a threshold for
reporting emissions from stationary combustion at 25,000 metric tons
CO2e.\63\ EPA selected the proposed 25,000 metric tons
CO2e threshold as it appears to strike the best balance
between covering a high percentage of nationwide GHG emissions and
keeping the number of affected facilities manageable. As illustrated in
Table C-2 of this preamble, selecting a 25,000 metric tons
CO2e threshold achieves the greatest incremental gain in
coverage with the lowest increase in the number of covered sources.
---------------------------------------------------------------------------
\63\ As described previously, the threshold only includes
CO2 from the combustion of fossil fuels and
CH4 and N2O emissions from all fuel
combustion. CO2 emissions from biomass are not considered
as part of the determination of the threshold level.
---------------------------------------------------------------------------
The 100,000 metric tons CO2e threshold was not proposed
because EPA believes it would exclude too many significant emitters of
GHG emissions that are not required to report pursuant to the other
provisions of this rule. EPA believes that most of the population of
facilities over a 100,000 metric tons CO2e threshold is
known either through source category studies or existing EPA reporting
programs.
The 10,000 metric tons CO2e threshold showed a smaller
incremental gain in emissions coverage from a higher threshold than the
25,000 metric tons CO2e threshold, while greatly increasing
the incremental number of reporters (as illustrated in Table C-2 of
this preamble). The 1,000 metric tons CO2e threshold greatly
increases the total number of reporters for this rule and places an
unnecessary administrative burden on EPA, while not greatly increasing
nationwide emissions coverage of stationary combustion sources.
In addition, although there is considerable uncertainty as to the
number of facilities under a 25,000 metric tons CO2e
threshold, there is evidence to indicate that moving the threshold from
25,000 to 10,000 metric tons CO2e would have a
disproportionate impact on the commercial sector. It should also be
noted that this concern is even more applicable to the 1,000 metric
tons CO2e threshold.
EPA concluded that a 25,000 metric tons CO2e threshold
would better achieve a comprehensive economy wide coverage of emissions
while focusing reporting efforts on large industrial emitters. In
particular, it would address the considerable uncertainties in the
25,000 to 100,000 metric tons CO2e emissions range, both as
to the number of reporters and the magnitude of emissions. EPA believes
that a 25,000 metric tons CO2e threshold would help in
gathering data from a reasonable number of reporters for which little
information is currently known without imposing undue administrative
burden.
EPA also considered including GHG emissions from the combustion of
biomass fuels in the emission threshold calculations. Therefore, the
proposed rule states that GHG emissions from biomass fuel combustion
are to be excluded when evaluating a facility's status with respect to
the 25,000 metric tons CO2e reporting threshold. This is
similar to the approach taken by the IPCC and various other GHG
emission inventories.
Finally, EPA considered a heat input capacity-based threshold (such
as all facilities with stationary combustion equipment rated over 100
mmBtu/hr maximum heat input capacity). A complete, reliable set of heat
input capacity data was unavailable for all facilities that might be
subject to this rule, thus this type of threshold could not be
thoroughly evaluated.
For a full discussion of the threshold analysis and for background
information on this threshold determination, please refer to the
Thresholds TSD (EPA-HQ-OAR-2008-0508-046). For specific information on
costs, including unamortized first year capital expenditures, please
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
EPA's proposed methods for calculating GHG emissions from
stationary fuel combustion sources is consistent with existing domestic
and international protocols, as well as monitoring programs currently
implemented by EPA. Those protocols and programs generally utilize
either a direct measurement approach based on concentrations of
combustion exhaust gases through a stack, or a direct measurement
approach based on the quantity of fuel combusted and the
characteristics of the fuel (e.g., heat content, carbon content, etc.).
As the magnitude of CO2 emissions released by stationary
combustion sources relative to CH4 and N2O is
greater (even on a CO2e basis), more guidance is provided on
the application of specific monitoring and calculation methods for
CO2. EPA is proposing simpler calculation methods for
CH4 and N2O.
[[Page 16483]]
For facilities which have EGUs subject to the ARP reporting
requirements under 40 CFR part 75, refer to Section V.D of this
preamble regarding those units. For other units located at that
facility (i.e., units that are not reporting to the ARP), the facility
would use the calculation methods presented below.
The discussions which follow in this subsection will focus on
methods for: (a) The calculation of CO2 emissions from fuel
combustion; (b) the calculation for the separate reporting of biogenic
CO2 emissions; (c) reporting biogenic CO2
emissions from MSW; (d) the calculation of CH4 and
N2O emissions; and (e) the calculation of additional
CO2 emissions from the sorbent in combustion control
technology systems.
a. CO2 Emissions From Fuel Combustion
To monitor and calculate CO2 emissions from stationary
combustion sources, EPA is proposing a four-tiered approach, which
would be applied either at the unit or facility level. The most
stringent emissions calculation methods would apply to large stationary
combustion units that are fired with solid fuels and that have existing
CEMS equipment. This is due to the complexity of monitoring solid fuel
consumption and the heterogeneous nature of solid fuels. Furthermore,
because of the significant mass of CO2 emissions that are
released by these large units, combining stringent methods and existing
monitoring equipment is justified.
The next level of methodological stringency applies to large
stationary combustion units that are fired with liquid or gaseous
fuels. The stringency of the methods reflects the homogenous nature of
these fuels and the ability to monitor fuel consumption more precisely.
However, in cases where there is greater heterogeneity in the fuels
(e.g., refinery fuel gas) more frequent analyses of liquid and gaseous
fuels is required.
For smaller combustion units, EPA is proposing to allow the use of
more simplified emissions calculation methods that rely on
relationships between the heat content of the fuel (a generally known
parameter) and the CO2 emission factor associated with the
fuel's characteristics.
The following subsections present EPA's proposed four-tiered
approach in order from the most rigorous to the least stringent, and
describe how it must be used by affected facilities. The applicability
of the four measurement tiers, based on unit size and fuel type, is
summarized in Table C-1 of this preamble. These CO2 emission
calculation methods would, in some cases, be applied at the unit level,
and in other cases at the facility level (for further discussion, see
``Selection of Data Reporting Requirements'' below). Affected
facilities would have the flexibility to use higher-tier methods (i.e.,
more stringent methods) than the ones required by this rule.
Tier 4. The Tier 4 methodology would require the use of certified
CEMS to quantify CO2 mass emissions, where existing CEMS
equipment is installed. The existing installed CEMS must include a gas
monitor of any kind or a flow monitor (or both). Generally, a
CO2 monitor and a stack gas volumetric flow rate monitor
would be required to calculate CO2 emissions, although in
some cases, in lieu of a CO2 concentration monitor, data
from a certified oxygen (O2) concentration monitor and fuel-
specific F-factors could be used to calculate hourly CO2
concentrations. An appropriate upgrade of the existing CEMS would be
required: (1) If the gas monitor is neither a CO2
concentration monitor nor an O2 concentration monitor and
(2) if a flow monitor is not already installed.
Any CEMS that would be used to quantify CO2 emissions
would also have to be certified and undergo on-going quality-assurance
testing according to the procedures specified in either: (1) 40 CFR
part 75; or (2) 40 CFR part 60, Appendix B; or (3) a State monitoring
program.
The Tier 4 method, and the use of CEMS (with any required monitor
upgrades), is required for solid fossil fuel-fired units with a maximum
heat input capacity greater than 250 mmBtu/hr (and for units with a
capacity to combust greater than 250 tons per day of MSW). The use of
an O2 monitor to determine CO2 concentrations
would not be allowed for units combusting MSW. EPA is unaware of
carbon-based F-factors for MSW that would be appropriate for converting
O2 readings to CO2 concentrations for this rule.
Therefore, units combusting MSW would need to use a CO2
monitor to calculate CO2 emissions.
For smaller solid fossil fuel-fired units (i.e., less than or equal
to 250 mmBtu/hr or 250 tons per day of MSW), EPA would require the use
of Tier 4 if all the monitors needed to calculate CO2 mass
emissions (i.e., CO2 gas monitor and flow monitor) are
already installed, and certified and quality assured as described
above.
In addition, in order to be subject to the Tier 4 requirements, the
unit must have been operated for 1,000 hours or more in any calendar
year since 2005.
The incremental cost of adding a diluent gas (CO2 or
O2) monitor or a flow monitor, or both, to meet Tier 4
monitoring requirements would likely not be unduly burdensome for a
large unit that combusts solid fossil fuels or MSW, operates
frequently, and is already required to install, certify, maintain, and
operate CEMS and to perform on-going QA testing of the existing
monitors. The cost of compliance with the proposed rule would be even
less for units that already have all of the necessary monitors in
place. Cost estimates are provided in the RIA (EPA-HQ-OAR-2008-0508-
002). In addition, EPA is allowing provisions to monitor common stack
configurations. Please refer to Section V.C.5 of this preamble, on data
reporting requirements, for further information on reporting where
there are common stack configurations.
Reporters would follow the reporting requirements stated in
proposed 40 CFR part 98, subpart A. However, EPA is allowing a January
1, 2011 compliance date to install CEMS to meet the Tier 4
requirements, if either a diluent gas monitor, flow monitor, or both,
must be added. The January 1, 2011 deadline would allow sufficient time
to purchase, install, and certify any additional monitor(s) needed to
quantify CO2 mass emissions. Until that time, affected units
subject to that deadline would be allowed to use the Tier 3 methodology
in 2010.
Tier 3. The Tier 3 calculation methodology would require periodic
determination of the carbon content of the fuel, using consensus
standards listed in the proposed 40 CFR part 98 (e.g., ASTM methods)
and direct measurement of the amount of fuel combusted. This
methodology is required for liquid and gaseous fossil fuel-fired units
with a maximum heat input capacity greater than 250 mmBtu/hr, and is
required for solid fossil fuel-fired units that are not subject to the
Tier 4 provisions. In addition, EPA is proposing that a facility may
use the Tier 3 calculation methodology to calculate facility-wide
CO2 emissions (rather than unit-by-unit emissions) when the
same liquid or gaseous fuel is used across the facility and a common
direct measurement of fuel consumed is available (e.g., a natural gas
meter at the facility gate). This flexibility is consistent with
existing protocols and methodologies allowed by EPA in existing
programs. Please refer to the subsequent subsection on data reporting
requirements for further information on the use of fuel data from
common supply lines.
[[Page 16484]]
The required frequency for carbon content determinations for the
Tier 3 calculation methodology would be monthly for natural gas, liquid
fuels, and solid fuels (monthly molecular weight determinations are
also required for gaseous fuels). Daily determinations for other
gaseous fuels (e.g., refinery gas, process gas, etc.) would be
required. The daily fuel sampling requirement for units that combust
``other'' gaseous fuels would likely not be overly burdensome, because
the types of facilities that burn these fuels are likely to have
equipment in place (e.g., on-line gas chromatographs) to continuously
monitor the fuels' characteristics in order to optimize process
operation. Solid fuel samples would be taken weekly and composited, but
would only be analyzed once a month. Also, fuel sampling and analysis
would be required only for those days or months when fuel is combusted
in the unit.
For liquid and gaseous fuels, Tier 3 would require direct
measurement of the amount of fuel combusted, using calibrated fuel flow
meters. Alternatively, for fuel oil, tank drop measurements could be
used. Solid fuel consumption would be quantified using company records.
For quality-assurance purposes, EPA proposes that all oil and gas flow
meters would have to be calibrated prior to the first reporting year.
EPA recommends the use of the fuel flow meter calibration methods in 40
CFR part 75, but, alternatively, the manufacturer's recommended
procedure could be used. Tank drop measurements and carbon content
determinations would be made using the appropriate methods incorporated
by reference.
Tier 2. The Tier 2 calculation methodology would require that the
HHVs of each fuel combusted would be measured monthly. EPA is proposing
that the Tier 2 method be used by units with heat input capacities of
250 mmBtu/hr or less, combusting fuels for which EPA has provided
default CO2 emission factors in the proposed rule. Fuel
consumption would be based on company records. Please refer to the
subsequent subsection on data reporting requirements for further
information on the aggregation of units.
Tier 1. Under Tier 1, the annual CO2 mass emissions
would be calculated using the quantity of each type of fuel combusted
during the year, in conjunction with fuel-specific default
CO2 emission factors and default HHVs. The amount of fuel
combusted would be determined from company records. The default
CO2 emission factors and HHVs are national-level default
factors. The Tier 1 method may be used by any small unit if EPA has
provided the fuel-specific HHV and emission factors in proposed 40 CFR
part 98, subpart C. However, if the owner or operator routinely
performs fuel sampling and analysis on a monthly (or more frequent)
basis to determine the HHV and other properties of the fuel, or if
monthly HHV data are provided by the fuel supplier, Tier 1 could not be
used but instead Tier 2 (or a higher tier) would have to be used.
EPA considered several alternative CO2 emission
calculation methods of varying stringency for stationary combustion
units. The most stringent method would have required all combustion
units at the affected facilities to use 40 CFR part 75 monitoring
methodologies. However, this option was not pursued because it would
have likely imposed an undue cost burden, particularly on smaller
entities. For homogenous fuels, this additional cost burden would
probably not lead to significant increases in accuracy compared with
Tiers 1-3.
For coal combustion, EPA evaluated a number of calculation methods
used in other mandatory and voluntary GHG emissions reporting programs.
In general, these methods require relatively infrequent fuel sampling,
do not take into account the heat input capacity of stationary
combustion equipment, and use company records to estimate fuel
consumption. Given the heterogeneous characteristics of coal, EPA
determined that the procedures used in these other programs are not
rigorous enough for this proposed rule and would introduce significant
uncertainty into the CO2 emissions estimates, especially for
larger combustion units.
EPA considered allowing the use of default emission factors,
default HHVs, and company records to quantify annual fuel consumption
for all stationary combustion units, regardless of size or the type of
fuel combusted. The Agency decided to limit the use of this type of
calculation methodology to smaller combustion units. The proposed rule
reflects this, by allowing use of the Tier 1 and Tier 2 calculation
methodologies at units with a maximum heat input capacity of 250 mmBtu/
hr or less.
For gaseous fuel combustion, EPA considered calculation
methodologies based on an assumption that all gaseous fuels are
homogeneous. However, the Agency decided against this approach because
the characteristics of certain gaseous fuels can be quite variable, and
mixtures of gaseous fuels are often heterogeneous in composition.
Therefore, the proposed rule requires daily sampling for all gaseous
fuels except for natural gas.
Finally, EPA considered allowing affected facilities to rely
exclusively on the results of fuel sampling and analysis provided by
fuel suppliers, rather than performing periodic on-site sampling for
all variables. The Agency decided not to propose this because in most
instances, only the fuel heating value, not the carbon content, is
routinely provided by fuel suppliers. Therefore, EPA proposes to allow
fuel suppliers to provide fuel HHVs for the Tier 2 calculation method.
However, EPA is requesting comment on integrating the fuel supplier
requirements of this proposed rule with both the Tier 1 and Tier 2
calculation methodologies.
b. CO2 Emissions From Biomass Fuel Combustion
Today's proposed rule requires affected facilities with units that
combust biomass fuels to report the annual biogenic CO2 mass
emissions separately. As previously described, this is consistent with
the approach taken in the IPCC and national U.S. GHG inventory
frameworks. EPA is proposing distinct methods to determine the biogenic
CO2 emissions from a stationary combustion source combusting
a biomass or biomass-derived fuel depending upon which tier is used for
reporting other fuel combustion CO2 emissions.
Where Tier 4 is not required, EPA is allowing the Tier 1 method to
be used to calculate biogenic CO2 emissions for fuels in
which EPA has provided default CO2 emission factors and a
default HHV in the proposed rule. If default values are not provided by
EPA, the facility would use the Tier 2 or Tier 3 method, as
appropriate, to calculate the biogenic CO2 emissions.
For units required to use Tier 4, total CO2 emissions
are directly measured using CEMS. Except when MSW is combusted, EPA
proposes that facilities perform a supplemental calculation to
determine the biogenic CO2 and non-biogenic CO2
portions of the measured CO2 emissions. The facility would
use company records on annual fossil fuel combusted to calculate the
annual volume of CO2 emitted from that fossil fuel
combustion. This value would then be subtracted from the total volume
of CO2 emissions measured to obtain the volume of biogenic
CO2 emissions. The volume ratio of biogenic CO2
emissions to total CO2 emissions would then be applied to
the measured total CO2 emissions to determine the biogenic
CO2 emissions.
c. CO2 Emissions From MSW
EPA is proposing a separate calculation method for a unit that
[[Page 16485]]
combusts MSW, which can include biomass components. For units subject
to Tier 4, as described above, an additional analysis would be required
to separately report any biogenic CO2 emissions. The
reporter would be required to use ASTM methods listed in the rule to
sample and analyze the CO2 in the flue gas once each
quarter, in order to determine the relative percentages of fossil fuel-
based carbon (e.g., petroleum-based plastics) and biomass carbon (e.g.,
newsprint) in the effluent when MSW is combusted in the unit. The
measured ratio of biogenic to fossil CO2 concentrations is
then applied to the measured or calculated total CO2
emissions to determine biogenic CO2 emissions.
The GHG emission calculation methods for units combusting MSW would
be used in conjunction with EPA's proposed calculation method for the
annual unit heat input, based on steam production and the design
characteristics of the combustion unit.
For units that combust MSW, EPA considered allowing a manual
sorting approach to be used to determine the biomass and non-biomass
fractions of the fuel, based on defined and traceable input streams.
However, this approach is not considered practical, given the highly
variable composition of MSW. To eliminate this uncertainty, EPA
believes that more rigorous and standardized ASTM methods should be
used to determine the biogenic percentage of the CO2
emissions when MSW is combusted.
d. CH4 and N2O Emissions From All Fuel Combustion
As described previously, EPA is allowing simplified emissions
calculation methods for CH4 and N2O. The annual
CH4 and N2O emissions would be estimated using
EPA-provided default emission factors and annual heat input values. The
calculation would either be done at the unit level or the facility
level, depending upon the tier required for estimating CO2
emissions (and using the same heat input value reported from the
CO2 calculation method).
A CEMS methodology was not selected for measuring N2O
primarily because the cost impacts of requiring the installation of
CEMS is high in comparison to the relatively low amount of
N2O emissions (even on a CO2e basis) that would
be emitted from stationary combustion equipment.
EPA considered requiring periodic stack testing to derive site-
specific emission factors for CH4 and N2O. This
approach has the advantage of ensuring a higher level of accuracy and
consistency among reporters. However, it was decided that this option
was too costly for the small improvement in data quality that it might
achieve. The CH4 and N2O emissions from
stationary combustion are relatively low compared to the CO2
emissions. The proposed approach, i.e., using fuel-specific default
emission factors to calculate CH4 and N2O
emissions, is in accordance with methods used in other programs and
provides data of sufficient accuracy. However, given the unit-level
approach for calculating CO2 emissions, EPA is requesting
comments on the use of more technology-specific CH4 and
N2O emission factors that could be applied in unit-level
calculations.
e. CO2 Emissions From Sorbent
For fluidized bed boilers and for units equipped with flue gas
desulfurization systems or other acid gas emission controls with
sorbent injection, CO2 emissions would be accounted for and
reported using simplified methods. These methods are based on the
quantity of limestone or other sorbent material used during the year,
if not accounted for using the Tier 4 calculation methodology.
In summary, EPA is proposing to allow facilities flexibility in
measuring and monitoring stationary fuel combustion sources by: (1)
Allowing most smaller combustion units (depending upon facility-level
considerations described above) to use the Tier 1 and Tier 2
calculation methods; (2) allowing Tier 3 to be widely used, with few
restrictions; (3) limiting the requirement to use Tier 4 to certain
solid fuel-fired combustion units located at facilities where there is
an established monitoring infrastructure; and (4) allowing simplified
methodologies to calculate CH4 and N2O emissions.
In addition, EPA is using a maximum heat input capacity determination
of 250 mmBtu/hr to distinguish between large and small units. This
approach is common to many existing EPA programs.
EPA believes that the proposed default CO2 emission
factors and high heat values used in Tiers 1 and 2 and the ASTM methods
incorporated by reference for the carbon content determinations
required by Tier 3 are well-established and minimize uncertainty.
In proposing this tiered approach, EPA acknowledges that, in the
case of solid fuels, a simple, standardized way of measuring the amount
of solid fuel combusted in a unit is not proposed. In view of this, the
proposed rule would require the owner or operator to keep detailed
records explaining how company records are used to quantify solid fuel
usage. These records would describe the procedures used to calibrate
weighing equipment and other measurement devices, and would include
scientifically-based estimates of the accuracy of these devices. EPA
therefore solicits comment on ways to ensure that the feed rate of
solid fuel to a combustion device is accurately measured.
4. Selection of Procedures for Estimating Missing Data
The proposed rule requires the use of substitute data whenever a
quality-assured value of a parameter that is used to calculate GHG
emissions is unavailable, commonly referred to as ``missing data.'' For
units using the CO2 calculation methodologies in Tiers 2 and
3, when HHV, fuel carbon content, or fuel molecular weight data are
missing, the substitute data value would be the average of the quality-
assured values of the parameter immediately before and immediately
after the missing data period. When Tier 3 or Tier 4 is used and fuel
flow rate or stack gas flow rate data is missing, the substitute data
values would be the best available estimates of these parameters, based
on process and operating data (e.g., production rate, load, unit
operating time, etc.). This same substitute data approach would be used
when fuel usage data and sorbent usage data are missing. The proposed
rule provides that the reporter would be required to document and keep
record of the procedures used to determine the appropriate substitute
data values.
EPA considered more conservative missing data procedures for the
proposed rule, such as requiring higher substitute data values for
longer missing data periods, but decided against proposing these
procedures out of concern that GHG emissions might be significantly
overestimated.
5. Selection of Data Reporting Requirements
In addition to the facility-level information that would be
reported under proposed 40 CFR part 98, subpart A, the proposed rule
would require the reporter to submit certain unit-level data for the
stationary combustion units at each affected facility. This additional
information would require reporting of the unit type, its maximum rated
heat input, the type of fuel combusted in the unit during the report
year, the methodology used to calculate CO2 emissions for
each type of fuel combusted, and the total annual GHG emissions from
the unit.
[[Page 16486]]
To reduce the reporting burden, the proposed rule would allow
reporting of the combined GHG emissions from multiple units at the
facility instead of requiring emissions reporting for each individual
unit, in certain instances. Three types of emissions aggregation would
be allowed. First, the combined GHG emissions from a group (or groups)
of small units at a facility could be reported, provided that the
combined maximum rated heat input of the units in the group does not
exceed 250 mmBtu/hr. Second, the combined GHG emissions from units in a
common stack configuration could be reported, if CEMS are used to
continuously monitor the CO2 emissions at the common stack.
Third, if a facility combusts the same type of homogeneous oil or
gaseous fuel through a common supply line, and the total amount of fuel
consumed through that supply line is accurately measured using a
calibrated fuel flow meter, the combined GHG emissions from the
facility could be reported.
Different levels of verification data are required depending upon
which tier is used for reporting. For Tier 1, only the total quantity
of each type of fuel combusted during the report year would be
reported. For Tier 2, the quantity of each type of fuel combusted
during each measurement period would be reported, along with all high
heat values used in the emissions calculations, the methods used to
determine the HHVs, and information indicating which HHVs (if any) are
substitute data values.
For Tier 3, the quantity of each type of fuel combusted during each
measurement period (day or month) would be reported, along with all
carbon content values and, if applicable, molecular weight measurements
used in the emissions calculations, with information indicating which
ones (if any) are substitute data values. In addition, the results of
all fuel flow meter calibrations would be reported along with
information indicating which analytical methods were used for the
carbon content determinations, flow meter calibrations and (if
applicable) oil tank drop measurements.
For Tier 4, the number of unit operating days and hours would be
reported, along with daily CO2 mass emission totals, the
number of hours of substitute data used in the annual emissions
calculations, the results of the initial CEMS certification tests and
the major ongoing QA tests.
If MSW is combusted in the unit, the owner or operator would be
required to report the results of the quarterly sample analyses used to
determine the biogenic percentage of CO2 emissions in the
effluent. If combinations of fossil and biomass fuels are combusted and
CEMS are used to measure CO2 emissions, the annual volumes
of biogenic and fossil CO2 would be reported, along with the
F-factors and fuel gross calorific values used in the calculations, and
the biogenic percentage of the annual CO2 emissions.
Finally, for units that use acid gas scrubbing with sorbent
injection but are not equipped with CEMS, the owner or operator would
be required to report information on the type and amount of sorbent
used.
6. Selection of Records That Must Be Retained
In addition to meeting the general recordkeeping requirements in
proposed 40 CFR part 98, subpart A, whenever company records are used
to estimate fuel consumption (e.g., when the Tier 1 or 2 emissions
calculation methodology is used) and sorbent consumption, EPA proposes
to require the owner or operator to keep on file a detailed explanation
of how fuel usage is quantified, including a description of the QA
procedures that are used to ensure measurement accuracy (e.g.,
calibration of weighing devices and other instrumentation).
As discussed in Section IV of this preamble and proposed 40 CFR
part 98, subpart A, there are a number of facilities that are not part
of a source category listed in 40 CFR 98.2(1)(a) or (2) but have
stationary combustion equipment emitting GHG emissions. In 2010, those
facilities would have to determine whether or not they are subject to
the requirements of this rule (i.e., if their emissions are 25,000
metric tons CO2e/yr or higher). In order to reduce the
burden on those facilities, we are proposing that facilities with an
aggregate maximum heat input capacity of less than 30 mmBtu/hr from
stationary combustion units are automatically exempt from the proposed
40 CFR part 98. Based on our assessment of the maximum amount of GHG
emissions likely from units of that size that burn fossil fuels (e.g,
coal, oil or gas) and operate continuously through the year, such a
facility would still be below the 25,000 metric tons CO2e
threshold. The purpose for having this provision is to exempt small
facilities from having to estimate emissions to determine if they are
subject to the rule, and re-estimate whenever there are process
changes.
D. Electricity Generation
1. Definition of the Source Category
This section of the preamble addresses GHG emissions reporting for
facilities with EGUs that are in the ARP, and are subject to the
CO2 emissions reporting requirements of Section 821 of the
CAA Amendments of 1990. All other facilities using stationary fuel
combustion equipment to generate electricity should refer to Section
V.C of this preamble (General Stationary Fuel Combustion Sources) to
understand EPA's proposed approach for GHG emissions reporting.
Electricity generating units in the ARP reported CO2
emissions of 2,262 million metric tons CO2e in 2006. This
represents almost one third of total U.S. GHG emissions and over 90
percent of CO2 emissions from electricity generation. EPA
has been receiving these CO2 data since 1995.\64\
---------------------------------------------------------------------------
\64\ This data can be accessed at: http://epa.gov/camdataandmaps.
---------------------------------------------------------------------------
2. Selection of Reporting Threshold
If a facility includes within its boundaries at least one EGU that
is subject to the ARP, the facility would be subject to the mandatory
GHG emissions reporting of proposed 40 CFR part 98, subpart D.
Facilities with EGUs in the ARP would not be expected to report any new
CO2 data. Therefore, EPA expects that the GHG emissions
reporting requirements of this rule would not be overly burdensome for
facilities already reporting to the ARP.
For specific information on costs, including unamortized first year
capital expenditures, please refer to section 4 of the RIA and the RIA
cost appendix.
3. Selection of Proposed Monitoring Methods
For ARP units, the CO2 mass emissions data already
reported to EPA under 40 CFR part 75 would be used in the annual GHG
emissions reports required under this proposed rule. The annual
CO2 mass emissions (i.e., English short tons) reported for
an ARP unit would simply be converted to metric tons and then included
in the GHG emissions report for the facility.
As CH4 and N2O emissions are not required to
be reported under 40 CFR part 75, the facility would consult the
proposed methods in proposed 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources) for calculating CH4 and
N2O from the ARP units.
The additional units at an affected facility that are not in the
ARP would use the GHG calculation methods specified and required in
proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources).
[[Page 16487]]
4. Selection of Procedures for Estimating Missing Data
The proposed missing data substitution procedures for
CH4 and N2O emissions from ARP units and all GHG
emissions from units at the facility not in ARP are discussed in
Section V.C.4 of this preamble, under General Stationary Fuel
Combustion Sources.
5. Selection of Data Reporting Requirements
The proposed data reporting requirements are discussed in Section
V.C.5 of this preamble, under General Stationary Fuel Combustion
Sources.
6. Selection of Records That Must Be Retained
The records that must be retained regarding CH4 and
N2O emissions from ARP units and all GHG emissions from
units at the facility not in the ARP are discussed in Section V.C.6 of
this preamble, under General Stationary Fuel Combustion Sources.
E. Adipic Acid Production
1. Definition of the Source Category
Adipic acid is a white crystalline solid used in the manufacture of
synthetic fibers, plastics, coatings, urethane foams, elastomers, and
synthetic lubricants. Commercially, it is the most important of the
aliphatic dicarboxylic acids, which are used to manufacture polyesters.
Adipic acid is also used in food applications.
Adipic acid is produced through a two-stage process. The first
stage usually involves the oxidation of cyclohexane to form a
cyclohexanone/cyclohexanol mixture. The second stage involves oxidizing
this mixture with nitric acid to produce adipic acid.
National emissions from adipic acid production were estimated to be
9.3 million metric tons CO2e (less than 0.1 percent of U.S.
GHG emissions) in 2006. These emissions include both process-related
emissions (N2O) and on-site stationary combustion emissions
(CO2, CH4, and N2O). The main GHG
emitted from adipic acid production is N2O, which is
generated as a by-product of the nitric acid oxidation stage of the
manufacturing process, and it is emitted in the waste gas stream.
Process N2O emissions alone were estimated at 5.9 million
metric tons CO2e, or 64 percent of the total GHG emissions
in 2006, while on-site stationary combustion emissions account for the
remaining 3.4 million metric tons CO2e, or 36 percent of the
total.
Process emissions from the production of adipic acid vary with the
types of technologies and level of emission controls employed by a
facility. DE for N2O emissions can vary from 90 to 98
percent using abatement technologies such as nonselective catalytic
reduction. In 1998, the three major adipic acid production facilities
in the U.S. had control systems in place. Only one small facility,
representing approximately two percent of adipic acid production, does
not control for N2O.
As part of this proposed rule, stationary combustion emissions
would be estimated and reported according to the applicable procedures
in proposed 40 CFR part 98, subpart C. For additional background
information on adipic acid production, please refer to the Adipic Acid
Production TSD (EPA-HQ-OAR-2008-0508-005).
2. Selection of Reporting Threshold
In developing the threshold for adipic acid production, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e. Table E-1 of
this preamble illustrates that the various thresholds do not affect the
amount of emissions or number of facilities that would be covered.
Table E-1. Threshold Analysis for Adipic Acid Production
----------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Threshold level metric tons Total Total number -------------------------------------------------------
CO2e/yr national of Metric tons
emissions facilities CO2e/yr Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000....................... 9,300,000 4 9,300,000 100 4 100
10,000...................... 9,300,000 4 9,300,000 100 4 100
25,000...................... 9,300,000 4 9,300,000 100 4 100
100,000..................... 9,300,000 4 9,300,000 100 4 100
----------------------------------------------------------------------------------------------------------------
Facility-level emissions estimates based on known facility
capacities for the four known adipic acid facilities suggests that each
of the facilities would be at least five times over the 100,000 metric
tons CO2e threshold based on just process-related emissions.
Because all adipic acid production facilities would have to report
under any of the emission thresholds that were examined, we propose
that all adipic acid production facilities be required to report. This
would simplify rule applicability and avoid any burden for the source
to perform unnecessary calculations.
For a full discussion of the threshold analysis, please refer to
the Adipic Acid Production TSD (EPA-HQ-OAR-2008-0508-005). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating adipic acid production
process emissions (e.g., 2006 IPCC Guidelines, U.S. Inventory, DOE
1605(b), and TRI). These methodologies coalesce around the four options
discussed below.
Option 1. Default emission factors would be applied to total
facility production of adipic acid. The emissions would be calculated
using the total production of adipic acid and the highest international
default emission factor available in the 2006 IPCC Guidelines. This
option assumes no abatement of N2O emissions. This approach
is consistent with IPCC Tier 1 and the DOE 1605(b) ``C'' rated
estimation method.
Option 2. Default emission factors would be applied on a site-
specific basis using the specific type of abatement technology used and
the adipic acid production activity. The amount of N2O
emissions would be determined by multiplying the technology-specific
emission factor by the production level of adipic acid. This approach
is consistent with 1605(b) ``B'' rated estimation method, IPCC Tier 2,
and TCR's ``B'' rated estimation method.
Option 3. Periodic direct emission measurement of N2O
emissions would be used to determine the relationship between adipic
acid production and the amount of N2O emissions; i.e., to
develop a facility-specific emissions
[[Page 16488]]
factor. The facility-specific emissions factor and production rate
(activity level) would be used to calculate the emissions. The
facility-specific emission factor would be developed from a single
annual test. Production rate is most likely already measured at
facilities. Existing procedures would be followed to measure the
production rate during the performance test and on a quarterly basis
thereafter. After the initial test, annual testing of N2O
emissions would be required each year to estimate the emission factor
and applied to production to estimate emissions. The yearly testing
would assist in verifying the emission factor. Testing would also be
required whenever the production rate is changed by more than 10
percent from the production rate measured during the most recent
performance test. Option 3 and the following Option 4 are approaches
consistent with IPCC Tier 3, DOE 1605(b) ``A'' and TCR's ``A2'' rated
estimation methods.
Option 4. CEMS would be used to directly measure the N2O
process emissions. CEMS would be used to directly measure
N2O concentration and flow rate to directly determine
N2O emissions. Measuring N2O emissions directly
with CEMS is feasible, but adipic acid production facilities are
currently only using NOX CEMS to comply with State programs
(e.g. Texas). Half of the adipic acid production facilities are located
in Texas where NOX CEMS are required in O3
nonattainment areas under Control of Air Pollution from Nitrogen
Compounds (TX Chap 117 (Reg 7)).
Proposed option: We propose Option 3 to quantify process emissions
from all adipic acid facilities. In addition, you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C to
estimate emissions of CO2, CH4 and N2O
from stationary combustion.
We identified Options 3 and 4 as the approaches providing the
lowest uncertainty and the best site-specific estimates based on
differences in process operation and abatement technologies. Option 3
requires annual monitoring of N2O emissions and the
establishment of a facility-specific emissions factor that relates
N2O emissions with adipic acid production rate.
Option 4 was not chosen as the required method because, while
N2O CEMS are available, there is no existing EPA method for
certifying N2O CEMS, and the cost impact of requiring the
installation of CEMS is high in comparison to the relatively low amount
of emissions that would be quantified from the adipic acid production
sector. NOX CEMS only capture emissions of NO and
NO2 and not N2O. Although the amount of
NOX and N2O emissions from adipic acid production
may be directly related, direct measurement of NOX does not
automatically correlate to the amount of N2O in the same
exhaust stream. Periodic testing of N2O emissions (Option 3)
would not indicate changes in emissions over short periods of time, but
it does offer direct measurement of GHGs.
We request comment on the advantages and disadvantages of using
Options 3 and 4. After consideration of public comments, we may
promulgate one or more of these options or a combination based on the
additional information that is provided.
We decided against Options 1 and 2 because facility-specific
emission factors are more appropriate for reflecting differences in
process design and operation. According to IPCC, the default emission
factors for adipic acid are relatively certain because they are derived
from the stoichiometry of the chemical reaction employed to oxidize
nitric acid. However, there is still uncertainty in the amount of
N2O that is generated. This variability is a result of
differences in the composition of cyclohexanone and cyclohexanol
feedstock. Variability also arises if adipic acid is produced from use
of other feedstocks, such as phenol or hydrogen peroxide. Facility-
specific emission factors would be based on actual feedstock
composition rather than an assumed composition.
The various approaches to monitoring GHG emissions are elaborated
in the Adipic Acid Production TSD (EPA-HQ-OAR-2008-0508-005).
4. Selection of Procedures for Estimating Missing Data
For process sources that use Option 3 (facility-specific emission
factor), no missing data procedures would apply because the facility-
specific emission factor is derived from an annual performance test and
used in each calculation. The emission factor would be multiplied by
the production rate, which is readily available. If the test data are
missing or lost, the test would have to be repeated. Therefore, 100
percent data availability would be required.
5. Selection of Data Reporting Requirements
We propose that facilities submit their total annual N2O
emissions from adipic acid production, as well as any stationary fuel
combustion emissions. In addition we propose that facilities submit the
following data, which are the basis of the calculations and are needed
to understand the emissions data and verify the reasonableness of the
reported emissions. The data submitted on an annual basis should
include annual adipic acid production capacity, total adipic acid
production, facility-specific emission rate factor used, abatement
technology used, abatement technology efficiency, abatement utilization
factor, and number of facility operating hours in calendar year.
Capacity, actual production, and operating hours support
verification of the emissions data provided by the facility. The
production rate can be determined through sales records or by direct
measurement using flow meters or weigh scales. This industry generally
measures the production rate as part of normal operating procedures.
A list of abatement technologies would be helpful in assessing the
widespread use of abatement in the adipic acid source category,
cataloging any new technologies that are being used, and documenting
the amount of time that the abatement technologies are being used.
A full list of data to be reported is included in the proposed 40
CFR part 98, subparts A and E.
6. Selection of Records That Must Be Retained
We propose that facilities maintain records of annual testing of
N2O emissions, calculation of the facility-specific emission
rate factor, hours of operation, annual adipic acid production, adipic
acid production capacity, and N2O emissions. These records
hold values directly used to calculate the emissions that are reported
and are necessary to allow determination of whether the GHG emissions
monitoring calculations were done correctly. A full list of records
that must be retained on site is included in the proposed 40 CFR part
98, subparts A and E.
F. Aluminum Production
1. Definition of the Source Category
This source category includes primary aluminum production
facilities. Secondary aluminum production facilities would not be
required to report emissions under Subpart F. Aluminum is a light-
weight, malleable, and corrosion-resistant metal that is used in
manufactured products in many sectors including transportation,
packaging, building and construction. As of 2005, the U.S. was the
fourth largest producer of primary aluminum, with approximately eight
percent of the world total (Aluminum Production TSD
[[Page 16489]]
(EPA-HQ-OAR-2008-0508-006)). The production of primary aluminum--in
addition to consuming large quantities of electricity--results in
process-related emissions of CO2 and two PFCs:
perfluoromethane (CF4) and perfluoroethane
(C2F6). Only these process-related emissions are
discussed here. Stationary fuel combustion source emissions must be
monitored and reported according to proposed 40 CFR part 98, subpart C
(General Stationary Fuel Combustion Sources), which is discussed in
Section V.C of this preamble.
CO2 is emitted during the primary aluminum smelting
process when alumina (aluminum oxide, Al2O3) is
reduced to aluminum using the Hall-H[eacute]roult reduction process.
The reduction of the alumina occurs through electrolysis in a molten
bath of natural or synthetic cryolite (Na3AlF6).
The reduction cells contain a carbon lining that serves as the cathode.
Carbon is also contained in the anode, which can be a carbon mass of
paste, coke briquettes, or prebaked carbon blocks from petroleum coke.
During reduction, most of the carbon in the anode is oxidized and
released to the atmosphere as CO2. In addition, a smaller
amount of CO2 is released during the baking of anodes for
use in smelters using prebake technologies.
In addition to CO2 emissions, the primary aluminum
production industry is also a source of PFC emissions. During the
smelting process, if the alumina ore content of the electrolytic bath
falls below critical levels required for electrolysis, rapid voltage
increases occur, which are termed ``anode effects.'' These anode
effects cause carbon from the anode and fluorine from the dissociated
molten cryolite bath to combine, thereby producing emissions of
CF4 and C2F6. For any particular
individual smelter, the magnitude of emissions for a given level of
production depends on the frequency and duration of these anode
effects. As the frequency and duration of the anode effects increase,
emissions increase. In addition, even at constant levels of production
and anode effect minutes, emissions vary among smelter technologies
(e.g., Center-Work Prebake vs. Side-Work Prebake) and among individual
smelters using the same smelter technology due to differing operational
practices.
Total U.S. Emissions. According to the U.S. GHG Inventory total
process-related GHG emissions from primary aluminum production in the
U.S. are estimated to be 6.4 million metric tons CO2e in
2006. Process emissions of CO2 from the 14 aluminum smelters
in the U.S. were estimated to be 3.9 million metric tons
CO2e in 2006. Process emissions of CF4 and
C2F6 from aluminum smelters were estimated to be
2.5 million metric tons CO2e in 2006. In 2006, 13 of the 14
primary aluminum smelters in the U.S. accounted for the vast majority
of primary aluminum emissions. The remaining smelter was idle through
most of 2006, restarting at the end of the year.
Emissions to be reported. We propose to require reporting of the
following types of emissions from primary aluminum production: Process
emissions of PFCs, process emissions of CO2 from consumption
of the anode during electrolysis (for both Prebake and S[oslash]derberg
cells), and process emissions of CO2 from the anode baking
process (for Prebake cells only).
Another potential source of process CO2 emissions is
coke calcining. We request comment on whether any U.S. smelters operate
calcining furnaces and the extent of these process emissions.
2. Selection of Reporting Threshold
We propose to require all owners or operators of primary aluminum
facilities to report the total quantities of PFC and CO2
process emissions. In 2006, 5 companies operated 14 primary aluminum
for at least part of the year. (One of these smelters operated only
briefly at the end of the year.) All primary aluminum smelters that
operated throughout 2006 would be covered at all capacity and
emissions-based thresholds considered in this analysis.
In developing the threshold for primary aluminum, we considered the
emissions thresholds 1,000, 10,000, 25,000, and 100,000 metric tons
CO2e per year (metric tons CO2e/yr). These
emissions thresholds translate to 64, 640, 1,594, and 6,378 metric tons
primary aluminum produced, respectively, based on use of the 2006 IPCC
default emission factors and assuming side-worked prebake cells and 100
percent capacity utilization as shown in Table F-1 of this preamble.
Table F-1. Threshold Analysis for Aluminum Production Based on 2006 Emissions and Facility Production Capacity
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Total national Total number ----------------------------------------------------------------
Emission threshold level metric tons CO2e/yr emissions of facilities Metric tons
CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000.................................................. 6,402,000 14 6,402,000 100 14 100
10,000................................................. 6,402,000 14 6,397,000 99.9 13 93
25,000................................................. 6,402,000 14 6,397,000 99.9 13 93
100,000................................................ 6,402,000 14 6,397,000 99.9 13 93
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production Capacity Threshold metric tons Al/year
--------------------------------------------------------------------------------------------------------------------------------------------------------
64..................................................... 6,402,000 14 6,402,000 100 14 100
640.................................................... 6,402,000 14 6,402,000 100 14 100
1,594.................................................. 6,402,000 14 6,402,000 100 14 100
6,378.................................................. 6,402,000 14 6,402,000 100 14 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
We propose that all primary aluminum facilities be subject to
reporting. All smelters that operated in 2006 would be required to
report if a 10,000, 25,000, or 100,000 metric tons CO2e per
year threshold were used. Requiring all facilities to report would
simplify the rule, avoid the need for facilities to estimate emissions
to determine applicability, and ensure complete coverage of emissions
from this source category. It results in little extra burden for the
industry since few if any additional facilities would be required to
report (compared to the thresholds considered). Significant
fluctuations in capacity utilization do occur; aluminum smelters
sometimes shut down for long periods. Under the proposed rule,
facilities that did not operate at all during the previous year
[[Page 16490]]
would still have to submit a report; however, reporting would be
minimal. (Zero production implies zero emissions.)
For a full discussion of the threshold analysis, please refer to
the Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
This section of this preamble provides monitoring methods for
calculating and reporting process CO2 and PFC emissions
only. If a facility has stationary fuel combustion it would need to
also refer to proposed 40 CFR part 98, subpart C for methods for
CO2, CH4 and N2O and would be required
to follow the calculation procedures, monitoring and QA/QC methods,
recordkeeping requirements as described.
Protocols and guidance reviewed for this analysis include the 2006
IPCC Guidelines, EPA's Voluntary Aluminum Industrial Partnership, the
Inventory of U.S. Greenhouse Gas Emissions and Sinks, the International
Aluminum Institute's Aluminum Sector Greenhouse Gas Protocol, the
Technical Guidelines for the Voluntary Reporting of Greenhouse Gases
(1605(b)) Program, EPA's Climate Leaders Program, and TRI.
The methods described in these protocols and guidance coalesce
around the methods described by the International Aluminum Institute's
Aluminum Sector Greenhouse Gas Protocol and the 2006 IPCC Guidelines.
These methods range from Tier 1 approaches based on aluminum production
to Tier 3 approaches based primarily on smelter-specific data. The IPCC
Tier 3 and International Aluminum Institute methods are essentially the
same.
Proposed Method for Monitoring PFC Emissions. The proposed method
for monitoring PFC emissions from aluminum processing is similar to the
Tier 3 approach in the 2006 IPCC Guidelines for primary aluminum
production. The proposed method requires smelter-specific data on
aluminum production, anode effect minutes per cell day (anode effect-
mins/cell-day), and recently measured slope coefficients. The slope
coefficient represents kg of CF4/metric ton of aluminum
produced divided by anode effect minutes per cell-day. The cell-day is
the number of cells operating multiplied by the number of days of
operation, per the 2006 IPCC Guidelines. The following describes how to
calculate CF4 and C2F6 emissions based
on the slope method. CF4 emissions equal the slope
coefficient for CF4 (kg CF4/metric ton Al)/anode
effect-Mins/cell-day) times metal production (metric tons Al). Annual
anode effect calculations and records should be the sum of anode effect
minutes per cell day and production by month.
C2F6 emissions equal emissions of CF4
times the weight fraction of C2F6/CF4
(kg C2F6/kg CF4).
Both the IPCC Tier 3 method and the less accurate IPCC Tier 2
method are based on these equations and parameters. The critical
distinction between the two methods is that the Tier 3 method requires
smelter-specific slope coefficients while the Tier 2 method relies on
default, technology-specific slope coefficients. Of the currently
operating U.S. smelters, all but one has measured a smelter-specific
coefficient at least once. However, as discussed below, some smelters
may need to update these measurements if they occurred more than 3
years ago.
Use of the Tier 3 approach significantly improves the precision of
a smelter's PFC emissions estimate. For individual facilities using the
most common smelter technology in the U.S., the uncertainty (95 percent
confidence interval) of estimates developed using the Tier 2 approach
is 50 percent,\65\ while the uncertainty of estimates
developed using the Tier 3 approach is approximately 15
percent (Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006)). For a
typical U.S. smelter emitting 175,000 metric tons CO2e in
PFCs, these errors result in absolute uncertainties of 88,000 metric tons CO2e and 26,000 metric
tons CO2e, respectively. The reduction in uncertainty
associated with moving from the Tier 2 to the Tier 3 approach, 62,000
metric tons CO2e, is as large as the emissions from many of
the sources that would be subject to the rule. We concluded the extra
burden to facilities of measuring the smelter-specific slope
coefficients is justified by the considerable improvement in the
precision of the reported emissions.
---------------------------------------------------------------------------
\65\ The most common smelter technology in the U.S. is the
center-worked prebake technology. The 2006 IPCC Guidelines provide a
95 percent confidence interval of 6 percent for the
center-worked prebake technology default slope coefficient. However,
this range is not the range within which the slope coefficient from
a single center-worked prebake technology has a 95 percent chance of
falling. Instead, it is the range within which the true mean of all
center-worked prebake technology slope factors has a 95 percent
chance of falling. This appears to depart from the usual convention
for expressing the uncertainties related to the use of default
coefficients in the Guidelines.
---------------------------------------------------------------------------
Measurement of Slope Coefficients. We propose that slope
coefficients be measured using a method similar to the USEPA/
International Aluminum Institute Protocol for Measurement of
Tetrafluoromethane and Hexafluoroethane from Primary Aluminum
Production. The protocol establishes guidelines to ensure that
measurements of smelter-specific slope-coefficients are consistent and
accurate (e.g., representative of typical smelter operating conditions
and emission rates). These guidelines include recommendations for
documenting the frequency and duration of anode effects, measuring
aluminum production, sampling design, measurement instruments and
methods, calculations, QA/QC, and measurement frequency.
During the past few years, multiple U.S. smelters have adopted
changes to their production process which are likely to have changed
their slope coefficients.\66\ These include the adoption of slotted
anodes and improvements to process control algorithms. Although some
U.S. smelters have recently updated their measurements of smelter-
specific coefficients, others may not have.
---------------------------------------------------------------------------
\66\ Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006).
---------------------------------------------------------------------------
We understand that two smelting companies in the U.S., Rio Tinto
Alcan and Alcoa, have the necessary equipment and teams in-house to
measure smelter-specific slope factors. These two companies account for
11 out of 15 of the operating smelters in the U.S. The remaining
facilities would need to hire a consultant to conduct a measurement
study once every three years to accurately determine their slope
coefficients. The cost of hiring a consultant to conduct the
measurement study is probably significantly lower than the capital,
labor and O&M costs of the equipment, training, and maintenance
required to conduct the measurements in-house. While the cost to
implement a Tier 3 approach is significantly greater than the cost to
implement a Tier 2 approach, the benefit of reduced uncertainty is
considerable (approximately 40 percent), as noted above.
We request comment on the proposal that all smelters be required to
measure their smelter-specific slope coefficients at least once every
three years. We considered, but are not proposing, to exempt ``high
performing'' smelters, as defined by the 2006 IPCC Guidelines, from the
requirement to measure their smelter-specific slope coefficients more
[[Page 16491]]
than once. The Guidelines define ``high-performing'' smelters as those
that operate with less than 0.2 anode effect minutes per cell day or
less than 1.4 millivolt overvoltage. The Guidelines state, ``no
significant improvement can be expected in the overall facility GHG
inventory by using the Tier 3 method rather than the Tier 2 method.''
(IPCC, page 4.53, footnote 1). However, EPA believes there is benefit
to EPA and to industry of periodic evaluation of the correlation of the
smelter-specific slope coefficient and actual emissions, even in
situations of low anode effect minutes per cell day or overvoltage.
The Overvoltage Method. Another Tier 3 method included in the IPCC
Guidelines is the Overvoltage Method. This method relates PFC emissions
to an overvoltage coefficient, anode effect overvoltage, current
efficiency, and aluminum production. The overvoltage method was
developed for smelters using the Pechiney technology. We request
comment on whether any U.S. smelters are using the Pechiney technology
and, if so, on whether these smelters should be permitted to use the
Overvoltage Method.
Proposed Method for Monitoring Process CO2 Emissions. If
you are required to use an existing CEMS to meet the requirements
outlined in proposed 40 CFR part 98, subpart C, you would be required
to use CEMS to estimate stationary fuel combustion CO2
emissions. Where the CEMS capture all combustion- and process-related
CO2 emissions you would be required to follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
proposed 40 CFR part 98, subpart C to estimate process and stationary
fuel combustion CO2 emissions from the industrial source.
Also, refer to proposed 40 CR part 98, subpart C to estimate
combustion-related CH4 and N2O.
If your facility does not have stationary combustion, or if you do
not currently have CEMS that meet the requirements outlined in proposed
40 CR part 98, subpart C, or where the CEMS would not adequately
account for process CO2 emissions, the proposed monitoring
method for process CO2 emissions is similar to the IPCC Tier
2 approach, which relies on industry defaults rather than smelter-
specific values for concentrations of minor anode components.
CO2 emitted during electrolysis. We propose to require
that CO2 emitted during electrolysis be calculated based on
metal production and net anode consumption using a mass balance
approach that assumes all carbon from net anode consumption is
ultimately emitted as CO2. Since the concentrations of the
non-carbon components are small (typically less than one percent to
five percent), facility-specific data on them is not as critical to the
precision of emission estimates as is facility-specific data on net
anode consumption. Tier 3 improves the accuracy of the results but the
improvement in accuracy is not expected to exceed 5 percent per the
2006 IPCC Guidelines. Although we do not propose to require the use of
the Tier 3 approach, we would allow and encourage smelter operators to
use facility-specific data on anode non-carbon components when that
data were available.
For prebake cells, CO2 emissions are equal to net
prebaked anode consumption per metric ton aluminum times total metal
production times the percent weight of sulfur and ash content in the
baked anode times the molecular mass of CO2.
CO2 emissions from S[oslash]derberg cells are a function
of total metal production, paste consumption, emissions of cyclohexane
soluble matter, percent binder and sulfur content in paste, percent ash
and hydrogen content in pitch, percent weight of sulfur and ash content
in calcined coke, carbon in skimmed dust from S[oslash]derberg cells,
and the carbon atomic mass ratio.
The data reported by companies participating in EPA's Voluntary
Aluminum Industrial Partnership has generally not included smelter-
specific values for each of these variables. However, most participants
in the Voluntary Aluminum Industrial Partnership have used either data
on paste consumption (for S[oslash]derberg cells) or on net anode
consumption (for Prebake cells), along with some smelter-specific data
on impurities, to develop a hybrid IPCC Tier 2/3 estimate (i.e.,
combination of smelter-specific and default factors).
CO2 emitted during anode baking. We propose that
CO2 emitted during anode baking be calculated based on a
mass balance approach involving chemical contents of the anodes and
packing materials. No anode baking emissions occur when using
S[oslash]derberg cells, since these cells are not baked before aluminum
smelting, but rather, bake in the electrolysis cell during smelting.
CO2 emissions from pitch volatiles combustion equal the
initial weight from green anode minus hydrogen content minus baked
anode production minus waste tar collected times the molecular weight
of CO2. CO2 emissions from bake furnace packing
material are a function of packing coke consumption times baked anode
production times the percent weight sulfur and ash content in packing
coke.
As is the case for CO2 emitted during electrolysis, the
IPCC Tier 2 approach for anode baking relies on industry-wide defaults
for minor anode components, requiring smelter-specific data only for
the initial weight of green anodes and for baked anode production. The
IPCC Tier 3 approach requires smelter-specific values for all
parameters. Again, the concentrations of minor components are small,
limiting their impact on the estimate of CO2 emissions from
anode baking. In addition, anode baking emissions account for
approximately 10 percent of total CO2 process emissions, so
reducing the uncertainty in this estimate would have only a minor
impact on the overall CO2 process estimate. For EPA's
Voluntary Aluminum Industrial Partnership program, many smelters report
only some smelter-specific values for the concentrations of minor anode
components. In light of these considerations, we propose to require the
Tier 2 method for estimating CO2 emissions from anode
baking, with the option to use facility-specific data on impurity
concentrations when that data is available.
Other Options Considered. We are not proposing IPCC's Tier 1
methodology for calculating PFC emissions. Although this methodology is
simple, the default emission factors for PFCs have large uncertainties
due to the variability in anode effect frequency and duration. Since
1990, all U.S. smelters have sharply reduced their anode effect
frequency and duration; through 2006, average anode minutes per cell
day have declined by approximately 85 percent, lowering U.S. smelter
emission rates well below those of the IPCC Tier 1 defaults.
Consequently, as discussed above, the Tier 3 methodology has been
proposed.
For CO2, we are not proposing IPCC's Tier 1 methodology
for calculating emissions. The difference in uncertainty between
emission estimates developed using IPCC Tier 1 and Tier 2/3 approaches
for U.S. smelters is notably lower than the difference for the PFC
estimates. However, as part of typical operations, facilities regularly
monitor inputs to higher Tier methods (e.g., consumption of anodes);
consequently, the incremental cost to use the IPCC Tier 2 or a Tier 2/3
hybrid estimate are small.
[[Page 16492]]
4. Selection of Procedures for Estimating Missing Data
Where anode effect minutes per cell day data points are missing,
the average anode effect minutes per cell day of the remaining
measurements within the same reporting period may be applied. These
parameters are typically logged by the process control system as part
of the operations of nearly all aluminium production facilities and the
uncertainties in these data are low.
It is likely that aluminum production levels would be well known,
since businesses rely on accurate monitoring and reporting of
production levels. The 2006 IPCC Guidelines specify an uncertainty of
less than 1 percent in the data for the annual production of aluminum.
The likelihood for missing data is low.
For CO2 emissions, the uncertainty in recording anode
consumption as baked anode consumption or coke consumption is estimated
to be only slightly higher than for aluminium production, less than 2
percent per the 2006 IPCC Guidelines. This is also an important
parameter in smelter operations and is routinely/continuously
monitored. Again, the likelihood for missing data is low.
5. Selection of Data Reporting Requirements
In addition to annual GHG emissions data, facilities would be
required to submit annual aluminum production and smelter technology
used. The following PFC-specific information would also be required to
be reported on an annual basis: Anode effect minutes per cell-day, and
anode effect frequency and duration. Smelters would also be required to
submit smelter-specific slope coefficient; the last date when smelter-
specific slope coefficient was measured; certification that
measurements of slope coefficients were conducted in accordance with
the method identified in proposed 40 CFR part 98, subpart F; and the
parameters used by the smelter to measure the frequency and duration of
anode effects.
The following CO2-specific information would be reported
on an annual basis: Anode consumption for pre-bake cells, paste
consumption for S[oslash]derberg cells, and smelter-specific inputs to
the CO2 process equations (e.g., levels of impurities) that
were used in the calculation. Exact data elements required would vary
depending on smelter technology.
These records consist of values that are used to calculate the
emissions and are necessary to enable verification that the GHG
emissions monitoring and calculations were done correctly.
6. Selection of Records That Must Be Retained
In addition to the data reported, we propose that facilities
maintain records on monthly production by smelter, anode effect minutes
per cell-day or anode effect overvoltage by month, facility specific
emission coefficient linked to anode effect performance, and net anode
consumption for Prebake cells or paste consumption for S[oslash]derberg
cells.
These records consist of data that would be used to calculate the
GHG emissions and are necessary to verify that the emissions monitoring
and calculations are done correctly.
G. Ammonia Manufacturing
1. Definition of the Source Category
Ammonia is a major industrial chemical that is mainly used as
fertilizer, directly applied as anhydrous ammonia, or further processed
into urea, ammonium nitrates, ammonium phosphates, and other nitrogen
compounds. Ammonia also is used to produce plastics, synthetic fibers
and resins, and explosives.
Ammonia can be produced through three processes: Steam reforming,
solid fuel gasification, and brine electrolysis. The production of
ammonia typically uses conventional steam reforming or solid fuel
gasification and generates both combustion and process-related
greenhouse gas emissions. The production of ammonia through the brine
electrolysis process does not produce process GHG emissions, although
it releases GHGs from combustion of fuels to support the electrolysis
process. We have not identified any facilities in the U.S. producing
ammonia through the brine electrolysis process.
Catalytic steam reforming of ammonia generates process-related
CO2, primarily through the use of natural gas as a
feedstock. One plant located in Kansas is manufacturing ammonia from
petroleum coke feedstock. This and other natural gas-based and
petroleum coke-based feedstock processes produce CO2 and
hydrogen, the latter of which is used in the manufacture of ammonia.
Not all of the CO2 produced in the manufacture of
ammonia is emitted directly to the atmosphere. Both ammonia and
CO2 are used as raw materials in the production of urea
(CO(NH2)2), which is another type of nitrogenous
fertilizer that contains carbon (C) and nitrogen (N). The carbon from
ammonia production that is used to manufacture urea is assumed to be
released into the environment as CO2 during urea use.
Therefore, the majority of CO2 emissions associated with
urea consumption are those that result from its use as a fertilizer.
For CO2 collected and used onsite or transferred offsite,
you must follow the methodology provided in proposed 40 CFR part 98,
subpart PP (Suppliers of CO2).
Some facilities produce for sale a combination of ammonia,
methanol, and hydrogen. We propose that facilities report their
process-related GHG emissions in the source category corresponding to
the primary NAICS code for the facility. For example, a facility that
primarily produces ammonia but also produces methanol would report in
the ammonia manufacturing source category. Since CO2 is used
to produce methanol, it does not get emitted directly into the
atmosphere. These facilities would account for the CO2 used
to produce methanol through the methodology provided in proposed 40 CFR
part 98, subpart G (Ammonia Manufacturing).
National emissions from ammonia manufacturing were estimated to be
14.6 million metric tons CO2 equivalent (<0.25 percent of
U.S. GHG emissions in 2006). These emissions include both process
related CO2 emissions and on-site stationary combustion emissions
(CO2, CH4, and N2O) from 24
manufacturing facilities across the U.S. Process-related emissions
account for 7.6 million metric tons CO2, or 52 percent of
the total, while on-site stationary combustion emissions account for
the remaining 7.0 million metric tons CO2 equivalent
emissions.
For additional background information on ammonia manufacturing,
please refer to the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-
007).
2. Selection of Reporting Threshold
In developing the reporting threshold for ammonia manufacturing, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e. Table G-1 of
this preamble illustrates the emissions and facilities that would be
covered under these various thresholds.
[[Page 16493]]
Table G-1. Threshold Analysis for Ammonia Manufacturing
----------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Total Total number -----------------------------------------------
Threshold level metric tons CO2e/yr national of Metric
emissions facilities tons CO2e/ Percent Number Percent
yr
----------------------------------------------------------------------------------------------------------------
1,000............................... 14,543,007 24 14,543,007 100 24 100
10,000.............................. 14,543,007 24 14,543,007 100 24 100
5,000............................... 14,543,007 24 14,543,007 100 24 100
100,000............................. 14,543,007 24 14,449,519 99 22 92
----------------------------------------------------------------------------------------------------------------
Facility-level emissions estimates based on known plant capacities
suggest that all known facilities, except two, exceed the 100,000
metric tons CO2e threshold. Where information was available,
emission estimates were adjusted to account for CO2
consumption during urea production, and this was taken into account in
the threshold analysis. In order to simplify the proposed rule and
avoid the need for the source to calculate and report whether the
facility exceeds the threshold value, we propose that all ammonia
manufacturing facilities are required to report.
For a full discussion of the threshold analysis, please refer to
the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international monitoring guidelines and protocols
include methodologies for estimating both combustion and process-
related emissions from ammonia manufacturing (e.g., 2006 IPCC
Guidelines, U.S. Inventory, DOE 1605(b), and TCR). These methodologies
coalesce around the following four options which we considered for
quantifying emissions from ammonia manufacture:
Option 1. The first method found in existing protocols estimates
emissions by applying a default emission factor to total ammonia
produced. This approach estimates only process-related emissions. This
approach is consistent with IPCC Tier 1 and DOE 1605(b) ``C'' rated
estimation methods.
Option 2. A second method consists of performing a mass balance
calculation using default carbon content values for feedstock (from the
U.S. DOE). Using default carbon content for fuel would not provide the
same level of accuracy as using facility-specific carbon contents. This
approach is consistent with IPCC Tier 2, DOE 1605(b) and TCR's ``B''
rated estimation methods.
Option 3. The third option is based on the IPCC Tier 3 method for
determining CO2 emissions from ammonia manufacture. This
method calculates emissions based on the monthly measurements of the
total feedstock consumed (quantity of natural gas or other feedstock)
and the monthly carbon content of the feedstock. All carbon in the
feedstock is assumed to be oxidized to CO2. The accuracy and
certainty of this approach is directly related to the accuracy of the
feedstock usage and the carbon content of the feedstock. If the
measurements or readings are made and verified according to established
QA/QC methods, the resulting emission calculations are as accurate as
possible. For CO2 collected and used onsite or transferred
offsite, you must follow the methodology provided in proposed 40 CFR
part 98, subpart PP of this part (Suppliers of CO2). This
approach is also consistent with DOE's 1605(b) ``A'' rated method and
TCR's ``A2'' rated estimation methods.
Option 4. The fourth option is using CEMS to directly measure
CO2 emissions. While this method does tend to provide the
most accurate emissions measurements, it is likely the costliest of all
the monitoring methods.
Proposed Option. Under the proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C and the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow requirements of proposed 40 CFR part 98, subpart C to estimate
CO2 emissions from the industrial source.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
the CEMS does not measure CO2 process emissions, the
proposed monitoring method is Option 3. You would be required to follow
the requirements of proposed 40 CFR part 98, subpart C to estimate
CO2, CH4 and N2O emissions from
stationary combustion.
The proposed monitoring method is Option 3. Options 3 and 4 provide
the most accurate estimates from site-specific conditions. Option 3 is
consistent with current feedstock monitoring practices at facilities
within this industry, thereby minimizing costs. For CO2 collected and
used onsite or transferred offsite, you must follow the methodology
provided in proposed 40 CFR part 98, subpart PP (Suppliers of CO2).
In general, we decided against existing methodologies that relied
on default emission factors or default values for carbon content of
materials because the differences among facilities could not be
discerned, and such default approaches are inherently inaccurate for
site-specific determinations. The use of default values is more
appropriate for sector-wide or national total estimates from aggregated
activity data than for determining emissions from a specific facility.
The various approaches to monitoring GHG emissions are elaborated
in the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007).
4. Selection of Procedures for Estimating Missing Data
The proposed rule requires the use of substitute data whenever a
quality-assured value of a parameter that is used to calculate GHG
emissions is unavailable, or ``missing.'' For missing feedstock supply
rates, use the lesser of the maximum supply rate that the unit is
capable of processing or the maximum supply rate that the meter can
measure. There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are
determined to be invalid.
5. Selection of Data Reporting Requirements
We propose that facilities that estimate their process CO2
emissions under proposed 40 CFR part 98, subpart G, submit their
process CO2 emissions data and the following additional data on an
annual basis. These data are the basis for calculations and are needed
for us to understand the emissions data and verify the reasonableness
of the reported emissions. We propose facilities submit
[[Page 16494]]
the following data on an annual basis for each process unit: The total
quantity of feedstock consumed for ammonia manufacturing, the monthly
analyses of carbon content for each feedstock used in ammonia
manufacturing. A full list of data to be reported is included in
proposed 40 CFR part 98, subparts A and G.
6. Selection of Records That Must Be Retained
We propose that each ammonia manufacturing facility maintain
records of monthly carbon content analyses, and the method used to
determine the quantity of feedstock used. These records consist of
values that are directly used to calculate the emissions that are
reported and are necessary to enable verification that the GHG
emissions monitoring and calculations were done correctly.
H. Cement Production
1. Definition of the Source Category
Hydraulic Portland cement, the primary product of the cement
industry, is a fine gray or white powder produced by heating a mixture
of limestone, clay, and other ingredients at high temperature.
Limestone is the single largest ingredient required in the cement-
making process, and most cement plants are located near large limestone
deposits. CO2 from the chemical process of cement production is the
second largest source of industrial CO2 emissions in the U.S.
During the cement production process, calcium carbonate (CaCO3)
(usually from limestone and chalk) is combined with silica-containing
materials (such as sand and shale) and is heated in a cement kiln at a
temperature of about 1,450 [deg]C (2,400 [deg]F). The CaCO3 forms
calcium oxide (or CaO) and CO2 in a process known as calcination or
calcining. Very small amounts of carbonates other than CaCO3, such as
magnesium carbonates and non-carbonate organic carbon may also be
present in the raw materials, both of which contribute to generation of
additional CO2. The product from the cement kiln is clinker, an
intermediate product, and the CO2 generated as a by-product. The CO2 is
released to the atmosphere.
Additional CO2 emissions are generated with the formation of
partially calcinated cement kiln dust. During clinker production, some
of the clinker precursor materials (instead of forming clinker) are
entrained in the flue gases exiting the kiln as non-calcinated,
partially calcinated, or fully calcinated cement kiln dust \67\. Cement
Kiln Dust is collected from the flue gas in dust collection equipment
and can either be recycled back to the kiln or be sent offsite for
disposal, depending on its quality. Organic carbon in raw materials is
also emitted as CO2 as raw material is heated.
---------------------------------------------------------------------------
\67\ Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
---------------------------------------------------------------------------
National GHG emissions from cement production were estimated to be
86.83 million metric tons CO2e in 2006. These emissions include both
process-related emissions (CO2) and on-site stationary combustion
emissions (CO2, CH4, and N2O) from 107 cement production facilities.
Process-related emissions account for over half of emissions (45.7
million metric tons CO2), while on-site stationary combustion emissions
account for the remaining 41.1 million metric tons CO2e emissions.
For additional background information on cement production, please
refer to the Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
2. Selection of Reporting Threshold
In developing the threshold for cement manufacturing, we considered
emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric
tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e. Table
H-1 of this preamble illustrates the emissions and facilities that
would be covered under these thresholds.
Table H-1. Threshold Analysis for Cement Manufacturing
----------------------------------------------------------------------------------------------------------------
Emissions Covered Facilities Covered
Total ---------------------------------------------------
Threshold level metric tons national Total number Million
CO2e/yr emissions of facilities metric tons Percent Number Percent
(MMTCO2e) CO2e/yr
----------------------------------------------------------------------------------------------------------------
1,000.......................... 86.83 107 86.83 100 107 100
10,000......................... 86.83 107 86.83 100 107 100
25,000......................... 86.83 107 86.83 100 107 100
100,000........................ 86.83 107 86.74 99.9 106 99.9
----------------------------------------------------------------------------------------------------------------
All emissions thresholds examined covered over 99.9 percent of CO2e
emissions from cement facilities. Only one plant out of 107 in the
dataset would be excluded by a 100,000 metric tons CO2e threshold. All
facilities would be included under a 25,000 metric tons CO2e threshold.
Therefore, EPA is proposing that all cement production facilities are
required to report. Having no threshold covers all of the cement
production process emissions without increasing the number of
facilities that must report and simplifies the rule.
For a full discussion of the threshold analysis, please refer to
the Cement Production TSD (EPA-HQ-OAR-2008-0508-008). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from cement manufacturing (e.g., the 2006 IPCC Guidelines,
U.S. Inventory, DOE 1605(b), CARB mandatory GHG emissions reporting
program, EPA's Climate Leaders, the EU Emissions Trading System, and
the Cement Sustainability Initiative Protocol). These
[[Page 16495]]
methodologies coalesce around four different options.
Option 1. Apply a default emission factor to the total quantity of
clinker produced at the facility. The quantity of clinker produced
could be directly measured, or a clinker fraction could be applied to
the total quantity of cement produced.
Option 2. Apply site-specific emission factors to the quantity of
clinker produced.
Option 3. Measure the carbonate inputs to the furnace. Under this
``kiln input'' approach, emissions are calculated by weighing the mass
of individual carbonate species sent to the kiln, multiplying by the
emissions factor (relating CO2 emissions to carbonate content in the
kiln feed), and subtracting for uncalcined cement kiln dust.
Option 4. Direct measurement of emissions using CEMS.
Proposed Option. Based on the agency's review of the above
approaches, we propose two different methods for quantifying GHG
emissions from cement manufacturing, depending on current emissions
monitoring at the facility.
CEMS Method. Under the proposed rule, if you are required to use an
existing CEMS to meet the requirements outlined in proposed 40 CFR part
98, subpart C, you would be required to use CEMS to estimate CO2
emissions. Where the CEMS capture all combustion- and process-related
CO2 emissions you would be required to follow the requirements of
proposed 40 CFR part 98, subpart C to estimate all CO2 emissions from
the industrial source. Also, refer to proposed 40 CFR part 98, subpart
C (discussed in Section V.C of this preamble) to estimate combustion-
related CH4 and N2O.
Calculation Method (Option 2). For facilities that do not currently
have CEMS that meet the requirements outlined in proposed 40 CFR part
98, subpart C, or where the CEMS would not adequately account for
process emissions, we propose that these facilities calculate emissions
following Option 2 outlined below. You would be required to follow the
requirements of proposed 40 CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from stationary combustion. The cement
production section provides only those procedures for calculating and
reporting process-related emissions.
Under Option 2, we propose that facilities develop facility-
specific emission factors relating CO2 emissions to clinker production
for each individual kiln. The emission factor relating CO2 emissions to
clinker production would be based on the percent of measured carbonate
content in the clinker (measured on a monthly basis) and the fraction
of calcination achieved. The clinker emission factor is then multiplied
by the monthly clinker production to estimate monthly process-related
CO2 emissions from cement production. Annual emissions are calculated
by summing CO2 emissions over 12 months across all kilns at the
facility.
Most current protocols propose this method, but allow facilities to
apply a national default emission factor. We propose the development of
a facility-specific emission factor based on the understanding that
facilities analyze the carbonate contents of their raw materials to the
kiln on a frequent basis, either on a daily basis or every time there
is a change in the raw material mix.
Cement Kiln Dust. The CO2 emissions attributable to calcined
material in the cement kiln dust not recycled back to the kiln must be
added to the estimate of CO2 emissions from clinker production. To
establish a cement kiln dust adjustment factor, we propose that
facilities conduct a chemical analysis on a quarterly basis to estimate
the plant-specific fraction of uncalcined carbonate in the cement kiln
dust from each kiln, that is not recycled to the kiln each quarter.
Again, this method provides reasonable accuracy and is highly
consistent with the prevailing methods presented in existing protocols.
TOC Content in Raw Materials. The CO2 emissions attributable to the
TOC content in raw material must be added to the estimate of CO2
emissions from clinker production and cement kiln dust. We propose that
facilities conduct an annual chemical analysis to determine the organic
content of the raw material on an annual basis. The emissions are
calculated from the TOC content by multiplying the organic content by
the amount of raw material consumed annually.
Other Options Considered. We considered three alternative options
to estimate process-related emissions from cement production. The first
method considered was to apply default emission factors to clinker
production (either based on measurement of clinker, or by applying a
clinker fraction to cement production). Applying default emission
factors to clinker production is one of the most common approaches in
existing protocols. However, we have determined that applying default
emission factors to clinker production is more appropriate for
national-level emissions estimates than facility-specific estimates,
where data are readily available to develop site-specific emission
factors.
In some protocols, this method requires correcting for purchases
and sales of clinker, such that a facility is only accounting for
emissions from the clinker that is manufactured on site. This approach
provides better emissions data than protocols where the method does not
correct for clinker purchases and sales. In some protocols, the method
requires reporters to start with cement production, estimate the
clinker fraction, and then estimate the carbonate input used to produce
the clinker. Conceptually, this might not be any different than the
kiln input approach as the facility would ultimately have to identify
and quantify the carbonate inputs to the kiln.
The kiln input approach was considered, but not proposed, because
it would not lead to significantly reduced uncertainty in the emissions
estimate over the clinker based approach, where a site-specific
emission factor is developed using periodic sampling of the carbonate
mix into the kiln. The primary difference is the proposed clinker-based
approach requires a monthly analysis of the degree of calcination
achieved in the clinker in order to develop the facility-specific
emissions factor, whereas the kiln input approach would require monthly
monitoring of the inputs and outputs of the kiln. We concluded that
although the kiln input does not improve certainty estimates
significantly, it could potentially be more costly depending on the
carbonate input sampling frequency.
Early domestic and international guidance documents for estimating
process CO2 emissions from cement production offered the option of
applying a default emission factor to cement production (e.g. IPCC Tier
1, DOE 1605(b) ``C'' rated approach). This is no longer considered an
acceptable method in national inventories therefore we did not consider
it further for developing a mandatory GHG reporting rule.
The various approaches to monitoring GHG emissions are elaborated
in the Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
4. Selection of Procedures for Estimating Missing Data
For facilities with CEMs, we propose that facilities follow the
missing data procedures in proposed 40 CFR part 98, subpart C, which
are also discussed in Section V.C of this preamble.
For facilities without CEMs, we propose that no missing data
procedures would apply because the emission
[[Page 16496]]
factors used to estimate CO2 emissions from clinker and cement kiln
dust production are derived from routine tests of carbonate contents.
In the event data on carbonate content analysis is missing we propose
that the facility undertake a new analysis of carbonate contents. We
are not proposing any missing data allowance for clinker and cement
kiln dust production data. The likelihood for missing input, clinker
and cement kiln dust production data is low, as businesses closely
track their purchase of production inputs, quantity of clinker
produced, and quantity of cement kiln dust discarded.
5. Selection of Data Reporting Requirements
We propose that facilities submit annual CO2 emissions
from cement production, as well as any stationary fuel combustion
emissions. In addition, facilities using CEMS would be required to
follow the data reporting requirements in proposed 40 CFR part 98,
subpart C. Facilities using the clinker-based approach would be
required to report annual clinker production, annual cement kiln dust
production, number of kilns, site-specific clinker emission factor, the
total annual fraction of cement kiln dust recycled to the kiln, and the
quantity of CO2 captured for use and the end use, if known.
In addition, we propose that facilities submit their annual analysis of
carbonate composition, the total annual fraction of calcination
achieved (for each carbonate), organic carbon content of the raw
material, and the amount of raw material consumed annually. These data,
used as the basis of the calculations, are needed for EPA to understand
the emissions data and verify reasonableness of the reported emissions.
A full list of data to be reported is included in proposed 40 CFR part
98, subparts A and H.
6. Selection of Records That Must Be Retained
In addition to the data reported, we propose that facilities using
the clinker-based approach to calculate emissions keep records of
monthly carbonate consumption, monthly cement production, monthly
clinker production, results from monthly chemical analysis of
carbonates, documentation of calculated site specific clinker emission
factor, quarterly cement kiln dust production, total annual fraction
calcination achieved, organic carbon content of the raw material, and
the amount of raw material consumed annually. These records include
values directly used to calculate the reported emissions; and these
records are necessary to verify the estimated GHG emissions. A full
list of records that must be retained onsite is included in proposed 40
CFR part 98, subparts A and H.
I. Electronics Manufacturing
1. Definition of the Source Category
The electronics industry uses multiple long-lived fluorinated GHGs
such as PFCs, HFCs, SF6, and NF3 during
manufacturing of semiconductors, liquid crystal displays (LCDs),
microelectrical mechanical systems (MEMs), and photovoltaic cells (PV).
We are also seeking comment below on the inclusion of light-emitting
diodes (LEDs), disk readers and other products as part of the
electronics manufacturing source category.
The fluorinated gases (at room temperature) are used for plasma
etching of silicon materials and cleaning deposition tool chambers.
Additionally, semiconductor manufacturing employs fluorinated GHGs
(typically liquids at room temperature) as heat transfer fluids. The
most common fluorinated GHGs in use are HFC-23, CF4,
C2F6, NF3 and SF6, although
other compounds such as perfluoropropane (C3F8)
and perfluorocyclobutane (c-C4F8) are also used
(EPA, 2008a).
Electronics manufacturers may also use N2O as the oxygen source for
chemical vapor deposition of silicon oxynitride or silicon dioxide.
Besides dielectric film etching and chamber cleaning, much smaller
quantities of fluorinated gases are used to etch polysilicon films and
refractory metal films like tungsten. Table I-1 of this preamble
presents the fluorinated GHGs typically used during manufacture of each
of these electronics devices.
Table I-1. Fluorinated GHGs Used by the Electronics Industry
------------------------------------------------------------------------
Fluorinated GHGs used during
Product type manufacture
------------------------------------------------------------------------
Electronics (e.g., Semiconductor, CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
MEMS, LCD, PV). C4F6, C5F8, CHF3, CH2F2, NF3,
SF6, and Heat Transfer Fluids
(CF3-(O-CF(CF3)-CF2)n-(O-CF2)m-O
-CF3, CnF2n+2, CnF2n+1(O)
CmF2m+1, CnF2nO, (CnF2n+1)3N)a.
------------------------------------------------------------------------
a IPCC Guidelines do not specify the fluorinated GHGs used by the MEMs
industry. Literature reviews revealed that CF4, SF6, and the Bosch
process (consisting of alternating steps of SF6 and c-C4F8) are used
to manufacture MEMs. For further information, see the Electronics
Manufacturing TSD (EPA-HQ-OAR-2008-0508-009).
The etching process uses plasma-generated fluorine atoms, which
chemically react with exposed dielectric film to selectively remove the
desired portions of the film. The material removed as well as
undissociated fluorinated gases flow into waste streams and, unless
emission control systems are employed, into the atmosphere.
Chambers used for depositing dielectric films are cleaned
periodically using fluorinated and other gases. During the cleaning
cycle the gas is converted to fluorine atoms in plasma, which etches
away residual material from chamber walls, electrodes, and chamber
hardware. Undissociated fluorinated gases and other products pass from
the chamber to waste streams and, unless emission control systems are
employed, into the atmosphere.
In addition to emissions of unreacted gases, some fluorinated
compounds can also be transformed in the plasma processes into
different fluorinated GHGs which are then exhausted, unless abated,
into the atmosphere. For example, when C2F6 is
used in cleaning or etching, CF4 is generated and emitted as a process
by-product.
Fluorinated GHG liquids (at room temperature) such as fully
fluorinated linear, branched or cyclic alkanes, ethers, tertiary amines
and aminoethers, and mixtures thereof are used as heat transfer fluids
at several semiconductor facilities to cool process equipment, control
temperature during device testing, and solder semiconductor devices to
circuit boards. The fluorinated heat transfer fluid's high vapor
pressures can lead to evaporative losses during use.\68\ We are seeking
comment on the extent of use and
[[Page 16497]]
annual replacement quantities of fluorinated liquids as heat transfer
fluids in other electronics sectors, such as their use for cooling or
cleaning during LCD manufacture.
---------------------------------------------------------------------------
\68\ Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009);
2006 IPCC Guidelines.
---------------------------------------------------------------------------
Total U.S. Emissions. Emissions of fluorinated GHGs from an
estimated 216 electronics facilities were estimated to be 6.1 million
metric tons CO2e in 2006. Below is a breakdown of emissions
by electronics product type.
Semiconductors. Emissions of fluorinated GHGs, including heat
transfer fluids, from 175 semiconductor facilities were estimated to be
5.9 million metric tons CO2e in 2006. Of the total estimated
semiconductor emissions, 5.4 million metric tons CO2e are
from etching/chamber cleaning and 0.5 million metric tons
CO2e are from heat transfer fluid usage. Partners of the PFC
Reduction/Climate Partnership for Semiconductors comprise approximately
80 percent of U.S. semiconductor production capacity. These partners
have committed to reduce their emissions (exclusive of heat transfer
fluid emissions) to 10 percent below their 1995 levels by 2010, and
their emissions have been on a general decline toward attainment of
this goal since 1999.
MEMs. Emissions of fluorinated GHGs from 12 facilities were
estimated to be 0.03 million metric tons CO2e in 2006.
LCDs. Emissions of fluorinated GHGs from 9 facilities were
estimated to be 0.02 million metric tons CO2e in 2006.
PVs. Emissions of fluorinated GHGs from 20 PV facilities were
estimated to be 0.07 million metric tons CO2e in 2006. We
request comment on the number and capacity of thin film (i.e.,
amorphous silicon) and other PV manufacturing facilities in the U.S.
using fluorinated GHGs.
Emissions To Be Reported. This section details our proposed
requirements for reporting fluorinated GHG and N2O emissions
from the following processes and activities:
(1) Plasma etching;
(2) Chamber cleaning;
(3) Chemical vapor deposition using N2O as the oxygen source; and
(4) Heat transfer fluid use.
Our understanding is that only semiconductor facilities use heat
transfer fluids; we request comment on this assumption.
For additional background information on the electronics industry,
refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009).
2. Selection of Reporting Threshold
For manufacture of semiconductors, LCDs, and MEMs, we are proposing
capacity-based thresholds equivalent to an annual emissions threshold
of 25,000 metric tons CO2e. For manufacture of PVs for which
we have less information on use and emissions of fluorinated GHGs, we
are proposing an emissions threshold of 25,000 metric tons of
CO2e.
We are seeking comment on the inclusion of LEDs, disk readers and
other products in the electronics manufacturing source category. Given
that the manufacturing process for these devices is similar to other
electronics, we are specifically interested in seeking feedback on the
level of emissions from their manufacturer and whether subjecting these
products to an emissions threshold of 25,000 metric ton CO2e
would be appropriate.
In our analysis, we considered emission thresholds of 1,000 metric
tons CO2e, 10,000 metric tons CO2e, 25,000 metric
tons CO2e, and 100,000 metric tons CO2e per year.
Table I-2 of this preamble shows emissions and facilities that would be
captured by the respective emissions thresholds.
Table I-2. Threshold Analysis for Electronics Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Total national Total number ----------------------------------------------------------------
Emission threshold level metric tons CO2e/yr emissions of facilities Metric tons
CO2e/yr Percent Facilities Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000.................................................. 5,984,462 216 5,972,909 99.8 173 80
10,000................................................. 5,984,462 216 5,840,411 98 118 55
25,000................................................. 5,984,462 216 5,708,283 95 96 44
100,000................................................ 5,984,462 216 4,708,283 79 54 25
--------------------------------------------------------------------------------------------------------------------------------------------------------
We selected the 25,000 metric tons CO2e per year
threshold because this threshold maximizes emissions reporting, while
excluding small facilities that do not contribute significantly to the
overall GHG emissions.
We propose to use a production-based threshold based on the rated
capacities of facilities, as opposed to an emissions-based threshold,
where possible, because it simplifies the applicability determination.
Therefore, we derived production capacity thresholds that are
approximately equivalent to metric tons CO2e using IPCC Tier
1 default emissions factors and assuming 100 percent capacity
utilization. Where IPCC Tier 1 default factors were unavailable (i.e.,
MEMs), the emissions factor was estimated based on those of
semiconductors for the relevant fluorinated GHGs. The proposed
capacity-based thresholds are 1,000 m2 silicon for
semiconductors; 4,000 m2 silicon for MEMs; and 236,000 m2
LCD for LCDs. Table I-3 of this preamble shows the estimated emissions
and number of facilities that would report for each source under the
proposed capacity-based thresholds. PV is not shown in the table
because we are proposing an emissions threshold due to lack of
information.
Table I-3. Summary of Rule Applicability Under the Proposed Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
Capacity-based Total national emissions of ---------------------------------------------------------------
Emissions source threshold facilities source (metric Metric tons
tons CO2e) CO2e/yr Percent Facilities Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semi-conductors................... 1,080 silicon m2.... 175 5,741,676 5,492,066 96 91 52
MEMs.............................. 1,020 silicon m2.... 12 146,115 96,164 66 2 17
LCD............................... 235,700 LCD m2...... 9 23,632 0 0 0 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 16498]]
The proposed capacity-based thresholds are estimated to cover about
50 percent of semiconductor facilities and between 0 percent and 20
percent of the facilities manufacturing MEMs and LCDs. At the same
time, the thresholds are expected to cover nearly 96 percent of
fluorinated GHG emissions from semiconductor facilities, and 0 percent
and 66 percent of fluorinated GHG emissions from facilities
manufacturing LCDs and MEMs, respectively. Combined these emissions are
estimated to account for close to 94 percent of fluorinated GHG
emissions from electronics as a whole.
We are proposing capacity-based thresholds for the electronics
industry, where possible, because electronics manufacturers may employ
emissions control equipment (e.g., thermal oxidizers, fluorinated GHG
capture recycle systems) to lower their fluorinated GHG emissions. In
addition, capacity-based thresholds would permit facilities to quickly
determine whether or not they must report under this rule.
When abatement equipment is used, electronics manufacturers often
estimate their emissions using the manufacturer-published DRE for the
equipment. However, abatement equipment may fail to achieve its rated
DRE either because it is not being properly operated and maintained or
because the DRE itself was incorrectly measured due to a failure to
account for the effects of dilution. (For example, CF4 can
be off by as much as a factor of 20 to 50 and
C2F6 can be off by a factor of up to 10 because
of failure to properly account for dilution.) In either event, the
actual emissions from facilities employing abatement equipment may
exceed estimates based on the rated DREs of this equipment and may
therefore exceed the 25,000 metric tons CO2e threshold
without the knowledge of the facility operators. Measuring and
reporting emission control device performance is therefore important
for developing an accurate estimate of emissions. As discussed below,
we propose an emission estimation method that would account for
destruction by abatement equipment only if facilities verified the
performance of their abatement equipment using one of two methods. If
facilities choose not to verify the performance of their abatement
equipment, the estimation method would not account for any destruction
by the abatement device.
For additional background information on the threshold analysis,
refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009).
For specific information on costs, including unamortized first year
capital expenditures, please refer to section 4 of the RIA and the RIA
cost appendix.
3. Selection of Proposed Monitoring Methods
a. Etching and Cleaning Emissions
Fluorinated GHG Emissions. Under the proposed rule, large
semiconductor facilities (defined as facilities with annual capacities
of greater than 10,500 m\2\ silicon) would be required to estimate
their fluorinated GHG emissions from etching and cleaning using an
approach based on the IPCC Tier 3 method, and all other facilities
would be required to use an approach based on the IPCC Tier 2b method.
We have determined that large semiconductor facilities are already
using Tier 3 methods and/or have the necessary data readily available
either in-house or from suppliers to apply the highest tier method. The
difference between the proposed approaches and the IPCC methods is that
the proposed approaches include stricter requirements for quantifying
the gas destroyed by abatement equipment, as described below. None of
the IPCC methods require a standard protocol to estimate DREs of
abatement equipment. Given that the actual DRE of the abatement
equipment can be significantly smaller (by up to a factor of 50)
compared to the manufacturer rated DRE, we are proposing verification
of the DREs using a standard reporting protocol (Burton, 2007).
Under the proposed rule, we estimate that 17 percent of all
semiconductor manufacturing facilities would be required to report
using an IPCC Tier 3 approach (equivalent to 29 facilities out of 175
total facilities) and that 56 percent of total semiconductor emissions
(equivalent 3.4 million metric tons CO2e out of a total 5.9
million metric tons CO2e emissions) would be reported using
the IPCC Tier 3 approach.
Method for Large Facilities. The IPCC Tier 3 approach uses company-
specific data on (1) gas consumption, (2) gas utilization, (3) by-
product formation, and (4) DRE for all emission abatement processes at
the facility.
Information on gas consumption by process is often gathered as
business as usual,\69\ and information on gas utilization, by-product
formation, and DRE for each process is readily available from tool
manufacturers and can also be experimentally measured on-site at the
facility. We propose that the DRE for abatement equipment be
experimentally measured using the protocol described below.
---------------------------------------------------------------------------
\69\ In the RIA for this rulemaking, we have conservatively
included the costs of gathering, consolidating, and checking
process-specific gas consumption information. However, we believe
that this information is already gathered in many cases for purposes
of internal process control and/or emissions reporting under EPA's
voluntary PFC Reduction Program for the Semiconductor Industry.
---------------------------------------------------------------------------
The guidance prepared by International SEMATECH Technology Transfer
0612485A-ENG (December 2006) must be followed when preparing
gas utilization and by-product formation measurements. We have
determined that electronics manufacturers commonly track fluorinated
GHG consumption using flow metering systems calibrated to 1
percent or better accuracy. Thus the equation for estimating emissions
does not account for cylinder heels. However, a facility may choose to
estimate consumption by weighing fluorinated GHG cylinders when placed
into and taken out of service, as is common practice by the magnesium
industry.
The use of the IPCC Tier 3 method and standard site-specific DRE
measurement would provide the most certain and practical emission
estimates for large facilities. The uncertainty associated with an IPCC
Tier 3 approach is lower than any of the other IPCC approaches, and is
on the order of 30 percent at the 95 percent confidence
interval. We estimate that the Tier 3 approach would not impose a
significant burden on facilities because large semiconductor facilities
are already using Tier 3 methods and/or have the necessary data to do
so readily available, as noted above.
Method for Other Semiconductor, LCD, MEMS, and PV Facilities. The
IPCC Tier 2b approach is based on gas consumption by process type
(i.e., etch or chamber clean) multiplied by default factors for
utilization, by-product formation, and destruction. We are proposing
that site-specific DRE measurements be used for quantifying the amount
of gas destroyed. The DRE measurements would be determined using the
protocol described below.
The Tier 2b approach does not account for variation among
individual processes or tools and, therefore, the estimated emissions
have an uncertainty about twice as high as that of IPCC Tier 3
estimates. However, we have concluded that the IPCC Tier 3 method would
be unduly burdensome to the estimated 146 facilities with annual
production less than 10,500 m\2\ silicon. We estimate that the IPCC
Tier 2b approach would not impose a significant burden on facilities
because it requires only minimal fluorinated gas usage tracking by
major production process type. These production input
[[Page 16499]]
data are readily available at all U.S. manufacturing facilities.
N2O Emissions. We are proposing that electronics manufacturers use
a simple mass-balance approach to estimate emissions of N2O
during etching and chamber cleaning. This methodology assumes
N2O is not converted or destroyed during etching or chamber
cleaning, due to lack of N2O utilization data. We request
comment on utilization factors for N2O during etching and
chamber cleaning, and any data on N2O by-product formation.
Verification of DRE. For facilities that employ abatement devices
and wish to reflect the emission reductions due to these devices in
their emissions estimates, two methods are proposed for verifying the
DRE of the equipment. Either method may be followed.
The first method would require facilities (or their equipment
suppliers) to test the DRE of the equipment using an industry standard
protocol, such as the one under development by EPA as part of the PFC
Reduction/Climate Partnership for Semiconductors (not yet published).
This draft protocol requires facilities to experimentally determine the
effective dilution through the abatement device and to measure
abatement DRE during actual or simulated process conditions. The second
method would require facilities to buy equipment that has been tested
by an independent third party (e.g., UL) using an industry standard
protocol such as the one under development by EPA. Under this approach,
manufacturers would pay the third party to select random samples of
each model and test them. Because testing would not need to be obtained
for every piece of equipment sold, this approach would probably be less
expensive than in-house testing by electronics manufacturers, but it
may not capture the full range of conditions under which the abatement
equipment would actually be used.
We believe that the proposed DRE measurement method is generally
robust, but we are requesting comment on one aspect of that method. We
are concerned that the DREs measured and calculated for CF4
may vary depending on the mix of input gases used in the electronics
manufacturing process. The calculated DRE for CF4 may be
influenced by the formation of CF4 from other PFCs during
the destruction process itself, and different input gases have
different CF4 byproduct formation rates. This means that a
DRE for CF4 calculated using one set of input gases might
over- or under-estimate CF4 emissions when applied to
another set of input gases (or even the original set in different
proportions). We request comment on the likelihood and potential
severity of such errors and on how they might be avoided.
Facilities pursuing either DRE verification method would also be
required to use the equipment within the manufacturer's specified
equipment lifetime, operate the equipment within manufacturer specified
limits for the gas mix and exhaust flow rate intended for fluorinated
GHG destruction, and maintain the equipment according to the
manufacturer's guidelines. We request comment on these proposed
requirements.
b. Emissions of Heat Transfer Fluids
We propose that electronics manufacturers use the IPCC Tier 2
approach, which is a mass-balance approach, to estimate the emissions
of each fluorinated heat transfer fluid. The IPCC Tier 2 approach uses
company-specific data and accounts for differences among facilities'
heat transfer fluids (which vary in their GWPs), leak rates, and
service practices. It has an uncertainty on the order of 20
percent at the 95 percent confidence interval according to the 2006
IPCC Guidelines. The Tier 2 approach is preferable to the IPCC Tier 1
approach, which relies on a default emissions factor to estimate heat
transfer fluid emissions and has relatively high uncertainty compared
to the Tier 2 approach.
c. Review of Existing Reporting Programs and Methodologies
We reviewed the PFC Reduction/Climate Partnership for the
Semiconductor Industry, U.S. GHG Inventory, 1605(b), EPA Climate
Leaders, WRI, TRI, and the World Semiconductor Council methods for
estimating etching and cleaning emissions. All of the methods draw from
both the 2000 and 2006 IPCC Guidelines.
Etching and Cleaning. For etching and cleaning emissions, we
considered the 2006 IPCC Tier 1 and Tier 2a methods, as well as a Tier
2b/3 hybrid which would apply Tier 3 to the most heavily used
fluorinated GHGs in all facilities.
The Tier 1 approach is based on the surface area of substrate
(e.g., silicon, LCD or PV-cell) produced during manufacture multiplied
by a default gas-specific emission factor. The advantages of the Tier 1
approach lie in its simplicity. However, this method does not account
for the differences among process types (i.e., etching versus
cleaning), individual processes, or tools, leading to uncertainties in
the default emission factors of up to 200 percent at the 95 percent
confidence interval.\70\ Facilities routinely monitor gas consumption
as part of business as usual, making it technically feasible to employ
a method of at least IPCC Tier 2a complexity or higher without
additional data collection efforts.
---------------------------------------------------------------------------
\70\ This uncertainty refers only to semiconductors and LCDs.
Tier 1 emission factor uncertainty for PV was not estimated in the
2006 IPCC Guidelines.
---------------------------------------------------------------------------
The Tier 2a approach is based on the gas consumption multiplied by
default factors for utilization, by-product formation, and destruction.
The Tier 2a approach is relatively simple, given that gas consumption
data is collected as part of business as usual. However, due to
variation in gas utilization between etching and cleaning processes,
the estimated emissions using Tier 2a have greater uncertainty than
Tier 2b estimated emissions.
Tier 2b/3 hybrid approach involves requiring Tier 3 reporting for
all facilities, but only for the top three gases emitted at each
facility. For all other gases, the Tier 2b approach would be required.
The top three gases emitted, based on data in the Inventory of U.S. GHG
Emissions and Sinks, are C2F6, CF4,
and SF6 (EPA, 2008a). These top three gases accounted for
approximately 80 percent of total fluorinated GHG emissions from
semiconductor manufacturing during etching and chamber cleaning in
2006. The uncertainty associated with the Tier 2b/3 hybrid approach has
not been determined, but is estimated to be between the uncertainty for
a Tier 2b and Tier 3 approach.
We did not select the Tier 1 and Tier 2a methods due to the greater
uncertainty inherent in these approaches. Although the Tier 2b/3 hybrid
approach would provide more accurate emissions estimates for small
facilities, we concluded that the Tier 2b method with site-specific DRE
measurements would provide sufficient accuracy without the additional
monitoring and recordkeeping requirements of the Tier 3 method.
We propose collecting emissions data from MEMS manufacturers
meeting the threshold criterion although no IPCC default emission
factors exist for MEMs and the IPCC emission factors for semiconductor
and LCD manufacturing may not be reliable for MEMs. Therefore, we are
seeking information on emissions and emission factors for both MEMs and
LCD manufacturing.
Heat Transfer Fluids. For heat transfer fluid emissions, we
reviewed both the IPCC Tier 1 and IPCC Tier 2 approaches. The Tier 1
approach for heat transfer fluid emissions is based on the
[[Page 16500]]
utilization capacity of the semiconductor facility multiplied by a
default emission factor. Although the Tier 1 approach has the
advantages of simplicity, it is less accurate than the Tier 2 approach
according to the 2006 IPCC Guidelines.
4. Selection of Procedures for Estimating Missing Data
Where facility-specific process gas utilization rates and by-
product gas formation rates are missing, facilities can estimate
etching/cleaning emissions by applying defaults from the next lower
Tier (e.g., IPCC Tier 2b or Tier 2a) to estimate missing data. However,
facilities must limit their use of defaults from the next lower Tier to
less than 5 percent of their emissions estimate.
Default values for estimating DRE would not be permitted. DRE
values must be estimated as zero in the absence of facility-specific
DREs that have been measured using a standard protocol. Gas consumption
is collected as business as usual and is not expected to be missing;
therefore, it would not be permitted to revert to the Tier 1 approach
for estimating emissions. When estimating heat transfer fluid emissions
during semiconductor manufacture, the use of the mass-balance approach
requires correct records for all inputs. Should the facility be missing
records for a given input, it may be possible that the heat transfer
fluid supplier has information in their records for the facility.
5. Selection of Data Reporting Requirements
Owners and operators would be required to report GHG emissions for
the facility, for all plasma etching processes, all chamber cleaning,
all chemical vapor deposition processes, and all heat tranfer fluid
use. Along with their emissions, facilities would be required to report
the following: Method used (i.e., 2b or 3), mass of each gas fed into
each process type, production capacity in terms of substrate surface
area (e.g., silicon, PV-cell, LCD), factors used for gas utilization,
by-product formation and their sources/uncertainties, emission control
technology DREs and their uncertainties, fraction of gas fed into each
process type with emissions, control technologies, description of
abatement controls, inputs in the mass-balance equation (for heat
transfer fluid emissions), example calculation, and emissions
uncertainty estimate.
These data form the basis of the calculations and are needed for us
to understand the emissions data and verify the reasonableness of the
reported emissions.
6. Selection of Records That Must Be Retained
We propose that facilities keep records of the following: Data
actually used to estimate emissions, records supporting values used to
estimate emissions, the initial and any subsequent tests of the DRE of
oxidizers, the initial and any subsequent tests to determine emission
factors for process, and abatement device calibration/maintenance
records.
These records consist of values that are directly used to calculate
the emissions that are reported and are necessary to enable
verification that the GHG emissions monitoring and calculations are
done correctly.
J. Ethanol Production
1. Definition of the Source Category
Ethanol is produced primarily for use as a fuel component, but is
also used in industrial applications and in the manufacture of beverage
alcohol. Ethanol can be produced from the fermentation of sugar,
starch, grain, and cellulosic biomass feedstocks, or produced
synthetically from ethylene or hydrogen and carbon monoxide.
The sources of GHG emissions at ethanol production facilities that
must be reported under the proposed rule are stationary fuel
combustion, onsite landfills, and onsite wastewater treatment.
Proposed requirements for stationary fuel combustion emissions are
set forth in proposed 40 CFR part 98, subpart C.
Proposed requirements for landfill emissions are set forth in
Section V.HH of this preamble. Data is unavailable on landfilling at
ethanol facilities, but it is our understanding that some of these
facilities may have landfills with significant CH4
emissions. For more information on landfills at industrial facilities,
please refer to the Ethanol Production TSD (EPA-HQ-OAR-2008-0508-010).
EPA is seeking comment on available data sources for landfilling
practices at ethanol production facilities.
The wastewater generated at ethanol production facilities is
handled in a variety of ways, with dry milling and wet milling
facilities generally treating wastewaters differently. In 2006,
CH4 emissions from wastewater treatment at ethanol
production facilities were 68,200 metric tons CO2e. Proposed
requirements for GHG emissions form wastewater treatment are set forth
in Section V.II of this preamble. For more information on wastewater
treatment at ethanol production facilities, please refer to the Ethanol
Production TSD (EPA-HQ-OAR-2008-0508-010).
As noted in Section IV.B of this preamble under the heading
``Reporting by fuel and industrial gas suppliers'', ethanol producers
and other suppliers of biomass-based fuel are not required to report
GHG emissions from their products under this proposal, and we seek
comment on this approach.
2. Selection of Reporting Threshold
The proposed threshold for reporting emissions from ethanol
production facilities is 25,000 metric tons CO2e total
emissions from stationary fuel combustion, landfills, and onsite
wastewater treatment. Table J-1 of this preamble illustrates the
emissions and facilities that would be covered under various
thresholds.
Table J-1. Threshold Analysis for Ethanol Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Threshold level National emissions Total number ------------------------------------------------------------------------
mtCO2e of facilities mtCO2e/year Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 mtCO2e......................... Not estimated........... 140 Not estimated........... Not estimated.......... >101 >72
10,000 mtCO2e........................ Not estimated........... 140 Not estimated........... Not estimated.......... >94 >67
25,000 mtCO2e........................ Not estimated........... 140 Not estimated........... Not estimated.......... >86 >61
100,000 mtCO2e....................... Not estimated........... 140 Not estimated........... Not estimated.......... >43 >31
--------------------------------------------------------------------------------------------------------------------------------------------------------
Data were unavailable to estimate emissions from landfills at
ethanol refineries, or to estimate the combined wastewater treatment
and stationary fuel combustion emissions at facilities. Data on
stationary fuel combustion were used to estimate the minimum number of
facilities that would meet each of the facility-level thresholds
examined. The
[[Page 16501]]
25,000 metric tons CO2e threshold results in a reasonable
number of reporters, and is consistent with thresholds for other source
categories.
For more information on this analysis, please refer to the Ethanol
Production TSD (EPA-HQ-OAR-2008-0508-010). EPA is seeking comment on
the analysis and on alternative data sources for stationary combustion
at ethanol production facilities. For specific information on costs,
including unamortized first year capital expenditures, please refer to
section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
Refer to Sections V.C, V.HH, and V.II of this preamble for
monitoring methods for general stationary fuel combustion sources,
landfills, and wastewater treatment occurring on-site at ethanol
production facilities.
4. Selection of Procedures for Estimating Missing Data
Refer to Sections V.C, V.HH, and V.II of this preamble for
procedures for estimating missing data for general stationary fuel
combustion sources, landfills, and industrial wastewater treatment
occurring on-site at ethanol production facilities.
5. Selection of Data Reporting Requirements
Refer to Sections V.C, V.HH, and V.II of this preamble for
reporting requirements for general stationary fuel combustion sources,
landfills, and industrial wastewater treatment occurring on-site at
ethanol production facilities. In addition, you would be required to
report the quantity of CO2e captured for use (if applicable)
and the end use, if known. For more information on reporting
requirements for CO2e capture, please refer to Section V.PP
of this preamble.
6. Selection of Records That Must Be Maintained
Refer to Sections V.C, V.HH, and V.GG of this preamble for
recordkeeping requirements for stationary fuel combustion, landfills,
and industrial wastewater treatment occurring on-site at ethanol
production facilities.
K. Ferroalloy Production
1. Definition of the Source Category
A ferroalloy is an alloy of iron with at least one other metal such
as chromium, silicon, molybdenum, manganese, or titanium. For this
proposed rule, we are defining the ferroalloy production source
category to consist of any facility that uses pyrometallurgical
techniques to produce any of the following metals: ferrochromium,
ferromanganese, ferromolybdenum, ferronickel, ferrosilicon,
ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or
silicon metal. Ferroalloys are used extensively in the iron and steel
industry to impart distinctive qualities to stainless and other
specialty steels, and serve important functions during iron and steel
production cycles. Silicon metal is included in the ferroalloy metals
category due to the similarities between its production process and
that of ferrosilicon. Silicon metal is used in alloys of aluminum and
in the chemical industry as a raw material in silicon-based chemical
manufacturing.
The basic process used at U.S. ferroalloy production facilities is
a batch process in which a measured mixture of metals, carbonaceous
reducing agents, and slag forming materials are melted and reduced in
an electric arc furnace. The carbonaceous reducing agents typically
used are coke or coal. Molten alloy tapped from the electric arc
furnace is casted into solid alloy slabs which are further mechanically
processed for sale as product or disposed in landfills.
Ferroalloy production results in both combustion and process-
related GHG emissions. The major source of GHG emissions from a
ferroalloy production facility are the process-related emissions from
the electric arc furnace operations. These emissions, which consist
primarily of CO2e with smaller amounts of CH4,
result from the reduction of the metallic oxides and the consumption of
the graphite (carbon) electrodes during the batch process.
Total nationwide GHG emissions from ferroalloy production
facilities operating in the U.S. were estimated to be approximately 2.3
million metric tons CO2e for the year 2006. Process-related
GHG emissions were 2.0 million metric tons CO2e (86 percent
of the total emissions). The remaining 0.3 million metric tons
CO2e (14 percent of the total emissions) were combustion GHG
emissions.
Additional background information about GHG emissions from the
ferroalloy production source category is available in the Ferroalloy
Production TSD (EPA-HQ-OAR-2008-0508-011).
2. Selection of Reporting Threshold
Ferroalloy production facilities in the U.S. vary in the specific
types of alloy products produced. In developing the threshold for
ferroalloy production facilities, we considered using annual GHG
emissions-based threshold levels of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric tons CO2e
and 100,000 metric tons CO2e. Table K-1 of this preamble
presents the estimated emissions and number of facilities that would be
subject to GHG emissions reporting, based upon emission estimates using
production capacity data for the nine U.S. facilities that produce
either ferrosilicon, silicon metal, ferrochromium, ferromanganese, or
silicomanganese alloys. We were unable to obtain production data for an
estimated five additional facilities that produce ferromolybdenum and
ferrotitanium alloys.
Table K-1. Threshold Analysis for Ferroalloy Production Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ------------------------------------------------------------
Threshold level (metric tons CO2e/yr) (metric tons of facilities Metric tons
CO2e/yr) CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................... 2,343,990 9 2,343,990 100 9 100
10,000..................................................... 2,343,990 9 2,343,990 100 9 100
25,000..................................................... 2,343,990 9 2,343,990 100 9 100
100,000.................................................... 2,343,990 9 2,276,639 97 8 89
--------------------------------------------------------------------------------------------------------------------------------------------------------
Table K-1 of this preamble shows that all nine of the facilities
would be required to report emissions at all thresholds except 100,000
metric tons CO2e, when considering combustion and process-
related emissions. The rule could be simplified for these facilities by
making the rule applicable to all ferroalloy production facilities.
[[Page 16502]]
However, because the threshold analysis did not include all of the
facilities in the ferroalloy source category that potentially could be
subject to the rule, we have decided that it is appropriate to include
a reporting threshold level. The proposed threshold selected for
reporting emissions from ferroalloy production facilities is 25,000
metric tons CO2e per year consistent with the threshold
level being proposed for other source categories. This threshold level
would avoid placing a reporting burden on any small specialty
ferroalloy production facility which may operate as a small business
while still requiring the reporting of GHG emissions from the
ferroalloy production facilities releasing most of the GHG emissions in
the source category. A full discussion of the threshold selection
analysis is available in the Ferroalloy Production TSD (EPA-HQ-OAR-
2008-0508-011). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
We reviewed existing methodologies used by the 2006 IPCC Guidelines
for National Greenhouse Gas Inventories, Canadian Mandatory Greenhouse
Gas Reporting Program, the Australian National Greenhouse Gas Reporting
Program, and EU Emissions Trading System. In general, the methodologies
used for estimating process related GHG emissions at the facility level
coalesce around the following four options.
Option 1. Apply a default emission factor to ferroalloy production.
This is a simplified emission calculation method using only default
emission factors to estimate process-related CO2 and
CH4 emissions. The method requires multiplying the amount of
each ferroalloy product type produced by the appropriate default
emission factors from the 2006 IPCC Guidelines.
Option 2. Perform a monthly carbon balance using measurements of
the carbon content of specific process inputs and process outputs and
the amounts of these materials consumed or produced during a specified
reporting period. This option is applicable to estimating only
CO2 emissions from an electric arc furnace, and is the IPCC
Tier 3 approach and the higher order methods in the Canadian and
Australian reporting programs. Implementation of this method requires
you to determine the carbon contents of carbonaceous material inputs to
and outputs from the electric arc furnaces. Facilities determine carbon
contents through analysis of representative samples of the material or
from information provided by the material suppliers. In addition, the
quantities of these materials consumed and produced during production
would be measured and recorded. To obtain the CO2 emissions
estimate, the average carbon content of each input and output material
is multiplied by the corresponding mass consumed and a conversion of
carbon to CO2. The difference between the calculated total
carbon input and the total carbon output is the estimated
CO2 emissions to the atmosphere. This method assumes that
all of the carbon is converted during the process. For estimating the
CH4 emissions from the electric arc furnace, selection of
this option for estimating CO2 emissions would still require
using the Option 1 approach of applying default emission factors to
estimate CH4 emissions.
Option 3. Use CO2 emissions data from a stack test
performed using U.S. EPA test methods to develop a site-specific
process emissions factor which is then applied to quantity measurement
data of feed material or product for the specified reporting period.
This monitoring method is applicable to electric arc furnace
configurations for which the GHG emissions are contained within a stack
or vent. Using site-specific emissions factors based on short-term
stack testing is appropriate for those facilities where process inputs
(e.g., feed materials, carbonaceous reducing agents) and process
operating parameters remain relatively consistent over time.
Option 4. Use direct emission testing of CO2 emissions.
For electric arc furnace configurations in which the process off-gases
are contained within a stack or vent, direct measurement of the
CO2 emissions can be made by continuously measuring the off-
gas stream CO2 concentration and flow rate using a CEMS.
Using a CEMS, the total CO2 emissions tabulated from the
recorded emissions measurement data would be reported annually. If a
ferroalloy production facility uses an open or semi-open electric arc
furnace for which the CO2 emissions are not fully captured
and contained within a stack or vent (i.e., a significant portion of
the CO2 emissions escape capture by the hood and are release
directly to the atmosphere), then another GHG emission estimation
method other than direct measurement would be more appropriate.
Proposed Option. Under the proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C, to
estimate CO2 emissions from the industrial source. Also,
refer to proposed 40 CFR part 98, subpart C to estimate combustion-
related CH4 and N2O.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
CEMS would not adequately account for process emissions, the proposed
monitoring method is Option 2. You would be required to follow the
requirements of proposed 40 CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary combustion. This section of the preamble provides procedures
only for calculating and reporting process-related emissions.
Given the variability of the alloy products produced and
carbonaceous reducing agents used at U.S. ferroalloy production
facilities, we concluded that using facility-specific information under
Option 2 is preferred for estimating CO2 emissions from
electric arc furnaces. This method is consistent with IPCC Tier 3
methods and the preferred approaches for estimating emissions in the
Canadian and Australian mandatory reporting programs. We consider the
additional burden of the material measurements required for the carbon
balance small in relation to the increased accuracy expected from using
this site-specific information to calculate CO2 emissions.
Emissions data collected under Option 3 would have the lowest
uncertainty, expected to be less than 5 percent. For Option 2, the
material-specific emission factors would be expected to be within 10
percent, which would provide less uncertainty overall than for Option
1, which may have uncertainty of 25 to 50 percent. The use of the
default CO2 emission factors under Option 1 would be more
appropriate for GHG estimates from aggregated process information on a
sector-wide or nationwide basis than for determining GHG emissions from
specific facilities.
In comparison to the CO2 emissions levels from an
electric arc furnace, the CH4 emissions compose a small
fraction of the total GHG emissions from electric arc furnace
operations at a ferroalloy production facility. The proposed Option 2
above doesn't account for CH4. Considering the amount that
CH4 emissions contribute to the total GHG emissions and the
absence of facility-specific methods in other reporting systems, we are
proposing that facilities
[[Page 16503]]
use Option 1 and the IPCC default emission factors to estimate
CH4 emissions from electric arc furnaces at ferroalloy
production facilities. This method provides reasonable estimates of the
magnitude of the CH4 emissions from the units without the
need for owners or operator to conduct on-site CH4 emissions
measurements.
We also decided against Option 3 because of the potential for
significant variations at ferroalloy production facilities in the
characteristics and quantities of the electric arc furnace inputs
(e.g., metal ores, carbonaceous reducing agents) and process operating
parameters. A method using periodic, short-term stack testing would not
be practical or appropriate for those ferroalloy production facilities
where the electric arc furnace inputs and operating parameters do not
remain relatively consistent over the reporting period.
The various approaches to monitoring GHG emissions are elaborated
in the Ferroalloy Production TSD (EPA-HQ-OAR-2008-0508-011).
4. Selection of Procedures for Estimating Missing Data
In cases when an owner or operator calculates CO2 and
CH4 emissions using a carbon balance or an emission factor,
the proposed rule would require the use of substitute data whenever a
quality-assured value of a parameter that is used to calculate GHG
emissions is unavailable, or ``missing.'' If the carbon content
analysis of carbon inputs or outputs is missing or lost, the substitute
data value would be the average of the quality-assured values of the
parameter immediately before and immediately after the missing data
period. The likelihood for missing process input and output data is
low, as businesses closely track their purchase of production inputs.
In those cases when an owner or operator uses direct measurement by a
CO2 CEMS, the missing data procedures would be the same as
the Tier 4 requirements described for general stationary combustion
sources in Section V.C of this preamble.
5. Selection of Data Reporting Requirements
The proposed rule would require reporting of the total annual
CO2 and CH4 emissions for each electric arc
furnace at a ferroalloy production facility, as well as any stationary
fuel combustion emissions. In addition we propose that additional
information which forms the basis of the emissions estimates also be
reported so that we can understand and verify the reported emissions.
This additional information includes the total number of electric arc
furnaces operated at the facility, the facility ferroalloy product
production capacity, the annual facility production quantity for each
ferroalloy product, the number of facility operating hours in calendar
year, and quantities of carbon inputs and outputs if applicable. A
complete list of data to be reported is included in the proposed 40 CFR
part 98, subparts A and K.
6. Selection of Records That Must Be Retained
Maintaining records of the information used to determine the
reported GHG emissions are necessary to enable us to verify that the
GHG emissions monitoring and calculations were done correctly. We
propose that all affected facilities maintain records of product
production quantities, and number of facility operating hours each
month. If you use the carbon balance procedure, you would record for
each carbon-containing input material consumed or used and output
material produced the monthly material quantity, monthly average carbon
content determined for material, and records of the supplier provided
information or analyses used for the determination. If you use the CEMS
procedure, you would maintain the CEMS measurement records.
L. Fluorinated GHG Production
1. Definition of the Source Category
This source category covers emissions of fluorinated GHGs that
occur during the production of HFCs, PFCs, SF6,
NF3, and other fluorinated GHGs such as fluorinated ethers.
Specifically, it covers emissions that are never counted as ``mass
produced'' under the proposed requirements for suppliers of industrial
GHGs discussed in Section OO of this preamble. These emissions include
fluorinated GHG products that are emitted upstream of the production
measurement and fluorinated GHG byproducts that are generated and
emitted either without or despite recapture or destruction.\71\ These
emissions exclude generation and emissions of HFC-23 during the
production of HCFC-22, which are discussed in Section O of this
preamble.
---------------------------------------------------------------------------
\71\ Byproducts that are emitted or destroyed at the production
facility are excluded from the proposed definition of ``produce a
fluorinated GHG.'' Any HFC-23 generated during the production of
HCFC-22 is also excluded from this definition, even if the HFC-23 is
recaptured. However, other fluorinated GHG byproducts that are
recaptured for any reason would be considered to be ``produced.''
---------------------------------------------------------------------------
Emissions can occur from leaks at flanges and connections in the
production line, during separation of byproducts and products, during
occasional service work on the production equipment, and during the
filling of tanks or other containers that are distributed by the
producer (e.g., on trucks and railcars). Fluorinated GHG emissions from
U.S. facilities producing fluorinated GHGs are estimated to range from
0.8 percent to 2 percent of the amount of fluorinated GHGs produced,
depending on the facility.
In 2006, 12 U.S. facilities produced over 350 million metric tons
CO2e of HFCs, PFCs, SF6, and NF3.
These facilities are estimated to have emitted approximately 5.3
million metric tons CO2e of HFCs, PFCs, SF6, and
NF3, based on an emission rate of 1.5 percent. We estimate
that an additional 6 facilities produced approximately 1 million metric
tons CO2e of fluorinated anesthetics. At an emission rate of
1.5 percent, these facilities would emit approximately 15,000 metric
tons CO2e of these anesthetics.
The production of fluorinated gases causes both combustion and
fluorinated GHG emissions. Fluorinated GHG production facilities would
be required to follow the requirements of proposed 40 CFR part 98,
subpart C to estimate emissions of CO2, CH4 and
N2O from stationary fuel combustion. In addition, these
facilities would be required to report their production of industrial
GHGs under proposed 40 CFR part 98, subpart OO. This section of the
preamble discusses only the procedures for calculating and reporting
emissions of fluorinated GHGs.
2. Selection of Reporting Threshold
We propose that owners and operators of facilities estimate and
report fluorinated GHG and combustion emissions if those emissions
together exceed 25,000 metric tons CO2e.
In developing the threshold, we considered emissions thresholds of
1,000 metric tons CO2e, 10,000 metric tons CO2e,
25,000 metric tons CO2e and 100,000 metric tons
CO2e and their capacity equivalents. Facility-specific
emissions were estimated by multiplying an emission factor of 1.5
percent by the estimated production at each facility. The capacity
thresholds were developed based on emissions of fluorinated GHGs,
assuming full capacity utilization and an emission rate of 2 percent of
production. Because EPA had little information on combustion-related
emissions at fluorinated GHG production facilities, these emissions
were not incorporated into the capacity thresholds or the threshold
analysis. Table L-1 of this preamble illustrates the HFC, PFC,
SF6, and NF3 emissions
[[Page 16504]]
and facilities that would be covered under these various thresholds.
Table L-1. Threshold Analysis for Fluorinated GHG Emissions From Production of HFCs, PFCs, SF6, and NF3
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
national ---------------------------------------------------------------
Threshold level (metric tons CO2e/r) emissions Number of
(metric tons facilities Metric tons Percent Number Percent
CO2e) CO2e
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 5,300,000 12 5,300,000 100 12 100
10,000.................................................. 5,300,000 12 5,300,000 100 12 100
25,000.................................................. 5,300,000 12 5,300,000 100 12 100
100,000................................................. 5,300,000 12 5,100,000 97 9 75
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
50,000.................................................. 5,300,000 12 5,300,000 100 12 100
500,000................................................. 5,300,000 12 5,300,000 100 12 100
1,250,000............................................... 5,300,000 12 5,300,000 100 12 100
5,000,000............................................... 5,300,000 12 5,200,000 98 10 83
--------------------------------------------------------------------------------------------------------------------------------------------------------
As can be seen from the tables, most HFC, PFC, SF6, and
NF3 production facilities would be covered by all emission-
and capacity-based thresholds. Although we do not have facility-
specific production information for producers of fluorinated
anesthetics, we believe that few or none of these facilities are likely
to have emissions above the proposed threshold.
EPA requests comment on whether it should adopt a capacity-based
threshold for this sector, and if so, what fluorinated GHG and
combustion-related emission rates should be used to develop this
threshold. Where EPA has reasonably good information on the
relationship between production capacity and emissions, and where this
relationship does not vary excessively from facility to facility, EPA
is generally proposing capacity-based thresholds to make it easy for
facilities to determine whether or not they must report. In this case,
however, EPA has little data on combustion emissions and their likely
magnitude compared to fluorinated GHG emissions from this source.
As noted above, the capacity thresholds in Table L-1 of this
preamble were developed based on a fluorinated GHG emission rate of 2
percent of production. While EPA believes that this emission rate is an
upper-bound for fluorinated GHGs, neither the rate nor the thresholds
account for combustion-related emissions. Thus, it is possible that the
production capacities listed in Table L-1 of this preamble are
inappropriately high.
In the event that a capacity-based threshold were adopted,
facilities would be required to multiply the production capacity of
each production line by the GWP of the fluorinated GHG produced on that
line. Facilities would then be required to sum the resulting
CO2e capacities across all lines. Where more than one
fluorinated GHG could be produced by a production line, yielding more
than one possible production capacity for that line in CO2e
terms, facilities would be required to use the highest possible
production capacity (in CO2e terms) in their threshold
calculations.
A full discussion of the threshold selection analysis is available
in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
In developing this proposed rule, we reviewed a number of protocols
for estimating fluorinated GHG emissions from fluorocarbon production,
such as the 2006 IPCC Guidelines. In general, these protocols present
three methods. In the first approach, a default emission factor is
applied to the total production of the plant. In the second approach,
fluorinated GHG emissions are equated to the difference between the
mass of reactants fed into the process and the sum of the masses of the
main product and those of any by-products and/or wastes. In the third
approach, the composition and mass flow rate of the gas streams
actually vented to the atmosphere are monitored either continuously or
during a period long enough to establish an emission factor.
If you produce fluorinated GHGs, we are proposing that you monitor
fluorinated GHG emissions using the second approach, known as the mass-
balance or yield approach. There are two variants of the mass-balance
approach. In the first variant, only some of the reactants and
products, including the fluorinated GHG product, are considered. In the
second variant, all of the reactants, products, and by-products are
considered. Both variants are discussed in more detail in the
Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).
We are proposing that you monitor emissions using the first
variant. In this approach, you would calculate the difference between
the expected production of each fluorinated GHG based on the
consumption of reactants and the measured production of that
fluorinated GHG, accounting for yield losses related to byproducts
(including intermediates permanently removed from the process) and
wastes. Yield losses that could not be accounted for would be
attributed to emissions of the fluorinated GHG product. This
calculation would be performed for each reactant, and estimated
emissions of the fluorinated GHG product would be equated to the
average of the results obtained for each reactant. If fluorinated GHG
byproducts were produced and were not completely recaptured or
completely destroyed, you would also estimate emissions of each
fluorinated GHG byproduct.
To carry out this approach, you would daily weigh or meter each
reactant fed into the process, the primary fluorinated GHG produced by
the process, any reactants permanently removed from the
[[Page 16505]]
process (i.e., sent to the thermal oxidizer or other equipment, not
immediately recycled back into the process), any byproducts generated,
and any streams that contain the product or byproducts and that are
recaptured or destroyed. For these measurements you would be required
to use scales and/or flowmeters with an accuracy and precision of 0.2
percent of full scale. If monitored process streams included more than
one component (product, byproducts, or other materials) in more than
trace concentrations,\72\ you would be required to monitor
concentrations of products and byproducts in these streams at least
daily using equipment and methods (e.g., gas chromatography) with an
accuracy and precision of 5 percent or better at the concentrations of
the process samples. Finally, you would be required to perform daily
mass balance calculations for each product produced.
---------------------------------------------------------------------------
\72\ EPA is proposing to define ``trace concentration'' as any
concentration less than 0.1 percent by mass of the process stream.
---------------------------------------------------------------------------
In general, we understand that production facilities already
perform these measurements and calculations to the proposed level of
accuracy and precision in order to monitor their processes and yields.
However, we request comment on this issue. We specifically request
comment on the proposed scope and frequency of process stream
concentration measurements. As noted above, concentration measurements
would be triggered when products or byproducts occur in more than trace
concentrations with other components in process streams (which include
waste streams). However, it is possible that products or byproducts
could occur in more than trace concentrations but still result in
negligible yield losses (e.g., less than 0.2 percent). In this case,
ignoring these losses may not significantly affect the accuracy of the
overall GHG emission estimate. (This issue is discussed in more detail
in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).)
Similarly, decreasing the frequency of stream sampling may not have a
significant impact on accuracy or precision if previous monitoring has
shown that the concentrations of products and byproducts in process
streams are stable or vary in a predictable and quantifiable way (e.g.,
seasonally due to differences in condenser cooling water temperature).
EPA recognizes that the proposed mass-balance approach would assume
that all yield losses that are not accounted for are attributable to
emissions of the fluorinated GHG product. In some cases, the losses may
be untracked emissions or other losses of reactants or fluorinated by-
products. In general, EPA understands that reactant flows are measured
at the inlet to the reactor; thus, any losses of reactant that occur
between the point of measurement and the reactor are likely to be
small. However, reactants that are recovered from the process, whether
they are recycled back into it or removed permanently, may experience
some losses that the proposed method does not account for. EPA requests
comment on the extent to which such losses occur, and how these might
be measured.
Fluorocarbon by-products, according to the IPCC Guidelines,
generally have ``radiative forcing properties similar to those of the
desired fluorochemical.'' If this is always the case (with the
exception of HFC-23 generated during production of HCFC-22, which is
addressed in Section V.O of this preamble), then assuming by-product
emissions are product emissions would not lead to large errors in
estimating overall fluorinated GHG emissions. If the GWPs of emitted
fluorinated by-products are sometimes significantly different from
those of the fluorinated GHG product, and if the quantity of by-product
emitted can be estimated (e.g., based on periodic or past sampling of
process streams), then the quantity of emitted product could be
adjusted to reflect this. EPA requests comment on whether it is
necessary or practical to distinguish between emissions of fluorinated
GHG products and emissions of fluorinated by-products, and if so, on
the best approach for doing so.
We also request comment on the proposed accuracy and precision
requirements for flowmeters and scales. If a waste or by-product stream
is significantly smaller than the reactant and product streams, a less
precise measurement of this stream (e.g., 0.5 percent) may not have a
large impact on the precision of the fluorinated GHG emission estimate
and may therefore be acceptable. Similarly, if a measurement is
repeated multiple times over the course of the reporting period, the
precision of individual measurements could be relaxed without seriously
compromising the precision of the monthly or annual estimates. One way
of adding flexibility to the precision requirements would be to require
that the error of the fluorinated GHG emissions estimate be no greater
than some fraction of the yield, e.g., 0.3 percent, on a monthly basis.
Facilities could achieve this level of precision however they chose. We
request comment on this issue and on the accuracy, precision, and cost
of the proposed approach as a whole.
Analysis of Alternative Methods. EPA is not proposing the approach
using the default emission factor. While this approach is simple, it is
also highly imprecise; emissions in U.S. plants are estimated to vary
from 0.8 percent to 2 percent of production, more than a factor of
two.\73\ Thus, applying a default factor (1.5 percent, for example) is
likely to significantly overestimate emissions at some plants while
significantly underestimating them at others.
---------------------------------------------------------------------------
\73\ Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).
---------------------------------------------------------------------------
EPA is not proposing the second variant of the mass-balance
approach. This variant is implemented by comparing the total mass of
reactants to the total mass of monitored products and byproducts,
without regard for chemical identity. The drawbacks of this variant are
that it is not the method currently used by facilities to track their
production, and it would count losses of non-GHG products (e.g., HCl)
as GHG emissions. EPA requests comment on this understanding and on the
potential usefulness and accuracy of the second variant of the mass-
balance approach for estimating fluorinated GHG emissions.
EPA is not proposing the third approach because it is our
understanding that facilities do not routinely monitor their process
vents, and therefore such monitoring is likely to be more expensive
than the proposed mass-balance approach. However, the cost of
monitoring may not be prohibitive, particularly if it is performed for
a relatively short period of time for the purpose of developing an
emission factor, similar to the approach for estimating smelter-
specific slope coefficients for aluminum production.\74\ Moreover, if
the vent monitoring approach reduces the uncertainty of the emissions
measurement by even 10 percent relative to the mass-balance approach,
this would reduce the absolute uncertainty at the typical production
facility by 40,000 metric tons CO2e. (The extent to which
uncertainty would be reduced would depend in part on the sensitivity
and
[[Page 16506]]
precision of the vent concentration measurements.)
---------------------------------------------------------------------------
\74\ Conversations with representatives of fluorocarbon
producers indicate that robust emission factors could often be
developed by monitoring emissions (and a related parameter, such as
production) for one month under representative operating conditions.
Where emissions vary seasonally (e.g., due to changes in condenser
cooling water temperature), two separate monitoring periods of one
month each would often suffice. However, the length and frequency of
monitoring would depend on the variability of the process.
---------------------------------------------------------------------------
For completeness, monitoring of process vents would need to be
supplemented by monitoring of equipment leaks, whose emissions would
not occur through process vents. To capture emissions from equipment
leaks, we could require use of EPA Method 21 and the Protocol for
Equipment Leak Estimates (EPA-453/R-95-017). The Protocol includes four
methods for estimating equipment leaks. These are, from least to most
accurate, the Average Emission Factor Approach, the Screening Ranges
Approach, EPA Correlation Approach, and the Unit-Specific Correlation
Approach. Most recent EPA leak detection and repair regulations require
use of one of the Correlation Approaches in the Protocol. To use any
approach other than the Average Emission Factor Approach, you would
need to have (or develop) Response Factors relating concentrations of
the target fluorinated GHG to concentrations of the gas with which the
leak detector was calibrated. We understand that at least two
fluorocarbon producers currently use methods in the Protocol to
quantify their emissions of fluorinated GHGs with different levels of
accuracy and precision.\75\
---------------------------------------------------------------------------
\75\ One producer estimates HFC and other fluorocarbon emissions
by using the Average Emission Factor Approach. This approach simply
assigns an average emission factor to each component without any
evaluation of whether or how much that component is actually
leaking. The second producer estimates emissions using the Screening
Ranges Approach, which assigns different emission factors to
components based on whether the concentrations of the target
chemical are above or below 10,000 ppmv. This producer has developed
a Response Factor for HCFC-22, which is present in the same streams
as the HFC-23 whose leaks are being estimated. (HFC-23 emissions are
discussed in Section O of this preamble.)
---------------------------------------------------------------------------
We request comment on the accuracies and costs of the approaches in
the Protocol as they would be applied to fluorinated GHG production. We
also request comment on the significance of equipment leaks compared to
process vents as a source of fluorinated GHG emissions.
In addition, we request comment on whether we should require the
vent monitoring approach, what sensitivity and precision would be
appropriate for the vent concentration measurements, and on the
increase in cost and improvements in accuracy and precision that would
be associated with this approach relative to the proposed approach.
Emissions from Evacuation of Returned Containers. We request
comment on whether you should be required to measure and report
fluorinated GHG emissions associated with the evacuation of cylinders
or other containers that are returned to the facility containing either
residual GHGs (heels) or GHGs that would be reclaimed or destroyed. We
are not proposing to require reporting of these emissions because they
are not associated with new production; instead, they are downstream
emissions associated with earlier production.\76\ Requiring reporting
of these emissions could therefore lead to double-counting.\77\
---------------------------------------------------------------------------
\76\ Emissions from the filling or refilling of containers with
new product may or may not be covered by proposed 40 CFR part 98,
subpart L, depending on where production is measured. If production
is measured upstream of filling, then the emissions would not be
covered by proposed 40 CFR part 98, subpart L. If production is
measured downstream of filling, then the emissions would be covered
by subpart L.
\77\ However, this double-counting could be avoided if the
emissions from returned cylinders were clearly distinguished from
other production facility emissions in the emissions report.
---------------------------------------------------------------------------
Nevertheless, according to the 2006 IPCC Guidelines, the overall
emission rate of a production facility can increase by nearly an order
of magnitude (up to 8 percent) if the residual GHG remaining in the
cylinders is vented to the atmosphere. One method of tracking such
emissions would be to subtract the quantities of GHG reclaimed
(purified) and sold or otherwise sent back to users from the quantities
of residual and used GHGs returned to the facility in cylinders by
users. This approach would be similar to the mass-balance approach
proposed for estimating SF6 emissions from users and
manufacturers of electrical equipment.
Emissions of Fluorinated GHGs Associated with Production of ODS. We
request comment on whether you should be required to report emissions
of fluorinated GHGs associated with production of ODS (other than
emissions of HFC-23 associated with production of HCFC-22, which are
discussed in Section O of this preamble). These emissions would be by-
product emissions, for example of HFCs, since the definition of
fluorinated GHGs excludes ODS. We specifically request comment on the
likely magnitude of these emissions, both in absolute terms and
relative to fluorinated GHG emissions from fluorinated GHG production.
We believe that these emissions may occur due to the chemical
similarities between HFCs, HCFCs, and CFCs and the common use of
halogen replacement chemistry to produce them. Although production of
HCFCs and CFCs is limited under the regulations implementing Title VI
of the CAA, production of these substances for use as feedstocks is
permitted to continue indefinitely.
4. Selection of Procedures for Estimating Missing Data
In the event that a scale or flowmeter normally used to measure
reactants, products, by-products, or wastes fails to meet an accuracy
or precision test, malfunctions, or is rendered inoperable, we are
proposing that facilities be required to estimate these quantities
using other measurements where these data are available. For example,
facilities that ordinarily measure production by metering the flow into
the day tank could use the weight of product charged into shipping
containers for sale and distribution as a substitute. It is our
understanding that the types of flowmeters and scales used to measure
fluorocarbon production (e.g., Coriolis meters) are generally quite
reliable, and therefore that it should rarely be necessary to rely
solely on secondary production measurements. In general, production
facilities rely on accurate monitoring and reporting of the inputs and
outputs of the production process.
If concentration measurements are unavailable for some period, we
are proposing that the facility use the average of the concentration
measurements from just before and just after the period of missing
data.
There is one proposed exception to these requirements: If either
method would result in a significant under- or overestimate of the
missing parameter, then the facility would be required to develop an
alternative estimate of the parameter and explain why and how it
developed that estimate.
We request comment on these proposed methods for estimating missing
data.
5. Selection of Data Reporting Requirements
Under the proposed rule, owners and operators of facilities
producing fluorinated GHGs would be required to report both their
fluorinated GHG emissions and the quantities used to estimate them,
including the masses of the reactants, products, by-products, and
wastes, and, if applicable, the quantities of any product in the by-
products and/or wastes (if that product is emitted at the facility). We
are proposing that owners and operators report annual totals of these
quantities.
Where fluorinated GHG production facilities have estimated missing
data, you would be required to report the reason the data were missing,
the length of time the data were missing, the method used to estimate
the missing
[[Page 16507]]
data, and the estimates of those data. Where the missing data was
estimated by a method other than one of those specified, the owner or
operator would be required to report why the specified method would
lead to a significant under- or overestimate of the parameter(s) and
the rationale for the methods used to estimate the missing data.
We propose that facilities report these data because the data are
necessary to verify facilities' calculations of fluorinated GHG
emissions. We request comment on these proposed reporting requirements.
6. Selection of Records That Must Be Retained
Under the proposed rule, owners and operators of facilities
producing fluorinated GHGs would be required to retain records
documenting the data reported, including records of daily and monthly
mass-balance calculations and calibration records for flowmeters,
scales, and gas chromatographs. These records are necessary to verify
that the GHG emissions monitoring and calculations were performed
correctly.
M. Food Processing
1. Definition of the Source Category
Food processing facilities prepare raw ingredients for consumption
by animals or humans. Many facilities in the meat and poultry, and
fruit, vegetable, and juice processing industries have on-site
wastewater treatment. This can include the use of anaerobic and aerobic
lagoons, screening, fat traps and dissolved air flotation. These
facilities can also include onsite landfills for waste disposal. In
2006, CH4 emissions from wastewater treatment at food
processing facilities were 3.7 million metric tons CO2e, and
CH4 emissions from onsite landfills were 7.2 million metric
tons CO2e. Data are not available to estimate stationary
fuel combustion-related GHG emissions at food processing facilities.
Proposed requirements for stationary fuel combustion emissions are
set forth in proposed 40 CFR part 98, subpart C.
Wastewater GHG emissions are described and considered in Section
V.II of this preamble. For more information on wastewater treatment at
food processing facilities, please refer to the Food Processing TSD
(EPA-HQ-OAR-2008-0508-013).
Landfill GHG emissions are described and considered in Section V.HH
of this preamble. For more information on landfills at food processing
facilities, please refer to the Landfills TSD (EPA-HQ-OAR-2008-0508-
034).
The sources of GHG emissions at food processing facilities that
must be reported under the proposed rule are stationary fuel
combustion, onsite landfills and onsite wastewater treatment.
2. Selection of Reporting Threshold
We considered using annual GHG emissions-based threshold levels of
1,000 metric tons CO2e, 10,000 metric tons CO2e,
25,000 metric tons CO2e and 100,000 metric tons
CO2e for food processing facilities. The proposed threshold
for reporting emissions from food processing facilities is 25,000
metric tons CO2e total emissions from combined stationary
fuel combustion, on-site landfills, and on-site wastewater treatment.
Table M-1 of this preamble illustrates the emissions and facilities
that would be covered under these various thresholds.
Table M-1. Threshold Analysis for Food Processing Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
---------------------------------------------------------------
Threshold National Total Metric tons
CO2e/year Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 mtCO2e............................................ NE 5,719 NE NE 802 14.0
10,000 mtCO2e........................................... NE 5,719 NE NE 170 3.0
25,000 mtCO2e........................................... NE 5,719 NE NE 100 1.7
100,000 mtCO2e.......................................... NE 5,719 NE NE 10 0.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
NE = Not Estimated.
Data were unavailable at the time of this analysis to estimate
stationary combustion emissions onsite, or the co-location of landfills
and wastewater treatment at food processing faculties. Facility
coverage based on onsite wastewater GHG emissions and landfill GHG
emissions was estimated as described in the Wastewater Treatment TSD
and Landfills TSD (EPA-HQ-OAR-2008-0508-035) and (EPA-HQ-OAR-2008-0508-
034). We estimate that at the 25,000 metric tons CO2e
threshold, a small percentage of facilities are covered by this rule,
resulting in potentially a large percentage of emissions data reporting
from this significant emissions source but avoiding small facilities.
For specific information on costs, including unamortized first year
capital expenditures, please refer to section 4 of the RIA and the RIA
cost appendix.
3. Selection of Proposed Monitoring Methods
Refer to Sections V.C, V.HH, and V.II of this preamble for
monitoring methods for general stationary fuel combustion sources,
landfills, and wastewater treatment, respectively, occurring on-site at
food production facilities.
4. Selection of Procedures for Estimating Missing Data
Refer to Sections V.C, V.HH, and V.II of this preamble for
procedures for estimating missing data for general stationary fuel
combustion sources, landfills, and wastewater treatment, respectively,
occurring on-site at food processing facilities.
5. Selection of Data Reporting Requirements
Refer to Sections V.C, V.HH, and V.II of this preamble for
reporting requirements for general stationary fuel combustion,
landfills, and wastewater treatment, respectively, occurring on-site at
food processing facilities. In addition, you would be required to
report the quantity of CO2 captured for use (if applicable)
and the end use, if known.
6. Selection of Records That Must Be Maintained
Refer to Sections V.C, V.HH, and V.II of this preamble for
recordkeeping requirements for general stationary fuel combustion
sources, landfills, and wastewater treatment, respectively, occurring
on-site at food processing facilities.
N. Glass Production
1. Definition of the Source Category
Glass is a common commercial item that is produced by melting a
mixture of
[[Page 16508]]
minerals and other substances, then cooling the molten materials in a
manner that prevents crystallization. Glass is typically classified as
container glass, flat (or window) glass, or pressed and blown glass.
Pressed and blown glass includes textile fiberglass, which is used
primarily as a reinforcement material in a variety of products, as well
as other types of glass. Wool fiberglass, which is commonly used for
insulation, is generally classified separately from textile fiberglass
and other pressed and blown glass. However, for the purposes of GHG
reporting, wool fiberglass production is included in the glass
manufacturing source category.
Glass can be produced using a variety of raw material formulations.
Most commercial glass is made using a soda-lime glass formulation,
which consists of silica (SiO2), soda (Na2O), and
lime (CaO), with small amounts of alumina
(Al2O3), magnesia (MgO), and other minor
ingredients. Several specialty glasses, including fiberglass, are made
using borosilicate or aluminoborosilicate recipes, which can consist
primarily of silica and boric oxides, along with varying amounts of
soda, lime, alumina, and other minor ingredients. Other formulations
used in the production of specialty glasses include aluminosilicate and
lead silicate formulations.
Major carbonates used in the production of glass are limestone
(CaCO3), dolomite (CaMg(CO3)2), and
soda ash (Na2CO3). The use of these carbonates in
the furnace during glass manufacturing results in a complex high-
temperature reaction that leads to process-related GHG emissions. Glass
manufacturers may also use recycled scrap glass (cullet) in the
production of glass, thereby reducing the carbonate input to the
process and resulting GHG emissions.
National emissions from glass manufacturing were estimated to be
4.43 million metric tons CO2e (0.1 percent of U.S. GHG
emissions) in 2005. These emissions include both process-related
emissions (CO2) and on-site stationary combustion emissions
(CO2, CH4, and N2O) from 374 glass
manufacturing facilities across the U.S. and Puerto Rico. Process-
related emissions account for 1.65 million metric tons CO2,
or 37 percent of the total, while on-site stationary combustion sources
account for the remaining 2.78 million metric tons CO2e
emissions.
For additional background information on glass manufacturing, refer
to the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014).
2. Selection of Reporting Threshold
In developing the threshold for glass manufacturing, we considered
an emissions-based threshold of 1,000 metric tons CO2e,
10,000 metric tons CO2e, 25,000 metric tons CO2e,
and 100,000 metric tons CO2e. Table N-1 of this preamble
summarizes the emissions and number of facilities that would be covered
under these various thresholds.
Table N-1. Threshold Analysis for Glass Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities Metric tons
CO2e/yr CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 4,425,269 374 4,336,892 98 217 58
10,000.................................................. 4,425,269 374 4,012,319 91 158 42
25,000.................................................. 4,425,269 374 2,243,583 51 55 15
100,000................................................. 4,425,269 374 207,535 5 1 0.3
--------------------------------------------------------------------------------------------------------------------------------------------------------
The glass manufacturing industry is heterogeneous in terms of the
types of facilities. There are some relatively large, emissions-
intensive facilities, but small artisan shops are common as well. For
example, at a 1,000 metric tons CO2e threshold, 98 percent
of emissions would be covered, with only 58 percent of facilities being
required to report.
The proposed threshold for reporting emissions from glass
manufacturing is 25,000 metric tons CO2e. We are proposing a
25,000 metric tons CO2e threshold to reduce the compliance
burden on small businesses, while still including half of the GHG
emissions from the industry. In comparison to the 100,000 metric tons
CO2e threshold, the 25,000 metric tons CO2e
threshold achieves reporting of 11 times more emissions while requiring
less than 15 percent of the facilities to report. Compared to the
10,000 metric tons CO2e threshold, the 25,000 metric tons
CO2e threshold captures more than half of those emissions,
but only requires a third of the number of reporters. We consider this
a significant coverage of the emissions, while impacting a relatively
small portion of the industry.
For a full discussion of the threshold analysis, please refer to
the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many of the domestic and international GHG monitoring guidelines
and protocols include methodologies for estimating process-related
CO2 emissions from glass manufacturing (e.g., the 2006 IPCC
Guidelines, U.S. Inventory, the Technical Guidelines for the DOE
1605(b), and the EU Emissions Trading System). These methodologies
coalesce around four different options. Two options are output-based
(production-based): One applies appropriate emission factors to the
type of glass produced, and the other applies a default emission factor
to total glass production. A third option is based on measuring the
carbonate input to the furnace. The final option uses direct
measurement to estimate emissions.
Option 1. The first production-based option we considered applies a
default emission factor to the total quantity of all glass produced,
correcting for the amount of cullet supplied to the process.
Option 2. The second production-based approach we considered
applies default emission factors to each of the types of glass produced
at the facility (e.g., container, flat, pressed and blown, and
fiberglass).
Option 3. The carbonate-input approach calculates emissions based
on actual input data and the mass fractions of the carbonates that are
volatilized and emitted as CO2. More specifically, this
option considers the type, quantity, and mass fraction of carbonate
inputs to the furnace and develops a facility-specific emission factor.
Option 4. This approach directly measures emissions using a CEMS.
CEMS can be used to measure both combustion-related and process-related
CO2 emissions from glass melting
[[Page 16509]]
furnaces. These emissions generally are exhausted through a common
furnace stack. Therefore, separate CEMS would not be needed to quantify
both types of emissions from glass melting furnaces.
Proposed Option. Under the proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions, you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from the industrial source.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
the CEMS would not adequately account for process emissions, the
proposed monitoring method would require estimating combustion
emissions and process emissions separately. For combustion emissions,
you would be required to follow the requirements of proposed 40 CFR
part 98, subpart C to estimate emissions of CO2,
CH4 and N2O from stationary combustion. For
process emissions, the carbonate input approach (Option 3) is proposed.
This section of the preamble provides only those procedures for
calculating and reporting process-related emissions.
To estimate process CO2 emissions from glass melting
furnaces, we propose that facilities measure the type, quantity, and
mass fraction of carbonate inputs to each furnace and apply the
appropriate emission factors for the carbonates consumed. This method
for determining process emissions is consistent with the IPCC Tier 3
method.
The proposed rule distinguishes between carbonate-based minerals
and carbonate-based raw materials used in glass production. Carbonate-
based raw materials are fired in the furnace during glass
manufacturing. These raw materials are typically limestone, which is
primarily CaCO3; dolomite, which is primarily
CaMg(CO3)CO2; and soda ash, which is primarily
NaCO2CO3. Because it is the calcination of the
mineral fraction of the raw material (e.g., CaCO3 fraction
in limestone) that leads to CO2 emissions, the purity of the
limestone or other carbonate input is important for emissions
estimation.
In order to assess the composition of the carbonate input, we
propose that facilities use data from the raw material supplier to
determine the carbonate-based mineral mass fraction of the carbonate-
based raw materials charged to an affected glass melting furnace. As an
alternative to using data provided by the supplier, facilities can
assume a value of 1.0 for the mass fraction of the carbonate-based
mineral in the carbonate-based raw material. We also propose that
emissions are estimated under the assumption that 100 percent of the
carbon in the carbonate-based raw materials is volatilized and released
from the furnace as CO2. Using the carbonate-based mineral
mass fractions, the carbonate-based raw material feed rates, and the
emission factors, the mass emissions of CO2 emitted from a
glass melting furnace can be determined.
Using values of 1.0 for the carbonate-based mineral mass fractions
is based on the assumption that the raw materials consist of 100
percent of the respective carbonate-based mineral (i.e., the limestone
charged to the furnace consists of 100 percent CaCO3, the
dolomite charged consists of 100 percent
CaMg(CO3)2, and the soda ash consists of 100
percent Na3CO3). Using this assumption generally
overestimates CO2 emissions. However, given the relative
purity of the raw materials used to produce glass, this method provides
accurate estimates of process CO2 emissions from glass
melting furnaces, while avoiding the costs associated with sampling and
analysis of the raw materials.
We have concluded that the carbonate input method specified in the
proposed option is more certain as it involves measuring the
consumption of each carbonate material charged to a glass melting
furnace. According to the 2006 IPCC Guidelines, the uncertainty
involved in the proposed carbonate input approach is 1 to 3 percent; in
contrast, the uncertainty with using the default emission factor and
cullet ratio for the production-based approach is 60 percent.
We considered use of a CO2 CEMS which does tend to
provide the most accurate CO2 emissions measurements and can
measure both the combustion- and process-related CO2
emissions. However, given the limited variability in the process inputs
and outputs contributing to emissions from glass production,
installation of CEMS would require significant additional burden to
facilities given that few glass facilities currently have
CO2 CEMS.
We also considered, but decided not to propose, the production-
based default emission factor-based approach referenced above for
quantifying process-related CO2 emissions based on the
quantity of glass produced. In general, the default emission factor
method results in less certainty because the method involves
multiplying production data by emission factors that are based on
default assumptions regarding carbonate-based mineral content and
degree of calcination.
As part of normal business practices, glass manufacturing plants
maintain the records that would be needed to calculate emissions under
the proposed option. Given the greater accuracy associated with the
input method and the minimal additional burden, we have determined that
this requirement would not add additional burden to current practices
at the facility, while providing accurate estimates of process-based
CO2 emissions.
The various approaches to monitoring GHG emissions are elaborated
in the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014).
4. Selection of Procedures for Estimating Missing Data
To estimate process emissions of CO2 based on carbonate
input, data are needed on the carbonate chemical analysis of the
carbonate-based raw materials and the carbonate-based raw material
input rate (process feed rate). Glass manufacturing facilities must
monitor raw material feed rate carefully in order to maintain product
quality. Therefore, we do not expect missing data on raw material input
to be an issue. However, if these data were missing, we propose
requiring facilities to use average data from the previous and
following months for the mass of carbonate-based raw materials charged
to the furnace. Given that glass furnaces generally operate
continuously at a relatively constant production rate, we do not expect
much variation in the amounts of carbonates charged to the furnace from
month to month. Furthermore, it would be unusual for a glass
manufacturing plant to change its glass formulation. Therefore, we
believe using average data from the previous and following months would
provide a reliable estimate of raw materials charged.
For missing data on carbonate-based mineral mass fractions, we
propose requiring facilities to assume that the mass fraction of each
carbonate-based mineral in the carbonate-based raw materials is 1.0.
This assumption may result in a slight overestimate of emissions, but
should still provide a reasonably accurate estimate of emissions for
the period with missing data.
5. Selection of Data Reporting Requirements
We propose that facilities report total annual emissions of
CO2 from each affected continuous glass melting furnace, as
well as any stationary fuel combustion emissions. The proposed
[[Page 16510]]
rule would also require facilities to report the quantity of each
carbonate-based raw material charged to each continuous glass melting
furnace in tons per year, and the quantity of glass produced by each
continuous glass melting furnace. For facilities that calculate process
emissions of CO2 based on the mass fractions of carbonate-
based minerals, the proposed rule would require facilities to report
those values. These data are requested because they provide the basis
for calculating process-based CO2 emissions and are needed
for us to understand the emissions data and verify the reasonableness
of the reported emissions. The data on raw material composition and
charge rates are needed to verify process-based emissions of
CO2. The data on glass production are needed to verify that
the reported quantities of raw materials charged to continuous furnaces
are reasonable. The production data also can be used to identify
potential outliers.
A full list of data to be reported is included in proposed 40 CFR
part 98, subparts A and N.
6. Selection of Records That Must Be Retained
In addition to the data to be reported, we propose that facilities
retain monthly records of the data used to calculate GHG emissions.
This would include records of the amounts of each carbonate-based raw
material charged to a continuous glass melting furnace and glass
production (by type). This requirement would be consistent with current
business practices and the reporting requirements for emissions of
other pollutants for the glass manufacturing industry.
The proposed rule also would require facilities to retain the
results of all tests used to determine carbonate-based mineral mass
fractions, as well as any other supporting information used in the
calculation of GHG emissions. These data are directly used to calculate
emissions that are reported and are necessary to enable verification
that the GHG emissions monitoring and calculations were performed
correctly.
A full list of records that must be retained on site is included in
proposed 40 CFR part 98, subparts A and N.
O. HCFC-22 Production and HFC-23 Destruction
1. Definition of the Source Category
This source category includes the generation, emissions, sales, and
destruction of HFC-23. The source category includes facilities that
produce HCFC-22, generating HFC-23 in the process. This source category
also includes facilities that destroy HFC-23, which are sometimes, but
not always, also facilities that produce HCFC-22.
HFC-23 is generated during the production of HCFC-22. HCFC-22 is
primarily employed in refrigeration and A/C systems and as a chemical
feedstock for manufacturing synthetic polymers. Because HCFC-22
depletes stratospheric O3, its production for non-feedstock
uses is scheduled to be phased out by 2020 under the CAA. Feedstock
production, however, is permitted to continue indefinitely.
HCFC-22 is produced by the reaction of chloroform
(CHCl3) and hydrogen fluoride (HF) in the presence of a
catalyst, SbClB5. In the reaction, the chlorine in the
chloroform is replaced with fluorine, creating HCFC-22. Some of the
HCFC-22 is over-fluorinated, producing HFC-23. Once separated from the
HCFC-22, the HFC-23 may be vented to the atmosphere as an unwanted by-
product, captured for use in a limited number of applications, or
destroyed.
2006 U.S. emissions of HFC-23 from HCFC-22 production were
estimated to be 13.8 million metric tons CO2e. This quantity
represents a 13 percent decline from 2005 emissions and a 62 percent
decline from 1990 emissions despite an 11 percent increase in HCFC-22
production since 1990. Both declines are primarily due to decreases in
the HFC-23 emission rate. The ratio of HFC-23 emissions to HCFC-22
production has decreased from 0.022 to 0.0077 since 1990, a reduction
of 66 percent. These decreases have occurred because an increasing
fraction of U.S. HCFC-22 production capacity has adopted controls to
reduce HFC-23 emissions. Three HCFC-22 production facilities operated
in the U.S. in 2006, two of which used recapture and/or thermal
oxidation to significantly lower their HFC-23 emissions. All three
plants are part of a voluntary agreement to report and reduce their
collective HFC-23 emissions.
The production of HCFC-22 and destruction of HFC-23 causes both
combustion and HFC-23 emissions. HCFC-22 production and HFC-23
destruction facilities are required to follow the requirements of
proposed 40 CFR part 98, subpart C to estimate emissions of
CO2, CH4 and N2O from stationary fuel
combustion. This section of the preamble provides only those procedures
for calculating and reporting generation, emissions, sales, and
destruction of HFC-23.
For additional background information on HCFC-22 production, please
refer to the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR-
2008-0508-015).
2. Selection of Reporting Threshold
We propose that all facilities producing HCFC-22 be required to
report under this rule. Facilities destroying HFC-23 but not producing
HCFC-22 would be required to report if they destroyed more than 25,000
metric tons CO2e of HFC-23.
For HCFC-22 production facilities, we considered emission-based
thresholds of 1,000 metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and 100,000 metric
tons CO2e and capacity-based thresholds equivalent to these.
The capacity-based thresholds are shown in Table O-1 of this preamble,
and are based on full utilization of HCFC-22 capacity and the emission
rate given for older plants in the 2006 IPCC Guidelines. (One plant is
relatively new, but the emission rate for older plants was used to be
consistent and somewhat conservative.)
Table O-1. Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total national ---------------------------------------------------------------
Threshold level (HCFC-22 capacity in tons) (metric tons facilities Metric tons
CO2e) CO2e/yr Percent Facilities Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
2....................................................... 13,848,483 3 13,848,483 100 3 100
21...................................................... 13,848,483 3 13,848,483 100 3 100
53...................................................... 13,848,483 3 13,848,483 100 3 100
214..................................................... 13,848,483 3 13,848,483 100 3 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 16511]]
Our analysis showed that all of the facilities, which have
capacities ranging from 18,000 to 100,000 metric tons of HCFC-22,
exceeded all of the capacity-based thresholds by wide margins. The
smallest plant exceeded the largest capacity-based threshold by a
factor of 85.
We are not presenting a table for emission-based thresholds because
we do not have facility-specific emissions information. (Under the
voluntary emission reduction agreement, total emissions from the three
facilities are aggregated by a third party, who submits only the total
to us.) Since two of the three facilities destroy or capture most or
all of their HFC-23 by-product, one or both of them probably have
emissions below at least some of the emission-based thresholds
discussed above. However, if the thermal oxidizers malfunctioned, were
not operated properly, or were unused for some other reason, emissions
of HFC-23 from each of the plants could easily exceed all thresholds.
Reporting is therefore important both for tracking the considerable
emissions of facilities that do not use thermal oxidation and for
verifying the performance of thermal oxidation where it is used. For
this reason, we propose that all HCFC-22 manufacturers report their
HFC-23 emissions.
We are aware of one facility that destroys HFC-23 but does not
produce HCFC-22. Although we do not know the precise quantity of HFC-23
destroyed by this facility, the Agency has concluded that the facility
destroys a substantial share of the HFC-23 generated by the largest
HCFC-22 production facility in the U.S. If the destruction facility
destroys even one percent of this HFC-23, it is likely to destroy
considerably more than the proposed threshold of 25,000 metric tons
CO2e.
For additional background information on the threshold analysis for
HCFC-22 production, please refer to the HCFC-22 Production and HFC-23
Destruction TSD (EPA-HQ-OAR-2008-0508-015). For specific information on
costs, including unamortized first year capital expenditures, please
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
a. Review of Monitoring Methods
In developing these proposed requirements, we reviewed several
protocols and guidance documents, including the 2006 IPCC Guidelines,
guidance developed under our voluntary program for HCFC-22
manufacturers, the WRI/WBCSD protocols, the TRI, the TSCA Inventory
Update Rule, The DOE 1605(b) Voluntary Reporting Program, EPA Climate
Leaders, and TRI.
We also considered the findings and conclusions of a recent report
that closely reviewed the methods that facilities use to estimate and
assure the quality of their estimates of HCFC-22 production and HFC-23
emissions. As noted above, the production facilities currently estimate
and report these quantities to us (across all three plants) under a
voluntary agreement. The report, by RTI International, is entitled
``Verification of Emission Estimates of HFC-23 from the Production of
HCFC-22: Emissions from 1990 through 2006'' and is available in the
docket for this rulemaking.
The 2008 Verification Report found that the estimation methods used
by the three HCFC-22 facilities currently operating in the U.S. were
all equivalent to IPCC Tier 3 methods. Under the Tier 3 methodology,
facility-specific emissions are estimated based on direct measurement
of the HFC-23 concentration and the flow rate of the streams,
accounting for the use of emissions abatement devices (thermal
oxidizers) where they are used. In general, Tier 3 methods for this
source category yield far more accurate estimates than Tier 2 or Tier 1
methods. Even at the Tier 3 level, however, the emissions estimation
methods used by the three facilities differed significantly in their
levels of absolute uncertainty. The uncertainty of the one facility
that does not thermally destroy its HFC-23 emissions dominates the
uncertainty for the national emissions from this source category.
In general, the methods proposed in this rule are very similar to
the procedures already being undertaken by the facilities to estimate
HFC-23 emissions and to assure the quality of these estimates. The
differences (and the rationale for them) are discussed in the HCFC-22
Production and HFC-23 Destruction TSD (EPA-HQ-OAR-2008-0508-015).
b. Proposed Monitoring Methods
This section of the preamble includes two proposed monitoring
methods for HCFC-22 production facilities and one for HFC-23
destruction facilities. The proposed monitoring methods differ for
HCFC-22 facilities that do and do not use a thermal oxidizer connected
to the HCFC-22 production equipment. All the monitoring methods rely on
measurements of HFC-23 concentrations in process or emission streams
and on measurements of the flow rates of those streams, although the
proposed frequency of these measurements varies.
Proposed Methods for Estimating HFC-23 Emissions from Facilities
that Do Not Use a Thermal Oxidizer or Facilities that Use a Thermal
Oxidizer that is Not Directly Connected to the HCFC-22 Production
Equipment. Under the proposed rule, you would be required to:
(1) Monitor the concentration of HFC-23 in the reaction product
stream containing the HFC-23 (which could be either the HCFC-22 or the
HCl product stream) on at least a daily basis. This proposed
requirement is intended to account for day-to-day fluctuations in the
rate at which HFC-23 is generated; this rate can vary depending on
process conditions.
(2) Monitor the mass flow of the product stream containing the HFC-
23 either directly or by weighing the other reaction product. The other
product could be either HCFC-22 or HCl. Plants would be required to
make or sum these measurements on at least a daily basis. If the HCFC-
22 or HCl product were measured significantly downstream of the reactor
(e.g., at storage tanks or the shipping dock), facilities would be
required to add a factor that accounted for losses to the measurement.
This factor would be 1.5 percent or another factor that could be
demonstrated, to the satisfaction of the Administrator, to account for
losses. This adjustment is intended to account for upstream product
losses, which are estimated to range from one to two percent. Without
the adjustment, HCFC-22 production and therefore HFC-23 generation at
affected facilities would be systematically underestimated (negatively
biased). A one-to two-percent underestimate could translate into an
underestimate of HFC-23 emissions of 100,000 metric tons
CO2e or more for each affected facility.
We request comment on this proposed approach for compensating for
the negative bias caused by HCFC-22 emissions. We specifically request
comment on the 1.5 percent factor, which is the midpoint of the one-to-
two-percent range of product loss rates cited by the affected facility.
We also request comment on what methods and data would be required to
verify a loss rate other than 1.5 percent, if a facility wished to
demonstrate a lower loss rate. One option would be a mass-balance
approach using measurements with very fine precisions (e.g., 0.2
percent or better).
(3) Facilities that do not use a thermal oxidizer connected to the
HCFC-22
[[Page 16512]]
production equipment would also be required to estimate the mass of
HFC-23 produced either by multiplying the HFC-23 concentration
measurement by the mass flow of the stream containing both the HFC-23
and the other product or by multiplying the ratio of the concentrations
of HFC-23 and of the other product by the mass of the other product.
(4) Facilities would also be required to measure the masses of HFC-
23 sold or sent to other facilities for destruction. This step would
ensure that any losses of HFC-23 during filling of containers were
included in the HFC-23 emission estimates for facilities that capture
HFC-23 for use as a product or for transfer to a destruction facility.
(5) Facilities would also be required to estimate the HFC-23
emitted by subtracting the masses of HFC-23 sold or sent for
destruction from the mass of HFC-23 generated.
This calculation assumes that all production that is not sold or
sent to another facility for destruction is emitted. Such emissions may
be the result of the packaging process; additional emissions can be
attributed to the number of flanges in a line and other on-site
equipment that is specific to each facility.
Proposed Methods for Estimating HFC-23 Emissions from Plants that
Use a Thermal Oxidizer Connected to the HCFC-22 Production Equipment.
Under the proposed rule, you would be required to estimate HFC-23
emissions from equipment leaks, process vents, and the thermal
oxidizer. To estimate emissions from leaks, you would be required to
estimate the number of leaks using EPA Method 21 of 40 CFR part 60,
Appendix A-7 and a leak definition of 10,000 ppmv. Leaks registering
above and below 10,000 ppmv would be assigned different default
emission rates, depending on the component and service (gas or light
liquid). These leak rates would be drawn from Table 2-5 from the
Protocol for Equipment Leak Estimates (EPA-453/R-95-017) and data on
the concentration of HFC-23 in the process stream.\78\ (The relevant
portions of Table 2-5 are included in the proposed regulatory text for
this rule.) To estimate emissions from process vents, you would be
required to use the results of annual emissions tests at process vents,
adjusting for changes in HCFC-22 production rates since the
measurements occurred. Tests would have to be conducted in accordance
with EPA Method 18 of 40 CFR part 60, Appendix A-6, Measurement of
Gaseous Organic Compounds by Gas Chromatography. Although HFC-23
emissions from process vents are believed to be quite low, this
monitoring would ensure that any year-to-year variability in the
emission rate was captured by the reporting. Finally, to estimate
emissions from the thermal oxidizer, you would be required to apply the
DE of the oxidizer to the mass of HFC-23 fed into the oxidizer.
---------------------------------------------------------------------------
\78\ Although EPA recognizes that the proposed method for
estimating emissions from equipment leaks is rather uncertain, EPA
believes that the level of precision is not unreasonable given the
small size of the HFC-23 emissions that would be estimated using the
method. These emissions are estimated to account for a fraction of a
percent of U.S. HFC-23 emissions from this source.
---------------------------------------------------------------------------
Destruction. Under the proposed rule, if you use thermal oxidation
to destroy HFC-23 you would be required to measure the quantities of
HFC-23 fed into the oxidizer. You would also be required to account for
any decreases in the DE of the oxidizer that occurred when the oxidizer
was not operating properly (as defined in State or local permitting
requirements and/or oxidizer manufacturer specifications). Finally, you
would be required to perform annual HFC-23 concentration measurements
by gas chromatography to confirm that emissions from the oxidizer were
as low as expected based on the rated DE of the device. If emissions
were found to be higher, then facilities would have the option of using
the DE implied by the most recent measurements or of conducting more
extensive measurements of the DE of the device.
As discussed in the HCFC-22 Production and HFC-23 Destruction TSD
(EPA-HQ-OAR-2008-0508-015), the initial testing and parametric
monitoring that facilities currently perform on their oxidizers
provides general assurance that the oxidizer is performing correctly.
However, the proposed requirement to measure HFC-23 concentrations at
the oxidizer outlet would provide additional assurance at relatively
low cost. Even a one- or two-percent decline in the DE of the oxidizer
could lead to emissions of over 100,000 metric tons CO2e,
making this a particularly important factor to monitor accurately.
Startups, shutdowns, and malfunctions. Under the proposed rule, if
you produce HCFC-22 you would be required to account for HFC-23
production and emissions that occur as a result of startups, shutdowns,
and malfunctions. This would be done either by recording HFC-23
production and emissions during these events, or documenting that these
events do not result in significant HFC-23 production and/or emissions.
Depending on the circumstances, startups, shutdowns, and malfunctions
(including both the process equipment and any thermal oxidation
equipment) can be significant sources of emissions, and the Agency
believes that emissions during these process disturbances should
therefore be tracked.
Precision and Accuracy Requirements. We are proposing to require
that HCFC-22 production facilities and HFC-23 destruction facilities
monitor the masses that would be reported under this rule using
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of 1.0 percent of full
scale or better. Our understanding is that some HCFC-22 production
facilities currently use devices with this level of accuracy and
precision. However, flowmeters with considerably better precisions are
available, e.g., 0.2 percent. We request comment on the option of
requiring plants to use flowmeters or scales with an accuracy and
precision of 0.2 percent or some other precision better than 1 percent.
Given the large quantities of HFC-23 generated by each plant, this
higher precision may be appropriate.
We are also proposing to require that HCFC-22 production facilities
and HFC-23 destruction facilities measure concentrations using
equipment and methods with an accuracy and precision of 5 percent or
better at the concentrations of the samples.
Calibration Requirements. Under the proposed rule, if you produce
HCFC-22 or destroy HFC-23 you would be required to perform the
following activities to assure the quality of their measurements and
estimates:
(1) Calibrate gas chromatographs used to determine the
concentration of HFC-23 by analyzing, on a monthly basis, certified
standards with known HFC-23 concentrations that are in the same range
(percent levels) as the process samples. This proposed requirement is
intended to verify the accuracy and precision of gas chromatographs at
the concentrations of interest; calibration at other concentrations
does not verify this accuracy with the same level of assurance. The
proposed requirement is similar to requirements in protocols for the
use of gas chromatography, such as EPA Method 18, Measurement of
Gaseous Organic Compound Emissions by Gas Chromatography.
(2) Initially verify each weigh scale, flow meter, and combination
of volumetric and density measurements used to measure quantities that
are to be reported under this rule, and calibrate it thereafter at
least every year. We request comment on these proposed requirements.
[[Page 16513]]
4. Selection of Procedures for Estimating Missing Data
We are proposing that in the cases when an upstream flow meter
(i.e., near reactor outlet) is ordinarily used but is not available for
some period, the facility can compensate by using downstream production
measures (e.g., quantity shipped) and adding 1.5 percent to account for
product losses. If HFC-23 concentration measurements are unavailable
for some period, we propose that the facility use the average of the
concentration measurements from just before and just after the period
of missing data.
There is one proposed exception to these requirements: If either
method would result in a significant under- or overestimate of the
missing parameter (e.g., because the monitoring failure was linked to a
process disturbance that is likely to have significantly increased the
HFC-23 generation rate), then the facility would be required to develop
an alternative estimate of the parameter and explain why and how it
developed that estimate.
We request comment on these methods for estimating missing data. We
also request comment on the option of estimating missing production
data based on consumption of reactants, assuming complete
stoichiometric conversion.
5. Selection of Data Reporting Requirements
If you produce HCFC-22 and do not use a thermal oxidizer connected
to the HCFC-22 production equipment, you would be required to report
the total mass of the HFC-23 generated in metric tons, the mass of any
HFC-23 packaged for sale in metric tons, the mass of any HFC-23 sent
off site for destruction in metric tons, and the mass of HFC-23 emitted
in metric tons. If you produce HCFC-22 and destroy HFC-23 using a
thermal oxidizer connected to the HCFC-22 production equipment, you
would be required to report the mass of HFC-23 emitted from the thermal
oxidizer, the mass of HFC-23 emitted from process vents, and the mass
of HFC-23 emitted from equipment leaks, in metric tons.
In addition, if you produce HCFC-22 you would also be required to
submit the following supplemental data, as applicable, for QA purposes:
Annual HCFC-22 production, annual consumption of reactants (including
factors to account for quantities that typically remain unreacted), by
reactant, annual mass of materials other than HCFC-22 and HFC-23 (i.e.,
unreacted reactants, HCl and other byproducts) that are permanently
removed from the process, and the method for tracking startups,
shutdowns, and malfunctions and HFC-23 generation/emissions during
these events. You would also be required to report the names and
addresses of facilities to which any HFC-23 was sent for destruction,
and the quantities sent to each.
Where HCFC-22 production facilities have estimated missing data,
you would be required to report the reason the data were missing, the
length of time the data were missing, the method used to estimate the
missing data, and the estimates of those data. Where the missing data
was estimated by a method other than one of those specified, the owner
or operator would be required to report why the specified method would
lead to a significant under- or overestimate of the parameter(s) and
the rationale for the methods used to estimate the missing data.
If you destroy HFC-23, you would be required to report the mass of
HFC-23 fed into the thermal oxidizer, the mass of HFC-23 destroyed, and
the mass of HFC-23 emitted from the thermal oxidizer. You would also be
required to submit the results of your annual HFC-23 concentration
measurements at the outlet of the oxidizer. In addition, you would be
required to submit a one-time report similar to that required under
EPA's stratospheric protection regulations at 40 CFR 82.13(j).
We propose that facilities report these data either because the
data are necessary to verify facilities' calculations of HFC-23
generation, emissions, or destruction or because the data allow us to
implement other QA checks (e.g., calculation of an HFC-23/HCFC-22
generation factor that can be compared across facilities and over
time). We request comment on these proposed reporting requirements.
6. Selection of Records That Must Be Retained
If you produce HCFC-22, you would be required to keep records of
the data used to estimate emissions and records documenting the initial
and periodic calibration of the gas chromatographs, scales, and
flowmeters used to measure the quantities reported under this rule.
If you destroy HFC-23, you would be required to keep records of
information documenting your one-time and annual reports.
These records are necessary to enable verification that the GHG
emissions monitoring and calculations were performed correctly.
P. Hydrogen Production
1. Definition of the Source Category
Approximately nine million metric tons of hydrogen are produced in
the U.S. annually. Hydrogen is used for industrial applications such as
petrochemical production, metallurgy, and food processing. Some of the
largest users of hydrogen are ammonia production facilities, petroleum
refineries, and methanol production facilities.
About 95 percent of all hydrogen produced in the U.S. today is made
from natural gas via steam methane reforming. This process consists of
two basic chemical reactions: (1) Reformation of the CH4
feedstock with high temperature steam supplied by burning natural gas
to obtain a synthesis gas (CH4 + H2O = CO +
3H2); and (2) Using a water-gas shift reaction to form
hydrogen and CO2 from the carbon monoxide produced in the
first step (CO + H2O = CO2 + H22).
Other processes used for hydrogen production include steam naptha
reforming, coal or biomass gasification, partial oxidation of coal or
hydrocarbons, autothermal reforming, electrolysis of water, recovery of
byproduct hydrogen from electrolytic cells used to produce chlorine and
other products, and dissociation of ammonia.
Hydrogen is produced in large quantities at approximately 77
merchant hydrogen production facilities (which produce hydrogen to
sell) and 145 captive hydrogen production facilities (which consume
hydrogen at the site where it is produced, e.g. petroleum refineries,
ammonia, and methanol facilities). Hydrogen is also produced in small
quantities at numerous other locations.
National emissions from hydrogen production were estimated to be
approximately 60 million metric tons CO2 (1 percent of U.S.
GHG emissions) annually.
The source category covered by the hydrogen production subpart of
the proposed rule is merchant hydrogen production. CO2
emissions from captive hydrogen production facilities at ammonia
facilities, petrochemical facilities, and petroleum refineries are
covered in proposed 40 CFR part 98, subparts G, X, and Y, respectively.
For additional background information on hydrogen production,
please refer to the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016).
2. Selection of Reporting Threshold
In developing the threshold for hydrogen production, we considered
emissions-based thresholds of 1,000
[[Page 16514]]
metric tons CO2e, 10,000 metric tons CO2e, 25,000
metric tons CO2e and 100,000 metric tons CO2e.
This threshold is based on combined combustion and process
CO2 emissions at the hydrogen production facility.
In selecting a threshold, we considered emissions data from
merchant hydrogen facilities only, which together account for an
estimated 15.2 million metric tons CO2e in 2006.
Table P-1 of this preamble illustrates the emissions and facilities
that would be covered under these various thresholds.
Table P-1. Threshold Analysis for Hydrogen Production
----------------------------------------------------------------------------------------------------------------
H2 Production Emissions covered Facilities covered
CO2 Threshold level (metric tons capacity (tons ---------------------------------------------------------------
CO2e/year) H2/year) Tons CO2e/year Percent Number Percent
----------------------------------------------------------------------------------------------------------------
No threshold.................... 0 15,226,620 100.0 77 100
1,000........................... 116 15,225,220 100.0 73 95
10,000.......................... 1,160 15,130,255 99.4 51 66
25,000.......................... 2,900 14,984,365 98.4 41 53
100,000......................... 11,600 14,251,265 93.6 30 39
----------------------------------------------------------------------------------------------------------------
The hydrogen production industry is heterogeneous in terms of the
types of facilities. There are some relatively large, emissions
intensive facilities, but small facilities are common as well. At a
25,000 ton threshold, although 98.4 percent of emissions would be
covered, only 53 percent of facilities would be required to report.
The proposed threshold for reporting emissions from hydrogen
production is 25,000 metric tons CO2e. We are proposing a
25,000 metric tons CO2e threshold to reduce the compliance
burden on small businesses, while still including a majority of GHG
emissions from the industry.
For a full discussion of the threshold analysis, please refer to
the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Several domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from hydrogen production (e.g., the American Petroleum
Institute Compendium, the DOE 1605(b), and the CARB Mandatory GHG
Emissions Reporting Program). These methods coalesce around variants of
two methods for merchant hydrogen production facilities: Direct
measurement of CO2 emissions by CEMS, and the feedstock
material balance method.
Option 1. Direct measurement. The CEMS would capture both
combustion and process-related CO2 emissions from a hydrogen
facility. Facilities that do not currently employ a CEMS could
voluntarily elect to install CEMS for reporting under this subpart.
This approach is consistent with DOE's 1605(b) ``A'' rated method and
the CARB Mandatory GHG Emissions Reporting Program.
Option 2. Feedstock material balance method. This method accounts
for the difference between the quantity and carbon content of all
feedstock delivered to the facility and of all products leaving the
facility. This approach is consistent with IPCC Tier 3 methods for
similar processes (i.e., steam reformation in ammonia production), the
DOE 1605(b) ``A'' rated method, and the CARB Mandatory GHG Emissions
Reporting Program.
Based on our review of the above approaches, we propose both
methods for quantifying GHG emissions from hydrogen production, to be
implemented depending on current circumstances at your facility. If you
are required to use an existing CEMS to meet the requirements outlined
in proposed 40 CFR part 98, subpart C, you would be required to use
CEMS to estimate CO2 emissions. Where the CEMS capture
combustion- and process-related CO2 emissions you would be
required to follow the calculation procedures, monitoring and QA/QC
methods, missing data procedures, reporting requirements, and
recordkeeping requirements of proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from the industrial source. Also,
refer to proposed 40 CFR part 98, subpart C to estimate combustion-
related emissions from fuels not captured in the CEMS, as well as
CH4 and N2O.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
the CEMS does not measure process emissions, the proposed monitoring
method is Option 2. You would be required to follow the calculation
procedures, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements of proposed 40
CFR part 98, subpart C to estimate combustion-related emissions from
each hydrogen production unit and any other stationary combustion
units. This section of the preamble provides only those procedures for
calculating and reporting process-related CO2 emissions. For
CO2 collected and used onsite or transferred offsite, you
must follow the methodology provided in proposed 40 CFR part 98,
subpart PP of this part (Suppliers of CO2).
The feedstock material balance method entails measurements of the
quantity and carbon content of all feedstock delivered to the facility
and of all products leaving the facility, with the assumption that all
the carbon entering the facility in the feedstock that is not captured
and sold outside the facility is converted to CO2 and
emitted. The quantity of feedstock consumed must be measured
continuously using a flowmeter. The carbon fraction in the feedstock
may be provided as part of an ultimate analysis performed by the
supplier (e.g., the local gas utility in the case of natural gas
feedstock). If the feedstock supplier does not provide the gas
composition or ultimate analysis data, the facility would be required
to analyze the carbon content of the feedstock on a monthly basis using
the appropriate test method in proposed 40 CFR 98.7.
We also considered three other methods for quantifying process-
related emissions. The first method requires direct measurement of
emissions by CEMS from all reporting facilities. The second method
applies a constant proportionality factor, based on the facility's
historical data on natural gas consumption, to the facility's hydrogen
production rate. The third method we
[[Page 16515]]
considered applies a national default emission factor to the natural
gas consumption rate at a facility.
The first method would generally increase accuracy of reported
data. We invite comment on the practicality of adopting the first
method. In general, the latter two methods are less certain, as they
involve multiplying production and feedstock consumption data by
default emission factors based on purity assumptions.
In contrast, the feedstock material balance method is more certain
as it involves measuring the consumption and carbon content of the
feedstock input. Because 95 percent of hydrogen is produced using steam
methane reforming, and the carbon content of natural gas is always
within 1 percent of the ratio: One mole of carbon per mole of natural
gas, the local utility QA/QC requirements should be more than adequate.
Given the increase in accuracy of the direct measurement and
feedstock material balance methods coupled with the minimal additional
burden for facilities that already employ CEMS, we propose that
facilities utilize the direct measurement method where currently
employed, and the feedstock material balance method for all facilities
that do not employ CEMS. We have concluded that this requirement does
not add additional burden to current practices at the facilities,
thereby minimizing costs. The primary additional burden for facilities
associated with this method would be in conducting a gas composition
analysis of the feedstock on a monthly basis, in cases where this
information is not provided by the supplier.
The various approaches to monitoring GHG emissions are elaborated
in the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016).
4. Selection of Procedures for Estimating Missing Data
Sources using CEMS to comply with this rule would be required to
comply with the missing data requirements of proposed 40 CFR part 98,
subpart C.
In the event that a facility lacks feedstock supply rates for a
certain time period, we propose that facilities use the lesser of the
maximum supply rate that the unit is capable of processing or the
maximum supply rate that the meter can measure. In the event that a
monthly value for carbon content is determined to be invalid, an
additional sample must be collected and tested. The likelihood for
missing data is small, since the fuel meter and carbon content data are
needed for financial accounting purposes.
5. Selection of Data Reporting Requirements
We propose that facilities submit their annual CO2, and
N2O emissions data. Facilities that use CEMS must comply
with the procedures specified in proposed 40 CFR 98.36(d)(iv). In
addition, we propose that facilities submit the following data on an
annual basis for each process unit. These data are needed for us to
understand the emissions data and verify the reasonableness of the
reported emissions, and are the basis of the feedstock material balance
calculation.
The data should include the total quantity of feedstock consumed
for hydrogen production, the quantity of CO2 captured for
use and the end use, if known, the monthly analyses of carbon content
for each feedstock used in hydrogen production, the annual quantity of
hydrogen produced, and the annual ammonia produced, if applicable.
A full list of data to be reported is included in proposed 40 CFR
part 98, subparts A and P.
6. Selection of Records That Must Be Retained
We propose that each hydrogen production facility comply with the
applicable recordkeeping requirements for stationary combustion units
in proposed 40 CFR part 98, subpart C, which are also discussed in
Section V.C of this preamble.
Also, we propose that each hydrogen production facility maintain
records of feedstock consumption and the method used to determine the
quantity of feedstock consumption, QA/QC records (including calibration
records and any records required by the QAPP), monthly carbon content
analyses, and the method used to determine the carbon content. A full
list of records that must be retained onsite is included in proposed 40
CFR part 98, subparts A and P. These records consist of values that are
directly used to calculate the emissions that are reported and are
necessary to enable verification that the GHG emissions monitoring and
calculations were done correctly.
Q. Iron and Steel Production
1. Definition of the Source Category
The iron and steel industry in the U.S. is the third largest in the
world, accounting for about 8 percent of the world's raw iron and steel
production and supplying several industrial sectors, such as
construction (building and bridge skeletons and supports), vehicle
bodies, appliances, tools, and heavy equipment. In this proposed rule,
we are defining the iron and steel production source category to be
taconite iron ore processing facilities, integrated iron and
steelmaking facilities, electric arc furnace steelmaking facilities
that are not located at integrated iron and steel facilities, and
cokemaking facilities that are not located at integrated iron and steel
facilities. Coke, sinter, and electric arc furnace steel production
operations at integrated iron and steel facilities are part of
integrated iron and steel facilities. Direct reduced iron furnaces are
located at and are part of electric arc furnace steelmaking facilities.
Currently, there are 18 integrated iron and steel steelmaking
facilities that make iron from iron ore and coke in a blast furnace and
refine the molten iron (and some ferrous scrap) in a basic oxygen
furnace to make steel. In addition, there are over 90 electric arc
furnace steelmaking facilities that produce steel primarily from
recycled ferrous scrap. There are also eight taconite iron ore (pellet)
processing facilities, 18 cokemaking facilities, seven of which are co-
located at integrated iron and steel facilities, and one direct reduced
iron furnace located at an electric arc furnace steelmaking facility.
The primary operation units that emit GHG emissions are blast
furnace stoves (24 million metric tons CO2e/yr), taconite
indurating furnaces, basic oxygen furnaces, electric arc furnaces
(about 5 million metric tons CO2e/yr each), coke oven
battery combustion stacks (6 million metric tons CO2e/yr),
and sinter plants (3 million metric tons CO2e/yr). Smaller
amounts of GHG emissions are produced by coke pushing (160,000 metric
tons CO2e/yr) and direct reduced iron furnaces (140,000
metric tons CO2e/yr).
Based on production in 2007, GHG emissions from the source category
are estimated at about 85 million metric tons CO2e/yr or
just over 1 percent of total U.S. GHG emissions. Emissions from both
process units (47 million metric tons CO2e/yr) and
miscellaneous combustion units (38 million metric tons CO2e/
yr) are significant. Small amounts of N2O and CH4
are also emitted during the combustion of different types of fuels.
Although by-product recovery coke batteries and blast furnaces
operations produce coke and pig iron, respectively, we are proposing
that their emissions be reported as required for combustion units in
proposed 40 CFR part 98, subpart C because the majority of their GHG
emissions originate from fuel combustion. Emissions from the blast
furnace operation occur primarily from the combustion of blast furnace
gas and
[[Page 16516]]
natural gas in the blast furnace stoves. Emissions from by-product
recovery coke batteries are generated from the combustion of coke oven
gas in the coke battery's underfiring system. In addition to the blast
furnace stoves and by-product coke battery underfiring systems, the
other combustion units where fuel is the only source of GHG emissions
include boilers, process heaters, reheat and annealing furnaces,
flares, flame suppression systems, ladle reheaters, and other
miscellaneous sources. Emissions from these other combustion sources in
2007 are estimated at 16.8 million metric tons CO2e/yr for
integrated iron and steel facilities, 18.6 million metric tons
CO2e/yr for electric arc furnace steelmaking facilities, and
2.7 million metric tons CO2e/yr for coke facilities not
located at integrated iron and steel facilities. As noted, the proposed
requirements for combustion units in proposed 40 CFR part 98, subpart C
would apply for estimating the CO2, CH4, and
N2O emissions from the following combustion units:
By-product recovery coke oven battery combustion stacks.
Blast furnace stoves.
Boilers.
Process heaters.
Reheat furnaces.
Annealing furnaces.
Flares.
Ladle reheaters.
Other miscellaneous combustion sources.
Emissions from the remaining operation units are generated from the
carbon in process inputs and in some cases, from fuel combustion in the
process. The process-related CO2, CH4 and
N2O emissions from the operation units listed below except
for coke pushing would be reported according to the proposed
requirements in this section:
Taconite indurating furnaces.
Nonrecovery coke oven battery combustion stacks.
Coke pushing.
Basic oxygen furnaces.
Electric arc furnaces.
Direct reduced iron furnaces.
Sinter plants.
Emissions from nonrecovery coke batteries do not result from the
combustion of a fuel input. In the nonrecovery battery, the volatiles
that evolve as the coal is heated are ignited in the crown above the
coal mass and in flues used to heat the oven. All of the combustible
compounds distilled from the coal are burned, and the exhaust gases
containing CO2 are emitted through the battery's combustion
stack. For all types of coke batteries, a small amount of
CO2 is formed when the incandescent coke is pushed from the
oven, and prior to quenching with water, some of the coke burns. The
CO2 emissions from taconite plants come primarily from the
indurating furnaces where coal and/or natural gas are burned in the
pelletizing process, and carbon in the process feed materials (iron
ore, limestone, bentonite) is converted to CO2. The
CO2 emissions from direct reduced iron furnaces result from
the combustion of natural gas in the furnace and from the process
inputs, primarily from the carbonaceous materials (such as coal or
coke) that is mixed with iron ore. During steelmaking in the basic
oxygen furnace, most of the GHGs result from blowing oxygen into the
molten iron to produce steel by removing carbon, primarily as
CO2. CO2 emissions also result from the addition
of fluxing materials and other process inputs that may contain carbon.
Emissions from electric arc furnaces are produced by the same
mechanisms as for basic oxygen furnaces, and in addition, the
consumption of carbon electrodes during the melting and refining stages
contribute to CO2 emissions.
Emissions of CH4 and N2O occur from the
combustion of fuels in both combustion units and process units. For
fuels that contain CH4, combustion of CH4 is not
complete, and a small amount of CH4 is not burned and is
emitted. In addition, a small amount of N2O can be formed as
a by-product of combustion from the air (nitrogen and oxygen) that is
required for combustion.
Additional background information about GHG emissions from the iron
and steel production source category is available in the Iron and Steel
Production TSD (EPA-HQ-OAR-2008-0508-017).
2. Selection of Reporting Threshold
In evaluating potential thresholds for iron and steel production,
we considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e per year. This
threshold is based on combined combustion and process CO2
emissions at an iron and steel production facility.
Table Q-1 of this preamble illustrates that the various thresholds
do not have a significant effect on the amount of emissions that would
be covered. To avoid placing a reporting burden on the smaller
specialty stainless steel producers which may operate as small
businesses while still requiring the reporting of GHG emissions from
those facilities releasing most of the GHG emissions in this source
category, we are proposing a threshold of 25,000 metric tons
CO2e per year for reporting of emissions. This threshold
level is consistent with the threshold level being proposed for other
source categories with similar facility size characteristics. We are
proposing that facilities emitting greater than 25,000 in the iron and
steel production source category would be subject to the proposed rule
because of the magnitude of their emissions. All integrated iron and
steel facilities and taconite facilities exceed the highest emissions
threshold considered. Most electric arc furnace facilities (with the
possible exception of about 9 facilities) exceed the 25,000 metric tons
CO2e emissions threshold. Requiring facilities that emit
25,000 metric tons CO2e a year or more to report would
capture nearly 100 percent of the emissions without significantly
increasing the number of affected facilities.
For a full discussion of the threshold analysis, refer to the Iron
and Steel Production TSD (EPA-HQ-OAR-2008-0508-017). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
Table Q-1. Threshold Analysis for Iron and Steel Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e (metric tons of facilities Metric tons
CO2e) CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
all in.................................................. 85,150,877 130 85,150,877 100 130 100
1,000................................................... 85,150,877 130 85,150,877 100 130 100
10,000.................................................. 85,150,877 130 85,141,500 100 128 98
25,000.................................................. 85,150,877 130 85,013,059 100 121 93
[[Page 16517]]
100,000................................................. 85,150,877 130 84,468,696 99.2 111 85
--------------------------------------------------------------------------------------------------------------------------------------------------------
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating emissions from process
and combustion sources (e.g. 2006 IPCC Guidelines, U.S. Inventory, the
WBCSD/WRI GHG protocol, DOE 1605(b), TCR, EU Emissions Trading System,
the American Iron and Steel Institute Protocol, International Iron and
Steel Institute Protocol, and Environment Canada's mandatory reporting
guidelines). We considered these methodologies for measuring or
estimating GHG emissions from the iron and steel source category. The
following five options were considered for reporting process-related
CO2 emissions from these sources.
Option 1. Apply a default emission factor based on the type of
process and an annual activity rate (e.g. quantity of raw steel,
sinter, or direct reduced iron produced). This option is the same as
the IPCC Tier 1 approach.
Option 2. Perform a carbon balance of all inputs and outputs using
default or typical values for the carbon content of the inputs and
outputs. Facility production and other records would be used to
determine the annual quantity of process inputs and outputs.
CO2 emissions from the difference of carbon-in minus carbon-
out, assuming all is converted to CO2, would be calculated.
This option is the same as the IPCC Tier 2 approach, the WRI default
approach, and the DOE 1605(b) approach that is rated ``B.'' It is
similar to the approach recommended by American Iron and Steel
Institute except that the carbon balance for Option 2 is based on the
individual processes rather than the entire plant.
Option 3. Perform a monthly carbon balance of all inputs and
outputs using measurements of the carbon content of specific process
inputs and process outputs and measure the mass rate of process inputs
and process outputs. Calculate CO2 emissions from the
difference of carbon-in minus carbon-out assuming all is converted to
CO2. This is consistent with an IPCC Tier 3 approach (if
direct measurements are not available), the WRI/WBCSD preferred
approach, the approach used in the EU Emissions Trading System, and the
DOE 1605(b) approach that is rated ``A.''
Option 4. Develop a site-specific emission factor based on
simultaneous and accurate measurements of CO2 emissions and
production rate or process input rate during representative operating
conditions. Multiply the site-specific factor by the annual production
rate or appropriate periodic production rate (or process input rate, as
appropriate). This approach is included in Environment Canada's
methodologies and might be considered a form of direct measurement
consistent with the IPCC's Tier 3 approach.
Option 5. Direct and continuous measurement of CO2
emissions using CEMS for CO2 concentration and stack gas
volumetric flow rate based on the requirements in 40 CFR part 75. This
is the IPCC Tier 3 approach (direct measurement).
Proposed option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C to
estimate CO2 emissions from the industrial source. Also, you
would use proposed 40 CFR part 98, subpart C to estimate combustion-
related CH4 and N2O.
If you do not currently have CEMS that meet the requirements
outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would
not adequately account for process emissions, we propose that Options
3, 4 or 5 could be implemented. You would be required to follow the
requirements of proposed 40 CFR part 98, subpart C to estimate
emissions of CO2, CH4 and N2O from
stationary combustion. This section of the preamble provides procedures
only for calculating and reporting process-related emissions.
We identified Options 3, 4, and 5 as the approaches that have
acceptable uncertainty for facility-specific estimates. All of these
options would provide insight into different levels of emissions caused
by facility-specific differences in feedstock or process operation.
Options 3, 4, and 5 are forms of the IPCC's highest tier methodology
(Tier 3), therefore, we propose these options as equal options. After
consideration of public comments, we may promulgate one or more of the
options or a combination based on the additional information that is
provided.
We considered but decided against Options 1 and 2 because the use
of default values and lack of direct measurements results in a very
high level of uncertainty in the emission estimates. These default
approaches would not provide site-specific estimates of emissions that
would reflect differences in feedstocks, operating conditions, fuel
combustion efficiency, variability in fuels and other differences among
facilities. In general, we decided against proposing existing
methodologies that relied on default emission factors or default values
for carbon content of materials because the differences among
facilities described above could not be discerned, and such default
approaches are inherently inaccurate for site-specific determinations.
The use of default values is more appropriate for sector wide or
national total estimates from aggregated activity data than for
determining emissions from a specific facility. According to the IPCC's
2006 guidelines, the uncertainty associated with default emission
factors for Options 1 and 2 is 25 percent, and the
uncertainty in the production data used with the default emission
factor is 10 percent, which results in a combined overall
uncertainty greater than 25 percent. If process-specific
carbon contents and actual mass rate data for the process inputs and
outputs are used (i.e., Option 3) or if direct measurements are used
(i.e., Options 4 and 5), the guidelines state that the uncertainty
associated with the emission estimates would be reduced.
For Option 3, we are proposing that facilities may estimate process
emissions based on a carbon balance that uses facility-specific
information on the carbon content of process inputs and outputs and
measurements of the mass rate of process inputs and outputs. Monthly
determinations of the mass of process inputs and outputs other than
[[Page 16518]]
fuels would be required. These data are readily available for almost
all process inputs and outputs on a monthly basis from purchasing,
accounting, and production records that are routinely maintained by
each facility. The mass rates of fuels would be measured according to
the procedures for fuels in combustion units in proposed 40 CFR part
98, subpart C. The carbon content of each process input and output
other than fuels would also be measured each month. A sample would be
taken each week, composited for the monthly analysis, and sent to an
independent laboratory for analysis of carbon content using the test
methods in proposed 40 CFR part 98, subpart A. The carbon content of
fuels would be determined using the procedures for fuels in combustion
units in proposed 40 CFR part 98, subpart C. The CO2
emissions would be estimated each month using the carbon balance
equations in the proposed rule and then summed to provide the totals
for the quarter and for the year.
While this proposed approach is consistent with how iron and steel
production facilities are currently developing facility level GHG
inventories, there are three components of this approach for which the
Agency is requesting comment and supporting information. One issue is
the ability to obtain accurate measurements of the process inputs and
outputs, especially materials that are bulk solids and molten metal and
slag. A second issue is the ability to obtain representative samples of
the process inputs and outputs to determine the carbon content,
especially for non-homogenous materials such as iron and steel scrap.
The third issue is the level of uncertainty in the emission estimates
for processes where there is a significant amount of carbon leaving the
process with product (such as coke plants). These and other factors may
result in an unacceptable level of uncertainty, especially for certain
processes, when using the carbon balance approach to estimate
emissions.
While we are proposing that emissions from blast furnace stoves and
coke battery combustion stacks be reported as would be required for
combustion sources under proposed 40 CFR part 98, subpart C, we are
also requesting comment on how the carbon balance approach (Option 3)
could be implemented as an alternative monitoring option for the entire
blast furnace operation and the entire coke plant operation at
integrated iron and steel facilities. Comments should address the
advantages, disadvantages, types and frequency of measurements that
should be required, and whether (and if so, how) the emissions can be
determined with reasonable certainty. Comments must demonstrate that
the procedures produce results that are reproducible and clearly
specify the sampling methods and QA procedures that would ensure
accurate results.
For the site-specific emission factor approach (Option 4), the
owner or operator may conduct a performance test and determine
CO2 emissions from all exhaust stacks for the process using
EPA reference methods to continuously measure the CO2
concentration and stack gas volumetric flow rate during the test. In
addition, either the feed rate of materials into the process or the
production rate during the test would be measured. The performance test
would be conducted under normal process operating conditions and at a
production rate no less than 90 percent of the process rated capacity.
For continuous processes (taconite indurating furnaces, non-recovery
coke batteries, and sinter plants), the testing would cover at least
nine hours of continuous operation. For batch or cyclic processes
(basic oxygen furnaces, electric arc furnaces, and direct reduction
furnaces), the testing would cover at least nine complete production
cycles that start when the furnace is being charged and end after steel
or iron and slag have been tapped. We are proposing testing for nine
hours or nine production cycles, as applicable, because nine tests
should provide a reasonable measure of variability (i.e., the standard
deviation for nine production cycles or nine 1-hour runs). If an
electric arc furnace is used to produce both carbon steel and low
carbon steel (including stainless or specialty steel), separate
emission factors would be developed for carbon steel and low carbon
steel.
The site-specific emission factor for the process would be
calculated in metric tons CO2 per metric ton of feed or
production, as applicable, by dividing the CO2 emission rate
by the feed or production rate. The CO2 emissions for the
process would be calculated by multiplying the emission factor by the
total amount of feed or production, as applicable. A new performance
test would be required each year to develop a new site-specific
emission factor. Whenever there is a significant change in fuel type or
mix, change in the process in a manner that affects energy efficiency
by more than 10 percent, or a change in the process feed materials in a
manner that changes the carbon content of the feed or fuel by more than
10 percent, a new performance test would be conducted and a new site-
specific emission factor calculated.
We are also requesting comment on the advantages and disadvantages
of Option 4, along with supporting documentation. We have concluded
that there may be situations in which the site-specific emission factor
approach may result in an uncertainty lower than that associated with
the carbon balance approach and provide more reasonable emission
estimates. An example is nonrecovery coke plants, where a carbon
balance approach may result in an unacceptably high level of
uncertainty from subtracting two very large numbers (carbon in with
coal and carbon out with coke) to estimate emissions that could instead
be accurately and directly measured at the combustion stack.
The primary sources of variability that affect CO2
emissions from process sources in general are the carbon content of the
process inputs and fuel and any changes to the process that alter
energy efficiency. For most processes, the carbon content of process
inputs and fuels is consistent and stable, and if a process change
alters energy efficiency, a re-test could be performed to develop a new
emission factor that reflected the change. We are requesting comment
and supporting information on the minimum time or number of production
cycles needed for testing to develop a representative emission factor,
and how often periodic re-testing should be required (e.g., annually,
quarterly, or only when there is a process change). We are also
requesting that any comments on Option 4 address how changes in process
inputs, fuels, or process energy efficiency should be accounted for,
such as requiring a re-test if the carbon content of inputs change by
more than some specified percent, if the type or mix of fuel is
changed, or if there is a significant change in fuel consumption due to
a process change.
We are also proposing that you may use direct measurements, noting
that CEMS (Option 5) provide the lowest uncertainty of the three
options. This approach overcomes many of the limitations associated
with other options considered such as accounting for the variability in
emissions due to changes in the process, feed materials, or fuel over
time. It would be applied to stacks that are already equipped with
sampling ports and access platforms; consequently, it is technically
feasible and cost effective. For those emission sources already
equipped with CEMS, we are proposing that they be modified (if
necessary) and used to determine CO2 emissions for that
emission source. We are proposing this requirement
[[Page 16519]]
because it provides direct emission measurements that have low
uncertainty with only a minimal additional cost burden. We also request
comment, along with supporting documentation, on the advantages and
disadvantages of Option 5.
We are also proposing that CH4 and N2O
emissions from the combustion of fuels in both combustion units and
process units be determined and reported. All of the fuels used at iron
and steel production processes are included in the methodologies in
proposed 40 CFR part 98, subpart C for N2O and
CH4. Consequently, EPA is proposing to use the same
methodology as in proposed 40 CFR part 98, subpart C for determining
and reporting emissions of N2O and CH4 from both
stationary combustion units and process units.
Miscellaneous Emissions Sources. Emissions may also occur when the
incandescent coke is pushed from the coke oven and transported to the
quench tower where it is cooled (quenched) with water. A small portion
of the coke burns during this process prior to quenching. We updated
the coke oven section of the AP-42 \79\ compilation of emission factors
in May 2008, and the update included an emission factor for
CO2 emissions developed from 26 tests for particulate matter
from pushing operations. The emissions factor (0.008 metric tons
CO2e per metric ton of coal charged) was derived to account
for emissions from the pushing emission control device and those
escaping the capture system. We are proposing that coke facilities use
the AP-42 emission factor to estimate CO2 emissions from
coke pushing operations.
---------------------------------------------------------------------------
\79\ See Compilation of Air Pollutant Emission Factors, Fifth
Edition: http://www.epa.gov/ttn/chief/ap42/ch12/final/c12s02_may08.pdf.
---------------------------------------------------------------------------
There are dozens of emission points and various types of fugitive
emissions, not collected for emission through a stack, from the
production processes and materials handling and transfer activities at
integrated iron and steel facilities. These emissions from iron and
steel plants have been of environmental interest primarily because of
the particulate matter in the emissions. Examples include ladle
metallurgy operations, desulfurization, hot metal transfer, sinter
coolers, and the charging and tapping of furnaces. The information we
have examined to date indicates that these emissions contribute very
little to the overall GHG emissions from the iron and steel sector
(probably on the order of one percent or less). For example, emissions
of blast furnace gas may be emitted during infrequent process upsets
(called ``slips'') when gas is vented for a short period or from leaks
in the ductwork that handles the gas. However, the mass of GHG
emissions is expected to be small because most of the carbon in blast
furnace gas is from carbon monoxide, which is not a GHG. Fugitive
emissions and emissions from control device stacks may also occur from
blast furnace tapping, the charging and tapping of basic oxygen
furnaces and electric arc furnaces, ladle metallurgy, desulfurization,
etc. However, we have no information that indicates CO2 is
generated from these operations, and a review of test reports from
systems that capture these emissions show that CO2
concentrations are very low (at ambient air levels). Fugitive emissions
containing CH4 may occur from leaks of raw coke oven gas
from the coke oven battery during the coking cycle. However, the mass
of these emissions is expected to be small based on the small number of
leaks that are now allowed under existing Federal and State standards
that regulate these emissions. In addition, since these emissions are
not captured in a conveyance, there is no practical way to measure
them. Consequently, we are not proposing that fugitive emissions be
reported because we believe their GHG content is negligible and because
there is no practical way of measuring them. However, we welcome public
comment, along with supporting data and documentation, on whether
fugitive emissions should be included, and if so, how these emissions
can be estimated.
4. Selection of Procedures for Estimating Missing Data
For process sources that use Option 3 (carbon balance) or Option 4
(site-specific emission factor), no missing data procedures would apply
because 100 percent data availability would be required. For process
sources that use Option 5 (direct measurement by CEMS), the missing
data procedures would be the same as for units using Tier 4 in the
general stationary fuel combustion source category in proposed 40 CFR
part 98, subpart C.
5. Selection of Data Reporting Requirements
We are proposing that facilities submit annual emission estimates
for CO2 presented by calendar quarters for coke oven battery
combustion stacks, coke pushing, blast furnace stoves, taconite
indurating furnaces, electric arc furnaces, argon-oxygen
decarburization vessel, direct reduced iron furnaces, and sinter
plants.
In addition we propose that facilities submit the following data to
assist in checks for reasonableness and for other data quality
considerations: Total mass for all process inputs and outputs when the
carbon balance is used for specific processes by calendar quarters,
site-specific emission factor for all processes for which the site-
specific emission factor approach is used, annual production quantity
for taconite pellets, coke, sinter, iron, raw steel by calendar
quarters, annual production capacity for taconite pellets, coke,
sinter, iron, raw steel, annual operating hours for taconite furnaces,
coke oven batteries, sinter production, blast furnaces, direct reduced
iron furnaces, and electric arc furnaces, and the quantity of
CO2 captured for use and the end use, if known.
A full list of data that would be reported is included in proposed
40 CFR part 98, subparts A and Q.
6. Selection of Records That Must Be Retained
In addition to the recordkeeping requirements for general
stationary fuel combustion sources, we propose that the following
additional records be kept to assist in QA/QC and verification
purposes: GHG emission estimates from the iron and steel production
process by calendar quarter, monthly total for all process inputs and
outputs when the carbon balance is used for specific processes,
documentation of calculation of site-specific emission factor for all
processes for which the site-specific emission factor approach is used,
monthly analyses of carbon content, and monthly production quantity for
taconite pellets, coke, sinter, iron, and raw steel.
R. Lead Production
1. Definition of the Source Category
Lead is a metal used to produce various products such as batteries,
ammunition, construction materials, electrical components and
accessories, and vehicle parts. For this proposed rule, we are defining
the lead production source category to consist of primary lead smelters
and secondary lead smelters. A primary lead smelter produces lead metal
from lead sulfide ore concentrates through the use of pyrometallurgical
processes. A secondary lead smelter produces lead and lead alloys from
lead-bearing scrap metal.
For the primary lead smelting process used in the U.S., lead
sulfide ore concentrate is first fed to a sintering process to burn
sulfur from the lead ore. The sinter is smelted with a
[[Page 16520]]
carbonaceous reducing agent in a blast furnace to produce molten lead
bullion. From the furnace, the bullion is transferred to dross kettle
furnaces to remove primarily copper and other metal impurities.
Following further refining steps, the lead is cast into ingots or alloy
products.
The predominate feed materials processed at U.S. secondary lead
smelters are used automobile batteries, but these smelters can also
process other lead-bearing scrap materials including wheel balance
weights, pipe, solder, drosses, and lead sheathing. These incoming lead
scrap materials are first pre-treated to partially remove metal and
nonmetal contaminants. The resulting lead scrap is smelted (U.S.
secondary lead smelters typically use either a blast furnace or
reverberatory furnace). The molten lead from the smelting furnace is
refined in kettle furnaces, and then cast into ingots or alloy
products.
Lead production results in both combustion and process-related GHG
emissions. Combustion-related CO2, CH4, and
N2O emissions are generated from metallurgical process
equipment used at primary and secondary lead smelters when natural gas
or another fuel is burned in the unit to produce heat for drying,
roasting, sintering, calcining, melting, or casting operations.
Process-related CO2 emissions are released from the lead
smelting process due to the addition of a carbonaceous reducing agent
such as metallurgical coke or coal to the smelting furnace. The
reduction of lead oxide to lead metal during the process produces the
CO2 emissions.
Currently there is one primary lead smelter operating in the U.S.
There are 26 secondary lead smelters in the U.S. with widely varying
annual lead production capacities ranging from approximately 1,000
metric tons to more than 100,000 metric tons. Total national GHG
emissions from lead production in the U.S. were estimated to be
approximately 0.9 million metric tons CO2e in 2006. These
emissions include both on-site stationary combustion emissions
(CO2, CH4, and N2O) and process-
related emissions (CO2). The majority of these emissions
were from the combustion of carbon-based fuels. Combustion GHG
emissions were 0.6 million metric tons CO2e emissions (69
percent of the total emissions). The remaining 0.3 million metric tons
CO2e (31 percent of the total emissions) were process-
related GHG emissions.
Additional background information about GHG emissions from the lead
production source category is available in the Lead Production TSD
(EPA-HQ-OAR-2008-0508-018).
2. Selection of Reporting Threshold
In developing the threshold for lead production facilities, we
considered using annual GHG emissions-based threshold levels of 1,000
metric tons CO2e, 10,000 metric tons CO2e, 25,000
metric tons CO2e and 100,000 metric tons CO2e.
This threshold is based on combined combustion and process
CO2 emissions at the lead production facility. Table R-1 of
this preamble presents the estimated emissions and number of facilities
that would be subject to GHG emissions reporting, based on existing
facility lead production capacities, under these various threshold
levels.
Table R-1. Threshold Analysis for Lead Smelters
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Total Nationwide ---------------------------------------------------------------
Threshold level metric tons CO2e/yr nationwide number of metric tons Facility
emissions facilities CO2e/yr Percent number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 866,000 27 859,000 99 17 63
10,000.................................................. 866,000 27 853,000 98 16 59
25,000.................................................. 866,000 27 798,000 92 13 48
100,000................................................. 866,000 27 0 0 0 0
--------------------------------------------------------------------------------------------------------------------------------------------------------
Secondary lead smelters in the U.S. vary greatly in production
capacity and include 10 small facilities with production capacities
less than 4,000 tons per year. Table R-1 of this preamble shows
approximately 92 percent of the GHG emissions that result from lead
production are released from the one primary smelter and 12 secondary
smelters that emit more than 25,000 metric tons CO2e
annually. Of the facilities with annual GHG emissions below 25,000
metric tons CO2e, 10 secondary smelters are estimated to
emit less than 1,000 metric tons CO2e annually.
To avoid placing a reporting burden on the smaller secondary lead
smelters which may operate as small businesses while still requiring
the reporting of GHG emissions from those facilities releasing most of
the GHG emissions in this source category, we are proposing a threshold
of 25,000 metric tons CO2e per year for reporting of
emissions. This threshold level is consistent with the threshold level
being proposed for other source categories with similar facility size
characteristics. More discussion of the threshold selection analysis is
available in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
We reviewed existing domestic and international GHG monitoring
guidelines and protocols including the 2006 IPCC Guidelines for
National Greenhouse Gas Inventories, U.S. GHG Inventory, the EU
Emissions Trading System, the Canadian Mandatory Greenhouse Gas
Reporting Program, and the Australian National Greenhouse Gas Reporting
Program. These methods coalesce around the following four options for
estimating process-related CO2 emissions from lead
production facilities. A full summary of methods reviewed is available
in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018).
Option 1. Apply a default emission factor for the process-related
emissions to the facility's lead production rate. This is a simplified
emission calculation method using only default emission factors to
estimate process-related CO2 emissions. The method requires
multiplying the amount of lead produced by the appropriate default
emission factors from the 2006 IPCC Guidelines. This method is
consistent with the IPCC Tier 1 method.
Option 2. Perform monthly measurements of the carbon content of
specific process inputs and measure the mass rate of these inputs. This
is the IPCC Tier 3 approach and the higher order methods in the
Canadian and Australian reporting programs. Implementation of this
method requires owners and operators of affected lead smelters to
determine the carbon
[[Page 16521]]
contents of materials added to the smelting furnace by analysis of
representative samples collected of the material or from information
provided by the material suppliers. In addition, you must measure and
record the quantities of these input materials consumed during
production. To obtain the process-related CO2 emission
estimate, the material carbon content would be multiplied by the
corresponding mass of the carbon-containing input material consumed and
a conversion factor of carbon to CO2. This method assumes
that all of the carbon is converted to CO2 during the
reduction process. The facility owner or operator would determine the
average carbon content of the material for each calendar month using
information provided by the material supplier or by collecting a
composite sample of material and sending it to an independent
laboratory for chemical analysis.
Option 3. Use CO2 emissions data from a stack test
performed using EPA reference test methods to develop a site-specific
process emissions factor which is then applied to quantity measurement
data of feed material or product for the specified reporting period.
This monitoring method is applicable to furnace configurations for
which the GHG emissions are contained within a stack or vent. Using
site-specific emissions factors based on short-term stack testing is
appropriate for those facilities where process inputs (e.g., feed
materials, carbonaceous reducing agents) and process operating
parameters remain relatively consistent over time.
Option 4. Use direct emission measurement of CO2
emissions. For furnace configurations in which the process off-gases
are contained within a stack or vent, direct measurement of the
CO2 emissions can be made by continuously measuring the off-
gas stream CO2 concentration and flow rate using a CEMS. For
a smelting furnace used for lead production where both combustion and
process-related emissions are released by a source (e.g. blast furnace)
emissions reported by using a CEMS would be total CO2
emissions including both combustion and process-related CO2
emissions.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow requirements of proposed 40 CFR part 98, subpart C to estimate
CO2 emissions. Also, refer to proposed 40 CFR part 98,
subpart C to estimate combustion-related CH4 and
N2O.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
CEMS would not adequately account for combustion and process related
CO2 emissions, the proposed monitoring method for process-
related CO2 from lead production is Option 2. You would be
required to follow the calculation procedures, monitoring and QA/QC
methods, missing data procedures, reporting requirements, and
recordkeeping requirements of proposed 40 CFR part 98, subpart C to
estimate emissions of CO2, CH4 and N2O
from stationary combustion. This section of the preamble provides
procedures only for calculating and reporting process-related
emissions.
We propose Option 2, due to the operating variations between the
individual U.S. lead production facilities, including differences in
equipment configurations, mix of lead feedstocks charged, and types of
carbon materials used. Further, Option 2 would result in lower
uncertainty as compared to applying a default emissions factor based
approach to these units.
Although we are not proposing to require you to directly measure
process emissions, unless you meet the requirements of proposed 40 CFR
part 98, subpart C and the CEMS account for both combustion and
process-relate emissions, you could opt to use direct measurement of
CO2 emissions as an alternative GHG emissions estimation
method because it would best reflect actual operating practices at your
facility, and therefore, reduce uncertainty. While we recognize that
the costs for conducting direct measurements may be higher than other
methods, we are proposing to include this alternative because it
provides GHG emissions data that have low uncertainty. The additional
cost burden may be acceptable to owners and operators with site-
specific reasons for choosing this alternative.
We decided not to propose the use of the default CO2
emission factors (Option 1) because their application is more
appropriate for GHG estimates from aggregated process information on a
sector-wide or nationwide basis than for determining GHG emissions from
specific facilities. We considered the additional burden of the
material measurements required for the carbon calculations under Option
2 small in relation to the increased accuracy expected from using this
site-specific information to calculate the process-related
CO2 emissions.
We also decided not to propose Option 3 because of the potential
for significant variations at lead smelters in the characteristics and
quantities of the furnace inputs (e.g., lead scrap materials,
carbonaceous reducing agents) and process operating parameters. A
method using periodic, short-term stack testing would not be practical
or appropriate for those lead smelters where the furnace inputs and
operating parameters do not remain relatively consistent over the
reporting period.
Further details about the selection of the monitoring methods for
GHG emissions is available in the Lead Production TSD (EPA-HQ-OAR-2008-
0508-018).
4. Selection of Procedures for Estimating Missing Data
For smelting furnaces for which the owner or operator calculates
process GHG emissions using site-specific carbonaceous input material
data, the proposed rule requires the use of substitute data whenever a
quality-assured value of a parameter that is used to calculate GHG
emissions is unavailable, or ``missing.'' If the carbon content
analysis of carbon inputs is missing or lost the substitute data value
would be the average of the quality-assured values of the parameter
immediately before and immediately after the missing data period. In
those cases when an owner or operator uses direct measurement by a
CO2 CEMS, the missing data procedures would be the same as
the Tier 4 requirements described for general stationary fuel
combustion sources in proposed 40 CFR part 98, subpart C. The
likelihood for missing data is low, as businesses closely track their
purchase of production inputs.
5. Selection of Data Reporting Requirements
The proposed rule would require annual reporting of the total
annual CO2 process-related emissions from each smelting
furnace at lead production facilities, as well as any stationary fuel
combustion emissions. In addition, we are proposing that additional
information that forms the basis of the emissions estimates also be
reported so that we can understand and verify the reported emissions.
This addition information includes the total number of smelting
furnaces operated at the facility, the facility lead product production
capacity, the annual facility production quantity, annual quantity and
type of carbon-containing input
[[Page 16522]]
materials consumed or used, annual weighted average carbon contents by
material type, and the number of facility operating hours in the
calendar year. A complete list of data to be reported is included in
proposed 40 CFR part 98, subparts A and R.
6. Selection of Records That Must Be Retained
Maintaining records of the information used to determine the
reported GHG emissions is necessary to enable us to verify that the GHG
emissions monitoring and calculations were done correctly. In addition
to the information reported as described in Section V.R.5 of this
preamble, we propose that all facilities estimating emissions according
to the carbon input method maintain records of each carbon-containing
input material consumed or used (other than fuel) the monthly material
quantity, monthly average carbon content determined for material, and
records of the supplier provided information or analyses used for the
determination. If you use the CEMS procedure, you would maintain the
CEMS measurement records according to the procedures in proposed 40 CFR
part 98, subpart C. These records would be required to be maintained
onsite for 5 years. A complete list of records to be retained is
included in the proposed rule.
S. Lime Manufacturing
1. Definition of the Source Category
Lime is an important manufactured product with many industrial,
chemical, and environmental applications. Its major uses are in steel
making, flue gas desulfurization systems at coal-fired electric power
plants, construction, and water purification. Lime is used for the
following purposes: Metallurgical uses (36 percent), environmental uses
(29 percent), chemical and industrial uses (21 percent), construction
uses (13 percent), and to make dolomite refractories (1 percent).
For U.S. operations, the term ``lime'' actually refers to a variety
of chemical compounds. These compounds include calcium oxide (CaO), or
high-calcium quicklime; calcium hydroxide (Ca(OH)2), or
hydrated lime; dolomitic quicklime ((CaO[bul]MgO)); and dolomitic
hydrate ((Ca(OH)2[bul]MgO) or
(Ca(OH)2[bul]Mg(OH)2)). Lime manufacturing
involves three main processes: Stone preparation, calcination, and
hydration. During the calcination process, the carbonate in limestone
is sufficiently heated and reduced to CO2 gas. In certain
applications, lime reabsorbs CO2 during use thereby reducing
onsite GHG emissions.
National emissions from the lime industry were estimated to be 25.4
million metric tons CO2e in 2004 (or <0.4 percent of
national emissions). These emissions include both process-related
emissions and on-site stationary combustion emissions from 89 lime
manufacturing facilities across the U.S. and Puerto Rico. Process-
related emissions account for 14.3 million metric tons CO2e,
or 56 percent of the total, while on-site stationary combustion
emissions account for the remaining 11.1 million metric tons
CO2e.
For additional background information on lime manufacturing, please
refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019).
2. Selection of Reporting Threshold
In developing the proposed reporting threshold for the lime
manufacturing source category, we considered emissions-based thresholds
of 1,000 metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and 100,000 metric
tons CO2e. This threshold is based on combined combustion
and process CO2 emissions at a lime production facility.
Table S-1 of this preamble illustrates the emissions and facilities
that would be covered under various thresholds.
Table S-1. Threshold Analysis for Lime Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities metric tons
CO2e/yr CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 25,421,043 89 25,421,043 100 89 100
10,000.................................................. 25,421,043 89 25,396,036 99.9 86 97
25,000.................................................. 25,421,043 89 25,371,254 99.8 85 96
100,000................................................. 25,421,043 89 23,833,273 94 52 58
--------------------------------------------------------------------------------------------------------------------------------------------------------
The lime manufacturing sector consists primarily of large
facilities and a few smaller facilities. All facilities, except four,
exceed the 25,000 metric tons CO2e threshold.
Consistent with National Lime Association recommendations, and in
order to simplify the proposed rule and avoid the need to calculate and
report whether the threshold value has been exceeded, we are proposing
that all lime manufacturing facilities report GHG emissions. This
captures 100 percent of emissions without significantly increasing the
number of facilities that would have reported at 1,000, 10,000, or
25,000 metric ton thresholds. For a full discussion of the threshold
analysis, please refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008-
0508-019). For specific information on costs, including unamortized
first year capital expenditures, please refer to section 4 of the RIA
and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from lime manufacturing (e.g., the 2006 IPCC Guidelines, U.S.
Inventory, DOE 1605(b), National Lime Association CO2
Protocol, and the EU Emissions Trading System). These methodologies can
be summarized by the following two overall approaches to estimating
emissions, based on measuring either the carbonate inputs to the kiln
or production outputs of the lime manufacturing process.
Input-based Options. We considered the IPCC Tier 3 method which
requires facilities to estimate process emissions by measuring the
quantity of carbonate inputs to the kiln(s) and applying the
appropriate emission factors and calcination fractions to the
carbonates consumed. In order to assess the composition of carbonate
inputs, facilities would send samples of their inputs and lime kiln
dust produced to an off-site laboratory for analysis on a monthly basis
using ASTM C25-06, ``Standard Test Methods for Chemical Analysis of
Limestone, Quicklime, and Hydrated Lime'' (incorporated by reference,
see proposed 40 CFR 98.7). For greater accuracy, facilities would
[[Page 16523]]
also estimate the calcination fraction of each carbonate consumed on a
monthly basis. However, it is generally accepted that the calcination
fraction of carbonates during lime production is 100 percent or very
close to it.
Output-based Options. We also considered three output-based methods
for quantifying process-related emissions based on the quantity of lime
produced. IPCC's Tier 1 method applies default emission factors to each
of the three types of lime produced (high calcium lime, dolomitic lime,
or hydraulic lime). The IPCC Tier 2 method applies a default emissions
factor based on lime type to the corresponding quantity of all lime
produced (by type), correcting for the amount of calcined byproduct/
waste product (such as lime kiln dust) produced in the process.
The third output method, developed by the National Lime
Association, improves upon the IPCC Tier 2 procedure. In this method,
facilities multiply the amount of lime produced at each kiln and the
amount of calcined byproducts/wastes at the kiln by an emission factor.
The emission factor is derived based on facility specific chemical
analysis of the CaO and magnesium oxide (MgO) content of the lime
produced at the kiln. To assess the composition of the lime and
calcined byproduct/waste product, facilities would send samples to an
off-site laboratory for analysis on a monthly basis following the
procedures described in the National Lime Association's method
protocol, along with the procedures in ASTM C25-06, ``Standard Test
Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated
Lime'' (incorporated by reference, see proposed 40 CFR 98.7). This
third output approach is also consistent with 1605(b)'s ``A'' rated
approach and EU Emission Trading System's calculation B method.
We compared the various methods for estimating process-related
CO2 emissions. In general, the IPCC output methods are less
certain, as they involve multiplying production data by emission and
correction factors for lime kiln dust that are likely default values
based on purity assumptions (i.e. the total CaO and MgO content of the
lime products). In contrast, the input method is more certain as it
involves measuring the consumption of each carbonate input and
calculating purity fractions. According to the 2006 IPCC Guidelines,
the uncertainty involved in the carbonate input approach for the IPCC
Tier 3 method is 1 to 3 percent and the uncertainty involved in using
the default emission factor and lime kiln dust correction factor for
the Tier 1 and Tier 2 production-based approaches is 15 percent.
However, IPCC states that the major source of uncertainty in the above
approaches is the CaO content of the lime produced.
Proposed Option. Under this proposed rule, if you are using an
existing CEMS that meets the requirements outlined in proposed 40 CFR
part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C to
estimate both combustion and process CO2 emissions. Also,
you would refer to proposed 40 CFR part 98, subpart C to estimate
combustion-related CH4 and N2O emissions.
Under this proposed rule, if you do not have CEMS that meet the
conditions outlined in proposed 40 CFR part 98, subpart C, you would
use the National Lime Association method in this section of the
preamble to calculate process-related CO2 emissions. Refer
to proposed 40 CFR part 98, subpart C specifically for procedures to
estimate combustion-related CO2, CH4 and
N2O emissions.
We are proposing the National Lime Association's output-based
procedure because this method is already in use by U.S. facilities and
the improvement in accuracy compared to default approaches can be
achieved at minimal additional cost. The measurement of production
quantities is common practice in the industry and is usually measured
through the use of scales or weigh belts so additional costs to the
industry are not anticipated. The primary additional burden for
facilities would include conducting a CaO and MgO analysis of each lime
product on a monthly basis (to be averaged on an annual basis).
However, approximately two thirds of the lime manufacturing facilities
in the U.S. are already undertaking sampling efforts to meet reporting
goals set forth by the National Lime Association.
We request comment on the advantages and disadvantages of the IPCC
Tier 3 method and supporting documentation. After consideration of
public comments, we may promulgate the IPCC Tier 3 input-based
procedure, the National Lime Association output-based procedure, or a
combination based on additional information that is provided.
The various approaches to monitoring GHG emissions are elaborated
in the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019).
4. Selection of Procedures for Estimating Missing Data
It is assumed that a facility would be able to supply facility-
specific production data. Since the likelihood for missing data is low
because businesses closely track production, 100 percent data
availability is required for lime production (by type) in the proposed
rule. If analysis for the CaO and MgO content of the lime product are
unavailable or ``missing'', facility owners or operators would
substitute a data value that is the average of the quality-assured
values of the parameter immediately before and immediately after the
missing data period.
5. Selection of Data Reporting Requirements
We propose that in addition to stationary fuel combustion GHG
emissions, you report annual CO2 emissions for each kiln. In
addition, for each kiln we are proposing that facilities report the
following data used as the basis of the calculations to assist in
verification of estimates, checks for reasonableness, and other data
quality considerations for process emissions: Annual lime production
and production capacity, emission factor by lime type, and number of
operating hours in the calendar year. A full list of data to be
reported is included in proposed 40 CFR part 98, subparts A and S.
6. Selection of Records That Must be Retained
Maintaining records of the information used to determine the
reported GHG emissions are necessary to enable us to verify that the
GHG emissions monitoring and calculations were done correctly. In
addition to the data to be reported, we are proposing that the
facilities maintain records of the calculation of emission factors,
results of the monthly chemical composition analyses, total lime
production for each kiln by month and type, total annual calcined
byproducts/wastes produced by each kiln averaged from monthly data, and
correction factor for byproducts/waste products for each kiln. A full
list of records that must be retained onsite is included in proposed 40
CFR part 98, subparts A and S.
T. Magnesium Production
1. Definition of the Source Category
Magnesium is a high-strength and light-weight metal that is
important for the manufacture of a wide range of products and
materials, such as portable electronics, automobiles, and other
machinery. The U.S. accounts for less than 10 percent of world primary
[[Page 16524]]
magnesium production but is a significant importer of magnesium and
producer of cast parts. The production and processing of magnesium
metal under common practice results in emissions of SF6. For
further information, see the Magnesium Production TSD (EPA-HQ-OAR-2008-
0508-020).
The magnesium metal production (primary and secondary) and casting
industry typically uses SF6 as a cover gas to prevent the
rapid oxidation and burning of molten magnesium in the presence of air.
A dilute gaseous mixture of SF6 with dry air and/or
CO2 is blown over molten magnesium metal to induce and
stabilize the formation of a protective crust. A small portion of the
SF6 reacts with the magnesium to form a thin molecular film
of mostly magnesium oxide and magnesium fluoride. The amount of
SF6 reacting in magnesium production and processing is under
study but is presently assumed to be negligible. Thus, all
SF6 used is presently assumed to be emitted into the
atmosphere.
Cover gas systems are typically used to protect the surface of a
crucible of molten magnesium that is the source for a casting operation
and to protect the casting operation itself (e.g., ingot casting).
SF6 has been used in this application in most parts of the
world for the last twenty years. Due to increasing awareness of the GWP
of SF6, the magnesium industry has begun exploring climate-
friendly alternative melt protection technologies. At this time the
leading alternatives include HFC-134a, a fluorinated ketone (FK 5-1-12,
C3F7C(O)C2F5), and dilute
sulfur dioxide (SO2). The application of the fluorinated
alternatives mentioned here may generate byproduct emissions of concern
including PFCs. We are proposing that magnesium production and
processing facilities report process emissions of SF6, HFC-
134a, FK 5-1-12, and CO2.
Total U.S. emissions of SF6 from magnesium production
and processing in the U.S. were estimated to be 3.2 metric tons
CO2e in 2006. Primary and secondary production activities at
3 facilities accounted for about 64 percent of total emissions, or 2
metric tons CO2e. Approximately 20 magnesium die casting
facilities in the U.S. accounted for more than 30 percent, or more than
0.9 metric tons CO2e of total magnesium-related
SF6 emissions. Other smaller casting activities such as sand
and permanent mold casting accounted for the remaining magnesium-
related emissions of SF6. The term ``metal processed'' used
here is defined as the mass of magnesium melted to cast or create
parts. This should not be confused with the mass of finished magnesium
parts because varying amounts of the metal may be lost as scrap when
performing casting operations.
2. Selection of Reporting Threshold
We considered emissions thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e as well as
capacity based thresholds as shown in Tables T-1 and T-2 of this
preamble.
Table T-1. Threshold Analysis for Mg Production Based On Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
nationwide Nationwide ---------------------------------------------------------------
Threshold level metric tons CO2e/yr emissions number of
metric tons facilities Metric tons Percent Facilities Percent
CO2e/Yr CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 3,200,000 13 2,954,559 92 13 100
10,000.................................................. 3,200,000 13 2,939,741 92 11 85
25,000.................................................. 3,200,000 13 2,939,741 92 11 85
100,000................................................. 3,200,000 13 2,872,982 90 9 69
--------------------------------------------------------------------------------------------------------------------------------------------------------
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
production levels.
Table T-2. Threshold Analysis for Mg Production Based On Mg Production Capacity
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities Covered
nationwide ---------------------------------------------------------------
Capacity threshold level Mg/yr emissions Number of
metric tons facilities Metric tons Percent Facilities Percent
CO2e/Yr CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
26...................................................... 3,200,000 13 2,954,559 92 13 100
262..................................................... 3,200,000 13 2,949,732 92 12 92
656..................................................... 3,200,000 13 2,949,732 92 12 92
2,622................................................... 3,200,000 13 2,780,717 87 9 69
--------------------------------------------------------------------------------------------------------------------------------------------------------
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
production levels.
Under the proposed rule, magnesium metal production and parts
casting facilities would have to report their total GHG emissions if
those emissions exceeded 25,000 metric tons CO2e. This
threshold covers all currently identified operating U.S. primary and
secondary magnesium producers and most die casters, accounting for over
99 percent of emissions from these source categories.
The proposed emissions threshold of 25,000 metric tons
CO2e is equal to emissions of 1,046 kg of SF6;
19,231 kg of HFC-134a; or 25,000,000 kg of CO2 or FK 5-1-2.
Other emission threshold options that we considered were 1,000 metric
tons CO2e, 10,000 metric tons CO2e, and 100,000
metric tons CO2e. The 10,000 metric tons CO2e
emission threshold yielded results identical to those of the proposed
option.
We also considered capacity-based thresholds of 26, 262, 656, and
2,622 metric tons, based on 100 percent capacity utilization and an
SF6 emission rate of 1.6 kg SF6 per metric ton of
magnesium produced or processed. This emission factor represents the
sum of (1) the average of the emission factors reported for secondary
production and die casting through our magnesium Partnership (excluding
outliers), and (2)
[[Page 16525]]
the standard deviation of those emission factors. The 1.6 kg-per-ton
factor is higher than most, though not all, of the emission factors
reported, which ranged from 0.7 to 7 kg/ton Mg in 2006. The resulting
capacity thresholds yielded results very similar to those of the
emission-based thresholds.
The emissions based threshold was selected over the capacity based
threshold for several reasons. The emissions based threshold is simple
to evaluate because magnesium production and processing facilities can
use readily available data regarding consumption of SF6 and
would also possess similar data for alternatives such as HFC-134a as
these are phased-in over time. To determine whether they exceeded the
thresholds, magnesium facilities would multiply the total consumption
of each of these gases by a GWP-unit conversion factor that could be
compared to the 25,000 metric ton threshold. The equation for this
calculation is provided in the proposed regulatory text.
The emissions-based threshold of 25,000 metric tons CO2e
also takes into account the variability in cover gas identities, usage
rates, and process conditions. Alternatives to SF6 have
considerably lower GWPs than SF6. In facilities where
SF6 is used, the usage rate can vary by an order of
magnitude depending on the casting process and operating conditions.
Therefore, cover gas emissions are not well predicted by production
capacity. Because emissions of each cover gas are assumed to equal use,
and facilities are expected to track gas use in the ordinary course of
business, facilities should have little difficulty determining whether
or not they must report under this rule. For a full discussion of the
threshold analysis, please refer to the Magnesium Production TSD (EPA-
HQ-OAR-2008-0508-020). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
We reviewed a wide range of protocols and guidance in developing
this proposal, including the 2006 IPCC Guidelines, EPA's SF6
Emission Reduction Partnership for the Magnesium Industry, the U.S. GHG
Inventory, DOE 1605(b), EPA's Climate Leaders Program, and TCR.
The methods described in these protocols and guidance were similar
to the methods described by the IPCC Guidelines and the U.S. GHG
Inventory methodology. These methods range from a Tier 1 approach,
based on default consumption factors per unit Mg produced or processed,
to a Tier 3 approach based on facility-specific measured emissions
data.
Under this proposed rule, if you are required to use an existing
CEMS to meet the requirements outlined in proposed 40 CFR part 98,
subpart C, you would be required to use CEMS to estimate CO2
emissions. Where the CEMS capture all combustion- and process-related
CO2 emissions you would be required to follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
proposed 40 CFR part 98, subpart C to estimate CO2
emissions. Also, refer to proposed 40 CFR part 98, subpart C to
estimate combustion-related CH4 and N2O
emissions.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
the CEMS would not adequately account for process emissions, you would
be required to follow the proposed monitoring method discussed below.
The proposed method outlined below accounts for process-related
SF6, HFC-134a, FK 5-1-12, and CO2 emissions.
Refer to proposed 40 CFR part 98, subpart C specifically for procedures
to estimate combustion-related CO2, CH4 and
N2O emissions.
The proposed method for monitoring SF6, HFC-134a, FK 5-
1-12, and CO2 cover gas emissions from magnesium production
and processing is similar to the Tier 2 approach in the 2006 IPCC
Guidelines for magnesium production. This approach is based on
facility-specific information on cover gas consumption and assumes that
all gases consumed are emitted. This methodology applies to any cover
gas that is a GHG, including SF6, CO2, HFC-134a
and FK 5-1-12.
We propose three options for measuring gas consumption:
1. Weighing gas cylinders as they are brought into and out of
service allowing a facility to accurately track the actual mass of gas
used.
2. Using a mass flow meter to continuously measure the mass of
global warming gases used.
3. Performing a facility level mass balance for all global warming
gases used at least once annually. Using this approach, a facility
would review its gas purchase records and inventory to determine actual
mass of gas used and subtract a 10 percent default heel factor to
account for residual gas in cylinders returned to the gas suppliers.
When weighing cylinders to determine cover gas consumption,
facilities would weigh all gas cylinders that are returned to the gas
supplier, or have the gas supplier weigh the cylinders, to determine
the residual gas still in the cylinder. The weight of residual gas
would be subtracted from the weight of gas delivered to determine gas
consumption. Gas suppliers can provide detailed monthly spreadsheets
with exact residual gas amounts returned.
Facilities would be required to follow several procedures to ensure
the quality of the consumption data. These procedures could be readily
adopted, or would be based on information that is already collected for
other reasons. Facilities would be required to track specific cylinders
leaving and entering storage with check-out and weigh-in sheets and
procedures. Scales used for weighing cylinders and mass flow meters
would need to be accurate to within 1 percent of true mass, and would
be periodically calibrated. Facilities would calculate the facility
usage rate, compare it to known default emission rates and historical
data for the facility, and investigate any anomalies in the facility
usage rate. Finally, facilities would need to have procedures to ensure
that all production lines have provided information to the manager
compiling the emissions report, if this is not already handled through
an electronic inventory system.
We are not proposing IPCC's Tier 1 or 3 methodologies for
calculating emissions. Although the Tier 1 methodology is
straightforward, the default consumption factor for the SF6
usage rate is significantly uncertain due to the variability in
production processes and operating conditions. The Tier 3 methodology
of conducting facility-specific measurements of emissions to account
for potential cover gas destruction and byproduct formation is the most
accurate, but also poses significant economic challenges for
implementation because of the cost of direct emission measurements.
4. Selection of Procedures for Estimating Missing Data
In general, it is unlikely that cover gas consumption data would be
missing. Facilities are expected to know the quantities of cover gas
that they consume because facility operations rely on accurate
monitoring and tracking of costs. Facilities would possess invoices
from gas suppliers during a given year and many facilities currently
track the weight of SF6 consumed by weighing individual
cylinders prior to replacement.
However, where cover gas consumption information is missing, we
[[Page 16526]]
propose that facilities estimate emissions by multiplying production by
the average cover gas usage rate (kg gas per ton of magnesium produced
or processed) from the most recent period when operating conditions
were similar to those for the period for which the data are missing,
i.e., using the same cover gas concentrations and flow rates and, if
applicable, casting parts of a similar size.
5. Selection of Data Reporting Requirements
Facilities would be required to report total facility GHG emissions
and emissions by process type: Primary production, secondary
production, die casting, or other type of casting. For total facility
and process emissions, emissions would be reported in metric tons of
SF6, HFC-134a, FK 5-1-12, and CO2 (used as a
carrier gas).
Along with their total emissions from cover gas use, facilities
would be required to submit supplemental data (as well as the
supplemental data required in the combustion and calcination sections)
including the type of production processes (e.g., primary, secondary,
die casting), mass of magnesium produced or processed in metric tons
for each process type, cover gas flow rate and composition, and mass of
any CO2 used as a carrier gas during reporting period.
If data were missing, facilities would be required to report the
length of time the data were missing, the method used to estimate
emissions in their absence, and the quantity of emissions thereby
estimated. Facilities would also submit an explanation for any
significant change in emission rate. Examples could include
installation of new melt protection technology that would account for
reduced emissions in any given year, or occurrence or repair of leaks
in the cover gas delivery system.
These non-emissions data need to be reported because they are
needed to understand the nature of the facilities for which data are
being reported and for verifying the reasonableness of the reported
data.
6. Selection of Records That Must Be Retained
We are proposing that magnesium producers and processors be
required to keep records documenting adherence to the QA/QC
requirements specified in the proposed rule. These records would
include: Check-out and weigh-in sheets and procedures for cylinders;
accuracy certifications and calibration records for scales; residual
gas amounts in cylinders sent back to suppliers; and invoices for gas
purchases and sales.
These records are being specified because they are the values that
are used to calculate the GHG emissions that are reported. They are
necessary to verify that the GHG emissions monitoring and calculations
were done correctly and accurately.
U. Miscellaneous Uses of Carbonates
1. Definition of the Source Category
Limestone (CaCO3), dolomite
(CaMg(CO3)2) and other carbonates are inputs used
in a number of industries. The most common applications of limestone
are used as a construction aggregate (78 percent of specified national
consumption in 2006), the chemical and metallurgy industries (18
percent), and other specialized applications (three percent). The
breakdown of reported specified dolomite national consumption was
similar to that of limestone, with the majority being used as a
construction aggregate, and a lesser but still significant percent used
in chemical and metallurgical applications.
For some of these applications, the carbonates undergo a
calcination process in which the carbonate is sufficiently heated,
generating CO2 as a by-product. Examples of such emissive
applications include limestone used as a flux or purifier in
metallurgical furnaces, as a sorbent in flue gas desulfurization
systems for utility and industrial plants, and as a raw material in the
production of mineral wool or magnesium. Non-emissive applications
include limestone used in producing poultry grit and asphalt filler.
The use of limestone, dolomite and other carbonates is purely an
industrial process source of emissions. Emissions from the use of
carbonates in the manufacture of cement, ferroalloys, glass, iron and
steel, lead, lime, pulp and paper, and zinc are elaborated in proposed
40 CFR part 98, subparts H, K, N, Q, R, S, AA and GG, since they are
relatively significant emitters. Facilities that include only these
source categories would not need to follow the methods presented in
this section to estimate emissions from the miscellaneous use of
carbonates. The methods presented in this section should be used by
facilities that use carbonates in source categories other than those
listed above, but which are covered by the proposed rule.
As estimated in the U.S. GHG Inventory, national process emissions
from other limestone and dolomite uses (i.e., excluding cement, lime,
and glass manufacturing) were 7.9 million metric tons CO2e
in 2006 (0.1 percent of U.S. emissions). CH4 and
N2O are not released from the calcination of carbonates.
For additional background information on the use of limestone,
dolomite and other carbonates, please refer to the Miscellaneous Uses
of Carbonates TSD (EPA-HQ-OAR-2008-0508-021).
2. Selection of Reporting Threshold
A separate threshold analysis is not proposed for uses of
limestone, dolomite and other carbonates as these emissions occur in a
large number of facilities across a range of industries. We propose
that facilities with source categories identified in proposed 40 CFR
98.2(a)(1) or (a)(2) consuming limestone, dolomite and other carbonates
calculate the relevant emissions from their facility, including
emissions from calcination of carbonates, to determine whether they
surpass the proposed threshold for that industry. Data were not
available to quantify emissions from the calcination of carbonates
across all industries; therefore, these emissions were considered where
appropriate in the thresholds analysis for the respective industries.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from the use of limestone, dolomite and other carbonates
(e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), the EU
Emissions Trading System, and the Australian National Greenhouse Gas
Reporting Program). These methodologies all rely on measuring the
consumption of carbonate inputs, but differ in their use of default
values. The range of default values reflect differing assumptions of
the carbonate weight fraction in process inputs; for example, the 2006
IPCC Guidelines Tier 1 and 2 assume that carbonate inputs are 95
percent pure (i.e., 95 percent of the mass consumed is carbonate),
whereas the Australian Program assumes a default purity of 90 percent
for limestone, 95 percent for dolomite, and 100 percent for magnesium
carbonate.
We propose that facilities estimate process emissions by measuring
the type and quantity of carbonate input to a kiln or furnace and
applying the appropriate emissions factors for the carbonates consumed.
In order to assess the composition of the carbonate input, we propose
that facilities send samples of each carbonate consumed to an off-site
laboratory for a chemical analysis of
[[Page 16527]]
the carbonate weight fraction on an annual basis. Emission factors are
based on stoichiometry and are presented in Table U-1 of this preamble.
You would also be required to determine the calcination fraction for
each of the carbonate-based minerals consumed, using an appropriate
test method. The calcination fraction is the fraction of carbonate that
is volatilized in the process. A calcination fraction of 1.0 could over
estimate CO2 emissions. You would refer to proposed 40 CFR
part 98, subpart C specifically for procedures to estimate combustion-
related CO2, CH4 and N2O emissions.
Table U-1. CO2 Emission Factors for Common Carbonates
------------------------------------------------------------------------
CO2 emission
factor
(metric tons
Mineral name--carbonate ons CO2/metric
tons on
carbonate)
------------------------------------------------------------------------
Limestone--CaCO3........................................ 0.43971
Magnesite--MgCO3........................................ 0.52197
Dolomite--CaMg(CO3)2.................................... 0.47732
Siderite--FeCO3......................................... 0.37987
Ankerite--Ca(Fe,Mg,Mn)(CO3)2............................ * 0.44197
Rhodochrosite--MnCO3.................................... 0.38286
Sodium Carbonate/Soda Ash--Na2CO3....................... 0.41492
------------------------------------------------------------------------
* This is an average of the range provided by the 2006 IPCC Guidelines.
We also considered but decided not to propose simplified methods
(similar to IPCC Tier 1 and 2) for quantifying process-related
emissions from this source, which assumes that limestone and dolomite
are the only carbonates consumed, and allow for the use of default
fractions of the two carbonates (85 percent for limestone and 15
percent for dolomite). Default factors do not account for variability
in relative carbonate consumption by other sources and therefore
inaccurately estimate emissions.
The various approaches to monitoring GHG emissions are elaborated
in the Miscellaneous Uses of Carbonates TSD (EPA-HQ-OAR-2008-0508-021).
4. Selection of Procedures for Estimating Missing Data
We propose that 100 percent data availability is required. If
chemical analysis on the fraction calcination of carbonates consumed
were lost or missing, the analysis would have to be repeated. It is
assumed that a facility would be able to supply facility-specific
carbonate consumption data. The likelihood for missing data is low, as
businesses closely track production inputs.
5. Selection of Data Reporting Requirements
We propose that facilities report annual CO2 emissions
from carbonate consumption. In addition, we are proposing that
facilities submit the following data which are the basis of the
emission calculation and are needed for us to understand the emissions
data and assess the reasonableness of the reported emissions: annual
carbonate consumption (in metric tons, by carbonate) and the total
fraction of calcination achieved (for each carbonate). A full list of
data to be reported is included in proposed 40 CFR part 98, subparts A
and U.
6. Selection of Records That Must Be Retained
We propose that facilities retain records on monthly carbonate
consumption (by type), annual records on the fraction of calcination
achieved (by carbonate type), and results of the annual chemical
analysis. These records provide values that are directly used to
calculate the emissions that are reported and are necessary to allow
determination of whether the GHG emissions monitoring and calculations
were done correctly. A full list of records that must be retained
onsite is included in proposed 40 CFR part 98, subparts A and U.
V. Nitric Acid Production
1. Definition of the Source Category
Nitric acid is an inorganic chemical that is used in the
manufacture of nitrogen-based fertilizers, adipic acid, and explosives.
Nitric acid is also used for metal etching and processing of ferrous
metals. A nitric acid production facility uses oxidation, condensation,
and absorption to produce a weak nitric acid (30 to 70 percent in
strength). The production process begins with the stepwise catalytic
oxidation of ammonia (NH3) through nitric oxide (NO) to
nitrogen dioxide (NO2) at high temperatures. Then the
NO2 is absorbed in and reacted with water (H2O)
to form nitric acid (HNO3).
According to a facility-level inventory for 2006, there are 45
nitric acid production facilities operating in 25 States with a total
of 65 process lines. These facilities represent the best available data
at the time of this rulemaking. Using the facility-level inventory,
production levels for 2006 have been estimated at 6.6 million metric
tons of nitric acid and indicate an estimated 17.7 million metric tons
CO2e of process-related emissions (this represents the
CO2 equivalent of N2O emissions, which is the
primary process-related GHG). Nitric Acid process emissions were
estimated in the U.S. GHG Inventory at 15.4 million metric tons
CO2e in 2006 or 0.2 percent of total U.S. GHG emissions. The
main reason for the difference in estimates is that the methodology of
the U.S. Inventory assumed 20 percent of the nitric acid facilities
were using nonselective catalytic reduction as an N2O
abatement technology. The facility-level analysis showed that only five
percent of the nitric acid facilities are using nonselective catalytic
reduction.
Stationary combustion emissions were not estimated at the source
category level in the U.S. GHG Inventory. Stationary combustion
emissions at nitric acid facilities may be associated with other
chemical production processes as well (such as adipic acid production,
phosphoric acid production, or ammonia manufacturing).
For additional background information on nitric acid production,
please refer to the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-
022).
2. Selection of Reporting Threshold
In developing the proposed threshold for nitric acid production, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e. Table V-1 of
this preamble illustrates the emissions and facilities that would be
covered under these various thresholds.
Table V-1. Threshold Analysis for Nitric Acid Production
----------------------------------------------------------------------------------------------------------------
Process N2O emissions covered Facilities covered
(metric tons CO2e/yr) --------------------------------
N2O emission threshold (metric tons CO2e) --------------------------------
Number Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................................... 17,731,650 100 45 100
10,000......................................... 17,723,576 99.9 44 97.8
[[Page 16528]]
25,000......................................... 17,706,259 99.9 43 95.6
100,000........................................ 17,511,444 98.8 40 88.9
----------------------------------------------------------------------------------------------------------------
We are proposing all nitric acid facilities report in order to
simplify the rule and avoid the need for each facility to calculate and
report whether it exceeds the threshold value. Facility-level emissions
estimates based on plant production suggests that all known facilities,
except two, exceed the 25,000 metric tons CO2e threshold.
When facility-level production data were not known, capacity data were
used along with a utilization factor of 70 percent. The utilization
factor is based on total 2006 nitric acid production from the U.S.
Census Bureau and capacity estimates from publicly available sources.
This analysis, however, only took into account process-related
emissions, as combustion-related emissions were not available. Had
combustion-related emissions been included, it is probable that
additional facilities would have been covered at each threshold. An
``all in'' threshold captures 100 percent of emissions without
significantly increasing the number of facilities required to report.
Finally, the cost of reporting using the proposed monitoring method
does not vary significantly between the four different emissions based
thresholds.
For a full discussion of the threshold analysis, please refer to
the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating these emissions (e.g.
2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), TCR, and EPA
NSPS). These methodologies coalesce around the five options discussed
below.
Option 1. Apply default emission factors to total facility
production of nitric acid using the Tier 1 approach established by the
IPCC. The emissions are calculated using the total production of nitric
acid and the highest international default emission factor available in
the 2006 IPCC Guidelines, based on technology type. It also assumes no
abatement of N2O emissions.
Option 2. Apply default emission factors on a site-specific basis
using the Tier 2 approach established by the IPCC. This approach is
also consistent with the DOE 1605(b) ``B'' rated approach. These
emission factors are dependent on the type of nitric acid process used,
the type of abatement technology used, and the production activity. The
process-related N2O emissions are then estimated by
multiplying the emission factor by the production level of nitric acid
(on a 100 percent acid basis).
Option 3. Follow the Tier 3 approach established by IPCC using
periodic direct monitoring of N2O emissions to determine the
relationship between nitric acid production and the amount of
N2O emissions; i.e., develop a site-specific emissions
factor. The site-specific emission factor would be determined from an
annual measurement or a single annual stack test. The site-specific
emissions factor developed from this test and production rate (activity
level) is used to calculate N2O emissions. After the initial
test, annual testing of N2O emissions would be required each
year to estimate the emission factor and applied to production to
estimate emissions. The yearly testing would assist in verifying the
emission factor. Testing would also be required whenever the production
rate is changed by more than 10 percent from the production rate
measured during the most recent performance test.
Option 4. Follow the approach used by the Nitric Acid NSPS (40 CFR
part 60, subpart G). This option would require monitoring
NOX emissions on a continuous basis and measuring
N2O emissions to establish a site-specific emission factor
that relates NOX emissions to N2O emissions. The
emission factor would then be used to estimate N2O emissions
based on continuous reading of NOX emissions. Periodic
measurement would also be required to verify the emission factor over
time. Testing would also be required whenever the production rate is
changed by more than 10 percent from the production rate measured
during the most recent performance test.
Option 5. Follow the Tier 3 approach established by IPCC using
continuous monitoring. Use CEMS to directly measure N2O
concentration and flow rate to directly determine N2O
emissions. CEMS that measure N2O emissions directly are
available, but the nitric acid industry is currently using only
NOX CEMS.
Proposed Option. We are proposing Option 3 to quantify
N2O process emissions from all nitric acid facilities. You
would be required to follow the requirements in proposed 40 CFR part
98, subpart C to estimate emissions of CO2, CH4
and N2O from stationary combustion. We identified Options 3,
4, and 5 as the approaches providing the highest certainty and the best
site-specific estimates. These three options span the range of types of
methodologies currently used that do not apply default values. These
options all use site-specific approaches that would provide insight
into different levels of emissions caused by site-specific differences
in process operation and abatement technologies. Option 3 requires an
annual test of N2O emissions and the establishment of a
site-specific emissions factor that relates N2O emissions
with the nitric acid production rate.
Options 4 and 5 are similar in that both use continuous monitoring
to calculate N2O emissions. Option 5 directly measures the
N2O emissions. Option 4 uses continuous measurement of
NOX emissions to estimate a site-specific emission factor
that relates NOX emissions to N2O emissions. The
emission factor is then used to estimate N2O emissions based
on continuous readings of NOX emissions.
Option 5 would provide the highest certainty of the three options
and capture the smallest changes in N2O emissions over time,
but N2O CEMS are not currently in use in the industry and
there is no existing EPA method for certifying N2O CEMS.
Option 3 and Option 4 use site-specific emission factors so the margin
of error is much lower than using default emission factors. Option 4
would require the use of NOX CEMS that are already in use by
[[Page 16529]]
many nitric acid facilities to automatically capture and record any
changes in NOX emissions over time. However, NOX
CEMS only capture emissions of NO and NO2 and not
N2O. Therefore they would not be useful in the estimation of
N2O emissions from nitric acid production facilities.
Although the amount of NOX and N2O emissions from
nitric acid production may be directly related, direct measurement of
NOX does not automatically correlate to the amount of
N2O in the same exhaust stream. Periodic testing of
N2O emissions (Option 3) would not indicate changes in
emissions over short periods of time, but does offer direct measurement
of the GHG.
We request comment, along with supporting documentation, on the
advantages and disadvantages of using Options 3, 4 and 5. After
consideration of public comments, EPA may promulgate one or more of
these options or a combination based on the additional information that
is provided.
We decided not to propose Options 1 and 2 because the use of
default values and lack of direct measurements results in a high level
of uncertainty. Although different default emissions factors have been
developed for different processes (e.g., low pressure, high pressure)
and abatement techniques, the use of these default values is more
appropriate for sector wide or national total estimates than for
determining emissions from a specific facility. Site-specific emission
factors are more appropriate for reflecting differences in process
design and operation.
The various approaches to monitoring GHG emissions are elaborated
in the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022).
4. Selection of Procedures for Estimating Missing Data
For process sources that use a site-specific emission factor, no
missing data procedures would apply because the site-specific emission
factor is derived from an annual performance test and used in each
calculation. The emission factor would be multiplied by the production
rate, which is readily available. If the test data is missing or lost,
the test would have to be repeated. Therefore, 100 percent data
availability would be required.
5. Selection of Data Reporting Requirements
We propose that facilities report annual N2O emissions
(in metric tons) from each nitric acid production line. In addition, we
propose that facilities submit the following data to understand the
emissions data and verify the reasonableness of the reported emissions.
The data should include annual nitric acid production capacity, annual
nitric acid production, type of nitric acid production process used,
number of operating hours in the calendar year, the emission rate
factor used, abatement technology used (if applicable), abatement
technology efficiency, and abatement utilization factor.
Capacity, actual production, and operating hours would be helpful
in determining the potential for growth in the nitric acid industry.
The production rate can be determined through sales records or by
direct measurement using flow meters or weigh scales. This industry
generally measures the production rate as part of normal operating
procedures.
A list of abatement technologies would be helpful in assessing how
widespread the use of abatement is in the nitric acid source category,
cataloging any new technologies that are being used, and documenting
the amount of time that the abatement technologies are being used.
A full list of data to be reported is included in proposed 40 CFR
part 98, subparts A and V.
6. Selection of Records That Must Be Retained
We propose that facilities maintain records of significant changes
to process, N2O abatement technology used, abatement
technology efficiency, abatement utilization factor (percent of time
that abatement system is operating), annual testing of N2O
emissions, calculation of the site-specific emission rate factor, and
annual production of nitric acid.
A full list of records that must be retained onsite is included in
proposed 40 CFR part 98, subparts A and V.
W. Oil and Natural Gas Systems
1. Definition of the Source Category
The U.S. petroleum and natural gas industry encompasses hundreds of
thousands of wells, hundreds of processing facilities, and over a
million miles of transmission and distribution pipelines. This section
of the preamble identifies relevant facilities and outlines methods and
procedures for calculating and reporting fugitive emissions (as defined
in this section) of CH4 and CO2 from the
petroleum and natural gas industry. Methods and reporting procedures
for emissions resulting from natural gas or crude oil combustion in
prime movers such as compressors are covered under Section V.C of this
preamble.
The natural gas segment involves production, processing,
transmission and storage, and distribution of natural gas. The U.S.
also receives, stores, and processes imported liquefied natural gas
(LNG) at LNG import terminals. The petroleum segment involves crude oil
production, transportation and refining.
The relevant facilities covered in this section are offshore
petroleum and natural gas production facilities, onshore natural gas
processing facilities (including gathering/boosting stations), onshore
natural gas transmission compression facilities, onshore natural gas
storage facilities, LNG storage facilities, and LNG import facilities.
Fugitive emissions from petroleum refineries are proposed for inclusion
in the rulemaking, but these emissions are addressed in the petroleum
refinery section (Section V.Y) of this preamble. Under this section of
the preamble, we seek comment on methods for reporting fugitive
emissions data from: On-shore petroleum and natural gas production and
natural gas distribution facilities.
For this rulemaking, fugitive emissions from the petroleum and
natural gas industry are defined as unintentional equipment emissions
and intentional or designed releases of CH4-and/or
CO2-containing natural gas or hydrocarbon gas (not including
combustion flue gas) from emissions sources including, but not limited
to, open ended lines, equipment connections or seals to the atmosphere.
In the context of this rule, fugitive emissions also mean
CO2 emissions resulting from combustion of natural gas in
flares. These emissions are hereafter collectively referred to as
``fugitive emissions'' or ``emissions''. We seek comment on the
proposed definition of fugitives, which is derived from the definition
of fugitive emissions outlined in the 2006 IPCC Guidelines for National
GHG Inventories, and is often used in the development of GHG
inventories. We acknowledge that there are multiple definitions for
fugitives, for example, defining the term fugitives to include ``those
emissions which could not reasonably pass through a stack, chimney,
vent, or other functionally-equivalent opening''. According to the 2008
U.S. Inventory, total fugitive emissions of CH4 and
CO2 from the natural gas and petroleum industry were 160
metric tons CO2e in 2006. The breakdown of these fugitive
emissions is shown in Table W-1 of this preamble.
[[Page 16530]]
Table W-1. Fugitive Emissions From Petroleum and Natural Gas Systems
(2006)
------------------------------------------------------------------------
Fugitive Fugitive
Sector CH4 CO2
(MMTCO2e) (MMTCO2e)
------------------------------------------------------------------------
Natural Gas Systems\1\........................ 102.4 28.5
Petroleum Systems............................. 28.4 0.3
------------------------------------------------------------------------
\1\ Emissions account for Natural Gas STAR Partner Reported Reductions.
Natural gas system fugitive CH4 emissions resulted from
onshore and offshore natural gas production facilities (27 percent);
onshore natural gas processing facilities (12 percent); natural gas
transmission and underground natural gas storage, including LNG import
and LNG storage facilities (37 percent); and natural gas distribution
facilities (24 percent). Natural gas segment fugitive CO2
emissions were primarily from onshore natural gas processing facilities
(74 percent), followed by onshore and offshore natural gas production
facilities (25 percent), and less than 1 percent each from natural gas
transmission and underground natural gas storage and distribution
facilities.\80\
---------------------------------------------------------------------------
\80\ The distribution of CO2 emissions is slightly
misleading due to current U.S. Inventory convention which assumes
that all CO2 from natural gas processing facilities is
emitted. In fact, approximately 7,000 metric tons CO2e is
captured and used for EOR.
---------------------------------------------------------------------------
Petroleum segment fugitive CH4 emissions are primarily
associated with onshore and offshore crude oil production facilities
(>97 percent of emissions) and petroleum refineries (2 percent) and are
negligible in crude oil transportation facilities (<0.5 percent).
Petroleum segment fugitive CO2 emissions are only estimated
for onshore and offshore production facilities.
With over 160 different sources of fugitive CH4 and
CO2 emissions in the petroleum and natural gas industry,
identifying those sources most relevant for a reporting program was a
challenge. We developed a decision tree analysis and undertook a
systematic review of each emissions source category included in the
Inventory of U.S. GHG Emissions and Sinks. In determining the most
relevant fugitive emissions sources for inclusion in this reporting
program, we applied the following criteria: the coverage of fugitive
emissions for the source category as a whole, the coverage of fugitive
emissions per unit of the source category, feasibility of a viable
monitoring method, including direct measurement and engineering
estimations, and an administratively manageable number of reporting
facilities.
Another factor we considered in assessing the applicability of
certain petroleum and natural gas industry fugitive emissions in a
mandatory reporting program is the definition of a facility. In other
words, what physically constitutes a facility? This definition is
important to determine who the reporting entity would be, and to ensure
that delineation is clear and double counting of fugitive emissions is
minimized. For some segments of the industry, identifying the facility
is clear since there are physical boundaries and ownership structures
that lend themselves to identifying scope of reporting and responsible
reporting entities (e.g., onshore natural gas processing facilities,
natural gas transmission compression facilities, and offshore petroleum
and natural gas facilities). In other segments of the industry, such as
the pipelines between compressor stations, and more particularly
onshore petroleum and natural gas production, such distinctions are not
straightforward. In defining a facility, we reviewed current
definitions used in the CAA and ISO definitions, consulted with
industry, and reviewed current regulations relevant to the industry.
The full results of our assessment can be found in the Oil and Natural
Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).
Following is a brief discussion of the proposed selected and
excluded sources based on our analysis. Additional information can be
found in the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-
023). This section of the preamble addresses only fugitive emissions.
Combustion-related emissions are discussed in Section V.C of this
preamble.
Offshore Petroleum and Natural Gas Production Facilities. Offshore
petroleum and natural gas production includes both shallow and deep
water wells in both U.S. State and Federal waters. These offshore
facilities house equipment to extract hydrocarbons from the ocean floor
and transport it to storage or transport vessels or onshore. Fugitive
emissions result from sources housed on the platforms.
In 2006, offshore petroleum and natural gas production fugitive
CO2 and CH4 emissions accounted for 5.6 million
metric tons CO2e. The primary sources of fugitive emissions
from offshore petroleum and natural gas production are from valves,
flanges, open-ended lines, compressor seals, platform vent stacks, and
other source components. Flare stacks account for the majority of
fugitive CO2 emissions.
Offshore petroleum and natural gas production facilities are
proposed for inclusion due to the fact that this represents
approximately 4 percent of emissions from the petroleum and natural gas
industry, ``facilities'' are clearly defined, and major fugitive
emissions sources can be characterized by direct measurement or
engineering estimation.
Onshore Natural Gas Processing Facilities. Natural gas processing
includes gathering/ boosting stations that dehydrate and compress
natural gas to be sent to natural gas processing facilities, and
natural gas processing facilities that remove NGLs and various other
constituents from the raw natural gas. The resulting ``pipeline
quality'' natural gas is injected into transmission pipelines.
Compressors are used within gathering/ boosting stations and also
natural gas processing facilities to adequately pressurize the natural
gas so that it can pass through all of the processes into the
transmission pipeline.
Fugitive CH4 emissions from reciprocating and
centrifugal compressors, including centrifugal compressor wet and dry
seals, reciprocating compressor rod packing, and all other compressor
fugitive emissions, are the primary CH4 emission source from
this segment. The majority of fugitive CO2 emissions come
from acid gas removal vent stacks, which are designed to remove
CO2 and hydrogen sulfide, when present, from natural gas.
While these are the major fugitive emissions sources in natural gas
processing facilities, if other potential fugitive sources such as
flanges, open-ended lines and threaded fittings are present at your
facility you would need to account for them if reporting under proposed
40 CFR part 98, subpart W. For this subpart you would assume no capture
of CO2 because capture and
[[Page 16531]]
transfer of CO2 offsite would be calculated in accordance
with Section V.PP of this preamble and reported separately.
Onshore natural gas processing facilities are proposed for
inclusion due to the fact that these operations represent a significant
emissions source, approximately 25 percent of emissions from the
natural gas segment. ``Facilities'' are easily defined and major
fugitive emissions sources can be characterized by direct measurement
or engineering estimation.
Onshore Natural Gas Transmission Compression Facilities and
Underground Natural Gas Storage Facilities. Natural gas transmission
compression facilities move natural gas throughout the U.S. natural gas
transmission system. Natural gas is also injected and stored in
underground formations during periods of low demand (e.g., spring or
fall) and withdrawn, processed, and distributed during periods of high
demand (e.g., winter or summer). Storage compressor stations are
dedicated to gas injection and extraction at underground natural gas
storage facilities.
Fugitive CH4 emissions from reciprocating and
centrifugal compressors, including centrifugal compressor wet and dry
seals, reciprocating compressor rod packing, and all other compressor
fugitive emissions, are the primary CH4 emission source from
natural gas transmission compression stations and underground natural
gas storage facilities. Dehydrators are also a significant source of
fugitive CH4 emissions from underground natural gas storage
facilities. While these are the major fugitive emissions sources in
natural gas transmission, other potential fugitive sources include, but
are not limited to, condensate tanks, open-ended lines and valve seals.
Transmission compression facilities and underground natural gas
storage facilities are proposed for inclusion due to the fact that
these operations represent a significant emissions source,
approximately 24 percent of emissions from the natural gas segment;
``facilities'' are easily defined, and major fugitive sources can be
characterized by direct measurement or engineering estimation.
LNG Import and LNG Storage Facilities. The U.S. imports natural gas
in the form of LNG, which is received, stored, and, when needed,
processed and compressed at LNG import terminals. LNG storage
facilities liquefy and store natural gas from transmission pipelines
during periods of low demand (e.g., spring or fall) and vaporize for
send out during periods of high demand (e.g., summer and winter)
Fugitive CH4 and CO2 emissions from
reciprocating and centrifugal compressors, including centrifugal
compressor wet and dry seals, reciprocating compressor rod packing, and
all other compressor fugitive emissions, are the primary CH4
and CO2 emission source from LNG storage facilities and LNG
import facilities. Process units at these facilities can include
compressors to liquefy natural gas (at LNG storage facilities), re-
condensers, vaporization units, tanker unloading equipment (at LNG
import terminals), transportation pipelines, and/or pumps.
LNG storage facilities and LNG import facilities are proposed for
inclusion due to the fact that fugitive emissions from these operations
represent approximately 1 percent of emissions from natural gas
systems. LNG storage ``facilities'' are defined as facilities that
store liquefied natural gas in above ground storage tanks. LNG import
terminal ``facilities'' are defined as facilities that receive imported
LNG, store it in storage tanks, and release re-gasified natural gas for
transportation.
Onshore Petroleum and Natural Gas Production. Similar to offshore
petroleum and natural gas production, the onshore petroleum and natural
gas production segment uses wells to draw raw natural gas, crude oil,
and associated gas from underground formations. The most dominant
sources of fugitive CH4 and CO2 emissions
include, but are not limited to, natural gas driven pneumatic valve and
pump devices, field crude oil and condensate storage tanks, chemical
injection pumps, releases and flaring during well completion and
workovers, and releases and flaring of associated gas.
We considered proposing the reporting of fugitive CH4
and CO2 emissions from onshore petroleum and natural gas
production in the rule. Onshore petroleum and natural gas production is
responsible for the largest share of fugitive CH4 and
CO2 emissions from petroleum and natural gas industry (27
percent of total emissions). However, this segment is not proposed for
inclusion primarily due to the unique difficulty in defining a
``facility'' in this sector and correspondingly determining who would
be responsible for reporting.
Given the significance of fugitive emissions from the onshore
petroleum and natural gas production, we would like to take comment on
whether we should consider inclusion of this source category in the
future. Specifically, we would like to take comment on viable ways to
define a facility for onshore oil and gas production and to determine
the responsible reporter. In addition, the Agency also requests comment
on the merits and/or concerns with the corporate basin level reporting
approach under consideration for onshore oil and gas production, as
outlined below.
One approach we are considering for including onshore petroleum and
natural gas production fugitive emissions in this reporting rule is to
require corporations to report emissions from all onshore petroleum and
natural gas production assets at the basin level. In such a case, all
operators in a basin would have to report their fugitive emissions from
their operations at the basin-level. For such a basin-level facility
definition, we may propose reporting of only the major fugitive
emissions sources; i.e., natural gas driven pneumatic valve and pump
devices, well completion releases and flaring, well blowdowns, well
workovers, crude oil and condensate storage tanks, dehydrator vent
stacks, and reciprocating compressor rod packing. Under this scenario,
we might suggest that all operators would be subject to reporting,
perhaps exempting small businesses, as defined by the Small Business
Administration.
This approach could substantially reduce the reporting complexity
and require individual companies that produce crude oil and/or natural
gas in each basin to be responsible for reporting emissions from all of
their onshore petroleum and natural production operations in that
basin, including from rented sources, such as compressors. In cases
where hydrocarbons or emissions sources are jointly owned by more than
one company, each company would report emissions equivalent to its
portion of ownership.
We considered other options in defining a facility such as
individual wellheads or aggregating all emissions sources prior to
compression as a facility. However, such definitions result in complex
reporting requirements and are difficult to implement.
We are seeking comments on reporting of the major fugitive
emissions sources by corporations at the basin level for onshore
petroleum and natural gas production.
Petroleum and Natural Gas Pipeline Segments. Natural gas
transmission involves high pressure, large diameter pipelines that
transport gas long distances from field production and natural gas
processing facilities to natural gas distribution pipelines or large
volume customers such as power
[[Page 16532]]
plants or chemical plants. Crude oil transportation involves pump
stations to move crude oil through pipelines and loading and unloading
crude oil tanks, marine vessels, and rails.
The majority of fugitive emissions from the transportation of
natural gas occur at the compressor stations, which are already
proposed for inclusion in the rule and discussed above. We do not
propose to include reporting of fugitive emissions from natural gas
pipeline segments between compressor stations, or crude oil pipelines
in the rulemaking due to the dispersed nature of the fugitive
emissions, the difficulty in defining pipelines as a facility, and the
fact that once fugitives are found, they are generally fixed quickly,
not allowing time for monitoring and direct measurement of the
fugitives.
Natural Gas Distribution. In the natural gas distribution segment,
high-pressure gas from natural gas transmission pipelines enter ``city
gate'' stations, which reduce the pressure and distribute the gas
through primarily underground mains and service lines to individual end
users. Distribution system CH4 and CO2 emissions
result mainly from fugitive emissions from gate stations (metering and
regulating stations) and vaults (regulator stations), and fugitive
emissions from underground pipelines. At gate stations and vaults,
fugitive CH4 emissions primarily come from valves, open-
ended lines, connectors, and natural gas driven pneumatic valve
devices.
Although fugitive emissions from a single vault, gate station or
segment of pipeline in the natural gas distribution segment may not be
significant, collectively these fugitive emissions sources contribute a
significant share of fugitive emissions from natural gas systems.
We do not propose to include the natural gas distribution segment
of the natural gas industry in this rulemaking due to the dispersed
nature of the fugitive emissions and difficulty in defining a facility
such that there would be an administratively manageable number of
reporters.
One approach to address the concern with defining a facility for
distribution would be to require corporate-level reporting of fugitive
emissions from major sources by distribution companies. We seek comment
on this and other ways of reporting fugitive emissions from the
distribution sector.
Crude Oil Transportation. Crude oil is commonly transported by
barge, tanker, rail, truck, and pipeline from production operations and
import terminals to petroleum refineries or export terminals. Typical
equipment associated with these operations are storage tanks and
pumping stations. The major sources of CH4 and
CO2 fugitive emissions include releases from tanks and
marine vessel loading operations.
We do not propose to include the crude oil transportation segment
of the petroleum and natural gas industry in this rulemaking due to its
small contribution to total petroleum and natural gas fugitive
emissions, accounting for much less than 1 percent, and the difficulty
in defining a facility.
2. Selection of Reporting Threshold
We propose that facilities with emissions greater than 25,000
metric tons CO2e per year be subject to reporting. This
threshold is applicable to all oil and natural gas system facilities
covered by this subpart: Offshore petroleum and natural gas production
facilities, onshore natural gas processing facilities, including
gathering/boosting stations; natural gas transmission compression
facilities, underground natural gas storage facilities; LNG storage
facilities; and LNG import facilities.
To identify the most appropriate threshold level for reporting of
fugitive emissions, we conducted analyses to determine fugitive
emissions reporting coverage and facility reporting coverage at four
different levels of threshold; 1,000 metric tons CO2e per
year, 10,000 metric tons CO2e per year, 25,000 metric tons
CO2e per year, and 100,000 metric tons CO2e per
year. Table W-2 of this preamble provides coverage of emissions and
number of facilities reporting at each threshold level for all the
industry segments under consideration for this rule.
Table W-2. Threshold Analysis for Fugitive Emissions From the Petroleum and Natural Gas Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Total emissions covered Facilities covered
national by thresholds \s\ -------------------------
emissions Total number Threshold --------------------------
Source category #a (metric of facilities level (metric
tons CO2e tons CO2e Percent Number Percent
per year) per year)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Offshore Petroleum & Gas Production Facilities............ 10,162,179 2,525 1,000 9,783,496 96 1,021 40
10,000 6,773,885 67 156 6
25,000 5,138,076 51 50 2
100,000 3,136,185 31 4 0.5
Natural Gas Processing Facilities......................... 50,211,548 566 1,000 50,211,548 100 566 100
10,000 49,207,852 98 394 70
25,000 47,499,976 95 287 51
100,000 39,041,555 78 125 22
Natural Gas Transmission Compression Facilities........... 73,198,355 1,944 1,000 73,177,039 100 1,659 85
10,000 71,359,167 97 1311 67
25,000 63,835,288 87 874 45
100,000 30,200,243 41 216 11
Underground Natural Gas Storage Facilities................ 11,719,044 398 1,000 11,702,256 100 346 87
10,000 10,975,728 94 197 49
25,000 9,879,247 84 131 33
100,000 5,265,948 45 35 9
LNG Storage Facilities.................................... 1,956,435 157 1,000 1,940,203 99 54 34
10,000 1,860,314 95 39 25
25,000 1,670,427 85 29 18
100,000 637,477 33 3 2
LNG Import Facilities..................................... 1,896,626 5 1,000 1,896,626 100 5 100
[[Page 16533]]
10,000 1,895,153 99.9 4 80
25,000 1,895,153 99.9 4 80
100,000 1,895,153 99.9 4 80
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The emissions include fugitive CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the 2008 U.S.
Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For additional
discussion, refer to the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).
A proposed threshold of 25,000 metric tons CO2e applied
to only those emissions sources listed in Table W-2 of this preamble
captures approximately 81 percent of fugitive CH4 and
CO2 emissions from the entire oil and natural gas industry,
while capturing only a small fraction of total facilities. For
additional information, please refer to the Oil and Natural Gas Systems
TSD (EPA-HQ-OAR-2008-0508-023). For specific information on costs,
including unamortized first year capital expenditures, please refer to
section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating fugitive emissions from
oil and natural gas operations, including the 2006 IPCC Guidelines,
U.S. GHG Inventory, DOE 1605(b), and corporate industry protocols
developed by the American Petroleum Institute, the Interstate Natural
Gas Association of America, and the American Gas Association. The
methodologies proposed vary by the emissions source, for example
fugitive emissions versus vented emissions, versus emissions from
flares (all of which are considered ``fugitive'' emissions in this
rulemaking). Generally, approaches range from direct measurement (e.g.,
high volume samplers), to engineering equations (where applicable), to
simple emission factor approaches based on national default factors.
Proposed Option. We propose that facilities would be required to
detect fugitive emissions from the identified emissions sources
proposed in this rulemaking, and then quantify emissions using either
engineering equations or direct measurement.
Fugitive emissions from all affected emissions sources at the
facility, whether in operating condition or on standby, would have to
be monitored on an annual basis. The proposed monitoring method would
depend on the fugitive emissions sources in the facility to be
monitored. Each fugitive emissions source would be required to be
monitored using one of the two monitoring methods: (1) Direct
measurement or (2) engineering estimation. Table W-3 of this preamble
provides the proposed fugitive emissions source and corresponding
monitoring methods. General guidance on the monitoring methods is given
below.
Table W-3. Source Specific Monitoring Methods and Emissions
Quantification
------------------------------------------------------------------------
Emissions
Emission source Monitoring method quantification
type methods
------------------------------------------------------------------------
Acid Gas Removal Vent Stacks Engineering Simulation software.
estimation.
Blowdown Vent Stacks........ Engineering Gas law and
estimation. temperature,
pressure, and
volume between
isolation valves.
Centrifugal Compressor Dry Direct measurement.. (1) High volume
Seals. sampler, or (2)
Calibrated bag, or
(3) Meter.
Centrifugal Compressor Wet Direct measurement.. (1) High volume
Seals. sampler, or (2)
Calibrated bag, or
(3) Meter.
Compressor Fugitive Direct measurement.. (1) High volume
Emissions. sampler, or (2)
Calibrated bag, or
(3) Meter.
Dehydrator Vent Stacks...... Engineering Simulation software.
estimation.
Flare Stacks................ Engineering Velocity meter and
estimation and mass/volume
direct measurement. equations.
Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer
Pumps. estimation, or (2) data, equipment
Direct measurement. counts, and amount
of chemical pumped,
or (2) Calibrated
bag.
Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer
Manual Valve Actuator estimation, or (2) data and actuation
Devices. Direct measurement. logs, or (2)
Calibrated bag.
Natural Gas Driven Pneumatic (1) Engineering (1) Manufacturer
Valve Bleed Devices. estimation, or (2) data and equipment
Direct measurement. counts, or (2) High
volume sampler, or
(3) Calibrated bag,
or (4) Meter.
Non-pneumatic Pumps......... Direct measurement.. High volume sampler.
Offshore Platform Pipeline Direct measurement.. High volume sampler.
Fugitive Emissions.
Open-ended Lines............ Direct measurement.. (1) High volume
sampler, or (2)
Calibrated bag, or
(3) Meter.
Pump Seals.................. Direct measurement.. (1) High volume
sampler, or (2)
Calibrated bag, or
(3) Meter.
Facility Fugitive Emissions. Direct measurement.. High volume sampler.
[[Page 16534]]
Reciprocating Compressor Rod Direct measurement.. (1) High volume
Packing. sampler, or (2)
Calibrated bag, or
(3) Meter.
Storage Tanks............... (1) Engineering (1) Meter, or (2)
estimation and Simulation
direct measurement, software, or (3)
or (2) Engineering Vasquez-Beggs
estimation. Equation.
------------------------------------------------------------------------
a. Direct Measurement
Fugitive emissions detection and measurement are both required in
cases where direct measurement is being proposed. Infrared fugitive
emissions detection instruments are capable of detecting fugitive
CH4 emissions, or Toxic Vapor Analyzers or Organic Vapor
Analyzers can be used by the operator to detect fugitive natural gas
emissions. These instruments detect the presence of hydrocarbons in the
natural gas fugitive emissions stream. They do not detect any pure
CO2 fugitive emissions. However, because all the sources
proposed for monitoring have natural gas fugitive emissions that have
CH4 as one of its constituents, there is no need for a
separate detection instrument for separately detecting CO2
fugitive emissions. The only exception to this is fugitive emissions
from acid gas removal vent stacks where the predominant constituent of
the fugitive emissions is CO2. Engineering estimation is
proposed for this source, and therefore there is no need for detection
of fugitive emissions from acid gas removal vent stacks.
In the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023),
we describe a particular method based on practicality of application.
For example, using Toxic Vapor Analyzers or Organic Vapor Analyzers on
very large facilities is not as cost effective as infrared fugitive
emissions detection instruments. We propose that irrespective of the
method used for fugitive natural gas emissions detection, the survey
for detection must be comprehensive. This means that, on an annual
basis, the entire population of emissions sources proposed for fugitive
emissions reporting has to be surveyed at least once. When selecting
the appropriate emissions detection instrument, it is important to note
that certain instruments are best suited for particular applications
and circumstances. For example, some optical infrared fugitive
emissions detection instruments may not perform well in certain weather
conditions or with certain colored backgrounds.
Infrared fugitive emissions detection instruments are able to scan
hundreds of source components at once, allowing for efficient detection
of emissions at large facilities; however, infrared fugitive emissions
detection instruments are typically much more expensive than other
options. Organic Vapor Analyzers and Toxic Vapor Analyzers are not able
to detect fugitive emissions from many components as quickly; however,
for small facilities this may provide a less costly alternative to
infrared fugitive emissions detection without requiring overly
burdensome labor to perform a comprehensive fugitive emissions survey.
We propose that operators choose the instrument from the choices
provided in the proposed rule that is best suited for their
circumstance. Further information is contained in the Oil and Natural
Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).
For direct measurement, we have proposed that high volume samplers,
meters (such as rotameters, turbine meters, hot wire anemometers, and
others), and/or calibrated bags be designated for use. However, if
fugitive emissions exceed the maximum range of the proposed monitoring
instrument, you would be required to use a different instrument option
that can measure larger magnitude emissions levels. For example, if a
high volume sampler is pegged by a fugitive emissions source, then
fugitive emissions would be required to be directly measured using
either calibrated bagging or a meter. In the Oil and Natural Gas
Systems TSD (EPA-HQ-OAR-2008-0508-023), we discuss multiple options for
measurement where the range of emissions measurement instruments is
seen as an issue. CH4 and CO2 fugitive emissions
from the natural gas fugitive emissions stream can be calculated using
the composition of natural gas.
b. Engineering Estimation
Engineering estimation has been proposed for calculating
CH4 and CO2 fugitive emissions from sources where
the variable in the emissions magnitude on an annual basis is the
number of times the source releases fugitive CH4 and
CO2 emissions to the atmosphere. For example, when a
compressor is taken offline for maintenance, the volume of fugitive
CH4 and CO2 emissions that are released is the
same during each release and the only variable is the number of times
the compressor is taken offline. Also, engineering estimates have been
proposed where safety concerns prohibit the use of direct measurement
methods. For example, sometimes the temperature of the fugitive
emissions stream for glycol dehydrator vent stacks is too high for
operators to safely measure fugitive emissions. Based on these
principles, we propose that direct measurement is mandatory unless
there is a demonstrated and documented safety concern or frequency of
fugitive emission releases is the only variable in emissions, at which
time engineering estimates can be applied.
c. Alternative Monitoring Methods Considered
Before proposing the monitoring methods discussed above, we
considered four additional measurement methods. The use of Method 21 or
the use of activity and emission factors were considered for fugitive
emissions detection and measurement. Although Toxic Vapor Analyzers and
Organic Vapor Analyzers were considered but not proposed for fugitive
emissions direct measurement they are acceptable for fugitive emissions
detection.
Method 21. This is the reference method for equipment leak
detection and repair regulations for volatile organic carbon (VOC)
emissions under several 40 CFR part 60 emission standards. Method 21 of
40 CFR part 60 Appendix A-7 determines a concentration at a point or
points of emissions expressed in parts per million concentration of
combustible hydrocarbon in the air stream of the instrument probe. This
concentration is then compared to the ``action level'' in the
referenced 40 CFR part 60 regulation to determine if a leak is present.
Although Method 21 was not developed for this purpose, it may allow for
better emission estimation than the overall average emission factors
that have been published for equipment leaks. Quantification of air
emissions from equipment leaks is generally done using EPA published
guidelines which correlate the measured concentration to a VOC mass
emission rate based on extensive measurements of air emissions from
leaking equipment. The
[[Page 16535]]
correlations are statistically determined for a very large population
of similar components, but not very accurate for single leaks or small
populations. Therefore, Method 21 was not found suitable for fugitive
emissions measurement under this reporting rule. However, we are
seeking comments on this conclusion, and whether Method 21 should be
permitted as a viable alternative method to estimate emissions for
sources where it is currently required for VOC emissions.
Activity Factor and Emissions Factor for All Sources. Fugitive
CH4 emissions factors for all of the fugitive emissions
sources proposed for inclusion in the rule are available in a study
that was conducted in 1992.81 82 There have been no
subsequent comparable studies published to replace or revise the
fugitive emissions estimates available from this study. However, some
petroleum and natural gas industry operations have changed
significantly with the introduction of new technologies and improved
operating and maintenance practices to mitigate fugitive emissions.
These are not reflected in the fugitive emissions factors available.
Also, in many cases the fugitive emissions factors are not
representative of emission levels for individual sources or are not
relevant to certain operations because the estimates were based on
limited or no field data. Hence, they are not representative of the
entire country or specific petroleum and natural gas facilities and
fugitive emissions sources such as tanks and wells. Therefore, we did
not propose this method for estimation of the fugitive emissions for
reporting.
---------------------------------------------------------------------------
\81\ EPA/GRI (1996) Methane Emissions from the Natural Gas
Industry. Harrison, M., T. Shires, J. Wessels, and R. Cowgill,
(eds.). Radian International LLC for National Risk Management
Research Laboratory, Air Pollution Prevention and Control Division,
Research Triangle Park, NC. EPA-600/R-96-080a.
\82\ EPA (1999) Estimates of Methane Emissions from the U.S. Oil
Industry (Draft Report). Prepared by ICF International. Office of
Air and Radiation, U.S. Environmental Protection Agency. October
1999.
---------------------------------------------------------------------------
Default fugitive CO2 emissions factors are available
only for whole segments of the industry (e.g., natural gas processing),
and are not available for individual sources. Further, these are
international default factors, which have a high uncertainty associated
with them and are not appropriate for facility-level reporting.
Mass Balance for Quantification. We considered, but decided not to
propose, the use of a mass balance approach for quantifying emissions.
This approach would take into account the volume of gas entering a
facility and the amount exiting the facility, with the difference
assumed to be emitted to the atmosphere. This is most often discussed
for emissions estimation from the transportation segment of the
industry. For transportation, the mass balance is often not recommended
because of the uncertainties surrounding meter readings and the large
volumes of throughput relative to fugitive emissions. We are seeking
feedback on the use of a mass balance approach and the applicability to
each sector of the oil and gas industry (production, processing,
transmission, and distribution) as a potential alternative to component
level leak detection and quantification.
Toxic Vapor Analyzers and Organic Vapor Analyzers for Emissions
Measurement. Toxic Vapor Analyzer and Organic Vapor Analyzer
instruments quantify the concentration of combustible hydrocarbon from
the fugitive emission in the air stream, but do not directly quantify
the volumetric or mass emissions. The instrument probe rarely ingests
all of the natural gas from a fugitive emissions source. Therefore,
these instruments are used primarily for fugitive emissions leak
detection. For the proposed rule, fugitive CH4 emissions
detection by more cost-effective detection technologies such as
infrared fugitive emissions detection instruments in conjunction with
direct measurement methodologies such as the high volume sampler,
meters and calibrated bags is deemed a better overall approach to
fugitive emissions quantification than the labor intensive Organic
Vapor Analyzers and Toxic Vapor Analyzers, which do not quantify
volumetric or mass fugitive emissions.
d. Outstanding Issues on Which We Seek Comments
The proposed rule does not indicate a particular threshold for
detection above which emissions measurement is required. This is
because the different emissions detection instruments proposed have
different levels and types of detection capabilities. Hence the
magnitude of actual emissions can only be determined after measurement.
This, however, does not serve the purpose of this rule in limiting
burden on emissions reporting. A facility can have hundreds of small
emissions (as low as 3 grams per hour) and it might not be practical to
measure all such small emissions for reporting.
To address this issue we intend to incorporate one of the following
two approaches in the final rule.
The first approach would provide performance standards for fugitive
emissions detection instruments and usage such that all instruments
follow a common minimum detection threshold. We may propose the use of
the Alternate Work Practice to Detect Leaks from Equipment standards
for infrared fugitive emissions detection instruments being developed
by EPA. In such a case all detected emissions from components subject
to this rule would require measurement and reporting.
The second approach would provide an emissions threshold above
which the source would be identified as an ``emitter'' for emissions
detection using Organic Vapor Analyzers or Toxic Vapor Analyzers. When
using infrared fugitive emissions detection instruments all sources
subject to this rule that have emissions detected would require
emissions quantification. Alternatively, the operator would be given a
choice of first detecting emissions sources using the infrared
detection instrument and then verifying for measurement status using
the emissions definition for Organic Vapor Analyzers or Toxic Vapor
Analyzers.
We are seeking comments on using the two options discussed above
for determining emission sources requiring measurement of emissions.
Some fugitive emissions by nature occur randomly within the
facility. Therefore, there is no way of knowing when a particular
source started emitting. This proposed rule requires annual fugitive
emissions detection and measurement. The emissions detected and
measured would be assumed to continue throughout the reporting year,
unless no emissions detection is recorded at an earlier and/or later
point in the reporting period. We recognize that this may not
necessarily be true in all cases and that emissions reported would be
higher than actual. Therefore, we are seeking comments on how this
issue can be resolved without resulting in additional reporting burden
to the facilities.
The petroleum and natural gas industry is already implementing
voluntary fugitive emissions detection and repair programs. Such
voluntary programs are useful, but pose an accounting challenge with
respect to emissions reporting for this rule. The proposed rule
requires annual detection and measurement of fugitive emissions. This
approach does not preclude any facility from performing emissions
detection and repair prior to the official detection, measurement, and
reporting of emissions for this rule. We are seeking comments on how to
avoid under-reporting of emissions as a result of a preliminary, ``un-
official'' emissions
[[Page 16536]]
survey and repair exercise ahead of the ``official'' annual survey.
Fugitive emissions from a compressor are a function of the mode in
which the compressor is operating. Typically, a compressor station
consists of several compressors with one (or more) of them on standby
based on system redundancy requirements and peak delivery capacity.
Fugitive emissions at compressors in standby mode are significantly
different than those from compressors that are operating. The rule
proposes annual direct measurement of fugitive emissions. This may not
adequately account for the different modes in which a particular
compressor is operating through the reporting period. We are soliciting
input on a method to measure emissions from each mode in which the
compressor is operating, and the period of time operated in that mode,
that would minimize reporting burden. Specifically, given the
variability of these measured emissions, EPA requests comment on
whether engineering estimates or other alternative methods that account
for total emissions from compressors, including open ended lines, could
address this issue of operating versus standby mode.
The fugitive emissions measurement instruments (i.e. high volume
sampler, calibrated bags, and meters) proposed for this rule measure
natural gas emissions. CH4 and CO2 emissions are
required to be estimated from the natural gas mass emissions using
natural gas composition appropriate for each facility. For this
purpose, the proposed rule requires that facilities use existing gas
composition estimates to determine CH4 and CO2
components of the natural gas emissions (flare stack and storage tank
fugitive emissions are an exception to this general rule). We have
determined that these gas composition estimates are available from
facilities reporting to this rule. We are seeking comments on whether
this is a practical assumption. In the absence of gas composition, an
alternative proposal would be to require the periodic measurement of
the required gas composition for speciation of the natural gas mass
emissions into CH4 and CO2 mass emissions.
4. Selection of Procedures for Estimating Missing Data
The proposal requires data collection for a single source a minimum
of once a year. If data are lost or an error occurs during fugitive
emissions direct measurement, the operator should carry out the direct
measurement a second time to obtain the relevant data point(s).
Similarly, engineering estimates must account for relevant source
counts and frequency of fugitive emissions releases throughout the
year. There should not be any missing data for estimating fugitive
emissions from petroleum and natural gas systems.
5. Selection of Data Reporting Requirements
We propose that fugitive emissions from the petroleum and natural
gas industry be reported on an annual basis. The reporting should be at
a facility level with fugitive emissions being reported at the source
type level. Fugitive emissions from each source type could be reported
at an aggregated level. In other words, process unit-level reporting
would not be required. For example, a facility with multiple
reciprocating compressors could report fugitive emissions from all
reciprocating compressors as an aggregate number. Since the proposed
monitoring method is fugitive emissions detection and measurement at
the source level, we determined that reporting at an aggregate source
type level is feasible.
Fugitive emissions from all sources proposed for monitoring,
whether in operating condition or on standby, would have to be
reported. Any fugitive emissions resulting from standby sources would
be separately identified from the aggregate fugitive emissions.
The reporting facility would be required to report the following
information to us as a part of the annual fugitive emissions reporting:
fugitive emissions monitored at an aggregate source level for each
reporting facility, assuming no carbon capture and transfer offsite;
the quantity of CO2 captured for use and the end use, if
known; fugitive emissions from standby sources; and activity data for
each aggregate source type level.
Additional data are proposed to be reported to support
verification: Engineering estimate of total component count; total
number of compressors and average operating hours per year for
compressors, if applicable; minimum, maximum and average throughput per
year; specification of the type of any control device used, including
flares; and detection and measurement instruments used. For offshore
petroleum and natural gas production facilities, the number of
connected wells, and whether they are producing oil, gas, or both is
proposed to be reported. For compressors specifically, we proposed that
the total number of compressors and average operating hours per year be
reported.
A full list of data to be reported is included in proposed 40 CFR
part 98, subparts A and W.
6. Selection of Records That Must Be Retained
The reporting facility shall retain relevant information associated
with the monitoring and reporting of fugitive emissions to us, as
follows; throughput of the facility when the fugitive emissions direct
measurement was conducted, date(s) of measurement, detection and
measurement instruments used, if any, results of the leak detection
survey, and inputs and outputs to calculations or simulation software
runs where the proposed monitoring method requires engineering
estimation.
A full list of records to be retained is included inproposed 40 CFR
part 98, subparts A and W.
X. Petrochemical Production
1. Definition of the Source Category
The petrochemical industry consists of numerous processes that use
fossil fuel or petroleum refinery products as feedstocks. For this
proposed GHG reporting rule, the reporting of process-related emissions
in the petrochemical industry is limited to the production of
acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene
oxide, and methanol. The petrochemicals source category includes
production of all forms of carbon black (e.g., furnace black, thermal
black, acetylene black, and lamp black) because these processes use
petrochemical feedstocks; bone black is not considered to be a form of
carbon black because it is not produced from petrochemical feedstocks.
The rule focuses on these six processes because production of GHGs from
these processes has been recognized by the IPCC to be significant
compared to other petrochemical processes. Facilities producing other
types of petrochemicals are not subject to proposed 40 CFR part 98,
subpart X of this reporting rule but may be subject to 40 CFR part 98,
subpart C, General Stationary Fuel Combustion Sources, or other
subparts.
There are 88 facilities operating petrochemical processes in the
U.S., and 9 of these operate either two or three types of petrochemical
processes (e.g., ethylene and ethylene oxide). We estimate
petrochemical production accounts for approximately 55 million metric
tons CO2e.
Total GHG emissions relevant to the petrochemical industry
primarily include process-based emissions and emissions from combustion
sources. Process-based emissions may be released to the atmosphere from
process vents, equipment leaks, aerobic biological treatment systems,
and in some cases, combustion source vents. CH4 may also be
a process-based
[[Page 16537]]
emission from processes where CH4 is a feedstock (e.g., when
methanol is produced from synthesis gas that is derived from reforming
natural gas, some CH4 passes through the process without
being converted and is emitted).
Emissions from the burning of process off-gas to supply energy to
the process are also process-based emissions because the organic
compounds being burned are derived from the feedstock chemical. These
emissions are included with other process-based emissions if the mass
balance monitoring method (described in Section V.X.3 of this preamble)
is used to estimate process-based emissions, but they are included with
combustion source emissions if CEMS are used to measure emissions from
all stacks. Combustion source emissions include CO2,
CH4, and N2O emissions from combustion of either
supplemental fuel alone (under the mass balance option) or combustion
of both supplemental fuels and process off-gas (under the CEMS option).
This difference in approach for emissions from the combustion of off-
gas is necessary to avoid either double counting or not counting these
emissions, particularly if off-gas and supplemental fuel are mixed in a
fuel gas system.
CH4 emissions from onsite wastewater treatment systems
(if anaerobic) are another possible source of GHG emissions from the
petrochemical industry, but these emissions are expected to be small
because anaerobic wastewater treatment is not common at petrochemical
facilities. CH4 emissions from onsite wastewater treatment
systems would be estimated and reported according to the proposed
procedures in proposed 40 CFR part 98, subpart II.
The ratio of process-based emissions to supplemental fuel
combustion emissions varies among the various petrochemical processes.
For example, process-based emissions dominate for acrylonitrile,
ethylene, and ethylene oxide processes. Both process-based and
supplemental fuel combustion emissions are important for carbon black
and methanol processes. Emissions from supplemental fuel combustion
predominate for ethylene dichloride processes. Equipment leak and
wastewater emissions are both estimated to be less than 1 percent of
the total emissions from petrochemical production.
For further discussion see the Petrochemical Production TSD (EPA-
HQ-OAR-2008-0508-024).
2. Selection of Reporting Threshold
We propose that every facility which includes within its boundaries
methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride,
or carbon black production be subject to the requirements of this
proposed rule.
In developing the proposed threshold for petrochemical facilities,
we considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e. Table X-1 of
this preamble illustrates the emissions and number of facilities that
would be covered under the four threshold options.
Table X-1. Threshold Analysis for Petrochemical Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total National Emissions covered Facilities covered
Emissions, Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities Metric tons Number of
CO2e/yr CO2e/yr Percent facilities Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 54,830,000 88 54,830,000 100 88 100
10,000.................................................. 54,830,000 88 54,820,000 99.98 87 98.9
25,000.................................................. 54,830,000 88 54,820,000 99.98 87 98.9
100,000................................................. 54,830,000 88 54,440,000 99.7 84 95.5
--------------------------------------------------------------------------------------------------------------------------------------------------------
The emissions presented in Table X-1 of this preamble are the total
emissions associated solely with the production of methanol,
acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon
black, not the total emissions from petrochemical facilities. An
estimate of the total emissions was difficult to develop because many
of these facilities contain multiple source categories. For example,
some petrochemical operations occur at petroleum refineries. Other
petrochemical manufacturing facilities produce chemicals such as
ammonia or hydrogen that are also subject to reporting. In addition,
numerous chemical manufacturing facilities produce other chemicals in
addition to one or more of the petrochemicals; these facilities may
have combustion sources associated with these other chemical
manufacturing processes that are separate from the combustion sources
for petrochemical processes.
Based on this analysis, 87 of the 88 petrochemical facilities have
estimated combustion and process-based GHG emissions that exceed the
25,000 metric tons CO2e/yr threshold, and 1 facility has
estimated GHG emissions less than 10,000 metric tons CO2e/
yr. The facility with estimated GHG emissions less than 10,000 metric
tons CO2e/yr is a carbon black facility. Considering that
the threshold analysis did not include all types of emissions occurring
at petrochemical facilities, and the large percentage of facilities
that were above the various thresholds even when these emissions were
excluded, EPA proposes that all facilities producing at least one of
the petrochemicals report. This would simplify the rule and likely
achieve the same result as having a 25,000 metric tons CO2e
threshold.
For a full discussion of the threshold analysis, please refer to
the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
We reviewed existing domestic and international GHG monitoring
guidelines and protocols including the 2006 IPCC Guidelines and DOE
1605(b). Protocols included methods for both CO2 and
CH4. From this review, we developed the following three
options that share a number of features with the three Tiers presented
by IPCC:
Option 1. Apply default emission factors based on the type of
process and site-specific activity data (e.g., measured or estimated
annual production rate). This option is the same as the IPCC Tier 1
approach.
Option 2. Perform a carbon balance to estimate CO2
emissions derived from carbon in feedstocks. Inputs to the carbon
balance would be the flow and carbon content of each feedstock, and
outputs would be the flow and carbon content of each product/byproduct.
Organic liquid wastes that are collected for shipment offsite would
also be considered an output in the carbon
[[Page 16538]]
balance. The difference between carbon inputs and outputs is assumed to
be CO2 emissions. This includes all unconverted
CH4 feedstock that is emitted. In addition, all
CO2 that is recovered for sale or other use is considered an
emission for the purposes of reporting for petrochemical processes.
However, the volume of CO2 would be accounted for separately
using the procedures in proposed 40 CFR part 98, subpart PP.
This option would require continuous monitoring of liquid and
gaseous flows using flow meters, measurement of solid feedstock and
product flows using scales or other weighing devices, and determination
of the carbon content of each feedstock and product/byproduct at least
once per week. Supplemental fuel is not considered to be a feedstock
because these fuels do not mix with process fluids (except in the
furnace of a carbon black process) and would be calculated consistent
with the monitoring methods in proposed 40 CFR part 98, subpart C.
In addition to using the carbon balance to estimate process-based
CO2 emissions, this option would require the petrochemical
facility owner to estimate CO2, CH4, and
N2O emissions from the combustion of supplemental fuels
using the monitoring methods in proposed 40 CFR part 98, subpart C, and
to estimate CH4 emissions from onsite wastewater treatment
using the monitoring methods in proposed 40 CFR part 98, subpart II.
Option 3. Direct and continuous measurement of CO2
emissions from each stack (process vent or combustion source) using a
CEMS for CO2 concentration and a stack gas volumetric flow
rate monitor.
This option also would require the petrochemical facility owner to
use engineering analyses to estimate flow and carbon content of gases
discharged to flares using the same procedures described in Section
V.Y.3 of this preamble for petroleum refineries. Just as at petroleum
refineries, flares at petrochemical facilities are used to control a
variety of emissions releases. In addition, the flow and composition of
gas flared can change significantly. Therefore, the Agency is proposing
the same methodology for petrochemical flares as for flares at
petroleum refineries. Please refer to the petroleum refineries section
(Section V.Y.3 of this preamble) for a discussion of the rationale for
these procedures.
We request comment on this approach as well as on descriptions of
differences in operating conditions for flares at petrochemical
facilities and refineries that would warrant specification of different
methodologies for estimating emissions.
In addition to measuring CO2 emissions from process
vents and estimating CO2 emissions from flares, this option
would require the petrochemical facility owner to calculate
CH4 and N2O emissions from combustion sources
using the monitoring methods in proposed 40 CFR part 98, subpart C, and
to calculate CH4 emissions from onsite wastewater treatment
systems using the monitoring methods in proposed 40 CFR part 98,
subpart II.
Proposed Options. Under this proposed rule, if you operate and
maintain an existing CEMS that measures total CO2 from
process vents and combustion sources, you would be required to follow
requirements of proposed 40 CFR part 98, subpart C to estimate
CO2 emissions from your facility. In such a circumstance,
you also would be required to estimate CO2, CH4
and N2O emissions from flares.
If you do not operate and maintain an existing CEMS that measures
total CO2 from process vents and combustion sources for your
facility, the proposed rule permits the use of either Options 2 or 3
since they account for process-based emissions, combustion source
emissions, and wastewater treatment system emissions. Process-based
CO2 emissions are estimated using procedures in proposed 40
CFR part 98, subpart X; combustion emissions (CO2,
CH4, and N2O) and wastewater emissions
(CH4) are calculated using methods in proposed 40 CFR part
98, subparts C and II, respectively. As discussed earlier, emissions
from combustion of process off-gas are calculated with other process-
based emissions (only CO2 emissions) under Option 2, but
they are estimated using methods for combustion sources under Option 3
(CO2, CH4, and N2O emissions). Option
2 offers greater flexibility and a lower cost of compliance than Option
3. However it also has a higher measurement uncertainty.
Option 3 is expected to have the lowest measurement uncertainty.
However, using CEMS to monitor all emissions at petrochemical
facilities would be relatively costly. For emissions estimates produced
using Option 2, the uncertainty in these estimates is expected to be
relatively low for most petrochemical processes. For ethylene
dichloride and ethylene processes, the uncertainty of the carbon
balance approach may be higher since it is influenced by the
measurements of inputs and outputs at the facility and the percentage
of carbon in the final product. Uncertainty may be high where the
percentage of carbon in the product is close to 100 percent (since
subtracting one large number for process output from another large
number for process input results in relatively large uncertainty in the
difference, even if the uncertainty in the two large numbers is low).
For the petrochemical processes, we have decided that Option 2 is
reasonable for purposes of this proposed rulemaking. However, direct
measurement may provide improved emissions estimates.
Option 1 was not proposed because the use of default values and
lack of direct measurement results in a high level of uncertainty.
These default approaches would not provide site-specific estimates of
emissions that would reflect differences in feedstocks, operating
conditions, catalyst selectivity, thermal/energy efficiencies, and
other differences among plants. The use of default values is more
appropriate for sector wide or national total estimates from aggregated
activity data than for determining emissions from a specific facility.
We request comment on how to improve the emission estimates
developed using the carbon balance approach (Option 2), including
whether the uncertainty in the estimated emissions can be reduced (and
if so, by how much), the advantages, disadvantages, types and frequency
of other measurements that could be required, costs of alternatives,
how the uncertainty of alternatives is estimated, and the QA procedures
that should be followed to assure accurate measurement. For further
discussion of our assumptions on the uncertainty of emissions estimates
see the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024).
Additional Issues and Requests for Comments. EPA is interested in
public comment on four additional issues.
Fugitive emissions from petrochemical production facilities have
been of environmental interest primarily because of the VOC emissions.
As noted above, we have concluded that fugitive CO2 and
CH4 emissions contribute very little to the overall GHG
emissions from the petrochemical production sector, and non-
CH4 hydrocarbon losses assumed to be CO2
emissions overstate the emissions only slightly. Consequently, the
Agency is not proposing that fugitive emissions be reported.
Second, Option 2 assumes all carbon entering the process is
released as CO2 and does not account for potential
CH4 emissions, nor are N2O emissions estimated in
this approach. EPA
[[Page 16539]]
believes CH4 and N2O emissions are small.
Third, EPA is aware that a limited number of petrochemical
facilities may produce petrochemicals as well as one or more other
chemicals that are part of another source category (e.g.production of
hydrogen for sale and the petrochemical methanol from synthesis gas
created by steam reforming of CH4). We consider these
``integrated processes'' and request comment on whether the procedures
for the affected source categories are clear and adequate for
addressing emissions from integrated facilities.
Fourth, we are proposing several methods for measuring the volume,
carbon content and composition of feedstocks and products. There may be
additional peer-reviewed and published measurement methodologies.
Public comment on each of these four issues is welcomed. Where
applicable, supporting data and documentation on how emissions should
be included, and if so, how these emissions can be estimated, including
the advantages, disadvantages, types and frequency of measurements that
could be required, costs of alternatives, how the uncertainty of
alternatives is estimated, and the QA procedures that should be
followed to assure accurate measurement.
4. Selection of Procedures for Estimating Missing Data
The missing data procedures in proposed 40 CFR part 98, subpart C
for combustion units are proposed for facilities that use CEMS to
estimate emissions from both combustion sources and process vents.
Similarly, if the mass balance option is used, the same procedures that
apply to missing data for fuel measurements in proposed 40 CFR part 98,
subpart C would also apply to missing flow and carbon content
measurements of feedstocks and products. Specifically, the substitute
data value for missing carbon content, CO2 concentration, or
stack gas moisture content values would be the average of the quality-
assured values of the parameter immediately before and immediately
after the missing data period. The substitute data value for missing
feedstock, product, or stack gas flows would be the best available
estimate based on all available process data.
5. Selection of Data Reporting Requirements
Where CEMS are used, the reporting requirements specified in
proposed 40 CFR part 98, subpart C would apply. Where the carbon
balance method is used, we propose that the following information be
reported: Identification of the process, annual CO2
emissions for each type of petrochemical produced and each process
unit, the methods used to determine flows and carbon contents, the
emissions calculation methodology, quantity of feedstocks consumed,
quantity of each product and byproduct produced, carbon contents of
each feedstock and product, information on the number of actual versus
substitute data points, and the quantity of CO2 captured for
use. In addition, owners and operators would report information related
to all equipment calibrations; measurements, calculations, and other
data; certifications; and any other QA procedures used to assess the
uncertainty in emissions estimates.
The data to be reported under the proposed rule form the basis of
the emissions calculations and are needed for us to understand the
emissions data and verify reasonableness of the reported emissions. The
Agency requests comment on the types of QA procedures that are most
commonly conducted or recommended and the information that would be
most useful in assessing uncertainty of the emissions estimates.
6. Selection of Records That Must Be Retained
Petrochemical production facilities would be required to keep
records of the information specified in proposed 40 CFR 98.3, as
applicable. Under the carbon balance option, a facility also would be
required to keep records of all feedstock and product flows and carbon
content determinations. If a petrochemical production facility complies
with the CEMS option, the additional records for CEMS listed in
proposed 40 CFR 98.37 would also be required for all CEMS, including
CEMS on process stacks that are not associated with combustion sources.
These records document values that are directly used to calculate the
emissions that are reported and are necessary to enable verification
that the GHG emissions monitoring and calculations were done correctly.
Y. Petroleum Refineries
1. Definition of the Source Category
Petroleum refineries are facilities engaged in producing gasoline,
kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt
(bitumen), or other products through distillation of petroleum or
through redistillation, cracking, or reforming of unfinished petroleum
derivatives. There are 150 operating petroleum refineries in the U.S.
and its territories. Emissions from petroleum refineries account for
approximately 205 million metric tons CO2e, representing
approximately 3 percent of the U.S. nationwide GHG emissions. Most of
these emissions are CO2 emissions from fossil fuel
combustion. While the U.S. GHG Inventory does not separately report
onsite fuel consumption at petroleum refineries, it estimates that
approximately 0.6 million metric tons CO2e of CH4
are emitted as fugitives per year from petroleum refineries in the U.S.
Most CO2 emissions at a refinery are combustion-related,
accounting for approximately 67 percent of CO2 emissions at
a refinery.
The combustion of catalyst coke in catalyst cracking units is also
a significant contributor to the CO2 emissions
(approximately 25 percent) from petroleum refineries. Combustion of
excess or waste fuel gas in flares contributes approximately 2 percent
of the refinery's overall CO2 emissions. As such, the Agency
proposes that the emissions from these sources must be reported.
Process emissions of CO2 also occur from the sulfur
recovery plant, because the amine solutions used to remove hydrogen
sulfide (H2S) from the refinery's fuel gas adsorb
CO2. The stripped sour gas from the amine adsorbers is fed
to the sulfur recovery plant; the CO2 contained in this
stream is subsequently released to the atmosphere. Most refineries have
on-site sulfur recovery plants; however, a few refineries send their
sour gas to neighboring sulfur recovery or sulfuric acid production
facilities. The quantity of CO2 contained in the sour gas
sent for off-site sulfur recovery operations is considered an emission
under this regulation.
There are a variety of GHG emission sources at the refinery, which
include: Asphalt blowing, delayed coking unit depressurization and coke
cutting, coke calcining, blowdown systems, process vents, process
equipment leaks, storage tanks, loading operations, land disposal,
wastewater treatment, and waste disposal. To fully account for the
refinery's GHG emissions, we propose that the emissions from these
sources must also be reported.
Based on the emission sources at petroleum refineries, GHGs to
report under proposed 40 CFR part 98, subpart Y are limited to
CO2, CH4, and N2O. Table Y-1 of this
preamble summarizes the GHGs to be reported by emission source at the
refinery.
[[Page 16540]]
Table Y-1. GHGs to Report Under 40 CFR Part 98, Subpart Y
------------------------------------------------------------------------
Subpart of
proposed 40 CFR
part 98 where
Emission source GHGs to report emissions
reporting
methodologies
addressed
------------------------------------------------------------------------
Stationary combustion sources... CO2, CH4, and N2O. Subpart C.
Coke burn-off emissions from CO2, CH4, and N2O. Subpart Y.
catalytic cracking units, fluid
coking units, catalytic
reforming units, and coke
calcining units.
Flares.......................... CO2, CH4, and N2O. Subpart Y.
Hydrogen plant vent............. CO2 and CH4....... Subpart P.
Petrochemical processes......... CO2 and CH4....... Subpart X.
Sulfur recovery plant, on-site CO2............... Subpart Y.
and off-site.
On-site wastewater treatment CO2 and CH4....... Subpart II.
system.
On-site land disposal unit...... CH4............... Subpart HH.
Fugitive Emissions.............. CO2, CH4, and N2O. Subpart Y.
Delayed coking units............ CH4............... Subpart Y.
------------------------------------------------------------------------
2. Selection of Reporting Threshold
Four options were considered as reporting thresholds for petroleum
refineries. Table Y-2 of this preamble illustrates the emissions and
number of facilities that would be covered under the four options.
Table Y-2. Threshold Analysis for Petroleum Refining
----------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
-----------------------------------------------------
Option/threshold level Million
metric tons Percent Number Percent
CO2e/year
----------------------------------------------------------------------------------------------------------------
1,000 metric tons CO2e.................................... 204.75 100 150 100
10,000 metric tons CO2e................................... 204.74 99.995 149 99.3
25,000 metric tons CO2e................................... 204.69 99.97 146 97.3
100,000 metric tons CO2e.................................. 203.75 99.51 128 85.3
----------------------------------------------------------------------------------------------------------------
We are proposing that all petroleum refineries should report. This
approach would ensure full reporting of emissions, affect an
insignificant number of additional sources compared to the 25,000
metric tons CO2e threshold, and would add minimal additional
burden to the reporting facilities. All U.S. refineries must report
their fuel consumption to the EIA, so there is limited additional
burden to estimate their GHG emissions. Furthermore, due to the
importance of the petroleum refining industry to our nation's energy
needs as well as the overall U.S. GHG inventory, it is important to
obtain the best information available for this source category. We
estimate that 4 refineries did not exceed a reporting threshold of
25,000 metric tons CO2e in 2006 and invite public comment on
this matter.
For a full discussion of the threshold analysis, please refer to
the Petroleum Refineries TSD (EPA-HQ-OAR-2008-0508-025). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
We considered monitoring methods that are used or recommended for
use from several sources including international groups, U.S. agencies,
State agencies, and petroleum refinery trade organizations. For most
emission sources, three general levels of monitoring options were
evaluated: (1) Use of engineering calculations and/or default factors;
(2) monitoring of process parameters (such as fuel consumption
quantities and carbon content); and (3) direct emission measurement
using CEMS for all emissions sources at a refinery.
Under this proposed rule, if you are required to use an existing
CEMS to meet the requirements outlined in proposed 40 CFR part 98,
subpart C, you would be required to use CEMS to estimate CO2
emissions. Where the CEMS capture all combustion- and process-related
CO2 emissions you would be required to follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
proposed 40 CFR part 98, subpart C to estimate CO2
emissions. Also, refer to proposed 40 CFR part 98, subpart C to
estimate combustion-related CH4 and N2O
emissions.
For facilities that do not currently have CEMS that meet the
requirements outlined in proposed 40 CFR part 98, subpart C, or where
the CEMS would not adequately account for process emissions, the
proposed monitoring method is Option 2. Option 2 accounts for process-
related CO2 emissions. Simplified methods for estimating
fugitive CH4 emissions are provided below. Refer to proposed
40 CFR part 98, subpart C specifically for procedures to estimate
combustion-related CH4 and N2O emissions.
You would be required to follow the calculation procedures,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of proposed 40 CFR part
98, subpart HH to estimate emissions from landfills, proposed 40 CFR
part 98, subpart II to estimate emissions from wastewater and proposed
40 CFR part 98, subpart P to estimate emissions from hydrogen
production (non-merchant hydrogen plants only).
Specifically, for fluid catalytic cracking units and fluid coking
units that already have CEMS in place, we
[[Page 16541]]
propose to require refineries to report CO2 emissions using
these CEMS. For the sources that contribute significantly to the
overall GHG emissions from the refinery, as defined below, we propose
monitoring of process parameters (Option 2). The Agency requests
comment on the feasibility of allowing smaller emission sources at the
refinery to employ less certain (Option 1) methods as a way to reduce
the costs and burden of measurement and verification under this
proposed rule. Providing this flexibility would result in lower costs
but greater uncertainty around some portions of a facility's emissions
estimates.
The selected monitoring methods for this proposed rule generally
follow those used in other reporting rules as well as those recommended
in the American Petroleum Institute's Compendium of Greenhouse Gas
Emissions Estimation Methodologies for the Oil and Gas Industry
(hereafter referred to as ``the API Compendium''). More detail
regarding the selection of the proposed monitoring options for specific
emission sources follows.
Coke burn-off. The proposed methods for estimating GHG emissions
from coke burn-off in the catalytic cracking unit, fluid coking unit,
and catalytic reforming unit generally follow the methods presented in
the API Compendium for coke burn-off. Fluid catalytic cracking units
and fluid coking units are large CO2 emission sources,
accounting for over 25 percent of the GHG emissions from petroleum
refineries. Most of these units are expected to monitor gas composition
for process control or for compliance with applicable monitoring
provisions under 40 CFR part 60, subparts J and Ja and under 40 CFR
part 63, subpart UUU. Given the magnitude of the GHG emissions from
catalytic cracking units and fluid coking units, direct monitoring for
CO2 emissions (i.e., continuous monitoring of CO2
concentration and flow rate at the final exhaust stack) is believed to
provide greater certainty in the emission estimate. However,
compositional analysis monitoring in the regenerator or fluid coking
burner exhaust vent prior to the combustion of other fuels (such as
auxiliary fuel fired to a CO boiler) may be used when direct monitoring
for CO2 emissions is not already employed. An equation is
provided in the rule for calculating the vent stream flow rate based on
the compositional analysis data rather than requiring a continuous flow
monitor; this equation is allowed in other petroleum refinery rules (40
CFR part 60, subparts J and Ja; 40 CFR part 63, subpart UUU) as an
alternative to continuous flow monitoring.
An engineering approach for estimating coke burn-off rates and
calculating CO2 emissions using default carbon content for
petroleum coke was considered. However, as most catalytic cracking
units already must have the compositional monitors in-place due to
other petroleum refinery rules and because catalytic cracking unit coke
burn-off is a significant contributor to the overall GHG emissions from
petroleum refineries, we are not proposing an engineering calculation
for the catalytic cracking units. However, comment is requested on the
engineering methods available to estimate coke burn-off rates, the
uncertainty of the methods, and the measurements or parameters and
enhanced QA that can be used to verify the engineering emission
estimates and their certainty.
The amount of coke burned in catalytic reforming units is estimated
to be about 1 percent of the amount of coke burned in catalytic
cracking units or fluid coking units; therefore, a simplified method is
provided for estimating coke burn-off emissions for catalytic reforming
units that do not monitor gas composition in the coke burn-off exhaust
vent.
Flares. Specific monitoring provisions are provided for flares. As
the composition of gas flared can change significantly, we considered
proposing continuous flow and composition monitors (or heating value
monitors) on all flares. For example, in California, both the South
Coast and Bay Area Air Quality Management Districts require these
monitors for refineries located in their districts. However, a
significant fraction of flares is not expected to have these monitoring
systems installed. Further, since flares are projected to contribute
only about 2 percent of a typical refinery's CO2 emissions,
it would be costly to improve the monitoring systems for flare emission
estimates. The use of the default CO2 emission factor for
refinery fuel gas was also considered. The default emission factor is
expected to be reasonable during normal refinery operations, but is
highly uncertain during periods of start-up, shutdown, or malfunction.
Consequently, a hybrid method is proposed that allows the use of a
default CO2 emission factor for refinery fuel gas during
periods of normal refinery operations and specific engineering analysis
of GHG emissions during periods of high flare volumes associated with
start-up, shutdown, or malfunction. As with stationary combustion
sources, default emission factors for refinery gas are proposed to
calculate CH4 and N2O emissions from flares.
Sulfur Recovery Plants. For sulfur recovery plants at the petroleum
refinery and for instances where sour gas is sent off-site for sulfur
recovery, direct carbon content measurement in the sour gas feed to the
sulfur recovery plant is the preferred monitoring approach. However, a
site-specific or default carbon content method is also provided. It is
anticipated that monitoring systems would be in place at most
refineries, as monitoring of the sour gas feed is important in the
operation of the sulfur recovery plant. The monitoring data for carbon
content and flow rate must be used if they are available. The
alternative default carbon content method is provided because the
emissions from this source are relatively small, 1 to 2 percent for a
given facility, and because only small, non-Claus sulfur recovery
plants are not expected to monitor the flow and composition of the sour
gas. We are proposing that only CO2 emissions would need to
be reported for the sulfur recovery plant process-related emissions.
Coke Calcining. For coke calcining units at the petroleum refinery,
direct CO2 measurement is the preferred monitoring approach.
However, a carbon balance approach is proposed similar to the approach
included in The Aluminum Sector Greenhouse Gas Protocol \83\ for units
that do not have CEMS. This is because coke calcining is a small source
of GHG emissions, less than 1 percent for a given facility.
CH4 and N2O emissions are calculated from the
coke calcining CO2 process emissions using the default
emission factors for petroleum coke combustion (the same equations as
proposed for calculating CH4 and N2O emissions
from coke burn-off).
---------------------------------------------------------------------------
\83\ International Aluminum Institute. 2006. The Aluminum Sector
Greenhouse Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas
Protocol). pp. 31-32. Available at: http://www.world-aluminium.org/Downloads/Publications/Download.
---------------------------------------------------------------------------
Process Vents not Otherwise Specified. For process vents other than
those discussed elsewhere in this section of the preamble, either
process knowledge or measurement data can be used to calculate the GHG
emissions. Due to other regulations affecting petroleum refineries,
only a few, small process vents are expected to be present at most
refineries. As such, these small vents do not warrant requiring the use
of CEMS to quantify emissions. Process vent emissions are expected to
be predominately CO2 or CH4, but N2O
[[Page 16542]]
emissions, if present, are also to be reported.
Other Sources. Due to the small (less than 1 percent) contribution
of other emissions sources at the refinery that make up the total GHG
emissions from the facility, very simple methods are proposed to
estimate these other emissions sources. Alternative methods are
provided so that facilities can provide more detailed estimates if
desired. For example, a refinery may estimate CH4 emissions
from individual tanks using EPA's TANKS model, if desired, or apply a
default emission factor to the facility's overall throughput. Simple
emission factor approaches are provided for asphalt blowing, delayed
coking unit depressurization and coke cutting, blowdown systems,
process equipment leaks, storage tanks, and loading operations.
For further discussion of this source category and monitoring of
its emissions, see the Petroleum Refineries TSD (EPA-HQ-OAR-2008-0508-
025).
4. Selection of Procedures for Estimating Missing Data
In those cases where you use direct measurement by a CO2
CEMS, the missing data procedures would be the same as the Tier 4
requirements described for general stationary fuel combustion sources
in proposed 40 CFR part 98, subpart C. Missing data procedures are also
specified, consistent with proposed 40 CFR part 98, subpart C, for heat
content, carbon content, fuel molecular weight, gas and liquid fuel
flow rates, stack gas flow rates, and compositional analysis data
(CO2, CO, O2, CH4, N2O, and
stack gas moisture content, as applicable). Generally, the average of
the data measurements before and after the missing data period would be
used to calculate the emissions during the missing data period.
5. Selection of Data Reporting Requirements
The reporting requirements for combustion sources other than those
associated with coke burn-off directly refer to those in proposed 40
CFR part 98, subpart C, General Stationary Fuel Combustion Sources. For
other sources, we propose to report the identification of the source,
throughput of the source (if applicable), the calculation methodology
used, the total GHG emissions for the source, and the quantity of
CO2 captured for use and the end use, if known. A list of
the specific GHG emissions reportable for each emission source is
provided in Table Y-1 of this preamble.
The reporting requirements consist of actual GHG emission values as
well as values that are directly used to calculate the emissions and
are necessary in order to verify that the GHG emissions monitoring and
calculations were done correctly. As there are high uncertainties
associated with many of the ancillary emission sources at the refinery,
separate reporting of the emissions for these separate sources is
needed to fully understand the importance and variability of these
ancillary emission sources. A complete list of information to report is
contained in proposed 40 CFR 98.256.
6. Selection of Records That Must Be Retained
The recordkeeping requirements in the general provisions of
proposed 40 CFR part 98 apply for petroleum refineries. Specifically,
refineries would be required to keep all records specified in proposed
40 CFR part 98, subpart A and summarized in Section III.E of this
preamble. In addition, records of the data required to be monitored and
reported under proposed 40 CFR part 98, subpart Y would be retained. If
CEMS are used to quantify the GHG emissions, you would be required to
keep additional records specified in proposed 40 CFR part 98, subparts
A and Y. These records consist of values that are directly used to
calculate the emissions and are necessary to enable verification that
the GHG emissions monitoring and calculations were done correctly.
Z. Phosphoric Acid Production
1. Definition of the Source Category
Phosphoric acid is a common industrial product used to manufacture
phosphate fertilizers. Phosphoric acid is a product of the reaction
between phosphate rock and, typically, sulfuric acid
(H2SO4). A byproduct called calcium sulfate
(CaSO4), or gypsum, is formed when calcium from the
phosphate rock reacts with sulfate. Most companies in the U.S. use a
dihydrate process in which two molecules of water (H2O) are
produced per molecule of gypsum (CaSO4 [middot] 2
H2O or calcium sulfate dihydrate).
Additionally, a second reaction occurs in which the limestone
(CaCO3) present in the phosphate rock reacts with sulfuric
acid (H2SO4) releasing CO2. The amount
of carbon in the phosphate rock feedstock varies depending on the
region in which it was mined.
National emissions from phosphoric acid production facilities were
estimated to be 3.8 million metric tons CO2e in 2006. These
emissions include both process-related emissions (CO2) and
on-site stationary combustion emissions (CO2, CH4
and N2O) from 14 phosphoric acid production facilities
across the U.S. Process-related emissions account for 1.2 million
metric tons CO2e, or 30 percent of the total, while on-site
stationary combustion emissions account for the remaining 2.7 million
metric tons CO2e emissions.
The phosphoric acid production industry has many production sites
that are integrated with mines; notably, three facilities import
phosphate rock from Morocco.
For additional background information on phosphoric acid
production, please refer to the Phosphoric Acid Production TSD (EPA-HQ-
OAR-2008-0508-026).
2. Selection of Reporting Threshold
In developing the threshold for phosphoric acid production, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e per year. Table
Z-1 of this preamble illustrates the emissions and number of facilities
would not be impacted under these various applicability thresholds.
Table Z-1. Threshold Analysis for Phosphoric Acid Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities Metric tons
CO2e/yr CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 3,838,036 14 3,838,036 100 14 100
10,000.................................................. 3,838,036 14 3,838,036 100 14 100
25,000.................................................. 3,838,036 14 3,838,036 100 14 100
100,000................................................. 3,838,036 14 3,838,036 100 14 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 16543]]
There is no proposed threshold for reporting emissions from
phosphoric acid production. Even at a 100,000 metric tons
CO2e threshold, all emissions would be covered, and all
facilities would be required to report. Having no threshold would
simplify the rule and avoid any burden for unnecessary calculations to
determine if a threshold is exceeded. Therefore, we propose that all
phosphoric acid production facilities report.
For a full discussion of the threshold analysis, please refer to
the Phosphoric Acid Production TSD (EPA-HQ-OAR-2008-0508-026). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
The methodology for estimating process-related emissions from
phosphoric acid production is based on the U.S. GHG Inventory method
discussed further in the Phosphoric Acid Production TSD (EPA-HQ-OAR-
2008-0508-026). Most domestic and international GHG monitoring
guidelines and protocols, such as the 2006 IPCC Guidelines do not
provide estimation methodologies for process-related emissions from
phosphoric acid production.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow the requirements of proposed 40 CFR part 98, subpart C to
estimate CO2 emissions. Also, refer to proposed 40 CFR part
98, subpart C to estimate combustion-related CH4 and
N2O emissions.
If you do not have CEMS that meet the conditions outlined in
proposed 40 CFR part 98, subpart C, we propose that facilities estimate
process-related CO2 emissions by determining the amount of
inorganic carbon input to the process through measurement of the
inorganic carbon content of the phosphate rock and multiplying by the
amount (mass) of phosphate rock used to manufacture phosphoric acid.
Refer to proposed 40 CFR part 98, subpart C specifically for procedures
to estimate combustion-related CH4 and N2O
emissions.
In order to assess the composition of the inorganic carbon input,
we assume that vertically integrated phosphoric acid production
facilities already have the necessary equipment on-site for conducting
chemical analyses of the inorganic carbon weight fraction of the
phosphate rock and that this analysis is conducted on a routine basis
at facilities. Facilities importing rock from Morocco would send rock
samples off-site for composition analysis. The inorganic carbon content
would be determined on a per-batch basis. Multiplying the inorganic
carbon content by the amount (mass) of phosphate rock processed and by
the molecular weight ratio of CO2 to inorganic carbon (44/
12) yields the estimate of CO2 emissions. This calculated
value should be recorded monthly based on the most recent batch of
phosphate rock received. The monthly emissions for each phosphoric acid
process line are then summed to obtain the annual emissions to be
included in the report.
The various approaches to monitoring GHG emissions are elaborated
in the Phosphoric Acid Production TSD (EPA-HQ-OAR-2008-0508-026).
4. Selection of Procedures for Estimating Missing Data
The likelihood for missing data is low, as businesses closely track
their purchase of production inputs. The Phosphoric Acid NSPS (40 CFR
part 60, subpart T) requires continuous monitoring of phosphorus-
bearing material (rock) to process. This requirement, along with the
fact that the facility would closely monitor production inputs, results
in low likelihood of missing data. Additionally, only 3 facilities
within the U.S. are not vertically integrated with mines and may lack
the necessary equipment to measure the inorganic carbon weight percent
of the rock. Therefore, no missing data procedures would apply to
CO2 emission estimates from wet-process phosphoric acid
production facilities because inorganic carbon test results and monthly
production data should be readily available. Therefore, 100 percent
data availability would be required.
5. Selection of Data Reporting Requirements
We propose that facilities report total annual CO2
emissions from each wet-process phosphoric acid productionline, as well
as any stationary fuel combustion emissions. In addition, we propose
that facilities report their annual average phosphate rock consumption,
percent of inorganic carbon in the phosphate rock consumed, annual
phosphoric acid production and concentration and annual phosphoric acid
capacity. These data are used to calculate emissions. They are needed
for us to understand the emissions data and assess the reasonableness
of the reported emissions. A full list of data to be reported is
included in proposed40 CFR part 98, subparts A and Z.
6. Selection of Records That Must Be Retained
In addition to the data reported, we propose that facilities
maintain records of inorganic carbon content chemical analyses on each
batch of phosphate rock and monthly phosphate rock consumption (by the
origin of the phosphate rock). These records provide values that are
directly used to calculate the emissions that are reported and are
necessary to allow determination of whether the GHG emissions
monitoring and calculations were done correctly.
A full list of records that must be retained on-site is included in
proposed 40 CFR part 98, subparts A and Z.
AA. Pulp and Paper Manufacturing
1. Definition of the Source Category
The pulp and paper source category consists of over 5,000
facilities engaged in the manufacture of pulp, paper, and/or paperboard
products primarily from wood material. However, less than 10 percent of
these facilities are expected to meet the applicability thresholds of
this proposed rule. The approximately 425 facilities that the proposed
rule is expected to cover mainly consist of facilities that include
pulp, paper and paperboard facilities that operate fossil fuel-fired
boilers in addition to operating other sources of GHG emissions (e.g.,
biomass boilers, lime kilns, onsite landfills, and onsite wastewater
treatment systems).\84\
---------------------------------------------------------------------------
\84\ This estimate is based on a survey of pulp and paper mills
conducted by the National Council for Air and Stream Improvement
that operated stationary combustion units in 2005. See: National
Council of Air and Stream Improvement Special Report No. 06-07.
December 2006.
---------------------------------------------------------------------------
Greenhouse gas emissions from the pulp and paper source category
are predominantly CO2 with smaller amounts of CH4
and N2O. The pulp and paper GHG emissions include biomass-
derived CO2 emissions from using the biomass generated on
site as a byproduct (e.g., bark, other wood waste, spent pulping
liquor). For example, kraft pulp and paper facilities are likely to
generate byproduct biomass fuel while the majority of the onsite energy
for non-integrated paper facilities and 100 percent recycled paper
facilities is likely to be generated from fossil fuel-fired boilers
because these facilities do not generate byproduct biomass fuel.
Table AA-1 of this preamble lists the GHG emission sources that may
be
[[Page 16544]]
found at pulp and paper facilities, the type of GHG emissions that are
required to be reported, and where the reporting methodologies are
found in proposed 40 CFR part 98.
Table AA-1. GHG Emission Sources at Pulp, Paper, and Paperboard
Facilities
------------------------------------------------------------------------
Subpart of 40 CFR
part 98 where
emissions
Emissions source GHG emissions reporting
methodologies
addressed
------------------------------------------------------------------------
General Stationary Fuel CO2, CH4, N2O, Subpart C.
Combustion. biomass-CO2.
Makeup Chemicals (CaCO3, Na2CO3) CO2............... Subpart AA.
Onsite industrial landfills..... CH4............... Subpart HH.
Wastewater treatment............ CH4............... Subpart II.
------------------------------------------------------------------------
The method presented in this section of the preamble is to account
for the use of make-up chemicals (e.g., sodium sulfate, calcium
carbonate, sodium carbonate) that are added into the recovery loop
(e.g., with the spent pulping liquor) at a pulp and paper facility to
replace the small amounts of sodium and calcium that are lost from the
recovery cycle at kraft and soda facilities. When carbonates are added,
the carbon in these make-up chemicals, which can be derived from
biomass or mineral sources, is emitted as CO2 from recovery
furnaces and lime kilns. In cases where the carbon is mineral-based,
emissions of CO2 would contribute to GHG emissions.
Affected facilities would be required to report total GHG emissions
on a facility-wide basis for all source categories for which methods
are presented in proposed 40 CFR part 98.
2. Selection of Reporting Threshold
For the pulp and paper source category, the Agency proposes a GHG
reporting threshold of 25,000 metric tons CO2e, which would
include the vast majority of GHG emissions from the pulp and paper
source category.\85\
---------------------------------------------------------------------------
\85\ The American Forest and Paper Association estimates that
the 25,000 metric tons CO2e would include approximately
99 percent of GHG emissions from the pulp and paper source category.
---------------------------------------------------------------------------
As described in proposed 40 CFR part 98, subpart A, biomass-derived
CO2 emissions should not be taken into consideration when
determining whether a facility exceeds the 25,000 metric tons
CO2e threshold.
In evaluating potential thresholds for the pulp and paper source
category, we considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e. The threshold
analysis focuses on the most significant sources of GHG emissions in
the pulp and paper industry, specifically facilities that make pulp,
paper and paperboard and operate fossil fuel-fired boilers. Therefore,
of the 5,000 facilities associated with this industry, only 425 were
included in the analysis. Table AA-2 of this preamble illustrates that
the various thresholds do not have a significant effect on the amount
of emissions that would be covered.
For a full discussion of the threshold analysis, please refer to
the Pulp and Paper Manufacturing TSD (EPA-HQ-OAR-2008-0508-027). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
Table AA-2. Reporting Thresholds for Pulp and Paper Sector
----------------------------------------------------------------------------------------------------------------
Total national Total Emissions covered Facilities covered
Threshold level metric tons emissions number of ------------------------------------------------------
CO2e (metric tons U.S. Metric tons
CO2e) facilities CO2e/yr Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000....................... 57,700,000 425 57,700,000 100 425 100
10,000...................... 57,700,000 425 57,700,000 100 425 100
25,000...................... 57,700,000 425 57,700,000 100 425 100
100,000..................... 57,700,000 425 57,527,000 99.7 410 96
----------------------------------------------------------------------------------------------------------------
3. Selection of Proposed Monitoring Methods
a. Calculation Methods Selected
Refer to proposed 40 CFR part 98, subparts C, HH, and II for
monitoring methods for general stationary fuel combustion sources,
landfills, and industrial wastewater treatment occurring on-site at
pulp and paper facilities. This section of the preamble includes
monitoring methods for calculating and reporting makeup chemicals at
pulp and paper facilities. Additional details on the proposed
monitoring options are elaborated in the Pulp and Paper Manufacturing
TSD (EPA-HQ-OAR-2008-0508-027).
The proposed method for monitoring emissions from carbonate-based
make-up chemicals used at chemical pulp facilities includes calculating
the CO2 emissions from the added CaCO3 and
Na2CO3 using emissions factors provided in the
rule. The calculation assumes that the carbonate based make-up
chemicals added (e.g., limestone) are pure carbonate minerals, and that
all of the carbon is released to the atmosphere. If you believe that
these assumptions do not represent circumstances at your facility, you
may send samples of each carbonate consumed to an off-site laboratory
for a chemical analysis of the carbonate weight fraction on a quarterly
basis, consistent with proposed 40 CFR part 98, subpart U. You could
also determine the calcination fraction for each of the carbonate-based
minerals consumed, using an appropriate test method. Make-up chemical
usage would be required to be determined by direct measurement of the
quantity of chemical added. The chemical usage should be quantified
separately for each chemical used, and
[[Page 16545]]
the estimate should be in terms of pure CaCO3 and/or
Na2CO3. We have proposed direct measurement for
quantifying the amount of makeup chemicals, consistent with the
estimation of emissions from carbonates in the rest of proposed 40 CFR
part 98.
For the monitoring methods detailed in proposed 40 CFR part 98,
subpart C for general stationary combustion, it should be noted that
biogenic CO2 emissions from the combustion of biomass fuels
are to be reported separately. Furthermore, in referring to proposed 40
CFR part 98, subpart C on general stationary combustion, we would
expand upon particular details unique to a pulp and paper facility,
because of the unique uses of biomass fuels. For the pulp and paper
source category, biomass fuels include, but may not be limited to: (1)
Unadulterated wood, wood residue, and wood products (e.g., trees, tree
stumps, tree limbs, bark, lumber, sawdust, sanderdust, chips, scraps,
slabs, millings, wood shavings, paper pellets, and corrugated container
rejects); (2) pulp and paper facility wastewater treatment system
sludge; (3) vegetative agricultural and silvicultural materials, such
as logging residues and bagasse; and (4) liquid biomass-based fuels
such as biomass-based turpentine and tall oil. Such fuels could be
combusted at a pulp and paper facility in stationary combustion units
including, but not limited to, boilers, chemical recovery furnaces, and
lime kilns. Proposed 40 CFR part 98, subpart C provides details on the
separate reporting of the biogenic CO2 emissions from these
biomass-based fuels, and the calculation methodologies for any fossil
fuels combusted, including when co-fired with biomass.
Where biomass is co-fired with fossil fuel, the appropriate
methodology as required in proposed 40 CFR part 98, subpart C should be
used. However, to minimize the burden on owners and operators of
biomass-fired stationary combustion equipment, this proposed rule
allows biogenic CO2 emissions to be calculated using default
emission factors and default HHVs used in the Tier 1 methodology.
Where available, like in the case of spent pulping liquor, we would
require direct analysis of the HHV, rather than allowing the use of a
default HHV. This is due to the variability in the HHV of spent pulping
liquor across the industry and because a number of facilities already
perform this analysis on a monthly basis. However, the proposed rule
does not propose the use of default GHG emissions factors for spent
pulping liquor at kraft pulp facilities. For sulfite and semichemical
chemical recovery combustion units, we propose that sources conduct a
monthly carbon content analysis of the spent pulping liquor for use in
calculating the biomass CO2 emissions because no default
emissions factors are known to exist for these sources.
We are requesting comment on the appropriateness of today's
proposed requirements for monthly measurement of spent pulping liquor
HHV (kraft recovery furnaces) and monthly carbon content analysis of
spent pulping liquor (sulfite and semichemical chemical recovery
combustion units). We welcome data and documentation regarding the use
of potential alternative methods or default emissions factors.
In addition, regarding the monitoring methods in proposed 40 CFR
part 98, subpart C for general stationary combustion, the majority of
biomass fuel consumed at pulp and paper mills is generated onsite, and
thus, as required in proposed 40 CFR part 98, subpart C, the use of
purchasing records might not be an option for these mills. As such, we
are taking comment on appropriate details to be reported on volume or
mass of biogenic fuel fed into stationary combustion units.
b. Other Monitoring Methods Considered
Lime kilns and calciners used in the pulp and paper source category
are unique and are defined separately from lime kilns used in the
commercial lime manufacturing industry because the source of the carbon
in the calcium carbonate entering the kraft lime kiln is biogenic. The
CO2 emitted from lime kilns at kraft pulp facilities
originates from two sources: (1) Fossil fuels burned in the kiln, and
(2) conversion of calcium carbonate (or ``lime mud'') to calcium oxide
during the chemical recovery process.
Although CO2 is also liberated from the CaCO3
burned in the kiln or calciner, the carbon released from
CaCO3 is biomass carbon that originates in wood and is
included in the biogenic CO2 emissions factor for the
recovery furnace as discussed previously. The reporting of the
CO2 emissions associated with the conversion of the calcium
carbonate to lime as biogenic CO2 is consistent with the
reporting requirements in other accepted protocols such as DOE 1605(b)
and guidance developed for the International Council of the Forest and
Paper Association. This approach has been widely accepted by the
domestic and international community, including WRI/WBCSD. The IPCC
does not directly state how CO2 emissions from kraft
facility lime kilns should be addressed. As biogenic process
CO2 emissions (i.e., any biogenic CO2 emissions
not associated with the combustion of biomass fuels) are not being
reported in this rule, we are taking comment on whether an exception
should be made for this unique case, consistent with other existing
protocols as noted above.
4. Selection of Procedures for Estimating Missing Data
Refer to proposed 40 CFR part 98, subparts C, HH, and II for
procedures for estimating missing data for stationary combustion,
landfills, and industrial wastewater treatment occurring on-site at
pulp and paper facilities.
Proposed 40 CFR part 98, subpart AA contains missing data
procedures for process emissions. There are no missing data procedures
for measurements of heat content and carbon content of spent pulping
liquor. A re-test must be performed if the data from any monthly
measurements are determined to be invalid. For missing spent pulping
liquor flow rates, the lesser value of either the maximum fuel flow
rate for the combustion unit, or the maximum flow rate that the fuel
flowmeter can measure would be used. For the use of makeup chemicals
(carbonates), the substitute data value shall be the best available
estimate of makeup chemical consumption, based on available data (e.g.,
past accounting records, production rates).
5. Selection of Data Reporting Requirements
Refer to proposed 40 CFR part 98, subparts C, HH, and II for
reporting requirements for stationary combustion, landfills, and
industrial wastewater treatment occurring on-site at pulp and paper
facilities.
We propose that some additional data be reported to assist in
verification of estimates, checks for reasonableness, and other data
quality considerations, including: Annual emission estimates presented
by calendar quarters (including biogenic CO2), total
consumption of all biomass fuels and spent pulping liquor by calendar
quarters, and total annual quantities of makeup chemicals (carbonates)
used and by carbonate.
6. Selection of Records That Must Be Retained
Refer to proposed 40 CFR part 98, subparts C, HH, and II for
recordkeeping requirements for stationary combustion, landfills, and
industrial wastewater treatment occurring on-site at pulp and paper
facilities.
[[Page 16546]]
In addition to the recordkeeping requirements for general
stationary fuel combustion sources in proposed 40 CFR part 98, subpart
C, we propose that the following additional records be kept to assist
in QA/QC, including: GHG emission estimates by calendar quarter by unit
and facility, monthly consumption total of all biomass fuels and spent
pulping liquor by unit and facility, monthly analyses of spent pulping
liquor HHV or carbon content, monthly and annual steam production for
each biomass unit, and monthly quantities of makeup chemicals
(carbonates) used.
BB. Silicon Carbide Production
1. Definition of the Source Category
Silicon carbide (SiC) is primarily an industrial abrasive
manufactured from silica sand or quartz and petroleum coke. Other uses
of silicon carbide include semiconductors, body armor, and the
manufacture of Moissanite, a diamond substitute. The silicon carbide
source category is limited to the production of silicon carbide for
abrasive purposes.
CO2 and CH4 are emitted during the production
of silicon carbide. Petroleum coke is utilized as a carbon source
during silicon carbide production and approximately 35 percent of the
carbon is retained within the silicon carbide product; the remaining
carbon is converted to CO2 and CH4.
Silicon carbide process emissions totaled 109,271 metric tons
CO2e in 2006 (less than 0.002 percent of the total national
GHG emissions). Of the total, process-related CO2 emissions
accounted for 91 percent (91,700 metric tons CO2e),
CH4 emissions accounted for 9 percent (8,526 metric tons
CO2e), and on-site stationary combustion emissions accounted
for less than 1 percent (9,045 metric tons CO2e).
For additional background information on silicon carbide
production, please refer to the Silicon Carbide Production TSD (EPA-HQ-
OAR-2008-0508-028).
2. Selection of Reporting Threshold
In developing the reporting threshold for silicon carbide
production, we considered emissions-based thresholds of 1,000 metric
tons CO2e, 10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e. Requiring
all facilities to report (no threshold) was also considered. Table BB-1
of this preamble illustrates the emissions and facilities that would be
covered under these various thresholds.
Table BB-1. Threshold Analysis for Silicon Carbide Production
----------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
national Total ------------------------------------------------------
Threshold level metric tons emissions number of
CO2e/yr (metric tons facilities Metric tons Percent Number Percent
CO2e/yr) CO2e/yr
----------------------------------------------------------------------------------------------------------------
1,000....................... 109,271 1 109,271 100 1 100
10,000...................... 109,271 1 109,271 100 1 100
25,000...................... 109,271 1 109,271 100 1 100
100,000..................... 109,271 1 109,271 100 1 100
----------------------------------------------------------------------------------------------------------------
There is no proposed threshold reporting level for GHG emissions
from silicon carbide production facilities. The current estimate of
emissions from the known facility just exceeds the highest threshold
considered. Therefore, in order to simplify the rule and avoid the need
for the facility to calculate and report whether the facility exceeds
the threshold value, we propose that all facilities report in this
source category. Requiring all facilities to report captures 100
percent of emissions, and small temporary changes to the facility would
not affect reporting requirements.
For a full discussion of the threshold analysis, please refer to
the Silicon Carbide Production TSD (EPA-HQ-OAR-2008-0508-028). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Monitoring of process emissions from silicon carbide production is
addressed in both domestic and international GHG monitoring guidelines
and protocols (the 2006 IPCC Guidelines and U.S. GHG Inventory). These
methodologies can be summarized in two different options based on
measuring either inputs or output of the production process. In
general, the output or production-based method is less certain, as it
involves multiplying production data by emission and correction factors
that are likely default values based on carbon content (i.e.,
percentage of petroleum coke input that is carbon) assumptions. In
contrast, the input method is more certain as it generally involves
measuring the consumption of reducing agents and calculating the carbon
contents of those reducing agents, specifically petroleum coke inputs.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS that meets the requirements outlined in proposed
40 CFR part 98, subpart C, then you would be required to use CEMS to
estimate CO2 emissions. Where the CEMS capture all
combustion- and process-related CO2 emissions you would be
required to follow the requirements of proposed 40 CFR part 98, subpart
C to estimate CO2 emissions from the industrial source.
Also, refer to proposed 40 CFR part 98, subpart C to estimate
combustion-related CH4 and N2O emissions.
Under this proposed rule, if you do not have CEMS that meet the
conditions outlined in proposed 40 CFR part 98, subpart C or where the
CEMS would not adequately account for process emissions, we propose
that facilities use an input based method to estimate process-related
CO2 emissions by measuring the facility-level petroleum coke
consumed and applying a facility-specific emission factor derived from
analysis of the carbon content in the coke. In addition, we propose
that facilities use default emission factors to estimate process-
related CH4 emissions. Refer to proposed 40 CFR part 98,
subpart C for procedures to estimate combustion-related CO2,
CH4 and N2O emissions.
We propose that facilities use an input-based method to estimate
process-related CO2 emissions by measuring the facility-
level petroleum coke consumed and applying a facility-specific emission
factor derived from analysis of the carbon content in the coke. Using
the emission factor, facilities would calculate CO2
emissions quarterly and aggregate for an annual estimate. In order to
estimate carbon content, we
[[Page 16547]]
propose that facilities request reports of the carbon content of the
petroleum coke directly from the supplier or send petroleum coke
samples out to a certified laboratory for chemical analysis on a
quarterly basis. Any changes in the measured values would be reflected
in a revised emission factor.
We assume that data on petroleum coke consumption is readily
available to facilities. The measurement of production quantities is
common practice in the industry and is usually measured through the use
of scales or weigh belts so additional costs to the industry are not
anticipated. The primary additional burden for facilities associated
with this method is modifying their petroleum coke supplier contract to
include an analysis of the carbon content of each delivery of petroleum
coke. Alternatively, a facility can send the coke to an off-site
laboratory for analysis of the carbon content by the applicable method
incorporated by reference in proposed 40 CFR 98.7. We consider the
additional burden of determining the carbon content of the coke raw
material minimal compared to the increases in accuracy expected from
the site specific emission factors.
We also considered a second method of estimating process-related
CO2 emissions that involves application of default emission
factors based on the quantity of coke consumed or total silicon carbide
produced. According to the 2006 IPCC Guidelines, the default
CO2 emission factors for silicon carbide production are
relatively uncertain because industry scale carbide production
processes differ from the stoichiometry of theoretical chemical
reactions. Given the relative uncertainty of defaults, we decided not
to propose existing methodologies that relied on default emission
factors or default values for carbon content of materials because
default approaches are inherently inaccurate for site-specific
determinations. The use of default values is more appropriate for
sector wide or national total estimates from aggregated activity data
than for determining emissions from specific facilities.
We propose that facilities estimate process-related CH4
emissions by using a default emission factor of 10.2 kg CH4
per metric ton of petroleum coke consumed during silicon carbide
production. This method coincides with the IPCC Tier 1 method. Direct
measurement of a CH4 emission factor was considered, but the
cost of performing testing to determine this factor is too burdensome,
considering that the amount of CH4 emissions originating
from silicon carbide production is less than 0.5 percent of the overall
GHG emissions from this source category.
The various approaches to monitoring GHG emissions are elaborated
in the Silicon Carbide Production TSD (EPA-HQ-OAR-2008-0508-028).
4. Selection of Procedures for Estimating Missing Data
It is assumed that a facility would be readily able to supply data
on annual petroleum coke consumption and its carbon contents.
Therefore, 100 percent data availability is required.
5. Selection of Data Reporting Requirements
We propose that facilities report the combined annual
CO2 and CH4 emissions from the silicon carbide
production processes. In addition, we propose that the following data
be reported to assist in verification of calculations and estimates,
checks for reasonableness, and other data quality considerations:
Annual silicon carbide production, annual silicon carbide production
capacity, facility-specific CO2 emission factor, and annual
operating hours. A full list of data to be reported is included in
proposed 40 CFR part 98, subparts A and BB.
6. Selection of Records That Must Be Retained
In addition to the data reported, we propose that facilities
maintain records of quarterly analyses of carbon content for consumed
coke (averaged to an annual basis), annual consumption of petroleum
coke, and calculations of emission factors. These records hold values
directly used to calculate reported emissions and are necessary for
future verification that GHG emissions monitoring and calculations were
done correctly. A full list of records that must be maintained onsite
is included in proposed 40 CFR part 98, subparts A and BB.
CC. Soda Ash Manufacturing
1. Definition of the Source Category
Soda ash (sodium carbonate, Na2CO3) is a raw
material utilized in numerous industries including glass production,
pulp and paper production, and soap production. According to the USGS,
the majority of the 11 million metric tons of soda ash produced is used
for glass production. In the U.S., trona (the raw material from which
most American soda ash is produced) is mined exclusively in Wyoming,
where five of the seven U.S. soda ash manufacturing facilities are
located. Total soda ash production in 2006 was 11 million metric tons,
an amount consistent with 2005 and 500,000 metric tons more than was
produced in 2002. Due to a surplus of soda ash in the market,
approximately 17 percent of the soda ash industry's nameplate capacity
was idled in 2006.
Trona-based production methods are collectively referred to as
``natural production'' methods. ``Natural production'' emits
CO2 by calcining trona. Calcining involves placing crushed
trona into a kiln to convert sodium bicarbonate into crude sodium
carbonate that would later be filtered into pure soda ash.
National emissions from natural soda ash manufacturing were
estimated to be 3.1 million metric tons CO2e in 2006 or less
than 0.04 percent of total emissions. These emissions include both
process-related emissions (CO2) and on-site stationary
combustion emissions (CO2, CH4, N2O)
from six production facilities across the U.S. and Puerto Rico.
Process-related emissions account for 1.6 million metric tons
CO2e, or 52 percent of the total, while on-site stationary
combustion emissions account for the remaining 1.5 million metric tons
CO2e emissions. Soda ash consumption in the U.S. generated
2.5 million metric tons CO2e in 2006.
Emissions from consumption of soda ash are not addressed in this
proposed rule as they do not occur at the soda ash manufacturing
source. Emissions from the use of soda ash would be reported by the
glass manufacturing industry, which consumes the soda ash.
For additional background information on soda ash manufacturing,
please refer to the Soda Ash Manufacturing TSD (EPA-HQ-OAR-2008-0508-
029).
2. Selection of Reporting Threshold
In developing the threshold for soda ash manufacturing, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e per year.
Table CC-1 of this preamble illustrates the emissions and facilities
that would be covered under these various thresholds.
[[Page 16548]]
Table CC-1. Threshold Analysis for Soda Ash Manufacturing
----------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
Threshold level metric tons emissions Total ------------------------------------------------------
CO2e/yr metric tons number of Metric tons
CO2e/yr facilities CO2e/yr Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000....................... 3,121,438 5 3,121,438 100 5 100
10,000...................... 3,121,438 5 3,121,438 100 5 100
25,000...................... 3,121,438 5 3,121,438 100 5 100
100,000..................... 3,121,438 5 3,121,438 100 5 100
----------------------------------------------------------------------------------------------------------------
Facility-level emissions estimates based on known plant capacities
suggest that all known facilities exceed the highest (100,000 metric
tons CO2e) threshold examined. Two facilities were excluded
from this analysis based on available information (one has not been
operating since 2004 and the second recycles or utilizes CO2
emissions as part of the process, resulting in limited fugitive
emissions). Even if sources are not operating at full capacity, all or
most of them would still be expected to exceed the 25,000 metric ton
threshold. We propose that all facilities report. Requiring all
facilities to report would simplify the proposed rule, and ensure that
100 percent of the emissions from this industry are reported.
For a full discussion of the threshold analysis, please refer to
the Soda Ash Manufacturing TSD (EPA-HQ-OAR-2008-0508-029). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from soda ash manufacturing (e.g., the 2006 IPCC Guidelines,
DOE 1605(b)). These methodologies coalesce around three different
options:
Option 1: Default emission factors would be applied to the amount
of trona consumed or soda ash produced. This method would also involve
applying an adjustment factor to the default emission factor to account
for fractional purity of the trona consumed or soda ash produced. A
default adjustment factor of 0.9 could be applied if country specific
or plant specific information is not available. This option is
consistent with IPCC Tier 2 methods and 1605(b)'s ``A'' rated approach.
Option 2: Develop a site-specific emission factor (determined by an
annual stack test). This method would account for the fractional purity
of the trona consumed or soda ash produced. This approach is consistent
with IPCC's Tier 2 method and consistent with the DOE 1605(b) ``A''
rated approach.
Option 3: Direct measurement of emissions using CEMS.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions, you would be required to
follow requirements of proposed 40 CFR part 98, subpart C to estimate
CO2 emissions. Also, refer to proposed 40 CFR part 98,
subpart C to estimate combustion-related CH4 and
N2O emissions.
Under this proposed rule, if you do not have CEMS that meet the
conditions outlined in proposed 40 CFR part 98, subpart C, or where the
CEMS would not adequately account for process emissions, we propose
that facilities estimate process-related CO2 emissions using
a modified Option 1. Refer to proposed 40 CFR part 98, subpart C for
procedures to estimate combustion-related CO2,
CH4 and N2O emissions.
The proposed monitoring method requires facilities to use default
stoichiometric emission factors (either 0.097 for trona consumed (ratio
of ton of CO2 emitted for each ton of trona) or 0.138 for
soda ash produced (ratio of ton of CO2 emitted for each ton
of natural soda ash produced)) and to measure the fractional purity of
the trona or soda ash. These factors are then applied to the estimated
quantity of raw material input or the amount of soda ash output. Raw
material input and output quantities are assumed to be readily
available to facilities. In order to assess the fractional purity of
trona or soda ash (as determined by the level of the inorganic carbon
present), we propose that facilities test samples of trona using in-
house TOC analyzers or test samples of soda ash for inorganic carbon
expressed as total alkalinity using applicable test methods. We are
assuming that soda ash facilities are conducting daily tests of
fractional purity and can develop monthly averages from daily tests.
This methodology was chosen because it would be more accurate than
methods using default factors for fractional purity.
We decided against applying a default emission factor and a default
adjustment factor of 0.9 to either the total amount of trona consumed
or soda ash produced. According to IPCC, the stoichiometric ratio used
in the default emission factor equation is an exact number and assumes
100 percent purity of the input or output and the uncertainty of the
default emission factor is negligible. However, simple application of
default emission and adjustment factors would not take into account the
actual fractional purities of either the trona input or soda ash
output.
We also decided against proposing the second option to determine an
annual site-specific emission factor. The stack from the calciner
(kiln) emits CO2 emissions from both combustion- and
process-related sources. An annual stack test would not capture the
variability in stationary combustion emissions associated with
consumption of various types of fuels, so would not significantly
reduce the uncertainty for developing annual estimates of
CO2 emissions. While not improving emissions estimates
significantly, annual stack testing would be burdensome to industry. We
have concluded that measuring fractional purity, as described in the
proposed modified Option 1 approach, would improve emissions estimates,
with a minimal cost burden.
The third option we considered, but did not select as the proposed
option, was continuous direct measurement of emissions from soda ash
manufacturing. This option is consistent with the 2006 IPCC Guidelines
Tier 3 method. Use of a CO2 CEMS would eliminate the need
for further periodic review because this method would account for the
variability in GHG emissions due to changes in the process or operation
over time. While this method does tend to provide the most accurate
CO2 emissions measurements and can
[[Page 16549]]
measure both the combustion- and process-related CO2
emissions, it is likely the costliest of all the monitoring methods.
Installation of CEMS would require significant additional burden to
facilities given that few soda ash facilities currently have
CO2 CEMS.
The various options of monitoring GHG emissions, as well as the
domestic and international GHG monitoring guidelines and protocols
researched, are elaborated in the Soda Ash Manufacturing TSD (EPA-HQ-
OAR-2008-0508-029).
4. Selection of Procedures for Estimating Missing Data
We propose that no missing data procedures would apply to
estimating CO2 process emissions because the calculations
are based on production, or trona consumption, which are closely
tracked production inputs and outputs. Given that the fractional purity
would have to be tested on a daily basis, if a value is missing the
test should be repeated. Therefore, 100 percent data availability would
be required.
5. Selection of Data Reporting Requirements
We propose that reported data include annual CO2 process
emissions from each soda ash manufacturing line, and the number of soda
ash manufacturing lines, as well as any stationary fuel combustion
emissions. In addition, we propose that facilities report the following
data for each soda ash manufacturing line: Annual soda ash production,
annual soda ash production capacity, annual trona quantity consumed,
fractional purity (i.e., inorganic carbon content) of the trona or soda
ash, and number of operating hours in the calendar year. These
additional data, most of which are used as a basis for calculating
emissions, are needed to understand the emissions data, verify the
reasonableness of the reported emissions, and identify outliers. A full
list of data that would be reported is included in proposed 40 CFR part
98, subparts A and CC.
6. Selection of Records That Must Be Retained
We propose that facilities keep information on monthly production
of soda ash (metric tons), monthly consumption of trona (metric tons),
and daily fractional purity (i.e., inorganic carbon content) of the
trona or soda ash. A full list of records that must be retained onsite
is included in the proposed rule.
DD. Sulfur Hexafluoride (SF6) From Electrical Equipment
1. Definition of the Source Category
The largest use of SF6, both in the U.S. and
internationally, is as an electrical insulator and interrupter in
equipment that transmits and distributes electricity. The gas has been
employed by the electric power industry in the U.S. since the 1950s
because of its dielectric strength and arc-quenching characteristics.
It is used in gas-insulated substations, circuit breakers, other
switchgear, and gas-insulated lines. SF6 has replaced
flammable insulating oils in many applications and allows for more
compact substations in dense urban areas. Currently, there are no
available substitutes for SF6 in this application. For
further information, see the SF6 from Electrical Equipment
TSD (EPA-HQ-OAR-2008-0508-030).
Fugitive emissions of SF6 can escape from gas-insulated
substations and switch gear through seals, especially from older
equipment. The gas can also be released during equipment manufacturing,
installation, servicing, and disposal.
PFCs are sometimes used as dielectrics and heat transfer fluids in
power transformers. PFCs are also used for retrofitting CFC-113 cooled
transformers. One PFC used in this application is perfluorohexane
(C6F14). In terms of both absolute and carbon-
weighted emissions, PFC emissions from electrical equipment are
generally believed to be much smaller than SF6 emissions
from electrical equipment; however, there may be some exceptions to
this pattern, according to the 2006 IPCC Guidelines.
According to the 2008 U.S. Inventory, total U.S. estimated
emissions of SF6 from an estimated 1,364 electric power
system utilities \86\ were 12.4 million metric tons CO2e in
2006. We do not have an estimate of PFC emissions.
---------------------------------------------------------------------------
\86\ The estimated total number of electric power system (EPS)
utilities includes all companies participating in the SF6
Emission Reduction Partnership for Electric Power Systems and the
number includes non-partner utilities with non-zero transmission
miles. The estimated total number of EPS utilities that emit
SF6 likely underestimates the population, as some
utilities may own high-voltage equipment yet not own transmission
miles. However, the estimated number is consistent with the U.S.
inventory methodology, in which only non-partner utilities with non-
zero transmission miles and partner utilities are assumed to emit
SF6.
---------------------------------------------------------------------------
This source category comprises electric power transmission and
distribution systems that operate gas-insulated substations, circuit
breakers, and other switchgear, or power transformers containing
sulfur-hexafluoride (SF6) or PFCs.
2. Selection of Reporting Threshold
We propose to require electric power systems to report their
SF6 and PFC emissions if the total nameplate capacity of
their SF6-containing equipment exceeds 17,820 lbs of
SF6. This threshold is equivalent to an emissions threshold
of 25,000 metric tons CO2e, and was developed using
historical (1999) data from utilities that participate in EPA's
SF6 Emission Reduction Partnership for Electric Power
Systems (Partnership).
In addition, we considered emission-based threshold options of
1,000 metric tons CO2e; 10,000 metric tons CO2e;
and 100,000 metric tons CO2e. Nameplate capacity thresholds
of 713; 7,128; and 71,280 lbs of SF6 for all utilities were
also considered, corresponding to the emission threshold options of
1,000; 10,000; and 100,000 metric tons CO2e, respectively.
Summaries of the threshold options (capacity-based and emissions-based)
and the number of utilities and emissions falling above each threshold
are presented in Tables DD-1 and DD-2 of this preamble.
Table DD-1. Options for Capacity-Based Thresholds for Electric Power Systems
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
Nameplate capacity threshold for all utilities (lbs emissions Total number ---------------------------------------------------------------
SF6) MMTCO2e/yr of facilities MMTCO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
713..................................................... 12.4 1,364 12.19 98 578 42
7,128................................................... 12.4 1,364 10.96 88 183 13
17,820.................................................. 12.4 1,364 10.32 83 141 10
71,280.................................................. 12.4 1,364 5.95 48 35 3
--------------------------------------------------------------------------------------------------------------------------------------------------------
[[Page 16550]]
Table DD-2. Options for Emissions-Based Thresholds for Electric Power Systems
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
Threshold level metric tons CO2e/yr emissions Total number ---------------------------------------------------------------
MMTCO2e/yr of facilities MMTCO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 12.4 1,364 12.20 98 564 41
10,000.................................................. 12.4 1,364 10.87 88 158 12
25,000.................................................. 12.4 1,364 10.11 82 111 8
100,000................................................. 12.4 1,364 5.84 47 27 2
--------------------------------------------------------------------------------------------------------------------------------------------------------
We selected a nameplate capacity threshold equivalent to the 25,000
metric tons CO2e emissions threshold level. A capacity-based
threshold was selected because it permits utilities to quickly
determine whether they are covered. There have been many mergers and
acquisitions in the electric power industry and nameplate capacity is
generally a known variable as a result of these transactions.
The proposed threshold is consistent with the threshold for other
source categories. Based on information from the Partnership and from
the Universal Database Interface Directory of Electric Power Producers
and Distributors, we estimate that the nameplate capacity threshold
covers only a small percentage of total utilities (10 percent or 141
utilities), while covering the majority of annual emissions
(approximately 83 percent).
Other Options Considered. We considered setting a threshold based
on the length of the transmission lines, defined as the miles of lines
carrying voltages above 34.5 kV, owned by electric power systems. The
transmission-mile threshold equivalent to 25,000 metric tons
CO2e is 1,186 miles. The fractions of utilities and
emissions covered by this threshold would be almost identical to those
covered by the nameplate-capacity threshold.
We decided not to propose the transmission-mile threshold because
the relationship between emissions and transmission miles, while
strong, is not as strong as that between emissions and nameplate
capacity. On the one hand, some utilities have far larger nameplate
capacities and emissions than would be expected based on their
transmission miles. This is the case for some urban utilities that have
large volumes of SF6 in gas-insulated switchgear. On the
other hand, some utilities have lower nameplate capacities and
emissions than would be expected based on their transmission miles,
because most of their transmission lines use lower voltages than
average and therefore typically use less SF6 than average as
well.
Additional information supporting the selection of the threshold
can be found in the SF6 from Electrical Equipment TSD (EPA-
HQ-OAR-2008-0508-030). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
In developing the proposed approach, we reviewed the 2006 IPCC
Guidelines, the SF6 Emissions Reduction Partnership for
Electric Power Systems, the U.S. GHG Inventory, DOE 1605(b), EPA's
Climate Leaders Program, and TCR. In the IPCC Guidelines, Tiers 1 and 2
are based on default SF6 and PFC emission factors, but Tier
3 is based on using utility-specific information to estimate emissions
of both SF6 and PFC using a mass-balance analysis.
The proposed monitoring methods for calculating SF6 and
PFC emissions from electric power systems are similar to the
methodologies described in EPA's SF6 Emission Reduction
Partnership for Electric Power Systems (Partnership) Inventory
Reporting Protocol and Form and the 2006 IPCC Guidelines Tier 3 methods
for emissions from electrical equipment. In general, these protocols
and guidance all support using a mass-balance approach as the most
accurate alternative to estimate emissions.
We propose that you report all SF6 and PFC emissions,
including those from equipment installation, equipment use, and
equipment decommissioning and disposal. This requirement would apply
only to systems where the total nameplate capacity of their
SF6-containing equipment exceeds 17,820 lbs of
SF6. The Tier 3 approach is being proposed because it is the
most accurate and it is feasible for all systems to conduct the mass
balance analysis for SF6 and PFC using readily available
information.
The mass-balance approach works by tracking and systematically
accounting for all facility uses of SF6 and PFC during the
reporting year. The quantities of SF6 and PFC that cannot be
accounted for are assumed to have been emitted to the atmosphere. The
emissions of SF6 and PFC would be estimated and reported
separately.
The following equation describes the proposed utility-level mass-
balance approach:
User Emissions = Decrease in SF6 Inventory +
Acquisitions of SF6-Disbursements of SF6-Net
Increase in Total Nameplate Capacity of Equipment
Where:
Decrease in SF6 Inventory is SF6 stored in containers
(but not in equipment) at the beginning of the year minus
SF6 stored in containers (but not in equipment) at the
end of the year.
Acquisitions of SF6 is SF6 purchased from
chemical producers or distributors in bulk + SF6
purchased from equipment manufacturers or distributors with or
inside of equipment + SF6 returned to site after off-site
recycling.
Disbursements of SF 6 is SF6 in bulk and contained in
equipment that is sold to other entities + SF6 returned
to suppliers + SF6 sent off-site for recycling +
SF6 sent to destruction facilities.
Net Increase in Total Nameplate Capacity of Equipment is the
Nameplate capacity of new equipment minus Nameplate capacity of
retiring equipment. (Note that Nameplate capacity refers to the full
and proper charge of equipment rather than to the actual charge,
which may reflect leakage.)
The same method is being proposed to estimate emissions of PFCs
from power transformers.
Other Options Considered. We also considered the IPCC Tier 1 and
the IPCC Tier 2 methods for calculating and reporting SF6
and PFC emissions, but did not choose them for several reasons.
Although the IPCC Tier 1 method is simpler, the default emission
factors have large uncertainty due to variability associated with
handling and management practices, age of equipment, mix of equipment,
and other similar factors. Utilities participating in EPA's Partnership
have reduced their emission factors to less than Tier 1 default values.
Less than 10 percent of U.S. utilities participate in this program;
however, these utilities represent close to 40 percent of the U.S.
grid, so the IPCC Tier 1 emission factors are not
[[Page 16551]]
accurate for a large percentage of the U.S. source category.
IPCC Tier 2 methods use country-specific emission factors, but the
Partner utilities have demonstrated by calculating their own utility-
level emission rates that large variability exists in utility-level
emission rates across the nation (i.e., emission rates range from less
than one percent of a utility's SF6 inventory to greater
than 35 percent). As a result, we are not proposing the IPCC Tier 2
method.
4. Selection of Procedures for Estimating Missing Data
It is expected that utilities should have 100 percent of the data
needed to perform the mass balance calculations for both SF6
and PFCs. Partner utilities missing inputs to the mass-balance approach
have estimated emissions using other methods, such as assuming that all
purchased SF6 is emitted. However, this method over-
estimates emissions, and we do not recommend this method of estimation
in the absence of more complete data. The use of the mass-balance
approach requires correct records for all inputs.
5. Selection of Data Reporting Requirements
We propose annual reporting for facilities in the electric power
systems industry. Each facility would report all SF6 and PFC
emissions, including those from equipment installation, equipment use,
and equipment decommissioning and disposal. However, the emissions
would not need to be broken down and reported separately for
installation, use or disposal. Along with their emissions, utilities
would be required to submit the following supplemental data, nameplate
capacity (existing as of the beginning of the year, new during the
year, and retired during the year), transmission miles, SF6
and PFC sales and purchases, SF6 and PFC sent off-site for
destruction or to be recycled, SF6 and PFC returned from
offsite after recycling, SF6 and PFC stored in containers at
the beginning and end of the year, SF6 and PFC with or
inside new equipment purchased in the year, SF6 and PFC with
or inside equipment sold to other entities and SF6 and PFC
returned to suppliers.
These data would be submitted because they are the minimum data
that are needed to understand and reproduce the emission calculations
that are the basis of the reported emissions. Transmission miles would
be included in the reported data so that the reasonableness of the
reported emissions could be quickly checked using default emission
factors.
6. Selection of Records That Must Be Retained
We propose that electric power systems be required to keep records
documenting (1) their adherence to the QA/QC requirements specified in
the proposed rule, and (2) the data that would be included in their
emission reports, as specified above. The QA/QC requirements records
include check-out sheets and weigh-in procedures for cylinders,
residual gas amounts in cylinders sent back to suppliers, invoices for
gas and equipment purchases or sales, and records of equipment
nameplate capacity. The records that are being proposed are the minimum
needed to reproduce and confirm emission calculations.
EE. Titanium Dioxide Production
1. Definition of the Source Category
Titanium dioxide is a metal oxide commonly used as a white pigment
in paint manufacturing, paper, plastics, rubber, ceramics, fabrics,
floor covering, printing ink, and other applications. The majority of
TiO2 production is for the manufacturing of white paint.
National production of TiO2 in 2006 was approximately
1,400,000 metric tons.
Titanium dioxide is produced through two processes: The chloride
process and the sulfate process. According to USGS, most facilities in
the U.S. employ the chloride process. Total U.S. production of titanium
dioxide pigment through the chloride process was approximately 1.4
metric tons in 2006, a 7 percent increase compared to 2005. The
chloride process emits process-related CO2 through the use
of petroleum coke and chlorine as raw materials, while the sulfate
process does not emit any significant process-related GHGs.
The chloride process is based on two chemical reactions. Petroleum
coke (C) is oxidized as the reducing agent in the first reaction in the
presence of chlorine and crystallized iron titanium oxide
(FeTiO3) to form and emit CO2. A special grade of
petroleum coke, known as calcined petroleum coke, is a highly
electrically conductive carbon (fixed carbon content >98 percent) and
is used in several manufacturing processes including titanium dioxide
(in the chloride process), aluminum, graphite, steel, and other carbon
consuming industries. For the purposes of this rulemaking effort EPA is
assuming the carbon content factor for calcined petroleum coke is 100
percent or a multiplier of 1. Therefore, no site-specific factor needs
to be determined. The titanium tetrachloride (TiCl4)
produced through this first reaction is oxidized with oxygen at about
1,000 [deg]C, and calcinated in a second reaction to remove residual
chlorine and any hydrochloric acid that may have formed in the reaction
producing titanium dioxide (TiO2).
National emissions from titanium dioxide production were estimated
to be 3.6 million metric tons CO2e in 2006. These emissions
include process-related (CO2) and on-site stationary
combustion emissions (CO2, CH4, and
N2O) from eight production facilities. Process-related
emissions from titanium dioxide production were 1.87 million metric
tons CO2e or 47 percent of the total, while on-site
combustion emissions account for the remaining 1.8 million metric tons
CO2e emissions in 2006.
For additional background information on titanium dioxide
production, please refer to the Titanium Dioxide Production TSD (EPA-
HQ-OAR-2008-0508-031).
2. Selection of Reporting Threshold
In developing the threshold for titanium dioxide production, we
considered an emissions-based threshold of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e. Table EE-1 of
this preamble illustrates the emissions and facilities that would be
covered under these various thresholds.
Table EE-1. Threshold Analysis for Titanium Dioxide Production
----------------------------------------------------------------------------------------------------------------
Emissions covered Facilities covered
Threshold level metric tons Total national Total ------------------------------------------------------
CO2e/yr emissions number of Metric tons
facilities CO2e/yr Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000....................... 3,685,777 8 3,685,777 100 8 100
10,000...................... 3,685,777 8 3,685,777 100 8 100
25,000...................... 3,685,777 8 3,685,777 100 8 100
[[Page 16552]]
100,000..................... 3,685,777 8 3,628,054 98 7 88
----------------------------------------------------------------------------------------------------------------
At the threshold levels of 1,000 metric tons CO2e,
10,000 metric tons CO2e, and 25,000 metric tons
CO2e, all facilities exceed the threshold, therefore
covering 100 percent of total emissions. At the 100,000 metric tons
CO2e level, one facility would not exceed the threshold and
98 percent of emissions would be covered. In order to simplify the
rule, and avoid the need for the source to calculate and report whether
the facility exceeds threshold value, we are proposing that all
titanium dioxide production facilities report. Including all facilities
simplifies the rule and ensures 100 percent coverage without
significantly increasing the number of affected facilities expected to
report relative to the 25,000 metric ton threshold.
For a full discussion of the threshold analysis, please refer to
the Titanium Dioxide Production TSD (EPA-HQ-OAR-2008-0508-031). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating process-related
emissions from titanium dioxide production (e.g., the 2006 IPCC
Guidelines, U.S. GHG Inventory, Australian Government's National
Greenhouse and Energy Reporting System). These methods coalesce around
two different options.
Option 1. CO2 emissions are estimated by applying a
default emission factor to annual facility level titanium dioxide
production.
Option 2. CO2 emissions are estimated based on the
facility-specific quantity of reducing agents or calcined petroleum
coke consumed.
Option 3. Direct measurement of emissions using CEMS.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Where the CEMS capture all combustion- and
process-related CO2 emissions you would be required to
follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of proposed 40 CFR part 98, subpart C to estimate
CO2 emissions. Also, refer to proposed 40 CFR part 98,
subpart C to estimate combustion-related CH4 and
N2O emissions.
Under this proposed rule, if you do not have CEMS that meet the
conditions outlined in proposed 40 CFR part 98, subpart C, we propose
that facilities use the second option discussed above to estimate
process-related CO2 emissions. Refer to proposed 40 CFR part
98, subpart C specifically for procedures to estimate combustion-
related CO2, CH4 and N2O emissions.
Under this approach the total amount of calcined petroleum coke
consumed would be assumed to be directly converted into CO2
emissions. The amount of calcined petroleum coke can be obtained from
facility records, as that data would be readily available. The carbon
oxidation factor for the calcined petroleum coke is assumed to be 100
percent, because any amount that is not oxidized is an insignificant
amount. For the purposes of this rulemaking effort EPA is assuming the
carbon oxidation factor for calcined petroleum coke, is equal to 100/
100 or 1. Therefore, no site-specific factor needs to be determined.
We decided not to propose the option to use continuous direct
measurement because it would not lead to significantly reduced
uncertainty in the emissions estimate over the proposed option.
Furthermore, the cost impact of requiring the installation of CEMS is
high in comparison to the relatively low amount of emissions that would
be quantified from the titanium production sector.
We decided not to propose the option to apply default emission
factors to titanium dioxide production to quantify process-related
emissions. Although default emissions factors have been developed for
quantifying process-related emissions from titanium dioxide production,
the use of these default values is more appropriate for sector wide or
national total estimates than for determining emissions from a specific
plant. Estimates based on site-specific consumption of reducing agents
are more appropriate for reflecting differences in process design and
operation. According to the 2006 IPCC Guidelines, the uncertainty
associated with the proposed approach is much lower given that
facilities closely track consumption of the calcined petroleum coke
(accurate within 2 percent), whereas the uncertainty associated with
the default emission factor is approximately 15 percent.
The various approaches to monitoring GHG emissions are elaborated
in the Titanium Dioxide Production TSD (EPA-HQ-OAR-2008-0508-031).
4. Selection of Procedures for Estimating Missing Data
It is assumed that a facility would be able to supply data on
annual calcined petroleum coke consumption data. Therefore, 100 percent
data availability is required for all parameters.
5. Selection of Data Reporting Requirements
We propose that facilities submit process-related CO2
emissions on an annual basis, as well as any stationary fuel combustion
emissions. In addition we propose that facilities report the following
additional data used as the basis of the calculations to assist in
verification of estimates, checks for reasonableness, and other data
quality considerations. The data includes: annual production of
titanium dioxide, annual amount of calcined petroleum coke consumed,
and number of operating hours in the calendar year. Facilities are not
required to submit carbon oxidation factor for calcined petroleum coke;
this value is assumed to be 100 percent, as any amount that is not
oxidized is assumed to be an insignificant amount. A full list of data
to be reported is included in proposed 40 CFR part 98, subparts A and
EE.
6. Selection of Records That Must Be Retained
In addition to the data reported, we propose that facilities
maintain records of monthly production of titanium dioxide and monthly
amounts of calcined petroleum coke consumed. These records hold values
that are directly used to calculate the emissions
[[Page 16553]]
that are reported and are necessary to allow determination of whether
GHG emissions monitoring and calculations were done correctly. They
also are needed to understand the emissions data and verify the
reasonableness of the reported emissions and identify potential
outliers.
A full list of records that must be retained onsite is included in
proposed 40 CFR part 98, subparts A and EE.
FF. Underground Coal Mines
1. Definition of the Source Category
Coal mining can produce significant amounts of CH4 from
the following areas and activities: Active underground coal mines,
surface coal mines, post-coal mining activities and abandoned
underground coal mines.
An active underground coal mine is a mine at which coal is produced
by tunneling into the earth to a subsurface coal seam, which is then
mined with equipment such as cutting machines, extracted and
transported to the surface. In underground mines, CH4 is
released from the coal and surrounding rock strata due to mining
activities, and can create an explosive hazard. Ventilation systems
dilute in-mine concentrations to within safe limits, and exhaust
CH4 to the atmosphere.
Mines that produce large amounts of CH4 also rely on
degasification (or ``drainage'') systems to remove CH4 from
the coal seam in advance of, during, or after mining, producing high-
concentration CH4 gas.
CH4 from degasification and ventilation systems can be
liberated to the atmosphere or destroyed. Destroyed CH4
includes, but is not limited to, CH4 combusted by flaring,
CH4 destroyed by thermal oxidation, CH4 combusted
for use in onsite energy or heat production technologies,
CH4 that is conveyed through pipelines (including natural
gas pipelines) for offsite combustion, and CH4 that is
collected for any other onsite or offsite use as a fuel.
At surface mines, CH4 in the coal seams is directly
exposed to the atmosphere.
Post coal mining activities release emissions as coal continues to
emit CH4 as it is stored in piles, processed, and
transported.
At abandoned (closed) underground coal mines, CH4 from
the coal seam and mined-out area may vent to the atmosphere through
fissures in rock strata or through incompletely sealed boreholes. It is
possible to recover and use the CH4 stored in abandoned coal
mines.
Total U.S. CH4 emissions from active mining operations
in 2006 were estimated to be 58.5 million metric tons CO2e
from these sources. Of this, active underground mines accounted for 61
percent of emissions, or 35.9 million metric tons CO2e,
surface mines accounted for 24 percent of emissions, or 14.0 million
metric tons CO2e, and post-mining emissions accounted for 15
percent, or 8.6 million metric tons CO2e. CH4
emissions from abandoned (closed) underground coal mines were estimated
to contribute another 5.4 million metric tons CO2e. On-site
stationary fuel combustion emissions at coal mining operations
accounted for an estimated 9.0 million metric tons CO2e
emissions in 2006. Proposed requirements for stationary fuel combustion
emissions are set forth in proposed 40 CFR part 98, subpart C.
We propose to require reporting of emissions from ventilation and
degasification systems at active underground mines in this rule. This
includes the fugitive CH4 from these systems and also
CO2 emissions from destruction of coal mine gas
CH4, where the gas is not a fuel input for energy generation
or use. Due to difficulties associated with obtaining accurate
measurements from surface mines, post-mining activities, and abandoned
(closed) mines, and in some cases, difficulties in identifying owners
of these sources, we propose to exclude fugitive CH4
emissions from these sources from this rule. These sources could still
surpass the threshold for stationary fuel combustion activities and
therefore be required to report stationary fuel combustion-related
emissions.
Although fugitive CO2 may be emitted from coal seams, it
is not typically a significant source of emissions from U.S. coal seams
compared to CH4. Furthermore, methodologies are not widely
available to measure these emissions, and therefore they are not
proposed for inclusion in this rule.
For additional background information on coal mining, please refer
to the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
2. Selection of Reporting Threshold
In developing the threshold for active underground coal mines, we
considered emissions-based thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e for total
onsite emissions from stationary fuel combustion, ventilation, and
degasification. We also considered requiring all coal mines for which
CH4 emissions from the ventilation system are sampled
quarterly by the MSHA to report under this proposal. Table FF-1 of this
preamble illustrates the emissions and facilities that would be covered
under these various thresholds.
Table FF-1. Threshold Analysis for Coal Mining at Active Underground Coal Mines
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr (metric tons of facilities Metric tons
CO2e) CO2e/yr Percent Facilities Percent
------------------------------------------------------------------------------------------------------------------------------------------
MSHA reporting............................ 39,520,000 612 33,945,956 86 128 21
1,000..................................... 39,520,000 612 33,945,446 86 125 20
10,000.................................... 39,520,000 612 33,926,526 86 122 20
25,000.................................... 39,520,000 612 33,536,385 85 100 16
100,000................................... 39,520,000 612 31,054,856 79 53 9
--------------------------------------------------------------------------------------------------------------------------------------------------------
We propose that all active underground coal mines for which
CH4 from the ventilation system is sampled quarterly by MSHA
(or on a more frequent basis), are required to report under this rule.
MSHA conducts quarterly testing of CH4 concentration and
flow at mines emitting more than 100,000 cf CH4 per day. We
selected this threshold because subjecting underground mine operators
to a new emissions-based threshold is unnecessarily burdensome, as many
of these mines are already subject to MSHA regulations. The MSHA
threshold for reporting of 100,000 cf CH4 per day covers
approximately 94 percent of the CH4 emitted from underground
coal mine ventilation systems and about 86 percent of total emissions
from underground mining
[[Page 16554]]
(including stationary fuel combustion emissions at mine sites, as shown
in Table FF-1 of this preamble).
For additional background information on the thresholds for coal
mining, please refer to the Underground Coal Mines TSD (EPA-HQ-OAR-
2008-0508-032). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating CH4 emissions
from coal mining (e.g., the 2006 IPCC Guidelines, U.S. GHG Inventory,
DOE 1605(b), and Australia's National Greenhouse Gas and Energy
Reporting System). These methodologies coalesce into three different
approaches.
Option 1. Engineering approaches, whereby default emission factors
would be applied to total annual coal production (for ventilation
systems), or emission factors associated with the system type (for
degasification systems) to estimate fugitive emissions.
Option 2. Periodic sampling of CH4. Quarterly or more
frequent samples could be taken in order to develop a site-specific
emission factor.
Option 3. Use of CEMS.
Proposed Option for Liberated Ventilation CH4. We propose Option 2,
quarterly sampling of ventilation air for monitoring ventilation
CH4 liberated from coal mines.
Under this option, coal mine operators are required to either (a)
independently collect quarterly samples of CH4 released from
the ventilation system(s), using MSHA procedures, have these samples
analyzed for CH4 composition, and report the results to us,
or (b) to obtain the results from the quarterly testing that MSHA
already conducts, and report those to EPA.
MSHA inspectors currently perform quarterly mine safety inspections
on mines emitting 100,000 cf CH4 or more per day, and as
part of these inspections, the inspectors test CH4 emissions
rates and ventilation shaft flow, using MSHA-approved sampling
procedures and devices. The sample bottles are sent to the MSHA lab for
analysis and the results are provided back to the MSHA district offices
for inclusion in the inspection report. Currently, the results of these
quarterly measurements are generally not provided back to the mine.
We would like to take comment on whether relying on MSHA sampling
procedures,\87\ which were developed to ensure adherence to safety
standards, is appropriate and sufficiently accurate for a GHG emissions
reporting program. Further, we are interested in viewpoints on whether
quarterly sampling is sufficient to account for potential fluctuations
in emissions over smaller time increments (e.g., daily) from the mine.
For more information on the MSHA sampling procedures, please refer to
the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
---------------------------------------------------------------------------
\87\ NIOSH, Handbook for Methane Control in Mining, CDC
Information Circular 9486, June 2006.
---------------------------------------------------------------------------
For all ventilation systems with CH4 destruction,
CH4 destruction would be monitored through direct
measurement of CH4 flow to combustion devices with
continuous flow monitoring systems. The resulting CO2
emissions would be calculated from these monitored values. If
CH4 from ventilation systems is destroyed, such a system
would have sufficient continuous monitoring devices associated with it
that such required monitoring would not propose any additional burden.
We considered requiring mines to monitor ventilation CH4
concentrations by daily sampling, in place of quarterly sampling, for
this rule. Many mines sample CH4 daily from ventilation
systems using handheld CH4 analyzers. The primary advantages
of this option are that many mines already take these measurements and
this would therefore not impose an additional monitoring burden, and
that daily measurements of CH4 concentration and ventilation
shaft flowrates could allow for more accurate annual estimates than
quarterly measurements. The primary disadvantages of this option
relative to the other options that were considered are that it is not
as accurate as continuous emissions measurements, and that, if
required, it would impose a cost burden for those mines that do not
already have a daily sampling and monitoring program in place.
We also decided against requiring mines with CEMS installed at
ventilation systems to use the continuous monitoring devices to monitor
ventilation system CH4 emissions. Mines without CEMS would
follow the quarterly option proposed above. In many underground mines,
CEMS devices are already in operation. In such cases, this option may
involve only placing such devices at or near the mine vent outflows
where the air samples are taken by MSHA inspectors. The primary
advantage of continuous monitoring is that it could increase the
accuracy of annual CH4 emissions calculations because it
takes into consideration any variability in emissions from mining
operations that may not be represented in the quarterly sampling.
Moreover, since such devices are already used within the mine to assess
safety conditions, mine operator personnel are familiar with their
operation. The disadvantage in requiring CEMS installation would be the
larger costs associated with purchasing and maintaining these devices.
We seek comment on the accuracy and cost of monitoring ventilation
emissions with CEMS.
Finally, we decided not to propose Option 1, which applies default
emission factors to coal production. We decided against the use of the
default CH4 emission factors because their application is
more appropriate for GHG estimates from aggregated process information
on a sector-wide or national basis than for determining GHG emissions
from specific mines.
Proposed Option for Degasification. We propose that all coal mine
operators subject to this rule that deploy degasification systems in
underground mines install continuous monitors for CH4
content and flowrates on all degasification wells or degasification
vent holes, and that all CH4 liberated and CH4
destroyed from these systems be reported (Option 3). For all systems
with CH4 destruction, CH4 destruction would be
monitored through direct measurement of CH4 flow to
combustion devices with continuous monitoring systems. The resulting
CO2 emissions would be calculated from these monitored
values. Option 3 is consistent with current practices for
CH4 that is destroyed, where the produced gas volume is
presumably already being measured with continuous monitors. For gas
that is simply vented to the atmosphere from degasification wells, this
requirement would ensure that this gas is accurately measured.
We considered, but are not proposing, Option 1, which would
estimate CH4 emissions based on the type of degasification
system employed. For example, in developing the U.S. GHG Inventory, we
currently assume for selected mines that degasification emissions
account for 40 percent of total CH4 liberated from the mine.
This method is very simplistic and least costly, but there is
relatively larger uncertainty associated with the emissions estimated.
Considering that emissions from many degasification wells are currently
monitored, and the need to characterize the quantity of these vented
emissions more accurately, we do not believe this option is
appropriate.
[[Page 16555]]
We also considered, but are not proposing, Option 2, which would
require mine operators to conduct periodic sampling of gob gas vent
holes and any other degasification boreholes, rather than installing
continuous monitoring. While such an approach would involve lower
capital costs than CEMS, greater labor costs would be involved with
traveling to each (often remote) well site to take samples. Moreover,
this method would not accurately reflect fluctuations in gas quantity
and CH4 concentration. Pre-mining degasification and gob
wells are generally characterized by large variations in emissions over
time, as emissions can decline rapidly in each individual well, while
new wells/vents come on line as mining advances.
The various approaches to monitoring GHG emissions are elaborated
in the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
4. Selection of Procedures for Estimating Missing Data
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation) a substitute data value for the
missing parameter shall be used in the calculations.
For each missing value of CH4 concentration, flow rate,
temperature, and pressure for ventilation and degassification systems,
the substitute data value shall be the arithmetic average of the
quality-assured values of that parameter immediately preceding and
immediately following the missing data incident. If, for a particular
parameter, no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
5. Selection of Data Reporting Requirements
We propose that coal mines report, for all ventilation shafts and
degasification systems (e.g., all boreholes), the following parameters:
CH4 liberated from the shaft or borehole, the quantity of
CH4 destroyed (if applicable), and net CH4
emissions on an annual basis. In addition to reporting emissions, all
input data needed to calculate liberation and emissions are to be
reported, as well as mine days of operation (for the ventilation and
degasification systems). A full list of data to be reported is
includedproposed 40 CFR part 98, subparts A and FF.
6. Selection of Records That Must Be Retained
Reporters are to retain all data listed in Section V.FF.5 of this
preamble. A full list of records to be retained onsite is included in
proposed 40 CFR part 98, subparts A and FF.
GG. Zinc Production
1. Definition of the Source Category
Zinc is a metal used as corrosion-protection coatings on steel
(galvanized metal), as die castings, as an alloying metal with copper
to make brass, and as chemical compounds in rubber, ceramics, paints,
and agriculture. For this proposed rule, we are defining the zinc
production source category to consist of zinc smelters using
pyrometallurgical processes and secondary zinc recycling facilities.
Zinc smelters can process zinc sulfide ore concentrates (primary zinc
smelters) or zinc-bearing recycled and scrap materials (secondary zinc
smelters). A secondary zinc recycling facility recovers zinc from zinc-
bearing recycled and scrap materials to produce crude zinc oxide for
use as a feed material to zinc smelters. Many of these secondary zinc
recycling facilities have been built specifically to process dust
collected from electric arc furnace operations at steel mini-mills
across the country.
There are no primary zinc smelters in the U.S. that use
pyrometallurgical processes. The one operating U.S. pyrometallurgical
zinc smelter processes crude zinc oxide and calcine produced from
recycled zinc materials. These feed materials are first processed
through a sintering machine. The sinter is mixed with metallurgical
coke and fed directly into the top of an electrothermic furnace.
Metallic zinc vapor is drawn from the furnaces into a vacuum condenser,
which is then tapped to produce molten zinc metal. The molten metal is
then transferred directly to a zinc refinery or cast into zinc slabs.
Secondary zinc recycling facilities operating in the U.S. use
either of two thermal processes to recover zinc from recycled electric
arc furnace dust and other scrap materials. For the Waelz kiln process,
the feed material is charged to an inclined rotary kiln together with
petroleum coke, metallurgical coke, or anthracite coal. The zinc oxides
in the gases from the kiln are then collected in a baghouse or
electrostatic precipitator. The second recovery process used for
electric arc furnace dust uses a water-cooled, flash-smelting furnace
to form vaporized zinc that is subsequently captured in a vacuum
condenser. The crude zinc oxide produced at secondary zinc recycling
facilities is shipped to a zinc smelter for further processing.
Zinc production results in both combustion and process-related GHG
emissions. The major sources of GHG emissions from a zinc production
facility are the process-related emissions from the operation of
electrothermic furnaces at zinc smelters and Waelz kilns at secondary
zinc recycling facilities. In an electrothermic furnace, reduction of
zinc oxide using carbon provided by the charging of coke to the furnace
produces CO2. In the Waelz kiln, the zinc feed materials are
heated to approximately 1200 [deg]C in the presence of carbon producing
zinc vapor and carbon monoxide (CO). When combined with the surplus of
air in the kiln, the zinc vapors are oxidized to form crude zinc oxide,
and the CO oxidized to form process-related CO2 emissions.
Total nationwide GHG emissions from zinc production facilities
operating in the U.S. were estimated to be approximately 851,708 metric
tons CO2e for the year 2006. This total GHG emissions
estimate includes both process-related emissions (CO2 and
CH4) and the additional combustion emissions
(CO2, CH4, and N2O). Process-related
GHG emissions were approximately 528,777 metric tons CO2e
emissions (62 percent of the total emissions). The remaining 38 percent
or 322,931 metric tons CO2e are from onsite stationary
combustion.
Additional background information about GHG emissions from the zinc
production source category is available in the Zinc Production TSD
(EPA-HQ-OAR-2008-0508-033).
2. Selection of Reporting Threshold
Zinc smelters and secondary zinc recycling facilities in the U.S.
vary in types and sizes of the metallurgical processes used and mix of
zinc-containing feedstocks processed to produce zinc products. In
developing the threshold for zinc production facilities, we considered
using annual GHG emissions-based threshold levels of 1,000, 10,000,
25,000 and 100,000 metric tons CO2e. Table GG-1 of this
preamble illustrates the emissions and facilities that would be covered
under these various thresholds.
[[Page 16556]]
Table GG-1. Threshold Analysis for Zinc Production Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total Emissions covered Facilities covered
nationwide National ---------------------------------------------------------------
Threshold level metric tons CO2e/yr emissions number of
metric tons facilities Metric tons Percent Facilities Percent
CO2e/yr CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 851,708 9 851,708 100 9 100
10,000.................................................. 851,708 9 843,154 99 8 89
25,000.................................................. 851,708 9 801,893 94 5 56
100,000................................................. 851,708 9 712,181 84 4 44
--------------------------------------------------------------------------------------------------------------------------------------------------------
We have concluded, based on emissions estimates using production
capacity, that the one primary zinc facility exceeds all thresholds
considered (Table GG-1 of this preamble). For the eight secondary zinc
production facilities, just half are over a 25,000 metric tons
CO2e threshold. We decided it is appropriate to propose a
threshold of 25,000 metric tons CO2e for reporting emissions
from zinc production facilities that is consistent with the threshold
level being proposed for other source categories. This threshold level
would avoid placing a reporting burden on a zinc production facility
with inherently low GHG emissions because of the type of metallurgical
processes used and type of zinc product produced while still requiring
the reporting of GHG emissions from the zinc production facilities
releasing most of the GHG emissions in the source category. More
discussion of the threshold selection analysis is available in the Zinc
Production TSD (EPA-HQ-OAR-2008-0508-033). For specific information on
costs, including unamortized first year capital expenditures, please
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
EPA reviewed existing domestic and international GHG monitoring
guidelines and protocols including the 2006 IPCC Guidelines, U.S. GHG
Inventory, the EU Emissions Trading System, the Canadian Mandatory GHG
Reporting Program, and the Australian National GHG Reporting Program.
These methods coalesce around the following four options for estimating
process-related GHG emissions from zinc production facilities. Zinc
smelters using hydrometallurgical processes (e.g., electrolysis) would
not be subject to the estimating and reporting requirements in proposed
40 CFR part 98, subpart GG for zinc production because the processes
used at these smelters do not release process-related GHG emissions.
However, combustion GHG emissions from the process equipment at these
smelters burning natural gas or other carbon-based fuels could be
subject to the estimating and reporting requirements for general
stationary fuel combustion units in proposed 40 CFR part 98, subpart C,
depending on the level of total GHG emissions from the facility with
respect to the reporting thresholds specified in proposed 40 CFR part
98, subpart A.
Option 1. Apply a default emission factor for the process-related
emissions to the facility zinc production rate. This is a simplified
emission calculation method using only default emission factors to
estimate CO2 emissions. The method requires multiplying the
amount of zinc produced by the appropriate default emission factors
from the 2006 IPCC Guidelines.
Option 2. Perform a carbon balance of all inputs and outputs using
monthly measurements of the carbon content of specific process inputs
and measure the mass rate of these inputs. This method is the same as
the IPCC Tier 3 approach and the higher order methods in the Canadian
and Australian reporting programs. Implementation of this method
requires owners and operators of affected zinc smelters to determine
the carbon contents of materials added to the electrothermic furnace or
Waelz kiln by analysis of representative samples collected of the
material or from information provided by the material suppliers. In
addition, the quantities of these materials consumed during production
are measured and recorded. To obtain the process-related CO2
emission estimate, the material carbon content would be multiplied by
the corresponding mass of material consumed and a factor for conversion
of carbon to CO2. This method assumes that all of the carbon
is converted during the reduction process. The facility owner or
operator would determine the average carbon content of the material for
each calendar month using information provided by the material supplier
or by collecting a composite sample of material and sending it to an
independent laboratory for chemical analysis.
Option 3. Use CO2 emissions data from a stack test
performed using U.S. EPA reference test methods to develop a site-
specific process emissions factor which is then applied to quantity
measurement data of feed material or product for the specified
reporting period. This monitoring method is applicable to furnace or
Waelz kiln configurations for which the GHG emissions are contained
within a stack or vent. Using site-specific emissions factors based on
short-term stack testing is appropriate for those facilities where
process inputs (e.g., feed materials, carbonaceous reducing agents) and
process operating parameters remain relatively consistent over time.
Option 4. Use direct emissions measurement of CO2
emissions. For furnace and kiln configurations in which the process
off-gases are contained within a stack or vent, direct measurement of
the CO2 emissions can be made by either continuously
measuring the off-gas stream CO2 concentration and flow rate
using a CEMS, or periodically measuring the off-gas stream
CO2 concentration and flow rate using standard stack testing
methods. Using a CEMS, the recorded emissions measurement data would be
reported annually. An annual emissions test could be used to develop a
site-specific process emissions factor which would then be applied to
quantity measurement data of feed material or product for the specified
reporting period.
Proposed Option. Under this proposed rule, if you are required to
use an existing CEMS to meet the requirements outlined in proposed 40
CFR part 98, subpart C, you would be required to use CEMS to estimate
CO2 emissions. Provided that the CEMS capture all
combustion- and process-related CO2 emissions, you would be
required to follow the requirements of proposed 40 CFR part 98, subpart
C to estimate CO2 emissions from the industrial source. You
would also refer to proposed 40 CFR part 98, subpart C to estimate
combustion-related CH4 and N2O emissions.
[[Page 16557]]
If you do not have CEMS that meet the conditions outlined in
proposed 40 CFR part 98, subpart C, or where the CEMS would not
adequately account for process emissions, we propose that you follow
Option 2, a carbon balance. You would still need to refer to proposed
40 CFR part 98, subpart C to estimate combustion-related CH4
and N2O emissions. Given the operating variations between
the individual U.S. zinc production facilities (including differences
in equipment configurations, mix of zinc feedstocks charged, and types
of carbon materials used) we are proposing Option 2 to estimate
CO2 emissions from an electrothermic furnace or Waelz kiln
at zinc production facilities because of the lower uncertainties
indicated by the IPCC Guidelines for these types of emissions
estimates, as compared to applying exclusively a default emissions
factor based approach to these units on a nationwide basis.
We decided not to propose the use of default CO2
emission factors (Option 1) because their application is more
appropriate for GHG estimates from aggregated process information on a
sector-wide or nationwide basis than for determining GHG emissions from
specific facilities. According to the 2006 IPCC Guidelines, the
uncertainty associated with default emission factors could be as high
as 50 percent, while the uncertainty associated with facility specific
estimates of process inputs and carbon contents would be within 5 to 10
percent. We considered the additional burden of the material
measurements required for the carbon calculations small in relation to
the increased accuracy expected from using this site-specific
information to calculate the process-related CO2 emissions.
We also decided against proposing Option 3 because of the potential
for significant variations at zinc production facilities in the
characteristics and quantities of the furnace or Waelz kiln inputs
(e.g., zinc scrap materials, carbonaceous reducing agents) and process
operating parameters. A method using periodic, short-term stack testing
would not be practical or appropriate for those zinc production
facilities where the furnace or Waelz kiln inputs and operating
parameters do not remain relatively consistent over the reporting
period.
Further details about the selection of the monitoring methods for
GHG emissions are available in the Zinc Production TSD (EPA-HQ-OAR-
2008-0508-033).
4. Selection of Procedures for Estimating Missing Data
For electrothermic furnaces or Waelz kilns for which the owner or
operator calculates process GHG emissions using site-specific
carbonaceous input material data, the proposed rule requires the use of
substitute data whenever a quality-assured value of a parameter that is
used to calculate GHG emissions is unavailable, or ``missing.'' If the
carbon content analysis of carbon inputs is missing or lost the
substitute data value would be the average of the quality-assured
values of the parameter immediately before and immediately after the
missing data period. In those cases when an owner or operator uses
direct measurement by a CO2 CEMS, the missing data
procedures would be the same as the Tier 4 requirements described for
general stationary fuel combustion sources in proposed 40 CFR part 98,
subpart C.
5. Selection of Data Reporting Requirements
The proposed rule would require annual reporting of the total
annual CO2 process-related emissions from the electrothermic
furnaces and Waelz kilns at zinc production facilities, as well as any
stationary fuel combustion emissions. In addition we propose that
additional information which forms the basis of the emissions estimates
also be reported so that we can understand and verify the reported
emissions. This additional information includes the total number of
Waelz kilns and electrothermic furnaces operated at the facility, the
facility zinc product production capacity, and the number of facility
operating hours in calendar year, carbon inputs by type, and carbon
contents of inputs by type.
A complete list of data to be reported is included in proposed 40
CFR part 98, subparts A and GG.
6. Selection of Records That Must Be Retained
Maintaining records of the information used to determine the
reported GHG emissions is necessary to enable us to verify that the GHG
emissions monitoring and calculations were done correctly. We propose
that all affected facilities maintain records of monthly facility
production quantities for each zinc product, number of facility
operating hours each month, and the annual facility production quantity
for each zinc product (in tons). If you use the carbon input procedure,
you would record for each carbon-containing input material consumed or
used (other than fuel) the monthly material quantity, monthly average
carbon content determined for material, and records of the supplier
provided information or analyses used for the determination. If you use
the CEMS procedure, you would maintain the CEMS measurement records.
A complete list of records to be retained is included in proposed
40 CFR part 98, subparts A and GG.
HH. Landfills
1. Definition of the Source Category
After being placed in a landfill, waste is initially decomposed by
aerobic bacteria, and then by anaerobic bacteria, which break down
organic matter into substances such as cellulose, amino acids, and
sugars. These substances are further broken down through fermentation
into gases and short-chain organic compounds that form the substrates
for the growth of methanogenic bacteria, which convert the fermentation
products into stabilized organic materials and biogas.
CH4 generation from a given landfill is a function of
several factors, including the total amount of waste disposed in the
landfill, the characteristics of the waste, and the climatic
conditions. The amount of CH4 emitted is the amount of
CH4 generated minus the amount of CH4 that is
destroyed and minus the amount of CH4 oxidized by aerobic
microorganisms in the landfill cover material prior to being released
into the atmosphere.
Waste decaying in landfills also produces CO2; however,
this CO2 is not counted in GHG totals as it is not
considered an anthropogenic emission. Likewise, CO2
resulting from the combustion of landfill CH4 is not
accounted as an anthropogenic emission under international accounting
guidance.
According to the 2008 U.S. Inventory, MSW landfills emitted 111.2
million metric tons CO2e of CH4 in 2006.
Generation of CH4 at these landfills was 246.8 million
metric tons CO2e; however, 65.3 million metric tons
CO2e were recovered and used (destroyed) in energy projects,
59.8 million metric tons CO2e were destroyed by flaring, and
12.4 million metric tons CO2e were oxidized in cover soils.
The majority of the CH4 emissions from on-site industrial
landfills occur at pulp and paper facilities and food processing
facilities. In 2006, these landfills emitted 14.6 million metric tons
CO2e CH4: 7.3 million metric tons CO2e
from pulp and paper facilities, and 7.2 million metric tons
CO2e from food processing facilities.
[[Page 16558]]
We propose to require reporting from open and closed,\88\ MSW
landfills meeting or exceeding the thresholds described below. We also
propose to require reporting of industrial landfills (e.g., landfills
at food processing, pulp and paper, and ethanol production facilities)
meeting or exceeding the applicable thresholds in the relevant
subparts. Hazardous waste landfills and construction and demolition
landfills are not included in the landfills source category as they are
not considered significant sources of GHG emissions.
---------------------------------------------------------------------------
\88\ For the purposes of this rule, an open landfill is one that
has accepted waste during the reporting year.
---------------------------------------------------------------------------
The definition of landfills in this rule does not include land
application units. Several refineries have land application units (also
known as land treatment units) in which oily waste is tilled into the
soil. We are seeking comment on the exclusion of land application units
from this rule.
For additional background information on landfills, please refer to
the Landfills TSD (EPA-HQ-OAR-2008-0508-034).
2. Selection of Reporting Threshold
In developing the threshold for landfills, we considered thresholds
of 1,000, 10,000, 25,000, and 100,000 metric tons CO2e of
CH4 generation at a landfill minus soil oxidation
(``generation threshold'') or of CH4 emissions from a
landfill, minus oxidation, after any destruction of landfill gas at a
combustion device (``emissions threshold'').
Table HH-1 of this preamble illustrates the emissions and
facilities that would be covered under these various thresholds for MSW
landfills. For landfills located at industrial facilities,\89\ please
refer to the threshold analyses for those sectors (e.g., food
processing, ethanol, pulp and paper).
---------------------------------------------------------------------------
\89\ As explained in sections III and IV of this preamble, many
facilities reporting to the proposed rule will have more than one
source category. In order to determine applicability, facilities
must add the emissions from all source categories for which there
are methods proposed in the proposed rule.
Table HH-1. Threshold Analysis for MSW Landfills (Open and Closed)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total national ------------------------------------------------------
Threshold level (metric tons facilities Metric tons
CO2e) CO2e /year Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 metric tons CO2e (generation).............................. 111,100,000 7800 110,800,000 99.7 6,830 88
1,000 metric tons CO2e (emissions)............................... 111,100,000 7800 110,800,000 99.7 6,827 88
10,000 metric tons CO2e (generation)............................. 111,100,000 7800 104,400,000 94 3,484 45
10,000 metric tons CO2e (emissions).............................. 111,100,000 7800 102,800,000 93 3,060 39
25,000 metric tons CO2e (generation)............................. 111,100,000 7800 91,100,000 82 2,551 33
25,000 metric tons CO2e (emissions).............................. 111,100,000 7800 82,400,000 74 1,926 25
100,000 metric tons CO2e (generation)............................ 111,100,000 7800 65,600,000 59 1,038 13
100,000 metric tons CO2e (emissions)............................. 111,100,000 7800 39,300,000 35 441 6
--------------------------------------------------------------------------------------------------------------------------------------------------------
The proposed threshold for reporting emissions from MSW landfills
is a generation threshold of 25,000 metric tons CO2e (i.e.,
CH4 generated at the landfill, minus oxidation in landfill
cover soils). This threshold is consistent with thresholds for other
source categories and covers over 70 percent of emissions from the
source category. It strikes a balance between the goal of covering the
majority of the emissions while avoiding a reporting burden for small
MSW landfills and, especially, small, closed MSW landfills.
For a full discussion of the threshold analysis, please refer to
the Landfills TSD (EPA-HQ-OAR-2008-0508-034). For specific information
on costs, including unamortized first year capital expenditures, please
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
This section of the preamble describes the proposed methods for
estimating CH4 generation and emissions from landfills and
for determining the quantity of landfill CH4 destroyed.
Many domestic and international GHG monitoring guidelines and
protocols include methodologies for estimating emissions from landfills
(e.g., 2006 IPCC Guidelines, U.S. GHG Inventory, CCAR, EPA Climate
Leaders, EU Emissions Trading System, TCR, EPA's Landfill Methane
Outreach Program, DOE 1605(b), Australia's National Mandatory GHG
Reporting Program (draft), NSPS/NESHAP, WRI/WBCSD GHG Protocol, and
National Council of Air and Stream Improvement). In general, these
methodologies include three methods for monitoring emissions: The
modeling method, the engineering method, and the direct measurement
method.
Option 1. Modeling Method. The IPCC First Order Decay Model \90\ in
the 2006 IPCC Guidelines produces emissions estimates that reflect the
degradation rate of wastes in a landfill. This method uses waste
disposal quantities, degradable organic carbon, dissimilated degradable
organic carbon, a decay rate, time lag before CH4
generation, fraction of CH4 in landfill gas, and an
oxidation factor.
---------------------------------------------------------------------------
\90\ The IPCC First Order Decay Model is available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol5.html.
---------------------------------------------------------------------------
Option 2. Engineering Method. Direct measurement of collected
landfill gas to determine CH4 generation from landfills
depends on two measurable parameters: The rate of gas flow to the
destruction device; and the CH4 content of the gas. These
are quantified by directly measuring the flow rate and CH4
concentration of the gas stream to the destruction device(s).
Option 3. Direct Measurement. Direct measurement methods for
calculating CH4 emissions from landfills include flux
chambers and optical remote sensing.
Proposed Option. As part of this proposed rule, stationary fuel
combustion emissions unrelated to the flaring of recovered landfill
CH4, and emissions from the use of auxiliary fuel to
maintain effective operation of the flare (e.g., for pilot gas, or fuel
used to supplement the heating value of the landfill gas occurring at
the landfill), would be estimated and reported according to the
proposed procedures in proposed 40 CFR part 98, subpart C (General
Stationary Fuel Combustion Sources), which are discussed in Section V.C
of this preamble.
In order to estimate CH4 emissions from the landfill we
propose a combination of Option 1 and Option 2.
Modeling method. In the proposed rule, all landfills would be
required to
[[Page 16559]]
calculate CH4 generation and emissions using the IPCC First
Order Decay Model. The IPCC First Order Decay Model has two calculation
options: A bulk waste option and a waste material-specific option. The
proposed rule would require the use of the material-specific option for
all industrial landfills, and for MSW landfills when material-specific
waste quantity data are available, as this option is expected to
provide more accurate emission estimates. However, the accuracy
improvement is limited and at MSW landfills, material-specific waste
quantity data are expected to be sparse, so use of the waste material-
specific approach would not be mandated for all MSW landfills. Where
landfills do not have waste material-specific data, the bulk waste
option would be used.
We propose that the landfills use site-specific data to determine
waste disposal quantities (by type of waste material disposed when
material-specific waste quantity data are available) and use
appropriate EPA and IPCC default values for all other factors used in
the emissions calculation. To accurately estimate emissions using this
method, waste disposal data are needed for the 50 year period prior to
the year of the emissions estimate. Annual waste disposal data are
estimated using receipts for disposal where available, and where
unavailable, estimates based on national waste disposal rates and
population served by the landfill.
Engineering method. For landfills with gas collection systems, it
is also possible to estimate CH4 generation and emissions
using gas flow and composition metering along with an estimate of the
landfill gas collection efficiency. We propose to require landfills
that have gas collection systems to calculate their CH4
generation (adjusted for oxidation) and emissions using both the IPCC
First Order Decay Model (as described above), and the measured
CH4 collection rates and estimated gas collection
efficiency. This proposal provides a means by which all landfills would
report emissions and generation consistently using the same (IPCC First
Order Decay Model) methodology, while also providing reporting of site-
specific emissions and generation estimates based on gas collection
data.
We propose that landfills with gas collection systems continuously
measure the CH4 flow and concentration at the flare or
energy device. This monitoring option is more accurate than a monthly
sample given variability in gas flow and concentration over time, and
many landfills with gas collection systems already have such equipment
in place.
We are seeking comment on monthly sampling of landfill gas
CH4 flow and concentration as an alternative to a continuous
composition analyzer. For the monthly sampling alternative, a
continuous gas flowmeter would still be required.
To estimate CH4 emissions remaining in the landfill gas
combustion exhaust of a destruction device, apply the DE of the
equipment to the quantity of CH4 collected as measured by
the monitoring systems described above.
Calculating generation and emissions. CH4 generation
(adjusted for oxidation) is calculated by applying an oxidation factor
to generated CH4. For landfills without gas collection
systems, the calculated value for CH4 generation (adjusted
for oxidation) is equal to CH4 emissions. For landfills with
collection systems, CH4 generation is also calculated using
both the IPCC First Order Decay model method and the gas collection
data measurement method with a collection efficiency as explained
above. CH4 emissions are calculated by deducting destroyed
CH4 and applying an oxidation factor to the fraction of
generated CH4 that is not destroyed.
Direct Measurement Method. We also considered direct measurement at
landfills as an option. The direct measurement methods available (e.g.,
flux chambers and optical remote sensing) are currently being used for
research purposes, but are complex and costly, their application to
landfills is still under investigation, and they may not produce
accurate results if the measuring system has incomplete coverage.
We are considering developing a tool to assist reporters in
calculating generation and emissions from this source category. We have
reviewed tools for calculating emissions and emissions reductions from
these sources, including IPCC's Waste Model, and National Council of
Air and Stream Improvement's GHG Calculation Tools for Pulp and Paper
Mills, and EPA's LandGEM, and are seeking comment on the advantages and
disadvantages of using these tools as a model for tool development and
on the utility of providing such a tool.
4. Selection of Procedures for Estimating Missing Data
Missing data procedures for landfills are proposed based on the
monitoring methodology. In the case where a monitoring system is used,
the substitute value would be calculated as the average of the values
immediately proceeding and succeeding the missing data period. For
prolonged periods of missing data when a monitoring system is used, or
for other non-monitored data, the substitute data would be determined
from the average value for the missing parameter from the previous
year, or from equations specified in the rule (for waste disposal
quantities). The proposed rule would require a complete record of all
parameters determined from company records that are used in the GHG
emissions calculations (e.g., disposal data, gas recovery data).
For purposes of the emissions calculation, we considered not
deducting CH4 destruction that was not recorded. However,
not including CH4 recovery could greatly overestimate a
facility's emissions. On the other hand, allowing extended periods of
missing data provides a disincentive to repairing the monitoring
system.
5. Selection of Data Reporting Requirements
We propose that landfills over the threshold report CH4
generation, CH4 oxidation, CH4 destruction (if
applicable), and net CH4 emissions on an annual basis, as
calculated above using both the First Order Decay Model and, if
applicable, gas flow data for landfills with gas collection systems. In
addition to reporting emissions, input data needed to calculate
CH4 generation and emissions would be required to be
reported. These data form the basis of the GHG emission calculations
and are needed for EPA to understand the emissions data and verify the
reasonableness of the reported data. A full list of data to be reported
is included in proposed 40 CFR part 98, subparts A and HH.
6. Selection of Records That Must Be Retained
Records to be retained include information on waste disposal
quantities, waste composition if available, and biogas measurements.
These records are needed to allow verification that the GHG emission
monitoring and calculations were done correctly. A full list of records
to be retained onsite is included in proposed 40 CFR part 98, subparts
A and HH.
II. Wastewater Treatment
1. Definition of the Source Category
An industrial wastewater treatment system is a system located at an
industrial facility which includes the collection of processes that
treat or remove pollutants and contaminants, such as soluble organic
matter, suspended solids, pathogenic organisms, and chemicals from
waters
[[Page 16560]]
released from industrial processes. Industrial wastewater treatment
systems may include a variety of processes, ranging from primary
treatment for solids removal to secondary biological treatment (e.g.,
activated sludge, lagoons) for organics reduction to tertiary treatment
for nutrient removal, disinfection, and more discrete filtration. In
some systems, the biogas (primarily CH4) generated by
anaerobic digestion of organic matter is captured and destroyed by
flaring and/or energy recovery. The components and configuration of an
industrial wastewater treatment system are determined by the type of
pollutants and contaminants targeted for removal or treatment.
Industrial wastewater systems that rely on microbial activity to
degrade organic compounds under anaerobic conditions are sources of
CH4.
CH4 emissions from wastewater treatment systems are
primarily a function of how much organic content is present in the
wastewater system and how the wastewater is treated. Industries that
have the potential to produce significant CH4B emissions
from wastewater treatment--those with high volumes of wastewater
generated and a high organic wastewater load--include pulp and paper
manufacturing, food processing, ethanol production, and petroleum
refining.
Wastewater treatment also produces CO2; however, with
the exception of CO2 from oil/water separators at petroleum
refineries, this CO2 is not counted in GHG totals as it is
not considered an anthropogenic emission. Likewise, CO2
resulting from the combustion of digester CH4 is not
accounted as an anthropogenic emission under international accounting
guidance.
In 2006, CH4B emissions from industrial wastewater
treatment were estimated to be 7.9 million metric tons CO2e.
The only wastewater treatment process emissions to be reported in
this rule are those from onsite wastewater treatment located at
industrial facilities, such as at pulp and paper, food processing,
ethanol production, petrochemical, and petroleum refining facilities.
POTWs are not included in this proposal because, as described in the
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035), emissions from
POTWs do not exceed the thresholds considered under this rule.
2. Selection of Reporting Threshold
A separate threshold is not proposed for emissions from industrial
wastewater treatment system as these emissions occur in a number of
facilities across a range of industries (e.g., pulp and paper, food
processing, ethanol production, petrochemical, and petroleum refining).
As described in Sections III and IV of this preamble, a facility may
have more than one source category and emissions from all source
categories for which there are methods (e.g., emissions from industrial
wastewater treatment systems) must be included in the facility's
applicability determination. Please see the preamble sections for the
relevant sectors for more information on the applicability
determination for your facility.
Despite the fact that we are not proposing a separate threshold for
industrial wastewater systems, there is analysis in the Wastewater
Treatment TSD on the types of industrial facilities that would meet
thresholds at the 1,000, 10,000, 25,000 and 100,000 million metric tons
CO2e level based on emissions from wastewater alone. There
is also a separate threshold analysis on POTWs.
For a full discussion of those threshold analyses, please refer to
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
For this proposal, we reviewed several protocols and programs for
monitoring and/or estimating GHG emissions including the 2006 IPCC
Guidelines, the U.S. GHG Inventory, CARB Mandatory GHG Emissions
Reporting System, CCAR, National Council of Air and Stream Improvement,
DOE 1605(b), EPA Climate Leaders, TCR, UNFCCC Clean Development
Mechanism, the EU Emissions Trading System, and the New Mexico
Mandatory GHG Reporting Program. These methodologies are all primarily
based on the IPCC Guidelines.
Based on this review, we considered the following options.
Option 1. Modeling Method. This method involves the use of certain
site-specific measured activity data and emission factors. The IPCC
method, for example, uses wastewater flow, COD, and wastewater
treatment system type to calculate CH4 emissions from
wastewater treatment.
Option 2. Direct Measurement. This method allows for site-specific
measurements, but the methods available (e.g., flux chambers and open
path methods) are currently being used only for research purposes, are
complex and costly, and might not be accurate if the measuring system
has incomplete coverage.
Proposed Methods. We propose that facilities use activity data,
such as measured COD concentration, and operational characteristics
(e.g., type of system), and the IPCC Tier 1 method to calculate
CH4 generation. To determine CH4 destruction, we
propose direct measurement of CH4 flow to combustion
devices. The proposed monitoring method uses a separate equation to
estimate CO2 from oil/water separators at petroleum
refineries, based on California's AB32 mandatory reporting rule. This
approach allows the use of default factors, such as a system emission
factor, for certain elements of the calculation, and the use of site-
specific data where possible.
CH4 emissions from industrial wastewater treatment
system components other than digesters. To estimate the amount of
CH4 emissions from industrial wastewater treatment, plant-
specific values of COD would be determined by weekly sampling. The
maximum amount of CH4 that could potentially be produced by
the wastewater under ideal conditions is calculated by multiplying the
COD by the maximum CH4 producing capacity of the wastewater,
per the 2006 IPCC Guidelines. This value is then multiplied by a
system-specific CH4 conversion factor reflecting the
capability of a system to produce the maximum achievable CH4
based on the organic matter present in the wastewater.
CH4 Generation from Anaerobic Digesters. If the
wastewater treatment system includes an anaerobic digester, we propose
that the CH4 generation of the digester be measured
continuously. Direct measurement to determine CH4 generation
from digesters depends on two measurable parameters: The rate of gas
flow to the combustion device and the CH4 content of the
gas. These are quantified by direct measurement of the gas stream to
the destruction device(s). The gas stream is measured by continuous
metering of both flow and gas concentration. This continuous monitoring
option is more accurate than a monthly sample given variability in gas
flow and concentration over time, and many digesters already have such
equipment in place.
We are also seeking comment on monthly sampling of digester gas
CH4 content as an alternative to a continuous composition
analyzer. For the monthly CH4 content sampling alternative,
a continuous gas flow meter would still be required.
CH4 Destruction. To estimate CH4 destroyed at
a digester, you would apply
[[Page 16561]]
the DE of the combustion equipment (lesser of manufacturer's specified
DE and 0.99) to the value of CH4 generated from anaerobic
digestion estimated above.
CO2 emissions from oil/water separators at petroleum
refineries. To calculate CO2 emissions from degradation of
petroleum or impurities at oil/water separators at petroleum
refineries, the volume of wastewater treated would be measured weekly
and multiplied by the non-methane volatile organic carbon emission
factor for the type of separator used, and an emission factor for
CO2 (mass of CO2/mass of non-methane volatile
organic carbon).
Total emissions. Total emissions from wastewater treatment are the
sum of the CH4 emissions (including undestroyed
CH4 from digesters), and CO2 emissions.
Other Options Considered. Direct measurement is another option we
considered but are not proposing in this rule. This method allows for
site-specific measurements, but it is costly and might not be accurate
if the measuring system has incomplete coverage. To be accurate, a
direct measurement system would need to be complete both spatially (in
that all emissions pathways are covered, not just individual pathways
as is the case with anaerobic digesters, at which gas is commonly
directly metered) and temporally (as emissions can vary greatly due to
changes in influent and conditions at the facility).
We are considering developing a tool to assist reporters in
calculating emissions from this source category. EPA has reviewed tools
for calculating emissions from these sources, such as National Council
of Air and Stream Improvement's GHG Calculation Tools for Pulp and
Paper Mills, and is seeking comment on the advantages and disadvantages
of using these tools as a model for tool development, and the utility
of providing such a tool.
For additional information on the proposed method, please see the
2006 IPCC Guidelines,\91\ the 2008 U.S. Inventory,\92\ and the
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035).
---------------------------------------------------------------------------
\91\ 2006 IPCC Guidelines. Chapter 6: Wastewater Treatment and
Discharge. (Volume 5 Waste.) Available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/5_Volume5/V5_6_Ch6_Wastewater.pdf.
\92\ 2008 U.S. Inventory. Chapter 8: Waste. Available at http://www.epa.gov/climatechange/emissions/usinventoryreport.html.
---------------------------------------------------------------------------
4. Selection of Procedures for Estimating Missing Data
On the occasion that a facility lacks data needed to determine the
emissions from wastewater treatment over a period of time, we propose
that the facility apply an average facility-level value for the missing
parameter from measurements of the parameter preceding and following
the missing data incident, as specified in the proposed rule. The
proposed rule would require a complete record of all parameters
determined from company records that are used in the GHG emissions
calculations (e.g., production data, biogas combustion data).
For purposes of the emissions calculations, we considered not
deducting CH4 destruction that was not recorded. However,
not including CH4 destruction could greatly overestimate a
facility's actual CH4 emissions.
5. Selection of Data Reporting Requirements
EPA proposes that industrial wastewater treatment plants over the
threshold report annually both CH4 and CO2
emissions from wastewater treatment system components other than
digesters, and CH4 generation and destruction at digesters.
In addition to reporting emissions, generation, and destruction, input
data used to calculate emissions from the wastewater treatment process
would be required to be reported. These data form the basis of the GHG
emission calculations and are needed for EPA to understand the
emissions data and verify the reasonableness of the reported data.
A full list of data to be reported is included in proposed 40 CFR
part 98, subparts A and II.
6. Selection of Records That Must Be Retained
Records to be retained include information on influent flow rate,
COD concentration, wastewater treatment system types, and digester
biogas measurements. These records are needed to allow verification
that the GHG emission monitoring and calculations were done correctly.
A full list of records to be retained onsite is included in proposed 40
CFR part 98, subparts A and II.
JJ. Manure Management
1. Definition of the Source Category
A manure management system is a system that stabilizes or stores
livestock manure, or does both. Anaerobic manure management systems
include liquid/slurry handling in uncovered anaerobic lagoons, ponds,
tanks, pits, or digesters. At some digesters, material other than
manure is treated along with the manure. Manure management systems in
which treatment is primarily aerobic include daily spread, solid
storage, drylot, and manure composting. For the purposes of this rule,
a manure management facility consists of uncovered anaerobic lagoons,
liquid/slurry systems, pits, digesters, and drylots (including systems
that combine drylot with solid storage) onsite manure composting, other
poultry manure systems, and cattle and swine deep bedding systems. The
manure management system does not include other onsite units and
processes at a livestock operation unrelated to the stabilization and/
or storage of manure.
When livestock manure are stored or treated, the anaerobic
decomposition of materials in the manure management system produces
CH4, while N2O is produced as part of the
nitrogen cycle through the nitrification and denitrification of the
organic nitrogen in livestock manure and urine. The amount and type of
emissions produced are related to the specific types of manure
management systems used at the farm and are driven by retention time,
temperature, and treatment conditions.
Manure management also produces CO2; however, this
CO2 is not counted in GHG totals as it is not considered an
anthropogenic emission. Likewise, CO2 resulting from the
combustion of digester CH4 is not accounted as an
anthropogenic emission under international accounting guidance.
According to the 2008 U.S. Inventory, CH4 emissions from
manure management systems totaled 41.4 million metric tons
CO2e, and N2O emissions were 14.3 million metric
tons CO2e in 2006; manure management systems account for 8
percent of total anthropogenic CH4 emissions and 3 percent
of N2O emissions in the U.S.
Manure management systems which include one or more of the
following components are to report emissions under this rule: Manure
handling in uncovered anaerobic lagoons, liquid/slurry systems, pits,
digesters, and drylots, including systems that combine drylot with
solid storage. Emissions to be reported include those from the systems
listed above, and also emissions from any high rise houses for caged
laying hens, broiler and turkey production on litter, deep bedding
systems for cattle and swine, and manure composting occuring onsite as
part of the manure management system.
This source category does not include systems which consist of only
components classified as daily spread, solid storage, pasture/range/
paddock, or manure composting. For detailed descriptions of system
types, please
[[Page 16562]]
refer to the Manure Management TSD (EPA-HQ-OAR-2008-0508-036).
A facility that is subject to the proposed rule only because of
emissions from manure management would also report CO2,
CH4, and N2O emissions from the combustion of
supplemental fuel in flares using the methods in proposed 40 CFR part
98, subpart C, but would not be required to report any other combustion
emissions.
2. Selection of Reporting Threshold
In developing the threshold for manure management, we considered
thresholds of 1,000, 10,000, 25,000, and 100,000 metric tons
CO2e of CH4 generation and N2O
emissions at a manure management system (``generation threshold''), and
CH4 and N2O emissions at manure management
systems (``emissions threshold''). The ``generation threshold'' is the
amount of CH4 and N2O that would be emitted from
the facility if no CH4 destruction takes place. This
includes all CH4 generation from all manure management
system types, including digesters, and N2O emissions. The
``emissions threshold'' includes the CH4 and N2O
that is emitted to the atmosphere from these facilities. In the
emissions threshold, CH4 that is destroyed at digesters is
taken into account and deducted from the total CH4
generation calculated.
To estimate the number of farms at each threshold, EPA first
developed a number of model farms to represent the manure management
systems that are most common on large farms and have the greatest
potential to exceed the GHG thresholds. Next, we used EPA's GHG
inventory methodology for manure management, to estimate the numbers of
livestock that would need to be present to exceed the threshold for
each model farm type. Finally, we combined the numbers of livestock
required on each model farm to meet the thresholds with U.S. Department
of Agriculture (USDA) data on farm sizes to determine how many farms in
the United States have the livestock populations required to meet the
GHG thresholds for each model farm.
Table JJ-1 of this preamble presents the estimated head of
livestock that would meet the thresholds evaluated for the highest GHG-
emitting common manure management systems for beef (steers and heifers
at a feedlot), dairy (cows at an uncovered anaerobic lagoon, heifers on
dry lot without solids separation), swine (farrow to finish at an
uncovered anaerobic lagoon), and poultry (layers and pullets at an
uncovered anaerobic lagoon).
Other types of farms and manure management systems could require
significantly higher head counts to meet the thresholds considered:
Meeting the 25,000 tCO2e threshold could require 978,000
head for beef on pasture, 13,000 head for some dairy liquid slurry
systems, 171,000 head of farrow to finish swine using a deep pit for
manure, and 47,028,300 broilers on litter. For more information on
estimated head of livestock that would meet these thresholds for other
manure management system types, please see the Manure Management TSD
(EPA-HQ-OAR-2008-0508-036).
Table JJ-1. Estimated Head of Livestock To Meet Thresholds
----------------------------------------------------------------------------------------------------------------
----------------------------------------------------------------------------------------------------------------
Threshold Levels (metric tons CO2e)
----------------------------------------------------------------------------------------------------------------
1,000 10,000 25,000 100,000
---------------------------------------------------
Total number of head to meet threshold
----------------------------------------------------------------------------------------------------------------
Beef........................................................ 3,500 35,500 89,000 356,000
Dairy....................................................... 200 2,000 5,000 20,000
Swine....................................................... 3,000 29,000 73,000 291,500
Poultry..................................................... 39,500 358,000 895,000 3,580,000
----------------------------------------------------------------------------------------------------------------
Although data are available at the national level on the number of
farms of certain sizes, most of the population sizes needed to meet
these thresholds occur in the largest farm size categories, in which
data are not sufficiently disaggregated to determine how many farms of
such sizes exist. For example, the largest dairy farm size category for
which data is available is ``1,000 head or more.'' The number of dairy
farms with populations large enough to meet thresholds for 10,000
metric tons CO2e (2,000 animals) and above therefore had to
be estimated using expert judgment. It is estimated that at the
proposed threshold, fewer than 50 manure management systems at beef,
dairy, and swine operations would be required to report. Table JJ does
not determine applicability alone, but rather serves as a ``screening''
guide in determining the approximate facility size that meets the
applicability requirements. We are also seeking comment on the
advantages and disadvantages of using additional screening tools such
as a look-up table or computerized calculator to help owners or
operators determine if they meet the reporting threshold. A table could
be developed that indicated whether a facility had a sufficient number
of animals to warrant further screening. If the initial screening
through use of the table indicated that the facility may meet the
reporting threshold a simple computerized calculator (e.g., web-based
model) utilizing site-specifica data such as the type of manure
management system and the average number of head, along with some other
default data provided in look-up tables could be used to determine if a
facility met the reporting threshold. Screening devices, if utilized,
could assist owners or operators in determining if they are near the
threshold for reporting and therefore potentially avoid costs incurred
from monthly manure analysis proposed in the calculation method of the
rule. More information and estimates based on existing farm size data
are presented in the Manure Management TSD (EPA-HQ-OAR-2008-0508-036).
The proposed threshold for reporting emissions from manure
management systems is the emission threshold of 25,000 metric tons
CO2e. More specifically, the CH4 and
N2O emissions from manure management are summed to determine
if a manure management system meets or exceeds the threshold.
Facilities exceeding the threshold would report both of these GHG
emissions. This threshold includes the largest emitters of GHG from
this source category, while avoiding reporting from many small farms
with less significant emissions. For a full discussion of the threshold
analysis, please refer to Manure Management TSD (EPA-HQ-OAR-2008-0508-
036). For specific information on costs, including unamortized first
year capital expenditures, please refer to section 4 of the RIA and the
RIA cost appendix.
[[Page 16563]]
We are seeking comment on the option of using a generation
threshold instead of the proposed emissions threshold. In the
generation threshold option, the CH4 generation (including
CH4 generated and later combusted) and the N2O
emissions from manure management are summed to determine if a manure
management system meets or exceeds the threshold. Facilities exceeding
the threshold would report both GHG generation and emissions. We
estimated that this option would cover several farms with digesters
that would not be covered in the emissions threshold option.
3. Selection of Proposed Monitoring Methods
Many domestic and international GHG programs provide monitoring
guidelines and protocols for estimating emissions from manure
management (e.g., the 2006 IPCC Guidelines, the U.S. GHG Inventory, DOE
1605(b), CARB Mandatory GHG Emissions Reporting System, CCAR, EPA
Climate Leaders, TCR, UNFCCC Clean Development Mechanism, EPA AgSTAR,
and Chicago Climate Exchange). These methodologies are all based on the
IPCC Guidelines.
Based on the review of these methods, we considered the following
options.
Option 1. Modeling Method. This method involves the use of certain
site-specific measured activity data and emission factors. The IPCC
method, for example, uses volatile solids, nitrogen excretion, climate
data, and manure management system type to calculate CH4 and
N2O emissions from manure management systems.
Option 2. Direct Measurement. This method allows for site-specific
measurements, but the methods available (e.g., flux chambers and open
path methods) are currently being used only for research purposes, are
complex and costly, and might not be accurate if the measuring system
has incomplete coverage.
Proposed option. We propose that facilities use activity data, such
as the number of head of livestock, operational characteristics (e.g.,
physical and chemical characteristics of the manure, including measured
volatile solids and nitrogen values, type of management system(s)), and
climate data, with the IPCC method to calculate CH4 and
N2O emissions, and measured values for gas destruction.
CH4 emitted at manure management system types other than
digesters. We propose that CH4 emissions at manure
management system components other than digesters be calculated using
the IPCC methodology and measured volatile solids values.
We propose that the amount of volatile solids excreted be
calculated using (1) calculation of manure quantity entering the system
using livestock population data and default values for average animal
mass and manure generation, and (2) monthly sampling and testing of
excreted manure for total volatile solids content.
We are seeking comment on the option of using facility-specific
livestock population and mass, and default values for volatile solids
rate to estimate total volatile solids, instead of measured values. We
are also seeking comment on whether a different sampling and testing
frequency, such as quarterly, would be more appropriate than monthly.
The maximum amount of CH4 that could potentially be
produced by the manure under ideal conditions would be calculated by
multiplying the volatile solids by the maximum CH4-producing
capacity of the manure (B0), a default value included in the GHG
Inventory. A system-specific CH4 conversion factor would
then be applied to determine the amount of CH4 produced by
the specific system type.
CH4 Generation at Digesters. If the manure management
system includes a digester, we propose that the CH4
generation of the digester be measured continuously. Direct measurement
to determine CH4 generation from digesters depends on two
measurable parameters: The rate of gas flow to the combustion device,
and the CH4 content of the gas. These would be quantified by
direct measurement of the total gas stream. We propose that the gas
stream be measured by continuous metering of both flow and gas
concentration. This continuous monitoring option is more accurate than
a monthly sample given variability in gas flow and concentration over
time, and many digesters already have such equipment in place.
We are also seeking comment on monthly sampling of digester gas
CH4 content as an alternative to a continuous composition
analyzer. For the monthly CH4 content sampling alternative,
a continuous gas flow meter would still be required.
CH4 Destruction at Digesters. To estimate CH4
destruction at a digester, you would apply the DE of the destruction
equipment (lesser of manufacturer's specified DE and 0.99) and the
ratio of operating hours to reporting hours to the value of
CH4 generated from anaerobic digestion estimated above.
CH4 Leakage at Digesters. To estimate CH4
leakage from digesters, we propose that a default value for collection
efficiency is applied to the measured quantity of CH4 flow
to a destruction device. We are seeking comment on the proposed method
and on the proposed default collection efficiency values for estimating
leakage from digesters.
CH4 Emissions from Digesters. We propose that emissions
from digesters be calculated as the sum of CH4 that is not
destroyed at the destruction device, and CH4 that leaks from
the digester.
N2O Emissions. We propose that N2O emissions
be calculated using the IPCC methodology and measured nitrogen (N)
values.
We propose that the amount of nitrogen entering the manure
management system be measured through (1) calculation of manure
quantity entering the system using livestock population data and
default values for average animal mass and manure generation, and (2)
monthly sampling and testing of excreted manure for total nitrogen
content.
We are seeking comment on the option of using facility-specific
livestock population and mass, and default values for nitrogen
excretion rate to estimate total N, instead of measured values.
Each manure management system type has an associated default
N2O emission factor which would be applied to the amount of
nitrogen managed by the system.
GHG Emissions. Reporters would be required to complete the
following to calculate the emissions for reporting.
Estimate and report GHG emissions by adding the CH4
emissions from manure management systems other than digesters, the
N2O emissions from manure management systems, and, for
manure management systems which include digesters, the CH4
emissions (monitored CH4 generation at the digester minus
CH4 destruction at the digester) from the anaerobic
digester.
Direct measurement is another option we considered but are not
proposing in this rule. A direct measurement system must be complete
both spatially (in that all emissions pathways are covered) and
temporally (as emissions can vary greatly due to changes in population,
diet, and conditions at the facility) and would hence be difficult and
expensive to implement accurately.
We are considering developing a tool to assist reporters in
calculating emissions from this source category. There are several
existing tools for calculating emissions and emissions reductions from
manure management systems, including EPA's FarmWare and CCAR's
Livestock Project Reporting Protocol. We are seeking comment on
[[Page 16564]]
the advantages and disadvantages of using such tools as a model for
tool development and on the utility of providing such a tool.
The various approaches to monitoring GHG emissions, as well as
specific cost information, are elaborated in the Manure Management TSD
(EPA-HQ-OAR-2008-0508-036).
4. Selection of Procedures for Estimating Missing Data
On the occasion that a facility lacks sufficient data to determine
the emissions from manure management over a period of time, we propose
that the facility apply an average facility-level value for the missing
parameter from measurements of the parameter preceding and following
the missing data incident, as specified in the proposed rule. The
proposed rule would require a complete record of all parameters
determined from company records that are used in the GHG emissions
calculations (e.g., historical livestock population data, biogas
destruction data).
For emissions calculation purposes, EPA considered not deducting
CH4 recovery and destruction that was not recorded, but not
including CH4 destruction could greatly overestimate an
entity's actual CH4 emissions.
5. Selection of Data Reporting Requirements
EPA proposes that facilities report CH4 and
N2O emissions, along with the input data to calculate these
values. These data form the basis of the GHG emission calculations and
are needed for EPA to understand the emissions data and verify the
reasonableness of the reported data. A full list of data to be reported
is included in proposed 40 CFR part 98, subparts A and JJ.
6. Selection of Records That Must Be Retained
Records to be retained include information on animal population,
manure management system types, animal waste characteristics, and
digester biogas measurements. These records are needed to allow
verification that the GHG emission monitoring and calculations were
done correctly. A full list of records to be retained onsite is
included in proposed 40 CFR part 98, subparts A and JJ.
KK. Suppliers of Coal
1. Definition of the Source Category
Proposed 40 CFR part 98, subpart KK would require reporting by
facilities or companies that introduce or supply coal into the economy
(e.g., coal mines, coal importers, and waste coal reclaimers). These
facilities or companies (in the case of coal importers and exporters)
would report on the CO2 emissions that would result from
complete combustion or oxidation of the quantities of coal supplied.
For completeness, this source category also includes coal exporters.
Facilities that use coal for energy purposes should refer to
proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion
Sources). Facilities that use coal for non-energy uses (e.g., as a
reducing agent in metal production such as ferroalloys, zinc, etc.)
should refer to the relevant subparts of the proposed rule. Underground
coal mine operators who are included in this subpart should also refer
to proposed 40 CFR part 98, subpart FF (Underground Coal Mines) in
order to account for any combustion and fugitive emissions separately,
as described in Sections III and IV of this preamble. A description of
the requirements related to the conversion of coal to liquid fuel is
covered in Section V.LL of this preamble.
Coal is a combustible black or brownish-black sedimentary rock
composed mostly of carbon and hydrocarbons. It is the most abundant
fossil fuel produced in the U.S. Over 90 percent of the coal used in
the U.S. is used to generate electricity. Coal is also used as a basic
energy source in many industries, including cement and paper. In 2006,
the combustion of coal for useful heat and work resulted in emissions
of 2,065.3 million metric tons CO2, or 29 percent of total
U.S. GHG emissions.
The supply chain for delivering coal to consumers is relatively
straightforward. It includes coal mines or importers, in some cases
coal washing or preparation onsite or at dedicated offsite plants, and
transport (usually by rail) to consumers. The U.S. typically produces
nearly all of its domestic coal needs; in 2007, domestic coal
production accounted for 97 percent of domestic coal consumption. A
relatively small share of coal consumed in the U.S. (3 percent in 2007)
is imported from other countries, and a small share of U.S. production
is exported for use abroad (5 percent in 2007).
In determining the most appropriate point in the supply chain of
coal for reporting potential CO2 emissions, we considered
the following criteria: An administratively manageable number of
reporting facilities; complete coverage of coal supply as a group of
facilities or in combination with facilities reporting under other
subparts of the proposed rule; minimal irreconcilable double-counting
of coal supply; and feasibility of monitoring or calculation methods.
We are proposing to include all active coal mines, coal importers,
coal exporters, and reclaimers of waste coal as reporters under this
subpart.
We are proposing to require all owners or operators of active
underground and surface coal mines to report under proposed 40 CFR part
98, subpart KK. There were 1,365 active coal mines (both underground
and surface mines) operating in the U.S. in 2007, according to the
MSHA. Currently, coal mines routinely monitor coal quantity and coal
quality data for use in coal sale contracts as well as for reporting
requirements to various State and Federal agencies.
We are proposing that importers of coal into the U.S. report under
proposed 40 CFR part 98, subpart KK. Reporting for coal importers is
proposed at the company level, as opposed to the facility level,
because the importers of record are typically companies, and these
companies currently track and report imports. Most of the 36 million
tons of coal that were imported to the U.S. in 2007 were used for power
generation. A small number of electric utility companies were
responsible for the large majority of coal imports in 2006.\93\ In many
cases, the importing companies also own and operate electricity
generating or industrial facilities that would be included as covered
facilities under other subparts of the proposed rule. Because these
entities already collect much of this information, EPA believes that
the reporting requirements for importers would impose a minimal
additional burden.
---------------------------------------------------------------------------
\93\ In 2006, the eight largest coal-importing power generating
companies accounted for 87 percent of total imported coal by
electric utilities (FERC Form 423 and EIA 906). Approximately 80
percent of coal imports were used in the electricity sector in 2006.
---------------------------------------------------------------------------
We are proposing that exporters of coal report under proposed 40
CFR part 98, subpart KK. In 2007, 59.2 million tons of coal produced
(mined) in the U.S. were exported. Coal exporters may include coal
mining companies who directly sell their coal to entities outside the
U.S., or other retailers who export the coal (typically via barge from
one of several U.S. ports). Coal exports are included in proposed 40
CFR part 98, subpart KK so that the total supply of coal (and
associated GHG emissions) into the U.S. economy is balanced against the
coal that leaves the country. Typically, coal exporters characterize
the quantity (tons) and heat value of the coal. Thus, this reporting
requirement would impose a minimal additional burden on coal exporters.
[[Page 16565]]
We are proposing that reclaimers of waste coal report under
proposed 40 CFR part 98, subpart KK. In some parts of the U.S., waste
coal that was mined decades ago and placed in waste piles is now being
actively recovered and sold to end users. Because this coal is
technically not being ``mined'' but is nonetheless entering the U.S.
economy for the first time, facilities that reclaim or recover such
waste coal from waste coal piles and sell or deliver it to end-users
are being included for reporting under proposed 40 CFR part 98, subpart
KK as waste coal reclaimers. Because these facilities would need to
collect data on the quantity and quality (e.g., heat value) of their
product, this reporting requirement should impose a minimal additional
burden on coal reclaimers.
We considered but are not proposing that facilities that convert
coking coal into industrial coke and importers of coke report under
proposed 40 CFR part 98, subpart KK. U.S. coke imports in 2007
constituted only 2.5 million tons (about 0.2 percent of total U.S. coal
production) and can therefore be considered negligible. Most
domestically consumed coal-based coke (87 percent) is derived from
domestically-mined coal or imported coal, and therefore the inclusion
of coal mines and coal importers in this subpart already provide for
coverage of carbon contained in the coke (and the potential
CO2 emissions from oxidizing or combusting the coke). Only
14 percent of coal-based coke consumed domestically is imported
directly as coke. Furthermore, coke production is an energy- and
emissions-intensive process, and these facilities are likely to be
above thresholds for the general stationary fuel combustion sources
(proposed 40 CFR part 98, subpart C) and industrial process categories
such as iron and steel, and ferro-alloys. Therefore, GHG emissions
associated with the combustion or oxidation of coke imports and
domestically produced coke would already be included in the actual GHG
emissions reported under those subparts.
We considered but are not proposing that coal preparation plants
located offsite from coal mines report the potential CO2
emissions associated with their processed coal. Some of these
facilities may be included as reporting facilities under proposed 40
CFR part 98, subpart C for direct emissions from combustion. An unknown
but likely very small share of coal production annually requires
additional preparation or washing at an offsite preparation plant.
Typically, only the smaller mines do not do their preparation onsite.
We are not requiring offsite coal preparation plants to report under
this subpart because the potential CO2 emissions from coal
supplied by these facilities is already accounted for by reported data
from coal mines, coal importers, and waste coal reclaimers.
Instead of requiring coal mines to report as coal suppliers, we
also considered, but are not proposing, that rail operators report the
quantity of coal they transport. We have determined that requiring
reporting on coal transport would add complexity without increasing the
accuracy of information on potential CO2 emissions
associated with the supply of coal to the U.S. economy. It is our
understanding that, unlike coal mines or coal importers, coal
transporters do not routinely collect information about the carbon
content or heating value of the coal they are transporting, so such
reporting requirements would add to the reporting burden. Furthermore,
in the case of mine mouth power plants for which the coal does not
travel via rail, rail transporters would miss this coal production
entirely.
We request comment on the inclusion of active underground and
surface coal mines, coal importers, coal exporters, and waste coal
reclaimers, and the exclusion of offsite preparation plants, coke
importers and coke manufacturing facilities, and coal rail transporters
from reporting requirements under proposed 40 CFR part 98, subpart KK.
For additional background information on suppliers of coal, please
refer to the Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
2. Selection of Reporting Threshold
In considering a threshold for coal suppliers, we considered the
application of the following emissions-based thresholds for each
affected company or facility under proposed 40 CFR part 98, subpart KK
(e.g., coal mine, coal importer, coal exporter, or waste coal
reclaimer): 1,000 metric tons CO2e, 10,000 metric tons
CO2e, 25,000 metric tons CO2e and 100,000 metric
tons CO2e per year. For coal suppliers, these thresholds
would be applied to the CO2 emissions that would result from
complete combustion or oxidation of the coal produced or supplied into
the U.S. economy, rather than the actual GHG emissions for the
individual facilities or companies. To provide general information on
how the thresholds would affect the coal industry, we used a weighted
average carbon content of 1,130 lbs/short ton.\94\ These thresholds
translate into annual coal production for a single mine of 532 short
tons, 5,321 short tons, 13,303 short tons, and 53,211 short tons,
respectively.
---------------------------------------------------------------------------
\94\ Carbon content is found using the weighted average of
CO2 (lbs/MMbtu) from EIA Table FE4 along with the heat
content (MMbtu/ton) and production (tons) from the 2007 MSHA
database. The molecular mass ratio of carbon to CO2 (12/
44) is then used to find carbon content from the derived
CO2 (4,143 lbs/short ton).
---------------------------------------------------------------------------
Coal Mines. Table KK-1 of this preamble illustrates the coal mine
emissions and facilities that would be covered under these various
thresholds.
Table KK-1. Threshold Analysis for Coal Mines
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total 2007 Emissions covered Facilities covered
national Total 2007 ---------------------------------------------------------------
emissions number of
Threshold level metric tons CO2e/yr (million facilities in Million metric Number of Percent of
metric tons the U.S. tons CO2e/yr Percent facilities \3\ facilities
CO2e/yr) \1\ \2\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 2,153 1,365 2,146 99.7 1,346 99
10,000.................................................. 2,153 1,365 2,146 99.7 1,237 91
25,000.................................................. 2,153 1,365 2,144 99.6 1,117 82
100,000................................................. 2,153 1,365 2,130 98.9 867 64
--------------------------------------------------------------------------------------------------------------------------------------------------------
Source: EIA Table FE4 and 2007 MSHA database.
Notes:
(1) 2007 National Emissions (metric tons CO2e) = 2007 Production x U.S. Weighted Average CO2 content (4,143 lbs/short ton)/(2205 lbs/metric ton).
(2) Emissions covered (metric tons CO2e) = sum of coal CO2 emissions for all facilities with metric tons CO2e production greater than the threshold.
[[Page 16566]]
(3) Facilities covered = total number of facilities with metric tons CO2e production greater than the threshold.
For this rule, we propose to include all active underground and
surface coal mines, with no threshold. Of the approximately 1,365
active coal mines operating in 2007, the 25,000 metric tons
CO2e threshold (corresponding to 1,140.8 million tons of
coal production) would include the largest 1,117 coal mines and 99.6
percent of U.S. coal production. All active U.S. coal mines already
report annual (and quarterly) coal production (based on aggregated
daily production data) to MSHA. The additional reporting required under
this proposal is the carbon content of the coal, which can be
calculated using the coal's higher heating value (HHV) also referred to
as the gross calorific value (GCV). All active U.S. coal mines already
conduct daily proximate analysis to record the HHV for coal sales
contracts. An alternative for coal mines with annual production lower
than 100,000 short tons is offered in the proposed rule to estimate
CO2 emissions using HHV and default values, making this a
very minimal additional reporting burden. Thus, we have determined that
including all mines as reporters under proposed 40 CFR part 98, subpart
KK would not significantly increase the burden on small coal mines. We
are seeking comments on this conclusion.
Coal Importers. As noted above, the majority of imported coal is
imported by power plants for steam generation of electricity, with the
remainder imported by other sizeable industrial facilities. We propose
that all coal importers report, with no threshold. Because most of the
imported coal is brought into the U.S. by companies owning facilities
that would already be required to report GHG data to EPA under other
subparts of the proposed 40 CFR part 98, EPA believes that there would
be a minimal incremental burden associated the inclusion of all
importing companies. We are seeking comments on this conclusion.
Coal Exporters. Under proposed 40 CFR part 98, subpart KK, we are
proposing that all coal exporting companies report, with no threshold.
Coal exporters already collect information about the quantity and
quality (e.g., heating value) of coal to be exported. Reporting to us
under proposed 40 CFR part 98, subpart KK would therefore impose only
minimal additional burden on these companies.
Waste coal reclaimers. Under proposed 40 CFR part 98, subpart KK,
we are proposing all waste coal reclaimers report, with no threshold.
Parties that recover this waste coal for sale to consumers already
collect information about the quantity and quality (e.g., heating
value) of coal to be sold. Reporting to us under proposed 40 CFR part
98, subpart KK would therefore impose only minimal additional burden on
these facilities.
For a full discussion of the threshold analysis, please refer to
the Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037). For specific
information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
We are proposing the reporting of the amount of coal produced or
supplied to the economy annually, as well as the CO2
emissions that would result from complete oxidation or combustion of
this quantity of coal.
The only GHG required to be reported under this subpart is
CO2. Combustion of coal may also lead to trace quantities of
CH4 and N2O emissions.\95\ Because the quantity
of CH4 and N2O emissions are highly variable and
dependent on technology and operating conditions in which the coal is
being consumed (unlike CO2), we are not proposing that coal
suppliers report on these emission. We seek comment on whether or not
EPA should use the national inventory estimates of CH4 and
N2O emissions from coal combustion, and apportion them to
individual coal suppliers based on the quantity of their products.
---------------------------------------------------------------------------
\95\ CO2, CH4, and N2O
emissions from coal combustion 2065.3, 0.8, and 10.23 million metric
tons CO2e, respectively.
---------------------------------------------------------------------------
We are proposing that coal mines, coal importers, coal exporters,
and reclaimers of waste coal use a mass-balance method to calculate
CO2 emissions. The mass balance approach is based on readily
available information: The quantity of coal (tons), and the carbon
content of the coal (as determined by the mine, importer, exporter, or
waste reclaimer, according to the methodology described below). The
formula is simple and can be automated. The mass-balance approach is
used extensively in national GHG inventories, and in existing reporting
guidelines for facilities, companies, and states, such as the WRI/WBCSD
GHG Protocol.
We propose that coal suppliers be required to report both the total
weight of coal produced or supplied annually (tons per year), as well
as either the carbon content (carbon mass fraction) or coal HHV, which
can be a proxy for carbon content. In practice, coal suppliers
routinely and frequently monitor both the weight and energy content of
coal for contractual purposes (e.g., daily measurements of tonnage and
analyses of the BTU, sulfur, and ash content of coal) as well as for
reporting requirements to various State and Federal agencies. We
propose that all coal suppliers report these routinely-collected data,
and use them as a basis for estimating the CO2 emissions
associated with the coal.
For the purpose of this calculation, we propose that larger coal
mines (i.e., coal mines that produce over 100,000 short tons of coal
per year) use mine-specific, carbon content values.
Generally, the carbon content of coal can be determined through one
of two procedures. The most accurate method is to determine the coal's
carbon content (carbon mass fraction) directly through ultimate
analysis of the coal's chemical constituents. An alternative method is
to measure the coal's energy content (HHV, which is often expressed in
units of MMBTU per unit weight) and use it as an indicator of the
coal's carbon content. This is done by establishing a statistically
significant correlation between the coal's heating value and the carbon
content of the coal, and using this correlation to estimate the carbon
content (carbon mass fraction) of a given batch of coal with known
heating value. For instance, a linear relationship between coal heating
value and coal carbon content can be established. This alternative
approach is convenient because heat value measurements of coal are
taken routinely and frequently by coal mines, coal importers, coal
exporters, and coal retailers.
For the purpose of proposed 40 CFR part 98, subpart KK, EPA
proposes that coal mines that produce over 100,000 short tons of coal
per year have two options for reporting the carbon content of their
coal: (1) Daily measurements of coal carbon content through ultimate
analyses (daily sampling and analyses, reported as annual weighted
average), or (2) a combination of daily measurements of coal HHV
through proximate analyses and monthly measurements of carbon content
through ultimate analyses, using an established, statistically
significant correlation to estimate the daily weighted average coal
carbon content (mass fraction), as described in the rule. We propose
that a minimum of one year of data be used to establish such a mine-
specific statistically significant correlation between the coal carbon
[[Page 16567]]
content (as measured by ultimate analyses) and coal heating value (as
measured by proximate analyses). We request comment on this approach,
including the minimum number of data points necessary to establish a
statistically significant mine-specific relationship between coal
carbon content and coal HHV, and how often and under what circumstances
should the statistical relationship be reestablished. According to MSHA
data, 706 mines produced over 100,000 short tons of coal during 2007
(52 percent of all mines), accounting for 98 percent of total
production. We propose that a more stringent method for calculating
carbon content be applied to these larger mines in order to reduce the
uncertainty of the CO2 data collected.
EPA proposes that coal mines with annual coal production less
100,000 short tons use either one of the above approaches for
estimating carbon content, or use a third alternative. This alternative
involves estimating the coal's carbon content based only on daily
measurements of coal HHV through proximate analyses and a default
CO2 emissions factor provided as described in proposed 40
CFR part 98, subpart KK. EPA has concluded that this alternative is
reasonable because it would reduce the sampling and analyses cost
burden on these entities, yet would provide sufficient accuracy given
their relatively small contribution to total U.S. coal supply. We
request comments on this approach.
EPA proposes that all coal importers, coal exporters, and
reclaimers of waste coal use any of three above approaches for
estimating carbon content based on measurements per shipment in place
of daily measurements if preferred. We seek comment on this measurement
approach.
We propose that the ASTM Method D5373 should be used as the
standard for all ultimate analyses.
We considered, but are not recommending, an option to allow all
coal mines to use default coal carbon content values instead of site-
specific values or measurements. Existing information available on the
variability of carbon content for coal from USGS, the U.S. GHG
Inventory, EIA's GHG Inventory, and the IPCC indicate that default
values introduce considerable uncertainty into the emissions
calculation. Given the large share of total GHG emissions represented
by use of coal in the U.S. economy, we view the direct measurement or
estimation of site-specific carbon content values as necessary. We seek
comment on an appropriate approach for reporters--such as importers--
who estimate a weighted annual average GCV according to specified
methodology that is not listed with a corresponding default coal carbon
content value in table KK-1 of this rule. Further information on
various approaches to monitoring GHG emissions is elaborated in the
Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
4. Selection of Procedures for Estimating Missing Data
We have determined that some of the information to be reported by
coal mines, coal importers, coal exporters, and waste coal reclaimers
is routinely collected as part of standard operating practices (e.g.,
coal tonnage). For these cases, we expect no missing data would occur.
Typically, coal is weighed using automated systems on the conveyor
belt or at the loadout facility. In general, the weighing and sampling
of coal at coal mines are conducted at about the same time to ensure
consistency between quantity and quality of coal. In this rule, EPA
proposes that the most current version of NIST Handbook 44 published by
Weights and Measures Division, National Institute of Standards and
Technology be used as the standard practice for coal weighing. In cases
where coal supply data are not available, reporters may estimate the
missing quantity of coal supplied, using documentation for the quantity
of coal received by end-users or other recipients. For any periods
during which mine scales are not operational or records are
unavailable, estimates of coal production at the mine may be estimated
using an average of values of production immediately preceding and
following the missing data period, or other standard industry
practices, such as estimating the volume of coal transported by rail
cars and coal density to estimate total coal weight in tons. For
additional background information on coal weighing, please refer to the
Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
In cases where carbon content or HHV measurements are missing,
reporters may estimate the missing value based on an weighted average
value for the previous seven days.
5. Selection of Data Reporting Requirements
We propose that coal mines, coal importers, coal exporters, and
waste coal reclaimers each report to us annually on the CO2
emissions that would result from complete combustion or oxidation of
coal produced during the previous calendar year.
Information from coal mines should be reported at the facility
level, and should include mine name, mine MSHA identification number,
name of operating company, coal production coal rank or classification
(e.g., anthracite, bituminous, sub-bituminous, or lignite), facility-
specific measured values of coal carbon content or HHV that are used to
calculate CO2 emissions, and the estimated CO2
emissions (metric tons CO2/yr).
Coal importers, coal exporters, and waste coal reclaimers should
report company name and technical contact information (name, e-mail,
phone).
Coal importers should report at the corporate level. Coal importers
already measure coal quantity for each shipment entering the U.S.
Importers generally conduct proximate analyses on each shipment to
assure that coal quality meets the coal specification under contract.
Some importers may also conduct ultimate analysis. Coal importers
should report the quantity of coal imported, coal rank or
classification (e.g., anthracite, bituminous, sub-bituminous, or
lignite), country of origin, origin-specific measured values of coal
carbon content and HHV that are used to calculate CO2
emissions, and estimated CO2 emissions.
Coal exporters should report, at the corporate level, the quantity
of coal exported, coal rank or classification (e.g.anthracite,
bituminous, sub-bituminous, or lignite), name and MSHA identification
number of mine of origin, country of destination, mine-specific
measured values of coal carbon content or HHV that are used to
calculate CO2 emissions, and estimated CO2
emissions (metric tons CO2/yr).
Waste coal reclaimers should report, at the facility level, the
quantity of coal recovered or reclaimed (tons/yr), coal rank or
classification (e.g., anthracite, bituminous, sub-bituminous, or
lignite), name of mine of origin, state of origin, mine-specific
measured values of coal carbon content or HHV that are used to
calculate CO2 emissions, and estimated CO2
emissions.
A full list of data to be reported is contained in the rule. These
data to be reported form the basis of calculating potential
CO2 emissions associated with the total supply of coal into
the U.S. economy. Therefore, these data are necessary for us to
understand the emissions data and to verify the reasonableness of the
reported emissions.
We considered, but are not proposing an option in which we would
obtain facility-specific data for coal production through access to
existing Federal
[[Page 16568]]
Government reporting databases, such as those maintained by MSHA. We
have determined that comparability and consistency in reporting
processes across all facilities included in the entire rule is vital,
particularly with respect to timing of submission, reporting formats,
QA/QC, database management, missing data procedures, transparency and
access to information, and recordkeeping. In addition, EPA's
methodological approach requires information that is not currently
reported to Federal agencies, such as facility-specific information on
coal quality (e.g., coal carbon content or heating value).
6. Selection of Records That Must Be Retained
A full list of records that must be retained onsite is included in
proposed 40 CFR part 98, subparts A and KK. EPA proposes that the
following records specific to suppliers of coal be kept onsite: Daily
production of coal, annual weighted average of coal carbon content
values (if measured), annual weighted average of coal HHV, calibration
records of any instruments used onsite (e.g., if coal analyses are done
onsite), and calibration records of scales or other equipment used to
weigh coal.
These records consist of data that are directly used to calculate
the potential CO2 emissions reported. We have concluded that
these records are necessary to enable verification that the GHG
emissions monitoring and calculation were done correctly.
LL. Suppliers of Coal-Based Liquid Fuels
1. Definition of the Source Category
We are proposing to include facilities that produce coal-based
liquids as well as importers and exporters of coal-based liquids in
this source category. Owners and operators of coal-to-liquids
facilities, or ``producers'', importers, and exporters would report on
the CO2 emissions that would result from complete combustion
or oxidation of the quantities of coal-based liquids supplied to or
exported from the U.S. economy. Producers would report at the facility
level; importers and exporters would report at the corporate level.
The carbon in coal-based liquids would already be captured in the
reporting from domestic coal suppliers and importers, but we believe
that it is important for climate policy development to have additional
information on a unique and potentially growing source of liquid fuels.
As discussed in Sections III and IV of this preamble, emissions
resulting from the combustion and other uses of coal-based liquids, as
well as emissions generated in the production of coal-based liquids,
are addressed in other sections of the preamble, particularly Section
V.C of this preamble (General Stationary Fuel Combustion Sources),
Section V.D (Electricity Generation), and Section V.FF (Underground
Coal Mines).
The output fuels from coal-to-liquids processes are compositionally
similar to standard petroleum-based products e.g., gasoline, diesel
fuel, jet fuel, light gases etc. The most common processes for
converting coal to liquids are direct and indirect liquefaction. In the
direct process, coal is processed directly to liquid. In the indirect
process, coal is first gasified, and then liquefied.
Once manufactured, the supply chain for coal-based liquids to
consumers is basically the same as it is for refined petroleum
products. Liquid fuels are moved from the manufacturing facility to a
terminal, at which point they may be blended or mixed with other
products, before entering the downstream distribution chain. Imported
coal-based liquids would enter the U.S. in the same way that refined
and semi-refined petroleum products enter the country. In determining
the most appropriate point in the supply chain of coal-based liquids,
we followed the decision-making process applied to suppliers of
petroleum products discussed in Section V.MM of this preamble, and
selected coal-to-liquids facilities (analogous to refineries), and
importers and exporters. For further information, see the Coal to
Liquids TSD (EPA-HQ-OAR-2008-0508-038). We request comment on the
approach of establishing a separate source category and subpart for
suppliers of coal-based liquids, and the selection of coal-to-liquids
facilities and corporate importers and exporters of coal-based liquids.
We also request comment on whether or not importers of liquid-based
fuels are likely to have the necessary information with which to
distinguish coal-based liquids from conventional petroleum-based
liquids.
2. Selection of Reporting Threshold
In developing the threshold for suppliers of coal-based liquids,
EPA considered the emissions-based threshold of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e and 100,000 metric tons CO2e per year, but
was limited by the fact that there are very few existing facilities.
According to DOE, there is one facility operating in the world, one
U.S. facility in the engineering phase, and thirteen facilities
proposed in the U.S.\96\ Given that conversion of coal to liquids is a
highly energy intensive process that is viable only on a large scale,
we propose that any coal-to-liquids facility operating in the U.S.
would be required to report.
---------------------------------------------------------------------------
\96\ Coal Conversion--Pathway to Alternate Fuels. C. Lowell
Miller. 2007 EIA Energy Outlook Modeling and Data Conference.
Washington, DC, March 28, 2007.
---------------------------------------------------------------------------
We also propose that all importers and exporters of coal-based
liquids report under this rule. While the number of existing importers
and exporters is very small in comparison to importers and exporters of
petroleum products, importers of coal-based liquids would be required
to track fuel quantities as part of routine business operations, and
report to DOE and other Federal agencies.
For further information, see the Coal to Liquids TSD (EPA-HQ-OAR-
2008-0508-038). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
We are proposing that producers, importers, and exporters of coal-
based liquids calculate potential CO2 emissions associated
with coal-based liquids on the basis of a mass balance approach. Under
this approach, CO2 emissions would be determined by applying
a carbon content value to the quantity of each coal-based liquid
supplied. The formulae are simple and can be automated. For carbon
content, reporters can either use the default CO2 emission
factors for standard petroleum-based fuels in proposed 40 CFR part 98,
subpart MM or develop their own factors.\97\ Reporters that choose to
substitute their own batch- or facility-specific values for density and
carbon share of individual coal-based liquids, and develop their own
CO2 emission factors, must do so according to the proposed
ASTM standards and procedures discussed in proposed 40 CFR part 98,
subpart MM. While carbon content of coal-based liquids may differ from
petroleum products, we believe the default emission factors for
petroleum products in proposed 40 CFR part 98, subpart MM can be used
for estimating emissions from coal-based liquids. We request comment on
this approach, the appropriateness of the proposed default
CO2 emission factors, and ways to improve these default
values. We also
[[Page 16569]]
request comment on the appropriateness of the proposed sampling and
analysis standards and methods for developing batch- or facility-
specific CO2 emission factors, especially the methods for
determining carbon share.
---------------------------------------------------------------------------
\97\ For a discussion of the benefits and disadvantages of
default carbon factors versus direct measurement see Section V.MM.3
of this preamble.
---------------------------------------------------------------------------
4. Selection of Procedures for Estimating Missing Data
We have determined that the information to be reported by suppliers
of coal-based liquids is routinely collected by facilities and entities
as part of standard operating practices, and therefore 100 percent data
availability would be required. Typically, coal-based liquids would be
metered directly at multiple stages. In cases where metered data are
not available, reporters may estimate the missing volumes based on
contracted maximum daily quantities and known conditions of receipt and
delivery during the period when data are missing.
5. Selection of Data Reporting Requirements
We propose that producers, importers, and exporters report
CO2 emissions directly to EPA on an annual basis. Suppliers
would report potential CO2 emissions disaggregated by fuel
types.
We considered but did not propose an option in which we would
obtain facility-specific data for coal-based liquids through access to
existing Federal government reporting databases, such as those
maintained by EIA. EPA believes that comparability and consistency in
reporting processes across all facilities included in the entire rule
are vital, particularly with respect to timing of submission, reporting
formats, QA/QC, database management, missing data procedures,
transparency and access to information, and recordkeeping.
6. Selection of Records That Must Be Retained
A full list of records that must be retained onsite is included in
proposed 40 CFR part 98, subparts A and LL.
MM. Suppliers of Petroleum Products
1. Definition of the Source Category
We are proposing that refineries as well as importers and exporters
of petroleum products be included in this source category. Owners or
operators of petroleum refineries, or ``refiners,'' and importers that
introduce petroleum products into the U.S. economy would be required to
report on the CO2 emissions associated with the complete
combustion or oxidation of their petroleum products. Additionally, both
refiners and importers would be required to report on biomass
components of their petroleum products as well as NGLs they supply to
the economy, and refiners would be required to report on certain types
of feedstock entering their facility. Refiners would report at the
facility level, and importers would report at the corporate level.
Exporters of petroleum products are also included in this source
category in order for us to appropriately account for petroleum
products that are produced but not consumed in the U.S. and therefore
do not result in direct CO2 emissions in the U.S. Exporters
would report on the petroleum products and NGLs they export, including
the biomass components of the petroleum products, at the corporate
level.
End users of petroleum products are addressed in other sections of
this preamble, such as Section V.C (General Stationary Fuel Combustion
Sources), and direct, onsite emissions at petroleum refineries are
covered in Section V.Y of this preamble.
The total estimated GHG emissions resulting from the combustion of
petroleum products in the U.S. in 2006 was 2,417 million metric tons
CO2e, according to the 2008 U.S. GHG Inventory. It is
estimated that 75 percent of the combustion-related CO2
emissions from petroleum use in the U.S. comes from the transportation
sector. The next largest sector is industrial use (15 percent), and the
commercial, residential, and electricity generation sectors make up the
remainder.
Petroleum products are ultimately consumed in one of two ways:
Either through combustion for energy use, or through a non-energy use
such as petrochemical feedstocks or lubricants. Combustion of petroleum
products produces CO2 and lesser amounts of CH4
and N2O, which are in almost all cases emitted directly into
the atmosphere. Some non-energy uses of fuels, such as lubricants, also
result in oxidation of carbon and CO2 emissions. This
process may occur immediately upon first use or, in the case of
biological deterioration, over time. Carbon in other petroleum
products, such as asphalts and durable plastics, may remain un-oxidized
for long periods unless burned as fuel or incinerated as waste.
The following list, while not comprehensive, illustrates the types
of products that EPA considers to fall under the category of petroleum
products:
Motor vehicle and nonroad gasoline and diesel fuels.
Jet fuel and kerosene.
Aviation gasoline.
Propane and other LPGs.
Home heating oil.
Residual fuel oil.
Petrochemical feedstocks.
Asphalt.
Petroleum coke.
Lubricants and waxes.
Reporting Parties. When considering the extent of the definition of
this source category and who should be required to report under this
rule, our approach was first to identify all parties within the
petroleum product supply chain. We considered parties that function
primarily in upstream petroleum production, such as oil drillers and
well owners, as well as petroleum refiners and importers of refined and
semi-refined products. We also considered parties located even further
downstream, such as terminal operators, oxygenate blenders of
transportation fuel, blenders of blendstock, transmix processors, and
retail gas station owners. In addition, we considered pipeline owners
and operators.
As discussed earlier in this preamble, one of our objectives when
determining which entities would fall within a source category was to
identify logical data reporting points or groups of facilities that
were relatively small in number but that could provide a comprehensive
set of data for the particular source category. Of all the parties that
make up the petroleum products supply chain, we have concluded that
petroleum refiners \98\ and importers and exporters of semi-refined and
refined petroleum products are the most appropriate parties to report
to EPA under this source category and that the data they can report
would be comprehensive.
---------------------------------------------------------------------------
\98\ A petroleum refinery is any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, asphalt (bitumen) or other products through distillation
of petroleum or through redistillation, cracking, or reforming of
unfinished petroleum derivatives.
---------------------------------------------------------------------------
There are approximately 150 operating petroleum refineries in the
U.S. and its territories. Our thresholds analysis in Section V.MM.2 of
this preamble, however, only reflects data on the 140 refineries that
reported atmospheric distillation capacity to EIA (at DOE) in 2006.
Petroleum products from these refineries account for approximately 90
percent of U.S. consumption. Given the coverage provided by a
relatively small number of facilities, we propose that all refiners be
subject to the reporting requirements for petroleum product suppliers
and that they report to EPA on a facility-by-facility basis. For
refiners that trade semi-refined and refined petroleum products between
facilities, leading to a
[[Page 16570]]
possible risk of double-counting in coverage, we are proposing a
straight-forward accounting method in Section V.MM.5 of this preamble
to address this possibility.
To account for refined and semi-refined petroleum products that are
not produced at U.S. refineries, we are proposing to include importers
under this source category. Importers currently report to EPA on
petroleum products designated for transportation or non-road mobile
end-uses. This rule would include all importers regardless of end-use
designations. The number of importing companies varies from year to
year, but it is typically on the order of 100 to 200.
We are also proposing to include under this source category
exporters of refined and semi-refined petroleum products in order to
have information on petroleum products that are produced but not
consumed in the U.S. The rationale to include reporting from exporters
is to be able to account for petroleum products that are consumed in
other countries and that do not contribute to direct CO2
emissions in the U.S.
Many refiners are also importers and exporters of petroleum
products. EPA is proposing that such refiners separately report data on
the petroleum products that they produce on a facility-by-facility
basis and report at a corporate level the petroleum products they
import or export. The rationale for this separate reporting is that we
are generally proposing coverage at the facility level where feasible
(e.g., refineries) and proposing corporate reporting only where
facility-level coverage may not be feasible (e.g., importers and
exporters). In addition, the separation simplifies reporting in cases
where a company that owns or operates multiple refineries may have a
consolidated arrangement for imports of refined and semi-refined
products destined for its refineries and for other consumers, or for
exports.
We considered but are not proposing to include parties that are
involved in upstream petroleum production. We believe the number of
domestic oil drillers and well owners is prohibitively large and
represents only a portion of the amount of crude petroleum that is
processed into finished products to be used in the U.S.
We are not proposing to include retail gas station owners and
oxygenate blenders to report to EPA as suppliers of petroleum products.
Retail gas station owners and oxygenate blenders mostly handle
transportation fuel and fuel used in small engines. Because we are
interested in GHG emissions from all petroleum products combusted or
consumed in the U.S. and can obtain information on such products on a
more aggregated basis directly from refiners and importers, we are
proposing to exclude retail gas station owners and oxygenate blenders
from reporting under this rule.
We are not proposing to include operators of terminals or
pipelines, blenders of blendstocks, or transmix processors in this
source category because we believe that refiners and importers can
provide comprehensive information on petroleum products supplied in the
U.S. with a lower risk of double-counting petroleum products. A given
quantity of refined or semi-refined petroleum product may pass between
multiple terminals and blending facilities, so asking terminal or
pipeline operators, blenders of blendstock, or transmix processors to
report information on incoming and outgoing products would likely
result in unreliable data for estimating GHG emissions from petroleum
products.\99\
---------------------------------------------------------------------------
\99\ See Section V.MM.3 of this preamble regarding a method for
accounting for trade between refineries.
---------------------------------------------------------------------------
Liquid fossil fuel products can be derived from feedstocks other
than petroleum crude, such as coal and natural gas. Suppliers of coal-
based products are covered under Section V.LL of this preamble,
Suppliers of Coal-Based Liquid Fuels. Primary suppliers of natural gas-
based products are covered in Section V.NN of this preamble, Suppliers
of Natural Gas and Natural Gas Liquids. We are proposing to require all
reporters in this source category to report data on the NGLs they
supply to or export from the economy because these products may not
currently be captured under Section V.NN of this preamble, Suppliers of
Natural Gas and NGLs. The natural-gas related reporting requirements
are discussed in Section V.MM.5 of this preamble.
This section of the preamble is focused on suppliers of petroleum
products, so EPA is not proposing to include primary \100\ suppliers of
renewable fuels, such as fuel derived from biomass like grains, animal
fats and oils, or waste, under this source category. However, as
described in Section IV.B of this preamble (Reporting by fuel and
industrial gas suppliers), we note that we are not proposing to require
suppliers of biomass-based fuels to report on their products anywhere
under this rule, except as discussed below for petroleum suppliers, due
to a longstanding accounting convention adopted by the IPCC, the
UNFCCC, the U.S. GHG Inventory, and many other State and regional GHG
reporting programs where emissions of CO2 from the
combustion of renewable fuels are distinguished from emissions of
CO2 from combustion of petroleum or other fossil-based
products. Under such convention, potential emissions from the
combustion of biomass-based fuels are accounted for at the time of
feedstock harvest, collection, or disposal, not at the point of fuel
combustion. Nonetheless, we seek comment on this approach.
---------------------------------------------------------------------------
\100\ Refiners, exporters, and importers of petroleum products
could, in some cases, be suppliers of renewable fuels but their
supply of renewable fuels is not the focus of this subpart.
---------------------------------------------------------------------------
Certain petroleum products can be co-processed or blended with
renewable fuels. We are proposing a method in Section V.MM.5 of this
preamble whereby petroleum product suppliers report data that allows
EPA to distinguish between the biomass and fossil fuel-based carbon in
their products.
2. Selection of Reporting Threshold
In assessing the appropriateness of applying a threshold to
refiners (at the facility level) and importers (at the corporate
level), we calculated the volume of finished gasoline that would
contain enough carbon that, when combusted or oxidized, would produce
1,000 metric tons CO2e, 10,000 metric tons CO2e,
25,000 metric tons CO2e, and 100,000 metric tons
CO2e. We took the volume of finished gasoline as an example
of how much of a refined or semi-refined product would result in a
given level of CO2 emissions. These data are summarized in
Table MM-1 of this preamble.
Table MM-1. Threshold Analysis for Finished Gasoline
------------------------------------------------------------------------
Total volume
Threshold level metric tons CO2/yr of gasoline
bbls/yr
------------------------------------------------------------------------
1,000................................................... 2,564
10,000.................................................. 25,641
25,000.................................................. 64,103
100,000................................................. 256,410
------------------------------------------------------------------------
Based on the calculations in Table MM-1 of this preamble and data
on the annual volume of petroleum products that refiners and importers
are currently reporting to the EIA, EPA estimated the number of
refineries and importers that would meet each of the four selected
threshold levels. The results of this analysis are summarized below.
[[Page 16571]]
Refineries. Data on the typical production levels for refineries
\101\ demonstrate that each of the thresholds considered would cover
all domestic refineries (see Table MM-2 of this preamble). This
conclusion is based on the result that all refineries would exceed the
thresholds for gasoline alone, and therefore would also exceed the
thresholds for all products combined. For this reason, we are proposing
to cover all petroleum refineries.
---------------------------------------------------------------------------
\101\ To simplify our reporting threshold analysis, EPA omitted
roughly 10 refineries that meet our definition of a petroleum
supplier but did not report any atmospheric distillation capacity to
EIA.
Table MM-2. Threshold Analysis for Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions 1 2 Total number ------------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons CO2/ of facilities Metric tons CO2/
yr \3\ yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000............................................. 2,447,738,368 140 2,447,738,368 100 140 100
10,000............................................ 2,447,738,368 140 2,447,738,368 100 140 100
25,000............................................ 2,447,738,368 140 2,447,738,368 100 140 100
100,000........................................... 2,447,738,368 140 2,447,738,368 100 140 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ These constitute total emissions from all petroleum products ex refinery gate. The total includes only CO2 emissions.
\2\ Estimated CO2 emissions for all refineries are based on applying product-specific default carbon contents to production of each product.
\3\ This number represents the total number of refineries that reported atmospheric distillation capacity to EIA in 2006.
Small Refiners. In recent EPA fuel rulemakings, we have provided
temporary exemptions from our regulations for small refiners, defined
as producers of transportation fuel from crude oil that employed an
average of 1,500 people or fewer over a given one-year period and with
a corporate-average crude oil capacity of 155,000 barrels per calendar
day or less. Such small refiner exemptions were provided to allow small
refiners extra time to meet standards or comply with new regulations.
This exemption was based on an assumption that to require small
refiners to comply with new regulations on the same schedule as larger
refiners would put them at a disadvantage if required to seek the same
capital and administrative resources being sought by their larger
competitors. Because of the nature of this reporting rule, however, we
are not proposing any temporary exemptions for small refiners. We do
not believe complying with this rule will require additional resources
that might put small refiners at an unfair disadvantage. All refiners
would already be reporting data to EPA, regardless of size, because all
refineries meet the proposed reporting threshold in proposed 40 CFR
part 98, subpart Y for direct onsite emissions.
Importers. Data on importers of petroleum products in 2006, the
most recent year available, show that 78 percent of the importing
companies exceeded the 25,000 metric tons CO2e/yr reporting
threshold and that some importing companies did not meet the 1,000
metric tons CO2e/yr threshold (see Table MM-3 of this
preamble). While 22 percent of importers supplied less than the amount
of products that, when combusted or oxidized, would have resulted in
25,000 metric tons CO2/yr, data on the amount and types of
petroleum products is information that all importers maintain as part
of their normal business operations. Therefore we believe the burden of
reporting the required information listed in Section V.MM.5 of this
preamble is minimal since no additional monitoring equipment has to be
installed to comply with this rule. In addition, the quantity of
products imported by a company may vary greatly from year to year.
Furthermore, our proposed definition for petroleum products for
importers and exporters in Subpart A excludes asphalt and road oil,
lubricants, waxes, plastics, and plastic products. For these reasons,
we are proposing that all importers of petroleum products be required
to report to EPA, and we seek comment on our proposed definition of
petroleum products as it applies to importers.
Table MM-3. Threshold Analysis for Importers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Companies covered
emissions \1\ Total number ------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of importers Metric tons
CO2/yr CO2/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
<1000............................................................ 393,294,390 224 393,294,390 100 224 100
1,000............................................................ 393,294,390 224 393,291,916 >99.9 219 98
10,000........................................................... 393,294,390 224 393,171,144 >99.9 193 86
25,000........................................................... 393,294,390 224 392,895,841 99.9 175 78
100,000.......................................................... 393,294,390 224 389,628,252 99 120 54
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ These constitute total emissions from all product imports. Analysis is based on EIA's Company Reports for 2006.
Exporters. Due to the limited availability of export data, EPA did
not conduct a threshold analysis for petroleum products exporters.
However, based on the type of information that exporters must maintain
as part of their normal business operations, we believe that the
incremental burden of reporting this information to EPA would be
minimal. Considering this information and the importance of being able
to account for petroleum products produced but not combusted or
oxidized in the U.S., EPA is proposing that all exporters report on
their exported petroleum products. Furthermore, our proposed definition
for petroleum products for importers and exporters in Subpart A
excludes asphalt and road oil, lubricants, waxes, plastics, and plastic
products. We seek comment on this proposal.
De Minimis Exports and Imports. We are seeking comment on whether
or not to establish a de minimis level, either in terms of total
product volume or potential CO2 emissions, to eliminate
[[Page 16572]]
any reporting burden for parties that may import or export a small
amount of petroleum products on an annual basis. We also note that in
the proposed rule some importers and exporters may not be required to
report their onsite combustion, process, and/or fugitive emissions
under other sections of the proposed rule because their combined
emissions do not meet the applicable thresholds.
For a full discussion of the threshold analysis, please refer to
the Suppliers of Petroleum Products TSD (EPA-HQ-OAR-2008-0508-039). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
Rather than directly measuring emissions from the combustion or
consumption of their products, suppliers of petroleum products would
need to estimate the potential emissions of their non-crude feedstocks
and products based on volume and characteristic information. Therefore
product volume metering and sampling would be of utmost importance to
accurately calculate potential CO2 emissions.
Volume measurement. EPA is proposing to require specific industry-
standard test methods for flow meters and tank gauges for measuring
volumes of feedstocks and products. For ultra-sonic flow meters, we
propose to require the test method described in AGA Report No. 9
(2007); for turbine meters, American National Standards Institute,
ANSI/ASME MFC-4M-1986; for orifice meters, American National Standards
Institute, ANSI/API 2530 (also called AGA-3) (1991); and for coriolis
meters, ASME MFC-11 (2006). For tank gauges, we propose to require the
following test methods: API-2550: Measurements and Calibration of
Petroleum Storage Tanks (1965), API MPMS 2.2: A Manual of Petroleum
Measurement Standards (1995), or API-653: Tank Inspection, Repair,
Alteration and Reconstruction, 3rd edition (2008).
We propose that all flow meters and tank gauges must be calibrated
prior to monitoring under this rule using a method published by a
consensus standards organization (e.g., ASTM, ASME, American Petroleum
Institute, or NAESB), or using calibration procedures specified by the
flow meter manufacturer. Product flow meters and tank gauges would be
required to be recalibrated either annually or at the minimum frequency
specified by the manufacturer.
Carbon content determination. To translate data on petroleum
product, NGLs, and biomass types and quantities into estimated
potential GHG emissions, it is necessary either to estimate or measure
the carbon content for each product type. For this proposal, we
reviewed the existing CO2 emission factors developed by EIA
and used in the U.S. GHG Inventory, and we researched the sampling and
test methods that would be required for direct measurement of carbon
content by reporters.
We also considered the benefits and disadvantages of using default
carbon content factors and of using direct measurements of carbon
content. Default CO2 emission factors have been used
extensively in the U.S. GHG Inventory, in inventories of other nations,
and in corporate reporting guidance; they are simple and cost effective
for evaluating GHG emissions from common classes of biomass and fossil
fuel types (e.g., ethanol, motor gasoline, jet fuel, distillate fuel,
etc). It is also possible to combine default CO2 emission
factors to develop alternative factors for fuel reformulations by
averaging according to weight. Some products, however, can have
multiple chemical compositions due to different feedstock, blending
components, and/or refinery processes, which can lead to variations in
carbon content. Default CO2 emission factors for common
chemical compositions of common products cannot account for the full
variability of carbon content in petroleum, natural gas, and biomass
products.
Direct measurements would provide the most accurate determination
of carbon content. It is relatively expensive, however, to design and
implement a program for regular sampling and testing for carbon content
across the variety of products produced at refineries. Many products
are homogeneous because they must meet ``minimum'' specifications
(e.g., jet fuel), and the use of direct measurements may not lead to
noticeable improvements in accuracy over default CO2
emission factors.
Based on this information, we are proposing that for purposes of
estimating emissions, reporters could either use the default
CO2 emission factors for each product type published in
proposed 40 CFR part 98, subpart MM or, in the case of petroleum
products and NGLs, develop their own factors. Reporters that choose to
substitute their own values for density and carbon share of individual
petroleum products and NGLs, and develop their own CO2
emission factors would be required to sample each product monthly for
the reporting year and to test the composite sample at the end of the
reporting period using ASTM D1298 (2003), ASTM D1657-02(2007), ASTM
D4052-96(2002)el, ASTM D5002-99(2005), or ASTM D5004-89(2004)el for
density, as appropriate, and ASTM D5291(2005) or ASTM D6729-(2004)el
for carbon share, as appropriate (see Suppliers of Petroleum Products
TSD (EPA-HQ-OAR-2008-0508-039)). For suppliers of seasonal gasoline,
reporters would be required to take a sample each month of the season
and test the composite sample at the end of the season.
We request comment on this approach. We request comment on whether
reporters should be allowed to combine default CO2 emission
factors to develop alternative factors for fuel reformulations
according to the volume percent of each fuel component, and if so using
what methodology. We also request comment on the appropriateness and
adequacy of the proposed default CO2 emission factors--
including factors for biomass products--and ways to improve these
default values. For full documentation of the derivation of the
proposed default factors, please refer to the Suppliers of Petroleum
Products TSD (EPA-HQ-OAR-2008-0508-039).
In addition, we request comment on the appropriateness of the
proposed sampling and analysis standards and methods for developing
CO2 emission factors for petroleum products and NGLs,
especially the methods for determining carbon share. Specifically, we
seek comment on specific ASTM or other industry standards that would be
more appropriate for sampling petroleum products and NGLs to determine
carbon share. Finally, we request comment on potential methods to
determine carbon share of biomass products.
The various approaches to monitoring GHG emissions are elaborated
in the Suppliers of Petroleum Products TSD (EPA-HQ-OAR-2008-0508-039).
4. Selection of Procedures for Estimating Missing Data
Under this proposal, we are suggesting methods for estimating data
that may be missing from different source categories for various
reasons. Petroleum product suppliers would need to estimate any missing
data on the amount of petroleum products or NGLs supplied or exported,
and the quantity of the crude and non-crude feedstocks, including
biomass, consumed. In most cases, the source category would be missing
data due to monitoring equipment malfunction or shutdown.
[[Page 16573]]
We have determined that the information to be reported by petroleum
fuel suppliers is collected as part of standard operating practices,
and expect that any missing data would be negligible. Typically,
products are metered directly at multiple stages, and billing systems
require rigorous reconciliation of data. In cases where metered data
are not available, we are proposing that reporting parties may estimate
the missing volumes based either on the last valid data point they
recorded or on an average of two valid data points based on their
established procedures for purposes of product tracking and billing. We
seek comment on the appropriateness and adequacy of our proposed
procedures for estimating missing data. Petroleum product suppliers
reporting under this rule would be required to keep sufficient records
to verify any volume estimates (see Section V.MM.6 of this preamble).
5. Selection of Data Reporting Requirements
We are proposing that suppliers of petroleum products be required
to report the type, volume, and CO2 emissions associated
with the complete combustion or oxidation of each individual petroleum
product and NGL they supply to the economy, export, or use as a
feedstock annually. We are also proposing to require reporting on the
total CO2 emissions of all products they supply to the
economy annually, minus any emissions associated with non-crude
feedstocks, including biomass, and renewable fuel blended in a
petroleum product. Additionally, we are proposing to require refiners
to report information on the volume, API gravity, sulfur content, and
country of origin of each crude oil batch used as feedstock at a
refinery. Finally, we are proposing to require reporting on the volume
of diesel fuel that is most likely to be used in the onroad mobile
source sector.
The only GHG required to be reported under proposed 40 CFR part 98,
subpart MM is CO2. Combustion of petroleum products may also
lead to trace quantities of CH4 and N2O
emissions.\102\ The amounts of CH4 and N2O are
dependent on factors other than fuel characteristics such as combustion
temperatures, air-fuel mixes, and use of pollution control equipment.
These other factors vary significantly across and within the major
categories of petroleum product end-uses. EPA bases national estimates
of CH4 and N2O for the U.S. GHG Inventory on
bottom-up data, such as penetration of control technologies and
distance traveled for on-highway mobile sources.\103\ We seek comment
on whether or not EPA should use the national inventory estimates of
CH4 and N2O emissions from petroleum product
combustion and apportion them to individual petroleum product suppliers
based on the quantity of their product.
---------------------------------------------------------------------------
\102\ CO2, CH4 and N2O
emissions from combustion of petroleum products were 1900, 3.1, and
34.1 million metric tons CO2e, respectively.
\103\ 2008 U.S. GHG Inventory, Annex 3--Methodological
Descriptions for Additional Source or Sink Categories. pp. A-106 to
A-120.
---------------------------------------------------------------------------
Data related to products supplied to or exported from the economy.
We are proposing that petroleum product suppliers use a mass-balance
method to calculate CO2 emissions, which is used extensively
in national GHG inventories and in existing reporting guidelines for
facilities, companies, and states, such as the WRI/WBCSD GHG
Protocol.\104\ The mass balance approach is based on readily available
information: The volume of fuel, which is typically tracked by
suppliers, and the carbon content of the fuel, i.e., mass of carbon per
volume of fuel (the carbon content of the petroleum product is also
referred to as the CO2 emission factor). The formula to
apply this method is simple and can be automated.\105\ Carbon content,
where not measured directly, can be estimated using other readily
available data and literature values.
---------------------------------------------------------------------------
\104\ See The Greenhouse Gas Protocol (GHG Protocol) http://www.ghgprotocol.org/; the 2008 U.S. Inventory http://www.epa.gov/climatechange/emissions/downloads/08_Energy.pdf, and the 2006 IPCC
Guidelines http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol2.html.
\105\ The generic formula is CO2 = Fuel Quantity *
Carbon Content * 44/12.
---------------------------------------------------------------------------
There is substantial trade and transfer of products between
refiners, between importers and refiners, and between other parties.
The products supplied by one refiner might in some cases serve as the
feedstock for another refiner. To avoid double-counting of emissions,
we are proposing an elaboration of the mass-balance approach for use by
refiners. Under this elaborated approach, to account for the fact that
any non-crude feedstock \106\ entering a refiner's facility would have
already been reported by the non-crude feedstock's source (such as an
importer or another refiner), the refiner would measure and report the
potential CO2 emissions from the non-crude feedstock, but
then subtract the amount from the overall CO2 emissions they
report.
---------------------------------------------------------------------------
\106\ This could include both petroleum- and natural gas-based
products.
---------------------------------------------------------------------------
We are proposing that suppliers report to EPA the types of products
and quantities of products sold during the reporting period or
otherwise transferred to another facility, in the case of refiners, or
corporate entity, in the case of importers and exporters. This
information underlies the proposed CO2 emissions
calculations. By focusing on petroleum products sold versus produced,
we would avoid double-counting products, especially semi-refined
products, that would either be used onsite by the facility to generate
energy or that would be reused as a feedstock at some point in the
facility's production process.
We are not proposing that petroleum product suppliers collect new
information on those petroleum products which may be used or converted
by other entities into long-lived products that are not oxidized or
combusted, or oxidized slowly over long periods of time (e.g.,
plastics). A comprehensive and rigorous system for tracking the fate of
non-energy petroleum products and their various end-uses is beyond the
scope of this rule, and would require a much more burdensome reporting
obligation for petroleum product suppliers. However, at some point, we
may need to address the question of non-emissive end uses of petroleum
products as part of future climate policy development. We request
comment on our proposal to require petroleum product suppliers to
report the CO2 emissions associated with products that could
potentially have non-emissive end-uses. We also request comment on ways
in which non-emissive end-uses could be tracked and reported.
Data related to crude feedstocks. We are proposing that refiners
report basic information to EPA on the crude oil feedstock type, API
gravity, sulfur content and country of origin during the reporting
period. This basic information on the feedstock characteristics would
provide useful information to EPA to assess the lifecycle GHG emissions
associated with petroleum refining.
Data related to non-crude petroleum and natural gas feedstocks. As
discussed previously, in order to minimize double-counting of non-crude
petroleum products and NGLs, we would require refiners to report the
volume and CO2 emissions of any non-crude petroleum and
natural gas feedstock that was acquired from an outside facility. We
are not proposing to require reporting of products produced at the
facility and recycled back into processing. In the event that a
reporter cannot determine whether a feedstock is petroleum-or natural
gas-based, we are proposing to have the reporter assume the product is
petroleum-based. We request comment on methods for distinguishing
between natural gas- and petroleum-based feedstock.
[[Page 16574]]
Data related to co-processed biomass and blended biomass-based
fuels. We are proposing to require reporters to provide information on
the biogenic portion of petroleum products under two circumstances
discussed below. We are proposing these reporting requirements to
ensure that EPA can distinguish between potential emissions of carbon
from biogenic sources (i.e., biomass) and from non-biogenic sources
(i.e., fossil fuel). We believe it is important to make this
distinction because CO2 emissions from biogenic sources are
traditionally accounted for at the time of harvest, collection, or
disposal, rather than the point of fuel combustion.
First, we are proposing to require refiners to report information
related to biomass that is co-processed with a petroleum feedstock
(crude or non-crude) to produce a product that would be supplied to the
economy. We propose that refiners report the volume of and estimated
CO2 emissions associated with both the biomass and
petroleum-based portions of these products. Refiners would then
subtract the estimated CO2 emissions from the biomass
portion from their total CO2 emissions calculation. We are
not proposing to require refiners to report on CO2 emissions
from biomass they combust onsite or co-process with a petroleum
feedstock to produce a product that they combust onsite; these
emissions are addressed in Section V.Y of this preamble.
Second, in the case where a reporter supplies or exports a
petroleum product that is blended with a biomass-based fuel, we are
proposing only to require CO2 emissions information on the
petroleum-based portion of the product along with the volume of the
biomass-based fuel. This reporting requirement would also apply to a
refiner that receives a blended fuel (e.g., gasoline with ethanol) as
feedstock to be further refined or otherwise used onsite. We are also
assuming that all reporters would know the percent volume of the
biomass-based component of any product. We seek comment on this
assumption and on any necessary methods for distinguishing between
biomass- and petroleum-based components of blended fuels.
Under this proposal, we are proposing to require reporters to
calculate and report CO2 emissions from products derived
from co-processing biomass and petroleum feedstocks outside their
operations as if the products were entirely petroleum-based. We are not
requiring reporters to report information on products that were derived
entirely from biomass. We seek comment on this proposed approach
towards biomass reporting.
Carbon Content. We are proposing that petroleum product suppliers
that directly measure the batch-or facility-specific density or carbon
share of their products report the density and carbon content values
along with the testing and sampling standards they use for each
product.\107\ We are not proposing that reporters that choose to use
the default carbon content values provided in the proposed 40 CFR part
98, subpart MM be required to report these values since they can easily
be back-calculated with data on volume and CO2 emissions.
---------------------------------------------------------------------------
\107\ Proposed 40 CFR part 98, subpart MM identifies the
specific ASTM standards that reporters must use, but allows
discretion for the reporter to select the most appropriate standard.
---------------------------------------------------------------------------
Designated End-use. Although not required as a direct input to the
mass-balance equation for estimating total emissions, EPA is also
interested in collecting data on designated end-use (such as for use in
a highway vehicle versus a stationary boiler) of petroleum products for
effective policy development. EPA recognizes that petroleum product
suppliers do not always have full knowledge of the ultimate end-use of
their products. We evaluated the potential end-uses that petroleum
product suppliers could know, including end-use designations required
by EPA's transportation fuel regulations,\108\ and determined that
reporters should be able to identify diesel fuel intended for use on
highway since it must contain less than 15 ppm of sulfur and should not
contain dyes or markers associated with nonroad and stationary fuel. We
recognize, however, that some of this fuel may ultimately be used in
nonroad and stationary sectors. We request comment on this proposal, on
the extent to which this and other refinery gate (ex refinery) and
importer end-use designations reflect actual end-use consumption
patterns, and other options EPA could pursue to track the combustion-
related end-uses of petroleum products.
---------------------------------------------------------------------------
\108\ Current regulations require refiners and importers to
designate diesel fuel (40 CFR 80.598(a)(2)).
---------------------------------------------------------------------------
Reporting to EIA. We realize that most petroleum product suppliers
report much of the relevant fuel quantity information to EIA on a
monthly, quarterly, or annual basis. During development of this
proposal, EPA consulted with EIA on its existing reporting programs and
discussed the feasibility of sharing this information through an
interagency agreement, rather than requiring reporting parties to
report the same information multiple times to the Federal government.
However, we have concluded that comparability and consistency in
reporting processes across all facilities included in the entire rule
is vital, particularly with respect to timing of submission, reporting
formats, QA/QC, database management, missing data procedures,
transparency and access to information, and recordkeeping. In addition,
all refineries would be reporting emissions from petroleum refining
processes under proposed 40 CFR part 98, subpart Y. Finally, as noted
above, we are requesting readily available information from petroleum
product suppliers and do not consider reporting information to more
than one Federal agency an undue burden for these industries. We thus
considered but are not proposing an option in which EPA obtains
facility-specific data for suppliers of petroleum products through
access to existing Federal government reporting databases, such as
those maintained by EIA. However, in order to reduce the reporting
burden placed on industry, we would consider information that refiners
and importers already report to EIA with respect to units and
frequency, for example, when crafting the reporting requirements for
refiners, importers, and exporters under the final rule.
Reporting to EPA's Office of Transportation of Air Quality. EPA
currently collects a variety of information associated with the
production and use of most transportation fuels in the U.S. in order to
ensure compliance with existing fuel regulations and standards. Over
the course of many years, EPA has developed a reporting system for its
transportation fuels programs that incorporates a number of compliance
and enforcement mechanisms. For example, all reporting parties must
register their facilities with EPA and in many cases use EPA's
dedicated reporting web portal, the CDX, to submit their reports. We
review reports to identify reporting errors (e.g. incorrect report
formats or missing data) but also require reporting parties to self-
report any errors or anomalies in their data. For some of our existing
transportation fuels reporting programs, we employ the use of annual
attest engagements, audits of the reporting parties' records by an
independent certified public accountant or certified internal auditor,
to help ensure that the data submitted in reports to EPA reflect data
maintained in the reporting parties' records.
For purposes of this rule, we are interested in minimizing the
additional reporting burden on reporters by
[[Page 16575]]
utilizing existing reporting and verification systems, such as EPA's
transportation fuel programs reporting protocols, as appropriate. We
request comments on ways to take advantage of existing reporting and
verification programs, particularly those related to transportation
fuels. Specifically, as noted in Section IV.J.3 of this preamble, we
are seeking comment on requiring annual attest engagements for all
reporters under proposed 40 CFR part 98, subpart MM. In addition,
whereas the proposed deadline for annual report submission is March 31
following the reporting year for all reporters under this rule, we seek
comment on an alternative deadline of February 28 following the
reporting year for annual reports from suppliers of petroleum products.
This deadline would align with the submission deadline for annual
compliance reports under several existing EPA fuels programs.
6. Selection of Records That Must Be Retained
We are proposing that reporters under this source category must
maintain all of the following records: copies of all reports submitted
to EPA under this rule, records documenting the type and quantity of
petroleum products and NGLs supplied to or exported from the economy,
records documenting the type, characteristics, and quantity of
purchased feedstocks, including crude oil, LPGs, biomass, and semi-
refined feedstocks, records documenting the CO2 emissions
that would result from complete combustion or oxidation of the
petroleum products, NGLs, and biomass, and sampling and analysis
records related to all batch-or facility-specific carbon contents
developed and used in reporting to EPA.
These records should contain data directly used to calculate the
emissions that are reported and are necessary to enable verification
that the CO2 emissions monitoring and calculations were done
correctly. These records would also consist of information used to
determine the required characteristics of crude feedstocks.
NN. Suppliers of Natural Gas and Natural Gas Liquids
1. Definition of the Source Category
This subpart would require reporting by facilities and companies
that introduce or supply natural gas and NGLs into the economy (e.g.,
LDCs). These facilities and companies would report the CO2
emissions that would result from complete combustion or oxidation of
the quantities of natural gas and NGLs supplied (e.g., as a fuel).
Combustion and other uses of natural gas are addressed in other
subparts, such as proposed 40 CFR part 98, subpart C (General Fuel
Stationary Combustion Sources).
Natural gas is a combustible gaseous mixture of hydrocarbons,
mostly CH4. It is produced from wells drilled into
underground reservoirs of porous rock. Natural gas withdrawn from the
well may contain liquid hydrocarbons and nonhydrocarbon gases. The
natural gas separated from these components at gas processing plants is
considered ``dry''. Dry natural gas is also known as consumer-grade
natural gas. In 2006, the combustion of natural gas for useful heat and
work resulted in 1,155.1 million metric tons CO2e emissions
out of a total of 7,054.2 million metric tons CO2e of GHG
emissions in the U.S.
In addition to being combusted for energy, natural gas is also
consumed for non-energy uses in the U.S. The non-energy applications of
natural gas are diverse, and include feedstocks for petrochemical
production, ammonia, and other products. In 2006, emissions from non-
energy uses of natural gas were 138 million metric tons
CO2e.
The supply chain for delivering natural gas to consumers is
complex, involving producers (i.e., wells), processing plants, storage
facilities, transmission pipelines, LNG terminals, and local
distribution companies. In developing the proposed rule, we concluded
that inclusion of all natural gas suppliers as reporters would not be
practical from an administrative perspective, nor would it be necessary
for complete coverage of the supply of natural gas. In determining the
most appropriate point in the supply chain of natural gas, we applied
the following criteria: An administratively manageable number of
reporting facilities; complete coverage of natural gas supply as a
group of facilities or in combination with facilities reporting under
other subparts of this rule; minimal irreconcilable double-counting of
natural gas supply; and feasibility of monitoring or calculation
methods.
Based on these criteria, we are proposing to include LDCs for
deliveries of dry gas, and natural gas processing facilities for the
supply of NGLs as reporters under this source category. LDCs receive
natural gas from the large transmission pipelines and re-deliver the
gas to end users on their systems, or, in some cases, re-deliver the
natural gas to other LDCs or even other transmission pipelines.
Importantly, LDCs keep records on the amount of natural gas delivered
to their customers. In 2006, LDCs delivered about 12.0 trillion cf or
60 percent of the total 19.9 trillion cf delivered to consumers. The
balance of the natural gas is delivered directly to large end users in
industry and for power generation. Most of these large end users would
already be included as reporting facilities for direct GHG emissions
because their emissions exceed the respective emissions threshold for
their source category.
LDCs meter the amount of gas they receive and meter and bill for
the deliveries they make to all end-use customers or other LDCs and
pipelines. Some of the end-use customers may be large industrial or
electricity generating facilities that would be included under other
subparts for direct emissions related to stationary combustion. LDCs
already report their total deliveries to DOE as well as to State
regulators. There are approximately 1,207 LDCs in the U.S.\109\
---------------------------------------------------------------------------
\109\ This number includes all LDCs that report to EIA on Form
176, and includes separate operating companies owned by a single
larger company, as for example Niagara Mohawk, a LDC in New York,
owned by National Grid, which also owns other LDCs in New York and
New England. For the purposes of this rule, LDCs are defined as
those companies that distribute natural gas to ultimate end users
and which are regulated as separate entities by state public utility
commissions.
---------------------------------------------------------------------------
Natural gas processing facilities (defined as any facility that
extracts or recovers NGLs from natural gas, separates individual
components of NGLs using fractionation, or converts one form of natural
gas liquid into another form such as butane to isobutene using
isomerization process) take raw untreated natural gas from domestic
production and strip out the NGLs, and other compounds. The NGLs are
then sold, and the processed gas is delivered to transmission
pipelines.\110\ According to EIA, processors generated about 638
million barrels of NGLs, in 2006, which is 69 percent of NGLs supplied
in the U.S. Processors meter the NGLs they produce and deliver to
pipelines. These data are reported to DOE.
---------------------------------------------------------------------------
\110\ This definition of processors does not include field
gathering and boosting stations, and is therefore narrower in scope
than the definition provided earlier in the preamble for the oil and
gas sector.
---------------------------------------------------------------------------
We are not proposing that processing plants report supply of dry
natural gas to transmission pipelines. While the processing industry in
2006 delivered an estimated 13.8 trillion cf of processed, pipeline
quality gas into the pipeline system, an estimated 30 percent of dry
natural gas goes directly from production fields to the transmission
pipelines, completely by-passing processing plants. In the interest of
increasing coverage, we considered but decided not to propose including
[[Page 16576]]
production wells producing pipeline quality natural gas (i.e., not
needing significant processing) due to the large number of potential
facilities affected.
We considered but are not proposing to include the approximately
448,641 (in 2006) production wells in the U.S. as covered facilities.
Producers routinely monitor production to predict sales, to distribute
sales revenues to working interest owners, pay royalties, and pay State
severance taxes. These data are reported regularly to State agencies.
At the national level, however, inclusion of producers would be
administratively difficult and would include many small facilities. EIA
collects reports from a subset of larger producers in key States, but
relies on State data to develop comprehensive aggregated national
statistics.
We considered but are not proposing to include interstate and
intrastate pipelines. Pipeline operators transport almost all of the
natural gas consumed in the U.S. including both domestically produced
and imported natural gas. While there are a relatively modest number of
transmission pipelines, approximately 160, and the operators meter
flows and report these data to DOE, their inclusion as reporters would
introduce significant complications. The U.S. pipeline network is
characterized by interconnectivity, in which natural gas moves through
multiple pipelines on its way to the consumers. Given the hundreds of
receipt and delivery points and the interconnections with a
multiplicity of other pipelines, processing plants, LDCs, and end
users, a substantial amount of double-counting errors would be
introduced. A time- and resource-intensive administrative effort by EPA
and reporting companies would be required annually in an attempt to
correct this double-counting.
We are also not proposing to include importers of natural gas as
reporting facilities. Natural gas is imported by land via transmission
pipelines (primarily from Canada), and as LNG via a small number of
port terminals (predominantly on the East and Gulf coasts). Imported
natural gas ultimately is delivered to consumers by LDCs or sent
directly to high volume consumers who would report under other subparts
of proposed 40 CFR part 98.
EPA requests comment on the inclusion of LDCs and processing
plants, and the exclusion of other parts of the natural gas supply and
distribution chain. For additional background information on suppliers
of natural gas, please refer to the Suppliers of Natural Gas and NGLs
TSD (EPA-HQ-OAR-2008-0508-040).
2. Selection of Reporting Threshold
In developing the reporting threshold for LDCs and natural gas
processors, EPA considered emissions-based thresholds of 1,000 metric
tons CO2e, 10,000 metric tons CO2e, 25,000 metric
tons CO2e and 100,000 metric tons CO2e per year.
For natural gas suppliers, these thresholds are applied on the amount
of CO2 emissions that would result from complete combustion
or oxidation of the natural gas. These thresholds translate into 18,281
thousand cf, 182,812 thousand cf, 457,030 thousand cf, and 1,828,120
thousand cf of natural gas, respectively.
Table NN-1 of this preamble illustrates the LDC emissions and
facilities that would be covered under these various thresholds.
Table NN-1. Threshold Analysis for LDCs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities Metric tons
CO2e/yr CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 632,100,851 1,207 632,004,022 99.98 1,022 85
10,000.................................................. 632,100,851 1,207 630,106,725 99.68 521 43
25,000.................................................. 632,100,851 1,207 627,543,971 99.28 365 30
100,000................................................. 632,100,851 1,207 619,456,607 98.00 206 17
--------------------------------------------------------------------------------------------------------------------------------------------------------
We propose to include all LDCs as reporters in this source
category. Of the approximate 1,207 LDCs, the 25,000 metric tons
CO2e threshold would capture the 365 largest LDCs and 98
percent of the natural gas that flows through them. The remaining LDCs
already report annual throughput to EIA in form EIA 176. Thus,
inclusion of all LDC's does not require collection of new information.
Comments on this conclusion are requested.
Table NN-2 of this preamble illustrates the NGL emissions and
number of processing facilities that would be covered under these
various thresholds.
Table NN-2. Threshold Analysis for NGLs From Processing Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ---------------------------------------------------------------
Threshold level metric tons CO2e/yr metric tons of facilities Metric tons
CO2e/yr CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000................................................... 164,712,077 566 164,704,346 100 466 82
10,000.................................................. 164,712,077 566 164,404,207 100 400 71
25,000.................................................. 164,712,077 566 163,516,733 99 347 61
100,000................................................. 164,712,077 566 157,341,629 96 244 43
--------------------------------------------------------------------------------------------------------------------------------------------------------
We propose there be no reporting threshold for natural gas
processing plants. Each natural gas processing plant is already
required to report the supply (beginning stocks, receipts, and
production) and disposition (input, shipments, fuel use and losses, and
ending stocks) of NGLs monthly on EIA Form 816. Processing plants are
also required to report the amounts of natural gas processed, NGLs
produced, shrinkage of the natural gas from NGLs extraction, and the
amount of natural gas used in processing on an annual basis on EIA Form
64A.
For a full discussion of the threshold analysis, please refer to
the Suppliers of Natural Gas and NGLs TSD (EPA-HQ-
[[Page 16577]]
OAR-2008-0508-040). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
Under this subpart, we are proposing reporting the amount of
natural gas and NGLs produced or supplied to the economy annually, as
well as the CO2 emissions that would result from complete
oxidation or combustion of this quantity of natural gas and NGLs.
The only GHG required to be reported under this subpart is
CO2. Combustion of natural gas and NGLs may also lead to
trace quantities of CH4 and N2O emission.\111\
Because the quantity of CH4 and N2O emissions are
small, highly variable and dependent on technology and operating
conditions in which the fuel is being consumed (unlike CO2),
we are not proposing that natural gas suppliers report on these
emissions. We seek comment on whether or not EPA should use the
national inventory estimates of CH4 and N2O
emissions from natural gas combustion, and apportion them to individual
natural gas suppliers based on the quantity of their product. We
request comments on this conclusion.
---------------------------------------------------------------------------
\111\ In 2006, CO2, CH4 and N2O
emissions from natural gas combustion were 1,155.1, 1.0, and 0.6
MMTCO2e, respectively.
---------------------------------------------------------------------------
We are proposing that LDCs and natural gas processing plants use a
mass-balance method to calculate CO2 emissions. The mass
balance approach is based on readily available information: The
quantity of fuel (e.g., thousand cf, barrels, mmBtus), and the carbon
content of the fuel. The formula is simple and can be automated. The
mass-balance approach is used extensively in national GHG inventories,
and in existing reporting guidelines for facilities, companies, and
States, such as the WRI/WBCSD GHG Protocol.
For carbon content, we have prepared two look-up tables listing
default CO2 emission factors of natural gas and natural gas
liquid. These emission factors are drawn from published sources,
including the American Petroleum Institute Compendium, EIA, and the
U.S. GHG Inventory.
Where natural gas processing plants extract and separate individual
components of NGLs, the facilities should report carbon content by
individual component of the NGLs. In cases where raw NGLs are not
separated, the processing plants should report carbon content for the
raw NGLs. LDCs and natural gas processing plants can substitute their
own values for carbon content provided they are developed according to
nationally-accepted ASTM standards for sampling and analysis.
We considered but do not propose an option in which LDCs and
natural gas processing plants would be required to sample and analyze
natural gas and NGLs periodically to determine the carbon content.
Given the close correlation between carbon content and BTU value of
natural gas and NGLs, and the availability of BTU information on these
products, EPA believes that periodic sampling and analysis would impose
a cost on facilities but would not result in improved accuracy of
reported emissions values. We request comment on an approach in which
natural gas suppliers would be required to develop facility- and batch-
specific carbon contents through periodic sampling and analysis. The
various approaches to monitoring GHG emissions are elaborated in the
Suppliers of Natural Gas and NGLs TSD (EPA-HQ-OAR-2008-0508-040).
4. Selection of Procedures for Estimating Missing Data
EPA has determined that the information to be reported by LDCs and
gas processing plants is routinely collected by facilities as part of
standard operating practices, and expects that any missing data would
be negligible. Typically, natural gas amounts are metered directly at
multiple stages, and billing systems require rigorous reconciliation of
data. In cases where metered data are not available, reporters may
estimate the missing volumes based on contracted maximum daily
quantities and known conditions of receipt and delivery during the
period when data are missing.
5. Selection of Data Reporting Requirements
We propose that LDCs and gas processing plants report
CO2 emissions directly to EPA on an annual basis. LDCs would
also report CO2 emissions disaggregated into categories that
represent residential consumers, commercial consumers, industrial
consumers, and electricity generating facilities. Further information
would be provided on the facilities to which LDCs deliver greater than
460,000 thousand cf of natural gas during the calendar year, which
would be used by EPA to check and verify information on facilities
covered under other subparts of this rule because of their onsite
stationary combustion or process emissions.\112\
---------------------------------------------------------------------------
\112\ 460,000 thousand cf/year is a conservative estimate of the
amount of dry natural gas that when fully combusted would produce at
least 25,000 metric tons of CO2.
---------------------------------------------------------------------------
Natural gas processing plants would report CO2 emissions
disaggregated by individual components of NGLs extracted and separated,
where applicable. Where raw NGLs are not separated into individual
components, plants should report CO2 emissions for raw NGLs.
We considered but are not proposing an option in which EPA obtained
facility-specific data for natural gas and NGLs through access to
existing Federal government reporting databases, such as those
maintained by EIA. We have concluded that comparability and consistency
in reporting processes across all facilities included in the entire
rule is vital, particularly with respect to timing of submission,
reporting formats, QA/QC, database management, missing data procedures,
transparency and access to information, and recordkeeping. In addition,
large natural gas processing plants would already be included as
reporting facilities under proposed 40 CFR 98.2(a)(2), therefore there
is minimal burden in reporting the additional information proposed
under this subpart. Finally, as noted above, we are requesting readily
available information from LDCs and natural gas processing facilities,
and do not consider reporting information to more than one Federal
agency to place an undue burden on these industries.
6. Selection of Records That Must Be Retained
Records that must be kept include quantity of individual fuels
supplied, BTU content, carbon content determined, flow records and/or
invoice records for customers with amount of natural gas received, type
of customer receiving natural gas (so the disaggregated report by
category can be checked), and data for determining carbon content for
natural gas processing plants. These records are necessary to enable
verification that the GHG monitoring and calculations were done
correctly. Records related to the end-user (e.g., ammonia facility) are
required to allow us to reconcile data reported by different facilities
and entities, and to ensure that coverage of natural gas supply and
end-use is comprehensive.
A full list of records that must be retained onsite is included in
proposed 40 CFR part 98, subparts A and NN.
[[Page 16578]]
OO. Suppliers of Industrial GHGs
1. Definition of the Source Category
The industrial gas supply category includes facilities that produce
N2O or fluorinated GHGs,\113\ importers of N2O or
fluorinated GHGs, and exporters of N2O or fluorinated GHGs.
These facilities and entities are collectively referred to as
``suppliers of industrial GHGs''.
---------------------------------------------------------------------------
\113\ Please see the proposed definition of fluorinated GHG near
the end of this section.
---------------------------------------------------------------------------
Under the proposed40 CFR part 98, subpart OO, if you produce
fluorinated GHGs or N2O, you would be required to report the
quantities of these gases that you produce, transform (use as
feedstocks in the production of other chemicals), destroy, or send to
another facility for transformation or destruction. Importers and
exporters of bulk fluorinated GHGs and N2O would be required
to report the quantities that they imported or exported and the
quantities that they imported and sold or transferred to another person
for transformation or destruction. As described in Sections III and IV
of this preamble, emissions from general stationary fuel combustion
sources and fugitive emissions from fluorinated gas production are
addressed separately (Sections V.C and V.L of this preamble).
Fluorinated GHGs. Fluorinated GHGs are man-made gases used in a
wide variety of applications. They include HFCs, PFCs, SF6,
NF3, fluorinated ethers, and other compounds such as
perfluoropolyethers. CFCs and HCFCs also contain fluorine and are GHGs,
but both the production and consumption (production plus import minus
export) of these ODS are currently being phased out and otherwise
regulated under the Montreal Protocol and Title VI of the CAA. We are
not proposing requirements for ODS under proposed 40 CFR part 98.
Fluorinated GHGs are powerful GHGs whose ability to trap heat in
the atmosphere is often thousands to tens of thousands times as great
as that of CO2, on a pound-for-pound basis. Some fluorinated
GHGs are also very long lived; SF6 and PFCs have lifetimes
ranging from 3,200 to 50,000 years.\114\
---------------------------------------------------------------------------
\114\ IPCCC SAR available at: http://www.ipcc.ch/ipccreports/assessments-reports.htm.
---------------------------------------------------------------------------
HFCs are the most commonly used fluorinated GHGs, they are used
primarily as a replacement for ODS in a number of applications,
including air-conditioning and refrigeration, foams, fire protection,
solvents, and aerosols. PFCs are used in fire fighting and to
manufacture semiconductors and other electronics. SF6 is
used in a diverse array of applications, including electrical
transmission and distribution equipment (as an electrical insulator and
arc quencher) and in magnesium casting operations (as a cover gas to
prevent oxidation of molten metal). NF3 is used in the
semiconductor industry, increasingly to reduce overall semiconductor
GHG emissions through processes such as NF3 remote cleaning
and NF3 substitution during in-situ cleaning. Fluorinated
ethers (HFEs and HCFEs) are used as anesthetics (e.g., isofluorane,
desflurane, and sevoflurane) and as heat transfer fluids (e.g., the H-
Galdens).
In 2006, 12 U.S. facilities produced over 350 million metric tons
CO2e of HFCs, PFCs, SF6, and NF3. More
specifically, 2006 production of HFCs is estimated to have exceeded 250
million metric tons CO2e while production of PFCs,
SF6, and NF3 was estimated to be almost 100
million metric tons CO2e. We estimate that an additional 6
facilities produced approximately 1 million metric tons CO2e
of fluorinated anesthetics.
Fluorinated GHGs are imported both in bulk (contained in shipping
containers and cylinders) and in products. For further information, see
the Bulk Imports and Exports of Fluorinated Gases TSD (EPA-HQ-OAR-2008-
0508-042) and the Imports of Fluorinated GHGs in Products TSD (EPA-HQ-
OAR-2008-0508-043). EPA estimates that over 110 million metric tons
CO2e of bulk HFCs, PFCs, and SF6 were imported
into the U.S. in 2007 by over 100 importers (PIERS, 2007). In
CO2e terms, SF6 and NF3 each made up
about one third of this total, while HFCs accounted for one quarter and
PFCs made up the remainder. Several other fluorinated GHGs may be
imported in smaller quantities, including fluorinated ethers such as
the H-Galdens and anesthetics such as desflurane (HFE-236ea2),
isoflurane (HCFE-235da2), and sevoflurane.
A variety of products containing fluorinated GHGs are imported into
the U.S. Imports of particular importance include pre-charged air-
conditioning, refrigeration, and electrical equipment and closed-cell
foams. Pre-charged air-conditioning and refrigeration equipment
contains a full or partial (holding) charge of HFC refrigerant, while
pre-charged electrical equipment contains a full or partial charge of
SF6 insulating gas. Closed-cell foams contain HFC blowing
agent.
We estimate that in 2010, approximately 18 million metric tons
CO2e of fluorinated GHGs would be imported in pre-charged
equipment.\115\ In 2006, an additional 2.5 million metric tons
CO2e of fluorinated GHGs were imported in closed-cell foams.
Together, these imports are expected to constitute between five and ten
percent of U.S. consumption of fluorinated GHGs.
---------------------------------------------------------------------------
\115\ The number of refrigeration and AC units imported in 2010
was assumed to equal the number of units imported in 2006. The
refrigeration and AC units imported in 2006 were pre-charged with
both HFCs and HCFCs. (HCFCs are ozone-depleting substances that are
regulated under the Montreal Protocol and are exempt from the
proposed definition of fluorinated GHG.) However, by 2010, EPA
expects that all imported refrigeration and AC units will be charged
with HFCs, because imports pre-charged with HCFCs will not be
permitted starting in that year.
---------------------------------------------------------------------------
Once produced or imported, fluorinated GHGs can have hundreds of
millions of downstream emission points. For example, the gases are used
in almost all car air conditioners and household refrigerators and in
other ubiquitous products and applications. Thus, tracking emissions of
these gases from all downstream uses would not be practical.
Nitrous oxide. N2O is a clear, colorless, oxidizing gas
with a slightly sweet odor. N2O is a strong GHG with a GWP
of 310.\116\
---------------------------------------------------------------------------
\116\ IPCCC SAR.
---------------------------------------------------------------------------
N2O is primarily used in carrier gases with oxygen to
administer more potent inhalation anesthetics for general anesthesia
and as an anesthetic in various dental and veterinary applications. In
this application, it is used to treat short-term pain, for sedation in
minor elective surgeries and as an induction anesthetic. The second
main use of N2O is as a propellant in pressure and aerosol
products, the largest application being pressure-packaged whipped
cream. In smaller quantities, N2O is also used as an
oxidizing agent and etchant in semiconductor manufacturing, an
oxidizing agent (with acetylene) in atomic absorption spectrometry, an
oxidizing agent in blowtorches used by jewelers and others, a fuel
oxidant in auto racing, and a component of the production of sodium
azide, which is used to inflate airbags.
Two companies operate a total of five N2O production
facilities in the U.S.. These facilities produced an estimated 4.5
million metric tons CO2e of N2O in 2006.
N2O may be imported in bulk or inside products. We
estimate that approximately 300,000 metric tons CO2e of bulk
N2O were imported into the U.S. in 2007 by 18 importers.
Products that may be imported include several of those listed above,
particularly pre-blended anesthetics and aerosol
[[Page 16579]]
products such as pressure-packaged whipped cream.
Further information on N2O supply and import can be
found in the Suppliers of Industrial GHGs TSD (EPA-HQ-OAR-2008-0508-
041).
Selection of Reporting Facilities and Types of Data to be Reported.
Because fluorinated GHGs and N2O have an extremely large
number of relatively small downstream sources, reporting of downstream
emissions of these gases would be incomplete, impractical, or both. On
the other hand, the number of upstream producers, importers, and
exporters is comparatively small, and the quantities that would be
reported by individual gas suppliers are often quite large. Thus,
upstream reporting is likely to be far more complete and cost-effective
than downstream reporting. For these reasons, we are proposing to
require upstream reporting of the quantities required to estimate U.S.
consumption of N2O and fluorinated gases. ``Consumption'' is
defined as the sum of the quantities of chemical produced in or
imported into the U.S. minus the sum of the quantities of chemical
transformed (used as a feedstock in the production of other chemicals),
destroyed, or exported from the U.S.
In developing this proposed rule, we reviewed a number of protocols
that track chemical consumption, its components (production, import,
export, etc.), or similar quantities. These protocols included EPA's
Stratospheric Ozone Protection regulations at 40 CFR part 82, the EU
Regulation on Certain Fluorinated Greenhouse Gases (No. 842/2006), the
Australian Commonwealth Government Ozone Protection and Synthetic
Greenhouse Gas Reporting Program, EPA's Chemical Substances Inventory
Update Rule at 40 CFR 710.43, EPA's Acid Rain regulations at 40 CFR
part 75, the TRI Program, and the 2006 IPCC Guidelines.\117\
---------------------------------------------------------------------------
\117\ We also reviewed other programs, including the DOE's
1605(b) Program, EPA's Climate Leaders Program, and the European
Commission's Article 6 reporting requirements, but we found that
these programs did not monitor consumption or its components.
---------------------------------------------------------------------------
We reviewed these protocols both for their overall scope and for
their specific requirements for monitoring and reporting. The
monitoring requirements are discussed in Section V.OO.3 of this
preamble. The protocols whose scopes were most similar to the one
proposed for industrial gas supply were EPA's Stratospheric Protection
Program, the EU Regulation on Certain Fluorinated Greenhouse Gases, the
Australian Synthetic Greenhouse Gas Reporting Program, and EPA's
Chemical Substances Inventory Update Rule. All four of these programs
require reporting of production and imports, and the first three also
require reporting of exports. In addition, the EU regulation and EPA's
Stratospheric Ozone Protection Program require reporting of the
quantities of chemicals (ODS) transformed or destroyed. In general, the
proposed requirements in this rule are based closely on those in EPA's
Stratospheric Ozone Protection Program. By accounting for all chemical
flows into and out of the U.S., including destruction and
transformation, this approach results in an estimate of consumption
that is more closely related to actual U.S. emissions than are
estimates of consumption that do not account for all of these flows.
Proposed Definition of Fluorinated GHGs. We propose to define
``Fluorinated GHG'' as SF6, NF3, and any
fluorocarbon except for ODS as they are defined under EPA's
stratospheric protection regulations at 40 CFR part 82, subpart A. In
addition to SF6 and NF3, this definition would
include any hydrofluorocarbon, any perfluorocarbon, any fully
fluorinated linear, branched or cyclic alkane, ether, tertiary amine or
aminoether, any perfluoropolyether, and any hydrofluoropolyether.
EPA is proposing this definition because HFCs, PFCs,
SF6, NF3, and many fluorinated ethers are known
to have significant GWPs. (For a list of these GWPs, see Table A-1 of
proposed 40 CFR part 98, subpart A.) In addition, although not all
fluorocarbons have had their GWPs evaluated, any fluorocarbon with an
atmospheric lifetime greater than one year is likely to have a
significant GWP due to the radiative properties of the carbon-fluorine
bond.
As discussed above, ODS are excluded from the proposed definition
of fluorinated GHG because they are already regulated under the
Montreal Protocol and Title VI of the CAA.
EPA requests comment on the proposed definition. EPA also requests
comment on two other options for defining or refining the set of
fluorinated GHGs to be reported. The first option would permit a
fluorocarbon to be excluded from reporting if (1) the GWP for the
fluorocarbon were not listed in Table A-1 of proposed 40 CFR part 98,
subpart A or in any of the IPCC Assessment Reports or World
Meteorological Organization (WMO) Scientific Assessments of Ozone
Depletion, and (2) the producer or importer of the fluorocarbon could
demonstrate, to the satisfaction of the Administrator, that the
fluorocarbon had an atmospheric lifetime of less than one year and a
100-year GWP of less than five. In general, we expect that new
fluorocarbons would be used in relatively low volumes. For such
chemicals, a GWP of five may be a reasonable trigger for reporting.
The second option would be to require reporting only of those
fluorinated chemicals listed in Table A-1 of proposed 40 CFR part 98,
subpart A. The disadvantage of this approach is that it would exclude
any new (or newly important) fluorocarbons whose GWPs have not been
evaluated. As discussed above, fluorocarbons in general are likely to
have significant GWPs. Given the pace of technological development in
this area, production (and emissions) of these gases could become
significant before the chemicals were added to the table.
2. Selection of Reporting Threshold
In developing the proposed thresholds for producers and importers
of fluorinated GHGs and N2O, we considered production,
capacity, and import/export thresholds of 1,000 metric tons
CO2e, 10,000 metric tons CO2e, 25,000 metric tons
CO2e, and 100,000 metric tons CO2e per year.
Table OO-1 of this preamble shows the emissions and facilities that
would be covered under the various thresholds for production and bulk
imports of N2O and HFCs, PFCs, SF6, and
NF3.
[[Page 16580]]
Table OO-1. Threshold Analysis for Industrial Gas Supply
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission Total national Production or imports covered Facilities Covered
threshold production or ----------------------------------------------------------------
Source category level import Number of
(metrics tons (metric tons facilities Metric tons Percent Number Percent
CO2e/yr) CO2e/yr) CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
HFC, PFC, SF6, and NF3 Producers....... 1,000 350,000,000 12 350,000,000 100 12 100
10,000 350,000,000 12 350,000,000 100 12 100
25,000 350,000,000 12 350,000,000 100 12 100
100,000 350,000,000 12 350,000,000 100 12 100
N2O Producers.......................... 1,000 4,500,000 5 4,500,000 100 5 100
10,000 4,500,000 5 4,500,000 100 5 100
25,000 4,500,000 5 4,500,000 100 5 100
100,000 4,500,000 5 4,500,000 100 5 100
N2O and Fluorinated GHG Importers 1,000 110,024,979 116 110,024,987 100 111 96
(bulk)................................
10,000 110,024,979 116 109,921,970 99.9 81 70
25,000 110,024,979 116 109,580,067 99.6 61 53
100,000 110,024,979 116 108,703,112 98.8 44 38
--------------------------------------------------------------------------------------------------------------------------------------------------------
Producers. We are proposing to require reporting for all
N2O and fluorinated GHG production facilities. As shown in
Table OO-1 of this preamble, all identified N2O, HFC, PFC,
SF6, and NF3 production facilities would be
covered at all capacity and production-based thresholds considered in
this analysis. We do not have facility-specific production capacity
information for the six facilities producing fluorinated anesthetics;
however, if all these facilities produced the same quantity in
CO2e terms, they too would probably be covered at all
capacity and production-based thresholds.
The requirement that all facilities report would simplify the rule
and permit facilities to quickly determine whether or not they must
report. The one potential drawback of this requirement is that small-
scale production facilities (e.g., for research and development) could
be inadvertently required to report their production, even though the
quantities produced would be small in both absolute and CO2e
terms. We are not currently aware of any small-scale deliberate
production of N2O or fluorinated GHGs, but we request
comment on this issue. These research and development facilities could
be specifically exempt from reporting. An alternative approach that
would address this concern would be to establish a capacity-based
threshold of 25,000 metric tons CO2e, summed across the
facility's production capacities for N2O and each
fluorinated GHG. We request comment on these alternative approaches.
Importers and Exporters. We are proposing to require importers and
exporters to report their imports and exports if either their total
imports or their total exports, in bulk, of all relevant gases, exceed
25,000 metric tons CO2e. We are proposing this threshold to
reduce the compliance burden on small businesses while still including
the vast majority of imports and exports. As is true for HFC
production, HFC import and export levels are expected to increase
significantly during the next several years as HFCs replace ODS, which
are being phased out under the Montreal Protocol.
Because it may be relatively easy for importers and exporters to
create new corporations in order to divide up their imports and exports
and remain below applicable thresholds, we considered setting no
threshold for importers and exporters. However, we are not proposing
this option because we are concerned that it would be too burdensome to
current small-scale importers. We request comment on this approach,
specifically the burden on small-scale importers if they were required
to report.
Further information on the threshold analysis for industrial gas
suppliers can be found in the Suppliers of Industrial GHGs TSD (EPA-HQ-
OAR-2008-0508-041). For specific information on costs, including
unamortized first year capital expenditures, please refer to section 4
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
a. Production
If you produce N2O or fluorinated GHGs, we propose that
you measure the total mass of N2O or fluorinated gases
produced by chemical, including production that was later transformed
or destroyed at the facility, but excluding any used GHG product that
was added to the production process (e.g., HFCs returned to the
production facility and added to the HFC production process for
reclamation). Production would be measured wherever it is traditionally
measured, e.g., at the inlet to the day tank or at the shipping dock.
The quantities transformed or destroyed would be reported separately;
see Sections V.OO.3.c and V.OO.3.d of this preamble. The quantities of
used product added to the production process would be measured and
subtracted from the total mass of product measured at the end of the
process. This would avoid counting used GHG product as new production.
b. Imports and Exports
If you import or export bulk N2O or fluorinated GHGs, we
propose that you report the total quantities of N2O or
fluorinated GHGs that you import or export by chemical. Reports would
include quantities imported in mixtures and the name/number of the
mixture, if applicable (e.g., HFC-410A). Reporting would occur at the
corporate level. You would not be required to report imports or exports
of heels (residual quantities inside returned containers) or
transshipments (GHGs that originate in a foreign country and that are
destined for another foreign country), but you would be required to
keep records documenting the nature of these transactions.
We propose to require reporting of imports and exports in metric
tons of chemical because that is the unit in which other quantities
(production, emissions, etc.) are proposed to be reported under this
rule. However,
[[Page 16581]]
because the preferred unit for Customs reporting is kg rather than
tons, EPA requests comment on whether it should require reporting of
imports and exports in kg of chemical.
In general, these proposed requirements are consistent with those
of other programs that monitor imports and exports of bulk chemical,
particularly EPA's Stratospheric Ozone Protection regulations.
Existing programs vary in their treatment of products containing
chemicals whose bulk import must be reported. The Australian program
requires reporting of all ODS and GHGs imported in pre-charged
equipment, including the identity of the refrigerant, the number of
pieces of equipment, and the charge size. The Inventory Update Rule
requires reporting of chemicals contained in products if the chemical
is designed to be released from the product when it is used (e.g., ink
from a pen). EPA's Stratospheric Ozone Protection regulations do not
currently require reporting of ODS contained in imported equipment or
other imported products; however, (1) EPA has prohibited the
introduction into interstate commerce, including import, of certain
non-essential products typically pre-charged with these chemicals, and
(2) EPA is in the process of proposing new regulations to prohibit
import of equipment pre-charged with HCFCs.
We are not proposing to require that importers of products
containing N2O or fluorinated GHGs report their imports. In
general, we are concerned that it would be difficult for importers to
identify and quantify the GHGs contained in these products and that the
number of importers would be high. However, it may be easier for
importers to identify and quantify the GHGs contained in a few types of
products, such as pre-charged equipment and foams. For example, the
identities and amounts of fluorinated GHGs contained in equipment are
generally well known; this data is typically listed on the nameplate
affixed to every unit. Moreover, in aggregate, the quantities of GHGs
imported in equipment can be large, for example, over 7 million metric
tons CO2e in imported pre-charged window air-conditioners.
We request comment on whether we should require reporting of imports or
exports of pre-charged equipment and/or closed-cell foams, including
the likely burden and benefits of such reporting.
c. N2O or Fluorinated GHGs Transformed
Under the proposed rule, if you chemically transform N2O
or fluorinated GHGs, you would be required to estimate the mass of
N2O or fluorinated GHGs transformed. This estimate would be
the difference between (1) the quantity of the N2O or
fluorinated GHG fed into the process for which the N2O or
fluorinated GHG was used as a feedstock, and (2) the mass of any
unreacted feedstock that was not returned to the process. Measuring the
quantity of N2O or fluorinated GHGs actually fed into the
process would account for any losses between the point where total
production of the fluorinated GHG is measured and the point where the
fluorinated GHG is reacted as a feedstock (transformed). The mass of
any unreacted feedstock that was not returned to the process would be
ascertained using mass flow measurements and (if necessary) gas
chromatography.
d. Destruction
Under the proposed rule, if you produce and destroy fluorinated
GHGs, you would be required to estimate the quantity of each
fluorinated GHG destroyed. This estimate would be based on (1) the
quantity of the fluorinated GHG fed into the destruction device, and
(2) the DE of the device. In developing the estimate, you would be
required to account for any decreases in the DE of the device that
occurred when the device was not operating properly (as defined in
State or local permitting requirements and/or destruction device
manufacturer specifications). Finally, you would be required to perform
annual fluorinated GHG concentration measurements by gas chromatography
to confirm that emissions from the destruction device were as low as
expected based on the DE of the device. If emissions were found to be
higher, then you would have the option of using the DE implied by the
most recent measurements or of conducting more extensive measurements
of the DE of the device.
These proposed requirements are identical to those proposed for
destruction of HFC-23 that is generated as a byproduct during HCFC-22
production. They are also similar to those contained in EPA's
Stratospheric Ozone Protection Regulations. Those regulations include
detailed requirements for reporting and verifying transformation and
destruction of chemicals.
We are proposing requirements for verifying the DE of destruction
devices used to destroy fluorinated GHGs because fluorinated GHGs,
particularly PFCs and SF6, are difficult to destroy. In many
cases, these chemicals have been selected for their end uses precisely
because they are not flammable. For destruction to occur, temperatures
must be quite high (over 2,300 [deg]F), fuel must be provided, flow
rates of fuels and air (or oxygen) must be kept above certain limits,
flow rates of fluorinated GHG must be kept below others, and for some
particularly difficult-to-destroy chemicals such as CF4,
pure oxygen must sometimes be fed into the process. If one or more of
these process requirements is not met, DEs can drop sharply (in some
cases, by an order of magnitude or more), and fluorinated GHGs would
simply be exhausted from the device. Both construction deficiencies and
operator error can lead to a failure to meet process requirements;
thus, both initial testing and periodic monitoring are important for
verifying destruction device performance. We request comment on the
option of requiring that the annual destruction device emissions
measurement be performed using a compound that is at least as difficult
to destroy as the most difficult-to-destroy GHG ever fed into the
device, e.g., SF6 or CF4.
We believe that owners or operators of facilities that destroy
fluorinated GHGs are already likely to verify the DEs of their
destruction devices. Many facilities destroying fluorinated GHGs are
likely to destroy ODS as well. In this case, they are already subject
to requirements to verify the DEs of their devices.
We request comment on the extent of potential overlap between the
destruction reported under proposed 40 CFR part 98, subpart OO and that
reported under proposed 40 CFR part 98, subpart L. To obtain an
accurate estimate of the net supply of fluorinated industrial
greenhouse gases, fluorinated GHGs that are produced and subsequently
destroyed should be subtracted from the total produced or imported.
However, if fluorinated GHGs are never included in the mass produced
(e.g., because they are removed from the production process with or as
byproducts), then including them in the mass destroyed would lead to an
underestimate of supply. One possible solution to this problem would be
to require facilities producing and destroying fluorinated GHGs to
separately estimate and report their destruction of fluorinated GHGs
that have been counted as produced in either the current year or
previously.
EPA is not proposing to require reporting of N2O
destruction, because EPA is not aware that such destruction occurs.
However, EPA requests comment on this.
[[Page 16582]]
e. Precision, Accuracy, and Calibration Requirements
The protocols and guidance reviewed by EPA differ in their level of
specificity regarding the measurement of production or other flows,
particularly regarding their precision and accuracy requirements. Some
programs, such as the Stratospheric Ozone Protection regulations, do
not specify any accuracy requirements, while other programs
specifically define acceptable errors and reference industry standards
for calibrating and verifying monitoring equipment. One of the latter
is 40 CFR part 75, Appendix D, which establishes requirements for
measuring oil and gas flows as a means of estimating SO2
emissions from their combustion. These requirements include a
requirement that the fuel flowmeter accuracy be within 2 percent of the
upper range value and a requirement that flowmeters be recalibrated at
least once a year.
In today's proposed rule, we are proposing to require facilities to
measure the mass of N2O or fluorinated GHGs produced,
transformed, or destroyed using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 0.2 percent of full scale or better. In addition, we are
proposing to require that weigh scales, flowmeters, and/or other
measurement devices be calibrated every year or sooner if an error is
suspected based on mass-balance calculations or other information.
Facilities could perform the verification and calibration of their
scales and flowmeters during routine product line maintenance. Finally,
we are proposing that facilities transforming or destroying fluorinated
GHGs calibrate gas chromatographs by analyzing, on a monthly basis,
certified standards with known GHG concentrations that are in the same
range (percent levels) as the process samples.
EPA requests comment on these proposed requirements. EPA
specifically requests comment on the proposed frequency of calibration
for flowmeters; the Agency understands that some types of flowmeters
that are commonly employed in chemical production, such as the Coriolis
type, may require less frequent calibration.
We are proposing specific accuracy, precision, and calibration
requirements because the high GWPs and large volumes of fluorinated
GHGs produced make such requirements worthwhile for this source
category. For example, a one percent error at a typical facility
producing fluorinated GHGs would equate to 300,000 metric tons
CO2e. The Agency believes that these precision and accuracy
requirements (0.2 percent) should not represent a significant burden to
chemical producers, who already use and regularly calibrate measurement
devices with similar accuracies.
EPA is not proposing precision and accuracy requirements for
importers and exporters of bulk chemical; however, EPA requests comment
on whether such requirements (e.g., 0.5 to 1 percent) would be
appropriate.
4. Selection of Procedures for Estimating Missing Data
a. Production
In the event that any data on the mass produced, fed into the
production process (for used material being reclaimed), fed into
transformation processes, fed into destruction devices, or sent to
another facility for transformation or destruction, is unavailable, we
propose that facilities be required to use secondary measurements of
these quantities. For example, facilities that ordinarily measure
production by metering the flow into the day tank could use the weight
of product charged into shipping containers for sale and distribution.
We understand that the types of flowmeters and scales used to measure
fluorocarbon production (e.g., Coriolis meters) are generally quite
reliable, and therefore it should rarely be necessary to rely on
secondary production measurements. In general, production facilities
rely on accurate monitoring and reporting of production and related
quantities.
If concentration measurements were unavailable for some period, we
propose that the facility be required to report the average of the
concentration measurements from just before and just after the period
of missing data.
There is one proposed exception to these requirements: If the
facility has reason to believe that either method would result in a
significant under- or overestimate of the missing parameter, then the
facility would be required to develop an alternative estimate of the
parameter and explain why and how it developed that estimate. We would
have the option of rejecting this alternative estimate and replacing it
with the value developed using the usual missing data method if we did
not agree with the rationale or method for the alternative estimate.
We request comment on these methods for estimating missing data. We
also request comment on the option of estimating missing production
data based on consumption of reactants, assuming complete
stoichiometric conversion. This approach could be used in the very
unlikely event that neither primary nor secondary direct measures of
production were available.
b. Imports and Exports
We do not believe that missing data would be a problem for
importers and exporters of GHGs due to their requirement to declare the
quantities of GHGs imported or exported for Customs purposes. However,
we request comment on this assumption.
5. Selection of Data Reporting Requirements
Under the proposed rule, facilities would be required to submit
data, described below, in addition to the production, import, export,
feedstock, and destruction data listed above. This data is intended to
permit us to check the main estimates submitted. A complete list of
data to be reported is included in proposed 40 CFR part 98, subparts A
and OO.
a. Production
Facilities producing N2O or fluorinated GHGs would be
required to submit data on the total mass of reactants fed into the
production process, the total mass of non-GHG reactants and byproducts
permanently removed from the process, and the mass of used product
added back into the production process. Facilities would also be
required to provide the names and addresses of other facilities to
which they sent N2O or fluorinated GHGs for transformation
or destruction. All quantities would be annual totals in metric tons,
by chemical.
b. Imports/Exports and Destroyers of Fluorinated GHG
Importers of N2O or fluorinated GHGs would be required
to submit an annual report that summarized their imports, providing the
following information for each import: The quantity of GHGs imported by
chemical, the date on which the GHGs were imported, the port of entry
through which the GHGs passed, the country from which the imported GHGs
were imported, and the importer number for the shipment. Importers
would also be required to provide the names and addresses of any
persons and facilities to which the imported GHGs were sold or
transferred for transformation or destruction.
Exporters of N2O and fluorinated GHGs would be required
to submit an annual report that summarized their exports, similar to
the report provided by importers. A complete list of data to be
reported is included in the proposed rule.
[[Page 16583]]
These proposed requirements are very similar to those that apply to
importers and exporters of ODS under EPA's Stratospheric Ozone
Protection Program. We are proposing them because they would provide us
with valuable information for verifying the nature and size of GHG
imports and exports.
In addition to annually reporting the mass of fluorinated GHG fed
into the destruction device, facilities destroying fluorinated GHGs
would be required to submit a one-time report including the following:
The destruction unit's DE, the methods used to record volume destroyed
and to measure and record DE, and the names of other relevant Federal
or State regulations that may apply to destruction process. This one-
time report is very similar to that required under EPA's Stratospheric
Ozone Protection regulations.
6. Selection of Records That Must Be Retained
EPA is proposing that the following records be retained because
they are necessary to verify production, import, export,
transformation, and destruction estimates and related quantities and
calibrations.
a. Production
Owners or operators of facilities producing N2O or
fluorinated GHGs would be required to keep records of the data used to
estimate production, as well as records documenting the initial and
periodic calibration of the flowmeters or scales used to measure
production.
b. Imports and Exports
Importers of N2O or fluorinated GHGs would be required
to keep the following records substantiating each of the imports that
they report: A copy of the bill of lading for the import, the invoice
for the import, the U.S. Customs entry form, and dated records
documenting the sale or transfer of the imported GHG for transformation
or destruction (if applicable).
Every person who imported a container with a heel would be required
to keep records of the amount brought into the U.S. and document that
the residual amount in each shipment is less than 10 percent of the net
mass of the container when full and would: Remain in the container and
be included in a future shipment, be recovered and transformed, or be
recovered and destroyed.
Exporters of N2O, or fluorinated GHGs, would be required
to keep the following records substantiating each of the exports that
they report: A copy of the bill of lading for the export and the
invoice for the import.
c. Transformation
Owners or operators of production facilities using N2O
or fluorinated GHGs as feedstocks would be required to keep records
documenting: The initial and annual calibration of the flowmeters or
scales used to measure the mass of GHG fed into the destruction device
and the periodic calibration of gas chromatographs used to analyze the
concentration of N2O fluorinated GHG in the product for
which the GHG is used as a feedstock.
d. Destruction
Owners or operators of GHG production facilities that destroy
fluorinated GHGs would be required to keep records documenting: The
information that they send in the one-time and annual reports, the
initial and annual calibration of the flowmeters or scales used to
measure the mass of GHG fed into the destruction device, the method for
tracking startups, shutdowns, and malfunctions and any GHG emissions
during these events, and the periodic calibration of gas chromatographs
used to annually analyze the concentration of fluorinated GHG in the
destruction device exhaust stream, as well as the representativeness of
the conditions under which the measurement took place.
PP. Suppliers of Carbon Dioxide (CO2)
1. Definition of the Source Category
CO2 is used for a variety of commercial applications,
including food processing, chemical production, carbonated beverage
production, refrigeration, and petroleum production for EOR, which
involves injecting a CO2 stream into injection wells at well
fields for the purposes of increasing crude oil production. Possible
suppliers of CO2 include industrial facilities or process
units that capture a CO2 stream, such as those found at
electric power plants, natural gas processing plants, cement kilns,
iron and steel mills, ammonia manufacturing plants, petroleum
refineries, petrochemical plants, hydrogen production plants, and other
combustion and industrial process sources. These suppliers can capture
and/or compress CO2 for delivery to a variety of end users
as discussed above.
To ensure consistent treatment of CO2 suppliers and
given the large percentage of CO2 supplied from
CO2 production wells, we have also proposed inclusion of
facilities producing CO2 from CO2 production
wells in the proposal. Importers and exporters of CO2 are
discussed under suppliers of industrial GHGs (see Section V.OO of this
preamble) because most of these facilities import or export multiple
industrial gases. For a full discussion of this source category, refer
to the Suppliers of CO2 TSD (EPA-HQ-OAR-2008-0508-044).
According to the U.S. GHG Inventory in 2006, the total supply of
CO2 from industrial facilities and CO2 production
wells was approximately 40.6 million metric tons CO2e.
Further research in support of this rulemaking identified three
additional facilities capturing a CO2 stream for sale. Data
for two of these facilities suggest an additional 0.5 million metric
tons CO2e captured. Currently, the majority of
CO2 (79 percent) is produced from CO2 production
wells. Approximately 18 percent of CO2 is produced at
natural gas processing facilities and less than 2 percent from ammonia
production facilities. Less than 1 percent of CO2 is
captured at other industrial facilities.
Fugitive Emissions from CO2 Supply. Fugitive CO2
emissions can occur from the production of CO2 streams from
CO2 production wells or capture at industrial facilities or
process units, as well as during transport of the CO2, and
during or after use of the gas. We propose to exclude the explicit
reporting of fugitive CO2 emissions from CO2
supply at industrial facilities or process units and CO2
production wells, as well as from CO2 pipelines, injection
wells and storage sites. Much of the CO2 that could
ultimately be released as a fugitive emission during transportation,
injection and storage, would be accounted for in the CO2
supply calculated using the methods below. Although separate
calculation and reporting of fugitive CO2 emissions are not
proposed for inclusion, we believe that obtaining robust data on
fugitive CO2 emissions from the entire carbon capture and
storage chain would provide a more complete understanding of the
efficacy of carbon capture and storage technologies as an option for
mitigating CO2 emissions.
We seek comment on the decision to exclude the reporting of
fugitive CO2 emissions from the carbon capture and storage
chain. We have concluded that there could be merit in requiring the
reporting of fugitive emissions from geologic sequestration of
CO2, in particular. This is discussed further below.
Geologic Sequestration of CO2. CO2 used in most
industrial applications would eventually be released to the atmosphere.
For EOR applications, however, some amount of CO2 could
ultimately remain sequestered in deep
[[Page 16584]]
geologic formations. The objective of EOR operations is not to maximize
reservoir CO2 retention rates, but to maximize oil
production and the amount of CO2 trapped underground would
be a function of site specific and operational factors. There are
several EOR operations in the Permian Basin of Texas. One study showed
that retention rates for eight reservoirs ranged from 38 to 100 percent
with an average of 71 percent, but many of these projects are not
mature enough to predict final retention (see Suppliers of
CO2 TSD (EPA-HQ-OAR-2008-0508-044)).
We are not proposing the inclusion of geologic sequestration in the
proposed rulemaking. However, the Agency recognizes that there may be
significant stakeholder interest in reporting the amount of
CO2 injected and geologically sequestered at EOR operations
in order to demonstrate the effectiveness of EOR projects that
ultimately intend to store the CO2 for long periods of time.
If an EOR project intends to sequester CO2 for long periods
of time, there would be additional operational factors and post-
operational considerations and monitoring. Although EPA is not
proposing inclusion of this source in the rulemaking, we have outlined
initial thoughts about how geologic sequestration might be included in
a reporting program for EOR sequestration or other types of geologic
sequestration. We welcome comment on the approach outlined below or
other suggestions for how to quantify and verify the amount of
CO2 sequestered in geologic formations.
We reviewed a number of existing and proposed methodologies for
monitoring and reporting fugitive emissions from carbon capture,
transport, injection and storage. A summary of these protocols can be
found in the Review of Existing Programs memorandum (EPA-HQ-OAR-2008-
0508-054). Based on this review, a possible approach to include
geologic sequestration might be to ask EOR operators to submit a
geologic sequestration report. This report could provide information on
the amount of CO2 sequestered (based on the amount of
CO2 injected minus any fugitive emissions) along with a
written description of the activities undertaken to document and verify
the amount sequestered at each site. This report could include the
following supporting information:
The owner and operator of the geologic sequestration
site(s). Including the business name, address, contact name, and
telephone number.
Location of the geologic sequestration site(s) including a
map showing the modeled aerial extent of the CO2 plume over
the lifetime of the project.
Permitting information. Including information on the UIC
well permit(s) issued by the appropriate State or Federal agency:
Permit number or other unique identification, date the permit was
issued and modified if applicable, permitting agency, contact name, and
telephone number.
An overview of the site characteristics, referencing or
providing information which demonstrates sufficient storage capacity
for the expected operating lifetime of the plant and the presence of an
effective confining system overlying the injection zone.
An assessment of the risks of CO2 leakage, or
escape of CO2 from the subsurface to the atmosphere,
including an evaluation of potential leakage pathways such as deep
wells, faults, and fractures.
An overview of the methods used to model the subsurface
behavior of CO2 and the results.
Baseline conditions used to evaluate performance of the
site including the amount of naturally occurring CO2
emissions and/or other characteristics that would be used to
demonstrate the effectiveness of the system to contain CO2.
Summary of the monitoring plan that would be used to
determine CO2 emissions from the site including a discussion
of the methodology, rationale, and frequency of monitoring.
The information listed above could be submitted one time and then
updated as appropriate. However, the volume of CO2 injected
and any emissions from the storage site, including physical leakage
from the geologic formation (via natural features or wells) and/or
fugitive emissions of CO2 co-produced with oil/gas, would be
reported on an annual basis in order to quantify the amount of
CO2 geologically sequestered.
2. Selection of Reporting Threshold
EPA has identified at least nine industrial facilities or process
units in the U.S. that currently capture CO2 (three natural
gas processing plants, two ammonia facilities, two electricity
generation facilities, one soda ash production plant, and one coal
gasification facility) (Table PP-1 of this preamble).
Table PP-1. Threshold Analysis for CO2 Supply From Industrial Facilities or Process Units
----------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
Threshold level metric tons emissions Total number ---------------------------------------------------
CO2e (metric tons of U.S. Metric tons
CO2e) facilities CO2e/yr Percent Number Percent
----------------------------------------------------------------------------------------------------------------
1,000....................... 8,184,875 9 8,186,881 100 9 100
10,000...................... 8,184,875 9 8,186,881 100 9 100
25,000...................... 8,184,875 9 8,186,881 100 9 100
100,000..................... 8,184,875 9 8,036,472 98 5 56
----------------------------------------------------------------------------------------------------------------
Under the proposed rule, all industrial facilities that capture and
transfer a CO2 stream would be required to report the mass
of CO2 captured and/or transferred. All known existing
facilities exceed all but the highest reporting threshold of 100,000
metric tons CO2e, taking into account solely the mass of
CO2 captured. At the 25,000 metric tons CO2e
threshold considered by other subparts of this rule, all industrial
facilities and capture sites exceed the threshold. The analysis did not
account for stationary combustion at each facility. We concluded that
all facilities capturing CO2 would likely already exceed the
reporting thresholds under other subparts of proposed 40 CFR part 98
for their downstream emissions. Therefore, a proposed threshold of
``All In'' for reporting CO2 supply from industrial
facilities or process units would not bring in additional facilities
not already triggering other subparts of the proposed rule.
Based on the volumes of CO2 supplied by facilities
producing a CO2 stream from CO2 production wells,
we also propose that they be subject to reporting. Currently there are
four natural formations--Jackson Dome, Bravo Dome, Sheep Mountain, and
McElmo Dome. Data are not available to estimate emissions from
individual owners or operators operating within
[[Page 16585]]
the Domes, therefore emissions data are presented at the Dome level
(Table PP-2 of this preamble). We propose that all CO2
production wells owned by a single owner or operator in a given Dome
report the mass of CO2 extracted and/or transferred off
site. We are seeking comment on alternative methods for defining the
reporting facility (e.g., reporting at the level of an individual
well).
Table PP-2. Threshold Analysis for CO2 Supply CO2 Production Wells
--------------------------------------------------------------------------------------------------------------------------------------------------------
Total national Emissions covered Facilities covered
emissions Total number ------------------------------------------------------
Threshold level metric tons CO2e (metric tons of U.S. Metric tons
CO2e) facilities * CO2e/yr Percent Number Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000............................................................ 31,358,853 4 31,358,853 100 4 100
10,000........................................................... 31,358,853 4 31,358,853 100 4 100
25,000........................................................... 31,358,853 4 31,358,853 100 4 100
100,000.......................................................... 31,358,853 4 31,358,853 100 4 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Under this proposal, owners or operator would be required to report on all CO2 production wells under their ownership/operation in a single Dome.
We have concluded that reporting the volume of the CO2
streams from CO2 production wells is important given the
large fraction of CO2 supplied from CO2
production wells. Further, we conclude that there is minimal burden
associated with these requirements, as all necessary monitoring
equipment should already be installed to support current operating
practice.
Importers and exporters of CO2 in bulk should review the
threshold language for industrial GHG suppliers found in Section OO of
this preamble, which proposes a threshold of 25,000 metric tons
CO2e, for applicability. We decided to have a single
threshold applicable for bulk importers and exporters of all industrial
gases, because many are importing and/or exporting multiple industrial
gases. We decided not to include CO2 imported or exported in
products (e.g., fire extinguishers), because of the potentially large
number of sources.
For additional information on the threshold analysis please refer
to the Suppliers of CO2 TSD (EPA-HQ-OAR-2008-0508-044). For
specific information on costs, including unamortized first year capital
expenditures, please refer to section 4 of the RIA and the RIA cost
appendix.
3. Selection of Proposed Monitoring Methods
The monitoring plan for CO2 suppliers at industrial
facilities or process units, CO2 production wells, and
CO2 importers and exporters involves accounting for the
total volume of the CO2 stream captured, extracted, imported
and exported. We propose that if CO2 suppliers already have
the flow meter installed to directly measure the CO2 stream
at the point of capture, extraction, import and/or export, that
facilities use the existing flow meter to measure CO2
supply. We propose that facilities sample the composition of the gas on
at least a quarterly basis to determine CO2 composition of
the CO2 stream. If the necessary flow meters are not
currently installed, CO2 suppliers would use mass flow
meters to measure the volume of the CO2 stream transferred
offsite.
We propose to require reporting on the volume of the CO2
stream at the point of capture, extraction, import and export because
this would provide information on the total quantity of CO2
available for sale. Measuring at this initial point could provide
additional information in the future on fugitive CO2
emissions from onsite purification, processing, and compression of the
gas. However, if the necessary flow meters are not currently in place,
facilities may conduct measurements at the point of CO2
transfer offsite.
We conclude that there is minimal incremental burden associated
with this approach for CO2 suppliers at industrial
facilities or process units, CO2 production wells, importers
and exporters because these sites likely already have the necessary
flow meters installed to monitor the CO2 stream. In
addition, facilities need to know CO2 composition of the gas
in order to ensure the gas meets appropriate specifications (e.g., food
grade CO2).
We also considered requiring CO2 suppliers to report
only on CO2 sales, without determining the actual
CO2 composition of the gas sold. This is a relatively simple
method, however, facilities already routinely measure the composition
of the gas, providing greater certainty in the potential emissions
data.
The methods proposed are generally consistent with existing GHG
reporting protocols. Although existing protocols focus on accounting
for fugitive emissions, and not quantity of CO2 supplied,
direct measurement is commonly the recommended approach for measuring
fugitive emissions. We concluded that while direct measurement of
fugitive emissions may not be common practice, and is therefore not
proposed, measurement of CO2 transfer is.
4. Selection of Procedures for Estimating Missing Data
Facilities with missing monitoring data on the volume of the
CO2 stream captured, extracted, imported, and exported
should use the greater of the volume of the CO2 stream
transferred offsite or the quarterly or average value for the parameter
from the past calendar year. The owners or operators of facilities
monitoring emissions at the point of transfer offsite, that have
missing monitoring data on the CO2 stream transferred, may
use the quarterly or average value for the parameter from the past
calendar year.
Facilities with missing data on the composition of the
CO2 stream captured, extracted, imported, and exported
should use the quarterly or average value for the parameter from the
past calendar year.
5. Selection of Data Reporting Requirements
For CO2 supply, the proposed monitoring method is based
on direct measurement of the gaseous and liquid CO2 streams.
All CO2 suppliers would report, on an annual basis, the
measured volume of the CO2 stream that is captured,
extracted, imported and exported if the proper flow meter is installed
to carry out these measurements. Facilities monitoring emissions at the
point of transfer offsite would report the annual volume of the
CO2 stream transferred. All suppliers also would report, on
an annual basis, the CO2 composition of the gas sold. The
end-use application of the supplied CO2 (e.g., EOR, food
processing) should also be reported, if known.
[[Page 16586]]
EPA proposes to collect data on the measured volume of the
CO2 stream captured, extracted, imported and exported, as
well as gas composition because these form the basis of the GHG
calculations and are needed for EPA to understand the emissions data
and verify reasonableness of the reported emissions. EPA also proposes
to collect information on the end use of the transferred
CO2, if known, because CO2 can be used in
emissive or non-emissive applications. Collecting data on the ultimate
fate of the CO2 stream can provide information on the
potential emissions of CO2 released to the atmosphere.
6. Selection of Records That Must Be Retained
Owners or operators of all CO2 suppliers would be
required to retain onsite all quarterly measurements for the volume of
the CO2 stream captured, extracted, imported and exported,
and CO2 composition. Where measurements are based on
CO2 transferred offsite, these quarterly measurements would
be retained, along with CO2 composition.
QQ. Mobile Sources
1. Definition of the Source Category
This section of the preamble describes proposed GHG reporting
requirements for manufacturers of new mobile sources, including motor
vehicles and engines, nonroad vehicles and engines, and aircraft
engines.\118\ It also seeks comment on the need to collect additional
in-use travel activity and other emissions-related data from States and
local governments and mobile source fleet operators. These proposed
requirements and the requests for comments are based on EPA's authority
under CAA Sections 114 and 208.
---------------------------------------------------------------------------
\118\ The terms ``manufacturers'' and ``manufacturing
companies'', as used in this section, mean companies that are
subject to EPA emissions certification requirements. This primarily
includes companies that manufacture vehicles and engines
domestically and foreign manufacturers that import vehicles and
engines into the U.S. market. In some cases, this also includes
domestic companies that are required to meet EPA certification
requirements when they import foreign-manufactured vehicles or
engines.
---------------------------------------------------------------------------
Not discussed in this portion of the preamble are proposed GHG
reporting requirements related to transportation fuels (see Section
V.MM of this preamble, Suppliers of Petroleum Products) and motor
vehicle and engine manufacturing facilities (see Section V.C of this
preamble, General Stationary Fuel Combustion Sources).
Total Emissions. For the U.S. transportation sector, the 2008 U.S.
Inventory includes GHGs from the operation of passenger and freight
vehicles within U.S. boundaries, natural gas used to power domestic
pipelines, lubricants associated with mobile sources, and international
bunker fuels purchased in the U.S. for travel outside U.S. boundaries.
GHG emissions from these sources in 2006 totaled 2102.6 Tg
CO2e, representing 29.3 percent of total U.S. GHG emissions.
Just under 79 percent of these emissions came from on-road sources,
including passenger cars and light-duty trucks (58.8 percent), medium-
and heavy-duty trucks (19.2 percent), buses (0.6 percent) and
motorcycles (0.1 percent). Aircraft (including domestic military
flights) accounted for 11.6 percent of transportation GHGs, ships and
boats 5 percent, rail 2.8 percent, pipelines 1.5 percent, and
lubricants 0.5 percent. These estimates primarily reflect GHGs
resulting from the combustion of fuel to power U.S. transportation
sources. These estimates do not include emissions from the operation of
other non-transportation mobile equipment and recreational vehicles,
which collectively accounted for over 2 percent of total U.S. GHG
emissions.
GHGs produced by transportation sources include CO2,
N2O and CH4, which result primarily from the
combustion of fuel to power these sources or from treatment of the
exhaust gases, and HFCs, which are released through the operation,
servicing and retirement of vehicle A/C systems. CO2 is the
predominant GHG from these sources, representing 95 percent of
transportation GHG emissions (weighted by the GWP of each gas). HFCs
account for 3.3 percent, N2O for 1.6 percent, and
CH4 for 0.1 percent of transportation GHG emissions. EPA is
proposing reporting requirements for each of these gases, where
appropriate.
2. Selection of Proposed GHG Measurement, Reporting, and Recordkeeping
Requirements
For the new vehicle and engine manufacturer reporting requirements
proposed in this Notice, EPA intends to build on our long-established
programs that control vehicle and engine emissions of criteria
pollutants including hydrocarbons, NOX, CO, and PM. These
programs, which include emissions standards, testing procedures, and
emissions certification and compliance requirements, are based on
emission rates over prescribed test cycles (e.g., grams of pollutant
per mile or grams per kilowatt-hour). Thus, we propose having
manufacturers also report GHG emissions in terms of emission rates for
this reporting program. It is important to note that this approach is
somewhat different from the direct reporting of tons per year of
emissions that is appropriate for the non-mobile source categories
addressed elsewhere in this preamble. However, EPA would be able to use
the GHG emission rate data from manufacturers with our existing models
and other information to project tons of GHG emissions for the various
mobile source categories.
Although the new reporting requirements proposed here focus on
emission rates from new vehicles and engines, EPA also is very
interested in continually updating and improving our understanding of
the in-use activity and total emissions from mobile sources. Thus, we
are seeking comment on the need to collect in-use travel activity and
other emissions-related data from States and local governments and
mobile source fleet operators. Section V.QQ.4 of this preamble
describes the existing State and local government and fleet operator
data that EPA currently collects and requests public comment on the
need for, and substance of, additional reporting requirements.
3. Mobile Source Vehicle and Engine Manufacturers
a. Overview
As mentioned above, EPA is proposing GHG reporting requirements
that fit within the reporting framework established for EPA's long-
established criteria pollutant emissions control programs and vehicle
fuel economy testing program. While the details of the programs vary
widely among the vehicle and engine categories, EPA generally requires
manufacturers to conduct emissions testing and report the resulting
emissions data to EPA for approval on an annual basis prior to the
introduction of the vehicles or engines into commerce. As a part of
this process, since the early 1970s, EPA has collected criteria
pollutant emissions data for all categories of vehicles and engines
used in the transportation sector, including engines used in nonroad
equipment (see Table QQ-1 of this preamble).
Table QQ-1. Mobile Source Vehicle and Engine Categories
------------------------------------------------------------------------
Category
-------------------------------------------------------------------------
Light-duty vehicles
Highway heavy-duty vehicles (chassis-certified)
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotive engines
Nonroad small spark ignition engines
[[Page 16587]]
Nonroad large spark ignition engines
Marine spark ignition engines/personal watercraft
Snowmobiles
Off-highway motorcycles and all terrain vehicles
Aircraft engines
------------------------------------------------------------------------
For purposes of EPA certification, manufacturers typically group
vehicles/engines with similar characteristics into families and perform
emission tests on representative or worst-case vehicles/engines from
each family. Integral to EPA's existing certification procedures are
well-established methods for assuring the completeness and quality of
reported emission test data. We are proposing to require manufacturers
to measure and report GHG emissions data as part of these current
emissions testing and certification procedures. These procedures,
appropriate here because of the long-standing history and structure of
mobile source control programs, are necessarily different from the
monitoring-based methods proposed for other sources elsewhere in this
notice.
After a discussion of the proposed small business threshold, the
following subsections describe the proposed GHG emissions measurement
and reporting requirements for manufacturers. As discussed in those
subsections, some manufacturers already measure and report some GHG
emissions, some measure but do not have to report GHG emissions, and
others would need to measure and report for the first time. We propose
that the new measurement and reporting requirements apply beginning
with the 2011 model year, although we encourage voluntary measurement
and reporting for model year 2010.
b. Selection of a Reporting Threshold
In most of EPA's recent mobile source regulatory programs for
criteria pollutants, EPA has applied special provisions to small
manufacturers. EPA proposes to exempt small manufacturers from the GHG
reporting requirements. We define ``small business'' or ``small volume
manufacturer'' separately for each mobile source category. These
definitions were established in the regulations during the rulemaking
process for each category, which included consultation with small
entities and with the Small Business Administration. We're proposing to
use these same definitions in each case for the reporting requirements
exemption. We believe that this exemption would avoid the relatively
high per-vehicle or per-engine reporting costs for small manufacturers
without detracting from the goals of the reporting program, as
discussed below.
It is important to note that this ``threshold'' would differ from
the approach proposed for other source categories discussed in Section
V of this preamble. That is, EPA would not have manufacturers determine
their eligibility based on total tons emitted per year. As discussed
above, EPA's current mobile source criteria pollutant control programs
are based on emissions rates over prescribed test cycles rather than
tons per year estimates. Since we are proposing to build on our
existing system, we believe that a threshold based on manufacturer size
is appropriate for the mobile source sector. Although the emission
rates of some vehicles and engines would not be reported, we do not
believe this is a concern because the technologies--and thus emission
rates--from larger manufacturers represent the same basic technologies
and emission rates of essentially all vehicles and engines. It is also
worth noting that the manufacturers that meet the small manufacturer
definitions represent a very small fraction of overall vehicle and
engine sales. For nine out of the twelve non-aircraft mobile source
categories (there are currently no small aircraft engine
manufacturers), we estimate that sales from small manufacturers
represent less than 10 percent of overall sales (for eight of these
categories, including light-duty vehicles, small manufacturers account
for less than 3 percent of sales). For the remaining three categories
(highway motorcycles, all terrain vehicles/off-road motorcycles, and
small spark ignition engines) we estimate that small entities account
for less than 32 percent of sales.
Please see the discussion of our compliance with the RFA in Section
IX.C of this preamble. We request comments on our proposed approach for
the reporting threshold for mobile source categories.
c. Light-Duty Vehicles
We propose that manufacturers of passenger cars, light trucks, and
medium-duty passenger vehicles measure and report emissions of
CO2 (including A/C-related CO2), CH4,
N2O, and refrigerant leakage.\119\ Existing criteria
pollutant emissions certification regulations, as well as fuel economy
testing regulations, already require manufacturers to measure and
report CO2 for essentially all of their vehicle testing.
Requiring manufacturers to also measure and report the other GHGs
emitted by these vehicles, as proposed in this Notice and discussed
below, would introduce a modest but reasonable additional testing and
reporting burden.
---------------------------------------------------------------------------
\119\ See 40 CFR 1803-01 for full definitions of ``light-duty
vehicle''.
---------------------------------------------------------------------------
For CH4 and N2O, we propose that
manufacturers begin to measure these emissions as a part of existing
emissions certification and fuel economy test procedures (FTP, SFTP,
HFET, et al.), if they are not already doing so, and then to report
those emissions in the same cycle-weighted format that they report
other emission results under the current certification requirements.
Because such testing has not generally been required, some
manufacturers would need to install additional exhaust analysis
equipment for the measurement of CH4 and/or N2O.
In most cases, both of these types of new analyzers could be added as
modular units to existing test equipment.
In the case of N2O, since this pollutant has not
previously been included in the certification testing process, it is
necessary to introduce a new analytical procedure for the measurement
of N2O over the FTP. This is not the case for
CH4, however, since an analytical procedure for
CH4 testing already exists. We propose that manufacturers
use an N2O procedure found in the regulatory language
associated with this notice that would be based largely on the
procedures currently used to measure CO2 and CO, using
nondispersive infrared measurement technology. In addition, EPA is
proposing a ``scrubbing'' stage as a part of this procedure that would
remove sulfur compounds that can contribute to N2O formation
in the sample bag. (See proposed 40 CFR 1065.257 and 1065.357 for the
proposed N2O measurement procedures.) EPA requests comments
on all aspects of the proposed N2O measurement procedure,
including potential alternate methods with equal or better analytical
performance.
Measuring and Reporting A/C-Related CO2. Manufacturers of light-
duty vehicles, unlike manufacturers of heavy-duty and nonroad engines,
sell their products as complete engine-plus-vehicle combinations that
include the vehicles' A/C systems. Thus, we believe it is appropriate
that these manufacturers report A/C-related emissions as a part of
their existing vehicle certification requirements. EPA does not
currently require these manufacturers to measure or report the A/C-
related CO2 emissions (or the
[[Page 16588]]
leakage of refrigerants, as discussed below) under current regulations.
We propose that these manufacturers begin to measure A/C-related
CO2 emissions (i.e., the indirect CO2 emissions
resulting from the additional load placed on the engine by an operating
A/C system), using a proposed new test cycle, which is described below.
This testing would not require new equipment, and the proposed test
cycle is similar to one that exists in many State Inspection &
Maintenance (I/M) programs.
The current FTP for light-duty vehicles is performed with the A/C
turned on only during the SC03, or ``air conditioning,'' test
procedure. This test is used to verify emissions compliance in a
``worst-case'' situation when the A/C system is operating under
relatively extreme conditions. The SC03 is also used in the 5-cycle
fuel economy calculation for fuel economy labeling. Thus, although the
SC03 test results in a value for CO2 emissions (in grams per
mile), the incremental increase of CO2 resulting from
operation of the A/C system, especially in a more typical situation, is
not quantified.
In order to provide for consistent, accurate measurement of A/C-
related CO2 emissions, EPA proposes to introduce a
specifically-designed test procedure for A/C-related CO2
emissions. Manufacturers would run this proposed test, the A/C
CO2 Idle Test, with the engine idling, upon completion of an
emissions certification test--such as the FTP, highway fuel economy, or
US06 test. The proposed A/C CO2 Idle Test is similar to the
``Idle CO'' test, which was once a part of vehicle certification, and
is still used in State I/M programs (see 40 CFR part 51, subpart S,
Appendix B).
Within each vehicle model type, various configurations of engine
and cooling system options can be expected to have somewhat different
A/C-related CO2 performance.\120\ However, we believe that
vehicles sharing certain technical characteristics would generally have
similar A/C-related CO2 emissions. Specifically, vehicles
with the same engine, A/C system design, and interior volume would be
expected in most cases to have similar A/C-related CO2
performance. In order to minimize the number of new tests that
manufacturers would be required to perform, EPA is proposing that
manufacturers be allowed to select a subset of vehicles for A/C
CO2 Idle Testing, each of which would represent the
performance of a larger group of vehicles with common A/C-related
technical characteristics. We believe that in most cases the vehicles
that manufacturers currently test for fuel economy purposes (as
described in 40 CFR 600.208(a)(2)) would generally also capture the key
engine-A/C system-vehicle configurations that may exist within a given
model type. The complete set of our proposed criteria for manufacturers
to meet in selecting the representative vehicles for the A/C
CO2 Idle Test is found in the regulatory language in the
proposed rule (see proposed 40 CFR 86.1843-01, ``Air conditioning
system commonality'').
---------------------------------------------------------------------------
\120\ In the existing regulations covering vehicle emissions
certification, under `Definitions' in 40 CFR 600.002-85(a)(15),
``model type'' means a unique combination of car line, basic engine,
and transmission class.
---------------------------------------------------------------------------
The A/C CO2 Idle Test would compare the additional
CO2 generated at idle with the A/C system in operation to
the CO2 generated at idle with the A/C system off.
Manufacturers would run the test with the vehicle's A/C system
operating under complete control of the climate control system and for
a sufficient length of time to stabilize the cabin conditions and
tailpipe emission levels. EPA believes that this test would account for
the CO2 contributions from most of the key A/C system
components and modes of operation.
The additional CO2 generated when the A/C is operated
during the Idle Test would then be normalized to account for the
interior cabin volume of the vehicle. This normalization is necessary
because the size and capacity of an A/C system is related to the volume
of air that an A/C system must cool. Rather than simply reporting the
vehicle's CO2 emissions, this normalization would provide a
more appropriate metric of CO2 emissions to compare systems
that must cool relatively larger volumes with those that cool smaller
volumes. EPA proposes that the interior cabin volume be defined as the
volume of air that the air conditioner cools, which includes the volume
of space used by passengers and, in some vehicles, the volume used for
cargo. The proposed calculation of interior cabin volume is adapted
from an industry protocol, Society of Automotive Engineers (SAE)
Surface Vehicle Standard J1100.
The proposed A/C CO2 Idle Test would require three
approximately 10-minute periods of CO2 emissions measurement
once the vehicle's cabin conditions and climate control system have
stabilized in order to quantify the A/C related CO2. The
test would be run at 75 [deg]F, the standard temperature of the FTP. As
discussed below, EPA considered proposing a more complex procedure that
would be performed at a higher temperature, such as the 95 [deg]F used
in the SC03 test. However, we believe that A/C-related CO2
can be accurately demonstrated on the Idle Test at 75 [deg]F, avoiding
the significant facility and testing issues associated with higher
temperature testing. In order to better simulate ``real world'' idling
conditions, we propose that the A/C CO2 Idle Test be
performed with the engine compartment hood and windows closed and
without operating the test site cooling fan that is usually used to
simulate the motion of the vehicle on the road.
The proposed A/C CO2 Idle Test procedure specifies how
climate control systems, whether manual or automatic, would need to be
set to appropriately simulate the maximum and minimum cooling demands
on the A/C system. CO2 exhaust emission measurements, in
grams per minute, would be taken during both of these modes.
Manufacturers would conduct the idle test following the completion of a
FTP certification test, a fuel economy test, or a test over the US06
cycle. As discussed above, manufacturers would measure the change in
CO2 due to A/C operation in grams per minute and then would
divide this value by the interior volume in cubic feet, for an A/C
CO2 emission value in terms of grams per minute per cubic
foot. The manufacturer would report this value to EPA with other
emission results.
EPA also requests comment on three different approaches that could
be used alone or in combination with the proposed A/C CO2
Idle Test or with each other. Each of these tests would capture a
somewhat different set of aspects of A/C-related CO2
emissions. First, EPA is seeking comment on basing reporting
requirements on the SC03 test (or some variant of this test), which, as
described above, is designed to simulate more extreme driving
conditions than the standard certification tests. Using the SC03 test
to determine A/C-related CO2 performance would likely
require manufacturers to run tests in additional modes or to repeat the
test in order to capture more real-world A/C usage (i.e., a stabilized
cabin temperature). Therefore such an approach could involve
significant modifications to the SC03 test procedure. The rationale for
considering such an adapted SC03 test would be to characterize more
systemic technological features (such as thermal management and
transient A/C control) that may not be captured in a 75 [deg]F idle
test or a bench test (as discussed below).
Second, EPA is seeking comment on basing reporting requirements on
a ``bench'' test procedure similar to the one being developed by the
SAE and the University of Illinois, which was employed to measure A/C
efficiency
[[Page 16589]]
improvements for the industry/government Improved Mobile Air
Conditioning project. This bench test only measures the power
consumption of the A/C compressor with simulated loads, and is not
integrated into a vehicle (as would be the case in the proposed A/C
CO2 Idle Test, which is a ``chassis,'' or whole-vehicle,
test). The purpose of the bench test for characterizing A/C-related
CO2 emissions would be to have a relatively repeatable test
that could represent a variety of temperature and humidity conditions
around the country. Unlike a chassis test, there would not be a direct
connection to a vehicle's interior volume, and we would need to develop
assumptions about a vehicle's interior volume in order to normalize the
results. This test procedure might be less expensive than a modified
SC03 test.
Finally, EPA is seeking comment on basing reporting requirements on
design-based criteria for characterizing A/C-related CO2
emissions. Design-based criteria would be conceptually similar to the
ones proposed for leakage emissions characterization as described
below. A manufacturer would choose technologies from a list provided by
EPA in the rule where we would specify the A/C-related CO2
characteristics associated with each major component and technology,
including system control strategy and systems integration. While such a
design-based approach might capture the expected CO2
emissions of individual components and controls, it would not
necessarily capture overall system A/C-related CO2 (when the
A/C components would be integrated into the vehicle and would interact
with the engine, cabin conditions, and other vehicle characteristics,
such as the under-hood environment).
Calculating and Reporting a ``Score'' for A/C-Related Refrigerant
Leakage. As part of most of EPA's existing mobile source emissions
testing and certification programs, where robust test procedures have
been developed and are in widespread use, EPA has relied on
``performance-based'' approaches, where emissions are measured directly
during vehicle or engine operation to determine emission levels.
Examples of performance-based test procedures include the FTP and the
proposed A/C CO2 Idle Test discussed above. In the case of
A/C refrigerant leakage, where it is known that leakage of refrigerants
with high GWPs occurs, a reliable, performance-based test procedure to
measure such emissions from a vehicle does not yet exist. Instead, we
are proposing a ``design-based'' approach to establish a vehicle's
expected refrigerant leakage emissions.
Under our proposal, each key A/C-related component and system would
be assigned an expected rate of refrigerant leakage, in the form of a
leakage ``score,'' in terms of grams per year. These individual scores
would be added to result in an overall leakage score for the vehicle.
We propose that manufacturers establish an overall leakage score for
the same test vehicle(s) on which they run the A/C CO2 Idle
Test, as described above.
The cooperative industry and government Improved Mobile Air
Conditioning Program referenced above also has developed a
comprehensive set of leakage scores that EPA proposes to use to
represent the significant sources of A/C refrigerant leakage from newer
vehicles. The Improved Mobile Air Conditioning Program and the SAE have
established a template for calculating individual leakage scores based
on the quantity and type of components, fittings, seals, and hoses
utilized in a specific A/C system design; this template is known as the
SAE Surface Vehicle Standard J2727. EPA is proposing a set of component
and system leakage scores, based closely on J2727, but expanded to
place greater emphasis on characterizing leakage emissions later in the
vehicle's life. Like the J2727, this proposed EPA protocol would
associate each technology or system design approach with a specific
leakage score. Each score would be a design-based, ``leakage-
equivalent'' value that would take into account expected early-in-life
refrigerant leakage from the specified components and systems.
Manufacturers would report this value to EPA on their application for
certification.
In addition, we request comment on the whether other A/C design
considerations, such as use of alternative refrigerants, monitoring
refrigerant leakage (with fault storage and indicators), and minimizing
refrigerant quantity, should be used in determining an A/C leakage
score.
d. Highway Heavy-Duty Diesel and Gasoline Vehicles and Engines
EPA's highway heavy-duty vehicle and engine emissions testing and
certification programs generally cover vehicles above 8,500 pounds
Gross Vehicle Weight Rating.\121\ For most large trucks, manufacturers
are required to measure and report criteria air pollutant emissions
data for engines rather than vehicles. Engine manufacturers measure and
report emissions prior to the engines being sold to separate companies
that build trucks or buses and install engines in them. Manufacturers
of gasoline-fueled complete vehicles below 14,000 pounds Gross Vehicle
Weight Rating, such as large pick-ups and SUVs, are required to measure
and report vehicle emissions, as do manufacturers of light-duty
vehicles. These vehicles are described as ``complete'' vehicles because
the vehicles leave the primary manufacturing facility fully assembled,
with the engine and associated hardware installed and the load-carrying
container attached.
---------------------------------------------------------------------------
\121\ See 40 CFR 1803-01 for full definitions of ``heavy-duty
vehicle'' and ``heavy-duty engine.''
---------------------------------------------------------------------------
Manufacturers That Certify Engines. EPA proposes to require
manufacturers to report CO2 emissions from highway heavy-
duty diesel and gasoline engines. All manufacturers currently measure
CO2 as an integral part of calculating emissions of criteria
pollutants, and some report CO2 emissions in some form. We
propose that engine manufacturers report CO2 to EPA with
criteria pollutant emission results and, as with the criteria
emissions, report the CO2 emissions in terms of brake-
specific emissions (i.e., in units of grams of CO2 per
brake-horsepower-hour).
We also propose that highway heavy-duty engine manufacturers
measure and report CH4 emissions. This would require most
manufacturers to install CH4 exhaust analytical equipment or
to arrange for testing at another facility. This equipment is usually
designed to be installed as a modular addition to existing analytical
equipment. Procedures for analyzing CH4 are currently in
place.
Finally, we also propose that these manufacturers measure and
report N2O. As with CH4, this would require most
manufacturers to install new, usually modular, N2O exhaust
analytical equipment, or to arrange for testing at another facility.
Because it has not been necessary in the past to measure
N2O, we are proposing a new procedure for measuring
N2O (see proposed 40 CFR 1065.257 and 1065.357).
As with CO2, manufacturers would measure both
CH4 and N2O as a part of the existing FTP for
heavy-duty engines and report the results to EPA with other criteria
pollutant emission test results.
Manufacturers That Certify Complete Highway Heavy-Duty Vehicles. We
propose that manufacturers certifying complete heavy-duty vehicles be
subject to the same measurement and reporting requirements as
manufacturers of heavy-duty engines. Thus, as described above, these
manufacturers would report the CO2 emissions they are
currently measuring as part of criteria air
[[Page 16590]]
pollutant emissions testing and would additionally measure and report
CH4 and N2O. Although vehicle emissions testing
(also known as ``chassis testing'') is different than engine-only
testing, measurement procedures are the same, and we are proposing
measurement and reporting requirements for complete heavy-duty vehicles
that are essentially identical to our proposed requirements for heavy-
duty engines.
However, manufacturers of complete heavy-duty vehicles, unlike
heavy-duty engine manufacturers, are generally responsible for
installing the vehicle's A/C equipment. For this reason, we propose
that these manufacturers be responsible for reporting A/C-related
emissions, in exactly the same ways that we are proposing for light-
duty manufacturers, as described in Section V.QQ.3.c of this preamble.
Thus, we propose that these manufacturers perform the A/C
CO2 Idle Test and report the A/C-related CO2
emissions. We also request comment on the potential applicability of
the alternate A/C CO2 measurement procedures discussed above
to manufacturers of complete heavy-duty vehicles. In addition, we
propose that these manufacturers calculate and report an overall A/C
refrigerant leakage ``score,'' using the same assigned component and
system scores we have developed for the proposed light-duty scoring
system.
Vehicle Manufacturers That Install Certified Engines. We are not
proposing any requirements for the heavy-duty truck and bus
manufacturers that install certified engines into their vehicles. These
truck manufacturers currently are not required to certify their trucks
to EPA emissions standards and do not conduct emissions testing.
However, we recognize that these vehicles are generally equipped with
A/C systems by the truck or bus manufacturer. We request comment on the
appropriateness, feasibility, and cost of extending some form of the
proposed A/C CO2 Idle Test and refrigerant leakage score
requirements discussed above for manufacturers of complete heavy-duty
trucks to these truck and bus manufacturers as well. In addition, we
request comment on how original-equipment or aftermarket auxiliary
power units--if used to provide power for cabin A/C--might be
incorporated into a GHG reporting program.
e. Nonroad Diesel Engines and Nonroad Large Spark-Ignition Engines
Nonroad diesel engines and nonroad large spark-ignition (generally
gasoline-fueled) engines are used in a wide variety of construction,
agricultural, and industrial equipment applications. However, these
engines are very similar (in terms of design, technology, and
certification process) to their counterparts certified for highway
operation. Given these similarities, we propose that manufacturers of
these engines measure and report CO2, CH4, and
N2O in the same manner as manufacturers of highway heavy-
duty diesel and gasoline engines, as described earlier in this section
of the preamble.
Like highway heavy-duty truck and bus manufacturers that use
certified engines, nonroad diesel equipment manufacturers install
certified engines into their equipment but do not certify their
equipment. As with trucks and buses, this equipment is often equipped
with A/C systems. While we are not proposing any reporting requirements
for nonroad equipment manufacturers, we request comment on the
appropriateness, feasibility, and cost of extending some form of the
proposed A/C CO2 Idle Test and refrigerant leakage score
reporting requirements discussed above to nonroad equipment
manufacturers. We also request comment on extending A/C-related GHG
reporting requirements to transportation refrigeration units that are
equipped with separate engines that are certified under EPA's nonroad
engine program.
f. Nonroad Small Spark-Ignition Engines, Marine Spark-Ignition Engines,
Personal Watercraft, Highway Motorcycles, and Recreational Engines and
Vehicles
There is a large range of spark-ignition engines in this category
including engines used in portable power equipment, snowmobiles, all
terrain vehicles, off-highway motorcycles, automotive-based, inboard
engines used in marine vessels. For purposes of this proposed reporting
rule, we also include highway motorcycles, which are tested as complete
vehicles. We are proposing that manufacturers measure and report
CO2, CH4, and N2O emissions for these
engines and vehicles. As part of existing criteria pollutant emissions
testing requirements, manufacturers must determine the amount of fuel
consumed either through direct measurement or through chemical balances
of the fuel, intake air, and exhaust. With the ``chemical balance''
approach, CO2 levels in the intake air and exhaust are
measured (along with either the intake air flow rate or exhaust flow
rate), and fuel consumption is calculated based on fuel properties and
the change in CO2 level between the intake and exhaust
flows. (CO2 levels with associated flow rates can be used to
calculate a CO2 emission rates). Alternatively, when a
``direct measurement'' approach is used to determine fuel consumption,
there is no need to measure CO2 levels in the intake air or
exhaust. For manufacturers that generally use only the direct
measurement approach, new analysis equipment might be required to
measure CO2 levels in the intake air and exhaust. We propose
that manufacturers measure and report cycle-weighted CO2
emissions (in the same ``grams-per-unit-of-work'' format used for
criteria pollutant emissions reporting) for all engines in these
categories, regardless of the method used to determine fuel
consumption. We also propose that highway motorcycle manufacturers
measure and report CO2 in terms of grams per mile.
For CH4, many of the engines described above are subject
to ``total'' hydrocarbon, or ``hydrocarbon + NOX ''
standards (as opposed to ``non-CH4'' hydrocarbon standards
applying to some other categories), and thus CH4 emissions
may not typically be measured. In these cases, the manufacturers would
need to install CH4 emissions analysis equipment. We propose
that manufacturers report cycle-weighted CH4 emissions for
these engines and for highway motorcycles.
Finally, we are proposing that manufacturers also report the cycle-
weighted N2O emissions for these engines and for highway
motorcycles. As with CH4, manufacturers would likely need to
install N2O emissions analysis equipment. The proposed new
procedure for measuring N2O is found in the draft
regulations (40 CFR 1065.257 and 1065.357).
g. Locomotive and Marine Diesel Engines
We are proposing that manufacturers of locomotive and marine diesel
engines--including those who certify ``remanufactured'' engines--
measure and report CO2, CH4, and N2O
emissions for locomotive and marine diesel engines. Manufacturers of
these engines already measure CO2 emissions during the
course of existing criteria air pollutant emission testing
requirements, but generally do not report this to EPA. For
manufacturers of these engines, we propose that CO2
emissions be reported in the same cycle-weighted, work-based format
(i.e., g/bhp-hr) as used for criteria pollutant emissions reporting.
For C3 marine diesel engines, we are requesting comment on whether
indirect CO2 measurement (i.e., calculating the
CO2 levels based on fuel flow rate and fuel composition
parameters) is an appropriate method for those manufacturers that do
not utilize CO2
[[Page 16591]]
analysis equipment in the course of emission testing.
Since diesel locomotives are subject to ``total'' hydrocarbon
standards (which include CH4 in the measured and reported
hydrocarbon value), as opposed to ``non-CH4'' hydrocarbon
standards (which do not include CH4), manufacturers
typically do not measure CH4 emissions. With the exception
of C3 marine diesel engines (which do not have any ``hydrocarbon''
emission standards, and are not required to measure hydrocarbon or
CH4 emissions), we propose that manufacturers measure and
report CH4 emissions as a part of certification. To do so,
we expect that some manufacturers would need to install equipment for
analyzing CH4 emissions.
We also propose that manufacturers--except for C3 marine--measure
and report N2O emissions as well. For C3 marine diesel
engines, we are requesting comment on the appropriateness and
feasibility of requiring N2O measurement and reporting on
the small number of engines represented by this category. As with
CH4, we expect that most or all manufacturers would need to
install N2O emissions analysis equipment. The proposed new
procedure for measuring N2O is found in the proposed
regulations (40 CFR 1065.257 and 1065.357).
h. Aircraft Engines
This category comprises turbofan, turbojet, turboprop (turbine-
driven propeller), turboshaft (turbine-driven helicopters), and piston
propulsion engines for commercial, air taxi, and general aviation
aircraft. In the case of turbofan and turbojet engines of rated output
(or thrust) greater than 26.7 kilonewtons, manufacturers of these
engines are already measuring and recording CO2 emissions as
part of existing criteria air pollutant emission requirements for the
landing and takeoff cycle. In this notice, we propose that
manufacturers measure, record and report CO2 separately for
each mode of the landing and takeoff (LTO) cycle used in the emission
certification test, as well as for the entire landing and takeoff
cycle. (The modes of the landing and takeoff cycle are taxi/idle,
takeoff, climb out, and approach.)
CH4 may be emitted by gas turbine engines during idle
and by relatively older technology engines, but recent data suggest
that little or no CH4 may be emitted by some newer engines.
Manufacturers of turbofan and turbojet engines of rated output greater
than 26.7 kilonewtons are currently measuring hydrocarbon emissions as
part of existing criteria air pollutant emissions testing, and
CH4 is included in the total hydrocarbon measurement. We
propose that manufacturers of these engines begin to separately measure
and report CH4 for all engines in this category for which
they are currently required to measure and record criteria air
pollutant emissions as part of the certification process. Some
manufacturers may need to acquire CH4 emissions analysis
equipment. We ask for comment on the degree to which engine
manufacturers now have the needed equipment in their certification test
cells to measure CH4.
Since little or no N2O is formed in modern gas turbine
engines, we are not proposing to require N2O measurement or
reporting.
Within the mobile source sector, NOX is a climate change
gas unique to aviation. As required in 40 CFR part 87, manufacturers of
turbofan and turbojet engines of rated output greater than 26.7
kilonewtons measure and record NOX emissions in each of the
four LTO test modes, and these manufacturers must comply with the LTO
NOX emission standard (for the entire LTO cycle). EPA asks
for comment on whether NOX emissions in the four LTO test
modes and for the overall LTO cycles should be reported under the
provisions of this proposal, as they are now not reported to EPA for
public consideration as is the case with all other mobile sources.\122\
---------------------------------------------------------------------------
\122\ Currently, these engine manufacturers voluntarily report
criteria air pollutant emissions for the LTO cycle to the
International Civil Aviation Organization.
---------------------------------------------------------------------------
EPA does not currently require manufacturers of piston engines
(used in any application) to measure, record or report criteria air
pollutant or GHG emissions, and no official FTP exists for these
engines.\123\ For these reasons, we are not proposing any GHG reporting
requirements for these engines. However, we request comment on the
potential costs and benefits of reporting requirements for GHG
emissions from these engines, including how an appropriate emission
test cycle might be designed. We also ask for comment on whether the
requirements should be applied to turbofan and turbojet engines of
rated output less than or equal to 26.7 kilonewtons, turboprop engines,
and turbo shaft engines which are not now regulated under 40 CFR 87
requirements for criteria air pollutant emissions.\124\
---------------------------------------------------------------------------
\123\ EPA received an administrative petition asking the agency
to determine under section 231 of the CAA whether lead emissions
from general aviation (piston engine) aircraft cause or contribute
to air pollution which may reasonably be anticipated to endanger
public health or welfare, and, if so, to establish standards for
such emissions. Today's proposal regarding GHG emissions from
piston-engine aircraft is not intended to respond in any way to the
petition regarding general aviation lead emissions.
\124\ Existing regulations in 40 CFR part 87 include smoke
number standards for turbofan and turbojet engines of rated output
less than or equal to 26.7 kilonewtons and turboprop engines of
rated output greater than or equal to 1,000 kilowatts. Requirements
for the term turboshaft engine are currently not specified in 40 CFR
part 87.
---------------------------------------------------------------------------
4. Request for Comments on Travel Activity and Other In-Use, Emissions-
Related Data
Travel activity and other emissions-related data from State and
local governments and fleet operators are critical to understanding the
overall GHG contribution of the mobile source sector. These data serve
the important role of reflecting real-world conditions and capturing
activity levels (e.g., distance traveled and hours operated) from all
vehicles and engines, which can complement data that manufacturers
report on expected emissions rates from new vehicles and engines. EPA
already receives some in-use data through existing reporting programs.
The purpose of this section of the preamble is to describe these
existing data sources and to request public comment on the need for
additional data. In Section V.QQ.4.a of this preamble, we describe data
currently reported by State and local governments, and request comment
on the potential benefits of the collection of additional data. In
Section V.QQ.4.b of this preamble, we highlight the types of data
reported by fleet operators as part of the SmartWay Transport Program
or other Federal programs, and request comment on the value of other
potential reporting requirements.
a. Travel Activity and Other Data From State and Local Governments
Travel activity is a term EPA primarily uses for on-road vehicle
activity and includes the number and type of vehicles and the distance
they travel. State and local governments collect many types of travel
activity data, including VMT by vehicle type and model year, fuel type,
and/or functional road class (e.g., limited access highways, arterials
with traffic signals, etc.). Other types of emissions-related data
include vehicle operation and environmental conditions that can affect
emissions during travel, such as idling practices and ambient
temperature. Travel activity and other emissions-related data can vary
over time, between regions, and between metropolitan and rural areas
within a given State. EPA can use these data to evaluate how changes in
vehicle
[[Page 16592]]
technology or travel activity can affect emissions.
EPA currently collects on-road mobile source data to better
understand criteria air pollutant emissions, and some of these data can
also be used to understand GHG emissions. For example, States provide
VMT data to the Agency through the AERR.\125\ EPA currently relies on
AERR data to develop the NEI \126\ which is used for, among other
things, evaluating Federal vehicle and fuel standards for criteria
pollutants and mobile source air toxics.
---------------------------------------------------------------------------
\125\ EPA promulgated the AERR in December 2008 (73 FR 76539)
(40 CFR part 51, subpart A). EPA promulgated the AERR to
consolidate, reduce, and simplify the current requirements; add
limited new requirements; provide additional flexibility to states
in the ways they collect and report emissions data; and accelerate
the reporting of emissions data to EPA by state and local agencies.
The AERR replaces the Consolidated Emissions Reporting Rule (CERR)
which was promulgated in June 2002 (67 FR 39602) in part to
streamline existing periodic emissions inventory requirements for
criteria pollutants.
\126\ EPA prepares a national database of air emissions
information from numerous state and local air agencies, from tribes,
and from industry: http://www.epa.gov/ttn/chief/eiinformation.html.
---------------------------------------------------------------------------
The AERR requires State air agencies to report mobile source data,
including VMT data at the county level by roadway type, \127\ every
three calendar years beginning with the 2002 calendar year (i.e.,
states report mobile source inventories for 2005, 2008, 2011, etc.).
The most recent submissions are for the 2005 calendar year. Although
not required by the rule, EPA understands that some State air agencies
consult with State and local transportation agencies in preparing VMT
data submissions. States also submit other information that can be used
to estimate criteria pollutant emissions, e.g., age and speed
distributions of vehicles by vehicle class and roadway type, fuel
properties by county, month, and year, and temperature and humidity
data by county, month, and year. The AERR also requires certain
emissions-related information, such as activity data (e.g., hours/day
of operation), for nonroad mobile sources, according to similar
submission requirements as described above.
---------------------------------------------------------------------------
\127\ Under the AERR, VMT data should reflect both roadway type
and vehicle type information.
---------------------------------------------------------------------------
In addition to EPA's existing data collection requirements, there
are other sources of travel activity and emissions-related data. DOT
currently collects statewide VMT data for urban and rural roadway types
through its Highway Performance Monitoring System. DOT and DOE also
publish statistical reports such as the Census Transportation Planning
Package, National Personal Transportation Survey, and the Urban
Mobility Study. In the past, the U.S. Census Bureau conducted the
Vehicle Inventory and Use Survey, which provided valuable data on the
physical and operational characteristics of the nation's private and
commercial truck populations.\128\ In specific geographic areas,
agencies such as metropolitan planning organizations, State departments
of transportation, transit agencies, air quality agencies, and county
planning agencies also collect and project State and local travel
activity and emissions data to meet Federal requirements, such as DOT's
transportation planning requirements and EPA's SIP and transportation
conformity requirements.
---------------------------------------------------------------------------
\128\ The primary goal of the Vehicle Inventory and Use Survey
database was to produce national and state-level estimates of the
total number of trucks. This survey was conducted every 5 years,
until it was discontinued in 2002.
---------------------------------------------------------------------------
In light of the existing data available to EPA, the Agency is not
proposing any new reporting requirements for State and local
governments at this time. However, EPA is interested in requesting
comment on several topics.
(1) Should EPA require States, local governments, or other entities
to report additional travel activity or emissions-related data beyond
what is required under EPA's existing reporting requirements? How would
such data be used to inform future climate policy?
(2) What, if any, are the specific gaps in the currently reported
travel activity or emissions-related data that are important for
understanding on-road mobile source GHG emissions? For example, would
it be helpful for EPA to better understand State- or county-level VMT
growth rates (e.g., based on VMT data collected over the past five or
ten years or other methodology) or emissions data related to the
freight sector (e.g., hours of long-duration truck idling or truck data
that was previously provided by the Vehicle Inventory and Use Survey)?
What is the quality of currently reported State and local VMT data, and
should travel activity and emissions-related data quality be improved?
(3) Is it sufficient to collect travel activity or emissions-
related data every three years as currently required, or should EPA
collect such data on an annual basis, similar to other collections
discussed in today's action?
(4) Should EPA consider any threshold(s) for States, local
governments, or other entities that must report additional travel
activity or other emissions-related data? For example, should
additional data be reported only from larger metropolitan areas with
more sophisticated transportation systems (e.g., metropolitan planning
organizations with an urbanized population of 200,000 or more)?
(5) What nonroad activity data is of most interest for
understanding GHG emissions, and should EPA consider any additional
requirements for reporting such data beyond what is currently required?
b. Mobile Source Fleet Operator Data
Mobile source fleet operators \129\ are in a unique position to
collect data that reflect real-world conditions that are difficult to
integrate into vehicle and engine testing procedures or to capture in
travel activity surveys. Fleet operator data includes fuel consumption,
which can be robustly converted into CO2 emissions, distance
traveled, and the number and/or weight of passengers and freight
transported. EPA currently collects fleet operator data from sources
that include DOT surveys such as the Vehicle Inventory and Use Survey
(described in Section V.QQ.4.a of this preamble, but discontinued in
2002), in-use testing as part of vehicle and engine manufacturer
compliance programs, ad-hoc internal and external field studies and
surveys, and voluntary programs such as the SmartWay Transport
Partnership. The rest of this section of the preamble describes the
data EPA collects as part of our voluntary programs as well as the
DOT's (DOT) rail and aviation fleet reporting requirements, and
requests comment on the need for, and substance of, any additional
reporting requirements.
---------------------------------------------------------------------------
\129\ For the purpose of our request for comments, ``fleet
operators'' are defined as entities that have operational control
over mobile sources. ``Operational control'' is defined as having
the full authority to introduce and implement operational,
environmental, health, and safety policies.
---------------------------------------------------------------------------
EPA believes that one of the most important functions of collecting
fleet operator data is to inform operators about their emissions
profiles and to shed light on opportunities to reduce emissions through
the use of clean technologies, fuels, and operational strategies.
Through the SmartWay Transport Partnership program, EPA requires
participating truck and rail equipment operators, or ``partners,'' to
report data as part of their voluntary commitment to measure and
improve the environmental performance of their fleets. EPA uses this
data to evaluate partner performance. Partners report annually on their
fuel consumption by fuel type, miles traveled, and tonnage of freight
carried. Truck operators also have the option of reporting the
configuration and model year of each of their trucks. There is no
minimum emissions reporting threshold for either truck or rail
operators. EPA requires partners to report their annual data
[[Page 16593]]
through the SmartWay Freight Logistics Environmental and Energy
Tracking performance model.\130\ The SmartWay Freight Logistics
Environmental and Energy Tracking model translates the partners' fuel
consumption data into CO2 emissions based on EPA's default
emissions factors for fuels. EPA does not publicly release individual
partners' emissions data. At present, the SmartWay Transport
Partnership has received annual data from more than 400 trucking
companies and all seven Class I rail companies. These partners'
CO2 emissions represent approximately 20 percent and 80
percent, respectively, of the 2005 national inventory of trucking and
rail GHG emissions.\131\
---------------------------------------------------------------------------
\130\ The SmartWay Freight Logistics Environmental and Energy
Tracking model and accompanying user guide and glossary is available
at http://www.epa.gov/otaq/smartway/smartway_fleets_software.htm.
\131\ Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2005, EPA, 2007.
---------------------------------------------------------------------------
EPA's Climate Leaders program also requires participating companies
that operate mobile sources to report CO2, N2O,
CH4, and HFC emissions from those sources annually as a part
of their voluntary commitment to develop a comprehensive, corporate-
wide GHG inventory. There are no minimum emissions reporting thresholds
for mobile sources. Companies quantify mobile source emissions based on
the Climate Leaders reporting protocol,\132\ which outlines several
methods for calculating CO2 including applying EPA's default
factors to fuel consumption data. The reporting protocol also includes
default N2O and CH4 factors for non-road fuel
consumption and on-road miles traveled by vehicle model year or
technology type. Additionally, the reporting protocol includes default
HFC leakage factors for mobile A/C units. As with SmartWay, EPA does
not publicly release individual participating companies' emissions
data. Currently, the Climate Leaders program has received mobile source
data from 37 companies representing roughly 0.09 percent of the 2005
national inventory of transportation sector GHG emissions.\133\
---------------------------------------------------------------------------
\132\ See Direct Emissions from Mobile Combustion Sources and
Direct HFC and PFC Emissions from Use of Refrigeration and Air
Conditioning Equipment, available at http://www.epa.gov/climateleaders/resources/cross-sector.html.
\133\ Inventory of U.S. Greenhouse Gas Emissions and Sinks:
1990-2005, EPA, 2007.
---------------------------------------------------------------------------
In addition, DOT collects and publicly releases extensive data from
rail and aircraft operators. All seven Class I \134\ rail operators are
required to report annual fuel consumption and ton-miles, among other
data, to the Surface Transportation Board per the reporting guidelines
in 49 U.S.C. 11145. Large certificated air carriers,\135\ small
certificated air carriers, and commuter air carriers with more than
$20,000,000 in annual operating revenues must report monthly fuel usage
data to the Bureau of Transportation Statistics via Form 41 pursuant to
14 CFR part 217 and part 241. Large certificated air carriers must also
report monthly traffic data including distance traveled, tonnage of
freight transported, and number of passengers transported.
---------------------------------------------------------------------------
\134\ A ``Class I railroad'' is defined as a carrier that has an
annual operating revenue of $250 million or more after applying the
railroad revenue deflator formula, which is based on the Railroad
Freight Price Index developed by the U.S. Department of Labor, BLS.
The formula is the current year's revenues x 1991 average index/
current year's average index.
\135\ The definition of ``large certified air carrier'',``small
certified air carrier'', and ``commuter air carrier'' for Form 41
reporting requirements is available at: http://www.bts.gov/programs/statistical_policy_and_research/source_and_accuracy_compendium/form41_schedule.html.
---------------------------------------------------------------------------
In light of the existing data available to EPA, the Agency is not
proposing mandatory reporting requirements for mobile source fleet
operators, but is requesting comments on the need for, and substance
of, potential reporting requirements at this time. We request comment
on the following questions:
(1) Should fleet operators be required to report to EPA outside of
voluntary participation in the SmartWay or Climate Leaders programs?
How would this data be used to inform future climate policy?
(2) Are there certain categories of mobile sources that should be
included or excluded in potential reporting requirements (e.g., lawn
mowers, commercial light-duty vehicles, heavy-duty trucks, rail
equipment, aircraft, waterborne vehicles)?
(3) Should one or more minimum emissions thresholds apply based on
the mobile source category, and what would be appropriate annual
thresholds?
(4) Are there certain categories of fleets that should be included
or excluded from potential reporting requirements (e.g., public fleets
versus private fleets)?
(5) If reporting requirements were to be introduced, what types of
data should operators report (e.g., fuel consumption for estimating
CO2 and non-road N2O and CH4
emissions; mileage and vehicle technology for estimating on-road
N2O and CH4 emissions; efficiency metrics such as
emissions per tons carried)?
(6) What type of data verification or quality control should EPA
require in any potential reporting requirements?
(7) For potential reporting requirements, are there preferred
emissions quantification methods other than those presented in the
SmartWay Freight Logistics Environmental and Energy Tracking model or
the Climate Leaders reporting protocol?
VI. Collection, Management, and Dissemination of GHG Emissions Data
A. Purpose
This section of the preamble describes the process by which EPA
proposes to collect, manage, and disseminate data under the GHG
reporting rule.
Section V.B of this preamble describes the proposed establishment
of a new reporting system that would accept electronic submissions of
GHG emissions and supporting data, quality assure the submissions,
store the results, and provide access to the public. The new system
would follow Agency standards for design, security, data element and
reporting format conformance, and accessibility.
Existing sources that would be affected by the proposed GHG
reporting rule may currently report emissions or other data to the
Agency (or in some cases States) under other titles of the CAA
including Title I (Emission Inventory, SIP, NSPS and NESHAP), Title II
(National Emissions Standards Act), Title IV (Acid Rain), Title V (Air
Operating Permits) and Title VI (Stratospheric Ozone Protection). EPA
intends to develop a reporting scheme that minimizes the burden of
stakeholders by integrating the new reporting requirements with
existing data collection and data management systems, when feasible.
Also, EPA would work with States to ease the burden on reporters to
State and Federal systems by harmonizing data management, where
possible.
Section VI.B of this preamble further describes the proposal
regarding the frequency and timeliness of reporting, the requirement
for a Designated Representative certification, and the units of measure
for submissions and published results.
Section VI.C of this preamble describes QA that EPA would perform
to ensure the completeness, accuracy, and validity of submissions. It
also describes the feedback that EPA would provide to emission
reporters indicating the results of the electronic data quality checks.
Section VI.D of this preamble discusses publication of data that
would be collected under the proposed
[[Page 16594]]
mandatory GHG reporting rule. EPA proposes to make data collected under
this rule available to State agencies and the public, with the
exception of any CBI data, as discussed in Section I.C of this
preamble. EPA requests comments on proposed strategies regarding data
collection, management, and dissemination outlined in this section of
the preamble.
B. Data Collection
1. Data Collection Methods
If a reporting source already reports GHG emissions data to an
existing EPA program, the Agency would make efforts to minimize any
additional burden on the sources. Some existing programs, however, have
data collection and reporting requirements that are inconsistent with
the proposed requirements for the mandatory GHG reporting rule. When it
is not feasible to adapt the existing program to collect the
appropriate emissions data and supplemental data, EPA proposes to
require affected sources to submit the data in the requested format to
the new data reporting system for the mandatory GHG reporting rule.
Emission sources may fall into one or more categories:
(1) Reporting sources that use existing data collection and
reporting methods and would not be required to report separately to the
new data reporting system for the GHG reporting rule.
(2) Reporting sources that use existing data collection and
reporting methods but would be required to report the data separately
to the new data reporting system for the GHG reporting rule.
(3) Reporting sources that are not currently required to collect
and report GHG emissions data to EPA and would be required to report
using the new data reporting system for the mandatory GHG reporting
rule.
EPA believes that using existing data collection methods and
reporting systems, when feasible, to collect data required by this
proposed rule would minimize additional burden on sources and the
Agency. We seek comment on the use of existing collection methods and
reporting systems to collect information required by this proposed
rule.
For those sources that do not report GHGs or data used to calculate
GHG emissions through an existing reporting system, EPA proposes to
develop a new system for emission reporters to submit the required
data. The detailed data elements that would be reported and other
requirements are specified in Sections III, IV and V of this preamble.
In general, reporters using this new method would report annually to
the Agency covering each calendar year by March 31 of the following
year (e.g., annual emissions for calendar year 2010 would be reported
by March 31, 2011.)
2. Data Submission
The Designated Representative (described in proposed 40 CFR part
98, subpart A and Section IV.G of this preamble) must use an electronic
signature device (for example, a PIN or password) to submit a report.
If the Designated Representative holds an electronic signature device
that is currently used for valid electronic signatures accepted under
another Agency program, we propose that the new reporting system would
also accept valid electronic signatures executed with that device where
feasible. (See 40 CFR 3.10 and the definitions of ``electronic
signature device'' and ``valid electronic signature'' under 40 CFR
3.3.)
3. Unique Identifiers for Facilities and Units
We believe that the Agency's reporting format for a given reporting
year could make use of several ID codes--unique codes for a unit or
facility. To ensure proper matching between databases, e.g., EPA-
assigned facility ID codes and the ORIS (DOE) ID code, and consistency
from one reporting year to the next, we are proposing that the
reporting system provide each facility with a unique identification
code to be specified by the Administrator.
4. Reporting Emissions in a Single Unit of Measure
To maintain consistency with existing State-level and Federal-level
greenhouse gas programs in the U.S. and internationally, the Agency is
proposing that all emission measurements be in the SI, also referred to
as metric, units. Data used in calculations and supplemental data for
QA could still be submitted in English weights and measures (e.g.,
mmBtu/hr) but the specific units of measure would be included in the
data submission. All emissions data would be submitted to the agency in
kg or metric tons per unit of time (per year in most cases, but for a
few source categories emissions per hour, day, month, quarter, or other
unit of time could also be required).
5. Conversion of Emissions to CO2e
Under this proposed rule, reporters would submit the quantity of
each applicable GHG emitted (or other metric) in two forms. The data
would be in the form of quantity of the gas emitted (e.g., metric tons
of N2O) per unit of time and CO2e emissions per
unit of time. Reporting the quantity and type of gas emitted allows for
future recalculation of CO2e emissions in the event that GWP
factors change.
6. Delegation of Authority to State Agencies To Collect GHG Data
The Agency proposes that affected sources submit the emissions data
and supplemental data directly to EPA. The Agency believes this would
reduce the burden on reporters and State agencies, provide faster
access to national emission data, and facilitate consistent QA.
Under CAA Section 114(b), EPA may delegate the authority to collect
emissions data from stationary sources to State agencies provided the
State agency can satisfy the procedural requirements. We seek comment
on the possibility of delegating the authority to State agencies that
request such authority and assessing whether the State agency has
procedures that are deemed consistent and adequate with the procedures
outlined in this rule. For example, how should EPA determine whether a
requesting State agency has ``consistent and adequate'' procedures?
7. Submission Method
EPA proposes to require all sources affected by this rule to report
in an electronic format to be specified by the Administrator.
Advantages of electronic reporting include reduced burden on reporters
and EPA staff, greater accuracy because data do not need to be manually
entered by EPA staff, enhanced ability to conduct electronic audits to
ensure data quality, improved comparability because data would be
reported in a consistent format, and improved data availability for EPA
and the public.
By not specifying the exact reporting format in the regulatory
text, EPA maintains flexibility to modify the reporting format and
tools in a timely manner. Changes based on stakeholder comment,
implementation experience, and new technology could be executed without
regulatory action. EPA has used this approach successfully with
existing programs, such as the ARP and the Title VI Stratospheric Ozone
Protection Program, facilitating the deployment of new reporting
formats and tools that take advantage of technologies (e.g., XML) and
reduce the burden on reporters and the Agency. The electronic reports
submitted under this rule would also be subject to the provisions of 40
CFR 3.10, specifying EPA systems to which electronic submissions must
be made and the requirements for valid electronic signatures.
[[Page 16595]]
C. Data Management
1. QA Procedures
The new reporting system would include automated checks for data
completeness, data quality, and data consistency. Such automated checks
are used for many other Agency programs (e.g., ARP).
2. Providing Feedback to Reporters
EPA has established a variety of mechanisms under existing programs
to provide feedback to reporters who have submitted data to the Agency.
EPA will consider the approaches used by other programs (e.g.,
electronic confirmations, results of QA checks) and develop appropriate
mechanisms to provide feedback to reporters for the GHG reporting rule.
The process is largely dependent upon such factors as the type of data
being submitted and the manner of data transmission. Regardless of data
collection system specifics, the goal is to ensure appropriate
transparency and timeliness when providing feedback to submitting
entities.
D. Data Dissemination
1. Public Access to Emissions Data
The Agency proposes to publish data submitted or collected under
this rulemaking through EPA's Web site, reports, and other formats,
with the exception of any CBI data, as discussed in Section I.C of this
preamble. This level of transparency would inform the public and
facilitate greater data verification and review. Transparency helps to
ensure data quality and build public confidence in the data so the data
can be used to support the development of potential future climate
policies or programs.
EPA proposes to disseminate the data on an annual basis. Under this
proposed rule, affected sources would be required to report at least on
an annual basis, with some reporting more frequently to existing data
reporting programs (e.g., the ARP). The Agency believes it would be
appropriate to post or publish data collected under this rule once a
year after the reporting deadline. The Agency recognizes the high level
of public interest in this data, and proposes to disclose it in a
timely manner, while also assuring accuracy.
2. Sharing Emission Data With Other Agencies
There are a growing number of programs at the State, Tribe,
Territory, and Local level that require emission sources in their
respective jurisdictions to monitor and report GHG emissions. These
programs would likely still continue because they may be broader in
scope or more aggressive in implementation than this proposal. In order
to be consistent with and supportive of these programs and to reduce
burden on reporters and program agencies, EPA proposes that it share
emission data with the exception of any CBI data, as discussed in
Section III.C of this preamble, with relevant agencies or approved
entities using, where practical, shared tools and infrastructure.
VII. Compliance and Enforcement
A. Compliance Assistance
To facilitate implementation and compliance, EPA plans to conduct
an active outreach and technical assistance program following
publication of the final rule. The primary audience would be
potentially affected industries. We intend to develop implementation
and outreach materials to help facilities understand if the rule
applies to them and explain the reporting requirements and timetables.
The program particularly would target industrial, commercial, and
institutional sectors that do not routinely deal with air pollution
regulations.
Compliance materials could be tailored to the needs of various
sectors. These materials might include, for example, compliance guides,
brochures, fact sheets, frequently asked question and answer documents,
sample reporting forms, and GHG emissions calculating tools. We also
are considering a compliance assistance hotline for answering questions
and providing technical assistance. (We may also want to consider
creating a compliance assistance center (http://www.assistancecenters.net).) EPA requests comment on the types of
assistance needed and the most effective mechanisms for delivering this
assistance to various industry sectors.
B. Role of the States
State and local air pollution control agencies routinely interact
with many of the sources that would report under this rule. Further, as
mentioned in Section II of this preamble, many States have already
implemented or are in the process of implementing mandatory GHG
reporting and reduction programs. In fact, many States may have
reporting programs that are broader in scope or more aggressive in
implementation because those programs are either components of
established reduction programs (e.g., cap and trade) or being used to
design and inform specific complementary measures (e.g., energy
efficiency).
Therefore, State and local agencies will serve an important role in
communicating the requirements of the rule and providing compliance
assistance. In concert with their routine inspection and other
compliance and enforcement activities for other CAA programs, State and
local agencies also can assist with educating facilities and assuring
compliance at facilities subject to this rule.
As discussed in Section VI of this preamble, CAA section 114(b)
allows EPA to delegate to States the authority to implement and enforce
Federal rules. At this time, however, EPA does not propose to formally
delegate implementation of the rule to State and local agencies. Even
without delegation, EPA will work with States to ease burden on
reporters to State and Federal systems by harmonizing data management,
where possible. Further, as discussed in Section VI of this preamble,
EPA is proposing to make the data collected under this rule available
to States and other interested parties as soon as possible. For
example, the quarterly data reported to EPA under Title IV of the CAA
is often available on EPA's Web site within a month after it is
reported. Furthermore, we recognize that many States with mandatory
reporting programs are members of TCR. In some cases, TCR would provide
States support in reporting tools, database management and serve as the
ultimate repository for data reported under State programs, after the
States have verified the data. Given the leadership many of the States
have shown in developing and implementing GHG reporting and reduction
programs, EPA is seeking comment on the possibility of delegating the
authority to collect data under this rule to State agencies. Overall,
we request comments on the role of States in implementing this rule and
on how States and EPA could interact in administering the reporting
program.
C. Enforcement
Facilities that fail to report GHG emissions according to the
requirements of the proposed rule could potentially be subject to
enforcement action by EPA under CAA sections 113 and 203-205. The CAA
provides for several levels of enforcement that include administrative,
civil, and criminal penalties. The CAA allows for injunctive relief to
compel compliance and civil and administrative penalties of up to
$32,500 per day.\136\
---------------------------------------------------------------------------
\136\ The Federal Civil Penalties Inflation Adjustment Act of
1990, Public Law 101-410, 104 Stat. 890, 28 U.S.C. 2461, note, as
amended by Section 31001(s)(1) of the Debt Collection Improvement
Act of 1996, Public Law 104-134, 110 Stat. 1321-373, April 26, 1996,
requires EPA and other agencies to adjust the ordinary maximum
penalty that it will apply when assessing a civil penalty for a
violation. Accordingly, EPA has adjusted the CAA's provision in
Section 113(b) and (d) specifying $25,000 per day of violation for
civil violations to $32,500 per day of violation.
---------------------------------------------------------------------------
[[Page 16596]]
Deviations from the rule that could ultimately be considered
violations include but are not limited to the following:
Failure to report GHG emissions.
Failure to collect data needed to estimate GHG emissions.
Failure to continuously monitor and test as required. Note
that merely filling in missing data as specified does not excuse a
failure to perform the monitoring or testing.
Failure to keep records needed to verify GHG emissions
estimates.
Failure to estimate GHG emissions according to the
methodology(s) specified in the rule.
Falsification of reports.
VIII. Economic Impacts of the Proposed Rule
This section of the preamble examines the costs and economic
impacts of the proposed rule, including the estimated costs and
benefits of the proposed rule, and the estimated economic impacts of
the proposed rule on affected entities, including estimated impacts on
small entities. Complete detail of the economic impacts of the proposed
rule can be found in the text of the regulatory impact analysis (RIA)
(EPA-HQ-OAR-2008-0318-002).
A. How are compliance costs estimated?
EPA estimated costs of complying with the proposed rule for process
emissions of GHGs in each affected industrial facility, as well as
emissions from stationary combustion sources at industrial facilities
and other facilities, and emissions of GHGs from mobile sources. 2006
is the representative year of the analysis in that the annual costs
were estimated using the 2006 population of emitting sources. EPA used
available industry and EPA data to characterize conditions at affected
sources. Incremental monitoring, recordkeeping, and reporting
activities were then identified for each type of facility and the
associated costs were estimated.
The costs of complying with the proposed rule would vary from one
facility to another, depending on the types of emissions, the number of
affected sources at the facility, existing monitoring, recordkeeping,
and reporting activities at the facility, etc. The costs include labor
costs for performing the monitoring, recordkeeping, and reporting
activities necessary to comply with the proposed rule. For some
affected facilities, costs include costs to monitor, record, and report
emissions of GHGs from production processes and from stationary
combustion units. For other facilities, the only emissions of GHGs are
from stationary combustion. EPA's estimated costs of compliance are
discussed in greater detail below:
Labor Costs. The costs of complying with and administering this
proposed rule include time of managers, technical, and administrative
staff in both the private sector and the public sector. Staff hours are
estimated for activities, including:
Monitoring (private): Staff hours to operate and maintain
emissions monitoring systems.
Reporting (private): Staff hours to gather and process
available data and reporting it to EPA through electronic systems.
Assuring and releasing data (public): Staff hours to
quality assure, analyze, and release reports.
Staff activities and associated labor costs would potentially vary
over time. Thus, cost estimates are developed for start-up and first-
time reporting, and subsequent reporting. Wage rates to monetize staff
time are obtained from the BLS.
Equipment Costs. Equipment costs include both the initial purchase
price of monitoring equipment and any facility/process modification
that may be required. For example, the cost estimation method for
mobile sources involves upstream measurement by the vehicle
manufacturers. This may require an upgrade to their test equipment and
facility. Based on expert judgment, the engineering costs analyses
annualized capital equipment costs with the appropriate lifetime and
interest rate assumptions. Cost recovery periods and interest rates
vary by industry, but typically, one-time capital costs are amortized
over a 10-year cost recovery period at a rate of 7 percent.
B. What are the costs of this proposed rule?
For the cost analysis, EPA gathered existing data from EPA,
industry trade associations, States, and publicly available data
sources (e.g., labor rates from the BLS) to characterize the processes,
sources, sectors, facilities, and companies/entities affected. Costs
were estimated on a per entity basis and then weighted by the number of
entities affected at the 25,000 metric tons CO2e threshold.
To develop the costs for the rule, EPA estimated the number of
affected facilities in each source category, the number and types of
combustion units at each facility, the number and types of production
processes that emit GHGs, process inputs and outputs (especially for
monitoring procedures that involve a carbon mass balance), and the
measurements that are already being made for reasons not associated
with the proposed rule (to allow only the incremental costs to be
estimated). Many of the affected sources categories, especially those
that are the largest emitters of GHGs (e.g., electric utilities,
industrial boilers, petroleum refineries, cement plants, iron and steel
production, pulp and paper) are subject to national emission standards
and we use data generated in the development of these standards to
estimate the number of sources affected by the reporting rule.
Other components of the cost analysis included estimates of labor
hours to perform specific activities, cost of labor, and cost of
monitoring equipment. Estimates of labor hours were based on previous
analyses of the costs of monitoring, reporting, and recordkeeping for
other rules; information from the industry characterization on the
number of units or process inputs and outputs to be monitored; and
engineering judgment by industry and EPA industry experts and
engineers. Labor costs were taken from the BLS and adjusted to account
for overhead. Monitoring costs were generally based on cost algorithms
or approaches that had been previously developed, reviewed, accepted as
adequate, and used specifically to estimate the costs associated with
various types of measurements and monitoring.
A detailed engineering analysis was conducted for each subpart of
the proposed rule to develop unique unit costs. This analysis is
documented in the RIA. The TSDs for each source category provide a
discussion of the applicable measurement technologies and any existing
programs and practices. Section 4 of the RIA contains a description of
the engineering cost analysis.
Table VIII-1 of this preamble presents by subpart: The number of
entities, the downstream emissions covered, the first year capital
costs and the first year annualized costs of the proposed rule. EPA
estimates that the total national annualized cost for the first year is
$168 million, and the total national annualized cost for subsequent
years is $134 million (2006$). Of these costs, roughly 5 percent fall
upon the public
[[Page 16597]]
sector for program administration, while 95 percent fall upon the
private sector. General stationary combustion sources, which are widely
distributed throughout the economy, are estimated to incur
approximately 18 percent of ongoing costs; other sectors incurring
relatively large shares of costs are oil and natural gas systems (21
percent of ongoing costs), and iron and steel manufacturing (11
percent).
The threshold, in large part, determines the number of entities
required to report GHG emissions and hence the costs of the rule. The
number of entities excluded increases with higher thresholds. Table
VIII-2 of this preamble provides the cost-effectiveness analysis for
the various thresholds. Three metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost
per metric ton of emissions reported ($/metric ton CO2e).
The second metric for evaluating the threshold option is the
incremental cost of reporting emissions. The incremental cost is
calculated as the additional (incremental) cost per metric ton starting
with the least stringent option and moving successively from one
threshold option to the next. The third metric shown is the marginal
cost of reported emissions. For this analysis, the marginal cost of
reporting indicates the cost per metric ton of each threshold option
relative to the 25,000 metric ton CO2e proposed threshold).
For more information about the first year capital costs (unamortized),
project lifetime and the amortized (annualized) costs for each subpart,
please refer to section 4 of the RIA and the RIA cost appendix. Not all
subparts require capital expenditures but those that do are clearly
documented in the RIA.
Table VIII-1. Estimated Covered Entities, Emissions and Costs by Subpart (2006$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Downstream emissions First year capital costs First year total
Number of ---------------------------------------------------- annualized costs \2\
Subpart covered (Million of -------------------------
entities MtCO2e) Share (%) (Million) Share (%) (Million) Share (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Subpart A--General Provisions
Subpart B--Reserved
Subpart C--General Stationary Fuel Combustion Sources........ 3,000 220.0 6 $12.7 15 $29.0 17
Subpart D--Electricity Generation............................ 1,108 2,262.0 58 0.0 0 3.3 2
Subpart E--Adipic Acid Production............................ 4 9.3 0 0.0 0 0.1 0
Subpart F--Aluminum Production............................... 14 6.4 0 0.0 0 0.4 0
Subpart G--Ammonia Manufacturing............................. 24 14.5 0 0.0 0 0.4 0
Subpart H--Cement Production................................. 107 86.8 2 5.4 6 6.9 4
Subpart I--Electronics Manufacturing......................... 96 5.7 0 0.0 0 3.6 2
Subpart J--Ethanol Production................................ 85 0.0 0 0.3 0 0.5 0
Subpart K--Ferroalloy Production............................. 9 2.3 0 0.0 0 0.3 0
Subpart L--Fluorinated Gas Production........................ 12 5.3 0 0.0 0 0.0 0
Subpart M--Food Processing................................... 113 0.0 0 0.0 0 0.6 0
Subpart N--Glass Production.................................. 55 2.2 0 0.0 0 0.6 0
Subpart O--HCFC-22 Production................................ 3 13.8 0 0.0 0 0.0 0
Subpart P--Hydrogen Production............................... 41 15.0 0 0.0 0 0.6 0
Subpart Q--Iron and Steel Production......................... 121 85.0 2 0.0 0 18.2 11
Subpart R--Lead Production................................... 13 0.8 0 0.0 0 0.3 0
Subpart S--Lime Manufacturing................................ 89 25.4 1 4.9 6 5.3 3
Subpart T--Magnesium Production.............................. 11 2.9 0 0.0 0 0.1 0
Subpart U--Miscellaneous Uses of Carbonates.................. 0 0.0 0 0.0 0 0.0 0
Subpart V--Nitric Acid Production............................ 45 17.7 0 0.2 0 0.9 1
Subpart W--Oil and Natural Gas Systems....................... 1,375 129.9 3 37.8 43 32.5 19
Subpart X--Petrochemical Production.......................... 88 54.8 1 0.0 0 1.6 1
Subpart Y--Petroleum Refineries.............................. 150 204.7 5 1.6 2 3.7 2
Subpart Z--Phosphoric Acid Production........................ 14 3.8 0 0.8 1 0.8 0
Subpart AA--Pulp and Paper Manufacturing..................... 425 57.7 1 14.8 17 9.2 5
Subpart BB--Silicon Carbide Production....................... 1 0.1 0 0.0 0 0.0 0
Subpart CC--Soda Ash Manufacturing........................... 5 3.1 0 0.0 0 0.0 0
Subpart DD--Sulfur Hexafluoride (SF6) from Electric Power 141 10.3 0 0.0 0 0.4 0
Systems.....................................................
Subpart EE--Titanium Dioxide Production...................... 8 3.7 0 0.0 0 0.1 0
Subpart FF--Underground Coal Mines........................... 100 33.5 1 0.6 1 2.3 1
Subpart GG--Zinc Production.................................. 5 0.8 0 0.0 0 0.1 0
Subpart HH--Landfills........................................ 2,551 91.1 2 7.9 9 15.3 9
Subpart II--Wastewater....................................... 0 0.0 0 0.0 0 0.0 0
Subpart JJ--Manure Management................................ 43 1.5 0 0.0 0 0.2 0
Subpart KK--Suppliers of Coal and Coal-based Products & 1,237 (\1\) 0 0.0 0 11.0 7
Subpart LL--Suppliers of Coal-based Liquid Fuels............
Subpart MM--Suppliers of Petroleum Products.................. 214 (\1\) 0 0.0 0 2.0 1
Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids. 1,554 (\1\) 0 0.0 0 2.1 1
Subpart OO--Suppliers of Industrial Greenhouse Gases......... 121 464.1 12 0.0 0 0.4 0
[[Page 16598]]
Subpart PP--Suppliers of Carbon Dioxide (CO2)................ 13 (\1\) 0 0.0 0 0.0 0
Subpart QQ--Motor Vehicle and Engine Manufacturers........... 350 35.4 1 0.0 0 7.4 4
Private Sector, Total........................................ 13,205 3,869.9 100 87.1 100 160.4 95
Public Sector, Total......................................... NA NA NA NA NA 8.0 5
------------------------------------------------------------------------------------------
Total.................................................... 13,205 3,869.9 100 87.1 100 168.4 100
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ Emissions from upstream facilities are excluded from these estimates to avoid double counting.
\2\ Total costs include labor and capital costs incurred in the first year. Capital Costs are annualized using appropriate equipment lifetime and
interest rate (see additional details in RIA section 4).
Table VIII-2. Threshold Cost-Effectiveness Analysis (2006$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Million Percentage
Entities Total costs metric tons of total Average Incremental Marginal
Threshold (metric tons CO2e) (covered) (million $) CO2e/year emissions cost ($/ cost ($/ cost * ($/
(covered) reported metric ton) metric ton) metric ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
100,000...................................................... 6,598 $101 3,699 52 $0.03 -- -$0.35
25,000....................................................... 13,205 160 3,870 55 0.04 $0.35 --
10,000....................................................... 20,765 213 3,916 56 0.05 1.16 1.16
1,000........................................................ 59,587 426 3,951 56 0.11 6.09 3.29
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Cost per metric ton relative to the selected option.
Table VIII-3 of this preamble presents costs broken out by upstream
and downstream sources. Upstream sources include the fuel suppliers and
industrial GHG suppliers. Downstream suppliers include combustion
sources, industrial processes, and biological processes. Most upstream
facilities (e.g., coal mines, refineries, etc.) are also direct
emitters of GHGs and are included in the downstream side of the table.
As shown in Table VIII-3 of this preamble, over 99 percent of
industrial processes emissions are covered at the 25,000 metric tons
CO2e threshold for a cost of approximately $36 million.
However, it should be noted that due to data limitations the coverage
estimates for upstream and downstream source categories are
approximations.
Table VIII-3. Upstream versus Downstream Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
Upstream \1\ Downstream \2\ \3\ \4\
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emissions
No. of Emissions First year No. of coverage First year
Source category Reporters coverage cost Source category Reporters \3\ \10\ cost \3\
(%) \10\ (millions) \2\ (%) (millions)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Supply................................ 1,237 100.0 $11.03 Coal \5\ \6\ Combustion...... N/A 99.0 N/A
Petroleum Supply........................... 214 100.0 1.99 Petroleum \5\ Combustion \10\ N/A 20.0 N/A
Natural Gas Supply......................... 1,554 68.0 2.14 Natural Gas \5\ Combustion... N/A 23.0 N/A
........... ........... ........... Sub Total Combustion......... 4,108 \5\ N/A 46.16
Industrial Gas Supply...................... 133 99.91 0.41 Industrial Gas Consumption... 265 28.0 3.70
........... ........... ........... Industrial Processes......... 1,077 99.6 36.12
........... ........... ........... Fugitive Emissions (coal, oil 1,475 86.6 34.86
and gas).
........... ........... ........... Biological Processes......... 2,792 55.5 16.59
........... ........... ........... Vehicle \7\ and Engine 350 84.0 7.41
Manufacturers \9\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
\1\ Most upstream facilities (e.g., coal mines, refineries, etc.) are also direct emitters of greenhouse gases, and are included in the downstream side
of the table.
\2\ Estimating the total number of downstream reporters by summing the rows will result in double-counting because some facilities are included in more
than one row due to multiple types of emissions (e.g., facilities that burn fossil fuel and have process/fugitive/biological emissions will be
included in each downstream category).
\3\ The coverage and costs for downstream reporters apply to the specific source category, i.e., the fixed costs are not ``double-counted'' in both
stationary combustion and industrial processes for the same facility.
\4\ The thresholds used to determine covered facilities are additive, i.e., all of the source categories located at a facility (e.g., stationary
combustion and process emissions) are added together to determine whether a facility meets the proposed threshold (e.g., 25,000 metric tons of CO2e/
yr).
[[Page 16599]]
\5\ Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels. National level data on
the number of reporters could be estimated. However, estimating the number of reporters by fuel was not possible because a single facility can combust
multiple fuels. For these reasons there is not a reliable estimate of the total of the emissions coverage from the downstream stationary combustion.
\6\ Approximately 90 percent of downstream coal combustion emissions are already reported to EPA through requirements for electricity generating units
under the Acid Rain Program.
\7\ Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take into account
thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that would result from this rule. To estimate
total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the industrial and electricity
generation sectors and divided that by total national GHG emissions from the combustion of that fuel.
\8\ The percent of coverage here is percentage of vehicle and engine manufacturers covered by this proposal rather than emissions coverage. This rule
proposes to collect an emissions rate for the four ``transportation-related'' GHG emissions (CO2, CH4, N2O and HFCs). The amounts of CH4 and N2O are
dependent on factors other than fuel characteristics such as combustion temperatures, air-fuel mixes, and use of pollution control equipment.
\9\ The emissions coverage for petroleum combustion includes combustion of fuel by transportation sources as well as other uses of petroleum (e.g., home
heating oil). It cannot be broken out by transportation versus other uses as there are difficulties associated with tracking which products from
petroleum refiners are used for transportation fuel and which were not. We know that although refiners make these designations for the products
leaving their gate, the actual end use can and does change in the market. For example, designated transportation fuel can always be used as home
heating oil.
\10\ Emissions coverage from the combustion of fossil fuels upstream represents CO2 emissions only. It is not possible to estimate nitrous oxide and
methane emissions without knowing where and how the fuel is combusted. In the case of downstream emissions from stationary combustion of fossil fuels,
nitrous oxide and methane emissions are included in the emissions coverage estimate. They represent approximately 1 percent of the total emissions.
\11\ EPA estimates that the majority of the costs for manufacturers of vehicles and engines can be attributed to the reporting requirements for non-CO2
gases.
C. What are the economic impacts of the proposed rule?
EPA prepared an economic impact analysis to evaluate the impacts of
the proposed rule on affected industries and economic sectors. In
evaluating the various reporting options considered, EPA conducted a
cost-effectiveness analysis, comparing the cost per metric ton of GHG
emissions across reporting options. EPA used this information to
identify the preferred options described in today's proposed rule.
To estimate the economic impacts of the proposed rule, EPA first
conducted a screening assessment, comparing the estimated total
annualized compliance costs by industry, where industry is defined in
terms of North American Industry Classification System (NAICS) code,
with industry average revenues. Overall national costs of the rule are
significant because there are a large number of affected entities, but
per-entity costs are low. Average cost-to-sales ratios for
establishments in affected NAICS codes are uniformly less than 0.8
percent.
These low average cost-to-sales ratios indicate that the proposed
rule is unlikely to result in significant changes in firms' production
decisions or other behavioral changes, and thus unlikely to result in
significant changes in prices or quantities in affected markets. Thus,
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002,
p. 124-125) and used the engineering cost estimates to measure the
social cost of the proposed rule, rather than modeling market responses
and using the resulting measures of social cost. Table VIII-4 of this
preamble summarizes cost-to-sales ratios for affected industries.
Table VIII-4. Estimated Cost-To-Sales Ratios for Affected Entities
----------------------------------------------------------------------------------------------------------------
Average
cost per Average
NAICS NAICS description entity entity cost-
($1,000/ to-sales
entity) ratio \1\
----------------------------------------------------------------------------------------------------------------
211......................................... Oil & gas extraction.................... $23 0.1%
212......................................... Mining (except oil & gas)............... 10 0.1
221......................................... Utilities............................... 1 <0.1
322......................................... Paper mfg............................... 22 0.1
324......................................... Petroleum & coal products mfg........... 16 <0.1
325......................................... Chemical mfg............................ 12 <0.1
327......................................... Nonmetallic mineral product mfg......... 51 0.8
331......................................... Primary metal mfg....................... 112 0.4
334......................................... Computer & electronic product mfg....... 37 0.1
335......................................... Electrical equipment, appliance, & 37 0.2
component mfg.
486......................................... Pipeline transportation................. 12 0.1
562......................................... Waste management & remediation services. 6 0.2
325199...................................... All other basic organic chemical mfg.... 24 <0.1
325311...................................... Nitrogenous fertilizer mfg.............. 19 0.1
327310...................................... Cement mfg.............................. 65 0.2
331112...................................... Electrometallurgical ferroalloy product 28 <0.1
mfg.
3272........................................ Glass & glass product mfg............... 11 0.1
325120...................................... Industrial gas mfg...................... 3 <0.1
331112...................................... Electrometallurgical ferroalloy product 150 0.3
mfg.
3314........................................ Nonferrous metal (except aluminum) 23 0.1
production & processing.
327410...................................... Lime mfg................................ 60 0.4
325311...................................... Nitrogenous fertilizer mfg.............. 20 0.1
324110...................................... Petroleum refineries.................... 19 <0.1
325312...................................... Phosphatic fertilizer mfg............... 60 0.1
322110...................................... Pulp mills.............................. 22 <0.1
324110...................................... Petroleum refineries.................... 24 <0.1
[[Page 16600]]
327910...................................... Abrasive product mfg.................... 11 0.1
3251........................................ Basic chemical mfg...................... 9 <0.1
325188...................................... All other basic inorganic chemical mfg.. 9 <0.1
3314........................................ Nonferrous metal (except aluminum) 19 0.1
production & processing.
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
include initial start-up activities.
D. What are the impacts of the proposed rule on small entities?
As required by the RFA and SBREFA, EPA assessed the potential
impacts of the proposed rule on small entities (small businesses,
governments, and non-profit organizations). (See Section IX.C of this
preamble for definitions of small entities.)
EPA believes the proposed thresholds maximize the rule coverage
with 85 to 90 percent of U.S. GHG emissions reported by approximately
13,205 reporters, while keeping reporting burden to a minimum and
excluding small emitters. Furthermore, many industry stakeholders that
EPA met with expressed support for a 25,000 metric ton CO2e
threshold because it sufficiently captures the majority of GHG
emissions in the U.S., while excluding smaller facilities and sources.
For small facilities that are captured by the rule, EPA has proposed
simplified emission estimation methods where feasible (e.g., stationary
combustion equipment under a certain rating can use a simplified mass
balance approach as opposed to more rigorous direct monitoring) to keep
the burden of reporting as low as possible. For further detail on the
rationale for excluding small entities through threshold selection
please see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046).
EPA conducted a screening assessment comparing compliance costs for
affected industry sectors to industry-specific receipts data for
establishments owned by small businesses. This ratio constitutes a
``sales'' test that computes the annualized compliance costs of this
proposed rule as a percentage of sales and determines whether the ratio
exceeds some level (e.g., 1 percent or 3 percent).\137\ The cost-to-
sales ratios were constructed at the establishment level (average
reporting program costs per establishment/average establishment
receipts) for several business size ranges. This allowed EPA to account
for receipt differences between establishments owned by large and small
businesses and differences in small business definitions across
affected industries. The results of the screening assessment are shown
in Table VIII-5 of this preamble.
---------------------------------------------------------------------------
\137\ EPA's RFA guidance for rule writers suggests the ``sales''
test continues to be the preferred quantitative metric for economic
impact screening analysis.
Table VIII-5. Estimated Cost-To-Sales Ratios by Industry and Enterprise Size a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Owned by enterprises with:
SBA Size Average -----------------------------------------------------------------
standard cost per All 100 to 500 to 750 to 1,000 to
Industry NAICS NAICS description (effective entity enterprises <20 20 to 99 499 749 999 1,499
March 11, ($1,000/ (%) Employees Employees Employees Employees Employees Employees
2008) entity) f (%) (%) (%) (%) (%)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Oil and Gas Extraction....................... 211 Oil & gas extraction............ 500 $23 0.1 1.5 0.1 0.1 0.0 0.0 0.0
Petroleum and Coal Products.................. 212 Mining (except oil & gas)....... 500 10 0.1 0.9 0.2 0.1 0.1 0.1 0.1
SF6 from Electrical Systems.................. 221 Utilities....................... (\b\) 1 0.0 0.1 0.0 0.0 0.0 0.0 0.0
Pulp & Paper Manufacturing................... 322 Paper mfg....................... 500 to 750 22 0.1 1.3 0.3 0.1 0.1 0.0 0.0
Petroleum and Coal Products.................. 324 Petroleum & coal products mfg... (\c\) 16 0.0 0.4 0.1 0.1 0.0 0.1 0.0
Chemical Manufacturing....................... 325 Chemical mfg.................... 500 to 12 0.0 0.6 0.1 0.0 0.0 0.0 0.0
1,000
Cement & Other Mineral Production............ 327 Nonmetallic mineral product mfg. 500 to 51 0.8 4.9 1.0 0.5 0.4 0.6 0.4
1,000
Primary Metal Manufacturing.................. 331 Primary metal mfg............... 500 to 112 0.4 9.1 1.4 0.4 0.2 0.1 0.2
1,000
Computer and Electronic Product Manufacturing 334 Computer & electronic product 500 to 37 0.1 2.9 0.5 0.1 0.1 0.1 0.1
mfg. 1,000
Electrical Equipment, Appliance, and 335 Electrical equipment, appliance, 500 to 37 0.2 2.9 0.5 0.2 0.1 0.1 0.1
Component Manufacturing. & component mfg. 1,000
Oil & Natural Gas Transportation............. 486 Pipeline transportation......... (\d\) 12 0.1 0.1 0.4 0.4 NA NA NA
[[Page 16601]]
Waste Management and Remediation Services.... 562 Waste management & remediation (\e\) 6 0.2 0.9 0.1 0.1 0.1 0.0 0.1
services.
Adipic Acid.................................. 325199 All other basic organic chemical 1,000 24 0.0 0.9 0.3 0.1 NA 0.0 NA
mfg.
Ammonia...................................... 325311 Nitrogenous fertilizer mfg...... 1,000 19 0.1 1.0 0.6 NA NA NA NA
Cement....................................... 327310 Cement mfg...................... 750 65 0.2 2.1 1.6 0.3 NA NA 0.1
Ferroalloys.................................. 331112 Electrometallurgical ferroalloy 750 28 0.0 NA NA NA NA NA NA
product mfg.
Glass........................................ 3272 Glass & glass product mfg....... 500 to 11 0.1 1.7 0.2 0.1 0.0 0.1 0.0
1,000
Hydrogen Production.......................... 325120 Industrial gas mfg.............. 1,000 3 0.0 0.6 0.0 0.1 NA NA NA
Iron and Steel............................... 331112 Electrometallurgical ferroalloy 750 150 0.3 NA NA NA NA NA NA
product mfg.
Lead Production.............................. 3314 Nonferrous metal (except 750 to 23 0.1 1.5 0.2 0.1 NA NA 0.1
aluminum) production & 1,000
processing.
Lime Manufacturing........................... 327410 Lime mfg........................ 500 60 0.4 16.5 1.2 NA NA NA NA
Nitric Acid.................................. 325311 Nitrogenous fertilizer mfg...... 1,000 20 0.1 1.0 0.6 NA NA NA NA
Petrochemical................................ 324110 Petroleum refineries............ (\c\) 19 0.0 0.3 0.0 0.0 0.0 NA NA
Phosphoric Acid.............................. 325312 Phosphatic fertilizer mfg....... 500 60 0.1 10.1 NA NA NA NA NA
Pulp and Paper............................... 322110 Pulp mills...................... 750 22 0.0 1.5 NA NA NA NA NA
Refineries................................... 324110 Petroleum refineries............ (\c\) 24 0.0 0.4 0.0 0.0 0.0 NA NA
Silicon Carbide.............................. 327910 Abrasive product mfg............ 500 11 0.1 0.8 0.2 0.1 NA NA NA
Soda Ash Manufacturing....................... 3251 Basic chemical mfg.............. 500 to 9 0.0 0.3 0.1 0.0 0.0 0.0 0.0
1,000
Titanium Dioxide............................. 325188 All other basic inorganic 1,000 9 0.0 0.7 0.4 0.1 NA NA NA
chemical mfg.
Zinc Production.............................. 3314 Nonferrous metal (except 750 to 19 0.1 1.2 0.1 0.1 NA NA 0.1
aluminum) production & 1,000
processing.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
a The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise and
the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments. Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is consistent with the concept of ultimate parent
company that is typically used for SBREFA screening analyses.
b NAICS codes 221111, 221112, 221113, 221119, 221121, 221122--A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of
electric energy for sale and its total electric output for the preceding fiscal year did not exceed 4 million MW hours.
c 500 to 1,500. For NAICS code 324110--For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more than 125,000 barrels per
calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement
such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona
fide feedstocks.
d NAICS codes 486110 = 1,500 employees; NAICS 486210 = $6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 = $11.5 million annual receipts.
e Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910--Environmental Remediation
Services:
(1) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged primarily in
furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment, site inspection, testing,
remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated materials and security and site
closeouts. If one of such activities accounts for 50 percent or more of a concern's total revenues, employees, or other related factors, the concern's primary industry is that of the
particular industry and not the Environmental Remediation Services Industry.
(2) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated environment and also
the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering), smaller sub-components of NAICS codes
with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as: Heavy Construction; Special Trade Construction;
Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere Classified; Local Trucking Without Storage; Testing Laboratories; and
Commercial, Physical and Biological Research. If any activity in the procurement can be identified with a separate NAICS code, or component of a code with a separate distinct size standard,
and that industry accounts for 50 percent or more of the value of the entire procurement, then the proper size standard is the one for that particular industry, and not the Environmental
Remediation Service size standard.
f Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
NA: Not available. SUSB did not report the data necessary to calculate this ratio.
[[Page 16602]]
EPA was not able to calculate a cost-to-sales ratio for manure
management (NAICS 112) as SUSB (SBA, 2008a) data does not provide
establishment information for agricultural NAICS codes (e.g., NAICS 112
which covers manure management). EPA estimates that the total first
year reporting costs for the entire manure management industry to be
$0.2 million with an average cost per ton reported of $0.14.
As shown, the cost-to-sales ratios are less than 1 percent for
establishments owned by small businesses that EPA considers most likely
to be covered by the reporting program (e.g. establishments owned by
businesses with 20 or more employees).
EPA acknowledges that several enterprise categories have ratios
that exceed this threshold (e.g., enterprise with one to 20 employees).
EPA took a conservative approach with the model entity analysis.
Although the appropriate SBA size definition should be applied at the
parent company (enterprise) level, data limitations allowed us only to
compute and compare ratios for a model establishment within several
enterprise size ranges. To assess the likelihood that these small
businesses would be covered by the rule, we performed several case
studies for manufacturing industries where the cost-to-receipt ratio
exceeded 1 percent. For each industry, we used and applied emission
data from a recent study examining emission thresholds.\138\ This study
provides industry-average CO2 emission rates (e.g., tons per
employee) for these manufacturing industries.
---------------------------------------------------------------------------
\138\ Nicholas Institute for Environmental Policy Solutions,
Duke University. 2008. Size Thresholds for Greenhouse Gas
Regulation: Who Would be Affected by a 10,000-ton CO2
Emissions Rule? Available at: http://www.nicholas.duke.edu/institute/10Kton.pdf.
---------------------------------------------------------------------------
The case studies showed two industries (cement and lime
manufacturing) where emission rates suggest small businesses of this
employment size could potentially be covered by the rule. As a result,
EPA examined corporate structures and ultimate parent companies were
identified using industry surveys and the latest private databases such
as Dun & Bradstreet. The results of this analysis show cost to sales
ratios below 1 percent.
For the other enterprise categories identified with ratios between
1 percent and 3 percent EPA examined industry specific bottom up
databases and previous industry specific studies to ensure that no
entities with less than 20 employees are captured under the rule.
Although this rule would not have a significant economic impact on
a substantial number of small entities, the Agency nonetheless tried to
reduce the impact of this rule on small entities, including seeking
input from a wide range of private- and public-sector stakeholders.
When developing the proposed rule, the Agency took special steps to
ensure that the burdens imposed on small entities were minimal. The
Agency conducted several meetings with industry trade associations to
discuss regulatory options and the corresponding burden on industry,
such as recordkeeping and reporting. The Agency investigated
alternative thresholds and analyzed the marginal costs associated with
requiring smaller entities with lower emissions to report. The Agency
also recommended a hybrid method for reporting, which provides
flexibility to entities and helps minimize reporting costs.
Additional analysis for a model small government also showed that
the annualized reporting program costs were less than 1 percent of
revenue. These impacts are likely representative of ratios in
industries where data limitations do not allow EPA to compute sales
tests (e.g., general stationary combustion and manure management).
Potential impacts of the proposed rule on small governments were
assessed separately from impacts on Federal Agencies. Small governments
and small non-profit organizations may be affected if they own affected
stationary combustion sources, landfills, or natural gas suppliers.
However, the estimated costs under the proposed rule are estimated to
be small enough that no small government or small non-profit is
estimated to incur significant impacts. For example, from the 2002
Census (in $2006), revenues for small governments (counties and
municipalities) with populations fewer than 10,000 are $3 million, and
revenues for local governments with populations less than 50,000 is $7
million. As an upper bound estimate, summing typical per-respondent
costs of combustion plus landfills plus natural gas suppliers yields a
cost of approximately $17,047 per local government. Thus, for the
smallest group of local governments (<10,000 people), cost-to-revenue
ratio would be 0.8 percent. For the larger group of governments less
than 50,000, the cost-to-revenue ratio is 0.3 percent.
E. What are the benefits of the proposed rule for society?
EPA examined the potential benefits of the GHG reporting rule.
Because the benefits of a reporting system are based on their relevance
to policy making, transparency issues, and market efficiency, and
therefore benefits would be very difficult to quantify and monetize.
Instead of a quantitative analysis of the benefits, EPA conducted a
systematic literature review of existing studies including government,
consulting, and scholarly reports.
A mandatory reporting system would benefit the public by increased
transparency of facility emissions data. Transparent, public data on
emissions allows for accountability of polluters to the public
stakeholders who bear the cost of the pollution. Citizens, community
groups, and labor unions have made use of data from Pollutant Release
and Transfer Registers to negotiate directly with polluters to lower
emissions, circumventing greater government regulation. Publicly
available emissions data also would allow individuals to alter their
consumption habits based on the GHG emissions of producers.
The greatest benefit of mandatory reporting of industry GHG
emissions to government would be realized in developing future GHG
policies. For example, in the EU's Emissions Trading System, a lack of
accurate monitoring at the facility level before establishing
CO2 allowance permits resulted in allocation of permits for
emissions levels an average of 15 percent above actual levels in every
country except the United Kingdom.
Benefits to industry of GHG emissions monitoring include the value
of having independent, verifiable data to present to the public to
demonstrate appropriate environmental stewardship. Such monitoring
allows for inclusion of standardized GHG data into environmental
management systems, providing the necessary information to achieve and
disseminate their environmental achievements.
Standardization would also be a benefit to industry, once
facilities invest in the institutional knowledge and systems to report
emissions, the cost of monitoring should fall and the accuracy of the
accounting should improve. A standardized reporting program would also
allow for facilities to benchmark themselves against similar facilities
to understand better their relative standing within their industry.
IX. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
Under section 3(f)(1) of EO 12866 (58 FR 51735, October 4, 1993),
this action is an ``economically significant
[[Page 16603]]
regulatory action'' because it is likely to have an annual effect on
the economy of $100 million or more. Accordingly, EPA submitted this
action to the OMB for review under EO 12866 and any changes made in
response to OMB recommendations have been documented in the docket for
this action.
In addition, EPA prepared an analysis of the potential costs and
benefits associated with this action. A copy of the analysis is
available in Docket No. EPA-HQ-OAR-2008-0508-002 and is briefly
summarized in Section VIII of this preamble.
B. Paperwork Reduction Act
The information collection requirements in this proposed rule have
been submitted for approval to the OMB under the Paperwork Reduction
Act, 44 U.S.C. 3501 et seq. The ICR document prepared by EPA has been
assigned EPA ICR number 2300.01.
EPA plans to collect complete and accurate economy-wide data on
facility-level greenhouse gas emissions. Accurate and timely
information on greenhouse gas emissions is essential for informing
future climate change policy decisions. Through data collected under
this rule, EPA will gain a better understanding of the relative
emissions of specific industries, and the distribution of emissions
from individual facilities within those industries. The facility-
specific data will also improve our understanding of the factors that
influence greenhouse gas emission rates and actions that facilities are
already taking to reduce emissions. Additionally, EPA will be able to
track the trend of emissions from industries and facilities within
industries over time, particularly in response to policies and
potential regulations. The data collected by this rule will improve
EPA's ability to formulate climate change policy options and to assess
which industries would be affected, and how these industries would be
affected by the options.
This information collection is mandatory and will be carried out
under CAA sections 114 and 208. Information identified and marked as
CBI will not be disclosed except in accordance with procedures set
forth in 40 CFR part 2. However, emissions information collected under
CAA sections 114 and 208 cannot be claimed as CBI and will be made
public.
The projected cost and hour burden for non-federal respondents is
$143 million and 1.63 million hours per year. The estimated average
burden per response is 2 hours; the proposed frequency of response is
annual for all respondents that must comply with the proposed rule's
reporting requirements, except for electricity generating units that
are already required to report quarterly under 40 CFR part 75 (EPA Acid
Rain Program); and the estimated average number of likely respondents
per year is 18,775. The cost burden to respondents resulting from the
collection of information includes the total capital cost annualized
over the equipment's expected useful life (averaging $20.7 million), a
total operation and maintenance component (averaging $22.4 million per
year), and a labor cost component (averaging $100.0 million per year).
Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from
those shown elsewhere in the RIA for several reasons:
ICR costs represent the average cost over the first three
years of the rule, but costs are reported elsewhere in the RIA for the
first year of the rule and for subsequent years of the rule;
The costs of reporting electricity purchases have been
excluded from the ICR, but are still reported in the RIA, although
electricity use reporting has been removed from the proposed rule and
EPA is soliciting comment on it (see Section 4.2.2, pg 4-18); and
The first-year costs of coverage determination, estimated
to be $867.60 per facility for approximately 16,800 facilities that
ultimately determine they do not have to report, are included in the
ICR but not in the RIA (see Section 4.2.2, pg 4-18). These costs,
averaged over 3 years, are $4.87 million incurred by an average of
5,613 respondents per year.
An agency may not conduct or sponsor, and a person is not required
to respond to, a collection of information unless it displays a
currently valid OMB control number. The OMB control numbers for EPA's
regulations in 40 CFR are listed in 40 CFR part 9. To comment on the
Agency's need for this information, the accuracy of the provided burden
estimates, and any suggested methods for minimizing respondent burden,
EPA has established a public docket for this rule. Submit any comments
related to the ICR to EPA and OMB. See ADDRESSES section at the
beginning of this notice for where to submit comments to EPA. Send
comments to OMB at the Office of Information and Regulatory Affairs,
Office of Management and Budget, 725 17th Street, NW., Washington, DC
20503, Attention: Desk Office for EPA. Since OMB is required to make a
decision concerning the ICR between 30 and 60 days after April 10,
2009, a comment to OMB is best assured of having its full effect if OMB
receives it by May 11, 2009. The final rule will respond to any OMB or
public comments on the information collection requirements contained in
this proposal.
C. Regulatory Flexibility Act (RFA)
The RFA generally requires an agency to prepare a regulatory
flexibility analysis of any rule subject to notice and comment
rulemaking requirements under the Administrative Procedure Act or any
other statute unless the agency certifies that the rule will not have a
significant economic impact on a substantial number of small entities.
Small entities include small businesses, small organizations, and small
governmental jurisdictions.
For purposes of assessing the impacts of today's rule on small
entities, small entity is defined as: (1) A small business as defined
by the Small Business Administration's regulations at 13 CFR 121.201;
(2) a small governmental jurisdiction that is a government of a city,
county, town, school district or special district with a population of
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not
dominant in its field.
After considering the economic impacts of today's proposed rule on
small entities, I certify that this action will not have a significant
economic impact on a substantial number of small entities. The small
entities directly regulated by this proposed rule include small
businesses across all sectors encompassed by the rule, small
governmental jurisdictions and small non-profits. We have determined
that some small businesses will be affected because their production
processes emit GHGs that must be reported, or because they have
stationary combustion units onsite that emit GHGs that must be
reported. Small governments and small non-profits are generally
affected because they have regulated landfills or stationary combustion
units onsite, or because they own a LDC.
For affected small entities, EPA conducted a screening assessment
comparing compliance costs for affected industry sectors to industry-
specific data on revenues for small businesses. This ratio constitutes
a ``sales'' test that computes the annualized compliance costs of this
proposed rule as a percentage of sales and determines whether the ratio
exceeds some level (e.g., 1 percent or 3 percent). The cost-to-sales
ratios were constructed at the establishment level (average compliance
cost for the establishment/average establishment revenues). As shown in
Table VIII-5 of this preamble, the cost-
[[Page 16604]]
to-sales ratios are less than 1 percent for establishments owned by
small businesses that EPA considers most likely to be covered by the
reporting program.\139\
---------------------------------------------------------------------------
\139\ U.S. Small Business Administration (SBA). 2008. Firm Size
Data from the Statistics of U.S. Businesses: U.S. Detail Employment
Sizes: 2002. http://www.census.gov/csd/susb/download_susb02.htm.
---------------------------------------------------------------------------
The screening analysis thus indicates that the proposed rule will
not have a significant economic impact on a substantial number of small
entities. See Table VIII-4 of this preamble for sector-specific
results. The screening assessment for small governments compared the
sum of average costs of compliance for combustion, local distribution
companies, and landfills to average revenues for small governments.
Even for a small government owning all three source types, the costs
constitute less than 1 percent of average revenues for the smallest
category of governments (those with fewer than 10,000 people).
Although this proposed rule will not have a significant economic
impact on a substantial number of small entities, EPA nonetheless took
several steps to reduce the impact of this rule on small entities. For
example, EPA determined appropriate thresholds that reduce the number
of small businesses reporting. In addition, EPA is not requiring
facilities to install CEMS if they do not already have them. Facilities
without CEMS can calculate emissions using readily available data or
data that are less expensive to collect such as process data or
material consumption data. For some source categories, EPA developed
tiered methods that are simpler and less burdensome. Also, EPA is
requiring annual instead of more frequent reporting.
Through comprehensive outreach activities, EPA held approximately
100 meetings and/or conference calls with representatives of the
primary audience groups, including numerous trade associations and
industries that include small business members. EPA's outreach
activities are documented in the memorandum, ``Summary of EPA Outreach
Activities for Developing the Greenhouse Gas Reporting Rule,'' located
in Docket No. EPA-HQ-OAR-2008-0508-055. EPA maintains an ``open door''
policy for stakeholders to provide input on key issues and to help
inform EPA's understanding of issues, including thresholds for
reporting and greenhouse gas calculation and reporting methodologies.
EPA continues to be interested in the potential impacts of the
proposed rule on small entities and welcomes comments on issues related
to such impacts.
D. Unfunded Mandates Reform Act (UMRA)
Title II of the UMRA of 1995 (UMRA), 2 U.S.C. 1531-1538, requires
Federal agencies, unless otherwise prohibited by law, to assess the
effects of their regulatory actions on State, local, and Tribal
governments and the private sector.
EPA has developed this regulation under authority of CAA sections
114 and 208. The required activities under this Federal mandate include
monitoring, recordkeeping, and reporting of GHG emissions from multiple
source categories (e.g., combustion, process, biologic and fugitive).
This rule contains a Federal mandate that may result in expenditures of
$100 million for the private sector in any one year. As described
below, we have determined that the expenditures for State, local, and
Tribal governments, in the aggregate, will be approximately $14.1
million per year, based on average costs over the first three years of
the rule. Accordingly, EPA has prepared under section 202 of the UMRA a
written statement which is summarized below.
Consistent with the intergovernmental consultation provisions of
section 204 of the UMRA, EPA initiated an outreach effort with the
governmental entities affected by this rule including State, local, and
Tribal officials. EPA maintained an ``open door'' policy for
stakeholders to provide input on key issues and to help inform EPA's
understanding of issues, including impacts to State, local and Tribal
governments. The outreach audience included State environmental
protection agencies, regional and Tribal air pollution control
agencies, and other State and local government organizations. EPA
contacted several States and State and regional organizations already
involved in greenhouse gas emissions reporting. EPA also conducted
several conference calls with Tribal organizations. For example, EPA
staff provided information to tribes through conference calls with
multiple Tribal working groups and organizations at EPA and through
individual calls with two Tribal board members of TRI. In addition, EPA
held meeting and conference calls with groups such as TRI, NACAA, ECOS,
and with State members of RGGI, the Midwestern GHG Reduction Accord,
and WCI. See the ``Summary of EPA Outreach Activities for Developing
the Greenhouse Gas Reporting Rule,'' in Docket No. EPA-HQ-OAR-2008-
0508-055 for a complete list of organizations and groups that EPA
contacted.
Consistent with section 205 of the UMRA, EPA has identified and
considered a reasonable number of regulatory alternatives. EPA
carefully examined regulatory alternatives, and selected the lowest
cost/least burdensome alternative that EPA deems adequate to address
Congressional concerns and to provide a consistent, comprehensive
source of information about emissions of GHGs. EPA has considered the
costs and benefits of the proposed GHG reporting rule, and has
concluded that the costs will fall mainly on the private sector
(approximately $131 million), with some costs incurred by State, local,
and Tribal governments that must report their emissions (less than
$12.4 million) that own and operate stationary combustion units,
landfills, or natural gas local distribution companies (LDCs). EPA
estimates that an additional 1,979 facilities owned by state, local, or
tribal governments will incur approximately $1.7 million in costs
during the first year of the rule to make a reporting determination and
subsequently determine that their emissions are below the threshold and
thus, they are not required to report their emissions. Furthermore, we
think it is unlikely that State, local and Tribal governments would
begin operating large industrial facilities, similar to those affected
by this rulemaking operated by the private sector.
Initially, EPA estimates that costs of complying with the proposed
rule will be widely dispersed throughout many sectors of the economy.
Although EPA acknowledges that over time changes in the patterns of
economic activity may mean that GHG generation and thus reporting costs
will change, data are inadequate for projecting these changes. Thus,
EPA assumes that costs averaged over the first three years of the
program are typical of ongoing costs of compliance. EPA estimates that
future compliance costs will total approximately $145 million per year.
EPA examined the distribution of these costs between private owners and
State, local, and Tribal governments owning GHG emitters. In addition,
EPA examined, within the private sector, the impacts on various
industries. In general, estimated cost per entity represents less than
0.1% of company sales in affected industries. These costs are broadly
distributed to a variety of economic sectors and represent
approximately 0.001 percent of 2007 Gross Domestic Product; overall,
EPA does not believe the proposed rule will have a significant
macroeconomic
[[Page 16605]]
impact on the national economy. Therefore, this rule is not subject to
the requirements of section 203 of UMRA because it contains no
regulatory requirements that might significantly or uniquely affect
small governments.
EPA does not anticipate that substantial numbers of either public
or private sector entities will incur significant economic impacts as a
result of this proposed rulemaking. EPA further expects that benefits
of the proposed rule will include more and better information for EPA
and the private sector about emissions of GHGs. This improved
information would enhance EPA's ability to develop sound future climate
policies, and may encourage GHG emitters to develop voluntary plans to
reduce their emissions.
This regulation applies directly to facilities that supply fuel or
chemicals that when used emit greenhouse gases, and to facilities that
directly emit greenhouses gases. It does not apply to governmental
entities unless the government entity owns a facility that directly
emits greenhouse gases above threshold levels such as a landfill or
large stationary combustion source. In addition, this rule does not
impose any implementation responsibilities on State, local or Tribal
governments and it is not expected to increase the cost of existing
regulatory programs managed by those governments. Thus, the impact on
governments affected by the rule is expected to be minimal.
E. Executive Order 13132: Federalism
EO 13132, entitled ``Federalism'' (64 FR 43255, August 10, 1999),
requires EPA to develop an accountable process to ensure ``meaningful
and timely input by State and local officials in the development of
regulatory policies that have Federalism implications.'' ``Policies
that have Federalism implications'' is defined in the EO to include
regulations that have ``substantial direct effects on the States, on
the relationship between the national government and the States, or on
the distribution of power and responsibilities among the various levels
of government.''
This proposed rule does not have Federalism implications. It will
not have substantial direct effects on the States, on the relationship
between the national government and the States, or on the distribution
of power and responsibilities among the various levels of government,
as specified in EO 13132. However, for a more detailed discussion about
how this proposal relates to existing State programs, please see
Section II of this preamble.
This regulation applies directly to facilities that supply fuel or
chemicals that when used emit greenhouse gases or facilities that
directly emit greenhouses gases. It does not apply to governmental
entities unless the government entity owns a facility that directly
emits greenhouse gases above threshold levels such as a landfill or
large stationary combustion source, so relatively few government
facilities would be affected. This regulation also does not limit the
power of States or localities to collect GHG data and/or regulate GHG
emissions. Thus, EO 13132 does not apply to this rule.
In the spirit of Executive Order 13132, and consistent with EPA
policy to promote communications between EPA and State and local
governments, EPA specifically solicits comments on this proposed rule
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This proposed rule is not expected to have Tribal implications, as
specified in EO 13175 (65 FR 67249, November 9, 2000). This regulation
applies directly to facilities that supply fuel or chemicals that when
used emit greenhouse gases or facilities that directly emit greenhouses
gases. Facilities expected to be affected by the proposed rule are not
expected to be owned by Tribal governments. Thus, Executive Order 13175
does not apply to this proposed rule.
Although EO 13175 does not apply to this proposed rule, EPA sought
opportunities to provide information to Tribal governments and
representatives during development of the rule. In consultation with
EPA's American Indian Environment Office, EPA's outreach plan included
tribes. EPA conducted several conference calls with Tribal
organizations. For example, EPA staff provided information to tribes
through conference calls with multiple Indian working groups and
organizations at EPA that interact with tribes and through individual
calls with two Tribal board members of TCR. In addition, EPA prepared a
short article on the GHG reporting rule that appeared on the front page
a Tribal newsletter--Tribal Air News--that was distributed to EPA/
OAQPS's network of Tribal organizations. EPA gave a presentation on
various climate efforts, including the mandatory reporting rule, at the
National Tribal Conference on Environmental Management on June 24-26,
2008. In addition, EPA had copies of a short information sheet
distributed at a meeting of the National Tribal Caucus. See the
``Summary of EPA Outreach Activities for Developing the GHG reporting
rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 for a complete list of
Tribal contacts.
EPA specifically solicits additional comment on this proposed rule
from Tribal officials.
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets EO 13045 (62 FR 19885, April 23, 1997) as applying
only to those regulatory actions that concern health or safety risks,
such that the analysis required under section 5-501 of the EO has the
potential to influence the regulation. This action is not subject to EO
13045 because it does not establish an environmental standard intended
to mitigate health or safety risks.
H. Executive Order 13211: Actions That Significantly Affect Energy
Supply, Distribution, or Use
This proposed rule is not a ``significant energy action'' as
defined in EO 13211 (66 FR 28355, May 22, 2001) because it is not
likely to have a significant adverse effect on the supply,
distribution, or use of energy. Further, we have concluded that this
rule is not likely to have any adverse energy effects. This proposal
relates to monitoring, reporting and recordkeeping at facilities that
supply fuel or chemicals that when used emit greenhouse gases or
facilities that directly emit greenhouses gases and does not impact
energy supply, distribution or use. Therefore, we conclude that this
rule is not likely to have any adverse effects on energy supply,
distribution, or use.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs
EPA to use voluntary consensus standards in its regulatory activities
unless to do so would be inconsistent with applicable law or otherwise
impractical. Voluntary consensus standards are technical standards
(e.g., materials specifications, test methods, sampling procedures, and
business practices) that are developed or adopted by voluntary
consensus standards bodies. NTTAA directs EPA to provide Congress,
through OMB, explanations when the Agency decides not to use available
and applicable voluntary consensus standards.
This proposed rulemaking involves technical standards. EPA proposes
to use more than 40 voluntary consensus
[[Page 16606]]
standards from six different voluntary consensus standards bodies:
ASTM, ASME, ISO, Gas Processors Association, American Gas Association,
and American Petroleum Institute. These voluntary consensus standards
will help facilities monitor, report, and keep records of greenhouse
gas emissions. No new test methods were developed for this proposed
rule. Instead, from existing rules for source categories and voluntary
greenhouse gas programs, EPA identified existing means of monitoring,
reporting, and keeping records of greenhouse gas emissions. The
existing methods (voluntary consensus standards) include a broad range
of measurement techniques, including many for combustion sources such
as methods to analyze fuel and measure its heating value; methods to
measure gas or liquid flow; and methods to gauge and measure petroleum
and petroleum products. The test methods are incorporated by reference
into the proposed rule and are available as specified in proposed 40
CFR 98.7.
By incorporating voluntary consensus standards into this proposed
rule, EPA is both meeting the requirements of the NTTAA and presenting
multiple options and flexibility for measuring greenhouse gas
emissions.
EPA welcomes comments on this aspect of the proposed rulemaking
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such
standards should be used in this regulation.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
EO 12898 (59 FR 7629, February 16, 1994) establishes Federal
executive policy on environmental justice. Its main provision directs
Federal agencies, to the greatest extent practicable and permitted by
law, to make environmental justice part of their mission by identifying
and addressing, as appropriate, disproportionately high and adverse
human health or environmental effects of their programs, policies, and
activities on minority populations and low-income populations in the
U.S.
EPA has determined that this proposed rule will not have
disproportionately high and adverse human health or environmental
effects on minority or low-income populations because it does not
affect the level of protection provided to human health or the
environment. This proposed rule does not affect the level of protection
provided to human health or the environment because it is a rule
addressing information collection and reporting procedures.
List of Subjects
40 CFR Part 86
Environmental protection, Administrative practice and procedure,
Air pollution control, Reporting and recordkeeping requirements, Motor
vehicle pollution.
40 CFR Part 87
Environmental protection, Air pollution control, Aircraft,
Incorporation by reference.
40 CFR Part 89
Environmental protection, Administrative practice and procedure,
Confidential business information, Imports, Labeling, Motor vehicle
pollution, Reporting and recordkeeping requirements, Research, Vessels,
Warranty.
40 CFR Part 90
Environmental protection, Administrative practice and procedure,
Confidential business information, Imports, Labeling, Reporting and
recordkeeping requirements, Research, Warranty.
40 CFR Part 94
Environmental protection, Administrative practice and procedure,
Air pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and
recordkeeping requirements, Warranties.
40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.
40 CFR Part 600
Administrative practice and procedure, Electric power, Fuel
economy, Incorporation by reference, Labeling, Reporting and
recordkeeping requirements.
40 CFR Part 1033
Environmental protection, Administrative practice and procedure,
Confidential business information, Incorporation by reference,
Labeling, Penalties, Railroads, Reporting and recordkeeping
requirements.
40 CFR Part 1039
Environmental protection, Administrative practice and procedure,
Air pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Reporting and
recordkeeping requirements, Warranties.
40 CFR Part 1042
Environmental protection, Administrative practice and procedure,
Air pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and
recordkeeping requirements, Warranties.
40 CFR Parts 1045, 1048, 1051, and 1054
Environmental protection, Administrative practice and procedure,
Air pollution control, Confidential business information, Imports,
Incorporation by reference, Labeling, Penalties, Reporting and
recordkeeping requirements, Warranties.
40 CFR Part 1065
Environmental protection, Administrative practice and procedure,
Incorporation by reference, Reporting and recordkeeping requirements,
Research.
Dated: March 10, 2009.
Lisa P. Jackson,
Administrator.
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is proposed to be amended as follows:
PART 86--[AMENDED]
1. The authority citation for part 86 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
2. Section 86.007-23 is amended by adding paragraph (n) to read as
follows:
Sec. 86.007-23 Required data.
* * * * *
(n) Starting in the 2011 model year for heavy-duty engines, measure
CO2, N2O, and CH4 with each low-hour
certification test using the procedures specified in 40 CFR part 1065.
Report these values in your application for certification. These
measurements are not required for NTE testing. Use the same units and
calculations as for your other results to report a single weighted
value for CO2, N2O, and CH4 for each
test. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
[[Page 16607]]
(3) Round CH4 to the nearest 0.001g/kW-hr.
3. Section 86.078-3 is amended by removing the paragraph (a)
designation and adding the abbreviations CH4 and
N2O in alphanumeric order to read as follows:
Sec. 86.078-3 Abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
Subpart B--[Amended]
4. A new Sec. 86.165-11 is added to read as follows:
Sec. 86.165-11 Air Conditioning Idle Test Procedure.
(a) Applicability. This section describes procedures for
determining air conditioning-related CO2 emissions from 2012
and later model year light-duty vehicles, light-duty trucks, and
medium-duty passenger vehicles.
(b) Overview. The test consists of a brief period to stabilize the
vehicle at idle, followed by a ten-minute period of idle when
CO2 emissions are measured without any climate control
systems operating; the test concludes with a ten-minute period when
CO2 emissions are measured with the air conditioning system
operating. This test is designed to determine the air conditioning-
related CO2 emission value, in grams per minute per cubic
foot of interior volume. If engine stalling occurs during cycle
operation, follow the provisions of Sec. 86.136-90 to restart the
test. Measurement instruments must meet the specifications described in
40 CFR part 1065, subparts C and D.
(c) Test sequence. Before testing, precondition the vehicle as
described in Sec. 86.132, then allow the vehicle to idle for not less
than 1 minute and not more than 5 minutes.
(1) Connect the vehicle exhaust system to the raw sampling location
or dilution stage according to 40 CFR 1065.130. For dilution systems,
dilute the exhaust as described in 40 CFR 1065.140. Continuous sampling
systems must meet the specifications of 40 CFR 1065.145.
(2) Test the vehicle in a fully warmed-up condition. If the vehicle
has soaked for two hours or less since the last exhaust test element,
preconditioning may consist of a 505, 866, highway, US06, or SC03 test
cycle. For longer soak periods, precondition the vehicle using one full
Urban Dynamometer Driving Schedule.
(3) Immediately after the preconditioning described in paragraph
(c)(1) of this section, turn off any cooling fans, if present, close
the vehicle's hood, fully close all the vehicle's windows, ensure that
all the vehicle's climate control systems are set to full off, start
the CO2 sampling system, and then idle the vehicle for not
less than 1 minute and not more than 5 minutes to achieve normal and
stable idle operation.
(4) Measure and record the continuous CO2 concentration
for 10.0 minutes. Measure the CO2 concentration continuously
using raw or dilute sampling procedures. Multiply this concentration by
the continuous (raw or dilute) flow rate at the emission sampling
location to determine the CO2 flow rate. Calculate the
constituent's cumulative flow rate continuously over the test interval.
This cumulative value is the total mass of the emitted constituent.
(5) Within 60 seconds after completing the measurement described in
paragraph (c)(4) of this section, turn on the vehicle's air
conditioning system. Set automatic systems to a temperature 9 [deg]F (5
[deg]C) below the ambient temperature of the test cell. Set manual
systems to maximum cooling with recirculation turned off. Continue
idling the vehicle while measuring and recording the continuous
CO2 concentration for 10.0 minutes as described in paragraph
(c)(4) of this section.
(d) Calculations. (1) For the measurement with no air conditioning,
calculate the CO2 emissions (in grams per minute) by
dividing the total mass of CO2 from paragraph (c)(4) of this
section by 10.0.
(2) For the measurement with air conditioning in operation,
calculate the CO2 emissions (in grams per minute) by
dividing the total mass of CO2 from paragraph (c)(5) of this
section by 10.0.
(3) Calculate the increased CO2 emissions due to air
conditioning (in grams per minute) by subtracting the results of
paragraph (d)(1) of this section from the results of paragraph (d)(2)
of this section.
(4) Divide the value from paragraph (d)(3) of this section by the
interior volume of the vehicle to determine the increase in
CO2 emissions in grams per minute per cubic foot.
(e) Reporting. Include the value calculated in paragraph (d)(4) of
this section in your application for certification.
Subpart E--[Amended]
5. Section 86.403-78 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 86.403-78 Abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
6. Section 86.431-78 is amended by adding paragraph (e) to read as
follows:
Sec. 86.431-78 Data submission.
* * * * *
(e) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each zero kilometer
certification test (if one is conducted) and with each test conducted
at the applicable minimum test distance as defined in Sec. 86.427-78.
Use the procedures specified in 40 CFR part 1065 as needed to measure
N2O, and CH4. Report these values in your
application for certification. Small-volume manufacturers (as defined
in Sec. 86.410-2006(e)) may omit this requirement. Use the same
measurement methods as for your other results to report a single value
for CO2, N2O, and CH4. Round the final
values as follows:
(1) Round CO2 to the nearest 1 g/km.
(2) Round N2O to the nearest 0.001 g/km.
(3) Round CH4 to the nearest 0.001g/km.
Subpart S--[Amended]
7. Section 86.1804-01 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 86.1804-01 Acronyms and abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
8. Section 86.1843-01 is amended by adding paragraph (i) to read as
follows:
Sec. 86.1843-01 General information requirements.
* * * * *
(i) Air conditioning leakage reporting. Starting in the 2011 model
year, the manufacturer shall calculate and report a value for the
annual leakage of refrigerant emissions from the air conditioning
system for each model type as described in 40 CFR 1064.201. The
manufacturer shall also report the type of refrigerant and the
refrigerant capacity for each air conditioning
[[Page 16608]]
system for each model type. The manufacturer shall calculate and report
these items for each combination of vehicle model type (as defined in
40 CFR 600.002) and air conditioning system produced. However,
calculation and reporting of these items for multiple air conditioning
systems for a given model type is not necessary if air conditioning
systems are identical with respect to the characteristics identified in
paragraphs (i)(1) through (8) of this section and they meet the
quantitative criteria identified in paragraph (i)(9) of this section.
Consider all the following criteria to determine whether to calculate
separate leakage rates for different air conditioning systems.
(1) Compressor type (e.g., belt driven or electric).
(2) Number and type of rigid pipes and method of connecting
sections of rigid pipes.
(3) Number and type of flexible hose and method of connecting
sections of flexible hose. Consider two hoses to be of a different type
if they use different materials or if they have a different
configuration of layers for reducing permeation.
(4) Number of high-side service ports.
(5) Number of low-side service ports.
(6) Number and type of switches, transducers, and expansion valves.
(7) Number and type of refrigerant control devices.
(8) Number and type of heat exchangers, mufflers, receiver/driers,
and accumulators.
(9) The following quantitative criteria (based on nominal values)
define operating characteristics for including air conditioning systems
together:
(i) Refrigerant mass (rated capacity) of larger system divided by
refrigerant mass of smaller system at or below 1.1.
(ii) Total length of rigid pipe in the longer system divided by
total length of rigid pipe in the shorter system at or below 1.1.
(iii) Total length of flexible hose in the longer system divided by
total length of flexible hose in the shorter system at or below 1.1.
9. Section 86.1844-01 is amended by adding paragraph (j) to read as
follows:
Sec. 86.1844-01 Information requirements: Application for
certification and submittal of information upon request.
* * * * *
(j) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each certification test on an
emission data vehicle. Do not apply deterioration factors to the
results. Use the procedures specified in 40 CFR part 1065 as needed to
measure N2O, and CH4. Report these values in your
application for certification. Use the same measurement methods as for
your other results to report a single value for CO2,
N2O, and CH4 for each test. Round the final
values as follows:
(1) Round CO2 to the nearest 1 g/mi.
(2) Round N2O to the nearest 0.001 g/mi.
(3) Round CH4 to the nearest 0.001g/mi.
PART 87--[AMENDED]
10. The authority citation for part 87 is revised to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
11. Section 87.2 is amended by adding the abbreviations
CH4 and CO2 in alphanumeric order to read as
follows:
Sec. 87.2 Acronyms and abbreviations.
* * * * *
CH4 methane.
* * * * *
CO2 carbon dioxide.
* * * * *
12. Section 87.64 is revised to read as follows:
Sec. 87.64 Sampling and analytical procedures for measuring gaseous
exhaust emissions.
(a) The system and procedures for sampling and measurement of
gaseous emissions shall be as specified by Appendices 3 and 5 to ICAO
Annex 16 (incorporated by reference in Sec. 87.8).
(b) Starting in the 2011 model year, measure CH4 with
each certification test. Use good engineering judgment to determine
CH4 emissions using a nonmethane cutter or gas chromatograph
as described in 40 CFR 1065.265 and 1065.267. Report CH4 and
CO2 values along with your emission levels of regulated
pollutants. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kilonewton rO.
(2) Round CH4 to the nearest 0.01g/g/kilonewton rO.
PART 89--[AMENDED]
13. The authority citation for part 89 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
14. Section 89.3 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 89.3 Acronyms and abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
Subpart B--[Amended]
15. Section 89.115 is amended by revising paragraph (d)(9) to read
as follows:
Sec. 89.115 Application for certificate.
* * * * *
(d) * * *
(9) All test data obtained by the manufacturer on each test engine,
including CO2, N2O, and CH4 as
specified in Sec. 89.407(d)(1);
* * * * *
Subpart E--[Amended]
16. Section 89.407 is amended by revising paragraph (d)(1) to read
as follows:
Sec. 89.407 Engine dynamometer test run.
* * * * *
(d) * * *
(1) Measure HC, CO, CO2, and NOX
concentrations in the exhaust sample. Starting in the 2011 model year,
also measure N2O, and CH4 with each low-hour
certification test using the procedures specified in 40 CFR part 1065.
Small-volume engine manufacturers (as defined in 40 CFR 1039.801) may
omit N2O, and CH4 measurements. Use the same
units and modal calculations as for your other results to report a
single weighted value for CO2, N2O, and
CH4. Round the final values as follows:
(i) Round CO2 to the nearest 1 g/kW-hr.
(ii) Round N2O to the nearest 0.001 g/kW-hr.
(iii) Round CH4 to the nearest 0.001g/kW-hr.
* * * * *
PART 90--[AMENDED]
17. The authority citation for part 90 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
18. Section 90.5 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
[[Page 16609]]
Sec. 90.5 Acronyms and abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
Subpart B--[Amended]
19. Section 90.107 is amended by revising paragraph (d)(8) to read
as follows:
Sec. 90.107 Application for certification.
* * * * *
(d) * * *
(8) All test data obtained by the manufacturer on each test engine,
including CO2, N2O, and CH4 as
specified in Sec. 90.409(c)(1);
* * * * *
Subpart E--[Amended]
20. Section 90.409 is amended by revising paragraph (c)(1) to read
as follows:
Sec. 90.409 Engine dynamometer test run.
* * * * *
(c) * * *
(1) Measure HC, CO, CO2, and NOX
concentrations in the exhaust sample. Starting in the 2011 model year,
also measure N2O, and CH4 with each low-hour
certification test using the procedures specified in 40 CFR part 1065.
Small-volume engine manufacturers may omit N2O, and
CH4 measurements. Use the same units and modal calculations
as for your other results to report a single weighted value for
CO2, N2O, and CH4. Round the final
values as follows:
(i) Round CO2 to the nearest 1 g/kW-hr.
(ii) Round N2O to the nearest 0.001 g/kW-hr.
(iii) Round CH4 to the nearest 0.001g/kW-hr.
* * * * *
PART 94--[AMENDED]
21. The authority citation for part 94 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
22. Section 94.3 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 94.3 Abbreviations.
* * * * *
* * * * *
CH4 methane.
* * * * *
N2O nitrous oxide.
* * * * *
Subpart B--[Amended]
22. Section 94.104 is amended by adding paragraph (e) to read as
follows:
Sec. 94.104 Test procedures for Category 2 marine engines.
* * * * *
(e) Measure CO2 as described in 40 CFR 92.129 through
the 2010 model year. Starting in the 2011 model year, measure
CO2, N2O, and CH4 as specified in 40
CFR 1042.235.
Sec. 94.109 [Amended]
23. Section 94.109 is amended by adding paragraph (d) to read as
follows:
Subpart C--[Amended]
24. Section 94.203 is amended by revising paragraph (d)(10) to read
as follows:
Sec. 94.203 Application for certification.
* * * * *
(d) * * *
(10) All test data obtained by the manufacturer on each test
engine, including CO2, N2O, and CH4 as
specified in 40 CFR 89.407(d)(1) for Category 1 engines, Sec.
94.104(e) for Category 2 engines, and Sec. 94.109(d) for Category 3
engines. Small-volume manufacturers may omit the requirement to measure
and report N2O, and CH4.
* * * * *
25. Add part 98 to read as follows:
PART 98--MANDATORY GREENHOUSE GAS REPORTING
Sec.
Subpart A--General Provisions
98.1 Purpose and scope.
98.2 Do I need to report?
98.3 What are the general monitoring, reporting, recordkeeping and
verification requirements of this part?
98.4 Authorization and responsibilities of the designated
representative.
98.5 How do I submit my report?
98.6 What definitions do I need to understand?
98.7 What standardized methods are incorporated by reference into
this part?
98.8 What are the compliance and enforcement provisions of this
part?
Table A-1 of Subpart A--Global Warming Potentials (100-Year Time
Horizon)
Table A-2 of Subpart A--Units of Measure Conversions
Subpart B [Reserved]
Subpart C--General Stationary Fuel Combustion Sources
98.30 Definition of the source category.
98.31 Reporting threshold.
98.32 GHGs to report.
98.33 Calculating GHG emissions.
98.34 Monitoring and QA/QC requirements.
98.35 Procedures for estimating missing data.
98.36 Data reporting requirements.
98.37 Records that must be retained.
98.38 Definitions.
Table C-1 of Subpart C--Default CO2 Emission Factors and
High Heat Values for Various Types of Fuel
Table C-2 of Subpart C--Default CO2 Emission Factors for
the Combustion of Alternative Fuels
Table C-3 of Subpart C--Default CH4 and N2O
Emission Factors for Various Types of Fuel
Subpart D--Electricity Generation
98.40 Definition of the source category.
98.41 Reporting threshold.
98.42 GHGs to report.
98.43 Calculating GHG emissions.
98.44 Monitoring and QA/QC requirements
98.45 Procedures for estimating missing data.
98.46 Data reporting requirements.
98.47 Records that must be retained.
98.48 Definitions.
Subpart E--Adipic Acid Production
98.50 Definition of source category.
98.51 Reporting threshold.
98.52 GHGs to report.
98.53 Calculating GHG emissions.
98.54 Monitoring and QA/QC requirements
98.55 Procedures for estimating missing data.
98.56 Data reporting requirements.
98.57 Records that must be retained.
98.58 Definitions.
Subpart F--Aluminum Production
98.60 Definition of the source category.
98.61 Reporting threshold.
98.62 GHGs to report.
98.63 Calculating GHG emissions.
98.64 Monitoring and QA/QC requirements.
98.65 Procedures for estimating missing data.
98.66 Data reporting requirements.
98.67 Records that must be retained.
98.68 Definitions.
Subpart G--Ammonia Manufacturing
98.70 Definition of source category.
98.71 Reporting threshold.
98.72 GHGs to report.
98.73 Calculating GHG emissions.
98.74 Monitoring and QA/QC requirements.
98.75 Procedures for estimating missing data.
98.76 Data reporting requirements.
98.77 Records that must be retained.
98.78 Definitions.
Subpart H--Cement Production
98.80 Definition of the source category.
[[Page 16610]]
98.81 Reporting threshold.
98.82 GHGs to report.
98.83 Calculating GHG emissions.
98.84 Monitoring and QA/QC requirements.
98.85 Procedures for estimating missing data.
98.86 Data reporting requirements.
98.87 Records that must be retained.
98.88 Definitions.
Subpart I--Electronics Manufacturing
98.90 Definition of the source category.
98.91 Reporting threshold.
98.92 GHGs to report.
98.93 Calculating GHG emissions.
98.94 Monitoring and QA/QC requirements.
98.95 Procedures for estimating missing data.
98.96 Data reporting requirements.
98.97 Records that must be retained.
98.98 Definitions.
Table I-1 of Subpart I--F-GHGs Typically Used by the Electronics
Industry
Table I-2 of Subpart I--Default Emission Factors for Semiconductor
and MEMs Manufacturing
Table I-3 of Subpart I--Default Emission Factors for LCD
Manufacturing
Table I-4 of Subpart I--Default Emission Factors for PV
Manufacturing
Subpart J--Ethanol Production
98.100 Definition of the source category.
98.101 Reporting threshold.
98.102 GHGs to report.
98.103 Definitions.
Subpart K--Ferroalloy Production
98.110 Definition of the source category.
98.111 Reporting threshold.
98.112 GHGs to report.
98.113 Calculating GHG emissions.
98.114 Monitoring and QA/QC requirements.
98.115 Procedures for estimating missing data.
98.116 Data reporting requirements.
98.117 Records that must be retained.
98.118 Definitions.
Table K-1 of Subpart K--Electric Arc Furnace (EAF) CH4
Emission Factors
Subpart L--Fluorinated Greenhouse Gas Production
98.120 Definition of the source category.
98.121 Reporting threshold.
98.122 GHGs to report.
98.123 Calculating GHG emissions.
98.124 Monitoring and QA/QC requirements.
98.125 Procedures for estimating missing data.
98.126 Data reporting requirements.
98.127 Records that must be retained.
98.128 Definitions.
Subpart M--Food Processing
98.130 Definition of the source category.
98.131 Reporting threshold.
98.132 GHGs to report.
98.133 Definitions.
Subpart N--Glass Production
98.140 Definition of the source category.
98.141 Reporting threshold.
98.142 GHGs to report.
98.143 Calculating GHG emissions.
98.144 Monitoring and QA/QC requirements.
98.145 Procedures for estimating missing data.
98.146 Data reporting requirements.
98.147 Records that must be retained.
98.148 Definitions.
Table N-1 of Subpart N--CO2 Emission Factors for
Carbonate-Based Raw Materials
Subpart O--HCFC-22 Production and HFC-23 Destruction
98.150 Definition of the source category.
98.151 Reporting threshold.
98.152 GHGs to report.
98.153 Calculating GHG emissions.
Table O-1 of Subpart O--Emission Factors for Equipment Leaks
98.154 Monitoring and QA/QC requirements.
98.155 Procedures for estimating missing data.
98.156 Data reporting requirements.
98.157 Records that must be retained.
98.158 Definitions.
Subpart P--Hydrogen Production
98.160 Definition of the source category.
98.161 Reporting threshold.
98.162 GHGs to report.
98.163 Calculating GHG emissions.
98.164 Monitoring and QA/QC requirements.
98.165 Procedures for estimating missing data.
98.166 Data reporting requirements.
98.167 Records that must be retained.
98.168 Definitions.
Subpart Q--Iron and Steel Production
98.170 Definition of the source category.
98.171 Reporting threshold.
98.172 GHGs to report.
98.173 Calculating GHG emissions.
98.174 Monitoring and QA/QC requirements.
98.175 Procedures for estimating missing data.
98.176 Data reporting requirements.
98.177 Records that must be retained.
98.178 Definitions.
Subpart R--Lead Production
98.180 Definition of the source category.
98.181 Reporting threshold.
98.182 GHGs to report.
98.184 Monitoring and QA/QC requirements.
98.185 Procedures for estimating missing data.
98.186 Data Reporting Procedures.
98.187 Records that must be retained.
98.188 Definitions.
Subpart S--Lime Manufacturing
98.190 Definition of the source category.
98.191 Reporting threshold.
98.192 GHGs to report.
98.193 Calculating GHG emissions.
98.194 Monitoring and QA/QC requirements.
98.195 Procedures for estimating missing data.
98.196 Data reporting requirements.
98.197 Records that must be retained.
98.198 Definitions.
Table S-1 of Subpart S--Basic Parameters for the Calculation of
Emission Factors for Lime Production
Subpart T--Magnesium Production
98.200 Definition of source category.
98.201 Reporting threshold.
98.202 GHGs to report.
98.203 Calculating GHG emissions.
98.204 Monitoring and QA/QC requirements.
98.205 Procedures for estimating missing data.
98.206 Data reporting requirements.
98.207 Records that must be retained.
98.208 Definitions.
Subpart U--Miscellaneous Uses of Carbonate
98.210 Definition of the source category.
98.211 Reporting threshold.
98.212 GHGs to report.
98.213 Calculating GHG emissions.
98.214 Monitoring and QA/QC requirements.
98.215 Procedures for estimating missing data.
98.216 Data reporting requirements.
98.217 Records that must be retained.
98.218 Definitions.
Table U-1 of Subpart U--CO2 Emission Factors for Common
Carbonates
Subpart V--Nitric Acid Production
98.220 Definition of source category.
98.221 Reporting threshold.
98.222 GHGs to report.
98.223 Calculating GHG emissions.
98.224 Monitoring and QA/QC requirements.
98.225 Procedures for estimating missing data.
98.226 Data reporting requirements.
98.227 Records that must be retained.
98.228 Definitions.
Subpart W--Oil and Natural Gas Systems
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.236 Records that must be retained.
98.237 Definitions.
Subpart X--Petrochemical Production
98.240 Definition of the source category.
98.241 Reporting threshold.
98.242 GHGs to report.
98.243 Calculating GHG emissions.
98.244 Monitoring and QA/QC requirements.
98.245 Procedures for estimating missing data.
98.246 Data reporting requirements.
98.247 Records that must be retained.
98.248 Definitions.
Subpart Y--Petroleum Refineries
98.250 Definition of source category.
98.251 Reporting threshold.
[[Page 16611]]
98.252 GHGs to report.
98.253 Calculating GHG emissions.
98.254 Monitoring and QA/QC requirements.
98.255 Procedures for estimating missing data.
98.256 Data reporting requirements.
98.257 Records that must be retained.
98.258 Definitions.
Subpart Z--Phosphoric Acid Production
98.260 Definition of the source category.
98.261 Reporting threshold.
98.262 GHGs to report.
98.263 Calculating GHG emissions.
98.264 Monitoring and QA/QC requirements.
98.265 Procedures for estimating missing data.
98.266 Data reporting requirements.
98.267 Records that must be retained.
98.268 Definitions.
Subpart AA--Pulp and Paper Manufacturing
98.270 Definition of source category.
98.271 Reporting threshold.
98.272 GHGs to report.
98.273 Calculating GHG emissions.
98.274 Monitoring and QA/QC requirements.
98.275 Procedures for estimating missing data.
98.276 Data reporting requirements.
98.277 Records that must be retained.
98.278 Definitions.
Table AA-1 of Subpart AA--Kraft Pulping Liquor Emissions Factors for
Biomass-Based CO2, CH4, and N2O
Table AA-2 of Subpart AA--Kraft Lime Kiln and Calciner Emissions
Factors for Fossil Fuel-Based CO2, CH4, and
N2O
Subpart BB--Silicon Carbide Production
98.280 Definition of the source category.
98.281 Reporting threshold.
98.283 Calculating GHG emissions.
98.284 Monitoring and QA/QC requirements.
98.285 Procedures for estimating missing data.
98.286 Data reporting requirements.
98.287 Records that must be retained.
98.288 Definitions.
Subpart CC--Soda Ash Manufacturing
98.290 Definition of the source category.
98.291 Reporting threshold.
98.292 GHGs to report.
98.293 Calculating GHG emissions.
98.294 Monitoring and QA/QC requirements.
98.295 Procedures for estimating missing data.
98.296 Data reporting requirements.
98.297 Records that must be retained.
98.298 Definitions.
Subpart DD--Sulfur Hexafluoride (SF6) From Electrical Equipment
98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC requirements.
98.305 Procedures for estimating missing data.
98.306 Data reporting requirements.
98.307 Records that must be retained.
98.308 Definitions.
Subpart EE--Titanium Dioxide Production
98.310 Definition of the source category.
98.311 Reporting threshold.
98.312 GHGs to report.
98.313 Calculating GHG emissions.
98.314 Monitoring and QA/QC requirements.
98.315 Procedures for estimating missing data.
98.316 Data reporting requirements.
98.317 Records that must be retained.
98.318 Definitions.
Subpart FF--Underground Coal Mines
98.320 Definition of the source category.
98.321 Reporting threshold.
98.322 GHGs to report.
98.323 Calculating GHG emissions.
98.324 Monitoring and QA/QC requirements.
98.325 Procedures for estimating missing data.
98.326 Data reporting requirements.
98.327 Records that must be retained.
98.328 Definitions.
Subpart GG--Zinc Production
98.330 Definition of the source category.
98.331 Reporting threshold.
98.332 GHGs to report.
98.333 Calculating GHG emissions.
98.334 Monitoring and QA/QC requirements.
98.335 Procedures for estimating missing data.
98.336 Data reporting requirements.
98.337 Records that must be retained.
98.338 Definitions.
Subpart HH--Landfills
98.340 Definition of the source category.
98.341 Reporting threshold.
98.343 Calculating GHG emissions.
98.344 Monitoring and QA/QC requirements.
98.345 Procedures for estimating missing data.
98.346 Data reporting requirements.
98.347 Records that must be retained.
98.348 Definitions.
Table HH-1 of Subpart HH--Emissions Factors, Oxidation Factors and
Methods
Table HH-2 of Subpart HH--U.S. Per Capita Waste Disposal Rates
Subpart II--Wastewater Treatment
98.350 Definition of source category.
98.351 Reporting threshold.
98.352 GHGs to report.
98.353 Calculating GHG emissions.
98.354 Monitoring and QA/QC requirements.
98.355 Procedures for estimating missing data.
98.356 Data reporting requirements.
98.357 Records that must be retained.
98.358 Definitions.
Table II-1 of Subpart II--Emission Factors
Subpart JJ--Manure Management
98.360 Definition of the source category.
98.361 Reporting threshold.
98.362 GHGs to report.
98.363 Calculating GHG emissions.
98.364 Monitoring and QA/QC requirements.
98.365 Procedures for estimating missing data.
98.366 Data reporting requirements.
98.367 Records that must be retained.
98.368 Definitions.
Table JJ-1 of Subpart JJ--Waste Characteristics Data
Table JJ-2 of Subpart JJ--Methane Conversion Factors
Table JJ-3 of Subpart JJ--Collection Efficiencies of Anaerobic
Digesters
Table JJ-4 of Subpart JJ--Nitrous Oxide Emission Factors (kg
N2O-N/kg Kjdl N)
Subpart KK--Suppliers of Coal
98.370 Definition of the source category.
98.371 Reporting threshold.
98.372 GHGs to report.
98.373 Calculating GHG emissions.
98.374 Monitoring and QA/QC requirements.
98.375 Procedures for estimating missing data.
98.376 Data reporting requirements.
98.377 Records that must be retained.
98.378 Definitions.
Table KK-1 of Subpart KK--Default Carbon Content of Coal for Method
3 (CO2 lbs/MMBtu1)
Subpart LL--Suppliers of Coal-based Liquid Fuels
98.380 Definition of the source category.
98.381 Reporting threshold.
98.382 GHGs to report.
98.383 Calculating GHG emissions.
98.384 Monitoring and QA/QC requirements.
98.385 Procedures for estimating missing data.
98.386 Data reporting requirements.
98.387 Records that must be retained.
98.388 Definitions.
Subpart MM--Suppliers of Petroleum Products
98.390 Definition of the source category.
98.391 Reporting threshold.
98.392 GHGs to report.
98.393 Calculating GHG emissions.
98.394 Monitoring and QA/QC requirements.
98.395 Procedures for estimating missing data.
98.396 Data reporting requirements.
98.397 Records that must be retained.
98.398 Definitions.
Table MM-1 of Subpart MM--Default CO2 Factors for
Petroleum Products 1,2
Table MM-2 of Subpart MM--Default CO2 Factors for Natural
Gas Liquids
Table MM-3 of Subpart MM--Default CO2 Factors for Biomass
Products and Feedstock
Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
98.400 Definition of the source category.
98.401 Reporting threshold.
98.402 GHGs to report.
98.403 Calculating GHG emissions.
98.404 Monitoring and QA/QC requirements.
[[Page 16612]]
98.405 Procedures for estimating missing data.
98.406 Data reporting requirements.
98.407 Records that must be retained.
98.408 Definitions.
Table NN-1 of Subpart NN--Default Factors for Calculation
Methodology 1 of This Subpart
Table NN-2 of Subpart NN--Lookup Default Values for Calculation
Methodology 2 of This Subpart
Subpart OO--Suppliers of Industrial Greenhouse Gases
98.410 Definition of the source category.
98.411 Reporting threshold.
98.412 GHGs to report.
98.413 Calculating GHG emissions.
98.414 Monitoring and QA/QC requirements.
98.415 Procedures for estimating missing data.
98.416 Data reporting requirements.
98.417 Records that must be retained.
98.418 Definitions.
Subpart PP--Suppliers of Carbon Dioxide
98.420 Definition of the source category.
98.421 Reporting threshold.
98.422 GHGs to report.
98.423 Calculating GHG emissions.
98.424 Monitoring and QA/QC requirements.
98.425 Procedures for estimating missing data.
98.426 Data reporting requirements.
98.427 Records that must be retained.
98.428 Definitions.
Authority: 42 U.S.C. 7401, et seq.
Subpart A--General Provisions
Sec. 98.1 Purpose and scope.
(a) This part establishes mandatory greenhouse gas (GHG) emissions
reporting requirements for certain facilities that directly emit GHG as
well as for fossil fuel suppliers and industrial GHG suppliers.
(b) Owners and operators of facilities and suppliers that are
subject to this part must follow the requirements of subpart A and all
applicable subparts of this part. If a conflict exists between a
provision in subpart A and any other applicable subpart, the
requirements of the subparts B through PP of this part shall take
precedence.
Sec. 98.2 Do I need to report?
(a) The GHG emissions reporting requirements, and related
monitoring, recordkeeping, and verification requirements, of this part
apply to the owners and operators of any facility that meets the
requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this
section; and any supplier that meets the requirements of paragraph
(a)(4) of this section:
(1) A facility that contains any of the source categories listed in
this paragraph in any calendar year starting in 2010. For these
facilities, the GHG emission report must cover all sources in any
source category for which calculation methodologies are provided in
subparts B through JJ of this part.
(i) Electricity generating facilities that are subject to the Acid
Rain Program, or that contain electric generating units that
collectively emit 25,000 metric tons CO2e or more per year.
(ii) Adipic acid production.
(iii) Aluminum production.
(iv) Ammonia manufacturing.
(v) Cement production.
(vi) Electronics--Semiconductor, microelectricomechanical system
(MEMS), and liquid crystal display (LCD) manufacturing facilities with
an annual production capacity that exceeds any of the thresholds listed
in this paragraph.
(A) Semiconductors: 1,080 m\2\ silicon.
(B) MEMS: 1,020 m\2\ silicon.
(C) LCD: 235,700 m\2\ LCD.
(vii) Electric power systems that include electrical equipment with
a total nameplate capacity that exceeds 17,820 lbs (7,838 kg) of
SF6 or perfluorocarbons (PFCs).
(viii) HCFC-22 production.
(ix) HFC-23 destruction processes that are not collocated with a
HCFC-22 production facility and that destroy more than 2.14 metric tons
of HFC-23 per year.
(x) Lime manufacturing.
(xi) Nitric acid production.
(xii) Petrochemical production.
(xiii) Petroleum refineries.
(xiv) Phosphoric acid production.
(xv) Silicon carbide production.
(xvi) Soda ash production.
(xvii) Titanium dioxide production.
(xviii) Underground coal mines that are subject to quarterly or
more frequent sampling by MSHA of ventilation systems.
(xix) Municipal landfills that generate CH4 in amounts
equivalent to 25,000 metric tons CO2e or more per year.
(xx) Manure management systems that emit CH4 and
N2O in amounts equivalent to 25,000 metric tons
CO2e or more per year.
(2) Any facility that emits 25,000 metric tons CO2e or
more per year in combined emissions from stationary fuel combustion
units, miscellaneous uses of carbonate, and all source categories that
are listed in this paragraph (a)(2) and that are located at the
facility in any calendar year starting in 2010. For these facilities,
the GHG emission report must cover all source categories for which
calculation methodologies are provided in subparts B through JJ of this
part.
(i) Electricity generation.
(ii) Electronics--photovoltaic manufacturing.
(iii) Ethanol production.
(iv) Ferroalloy production.
(v) Fluorinated greenhouse gas production.
(vi) Food processing.
(vii) Glass production.
(viii) Hydrogen production.
(ix) Iron and steel production.
(x) Lead production.
(xi) Magnesium production.
(xii) Oil and natural gas systems.
(xiii) Pulp and Paper Manufacturing.
(xiv) Zinc production.
(xv) Industrial landfills.
(xvi) Wastewater treatment.
(3) Any facility that in any calendar year starting in 2010 meets
all three of the conditions listed in this paragraph (a)(3). For these
facilities, the GHG emission report must cover emissions from
stationary fuel combustion sources only. For 2010 only, the facilities
may submit an abbreviated emissions report according to Sec. 98.3(d).
(i) The facility does not contain any source category designated in
paragraphs (a)(1) and (2) of this section.
(ii) The aggregate maximum rated heat input capacity of the
stationary fuel combustion units at the facility is 30 mmBtu/hr or
greater.
(iii) The facility emits 25,000 metric tons CO2e or more
per year from all stationary fuel combustion sources.
(4) Any supplier of any of the products listed in this paragraph
(a)(4) in any calendar year starting in 2010. For these suppliers, the
GHG emissions report must cover all applicable products for which
calculation methodologies are provided in subparts KK through PP of
this part.
(i) Coal.
(ii) Coal-based liquid fuels.
(iii) Petroleum products.
(iv) Natural gas and natural gas liquids.
(v) Industrial greenhouse gases, as specified in either paragraph
(a)(4)(v)(A) or (B) of this section:
(A) All producers of industrial greenhouse gases.
(B) Importers of industrial greenhouse gases with total bulk
imports that exceed 25,000 metric tons CO2e per year.
(C) Exporters of industrial greenhouse gases with total bulk
exports that exceed 25,000 metric tons CO2e per year.
(vi) Carbon dioxide, as specified in either paragraph (a)(4)(vi)(A)
or (B) of this section.
(A) All producers of carbon dioxide.
(B) Importers of CO2 or a combination of CO2
and other industrial GHGs with total bulk imports that exceed 25,000
metric tons CO2e per year.
(C) Exporters of CO2 or a combination of CO2
and other industrial GHGs with
[[Page 16613]]
total bulk exports that exceed 25,000 metric tons CO2e per
year.
(b) To calculate GHG emissions for comparison to the 25,000 metric
ton CO2e per year emission threshold in paragraph (a)(2) of
this section, the owner or operator shall calculate annual
CO2e emissions, as described in paragraphs (b)(1) through
(4) of this section.
(1) Estimate the annual emissions of CO2,
CH4, N2O, and fluorinated GHG (as defined in
Sec. 98.6) in metric tons from stationary fuel combustion units,
miscellaneous uses of carbonate, and any applicable source category
listed in paragraph Sec. 98.2(a)(2). The GHG emissions shall be
calculated using the methodologies specified in each applicable
subpart. For this calculation, facilities with industrial landfills
must use the CH4 generation calculation methodology in
subpart HH of this part.
(2) For stationary combustion units, calculate the annual
CO2 emissions in metric tons using any appropriate method
specified in Sec. 98.33(a). Calculate the annual CH4 and
N2O emissions from the stationary combustion sources in
metric tons using Equation C-9 in Sec. 98.33(c). Carbon dioxide
emissions from the combustion of biogenic fuels shall be excluded from
the calculations. In using Equations C-2a and C-9 in Sec. 98.33, the
high heat value for all types of fuel shall be determined monthly.
(3) For miscellaneous uses of carbonate, calculate the annual
CO2 emissions in metric tons using the procedures specified
in subpart U of this part.
(4) Sum the emissions estimates from paragraphs (b)(1), (2), and
(3) of this section for each GHG and calculate metric tons of
CO2e using Equation A-1.
[GRAPHIC] [TIFF OMITTED] TP10AP09.000
Where:
CO2e = Carbon dioxide equivalent, metric tons/year.
GHGi = Mass emissions of each greenhouse gas emitted,
metric tons/year.
GWPi = Global warming potential for each greenhouse gas
from Table A-1 of this subpart.
n = The number of greenhouse gases emitted.
(5) For purpose of determining if an emission threshold has been
exceeded, capture of CO2 for transfer off site must not be
considered.
(c) To calculate GHG emissions for comparison to the 25,000 metric
ton CO2e/year emission threshold for stationary fuel
combustion under paragraph (a)(3) of this section, the owner or
operator shall calculate CO2, CH4, N2O
emissions from all stationary combustion units using the methods
specified in paragraph (b)(2) of this section. Then, convert the
emissions of each GHG to metric tons CO2e per year using
Equation A-1 of this section, and sum the emissions for all units at
the facility.
(d) To calculate GHG quantities for comparison to the 25,000 metric
ton CO2e per year threshold for importers and exporters of
industrial greenhouse gases under paragraph (a)(4) of this section, the
owner or operator shall calculate the total annual CO2e of
all the industrial GHGs that the company imported and the total annual
CO2e of all the industrial GHGs that the company exported
during the reporting year, as described in paragraphs (d)(1) through
(d)(3) of this section.
(1) Calculate the mass in metric tons per year of CO2,
N2O, and each fluorinated GHG (as defined in Sec. 98.6)
imported and the mass in metric tons per year of CO2,
N2O, and fluorinated GHG exported during the year. The
masses shall be calculated using the methodologies specified in subpart
OO of this part.
(2) Convert the mass of each GHG imported and each GHG exported
from paragraph (d)(1) of this section to metric tons of CO2e
using Equation A-1 of Sec. 98.3.
(3) Sum the total annual metric tons of CO2e in
paragraph (d)(2) of this section for all imported GHGs. Sum the total
annual metric tons of CO2e in paragraph (d)(2) of this
section for all exported GHGs.
(e) If a capacity or generation reporting threshold in paragraph
(a)(1) of this section applies, the owner or operator shall review the
appropriate records to determine whether the threshold has been
exceeded.
(f) Except as provided in paragraph (g) of this section, the owners
and operators of a facility or supplier that does not meet the
applicability requirements of paragraph (a) of this section are not
required to submit an emission report for the facility or supplier.
Such owners and operators must reevaluate the applicability to this
part to the facility or supplier (which reevaluation must include the
revising of any relevant emissions calculations or other calculations)
whenever there is any change to the facility or supplier that could
cause the facility or supplier to meet the applicability requirements
of paragraph (a) of this section. Such changes include but are not
limited to process modifications, increases in operating hours,
increases in production, changes in fuel or raw material use, addition
of equipment, and facility expansion.
(g) Once a facility or supplier is subject to the requirements of
this part, the owners and operators of the facility or supply operation
must continue for each year thereafter to comply with all requirements
of this part, including the requirement to submit GHG emission reports,
even if the facility or supplier does not meet the applicability
requirements in paragraph (a) of this section in a future year. If a
GHG emission source in a future year through change of ownership
becomes part of a different facility that has not previously met, and
does not in that future year meet, the applicability requirements of
paragraph (a) of this section; the owner or operator shall comply with
the requirements of this part only with regard to that source,
including the requirement to submit GHG emission reports.
(h) Table A-2 of this subpart provides a conversion table for some
of the common units of measure used in part 98.
Sec. 98.3 What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?
The owner or operator of a facility or supplier that is subject to
the requirements of this part must submit GHG emissions reports to the
Administrator, as specified in paragraphs (a) through (g) of this
section.
(a) General. You must collect emissions data, calculate GHG
emissions, and follow the procedures for quality assurance, missing
data, recordkeeping, and reporting that are specified in each relevant
subpart of this part.
(b) Schedule. Unless otherwise specified in subparts B through PP,
you must submit an annual GHG emissions report no later than March 31
of each calendar year for GHG emissions in the previous calendar year.
(1) For existing facilities that commenced operation before January
1, 2010, you must report emissions for calendar year 2010 and each
subsequent calendar year.
(2) For new facilities that commence operation on or after January
1, 2010, you must report emissions for the first calendar year in which
the facility operates, beginning with the first operating month and
ending on December 31 of that year. Each subsequent annual report must
cover emissions for the calendar year, beginning on January 1 and
ending on December 31.
[[Page 16614]]
(3) For any facility or supplier that becomes subject to this rule
because of a physical or operational change that is made after January
1, 2010, you must report emissions for the first calendar year in which
the change occurs, beginning with the first month of the change and
ending on December 31 of that year. Each subsequent annual report must
cover emissions for the calendar year, beginning on January 1 and
ending on December 31.
(c) Content of the annual report. Except as provided in paragraph
(d) of this section, each annual GHG emissions report shall contain the
following information:
(1) Facility name or supplier name (as appropriate), street
address, physical address, and Federal Registry System identification
number.
(2) Year covered by the report.
(3) Date of submittal.
(4) Annual emissions of CO2, CH4,
N2O, and each fluorinated GHG. Emissions must be calculated
assuming no capture of CO2 and reported at the following
levels:
(i) Total facility emissions aggregated from all applicable source
categories in subparts C through JJ of this part and expressed in
metric tons of CO2e calculated using Equation A-1 of this
subpart.
(ii) Total emissions aggregated from all applicable supply
categories in subparts KK through PP of this part and expressed in
metric tons of CO2e calculated using Equation A-1 of this
subpart.
(iii) Emissions from each applicable source category or supply
category in subparts C through PP of this part, expressed in metric
tons of each GHG.
(iv) Emissions and other data for individual units, processes,
activities, and operations as specified for each source category in the
``Data reporting requirements'' section of each applicable subpart of
this part.
(5) Total electricity generated onsite in kilowatt hours.
(6) Total pounds of synthetic fertilizer produced at the facility
and total nitrogen contained in that fertilizer.
(7) Total annual mass of CO2 captured in metric tons.
(8) A signed and dated certification statement provided by the
designated representative of the owner or operator, according to the
requirements of Sec. 98.4(e)(1).
(d) Abbreviated emissions report. In lieu of the report required by
paragraph (c) of this section, the owner or operator of an existing
facility that is in operation on January 1, 2010 and that is subject to
Sec. 98.2(a)(3) may submit an abbreviated GHG emissions report for the
facility for emissions in 2010. The abbreviated report must be
submitted by March 31, 2011. An owner or operator that submits an
abbreviated report for a facility in 2011 must submit a full GHG
emissions report according to the requirements of paragraph (c) of this
section for each calendar year thereafter. The abbreviated facility
report must include the following information:
(1) Facility name, street address, physical address, and Federal
Registry System identification number.
(2) The year covered by the report.
(3) Date of submittal.
(4) Total facility GHG emissions aggregated for all stationary fuel
combustion units calculated according to any appropriate method
specified in Sec. 98.33(a) and expressed in metric tons of
CO2, CH4, N2O, and CO2e. If
Equation C-2a or C-9 of subpart C are selected, the high heat value for
all types of fuel shall be determined monthly.
(5) A signed and dated certification statement provided by the
designated representative of the owner or operator, according to the
requirements of Sec. 98.4(e)(1).
(e) Emission Calculations. In preparing the GHG emissions report,
you must use the emissions calculation protocols specified in the
relevant subparts, except as specified in paragraph (d) of this
section.
(f) Verification. To verify the completeness and accuracy of
reported GHG emissions, the Administrator may review the certification
statements described in paragraphs (c)(8) and (d)(5) of this section
and any other credible evidence, in conjunction with a comprehensive
review of the emissions reports and periodic audits of selected
reporting facilities. Nothing in this section prohibits the
Administrator from using additional information to verify the
completeness and accuracy of the reports.
(g) Recordkeeping. An owner or operator that is required to report
GHG emissions under this part must keep records as specified in this
paragraph. You must retain all required records for at least 5 years.
The records shall be kept in an electronic or hard-copy format (as
appropriate) and recorded in a form that is suitable for expeditious
inspection and review. Upon request by EPA, the records required under
this section must be made available to the Administrator. For records
that are electronically generated or maintained, the equipment or
software necessary to read the records shall be made available, or, if
requested by EPA, electronic records shall be converted to paper
documents. You must retain the following records, in addition to those
records prescribed in each applicable subpart of this part:
(1) A list of all units, operations, processes, and activities for
which GHG emission were calculated.
(2) The data used to calculate the GHG emissions for each unit,
operation, process, and activity, categorized by fuel or material type.
The results of all required fuel analyses for high heat value and
carbon content, the results of all required certification and quality
assurance tests of continuous monitoring systems and fuel flow meters
if applicable, and analytical results for the development of site-
specific emissions factors.
(3) Documentation of the process used to collect the necessary data
for the GHG emissions calculations.
(4) The GHG emissions calculations and methods used.
(5) All emission factors used for the GHG emissions calculations.
(6) Any facility operating data or process information used for the
GHG emission calculations.
(7) Names and documentation of key facility personnel involved in
calculating and reporting the GHG emissions.
(8) The annual GHG emissions reports.
(9) A log book, documenting procedural changes (if any) to the GHG
emissions accounting methods and changes (if any) to the
instrumentation critical to GHG emissions calculations.
(10) Missing data computations.
(11) A written quality assurance performance plan (QAPP). Upon
request from regulatory authorities, the owner or operator shall make
all information that is collected in conformance with the QAPP
available for review during an audit. Electronic storage of the
information in the QAPP is permissible, provided that the information
can be made available in hard copy upon request during an audit. At a
minimum, the QAPP plan shall include (or refer to separate documents
that contain) a detailed description of the procedures that are used
for the following activities:
(i) Maintenance and repair of all continuous monitoring systems,
flow meters, and other instrumentation used to provide data for the GHG
emissions reported under this part. A maintenance log shall be kept.
(ii) Calibrations and other quality assurance tests performed on
the continuous monitoring systems, flow meters, and other
instrumentation used to provide data for the GHG emissions reported
under this part.
[[Page 16615]]
Sec. 98.4 Authorization and responsibilities of the designated
representative.
(a) General. Except as provided under paragraph (f) of this
section, each owner or operator that is subject to this part, shall
have one and only one designated representative responsible for
certifying and submitting GHG emissions reports and any other
submissions to the Administrator under this part.
(b) Authorization of a designated representative. The designated
representative of the facility shall be selected by an agreement
binding on the owners and operators and shall act in accordance with
the certification statements in paragraph (i)(4) of this section. The
designated representative must be an individual having responsibility
for the overall operation of the facility or activity such as the
position of the plant manager, operator of a well or a well field,
superintendent, position of equivalent responsibility, or an individual
or position having overall responsibility for enviromental matters for
the company.
(c) Responsibility of the designated representative. Upon receipt
by the Administrator of a complete certificate of representation under
this section, the designated representative of the facility shall
represent and, by his or her representations, actions, inactions, or
submissions, legally bind each owner and operator in all matters
pertaining to this part, notwithstanding any agreement between the
designated representative and such owners and operators. The owners and
operators shall be bound by any decision or order issued to the
designated representative by the Administrator or a court.
(d) Timing. No GHG emissions report or other submissions under this
part will be accepted until the Administrator has received a complete
certificate of representation under this section for a designated
representative of the owner or operator.
(e) Certification of the GHG emissions report. Each GHG emission
report and any other submission under this part shall be submitted,
signed, and certified by the designated representative in accordance
with 40 CFR 3.10.
(1) Each such submission shall include the following certification
statement by the designated representative: ``I am authorized to make
this submission on behalf of the owners and operators of the facility
(or supply operation, as appropriate) for which the submission is made.
I certify under penalty of law that I have personally examined, and am
familiar with, the statements and information submitted in this
document and all its attachments. Based on my inquiry of those
individuals with primary responsibility for obtaining the information,
I certify that the statements and information are to the best of my
knowledge and belief true, accurate, and complete. I am aware that
there are significant penalties for submitting false statements and
information or omitting required statements and information, including
the possibility of fine or imprisonment.''
(2) The Administrator will accept a GHG emission report or other
submission under this part only if the submission is signed and
certified in accordance with paragraph (e)(1) of this section.
(f) Alternate designated representative. A certificate of
representation under this section may designate an alternate designated
representative, who may act on behalf of the designated representative.
The agreement by which the alternate designated representative is
selected shall include a procedure for authorizing the alternate
designated representative to act in lieu of the designated
representative.
(1) Upon receipt by the Administrator of a complete certificate of
representation under this section, any representation, action,
inaction, or submission by the alternate designated representative
shall be deemed to be a representation, action, inaction, or submission
by the designated representative.
(2) Except in this section, whenever the term ``designated
representative'' is used, the term shall be construed to include the
designated representative or any alternate designated representative.
(g) Changing a designated representative or alternate designated
representative. The designated representative (or alternate designated
representative) may be changed at any time upon receipt by the
Administrator of a superseding complete certificate of representation
under this section. Notwithstanding any such change, all
representations, actions, inactions, and submissions by the previous
designated representative (or alternate designated representative)
before the time and date when the Administrator receives the
superseding certificate of representation shall be binding on the new
designated representative and the owners and operators.
(h) Changes in owners and operators. In the event a new owner or
operator is not included in the list of owners and operators in the
certificate of representation under this section, such new owner or
operator shall be deemed to be subject to and bound by the certificate
of representation, the representations, actions, inactions, and
submissions of the designated representative and any alternate
designated representative, as if the new owner or operator were
included in such list. Within 30 days following any change in the
owners and operators, including the addition of a new owner or
operator, the designated representative or any alternate designated
representative shall submit a revision to the certificate of
representation under this section amending the list of owners and
operators to include the change.
(i) Certificate of representation. A complete certificate of
representation for a designated representative or an alternate
designated representative shall include the following elements in a
format prescribed by the Administrator:
(1) Identification of the facility or supply operation for which
the certificate of representation is submitted.
(2) The name, address, e-mail address (if any), telephone number,
and facsimile transmission number (if any) of the designated
representative and any alternate designated representative.
(3) A list of the owners and operators of the facility or supply
operation.
(4) The following certification statements by the designated
representative and any alternate designated representative:
(i) ``I certify that I was selected as the designated
representative or alternate designated representative, as applicable,
by an agreement binding on the owners and operators that are subject to
the requirements of 40 CFR 98.3.''
(ii) ``I certify that I have all the necessary authority to carry
out my duties and responsibilities under the Mandatory Greenhouse Gas
Reporting Program on behalf of the owners and operators that are
subject to the requirements of 40 CFR 98.3 and that each such owner and
operator shall be fully bound by my representations, actions,
inactions, or submissions.''
(iii) ``I certify that the owners and operators that are subject to
the requirements of 40 CFR 98.3 shall be bound by any order issued to
me by the Administrator or a court regarding the source or unit.''
(iv) ``Where there are multiple holders of a legal or equitable
title to, or a leasehold interest in, a facility (or supply operation
as appropriate) that is subject to the requirements of 40 CFR 98.3, I
certify that I have given a written notice of my selection as the
`designated representative' or `alternate designated representative',
as applicable, and of the agreement by which I was selected to
[[Page 16616]]
each owner and operator that is subject to the requirements of 40 CFR
98.3.''
(5) The signature of the designated representative and any
alternate designated representative and the dates signed.
(j) Documents of Agreement. Unless otherwise required by the
Administrator, documents of agreement referred to in the certificate of
representation shall not be submitted to the Administrator. The
Administrator shall not be under any obligation to review or evaluate
the sufficiency of such documents, if submitted.
(k) Binding nature of the certificate of representation. Once a
complete certificate of representation under this section has been
submitted and received, the Administrator will rely on the certificate
of representation unless and until a superseding complete certificate
of representation under this section is received by the Administrator.
(l) Objections concerning a designated representative. (1) Except
as provided in paragraph (g) of this section, no objection or other
communication submitted to the Administrator concerning the
authorization, or any representation, action, inaction, or submission,
of the designated representative or alternate designated representative
shall affect any representation, action, inaction, or submission of the
designated representative or alternate designated representative, or
the finality of any decision or order by the Administrator under the
Mandatory Greenhouse Gas Reporting Program.
(2) The Administrator will not adjudicate any private legal dispute
concerning the authorization or any representation, action, inaction,
or submission of any designated representative or alternate designated
representative.
Sec. 98.5 How do I submit my report?
Each GHG emissions report for a facility or supplier must be
submitted electronically on behalf of the owners and operators of that
facility or supplier by their designated representative, in a format
specified by the Administrator.
Sec. 98.6 What definitions do I need to understand?
All terms used in this part shall have the same meaning given in
the Clean Air Act and in this section.
Abandoned (closed) mines mean mines that are no longer operational
(per MSHA definition).
Absorbent circulation pump means a pump commonly powered by natural
gas pressure that circulates the absorbent liquid between the absorbent
regenerator and natural gas contactor.
Accuracy of a measurement at a specified level (e.g., one percent
of full scale) means that the mean of repeat measurements made by a
device or technique has a 95 percent chance of falling within the range
bounded by the true value plus or minus the specified level.
Acid gas means hydrogen sulfide (H2S) and carbon dioxide
(CO2) contaminants that are separated from sour natural gas
by an acid gas removal process.
Acid gas removal unit (AGR) means a process unit that separates
hydrogen sulfide and/or carbon dioxide from sour natural gas using
liquid or solid absorbents, such as liquid absorbents, solid
adsorbents, or membrane separators.
Acid gas removal vent stack fugitive emissions mean the acid gas
(typically CO2 and H2S) separated from the acid
gas absorbing medium (most commonly an amine solution) and released
with methane and other light hydrocarbons to the atmosphere or a flare.
Acid Rain Program means the program established under title IV of
the Clean Air Act, and implemented under parts 72 through 78 of this
chapter for the reduction of sulfur dioxide and nitrogen oxides
emissions.
Actual conditions mean temperature, pressure and volume at
measurement conditions of natural gas.
Actuation means, for the purposes of this rule, an event in which a
natural gas pneumatically driven valve is opened and/or closed by
release of natural gas pressure to the atmosphere.
Administrator means the Administrator of the United States
Environmental Protection Agency or the Administrator's authorized
representative.
AGA means the American Gas Association
Air injected flare means a flare in which air is blown into the
base of a flare stack to induce complete combustion of low Btu natural
gas (i.e., high non-combustible component content).
Alkali bypass means a duct between the feed end of the kiln and the
preheater tower through which a portion of the kiln exit gas stream is
withdrawn and quickly cooled by air or water to avoid excessive buildup
of alkali, chloride and/or sulfur on the raw feed. This may also be
referred to as the ``kiln exhaust gas bypass.''
Anaerobic digester means the equipment designed and operated for
waste stabilization by the microbial reduction of complex organic
compounds to CO2 and CH4, which is captured and
flared or used as a fuel.
Anode effect is a process upset condition of an aluminum
electrolysis cell caused by too little alumina dissolved in the
electrolyte. The anode effect begins when the voltage rises rapidly and
exceeds a threshold voltage, typically 8 volts.
Anode Effect Minutes Per Cell Day (24 hours) are the total minutes
during which an electrolysis cell voltage is above the threshold
voltage, typically 8 volts.
ANSI means the American National Standards Institute.
Anti-static wrap means wrap used to assist the process of ensuring
that all fugitive emissions from a single source are captured and
directed to a measurement instrument.
API means the American Petroleum Institute.
Argon-oxygen decarburization (AOD) vessel means any closed-bottom,
refractory-lined converter vessel with submerged tuyeres through which
gaseous mixtures containing argon and oxygen or nitrogen may be blown
into molten steel for further refining to reduce the carbon content of
the steel.
ASME means the American Society of Mechanical Engineers.
ASTM means the American Society of Testing and Materials.
B0 means the maximum CH4 producing capacity of a waste
stream, kg CH4/kg COD.
Backpressure means impeding the natural atmospheric release of
fugitive emissions by enclosing the release with a lower capacity
sampling device and altering natural flow.
Basic oxygen furnace means any refractory-lined vessel in which
high-purity oxygen is blown under pressure through a bath of molten
iron, scrap metal, and fluxes to produce steel.
Biodiesel means any liquid biofuel suitable as a diesel fuel
substitute or a diesel fuel additive or extender. Biodiesel fuels are
usually made from agricultural oils or from animal tallow.
Biogenic CO2 means carbon dioxide emissions generated as the result
of biomass combustion.
Biomass means non-fossilized and biodegradable organic material
originating from plants, animals and micro-organisms, including
products, by-products, residues and waste from agriculture, forestry
and related industries as well as the non-fossilized and biodegradable
organic fractions of industrial and municipal wastes, including gases
and liquids recovered from the decomposition of non-fossilized and
biodegradable organic material.
Blast furnace means a furnace that is located at an integrated iron
and steel
[[Page 16617]]
plant and is used for the production of molten iron from iron ore
pellets and other iron bearing materials.
Bleed rate means the rate at which natural gas flows continuously
or intermittently from a process measurement instrument to a valve
actuator controller where it is vented (bleeds) to the atmosphere.
Blendstocks are naphthas used for blending or compounding into
finished motor gasoline. These include RBOB (reformulated gasoline for
oxygenate blending), CBOB (conventional gasoline for oxygebate
blending), and GTAB (gasoline treated as blendstock).
Blowdown means manual or automatic opening of valves to relieve
pressure and or release natural gas from but not limited to process
vessels, compressors, storage vessels or pipelines by venting natural
gas to the atmosphere or a flare. This practice is often implemented
prior to shutdown or maintenance.
Blowdown vent stack fugitive emissions mean natural gas released
due to maintenance and/or blowdown operations including but not limited
to compressor blowdown and Emergency Shut-Down system testing.
Boil-off gas means natural gas that vaporizes from liquefied
natural gas in storage tanks.
British Thermal Unit or Btu means the quantity of heat required to
raise the temperature of one pound of water by one degree Fahrenheit at
about 39.2 degrees Fahrenheit.
Bulk, with respect to industrial GHG suppliers, means the transfer
of a product inside containers, including but not limited to tanks,
cylinders, drums, and pressure vessels.
Butane (C4H10) or n-Butane means the normally gaseous straight-
chain or branch-chain hydrocarbon extracted from natural gas or
refinery gas streams and is designated in ASTM Specification D1835 and
Gas Processors Association Specifications for commercial butane. Not
included in this definition is isobutene, which normally is used for
feedstock.
Butylene (C2H8) is an olefinic hydrocarbon
recovered from refinery processes and used as a feedstock.
By-product coke oven battery means a group of ovens connected by
common walls, where coal undergoes destructive distillation under
positive pressure to produce coke and coke oven gas from which by-
products are recovered.
By-product formation is the quantity of fluorinated GHGs created
during the etching or chamber cleaning processes in an electronics
manufacturing process.
C2+ means the NGL fraction consisting of hydrocarbon molecules
ethane and heavier. The characteristics for this fraction, as reported
in Table MM-2, are derived from the mixture of 31 percent ethane and 29
percent propane as reported in Table MM-1, and 41 percent C4+. These
proportions are determined from an example API E&PTankCalc run on
34[deg]API crude oil from a separator temperature of 100 [deg]F and
pressure of 40 psig.
C4+ means the NGL fraction consisting of hydrocarbon molecules
butane and heavier. The characteristics for this fraction, as reported
in Table MM-2, are derived from the mixture of 39 percent ``pentanes
plus'' and 61 percent butane as reported in Table MM-1. These
proportions are determined from an example API E&PTankCalc run on
34[deg]API crude oil from a separator temperature of 100 [deg]F and
pressure of 40 psig.
C5+ is pentane plus in the specific chemical composition that
underlies the default factors in Table MM-1.
C6+ means NGL fraction consisting of hydrocarbon molecules hexane
and heavier. The characteristics for this fraction, as reported in
Table MM-2, are derived from the assumption that ``pentane plus'', as
reported in Table MM-1, consists of a mixture of 53 percent C6+ and 47
percent pentane. These proportions are determined from an example API
E&PTankCalc run on 34[deg]API crude oil from a separator temperature of
100 [deg]F and pressure of 40 psig.
Calibrated bag means a flexible, non-elastic bag of a calibrated
volume that can be quickly affixed to a fugitive emitting source such
that the fugitive emissions inflate the bag to its calibrated volume.
Carbon black oil means a heavy aromatic oil that may be derived
either as a by-product of petroleum refining or metallurgical coke
production. Carbon black oil consists mainly of unsaturated
hydrocarbons, predominately higher than C14.
Carbon dioxide equivalent or CO2e means the number of
metric tons of CO2 emissions with the same global warming
potential as one metric ton of another primary greenhouse gas.
Carbon dioxide production well means any hole drilled in the earth
to extract a carbon dioxide stream from a geologic formation or group
of formations which contain deposits of carbon dioxide.
Carbon dioxide production well facility means one or more carbon
dioxide production wells that are located on one or more contiguous or
adjacent properties, which are under the control of the same entity.
Carbon dioxide production wells located on different oil and gas
leases, mineral fee tracts, lease tracts, subsurface or surface unit
areas, surface fee tracts, surface lease tracts, or separate surface
sites, whether or not connected by a road, waterway, power line, or
pipeline, shall be considered part of the same CO2
production well facility.
Carbon dioxide stream means carbon dioxide that has been captured
from an emission source (e.g., a power plant or other industrial
facility) or extracted from a carbon dioxide production well plus
incidental associated substances either derived from the source
materials and the capture process or extracted with the carbon dioxide.
Carbon share means the weight percentage of carbon in any product.
Carbonate means compounds containing the radical
CO3-2. Upon calcination, the carbonate radical
decomposes to evolve carbon dioxide (CO2). Common carbonates
consumed in the mineral industry include calcium carbonate
(CaCO3) or calcite; magnesium carbonate (MgCO3)
or magnesite; and calcium-magnesium carbonate
(CaMg(CO3)2) or dolomite.
Carbonate-based mineral means any of the following minerals used in
the manufacture of glass: calcium carbonate (CaCO3), calcium
magnesium carbonate (CaMg(CO3)2), and sodium
carbonate (Na2CO3).
Carbonate-based mineral mass fraction means the following: for
limestone, the mass fraction of CaCO3 in the limestone; for
dolomite, the mass fraction of CaMg(CO3)2 in the
dolomite; and for soda ash, the mass fraction of
Na2CO3 in the soda ash.
Carbonate-based raw material means any of the following materials
used in the manufacture of glass: limestone, dolomite, and soda ash.
Carrier gas means the gas with which cover gas is mixed to
transport and dilute the cover gas thus maximizing its efficient use.
Carrier gases typically include CO2, N2, and/or
dry air.
Catalytic cracking unit means a refinery process unit in which
petroleum derivatives are continuously charged and hydrocarbon
molecules in the presence of a catalyst are fractured into smaller
molecules, or react with a contact material suspended in a fluidized
bed to improve feedstock quality for additional processing and the
catalyst or contact material is continuously regenerated by burning off
coke and other deposits. Catalytic cracking units include both
fluidized bed systems, which are referred to as fluid catalytic
cracking units (FCCU), and moving bed systems, which are also referred
to as thermal catalytic cracking units. The unit includes the riser,
[[Page 16618]]
reactor, regenerator, air blowers, spent catalyst or contact material
stripper, catalyst or contact material recovery equipment, and
regenerator equipment for controlling air pollutant emissions and for
heat recovery.
Cattle and swine deep bedding means as manure accumulates, bedding
is continually added to absorb moisture over a production cycle and
possibly for as long as 6 to 12 months. This manure management system
also is known as a bedded pack manure management system and may be
combined with a dry lot or pasture.
CBOB or conventional gasoline for oxygenate blending means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of conventional gasoline.
Centrifugal compressor means any equipment that increases the
pressure of a process natural gas by centrifugal action, employing
rotating movement of the driven shaft.
Centrifugal compressor dry seals mean a series of rings that are
located around the compressor shaft where it exits the compressor case
and that operate mechanically under the opposing forces to prevent
natural gas from escaping to the atmosphere.
Centrifugal compressor dry seals fugitive emissions mean natural
gas released from a dry seal vent pipe and/or the seal face around the
rotating shaft where it exits one or both ends of the compressor case.
Centrifugal compressor wet seals mean a series of rings around the
compressor shaft where it exits the compressor case, that use oil
circulated under high pressure between the rings to prevent natural gas
from escaping to the atmosphere.
Centrifugal compressor wet seals fugitive emissions mean natural
gas released from the seal face around the rotating shaft where it
exits one or both ends of the compressor case PLUS the natural gas
absorbed in the circulating seal oil and vented to the atmosphere from
a seal oil degassing vessel or sump before the oil is re-circulated, or
from a seal oil containment vessel vent.
Certified standards means calibration gases certified by the
manufacturer of the calibration gases to be accurate to within 2
percent of the value on the label or calibration gases.
CH4 means methane.
Chemical recovery combustion unit means a combustion device, such
as a recovery furnace or fluidized-bed reactor where spent pulping
liquor from sulfite or semi-chemical pulping processes is burned to
recover pulping chemicals.
Chemical recovery furnace means an enclosed combustion device where
concentrated spent liquor produced by the kraft or soda pulping process
is burned to recover pulping chemicals and produce steam. Includes any
recovery furnace that burns spent pulping liquor produced from both the
kraft and soda pulping processes.
Chloride process means a production process where titanium dioxide
is produced using calcined petroleum coke and chlorine as raw
materials.
Close-range means, for the purposes of this rule, safely accessible
within the operator's arm's reach from the ground or stationary
platforms.
CO2 means carbon dioxide.
Coal means all solid fuels classified as anthracite, bituminous,
sub-bituminous, or lignite by the American Society for Testing and
Materials Designation ASTM D388-05 ``Standard Classification of Coals
by Rank'' (as incorporated by reference in Sec. 98.7).
COD means the chemical oxygen demand as determined using methods
specified pursuant to 40 CFR Part 136.
Coke (petroleum) means a solid residue consisting mainly of carbon
which results from the cracking of petroleum hydrocarbons in processes
such as coking and fluid coking. This includes catalyst coke deposited
on a catalyst during the refining process which must be burned off in
order to regenerate the catalyst.
Coke burn-off means the coke removed from the surface of a catalyst
by combustion during catalyst regeneration. Coke burn-off also means
the coke combusted in fluid coking unit burner.
Cokemaking means the production of coke from coal in either a by-
product coke oven battery or a non-recovery coke oven battery.
Cold and steady emissions mean a nearly constant and steady
emissions stream that is low enough in temperature (i.e., less than 140
degrees Fahrenheit) to be safely directly measured by a person.
Commercial Applications means any use including but not limited to:
Food and beverage, industrial and municipal water/wastewater treatment,
metal fabrication, including welding and cutting, greenhouse uses for
plant growth, fumigants (e.g., grain storage) and herbicides, pulp and
paper, cleaning and solvent use, fire fighting, transportation and
storage of explosives, enhanced oil and natural gas recovery, long-term
storage (sequestration), or research and development.
Completely destroyed means destroyed with a destruction efficiency
of 99.99 percent or greater.
Completely recaptured means 99.99 percent or greater of each GHG is
removed from a process stream.
Component, for the purposes of subpart W only, means but is not
limited to each metal to metal joint or seal of non-welded connection
separated by a compression gasket, screwed thread (with or without
thread sealing compound), metal to metal compression, or fluid barrier
through which natural gas or liquid can escape to the atmosphere.
Compressor means any machine for raising the pressure of a natural
gas by drawing in low pressure natural gas and discharging
significantly higher pressure natural gas (i.e., compression ratio
higher than 1.5).
Compressor fugitive emissions mean natural gas emissions from all
components in close physical proximity to compressors where mechanical
and thermal cycles may cause elevated emission rates, including but not
limited to open-ended blowdown vent stacks, piping and tubing
connectors and flanges, pressure relief valves, pneumatic starter open-
ended lines, instrument connections, cylinder valve covers, and fuel
valves.
Condensate means hydrocarbon and other liquid separated from
natural gas that condenses due to changes in the temperature, pressure,
or both, and remains liquid at storage conditions, includes both water
and hydrocarbon liquids.
Connector means but is not limited to flanged, screwed, or other
joined fittings used to connect pipe line segments, tubing, pipe
components (such as elbows, reducers, ``T's'' or valves) or a pipe line
and a piece of equipment or an instrument to a pipe, tube or piece of
equipment. A common connector is a flange. Joined fittings welded
completely around the circumference of the interface are not considered
connectors for the purpose of this regulation.
Container glass means glass made of soda-lime recipe, clear or
colored, which is pressed and/or blown into bottles, jars, ampoules,
and other products listed in North American Industry Classification
System 327213 (NAICS 327213).
Continuous emission monitoring system or CEMS means the total
equipment required to sample, analyze, measure, and provide, by means
of readings recorded at least once every 15 minutes, a permanent record
of gas concentrations, pollutant emission rates, or gas volumetric flow
rates from stationary sources.
Continuous glass melting furnace means a glass melting furnace that
[[Page 16619]]
operates continuously except during periods of maintenance,
malfunction, control device installation, reconstruction, or
rebuilding.
Control method means any equipment used for recovering and/or
oxidizing air emissions of methane. Such equipment includes, but is not
limited to, vapor recovery systems, absorbers, carbon dioxide
adsorbers, condensers, incinerators, flares, catalytic oxidizers,
boilers, and process heaters.
Conventional gasoline means any gasoline which has not been
certified under Sec. 80.40.
Cover gas means SF6, HFC-134a, fluorinated ketone (FK 5-
1-12) or other gas used to protect the surface of molten magnesium from
rapid oxidation and burning in the presence of air. The molten
magnesium may be the surface of a casting or ingot production operation
or the surface of a crucible of molten magnesium that is the source of
the casting operation.
Crude oil means any of the naturally occurring liquids and semi-
solids found in rock formations composed of complex mixtures of
hydrocarbons ranging from one to hundreds of carbon atoms in straight
and branched chains and rings.
Daily spread means manure is routinely removed from a confinement
facility and is applied to cropland or pasture within 24 hours of
excretion.
Degasification systems mean wells drilled from the surface or
boreholes drilled inside the mine that remove large volumes of
CH4 before, during, or after mining. Pre-mining
degasification systems refer to drainage wells drilled through a coal
seam or seams and cased to pre-drain the methane prior to mining. The
wells are normally placed in operation 2 to 7 years ahead of mining.
Degasification systems also include ``gob wells'' which recover methane
from the longwall face area during and after mining.
Degradable organic carbon (DOC) means the fraction of the total
mass of a waste material that can be biologically degraded.
Dehydrator means, for the purposes of this rule, a device in which
a liquid absorbent (including but not limited to desiccant, ethylene
glycol, diethylene glycol, or triethylene glycol) directly contacts a
natural gas stream to absorb water vapor.
Dehydrator vent stack fugitive emissions means natural gas released
from a natural gas dehydrator system absorbent (typically glycol)
reboiler or regenerator, including stripping natural gas and motive
natural gas used in absorbent circulation pumps.
Delayed coking unit means one or more refinery process units in
which high molecular weight petroleum derivatives are thermally cracked
and petroleum coke is produced in a series of closed, batch system
reactors.
De-methanizer means the natural gas processing unit that separates
methane rich residue gas from the heavier hydrocarbons (ethane,
propane, butane, pentane-plus) in feed natural gas stream.
Density means the mass contained in a given unit volume (mass/
volume).
Destruction means, with respect to underground coal mines, the
combustion of methane in any on-site or off-site combustion technology.
Destroyed methane includes, but is not limited to, methane combusted by
flaring, methane destroyed by thermal oxidation, methane combusted for
use in on-site energy or heat production technologies, methane that is
conveyed through pipelines (including natural gas pipelines) for off-
site combustion, and methane that is collected for any other on-site or
off-site use as a fuel.
Destruction means, with respect to fluorinated GHGs, the expiration
of a fluorinated GHG to the destruction efficiency actually achieved.
Such destruction does not result in a commercially useful end product.
Destruction Efficiency means the efficiency with which a
destruction device reduces the GWP-weighted mass of greenhouse gases
fed into the device, considering the GWP-weighted masses of both the
greenhouse gases fed into the device and those exhausted from the
device. The Destruction Efficiency is expressed in the following
Equation A-2:
[GRAPHIC] [TIFF OMITTED] TP10AP09.001
Where:
DE = Destruction Efficiency
tCO2eIN = The GWP-weighted mass of GHGs fed
into the destruction device
tCO2eOUT = The GWP-weighted mass of GHGs
exhausted from the destruction device, including GHGs formed during
the destruction process
Destruction efficiency, or flaring destruction efficiency, refers
to the fraction of the gas that leaves the flare partially or fully
oxidized
Destruction or removal efficiency (DRE) is the efficiency of a
control device to destroy or remove F-GHG and N2O. The DRE
is equal to one minus the ratio of the mass of all relevant GHG exiting
the emission control device to the mass of GHG entering the emission
control device.
Diesel fuel means a low sulfur fuel oil of grades 1BD or 2BD, as
defined by the American Society for Testing and Materials standard ASTM
D975-91, ``Standard Specification for Diesel Fuel Oils'' (as
incorporated by reference in Sec. 98.7), grades 1-GT or 2-GT, as
defined by ASTM D2880-90a, ``Standard Specification for Gas Turbine
Fuel Oils'' (as incorporated by reference in Sec. 98.7), or fuel oil
numbers 1 or 2, as defined by ASTM D396-90a, ``Standard Specification
for Fuel Oils'' (as incorporated by reference in Sec. 98.7).
Diesel fuel No. 1 has a distillation temperature of 550 [deg]F at
the 90 percent recovery point and conforms to ASTM D975-08 (2007)
Standard Specification for Diesel Fuel Oils. It is used in high speed
diesel engines such as city buses. Compared to fuel oil No. 1 it has a
higher octane number, a lower sulfur content, and a higher flash point.
It is blended with diesel No. 2 in the colder regions of the country to
facility cold starts.
Diesel fuel No. 2 has a distillation temperature of 500 [deg]F at
the 10 percent recovery point and 640 [deg]F at the 90 percent recovery
point and is defined in ASTM D975. It is used in high speed diesel
engines, such as locomotives, trucks and automobiles. Currently, there
are three categories of diesel fuel No. 2 defined by sulfur content:
High sulfur (>0.05%/wgt), low sulfur (<0.05%/wgt), and ultra low sulfur
(<0.0015%/wgt). Ultra low sulfur is used for on road vehicles.
Diesel fuel No. 4, made by blending diesel fuel and residual fuel
and conforming to ASTM D975, is used for low and medium speed diesel
engines.
Digesters are systems where animal excreta are collected and
anaerobically digested in a large containment vessel or covered lagoon.
Digesters are designed and operated for waste stabilization by the
microbial reduction of complex organic compounds to CO2 and
CH4, which is captured and may be flared or used as fuel.
There are multiple types of anaerobic digestion systems, including
covered lagoon, complete mix, plug flow, and fixed film digesters.
Direct liquefaction means the conversion of coal directly into
liquids, rather than passing through an intermediate gaseous state.
Direct reduction furnace means a high temperature furnace typically
fired with natural gas to produce solid iron from iron ore or iron ore
pellets and coke, coal, or other carbonaceous materials.
Distillate fuel oil means a classification for one of the petroleum
fractions produced in conventional distillation operations and from
crackers and hydrotreating process units. The
[[Page 16620]]
generic term distillate fuel oil includes both diesel fuels (Diesel
Fuels No. 1, No. 2, and No. 4) and fuel oils (Fuel oil No. 1, No. 2,
and No. 4). Fuel oils are used primarily for space heating, in
industrial and commercial boilers and furnaces and for electric power
generation. Diesel fuels are used in on-highway vehicles as well as in
off highway engines, such as locomotives, marine engines, agricultural
and construction equipment.
DOCf means the fraction of DOC that actually decomposes under the
(presumably anaerobic) conditions within the landfill.
Dry lot means a paved or unpaved open confinement area without any
significant vegetative cover where accumulating manure may be removed
periodically.
Electric arc furnace (EAF) means a furnace that produces molten
alloy metal and heats the charge materials with electric arcs from
carbon electrodes.
Electric arc furnace steelmaking means the production of carbon,
alloy, or specialty steels using an EAF. This definition excludes EAFs
at steel foundries and EAFs used to produce nonferrous metals.
Electrical equipment means any item used for the generation,
conversion, transmission, distribution or utilization of electric
energy, such as machines, transformers, apparatus, measuring
instruments, or protective devices, that contains sulfur hexafluoride
(SF6) or perfluorocarbons (PFCs) (including but not limited
to gas-insulated switchgear substations (GIS), gas circuit breakers
(GCB), and power transformers).
Electricity generating unit or EGU means any unit that combusts
solid, liquid, or gaseous fuel and is physically connected to a
generator to produce electricity.
Electrothermic furnace means a furnace that heats the charged
materials with electric arcs from carbon electrodes.
Emergency generator means a stationary internal combustion engine
that serves solely as a secondary source of mechanical or electrical
power whenever the primary energy supply is disrupted or discontinued
during power outages or natural disasters that are beyond the control
of the owner or operator of a facility. Emergency engines operate only
during emergency situations or for standard performance testing
procedures as required by law or by the engine manufacturer. The hours
of operation per calendar year for such standard performance testing
shall not exceed 100 hours. An engine that serves as a back-up power
source under conditions of load shedding, peak shaving, power
interruptions pursuant to an interruptible power service agreement, or
scheduled facility maintenance shall not be considered an emergency
engine.
Engineering estimation means an estimate of fugitive emissions
based on engineering principles applied to measured and/or approximated
physical parameters such as dimensions of containment, actual
pressures, actual temperatures, and compositions.
Equipment means but is not limited to each pump, compressor, pipe,
pressure relief device, sampling connection system, open-ended valve or
line, valve, connector, surge control vessel, tank, vessel, and
instrumentation system in natural gas or liquid service; and any
control devices or systems referenced by this subpart.
Equipment chambers means the total natural gas-containing volume
within any equipment and between the equipment isolation valves.
Ethane (C2H6) is a colorless paraffinic gas
that boils at temperatures of -127.48 [deg]F. It is extracted from
natural gas and from refinery gas streams. Ethane is a major feedstock
for the petrochemical industry.
Ethylene (C2H4) is an olefinic hydrocarbon
received from refinery processes or petrochemical processes. Ethylene
is used as a petrochemical feedstock for numerous chemical applications
and the production of consumer goods.
Ex refinery gate means the point at which a refined or semi-refined
product leaves the refinery.
Experimental furnace means a glass melting furnace with the sole
purpose of operating to evaluate glass melting processes, technologies,
or glass products. An experimental furnace does not produce glass that
is sold (except for further research and development purposes) or that
is used as a raw material for non-experimental furnaces.
Export means to transport a product from inside the United States
to persons outside the United States, excluding United States military
bases and ships for on-board use.
Exporter means any person, company, or organization of record that
contracts to transfer a product from the United States to another
country or that transfers products to an affiliate in another country,
excluding transfers to United States military bases and ships for on-
board use.
Extracted means production of carbon dioxide from carbon dioxide
production wells.
Facility means any physical property, plant, building, structure,
source, or stationary equipment located on one or more contiguous or
adjacent properties in actual physical contact or separated solely by a
public roadway or other public right-of-way and under common ownership
or common control, that emits or may emit any greenhouse gas. Operators
of military installations may classify such installations as more than
a single facility based on distinct and independent functional
groupings within contiguous military properties.
Feed means the prepared and mixed materials, which include but are
not limited to materials such as limestone, clay, shale, sand, iron
ore, mill scale, cement kiln dust and flyash, that are fed to the kiln.
Feed does not include the fuels used in the kiln to produce heat to
form the clinker product.
Feedstock means raw material inputs to a process that are
transformed by reaction, oxidation, or other chemical or physical
methods into products and by-products. Supplemental fuel burned to
provide heat or thermal energy is not a feedstock.
Finished aviation gasoline means a complex mixture of volatile
hydrocarbons, with or without additives, suitably blended to be used in
aviation reciprocating engines. Specifications can be found in ASTM
Specification D910-07a (2002) and Military Specification MIL-G-5572.
Finished motor gasoline means a complex mixture of volatile
hydrocarbons, with or without additives, suitably blended to be used in
spark ignition engines. Motor gasoline, defined in ASTM Specifications
D4814-08a (2001) or Federal Specification VV-G-1690C, has a boiling
range of 122 [deg] to 158 [deg]F at the 10 percent recovery point to
365 [deg] to 374 [deg]F at the 90 percent recovery rate. Motor gasoline
includes, conventional gasoline, reformulated gasoline, and all types
of oxygenated gasoline. Gasoline also has seasonal variations in an
effort to control ozone levels. This is achieved by lowering the Reid
Vapor Pressure (RVP) of gasoline during the summer driving season.
Depending on the region of the country the RVP is lowered to below 9.0
psi or 7.8 psi. The RVP may be further lowered by state regulations.
Fischer-Tropsch process means a catalyzed chemical reaction in
which synthesis gas, a mixture of carbon monoxide and hydrogen, is
converted into liquid hydrocarbons of various forms.
Flare means a combustion device, whether at ground level or
elevated, that uses an open flame to burn combustible gases with
combustion air provided by uncontrolled ambient air around the flame.
[[Page 16621]]
Flare combustion efficiency means the fraction of natural gas, on a
volume or mole basis, that is combusted at the flare burner tip,
assumed 95 percent for non-aspirated field flares and 98 percent for
steam or air asperated flares.
Flare stack means a device used to provide a safe means of
combustible natural gas disposal from routine operations, upsets, or
emergencies via combustion of the natural gas in an open, normally
elevated flame.
Flare stack fugitive emissions means the CH4 and
CO2 content of that portion of natural gas (typically 5
percent in non-aspirated field flares and 2 percent in steam or air
asperated flares) that passes through flares un-combusted and the total
CO2 emissions of that portion of the natural gas that is
combusted.
Flat glass means glass made of soda-lime recipe and produced into
continuous flat sheets and other products listed in NAICS 327211.
Fluid coking unit means one or more refinery process units in which
high molecular weight petroleum derivatives are thermally cracked and
petroleum coke is continuously produced in a fluidized bed system. The
fluid coking unit includes equipment for controlling air pollutant
emissions and for heat recovery on the fluid coking burner exhaust
vent. There are two basic types of fluid coking units: a traditional
fluid coking unit in which only a small portion of the coke produced in
the unit is burned to fuel the unit and the fluid coking burner exhaust
vent is directed to the atmosphere (after processing in a CO boiler or
other air pollutant control equipment) and a flexicoking unit in which
an auxiliary burner is used to partially combust a significant portion
of the produced petroleum coke to generate a low value fuel gas that is
used as fuel in other combustion sources at the refinery.
Fluorinated greenhouse gas means sulfur hexafluoride
(SF6), nitrogen trifluoride (NF3), and any
fluorocarbon except for controlled substances as defined at 40 CFR Part
82 Subpart A. In addition to SF6 and NF3,
``fluorinated GHG'' includes but is not limited to any
hydrofluorocarbon, any perfluorocarbon, any fully fluorinated linear,
branched or cyclic alkane, ether, tertiary amine or aminoether, any
perfluoropolyether, and any hydrofluoropolyether.
Fossil fuel means natural gas, petroleum, coal, or any form of
solid, liquid, or gaseous fuel derived from such material for purpose
of creating useful heat.
Fuel means solid, liquid or gaseous combustible material.
Fuel ethanol (C2H5OH) is an anhydrous alcohol
made either chemically from ethylene or biologically from the
fermentation of sugars from carbohydrates found in agricultural
products. It is used as a gasoline octane enhancer and as an oxygenate
blendstock.
Fuel gas (still gas) means gas generated at a petroleum refinery,
petrochemical plant, or similar industrial process unit, and that is
combusted separately or in any combination with any type of gas.
Fuel gas system means a system of compressors, piping, knock-out
pots, mix drums, and, if necessary, units used to remove sulfur
contaminants from the fuel gas (e.g., amine scrubbers) that collects
fuel gas from one or more sources for treatment, as necessary, and
transport to a stationary combustion unit. A fuel gas system may have
an overpressure vent to a flare but the primary purpose for a fuel gas
system is to provide fuel to the various combustion units at the
refinery or petrochemical plant.
Fuel oil No. 1 has a distillation temperature of 400 [deg]F at the
10 percent recovery point and 550 [deg]F at the 90 percent recovery
point and is used primarily as fuel for portable outdoor stoves and
heaters. It is defined in ASTM D396-08 (2007) Standard Specification
for Fuel Oils.
Fuel oil No. 2 has a distillation temperature of 400 [deg]F at the
10 percent recovery point and 640 [deg]F at the 90 percent recovery
point and is defined in ASTM D396. It is used primarily for residential
heating and for moderate capacity commercial and industrial burner
units.
Fuel oil No. 4 is a distillate fuel oil made by blending distillate
fuel oil and residual fuel oil and conforms to ASTM D396 or Federal
Specification VV-F-815C. and is used extensively in industrial plants
and commercial burner installations that are not equipped with
preheating facilities.
Fugitive emissions means unintentional equipment emissions of
methane and/or carbon dioxide containing natural gas or hydrocarbon gas
(not including combustion flue gas) from emissions sources including,
but not limited to, open ended lines, equipment connections or seals to
the atmosphere. Fugitive emissions also mean CO2 emissions
resulting from combustion of natural gas in flares.
Fugitive emissions detection means the process of identifying
emissions from equipment, components, and other point sources.
Fugitive emissions detection instruments mean any device or
instrument that has been approved for fugitive emissions detection in
this rule, namely infrared fugitive emissions detection instruments,
OVAs, and TVAs.
Gas collection system or landfill gas collection system means a
system of pipes used to collect landfill gas from different locations
in the landfill to a single location for treatment (thermal
destruction) or use. Landfill gas collection systems may also include
knock-out or separator drums and/or a compressor.
Gas conditions mean the actual temperature, volume, and pressure of
a gas sample.
Gas-fired unit means a stationary combustion unit that derives more
than 50 percent of its annual heat input from the combustion of gaseous
fuels, and the remainder of its annual heat input from the combustion
of fuel oil or other liquid fuels.
Gas monitor means an instrument that continuously measures the
concentration of a particular gaseous species in the effluent of a
stationary source.
Gas utilization is the quantity of GHG gas consumed (and therefore
not available for emission) during the etching and/or chamber cleaning
processes.
Gaseous fuel means a material that is in the gaseous state at
standard atmospheric temperature and pressure conditions and that is
combusted to produce heat and/or energy.
Gasification means the conversion of a solid material into a gas.
Gathering and boosting station means a station used to gather
natural gas from well or field pipelines for delivery to a natural gas
processing facility or central point. Stations may also provide
compression, dehydration, and/or treating services.
Glass melting furnace means a unit comprising a refractory-lined
vessel in which raw materials are charged and melted at high
temperature to produce molten glass.
Global warming potential or GWP means the ratio of the time-
integrated radiative forcing from the instantaneous release of one
kilogram (kg) of a trace substance relative to that of one kg of a
reference gas, i.e., CO2.
GPA means the Gas Processors Association.
Greenhouse gas or GHG means carbon dioxide (CO2),
methane (CH4), nitrous oxide (N2O), sulfur
hexafluoride (SF6), hydrofluorocarbons (HFCs),
chlorofluorocarbons (CFCs), perfluorocarbons (PFCs), and other
fluorinated greenhouse gases as defined in this section.
[[Page 16622]]
Heat Transfer Fluids are F-GHGs that are liquid at room
temperature, have appreciable vapor pressures, and are used for
temperature control during certain processes in electronic
manufacturing. Heat transfer fluids used in the electronics sector
include perfluoropolyethers, perfluoroalkanes, perfluoroethers,
tertiary perfluoroamines, and perfluorocyclic ethers.
Heel means the amount of gas that remains in a shipping container
after it is discharged or off-loaded (that is no more than ten percent
of the volume of the container).
High heat value or HHV means the high or gross heat content of the
fuel with the heat of vaporization included. The water is assumed to be
in a liquid state.
High volume sampler means an atmospheric emissions measurement
device that captures emissions from a source in a calibrated air intake
and uses dual hydrocarbon sensors and other devices to measure the flow
rate and combustible hydrocarbon concentrations of the fugitive
emission such that the quantity of emissions is determined.
Hydrofluorocarbons or HFCs means a class of GHGs primarily used as
refrigerants, consisting of hydrogen, fluorine, and carbon.
Import means, with respect to fluorinated GHGs and nitrous oxide,
to land on, bring into, or introduce into, any place subject to the
jurisdiction of the United States whether or not such landing,
bringing, or introduction constitutes an importation within the meaning
of the customs laws of the United States, with the following
exemptions:
(1) Off-loading used or excess fluorinated GHGs or nitrous oxide of
U.S. origin from a ship during servicing,
(2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from
Mexico where the fluorinated GHGs or nitrous oxide had been admitted
into Mexico in bond and were of U.S. origin, and
(3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when
transported in a consignment of personal or household effects or in a
similar non-commercial situation normally exempted from U.S. Customs
attention.
Importer means any person, company, or organization of record that
for any reason brings a product into the United States from a foreign
country. An importer includes the person, company, or organization
primarily liable for the payment of any duties on the merchandise or an
authorized agent acting on their behalf. The term also includes, as
appropriate:
(1) The consignee.
(2) The importer of record.
(3) The actual owner.
(4) The transferee, if the right to draw merchandise in a bonded
warehouse has been transferred.
Indurating furnace means a furnace where unfired taconite pellets,
called green balls, are hardened at high temperatures to produce fired
pellets for use in a blast furnace. Types of indurating furnaces
include straight gate and grate kiln furnaces.
Infrared remote fugitive emissions detection instrument means an
instrument that detects infrared light in the narrow wavelength range
absorbed by light hydrocarbons including methane, and presents a signal
(sound, digital or visual image) indicating the presence of methane and
other light hydrocarbon vapor emissions in the atmosphere. For the
purpose of this rule, it must detect the presence of methane.
In-line kiln/raw mill means a system in a portland cement
production process where a dry kiln system is integrated with the raw
mill so that all or a portion of the kiln exhaust gases are used to
perform the drying operation of the raw mill, with no auxiliary heat
source used. In this system the kiln is capable of operating without
the raw mill operating, but the raw mill cannot operate without the
kiln gases, and consequently, the raw mill does not generate a separate
exhaust gas stream.
Integrated process means a process that produces a petrochemical as
well as one or more other chemicals that are part of other source
categories under this part. An example of an integrated process is the
production of both hydrogen for sale (i.e., a merchant hydrogen
facility) and methanol from synthesis gas created by steam reforming of
methane.
Interstate pipeline means a natural gas pipeline designated as
interstate pipelines under the Natural Gas Act, 15 U.S.C. 717a.
Intrastate pipeline means a natural gas pipeline not subject to the
jurisdiction of the Federal Energy Regulatory Commission as described
in 15 U.S.C. 3301.
Isobutane (C4H10) is a normally gaseous
branch chain hydrocarbon extracted from natural gas or refinery gas
streams. A colorless paraffinic gas that boils at 10.9 [deg]F, it is
used as a feedstock in refineries.
Kerosene-type jet fuel means a kerosene-based product used in
commercial and military turbojet and turboprop aircraft. The product
has a maximum distillation temperature of 400 [deg]F at the 10 percent
recovery point and a final maximum boiling point of 572 [deg]F. It
meets ASTM Specification D1655-08a (2001) and Military Specification
MIL-T-5624P and MIL-T-83133D (JP-5 and JP-8).
Kiln means a device, including any associated preheater or
precalciner devices, that produces clinker by heating limestone and
other materials for subsequent production of portland cement.
Kiln exhaust gas bypass means alkali bypass.
Landfill means an area of land or an excavation in which wastes are
placed for permanent disposal and that is not a land application unit,
surface impoundment, injection well, or waste pile as those terms are
defined under Sec. 257.2 of this chapter.
Landfill gas means gas produced as a result of anaerobic
decomposition of waste materials in the landfill. Landfill gas
generally contains 40 to 60 percent methane on a dry basis, typically
less than 1 percent non-methane organic chemicals, and the remainder
being carbon dioxide.
Lime is the generic term for a variety of chemical compounds that
are produced by the calcination of limestone or dolomite. These
products include but are not limited to calcium oxide, high-calcium
quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and
dolomitic hydrate.
Liquefied natural gas (LNG) means natural gas (primarily methane)
that has been liquefied by reducing its temperature to -260 degrees
Fahrenheit at atmospheric pressure.
Liquefied natural gas import and export facilities mean onshore
and/or offshore facilities that send out exported or receive imported
liquefied natural gas, store it in storage tanks, re-gasify it, and
deliver re-gasified natural gas to natural gas transmission or
distribution systems. The facilities include tanker unloading
equipment, liquefied natural gas transportation pipelines, pumps,
compressors to liquefy boil-off-gas, re-condensers, and vaporization
units for re-gasification of the liquefied natural gas.
Liquefied natural gas storage facilities means an onshore facility
that stores liquefied natural gas in above ground storage vessels. The
facility may include equipment for liquefying natural gas, compressors
to liquefy boil-off-gas, re-condensers, and vaporization units for re-
gasification of the liquefied natural gas.
Liquid/Slurry means manure is stored as excreted or with some
minimal addition of water to facilitate handling
[[Page 16623]]
and is stored in either tanks or earthen ponds, usually for periods
less than one year.
LNG import and export facility fugitive emissions mean natural gas
releases from valves, connectors, storage tanks, flanges, open-ended
lines, pressure relief valves, boil-off-gas recovery, send outs (pumps
and vaporizers), packing and gaskets. This does not include fugitive
emissions from equipment and equipment components reported elsewhere
for this rule.
LNG storage station fugitive emissions mean natural gas releases
from valves, connectors, flanges, open-ended lines, storage tanks,
pressure relief valves, liquefaction process units, packing and
gaskets. This does not include fugitive emissions from equipment and
equipment components reported elsewhere for this rule.
Lubricants include all grades of lubricating oils, from spindle oil
to cylinder oil to those used in greases. Petroleum lubricants may be
produced from distillates or residues.
Makeup chemicals means carbonate chemicals (e.g., sodium and
calcium carbonates) that are added to the chemical recovery areas of
chemical pulp mills to replace chemicals lost in the process.
Mass-balance approach means a method for estimating emissions of
fluorinated greenhouse gases from use in equipment that can be applied
to aggregates of units (for example by system). In this approach,
annual emissions are the difference between the quantity of gas
consumed in the year and the quantity of gas used to fill the net
increase in equipment capacity or to replace destroyed gas.
Maximum rated heat input capacity means the hourly heat input to a
unit (in mmBtu/hr), when it combusts the maximum amount of fuel per
hour that it is capable of combusting on a steady state basis, as of
the initial installation of the unit, as specified by the manufacturer.
Maximum rated input capacity means the maximum amount of municipal
solid waste per day (in tons/day) that a unit is capable of combusting
on a steady state basis as of the initial installation of the unit as
specified by the manufacturer of the unit.
Mcf means thousand cubic feet.
Meter means a device that measures gas flow rate from a fugitive
emissions source or through a conduit by detecting a condition
(pressure drop, spin induction, temperature loss, electronic signal)
that varies in proportion to flow rate or measures gas velocity in a
manner that can calculate flow rate.
Methane conversion factor means the extent to which the
CH4 producing capacity (Bo) is realized in each
type of treatment and discharge pathway and system. Thus, it is an
indication of the degree to which the system is anaerobic.
Methane correction factor means an adjustment factor applied to the
methane generation rate to account for portions of the landfill that
remain aerobic. The methane correction factor can be considered the
fraction of the total landfill waste volume that is ultimately disposed
of in an anaerobic state. Managed landfills that have soil or other
cover materials have a methane correction factor of 1.
Miscellaneous products include all petroleum products not
classified elsewhere. It includes petrolatum lube refining by-products
(aromatic extracts and tars) absorption oils, ram-jet fuel, petroleum
rocket fuels, synthetic natural gas feedstocks, and specialty oils.
MMBtu means million British thermal units.
Municipal solid waste landfill or MSW landfill means an entire
disposal facility in a contiguous geographical space where household
waste is placed in or on land. An MSW landfill may also receive other
types of RCRA Subtitle D wastes (Sec. 257.2 of this chapter) such as
commercial solid waste, nonhazardous sludge, conditionally exempt small
quantity generator waste, and industrial solid waste. Portions of an
MSW landfill may be separated by access roads. An MSW landfill may be
publicly or privately owned.
Municipal solid waste or MSW means solid phase household,
commercial/retail, and/or institutional waste, such as, but not limited
to, yard waste and refuse.
N2O means nitrous oxide.
NAESB is the North American Energy Standards Board.
Nameplate capacity means the full and proper charge of gas
specified by the equipment manufacturer to achieve the equipment's
specified performance. The nameplate capacity is typically indicated on
the equipment's nameplate; it is not necessarily the actual charge,
which may be influenced by leakage and other emissions.
Naphtha-type jet fuel means a fuel in the heavy naphtha boiling
range having an average gravity of 52.8 API and meeting Military
Specification MIL-T-5624L (Grade JP-4). It is used primarily for
military turbojet and turboprop aircraft because it has a lower freeze
point than other aviation fuels and meets engine requirements at high
altitudes and speeds.
Natural gas means a naturally occurring mixture of hydrocarbon and
non-hydrocarbon gases found in geologic formations beneath the earth's
surface, of which its constituents include, but are not limited to,
methane, heavier hydrocarbons and carbon dioxide. Natural gas may be
field quality (which varies widely) or pipeline quality. For the
purposes of this subpart, the definition of natural gas includes
similarly constituted fuels such as field production gas, process gas,
and fuel gas.
Natural gas driven pneumatic manual valve actuator device means
valve control devices that use pressurized natural gas to provide the
energy required for an operator to manually open, close, or throttle a
liquid or gas stream. Typical manual control applications include, but
are not limited to, equipment isolation valves, tank drain valves,
pipeline valves.
Natural gas driven pneumatic manual valve actuator device fugitive
emissions means natural gas released due to manual actuation of natural
gas pneumatic valve actuation devices, including, but not limited to,
natural gas diaphragm and pneumatic-hydraulic valve actuators.
Natural gas driven pneumatic pump means a pump that uses
pressurized natural gas to move a piston or diaphragm, which pumps
liquids on the opposite side of the piston or diaphragm.
Natural gas driven pneumatic pump fugitive emissions means natural
gas released from pumps that are powered or assisted by pressurized
natural gas.
Natural gas driven pneumatic valve bleed device means valve control
devices that use pressurized natural gas to transmit a process
measurement signal to a valve actuator to automatically control the
valve opening. Typical bleeding process control applications include,
but are not limited to, pressure, temperature, liquid level, and flow
rate regulation.
Natural gas driven pneumatic valve bleed devices fugitive emissions
means the continuous or intermittant release of natural gas from
automatic process control loops including the natural gas pressure
signal flowing from a process measurement instrument (e.g. liquid
level, pressure, temperature) to a process control instrument which
activates a process control valve actuator.
Natural gas liquids (NGL) means those hydrocarbons in natural gas
that are separated from the gas as liquids through the process of
absorption, condensation, adsorption, or other methods in gas
processing or cycling
[[Page 16624]]
plants. Generally, such liquids consist of primarily ethane, propane,
butane, and isobutane, primarily pentanes produced from natural gas at
lease separators and field facilities. For the purposes of subpart NN
only, natural gas liquids does not include lease condensate. Bulk NGLs
refers to mixtures of NGLs that are sold or delivered as
undifferentiated product from natural gas processing plants.
Natural gas processing facilities are engaged in the extraction of
natural gas liquids from produced natural gas; fractionation of mixed
natural gas liquids to natural gas products; and removal of carbon
dioxide, sulfur compounds, nitrogen, helium, water, and other
contaminants. Natural gas processing facilities also encompass
gathering and boosting stations that include equipment to phase-
separate natural gas liquids from natural gas, dehydrate the natural
gas, and transport the natural gas to transmission pipelines or to a
processing facility.
Natural gas products means products produced for consumers from
natural gas processing facilities including, but not limited to,
ethane, propane, butane, iso-butane, and pentanes-plus.
Natural gas transmission compression facility means any permanent
combination of compressors that move natural gas at increased pressure
from production fields or natural gas processing facilities, in
transmission pipelines, to natural gas distribution pipelines, or into
storage facilities. In addition, transmission compressor stations may
include equipment for liquids separation, natural gas dehydration, and
storage of water and hydrocarbon liquids.
NIST means the United States National Institute of Standards and
Technology.
Nitric acid production line means a series of reactors and
absorbers used to produce nitric acid.
Nitrogen excreted is the nitrogen that is excreted by livestock in
manure and urine.
Non-crude feedstocks means natural gas liquids, hydrogen and other
hydrocarbons, and petroleum products that are input into the
atmospheric distillation column or other processing units in a refinery
Non-pneumatic pump means any pump that is not pneumatically powered
with pressurized gas of any type, such as natural gas, air, or
nitrogen.
Non-pneumatic pump fugitive emissions means natural gas released
through connectors and flanges of electric motor or engine driven
pumps.
Non-recovery coke oven battery means a group of ovens connected by
common walls and operated as a unit, where coal undergoes destructive
distillation under negative pressure to produce coke, and which is
designed for the combustion of the coke oven gas from which by-products
are not recovered.
Non-steam aspirated flare means a flare where natural gas burns at
the tip with natural induction of air (and relatively lower combustion
efficiency as may be evidenced by smoke formation).
Offshore means tidal-affected borders of the U.S. lands, both state
and Federal, adjacent to oceans, bays, lakes or other normally standing
water.
Offshore petroleum and natural gas production facilities means any
platform structure, floating in the ocean or lake, fixed on ocean or
lake bed, or located on artificial islands in the ocean or lake, that
houses equipment to extract hydrocarbons from ocean floor and
transports it to storage or transport vessels or onshore. In addition,
offshore production facilities may include equipment for separation of
liquids from natural gas components, dehydration of natural gas,
extraction of H2S and CO2 from natural gas, crude
oil and condensate storage tanks, both on the platform structure and
floating storage tanks connected to the platform structure by a
pipeline, and compression or pumping of hydrocarbons to vessels or
onshore. The facilities under consideration are located in both State
administered waters and Mineral Management Services administered
Federal waters.
Offshore platform pipeline fugitive emissions means natural gas
above the water line released from piping connectors, pipe wall
ruptures and holes in natural gas and crude oil pipeline surfaces on
offshore production facilities.
Oil/water separator means equipment used to routinely handle oily-
water streams, including gravity separators or ponds and air flotation
systems.
Oil-fired unit means a stationary combustion unit that derives more
than 50 percent of its annual heat input from the combustion of fuel
oil, and the remainder of its annual heat input from the combustion of
natural gas or other gaseous fuels.
Open-ended line fugitive emissions means natural gas released from
pipes or valves open on one end to the atmosphere that are intended to
periodically vent or drain natural gas to the atmosphere but may also
leak process gas or liquid through incomplete valve closure including
valve seat obstructions or damage.
Open-ended valve or Lines (OELs) means any valve, except pressure
relief valves, having one side of the valve seat in contact with
process fluid and one side open to atmosphere, either directly or
through open piping.
Operating hours means the duration of time in which a process or
process unit is utilized; this excludes shutdown, maintenance, and
standby.
Operating pressure means the containment pressure that
characterizes the normal state of gas and/or liquid inside a particular
process, pipeline, vessel or tank.
Operator means any person who operates or supervises a facility or
supply operation.
Organic monitoring device means an instrument used to indicate the
concentration level of organic compounds exiting a control device based
on a detection principle such as IR, photoionization, or thermal
conductivity.
Organic vapor analyzer (OVA) means an organic monitoring device
that uses a flame ionization detector to measure the concentrations in
air of combustible organic vapors from 9 to 10,000 parts per million
sucked into the probe.
Owner means any person who has legal or equitable title to, has a
leasehold interest in, or control of a facility or supply operation.
Oxygenated gasoline means gasoline which contains a measurable
amount of oxygenate.
Oxygenates means substances which, when added to gasoline increase
the oxygen content of the gasoline. Common oxygenates are ethanol
CH3-CH2OH, Methyl Tertiary Butl Ether
(CH3)3COCH3 (MTBE), Ethyl Tertial Butl
Ether (CH3)3COC2H (ETBE), Tertiary
Amyl Methyl Ether (CH3)(2C2H5)
COCH3 (TAME), Diisopropyl Ether
(CH3)2CHOCH(CH3)2 (DIPE),
and Methanol CH3OH. Lawful use of any of the substances or
any combination of these substances requires that they be
``substantially similar'' under section 211(f)(1) of the Clean Air Act.
Pasture/Range/Paddock means the manure from pasture and range
grazing animals is allowed to lie as deposited, and is not managed.
Pentanes plus is a mixture of hydrocarbons, mostly pentanes and
heavier, extracted from natural gas. Pentanes plus includes isopentane,
natural gasoline, and plant condensate.
Perfluorocarbons or PFCs means a class of greenhouse gases
consisting on the molecular level of carbon and fluorine.
Petrochemical means methanol, acrylonitrile, ethylene, ethylene
oxide,
[[Page 16625]]
ethylene dichloride, and any form of carbon black.
Petrochemical feedstocks means feedstocks derived from petroleum
for the manufacture of chemicals, synthetic rubber, and a variety of
plastics. This category is usually divided into naphtha less than 401
[deg]F and other oils greater than 401 [deg]F.
Petroleum means oil removed from the earth and the oil derived from
tar sands and shale.
Petroleum coke means a black solid residue, obtained mainly by
cracking and carbonizing of petroleum derived feedstocks, vacuum
bottoms, tar and pitches in processes such as delayed coking or fluid
coking. It consists mainly of carbon (90 to 95 percent) and has low ash
content. It is used as a feedstock in coke ovens for the steel
industry, for heating purposes, for electrode manufacture and for
production of chemicals.
Petroleum product means all refined and semi-refined products that
are produced at a refinery by processing crude oil and other petroleum-
based feedstocks, including petroleum products derived from co-
processing biomass and petroleum feedstock together. Petroleum products
may be combusted for energy use, or they may be used either for non-
energy processes or as non-energy products. The definition of petroleum
product for importers and exporters excludes asphalt and road oil,
lubricants, waxes, plastics, and plastics products.
Platform fugitive emissions means natural gas released from
equipment and equipment components including valves, pressure relief
valves, connectors, tube fittings, open-ended lines, ports, and
hatches. This does not include fugitive emissions from equipment and
components reported elsewhere for this rule.
Portable means designed and capable of being carried or moved from
one location to another. Indications of portability include but are not
limited to wheels, skids, carrying handles, dolly, trailer, or
platform. Equipment is not portable if:
(1) The equipment is attached to a foundation.
(2) The equipment or a replacement resides at the same location for
more than 12 consecutive months.
(3) The equipment is located at a seasonal facility and operates
during the full annual operating period of the seasonal facility,
remains at the facility for at least two years, and operates at that
facility for at least three months each year.
(4) The equipment is moved from one location to another in an
attempt to circumvent the portable residence time requirements of this
definition.
Post-coal mining activities means the storage, processing, and
transport of extracted coal.
Poultry manure with litter is similar to cattle and swine deep
bedding except usually not combined with a dry lot or pasture.
Typically used for all poultry breeder flocks and for the production of
meat type chickens (broiler) and other fowl.
Poultry manure without litter systems may manage manure in a liquid
form, similar to open pits in enclosed animal confinement facilities.
These systems may alternatively be designed and operated to dry manure
as it accumulates. The latter is known as a high-rise manure management
system and is a form of passive windrow manure composting when designed
and operated properly.
Precision of a measurement at a specified level (e.g., one percent
of full scale) means that 95 percent of repeat measurements made by a
device or technique fall within the range bounded by the mean of the
measurements plus or minus the specified level.
Pressed and blown glass means glass which is pressed, blown, or
both, into products such as light bulbs, glass fiber, technical glass,
and other products listed in NAICS 327212.
Pressure relief device or pressure relief valve or pressure safety
valve means a safety device used to prevent operating pressures from
exceeding the maximum allowable working pressure of the process
equipment. A common pressure relief device includes, but is not limited
to, a spring-loaded pressure relief valve. Devices that are actuated
either by a pressure of less than or equal to 2.5 psig or by a vacuum
are not pressure relief devices.
Primary product means the product of a process that is produced in
greater mass quantity than any other product of the process.
Process emissions means the emissions from industrial processes
(e.g., cement production, ammonia production) involving chemical or
physical transformations other than fuel combustion. For example, the
calcination of carbonates in a kiln during cement production or the
oxidation of methane in an ammonia process results in the release of
process CO2 emissions to the atmosphere. Emissions from fuel
combustion to provide process heat are not part of process emissions,
whether the combustion is internal or external to the process
equipment.
Process Type, for purposes of electronics manufacturing, means the
kind of electronics manufacturing process, i.e., etching, cleaning, or
chemical vapor deposition using N2O.
Process gas means any gas generated by an industrial process such
as petroleum refining.
Processing facility fugitive emissions means natural gas released
from all components including valves, flanges, connectors, open-ended
lines, pump seals, ESD (emergency shut-down) system fugitive emissions,
packing and gaskets in natural gas processing facilities. This does not
include fugitive emissions from equipment and components reported
elsewhere for this rule, such as compressor fugitive emissions; acid
gas removal, blowdown, wet seal oil degassing, and dehydrator vents;
and flare stacks.
Production process unit means equipment used to capture a carbon
dioxide stream.
Propane means the normally gaseous paraffinic compound
(C3H8), which includes all products covered by
Natural Gas Policy Act Specifications for commercial and HD-5 propane
and ASTM Specification D 1835. It excludes feedstock propanes, which
are propanes not classified as consumer grade propanes, including the
propane portion of any natural gas liquid mixes, i.e., butane-propane
mix.
Propylene (C3H6) is an olefinic hydrocarbon
recovered from refinery processes or petrochemical processes.
Pulp Mill Lime kiln means the combustion units (e.g., rotary lime
kiln or fluidized bed calciner) used at a kraft or soda pulp mill to
calcine lime mud, which consists primarily of calcium carbonate, into
quicklime, which is calcium oxide.
Pump seals means any seal on a pump drive shaft used to keep
methane and/or carbon dioxide containing light liquids from escaping
the inside of a pump case to the atmosphere.
Pump seal fugitive emissions means natural gas released from the
seal face between the pump internal chamber and the atmosphere.
Pushing means the process of removing the coke from the coke oven
at the end of the coking cycle. Pushing begins when coke first begins
to fall from the oven into the quench car and ends when the quench car
enters the quench tower.
Raw mill means a ball and tube mill, vertical roller mill or other
size reduction equipment, that is not part of an in-line kiln/raw mill,
used to grind feed to the appropriate size. Moisture may be added or
removed from the feed during the grinding operation. If the raw mill is
used to remove moisture from feed materials, it is also, by definition,
[[Page 16626]]
a raw material dryer. The raw mill also includes the air separator
associated with the raw mill.
RBOB (reformulated gasoline for oxygenate blending) means a
petroleum product which, when blended with a specified type and
percentage of oxygenate, meets the definition of reformulated gasoline.
Reciprocating compressor means a piece of equipment that increases
the pressure of a process natural gas by positive displacement,
employing linear movement of a shaft driving a piston in a cylinder.
Reciprocating compressor rod packing means a series of flexible
rings in machined metal cups that fit around the reciprocating
compressor piston rod to create a seal limiting the amount of
compressed natural gas that escapes to the atmosphere.
Reciprocating compressor rod packing fugitive emissions means
natural gas released from a connected tubing vent and/or around a
piston rod where it passes through the rod packing case. It also
includes emissions from uncovered distance piece, rod packing flange
(on each cylinder), any packing vents, cover plates (on each cylinder),
and the crankcase breather cap.
Re-condenser means heat exchangers that cool compressed boil-off
gas to a temperature that will condense natural gas to a liquid.
Refined petroleum product means petroleum products produced from
the processing of crude oil, lease condensate, natural gas and other
hydrocarbon compounds
Refinery fuel gas (still gas) means any gas generated at a
petroleum refinery, or any gas generated by a refinery process unit,
that is combusted separately or in any combination with any type of gas
or used as a chemical feedstock.
Reformulated gasoline means any gasoline whose formulation has been
certified under 40 CFR 80.40, and which meets each of the standards and
requirements prescribed under 40 CFR 80.41.
Re-gasification means the process of vaporizing liquefied natural
gas to gaseous phase natural gas.
Research and development process unit means a process unit whose
purpose is to conduct research and development for new processes and
products and is not engaged in the manufacture of products for
commercial sale, except in a de minimis manner.
Residual fuel oil means a classification for the heavier fuel oils,
No. 5 and No. 6. No. 5 is also known as Navy Special and is used in
steam powered vessels in government service and inshore power plants.
No.6 includes Bunker C and is used for the production of electric
power, space heating, vessel bunkering and various industrial purposes.
Residue gas means natural gas from which natural gas processing
facilities liquid products and, in some cases, non-hydrocarbon
components have been extracted.
Rotameter means a flow meter in which gas flow rate upward through
a tapered tube lifts a ``float bob'' to an elevation related to the gas
flow rate indicated by etched calibrations on the wall of the tapered
tube.
Rotary lime kiln means a unit with an inclined rotating drum that
is used to produce a lime product from limestone by calcination.
Semi-refined petroleum product means all oils requiring further
processing. Included in this category are unfinished oils which are
produced by the partial refining of crude oil and include the
following: naphthas and lighter oils; kerosene and light gas oils;
heavy gas oils; and residuum, and all products that require further
processing or the addition of blendstocks.
Sensor means a device that measures a physical quantity/quality or
the change in a physical quantity/quality, such as temperature,
pressure, flow rate, pH, or liquid level.
SF6 means sulfur hexafluoride.
Shutdown means the cessation of operation of an emission source for
any purpose.
Silicon carbide means an artificial abrasive produced from silica
sand or quartz and petroleum coke.
Simulation software means a calibrated, empirical computer program
that uses physical parameters and scientific laws to numerically
simulate the performance variables of a physical process, outputting
such parameters as emission rates from which methane emissions can be
estimated.
Sinter process means a process that produces a fused aggregate of
fine iron-bearing materials suited for use in a blast furnace. The
sinter machine is composed of a continuous traveling grate that conveys
a bed of ore fines and other finely divided iron-bearing material and
fuel (typically coke breeze), a burner at the feed end of the grate for
ignition, and a series of downdraft windboxes along the length of the
strand to support downdraft combustion and heat sufficient to produce a
fused sinter product.
Site means any combination of one or more graded pad sites, gravel
pad sites, foundations, platforms, or the immediate physical location
upon which equipment is physically located.
Smelting furnace means a furnace in which lead-bearing materials,
carbon-containing reducing agents, and fluxes are melted together to
form a molten mass of material containing lead and slag.
Solid storage is the storage of manure, typically for a period of
several months, in unconfined piles or stacks. Manure is able to be
stacked due to the presence of a sufficient amount of bedding material
or loss of moisture by evaporation.
Sour natural gas means natural gas that contains significant
concentrations of hydrogen sulfide and/or carbon dioxide that exceed
the concentrations specified for commercially saleable natural gas
delivered from transmission and distribution pipelines.
Special naphthas means all finished products with the naphtha
boiling range (290[deg] to 470 [deg]F) that are used as paint thinners,
cleaners or solvents.
Spent liquor solids means the dry weight of the solids in the spent
pulping liquor that enters the chemical recovery furnace or chemical
recovery combustion unit.
Spent pulping liquor means the residual liquid collected from on-
site pulping operations at chemical pulp facilities that is
subsequently fired in chemical recovery furnaces at kraft and soda pulp
facilities or chemical recovery combustion units at sulfite or semi-
chemical pulp facilities.
Standard conditions or standard temperature and pressure (STP)
means 60 degrees Fahrenheit and 14.7 pounds per square inch absolute.
Standby means for an equipment to be in a state ready for
operation, but not operating.
Steam aspirated flare means steam injected into the flare burner
tip to induce air mixing with the hydrocarbon fuel to promote more
complete combustion as indicated by lack of smoke formation.
Steam reforming means a catalytic process that involves a reaction
between natural gas or other light hydrocarbons and steam. The result
is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.
Storage station fugitive emissions means natural gas released from
all components including valves, flanges, connectors, open-ended lines,
pump seals, ESD (emergency shut-down) system emissions, packing and
gaskets in natural gas storage station. This does not include fugitive
emissions from equipment and equipment components reported elsewhere
for this rule.
Storage tank means other vessel that is designed to contain an
accumulation of crude oil, condensate, intermediate
[[Page 16627]]
hydrocarbon liquids, or produced water and that is constructed entirely
of non-earthen materials (e.g., wood, concrete, steel, plastic) that
provide structural support.
Storage tank fugitive emissions means natural gas vented when it
flashes out of liquids; this occurs when liquids are transferred from
higher pressure and temperature conditions upstream, plus working
losses from liquid level increases and decreases during filling and
draining and standing losses (breathing losses) from diurnal
temperature changes and barometric pressure changes expanding and
contracting the vapor volume of a tank.
Storage wellhead fugitive emissions means natural gas released from
storage station wellhead components including but not limited to
valves, OELs, connectors, flanges, and tube fittings.
Sub-surface or subsurface facility means for the purposes of this
rule, a natural gas facility, such as a pipeline and metering and
regulation station in a closed vault below the land surface of the
Earth.
Sulfur recovery plant means all process units which recover sulfur
or produce sulfuric acid from hydrogen sulfide (H2S) and/or
sulfur dioxide (SO2) at a petroleum refinery. The sulfur
recovery plant also includes sulfur pits used to store the recovered
sulfur product, but it does not include secondary sulfur storage
vessels downstream of the sulfur pits. For example, a Claus sulfur
recovery plant includes: Reactor furnace and waste heat boiler,
catalytic reactors, sulfur pits, and, if present, oxidation or
reduction control systems, or incinerator, thermal oxidizer, or similar
combustion device.
Supplemental fuel means a fuel burned within a petrochemical
process that is not produced within the process itself.
Supplier means a producer, importer, or exporter of a fossil fuel
or an industrial greenhouse gas.
Taconite iron ore processing means an industrial process that
separates and concentrates iron ore from taconite, a low grade iron
ore, and heats the taconite in an indurating furnace to produce
taconite pellets that are used as the primary feed material for the
production of iron in blast furnaces at integrated iron and steel
plants.
Tanker unloading means pumping of liquid hydrocarbon (e.g., crude
oil, LNG) from an ocean-going tanker or barge to shore storage tanks.
Toxic vapor analyzer (TVA) means an organic monitoring device that
uses a flame ionization detector and photoionization detector to
measure the concentrations in air of combustible organic vapors from 9
parts per million and exceeding 10,000 parts per million sucked into
the probe.
Trace concentrations means concentrations of less than 0.1 percent
by mass of the process stream.
Trained technician means a person who has completed a vendor
provided or equivalent training program and demonstrated proficiency to
use specific equipment for its intended purpose, such as high volume
sampler for the purposes of this rule.
Transform means to use and entirely consume (except for trace
concentrations) nitrous oxide or fluorinated GHGs in the manufacturing
of other chemicals for commercial purposes. Transformation does not
include burning of nitrous oxide.
Transshipment means the continuous shipment of nitrous oxide or a
fluorinated GHG from a foreign state of origin through the United
States or its territories to a second foreign state of final
destination, as long as the shipment does not enter into United States
jurisdiction. A transshipment, as it moves through the United States or
its territories, cannot be re-packaged, sorted or otherwise changed in
condition.
Transmission compressor station fugitive emissions means natural
gas released from all components including but not limited to valves,
flanges, connectors, open-ended lines, pump seals, ESD (emergency shut-
down) system emissions, packing and gaskets in natural gas transmission
compressor stations. This does not include fugitive emissions from
equipment and equipment components reported elsewhere for this rule,
such as compressor fugitive emissions.
Transmission pipeline means high pressure cross country pipeline
transporting saleable quality natural gas from production or natural
gas processing to natural gas distribution pressure let-down, metering,
regulating stations where the natural gas is typically odorized before
delivery to customers.
Trona means the raw material (mineral) used to manufacture soda
ash; hydrated sodium bicarbonate carbonate
(NaCO3.NaHCO3.2H2O).
Turbine meter means a flow meter in which a gas or liquid flow rate
through the calibrated tube spins a turbine from which the spin rate is
detected and calibrated to measure the fluid flow rate.
Ultimate analysis means the determination of the percentages of
carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference)
oxygen in the gaseous products and ash after the complete combustion of
a sample of an organic material.
Uncovered anaerobic lagoons are a type of liquid storage system
designed and operated to combine waste stabilization and storage.
Lagoon supernatant is usually used to remove manure from the associated
confinement facilities to the lagoon. Anaerobic lagoons are designed
with varying lengths of storage (up to a year or greater), depending on
the climate region, the volatile solids loading rate, and other
operational factors. The water from the lagoon may be recycled as flush
water or used to irrigate and fertilize fields.
Underground natural gas storage facility means a subsurface
facility, including but not limited to depleted gas or oil reservoirs
and salt dome caverns, utilized for storing natural gas that has been
transferred from its original location for the primary purpose of load
balancing, which is the process of equalizing the receipt and delivery
of natural gas. Processes and operations that may be located at a
natural gas underground storage facility include, but are not limited
to, compression, dehydration and flow measurement. The storage facility
also includes all the wellheads connected to the compression units
located at the facility.
United States means the 50 states, the District of Columbia, and
U.S. possessions and territories.
Unstabilized crude oil means, for the purposes of this subpart,
crude oil that is pumped from the well to a pipeline or pressurized
storage vessel for transport to the refinery without intermediate
storage in a storage tank at atmospheric pressures. Unstabilized crude
oil is characterized by having a true vapor pressure of 5 pounds per
square inch absolute (psia) or greater.
Valve means any device for halting or regulating the flow of a
liquid or gas through a passage, pipeline, inlet, outlet, or orifice;
including, but not limited to, gate, globe, plug, ball, butterfly and
needle valves.
Vapor recovery system means any equipment located at the source of
potential gas emissions to the atmosphere or to a flare, that is
composed of piping, connections, and, if necessary, flow-inducing
devices; and that is used for routing the gas back into the process as
a product and/or fuel.
Vaporization unit means a process unit that performs controlled
heat input to vaporize liquefied natural gas to supply transmission and
distribution pipelines, or consumers with natural gas.
[[Page 16628]]
Ventilation system means a system deployed within a mine to ensure
that CH4 levels remain within safe concentrations.
Volatile solids are the organic material in livestock manure and
consist of both biodegradable and non-biodegradable fractions.
Waelz kiln means an inclined rotary kiln in which zinc-containing
materials are charged together with a carbon reducing agent (e.g.,
petroleum coke, metallurgical coke, or anthracite coal).
Waste feedstocks are non-crude feedstocks that have been
contaminated, downgraded, or no longer meet the specifications of the
product category or end-use for which they were intended. Waste
feedstocks include but are not limited to: Used plastics, used engine
oils, used dry cleaning solvents, and trans-mix (mix of products at the
interface in delivery pipelines).
Waxes means a solid or semi-solid material at 77 [deg]F consisting
of a mixture of hydrocarbons obtained or derived from petroleum
fractions, or through a Fischer-Tropsch type process, in which the
straight chained paraffin series predominates.
Wellhead means the piping, casing, tubing and connected valves
protruding above the Earth's surface for an oil and/ or natural gas
well. The wellhead ends where the flow line connects to a wellhead
valve.
Wet natural gas means natural gas in which water vapor exceeds the
concentration specified for commercially saleable natural gas delivered
from transmission and distribution pipelines. This input stream to a
natural gas dehydrator is referred to as ``wet gas''.
Wool fiberglass means fibrous glass of random texture, including
fiberglass insulation, and other products listed in NAICS 327993.
You means the owner or operator subject to Part 98.
Zinc smelters means a facility engaged in the production of zinc
metal, zinc oxide, or zinc alloy products from zinc sulfide ore
concentrates, zinc calcine, or zinc-bearing scrap and recycled
materials through the use of pyrometallurgical techniques involving the
reduction and volatization of zinc-bearing feed materials charged to a
furnace.
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
The materials listed in this section are incorporated by reference
for use in this part and are incorporated as they existed on the date
of approval of this part.
(a) The following materials are available for purchase from the
following addresses: American Society for Testing and Material (ASTM),
100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania
19428-B2959; and the University Microfilms International, 300 North
Zeeb Road, Ann Arbor, Michigan 48106:
(1) ASTM D240-02, (Reapproved 2007), Standard Test Method for Heat
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter.
(2) ASTM D388-05, Standard Classification of Coals by Rank.
(3) ASTM D396-08, Standard Specification for Fuel Oils.
(4) ASTM D975-08, Standard Specification for Diesel Fuel Oils.
(5) ASTM D1250-07, Standard Guide for Use of the Petroleum
Measurement Tables.
(6) ASTM D1826-94 (Reapproved 2003), Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter.
(7) ASTM Specification D1835-05 (2005).
(8) ASTM D1945-03 (Reapproved 2006), Standard Test Method for
Analysis of Natural Gas by Gas Chromatography.
(9) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis
of Reformed Gas by Gas Chromatography.
(10) ASTM D2013-07, Standard Practice of Preparing Coal Samples for
Analysis.
(11) ASTM D2234/D2234M-07, Standard Practice for Collection of a
Gross Sample of Coal.
(12) ASTM D2502-04 (Reapproved 2002), Standard Test Method for
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum
Oils from Viscosity Measurements.
(13) ASTM D2503-92 (Reapproved 2007), Standard Test Method for
Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure.
(14) ASTM D2880-03, Standard Specification for Gas Turbine Fuel
Oils.
(15) ASTM D3176-89 (Reapproved 2002), Standard Practice for
Ultimate Analysis of Coal and Coke.
(16) ASTM D3238-95 (Reapproved 2005), Standard Test Method for
Calculation of Carbon Distribution and Structural Group Analysis of
Petroleum Oils by the n-d-M Method.
(17) ASTM D3588-98 (Reapproved 2003), Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels.
(18) ASTM Specification D3699-07, Standard Specification for
Kerosene.
(19) ASTM D4057-06, Standard Practice for Manual Sampling of
Petroleum and Petroleum Products.
(20) ASTM D4809-06, Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method).
(21) ASTM Specification D4814-08a, Standard Specification for
Automotive Spark-Ignition Engine Fuel.
(22) ASTM D4891-89 (Reapproved 2006), Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion.
(23) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants.
(24) ASTM D5373-08, Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal and Coke.
(25) ASTM D5865-07a, Standard Test Method for Gross Calorific Value
of Coal and Coke.
(26) ASTM D6316-04, Standard Test Method for the Determination of
Total, Combustible and Carbonate Carbon in Solid Residues from Coal and
Coke.
(27) ASTM D6866-06a, Standard Test Methods for Determining the
Biobased Content of Natural Range Materials Using Radiocarbon and
Isotope Ratio Mass Spectrometry Analysis.
(28) ASTM E1019-03, Standard Test Methods for Determination of
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and
Cobalt Alloys.
(29) ASTM E1915-07a, Standard Test Methods for Analysis of Metal
Bearing Ores and Related Materials by Combustion Infrared-Absorption
Spectrometry.
(30) ASTM CS-104 (1985), Carbon Steel of Medium Carbon Content.
(31) ASTM D 7459-08, Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources.
(32) ASTM D6060-96(2001) Standard Practice for Sampling of Process
Vents With a Portable Gas Chromatograph.
(33) ASTM D 2502-88(2004)e1 Standard Test Method for Ethylene,
Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas
Chromatography.
(34) ASTM C25-06 Standard Test Method for Chemical Analysis of
Limestone, quicklime, and Hydrated Lime.
(35) UOP539-97 Refinery Gas Analysis by Gas Chromatography.
(b) The following materials are available for purchase from the
American Society of Mechanical
[[Page 16629]]
Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, NJ 07007-
2900:
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi.
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by
Turbine Meters.
(3) ASME-MFC-5M-1985, (Reaffirmed 1994), Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters.
(4) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters.
(5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles.
(6) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow
in Closed Conduits by Weighing Method.
(c) The following materials are available for purchase from the
American National Standards Institute (ANSI), 25 West 43rd Street,
Fourth Floor, New York, New York 10036:
(1) ISO 8316: 1987 Measurement of Liquid Flow in Closed Conduits--
Method by Collection of the Liquid in a Volumetric Tank.
(2) ISO/TR 15349-1:1998, Unalloyed steel--Determination of low
carbon content. Part 1: Infrared absorption method after combustion in
an electric resistance furnace (by peak separation).
(3) ISO/TR 15349-3: 1998, Unalloyed steel--Determination of low
carbon content. Part 3: Infrared absorption method after combustion in
an electric resistance furnace (with preheating).
(d) The following materials are available for purchase from the
following address: Gas Processors Association (GPA), 6526 East 60th
Street, Tulsa, Oklahoma 74143:
(1) GPA Standard 2172-96, Calculation of Gross Heating Value,
Relative Density and Compressibility Factor for Natural Gas Mixtures
from Compositional Analysis.
(2) GPA Standard 2261-00, Analysis for Natural Gas and Similar
Gaseous Mixtures by Gas Chromatography.
(e) The following American Gas Association materials are available
for purchase from the following address: ILI Infodisk, 610 Winters
Avenue, Paramus, New Jersey 07652:
(1) American Gas Association Report No. 3: Orifice Metering of
Natural Gas, Part 1: General Equations and Uncertainty Guidelines
(1990), Part 2: Specification and Installation Requirements (1990).
(2) American Gas Association Transmission Measurement Committee
Report No. 7: Measurement of Gas by Turbine Meters (2006).
(f) The following materials are available for purchase from the
following address: American Petroleum Institute, Publications
Department, 1220 L Street, NW., Washington, DC 20005-4070:
(1) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 3--Tank Gauging:
(i) Section 1A, Standard Practice for the Manual Gauging of
Petroleum and Petroleum Products, Second Edition, August 2005.
(ii) Section 1B--Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second
Edition June 2001 (Reaffirmed, October 2006).
(iii) Section 3--Standard Practice for Level Measurement of Liquid
Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank
Gauging, First Edition June 1996 (Reaffirmed, October 2006).
(2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B,
December 1961 (Reaffirmed August 1987, October 1992).
(3) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 4--Proving Systems:
(i) Section 2--Displacement Provers, Third Edition, September 2003.
(ii) Section 5--Master-Meter Provers, Second Edition, May 2000
(Reaffirmed, August 2005).
(4) American Petroleum Institute (API) Manual of Petroleum
Measurement Standards, Chapter 22--Testing Protocol, Section 2--
Differential Pressure Flow Measurement Devices, First Edition, August
2005.
(g) The following material is available for purchase from the
following address: American Society of Heating, Refrigerating and Air-
Conditioning Engineers, Inc., 1791 Tullie Circle, NE., Atlanta, Georgia
30329.
(1) ASHRAE 41.8-1989: Standard Methods of Measurement of Flow of
Liquids in Pipes Using Orifice Flowmeters.
Sec. 98.8 What are the compliance and enforcement provisions of this
part?
Any violation of the requirements of this part shall be a violation
of the Clean Air Act. A violation includes, but is not limited to,
failure to report GHG emissions, failure to collect data needed to
calculate GHG emissions, failure to continuously monitor and test as
required, failure to retain records needed to verify the amount of GHG
emission, and failure to calculate GHG emissions following the
methodologies specified in this part. Each day of a violation
constitutes a separate violation.
Table A-1 of Subpart A--Global Warming Potentials (100-Year Time Horizon)
----------------------------------------------------------------------------------------------------------------
Global warming
Name CAS No. Chemical formula potential (100
yr.)
----------------------------------------------------------------------------------------------------------------
Carbon dioxide................................ 124-38-9 CO2............................. 1
Methane....................................... 74-82-8 CH4............................. 21
Nitrous oxide................................. 10024-97-2 N2O............................. 310
HFC-23........................................ 75-46-7 CHF3............................ 11,700
HFC-32........................................ 75-10-5 CH2F2........................... 650
HFC-41........................................ 593-53-3 CH3F............................ 150
HFC-125....................................... 354-33-6 C2HF5........................... 2,800
HFC-134....................................... 359-35-3 C2H2F4.......................... 1,000
HFC-134a...................................... 811-97-2 CH2FCF3......................... 1,300
HFC-143....................................... 430-66-0 C2H3F3.......................... 300
HFC-143a...................................... 420-46-2 C2H3F3.......................... 3,800
HFC-152....................................... 624-72-6 CH2FCH2F........................ 53
HFC-152a...................................... 75-37-6 CH3CHF2......................... 140
HFC-161....................................... 353-36-6 CH3CH2F......................... 12
HFC-227ea..................................... 431-89-0 C3HF7........................... 2,900
HFC-236cb..................................... 677-56-5 CH2FCF2CF3...................... 1,340
HFC-236ea..................................... 431-63-0 CHF2CHFCF3...................... 1,370
[[Page 16630]]
HFC-236fa..................................... 690-39-1 C3H2F6.......................... 6,300
HFC-245ca..................................... 679-86-7 C3H3F5.......................... 560
HFC-245fa..................................... 460-73-1 CHF2CH2CF3...................... 1,030
HFC-365mfc.................................... 406-58-6 CH3CF2CH2CF3.................... 794
HFC-43-10mee.................................. 138495-42-8 CF3CFHCFHCF2CF3................. 1,300
Sulfur hexafluoride........................... 2551-62-4 SF6............................. 23,900
Trifluoromethyl sulphur pentafluoride......... 373-80-8 SF5CF3.......................... 17,700
Nitrogen trifluoride.......................... 7783-54-2 NF3............................. 17,200
PFC-14 (Perfluoromethane)..................... 75-73-0 CF4............................. 6,500
PFC-116 (Perfluoroethane)..................... 76-16-4 C2F6............................ 9,200
PFC-218 (Perfluoropropane).................... 76-19-7 C3F8............................ 7,000
Perfluorocyclopropane......................... 931-91-9 c-C3F6.......................... 17,340
PFC-3-1-10 (Perfluorobutane).................. 355-25-9 C4F10........................... 7,000
Perfluorocyclobutane.......................... 115-25-3 c-C4F8.......................... 8,700
PFC-4-1-12 (Perfluoropentane)................. 678-26-2 C5F12........................... 7,500
PFC-5-1-14 (Perfluorohexane).................. 355-42-0 C6F14........................... 7,400
PFC-9-1-18.................................... 306-94-5 C10F18.......................... 7,500
HCFE-235da2 (Isoflurane)...................... 26675-46-7 CHF2OCHClCF3.................... 350
HFE-43-10pccc (H-Galden 1040x)................ NA CHF2OCF2OC2F4OCHF2.............. 1,870
HFE-125....................................... 3822-68-2 CHF2OCF3........................ 14,900
HFE-134....................................... 1691-17-4 CHF2OCHF2....................... 6,320
HFE-143a...................................... 421-14-7 CH3OCF3......................... 756
HFE-227ea..................................... 2356-62-9 CF3CHFOCF3...................... 1,540
HFE-236ca12 (HG-10)........................... NA CHF2OCF2OCHF2................... 2,800
HFE-236ea2 (Desflurane)....................... 57041-67-5 CHF2OCHFCF3..................... 989
HFE-236fa..................................... 20193-67-3 CF3CH2OCF3...................... 487
HFE-245cb2.................................... 22410-44-2 CH3OCF2CF3...................... 708
HFE-245fa1.................................... NA CHF2CH2OCF3..................... 286
HFE-245fa2.................................... 1885-48-9 CHF2OCH2CF3..................... 659
HFE-254cb2.................................... 425-88-7 CH3OCF2CHF2..................... 359
HFE-263fb2.................................... 460-43-5 CF3CH2OCH3...................... 11
HFE-329mcc2................................... 67490-36-2 CF3CF2OCF2CHF2.................. 919
HFE-338mcf2................................... 156-05-3 CF3CF2OCH2CF3................... 552
HFE-338pcc13 (HG-01).......................... NA CHF2OCF2CF2OCHF2................ 1,500
HFE-347mcc3................................... 28523-86-6 CH3OCF2CF2CF3................... 575
HFE-347mcf2................................... NA CF3CF2OCH2CHF2.................. 374
HFE-347pcf2................................... 406-78-0 CHF2CF2OCH2CF3.................. 580
HFE-356mec3................................... 382-34-3 CH3OCF2CHFCF3................... 101
HFE-356pcc3................................... NA CH3OCF2CF2CHF2.................. 110
HFE-356pcf2................................... NA CHF2CH2OCF2CHF2................. 265
HFE-356pcf3................................... 35042-99-0 CHF2OCH2CF2CHF2................. 502
HFE-365mcf3................................... NA CF3CF2CH2OCH3................... 11
HFE-374pc2.................................... 512-51-6 CH3CH2OCF2CHF2.................. 557
HFE-449sl (HFE-7100) Chemical blend........... 163702-07-6 C4F9OCH3........................ 297
163702-08-7 (CF3)2CFCF2OCH3.................
HFE-569sf2 (HFE-7200) Chemical blend.......... 163702-05-4 C4F9OC2H5....................... 59
163702-06-5 (CF3)2CFCF2OC2H5................
Sevoflurane................................... 28523-86-6 CH2FOCH(CF3)2................... 345
NA............................................ 13171-18-1 (CF3)2CHOCH3.................... 27
NA............................................ 26103-08-2 CHF2OCH(CF3)2................... 380
NA............................................ NA -(CF2)4CH(OH)-.................. 73
NA............................................ NA CH3OCF(CF3)2.................... 343
NA............................................ NA (CF3)2CHOH...................... 195
NA............................................ NA CF3CF2CH2OH..................... 42
PFPMIE........................................ NA CF3OCF(CF3)CF2OCF2OCF3.......... 10,300
----------------------------------------------------------------------------------------------------------------
NA = not available.
Table A-2 of Subpart A--Units of Measure Conversions
----------------------------------------------------------------------------------------------------------------
To convert from To Multiply by
----------------------------------------------------------------------------------------------------------------
Kilograms (kg)......................... Pounds (lbs).............. 2.20462.
Pounds (lbs)........................... Kilograms (kg)............ 0.45359.
Pounds (lbs)........................... Metric tons............... 4.53592 x 10-4.
Short tons............................. Pounds (lbs).............. 2,000.
Short tons............................. Metric tons............... 0.90718.
Metric tons............................ Short tons................ 1.10231.
Metric tons............................ Kilograms (kg)............ 1,000.
Cubic meters (m\3\).................... Cubic feet (ft\3\)........ 35.31467.
[[Page 16631]]
Cubic feet (ft\3\)..................... Cubic meters (m\3\)....... 0.028317.
Gallons (liquid, US)................... Liters (l)................ 3.78541.
Liters (l)............................. Gallons (liquid, US)...... 0.26417.
Barrels of Liquid Fuel (bbl)........... Cubic meters (m\3\)....... 0.15891.
Cubic meters (m\3\).................... Barrels of Liquid Fuel 6.289.
(bbl).
Barrels of Liquid Fuel (bbl)........... Gallons (liquid, US)...... 42.
Gallons (liquid, US)................... Barrels of Liquid Fuel 0.023810.
(bbl).
Gallons (liquid, US)................... Cubic meters (m\3\)....... 0.0037854.
Liters (l)............................. Cubic meters (m\3\)....... 0.001.
Feet (ft).............................. Meters (m)................ 0.3048.
Meters (m)............................. Feet (ft)................. 3.28084.
Miles (mi)............................. Kilometers (km)........... 1.60934.
Kilometers (km)........................ Miles (mi)................ 0.62137.
Square feet (ft\2\).................... Acres..................... 2.29568 x 10-5.
Square meters (m\2\)................... Acres..................... 2.47105 x 10-4.
Square miles (mi\2\)................... Square kilometers (km\2\). 2.58999.
Degrees Celsius ([deg]C)............... Degrees Fahrenheit [deg]C = (5/9) x ([deg]F-32).
([deg]F).
Degrees Fahrenheit ([deg]F)............ Degrees Celsius ([deg]C).. [deg]F = (9/5) x [deg]C + 32.
Degrees Celsius ([deg]C)............... Kelvin (K)................ K = [deg]C + 273.15.
Kelvin (K)............................. Degrees Rankine ([deg]R).. 1.8.
Joules................................. Btu....................... 9.47817 x 10-4.
Btu.................................... MMBtu..................... 1 x 10-6.
Pascals (Pa)........................... Inches of Mercury (in Hg). 2.95334 x 10-4.
Inches of Mercury (inHg)............... Pounds per square inch 0.49110.
(psi).
Pounds per square inch (psi)........... Inches of Mercury (in Hg). 2.03625.
----------------------------------------------------------------------------------------------------------------
Subpart B--[Reserved]
Subpart C--General Stationary Fuel Combustion Sources
Sec. 98.30 Definition of the source category.
(a) Stationary fuel combustion sources are devices that combust
solid, liquid, or gaseous fuel, generally for the purposes of producing
electricity, generating steam, or providing useful heat or energy for
industrial, commercial, or institutional use, or reducing the volume of
waste by removing combustible matter. Stationary fuel combustion
sources include, but are not limited to, boilers, combustion turbines,
engines, incinerators, and process heaters.
(b) This source category does not include portable equipment or
generating units designated as emergency generators in a permit issued
by a state or local air pollution control agency.
Sec. 98.31 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains one or more stationary combustion sources and the facility
meets the requirements of either Sec. 98.2(a)(1), (2), or (3).
Sec. 98.32 GHGs to report.
You must report CO2, CH4, and N2O
mass emissions from each stationary fuel combustion unit.
Sec. 98.33 Calculating GHG emissions.
The owner or operator shall use the methodologies in this section
to calculate the GHG emissions from stationary fuel combustion sources,
except for electricity generating units that are subject to the Acid
Rain Program. The GHG emissions calculation methods for Acid Rain
Program units are addressed in subpart D of this part.
(a) CO2 emissions from fuel combustion. For each stationary fuel
combustion unit, the owner or operator shall use the four-tiered
approach in this paragraph, subject to the conditions, requirements,
and restrictions set forth in paragraph (b) of this section.
(1) Tier 1 Calculation Methodology. Calculate the annual
CO2 mass emissions for a particular type of fuel combusted
in a unit, by substituting a fuel-specific default CO2
emission factor (from Table C-1 of this subpart), a default high
heating value (from Table C-1 of this subpart), and the annual fuel
consumption (from company records kept as provided in this rule) into
the Equation C-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.002
Where:
CO2 = Annual CO2 mass emissions for the
specific fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company
records (express mass in short tons for solid fuel, volume in
standard cubic feet for gaseous fuel, and volume in gallons for
liquid fuel).
HHV = Default high heat value of the fuel, from Table C-1 of this
subpart (mmBtu per mass or mmBtu per volume, as applicable).
EF = Fuel-specific default CO2 emission factor, from
Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(2) Tier 2 Calculation Methodology. Calculate the annual
CO2 mass emissions for a particular type of fuel combusted
in a unit, by substituting measured high heat values, a default
CO2 emission factor (from Table C-1 or Table C-2 of this
subpart), and the quantity of fuel combusted (from company records kept
as provided in this rule) into the following equations:
(i) Equation C-2a of this section applies to any type of fuel,
except for municipal solid waste (MSW):
[[Page 16632]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.003
Where:
CO2 = Annual CO2 mass emissions for a specific
fuel type (metric tons).
n = Number of required heat content measurements for the year.
(Fuel)p = Mass or volume of the fuel combusted during the
measurement period ``p'' (express mass in short tons for solid fuel,
volume in standard cubic feet for gaseous fuel, and volume in
gallons for liquid fuel).
p = Measurement period (month).
(HHV)p = High heat value of the fuel for the measurement
period (mmBtu per mass or volume).
EF = Fuel-specific default CO2 emission factor, from
Table C-1 or C-2 of this subpart (kg CO2/mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(ii) In Equation C-2a of this section, the value of ``n'' depends
upon the frequency at which high heat value (HHV) measurements are
required under Sec. 98.34(c). For example, for natural gas, which
requires monthly sampling and analysis, n = 6 if the unit combusts
natural gas in only 6 months of the year.
(iii) For MSW combustion, use Equation C-2b of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.004
Where:
CO2 = Annual CO2 mass emissions from MSW
combustion (metric tons).
Steam = Total mass of steam generated by MSW combustion during the
reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its
design rated steam output capacity (mmBtu/lb steam).
EF = Default CO2 emission factor for MSW, from Table C-3
of this subpart (kg CO2/mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(3) Tier 3 Calculation Methodology. Calculate the annual
CO2 mass emissions for a particular type of fuel combusted
in a unit, by substituting measurements of fuel carbon content,
molecular weight (gaseous fuels, only), and the quantity of fuel
combusted into the following Equations. For solid fuels, the amount of
fuel combusted is obtained from company records kept as provided in
this rule. For liquid and gaseous fuels, the volume of fuel combusted
is measured directly, using fuel flow meters (including gas billing
meters). For fuel oil, tank drop measurements may also be used.
(i) For a solid fuel, use Equation C-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.005
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific solid fuel (metric tons).
N = Number of required carbon content determinations for the year.
(Fuel)n = Mass of the solid fuel combusted in month ``n''
(metric tons).
P = Measurement period (month).
(CC)n = Carbon content of the solid fuel, from the fuel
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
(ii) For a liquid fuel, use Equation C-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.006
Where:
CO2 = Annual CO2 mass emissions from the
combustion of the specific liquid fuel (metric tons).
N = Number of required carbon content determinations for the year.
(Fuel)n = Volume of the liquid fuel combusted in month
``n'' (gallons).
P = Measurement period (month).
(CC)n = Carbon content of the liquid fuel, from the fuel
analysis results for month ``n'' (kg C per gallon of fuel).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(iii) For a gaseous fuel, use Equation C-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.007
Where:
CO2 = Annual CO2 mass emissions from
combustion of the specific gaseous fuel (metric tons).
N = Number of required carbon content and molecular weight
determinations for the year.
(Fuel)n = Volume of the gaseous fuel combusted on day
``n'' or in month ``n'', as applicable (scf).
P = Measurement period (month or day, as applicable).
[[Page 16633]]
(CC)n = Average carbon content of the gaseous fuel, from
the fuel analysis results for the day or month, as applicable (kg C
per kg of fuel).
MW = Molecular weight of the gaseous fuel, from fuel analysis (kg/
kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(iv) In applying Equation C-5 of this section to natural gas
combustion, the CO2 mass emissions are calculated only for
those months in which natural gas is combusted during the reporting
year. For the combustion of other gaseous fuels (e.g., refinery gas or
process gas), the CO2 mass emissions are calculated only for
those days on which the gaseous fuel is combusted during the reporting
year. For example, if the unit combusts process gas on 250 of the 365
days in the year, then n = 250 in Equation C-5 of this section.
(4) Tier 4 Calculation Methodology. Calculate the annual
CO2 mass emissions from all fuels combusted in a unit, by
using quality-assured data from continuous emission monitoring systems
(CEMS).
(i) This methodology requires a CO2 concentration
monitor and a stack gas volumetric flow rate monitor, except as
otherwise provided in paragraph (a)(1)(iv)(D) of this section. Hourly
measurements of CO2 concentration and stack gas flow rate
are converted to CO2 mass emission rates in metric tons per
hour.
(ii) When the CO2 concentration is measured on a wet
basis, Equation C-6 of this section is used to calculate the hourly
CO2 emission rates:
[GRAPHIC] [TIFF OMITTED] TP10AP09.008
Where:
CO2 = CO2 mass emission rate (metric tons/hr).
CCO2 = Hourly average CO2 concentration (%
CO2).
Q = Hourly average stack gas volumetric flow rate (scfh).
5.18 x 10-\7\ = Conversion factor (tons/scf-%
CO2).
(iii) If the CO2 concentration is measured on a dry
basis, a correction for the stack gas moisture content is required. The
owner or operator shall either continuously monitor the stack gas
moisture content as described in Sec. 75.11(b)(2) of this chapter or,
for certain types of fuel, use a default moisture percentage from Sec.
75.11(b)(1) of this chapter. For each unit operating hour, a moisture
correction must be applied to Equation C-6 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TP10AP09.009
Where:
CO2\*\ = Hourly CO2 mass emission rate,
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from
Equation C-6 of this section, uncorrected (tons/hr).
%H2O = Hourly moisture percentage in the stack gas
(measured or default value, as appropriate).
(iv) An oxygen (O2) concentration monitor may be used in
lieu of a CO2 concentration monitor to determine the hourly
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the
effluent gas stream monitored by the CEMS consists solely of combustion
products and if only fuels that are listed in Table 1 in section 3.3.5
of appendix F to part 75 of this chapter are combusted in the unit. If
the O2 monitoring option is selected, the F-factors used in
Equations F-14a and F-14b shall be determined according to section
3.3.5 or section 3.3.6 of appendix F to part 75 of this chapter, as
applicable. If Equation F-14b is used, the hourly moisture percentage
in the stack gas shall be either a measured value in accordance with
Sec. 75.11(b)(2) of this chapter, or, for certain types of fuel, a
default moisture value from Sec. 75.11(b)(1) of this chapter.
(v) Each hourly CO2 mass emission rate from Equation C-6
or C-7 of this section is multiplied by the operating time to convert
it from metric tons per hour to metric tons. The operating time is the
fraction of the hour during which fuel is combusted (e.g., the unit
operating time is 1.0 if the unit operates for the whole hour and is
0.5 if the unit operates for 30 minutes in the hour). For common stack
configurations, the operating time is the fraction of the hour during
which effluent gases flow through the common stack.
(vi) The hourly CO2 mass emissions are then summed over
the entire calendar year.
(vii) If both biogenic fuel and fossil fuel are combusted during
the year, determine the biogenic CO2 mass emissions
separately, as described in paragraph (e) of this section.
(b) Use of the four tiers. Use of the four tiers of CO2
emissions calculation methodologies described in paragraph (a) of this
section is subject to the following conditions, requirements, and
restrictions:
(1) The Tier 1 Calculation Methodology may be used for any type of
fuel combusted in a unit with a maximum rated heat input capacity of
250 mmBtu/hr or less, provided that:
(i) An applicable default CO2 emission factor and an
applicable default high heat value for the fuel are specified in Table
C-1 of this subpart.
(ii) The owner or operator does not perform, or receive from the
entity supplying the fuel, the results of fuel sampling and analysis on
a monthly (or more frequent) basis that includes measurements of the
HHV. If the owner or operator performs such fuel sampling and analysis
or receives such fuel sampling and analysis results, the Tier 1
Calculation Methodology shall not be used, and the Tier 2, Tier 3, or
Tier 4 Calculation Methodology shall be used instead.
(2) The Tier 1 Calculation Methodology may also be used to
calculate the biogenic CO2 emissions from a unit of any size
that combusts wood, wood waste, or other solid biomass-derived fuels,
except when the Tier 4 Calculation Methodology is used to quantify the
total CO2 mass emissions. If the Tier 4 Calculation
Methodology is used, the biogenic CO2 emissions shall be
calculated according to paragraph (e) of this section.
(3) The Tier 2 Calculation Methodology may be used for any type of
fuel combusted in any unit with a maximum rated heat input capacity of
[[Page 16634]]
250 mmBtu/hr or less, provided that a default CO2 emission
factor for the fuel is specified in Table C-1 or C-2 of this subpart.
(4) The Tier 3 Calculation Methodology may be used for a unit of
any size, combusting any type of fuel, except when the use of Tier 4 is
required or elected, as provided in paragraph (b)(5) of this section.
(5) The Tier 4 Calculation Methodology:
(i) May be used for a unit of any size, combusting any type of
fuel.
(ii) Shall be used for a unit if:
(A) The unit has a maximum rated heat input capacity greater than
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a
maximum rated input capacity greater than 250 tons per day of MSW.
(B) The unit combusts solid fossil fuel or MSW, either as a primary
or secondary fuel.
(C) The unit has operated for more than 1,000 hours in any calendar
year since 2005.
(D) The unit has installed CEMS that are required either by an
applicable Federal or State regulation or the unit's operating permit.
(E) The installed CEMS include a gas monitor of any kind, a stack
gas volumetric flow rate monitor, or both and the monitors have been
certified in accordance with the requirements of part 75 of this
chapter, part 60 of this chapter, or an applicable State continuous
monitoring program.
(F) The installed gas and/or stack gas volumetric flow rate
monitors are required, by an applicable Federal or State regulation or
the unit's operating permit, to undergo periodic quality assurance
testing in accordance with appendix B to part 75 of this chapter,
appendix F to part 60 of this chapter, or an applicable State
continuous monitoring program.
(iii) Shall be used for a unit with a maximum rated heat input
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal
solid waste with a maximum rated input capacity of 250 tons of MSW per
day or less, if the unit:
(A) Has both a stack gas volumetric flow rate monitor and a
CO2 concentration monitor.
(B) The unit meets the other conditions specified in paragraphs
(b)(5)(ii)(B) and (C) of this section.
(C) The CO2 and stack gas volumetric flow rate monitors
meet the conditions specified in paragraphs (b)(5)(ii)(D) through
(b)(5)(ii)(F) of this section.
(6) The Tier 4 Calculation Methodology, if selected or required,
shall be used beginning on:
(i) January 1, 2010, for a unit is required to report
CO2 mass emissions beginning on that date, if all of the
monitors needed to measure CO2 mass emissions have been
installed and certified by that date.
(ii) January 1, 2011, for a unit that is required to report
CO2 mass emissions beginning on January 1, 2010, if all of
the monitors needed to measure CO2 mass emissions have not
been installed and certified by January 1, 2010. In this case, the
owner or operator shall use the Tier 3 Calculation Methodology in 2010.
(c) Calculation of CH4 and N2O emissions from all fuel combustion.
Calculate the annual CH4 and N2O mass emissions
from stationary fuel combustion sources as follows:
(1) For units subject to the requirements of the Acid Rain Program
and for other units monitoring and reporting heat input on a year-round
basis according to Sec. Sec. 75.10(c) and 75.64 of this chapter, use
Equation C-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.010
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
(HI)A = Cumulative annual heat input from the fuel,
derived from the electronic data report required under Sec. 75.64
of this chapter (mmBtu).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-3 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kg to metric tons.
(2) For all other units, use the applicable equations and
procedures in paragraphs (c)(2) through (4) of this section to
calculate the annual CH4 and N2O emissions.
(i) If a default high heat value for a particular fuel is specified
in Table C-1 of this subpart and if the HHV is not measured or provided
by the entity supplying the fuel on a monthly (or more frequent) basis
throughout the year, use Equation C-9 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.011
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
Fuel = Mass or volume of the fuel combusted, from company records
(mass or volume per year).
HHV = Default high heat value of the fuel from Table C-1 of this
subpart (mmBtu per mass or volume).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-3 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
(ii) If the high heat value of a particular fuel (except for
municipal solid waste) is measured on a monthly (or more frequent)
basis throughout the year, or if such data are provided by the entity
supplying the fuel, use Equation C-10a of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.012
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a particular type of
fuel (metric tons).
n = Number of required heat content measurements for the year.
(Fuel)p = Mass or volume of the fuel combusted during the
measurement
[[Page 16635]]
period ``p'' (mass or volume per unit time).
(HHV)p = Measured high heat value of the fuel for period
``p'' (mmBtu per mass or volume).
p = Measurement period (day or month, as applicable).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-3 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10\-3\ = Conversion factor from kilograms to metric tons.
(iii) For municipal solid waste combustion, use Equation C-10b of
this section to estimate CH4 and N2O emissions:
[GRAPHIC] [TIFF OMITTED] TP10AP09.013
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of a municipal solid
waste (metric tons).
Steam = Total mass of steam generated by MSW combustion during the
reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its
design rated steam output (mmBtu/lb steam).
EF = Fuel-specific emission factor for CH4 or
N2O, from Table C-3 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10\-3\ = Conversion factor from kilograms to metric tons.
(3) Multiply the result from Equations C-8, C-9, C-10a, or C-10b of
this section (as applicable) by the global warming potential (GWP)
factor to convert the CH4 or N2O emissions to
metric tons of CO2 equivalent.
(4) If, for a particular type of fuel, default CH4 and
N2O emission factors are not provided in Table C-4 of this
subpart, the owner or operator may, subject to the approval of the
Administrator, develop site-specific CH4 and N2O
emission factors, based on the results of source testing.
(d) Calculation of CO2 from sorbent. (1) When a unit is
a fluidized bed boiler, is equipped with a wet flue gas desulfurization
system, or uses other acid gas emission controls with sorbent
injection, use the following equation to calculate the CO2
emissions from the sorbent, if those CO2 emissions are not
monitored by CEMS:
[GRAPHIC] [TIFF OMITTED] TP10AP09.014
Where:
CO2 = CO2 emitted from sorbent for the
reporting year (metric tons).
S = Limestone or other sorbent used in the reporting year (metric
tons).
R = Ratio of moles of CO2 released upon capture of one
mole of acid gas.
MWCO2 = Molecular weight of carbon dioxide (44).
MWS = Molecular weight of sorbent (100, if calcium
carbonate).
(2) The total annual CO2 mass emissions for the unit
shall be the sum of the CO2 emissions from the combustion
process and the CO2 emissions from the sorbent.
(e) Biogenic CO2 emissions. If any fuel combusted in the
unit meet the definition of biomass or biomass-derived fuel in Sec.
98.6, then the owner or operator shall estimate and report the total
annual biogenic CO2 emissions, according to paragraph
(e)(1), (2), (3), or (4) of this section, as applicable.
(1) The owner or operator may use Equation C-1 of this section to
calculate the annual CO2 mass emissions from the combustion
of biogenic fuel, for a unit of any size, provided that:
(i) The Tier 4 calculation methodology is not required or elected.
(ii) The biogenic fuel consists of wood, wood waste, or other
biomass-derived solid fuels (except for MSW).
(2) If CEMS are used to determine the total annual CO2
emissions, either according to part 75 of this chapter or the Tier 4
Calculation Methodology of this section and if both fossil fuel and
biogenic fuel (except for MSW) are combusted in the unit during the
reporting year, use the following procedure to determine the annual
biogenic CO2 mass emissions. If MSW is combusted in the
unit, follow the procedures in paragraph (e)(3) of this section:
(i) For each operating hour, use Equation C-12 of this section to
determine the volume of CO2 emitted.
[GRAPHIC] [TIFF OMITTED] TP10AP09.015
Where:
VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly CO2 concentration,
measured by the CO2 concentration monitor
(%CO2).
Qh = Hourly stack gas volumetric flow rate, measured by
the stack gas volumetric flow rate monitor (scfh).
th = Source operating time (decimal fraction of the hour
during which the source combusts fuel, i.e., 1.0 for a full
operating hour, 0.5 for 30 minutes of operation, etc.).
100 = Conversion factor from percent to a decimal fraction.
(ii) Sum all of the hourly VCO2h values for
the reporting year, to obtain Vtotal, the total annual
volume of CO2 emitted.
(iii) Calculate the annual volume of CO2 emitted from
fossil fuel combustion using Equation C-13 of this section. If two or
more types of fossil fuel are combusted during the year, perform a
separate calculation with Equation C-13 of this section for each fuel
and sum the results.
[GRAPHIC] [TIFF OMITTED] TP10AP09.016
Where:
Vff = Annual volume of CO2 emitted from
combustion of a particular fossil fuel (scf).
Fuel = Total quantity of the fossil fuel combusted in the reporting
year, from company records (lb for solid fuel, gallons for liquid
fuel, and scf for gaseous fuel).
Fc = Fuel-specific carbon based F-factor, either a
default value from Table 1 in section 3.3.5 of appendix F to part 75
of this chapter or a site-specific value determined under section
3.3.6 of appendix F to part 75 of this chapter (scf CO2/
mmBtu).
GCV = Gross calorific value of the fossil fuel, from fuel sampling
and analysis (annual average value in Btu/lb for solid fuel, Btu/gal
for liquid fuel and Btu/scf for gaseous fuel).
10 \6\ = Conversion factor, Btu per mmBtu.
(iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biogenic fuels.
(v) Calculate the biogenic percentage of the annual CO2
emissions, using Equation C-14 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.017
[[Page 16636]]
(vi) Calculate the annual biogenic CO2 mass emissions,
in metric tons, by multiplying the percent Biogenic obtained from
Equation C-14 of this section of this section by the total annual
CO2 mass emissions in metric tons, as determined under
paragraph (a)(1)(iv) of this section.
(3) For a unit that combusts MSW, the owner or operator shall use,
for each quarter, ASTM Methods D 6866-06a and D 7459-08, as described
in Sec. 98.34(f), to determine the relative proportions of biogenic
and non-biogenic CO2 emissions when MSW is combusted. The
results of each determination shall be expressed as a decimal fraction
(e.g., 0.30, if 30 percent of the CO2 from MSW combustion is
biogenic), and the quarterly values shall be averaged over the
reporting year. The annual biogenic CO2 emissions shall be
calculated as follows:
(i) If the unit qualifies for the Tier 2 or Tier 3 Calculation
Methodology of this section and the owner or operator elects to use the
Tier 2 or Tier 3 Calculation Methodology to quantify GHG emissions:
(A) Use Equations C-2a, C-2b and C-3 of this section, as
applicable, to calculate the annual CO2 mass emissions from
MSW combustion and from any auxiliary fuels such as natural gas. Sum
these values, to obtain the total annual CO2 mass emissions
from the unit.
(B) Determine the annual biogenic CO2 mass emissions
from MSW combustion as follows. Multiply the total annual
CO2 mass emissions from MSW combustion by the biogenic
decimal fraction obtained from ASTM Methods D 6866-06a and D 7459-08.
(ii) If the unit uses CEMS to quantify CO2 emissions:
(A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this
section, to determine Vtotal.
(B) If any fossil fuel was combusted during the year, follow the
procedures in paragraph (e)(2)(iii) of this section, to determine
Vff.
(C) Subtract Vff from Vtotal, to obtain
VMSW, the total annual volume of CO2 emissions
from MSW combustion.
(D) Determine the annual volume of biogenic CO2
emissions from MSW combustion as follows. Multiply the annual volume of
CO2 emissions from MSW combustion by the biogenic decimal
fraction obtained from ASTM Methods D 6866-06a and D 7459-08.
(E) Calculate the biogenic percentage of the total annual
CO2 emissions from the unit, using Equation C-14 of this
section. For the purposes of this calculation, the term
``Vbio'' in the numerator of Equation C-14 of this section
shall be the results of the calculation performed under paragraph
(e)(3)(ii)(D) of this section.
(F) Calculate the annual biogenic CO2 mass emissions
according to paragraph (e)(2)(vi) of this section.
(4) For biogas combustion, the Tier 2 or Tier 3 Calculation
Methodology shall be used to determine the annual biogenic
CO2 mass emissions, except as provided in paragraph (e)(2)
of this section.
Sec. 98.34 Monitoring and QA/QC requirements.
The CO2 mass emissions data for stationary combustion
units shall be quality-assured as follows:
(a) For units using the calculation methodologies described in this
paragraph, the records required under Sec. 98.3(g) shall include both
the company records and a detailed explanation of how company records
are used to estimate the following:
(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation
Methodologies described in Sec. 98.33(a) are used.
(2) Fuel consumption, when solid fuel is combusted and the Tier 3
Calculation Methodology in Sec. 98.33(a)(3) is used.
(3) Fossil fuel consumption, when, pursuant to Sec. 98.33(e), the
owner or operator of a unit that uses CEMS to quantify CO2
emissions and that combusts both fossil and biogenic fuels separately
reports the biogenic portion of the total annual CO2
emissions.
(4) Sorbent usage, if the methodology in Sec. 98.33(d) is used to
calculate CO2 emissions from sorbent.
(b) The owner or operator shall document the procedures used to
ensure the accuracy of the estimates of fuel usage and sorbent usage
(as applicable) in paragraph (a) of this section, including, but not
limited to, calibration of weighing equipment, fuel flow meters, and
other measurement devices. The estimated accuracy of measurements made
with these devices shall also be recorded, and the technical basis for
these estimates shall be provided.
(c) For the Tier 2 Calculation Methodology, the applicable fuel
sampling and analysis methods incorporated by reference in Sec. 98.7
shall be used to determine the high heat values. For coal, the samples
shall be taken at a location in the fuel handling system that provides
a sample representative of the fuel bunkered or consumed. The minimum
frequency of the sampling and analysis for each type of fuel (only for
the weeks or months when that fuel is combusted in the unit) is as
follows:
(1) Monthly, for natural gas, biogas, fuel oil, and other liquid
fuels.
(2) For coal and other solid fuels, weekly sampling is required to
obtain composite samples, which are analyzed monthly.
(d) For the Tier 3 Calculation Methodology:
(1) All oil and gas flow meters (except for gas billing meters)
shall be calibrated prior to the first year for which GHG emissions are
reported under this part, using an applicable flow meter test method
listed in Sec. 98.7 or the calibration procedures specified by the
flow meter manufacturer. Fuel flow meters shall be recalibrated either
annually or at the minimum frequency specified by the manufacturer.
(2) Oil tank drop measurements (if applicable) shall be performed
according to one of the methods listed in Sec. 98.7.
(3) The carbon content of the fuels listed in paragraphs (c)(1) and
(2) of this section shall be determined monthly. For other gaseous
fuels (e.g., refinery gas, or process gas), daily sampling and analysis
is required to determine the carbon content and molecular weight of the
fuel. An applicable method listed in Sec. 98.7 shall be used to
determine the carbon content and (if applicable) molecular weight of
the fuel.
(e) For the Tier 4 Calculation Methodology, the CO2 and
flow rate monitors must be certified prior to the applicable deadline
specified in Sec. 98.33(b)(6).
(1) For initial certification, use the following procedures:
(i) Section 75.20(c)(2) and (4) and appendix A to part 75) of this
chapter.
(ii) The calibration drift test and relative accuracy test audit
(RATA) procedures of Performance Specification 3 in appendix B to part
60 (for the CO2 concentration monitor) and Performance
Specification 6 in appendix B to part 60 (for the continuous emission
rate monitoring system (CERMS)).
(iii) The provisions of an applicable State continuous monitoring
program.
(2) If an O2 concentration monitor is used to determine
CO2 concentrations, the applicable provisions of part 75 of
this chapter, part 60 of this chapter, or an applicable State
continuous monitoring program shall be followed for initial
certification and on-going quality assurance, and all required RATAs of
the monitor shall be done on a percent CO2 basis.
(3) For ongoing quality assurance, follow the applicable procedures
in appendix B to part 75 of this chapter, appendix F to part 60 of this
chapter, or an applicable State continuous monitoring program. If
appendix F to
[[Page 16637]]
part 60 of this chapter is selected for on-going quality assurance,
perform daily calibration drift (CD) assessments for both the
CO2 and flow rate monitors, conduct cylinder gas audits of
the CO2 concentration monitor in three of the four quarters
of each year (except for non-operating quarters), and perform annual
RATAs of the CO2 concentration monitor and the CERMS.
(4) For the purposes of this part, the stack gas volumetric flow
rate monitor RATAs required by appendix B to part 75 of this chapter
and the annual RATAs of the CERMS required by appendix F to part 60 of
this chapter need only be done at one operating level, representing
normal load or normal process operating conditions, both for initial
certification and for ongoing quality assurance.
(f) When municipal solid waste (MSW) is combusted in a unit, the
biogenic portion of the CO2 emissions from MSW combustion
shall be determined using ASTM D6866-06a and ASTM D7459-08. The ASTM
D6866-06a analysis shall be performed at least once in every calendar
quarter in which MSW is combusted in the unit. Each gas sample shall be
taken using ASTM D7459-08, during normal unit operating conditions
while MSW is the only fuel being combusted, for at least 24 consecutive
hours or for as long as is necessary to obtain a sample large enough to
meet the specifications of ASTM D6866-06a. The owner or operator shall
separate total CO2 emissions from MSW combustion in to
biogenic emissions and non-biogenic emissions, using the average
proportion of biogenic emissions of all samples analyzed during the
reporting year. If there is a common fuel source of MSW that feeds
multiple units at the facility, performing the testing at only one of
the units is sufficient.
Sec. 98.35 Procedures for estimating missing data.
Whenever a quality-assured value of a required parameter is
unavailable (e.g., if a CEMS malfunctions during unit operation or if a
required fuel sample is not taken), a substitute data value for the
missing parameter shall be used in the calculations.
(a) For all units subject to the requirements of the Acid Rain
Program, the applicable missing data substitution procedures in part 75
of this chapter shall be followed for CO2 concentration,
stack gas flow rate, fuel flow rate, gross calorific value (GCV), and
fuel carbon content.
(b) For all units that are not subject to the requirements of the
Acid Rain Program, when the Tier 1, Tier 2, Tier 3, or Tier 4
calculation is used, perform missing data substitution as follows for
each parameter:
(1) For each missing value of the heat content, carbon content, or
molecular weight of the fuel, and for each missing value of
CO2 concentration and percent moisture, the substitute data
value shall be the arithmetic average of the quality-assured values of
that parameter immediately preceding and immediately following the
missing data incident. If, for a particular parameter, no quality-
assured data are available prior to the missing data incident, the
substitute data value shall be the first quality-assured value obtained
after the missing data period.
(2) For missing records of stack gas flow rate, fuel usage, and
sorbent usage, the substitute data value shall be the best available
estimate of the flow rate, fuel usage, or sorbent consumption, based on
all available process data (e.g., steam production, electrical load,
and operating hours). The owner or operator shall document and keep
records of the procedures used for all such estimates.
Sec. 98.36 Data reporting requirements.
(a) In addition to the facility-level information required under
Sec. 98.3, the annual GHG emissions report shall contain the unit-
level or process-level emissions data in paragraph (b) and (c) of this
section (as applicable) and the emissions verification data in
paragraph (d) of this section.
(b) Unit-level emissions data reporting. Except where aggregation
of unit-level information is permitted under paragraph (c) of this
section, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A code representing the type of unit.
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr
(boilers, combustion turbines, engines, and process heaters only).
(4) Each type of fuel combusted in the unit during the report year.
(5) The calculated CO2, CH4, and
N2O emissions for each type of fuel combusted, expressed in
metric tons of each gas and in metric tons of CO2e.
(6) The method used to calculate the CO2 emissions for
each type of fuel combusted (e.g., part 75 of this chapter or the Tier
1 or Tier 2 calculation methodology)
(7) If applicable, indicate which one of the monitoring and
reporting methodologies in part 75 of this chapter was used to quantify
the CO2 emissions (e.g., CEMS, appendix G, LME).
(8) The calculated CO2 emissions from sorbent (if any),
expressed in metric tons.
(9) The total GHG emissions from the unit for the reporting year,
i.e., the sum of the CO2, CH4, and N2O
emissions for all fuel types, expressed in metric tons of
CO2e.
(c) Reporting alternatives for stationary combustion units. For
stationary combustion units, the following reporting alternatives may
be used to simplify the unit-level reporting required under paragraph
(b) of this section:
(1) Aggregation of small units. If a facility contains two or more
units (e.g., boilers or combustion turbines) that have a combined
maximum rated heat input capacity of 250 mmBtu/hr or less, the owner or
operator may report the combined emissions for the group of units in
lieu of reporting separately the GHG emissions from the individual
units, provided that the amount of each type of fuel combusted in the
units in the group is accurately quantified. More than one such group
of units may be defined at a facility, so long as the aggregate maximum
rated heat input capacity of the units in the group does not exceed 250
mmBtu/hr. If this option is selected, the following information shall
be reported instead of the information in paragraph (b) of this
section:
(i) Group ID number, beginning with the prefix ``GP''.
(ii) The ID number of each unit in the group.
(iii) Cumulative maximum rated heat input capacity of the group
(mmBtu/hr).
(iv) Each type of fuel combusted in the units during the reporting
year.
(v) The calculated CO2, CH4, and
N2O mass emissions for each type of fuel combusted in the
group of units during the year, expressed in metric tons of each gas
and in metric tons of CO2e.
(vi) The methodology used to calculate the CO2 mass
emissions for each type of fuel combusted in the units.
(vii) The calculated CO2 mass emissions (if any) from
sorbent.
(viii) The total GHG emissions from the group for the year, i.e.,
the sum of the CO2, CH4, and N2O
emissions across, all fuel types, expressed in metric tons of
CO2e.
(2) Monitored common stack configurations. When the flue gases from
two or more stationary combustion units at a facility are discharged
through a common stack, if CEMS are used to continuously monitor
CO2 mass emissions at the common stack according to part 75
of this chapter or as described in the Tier 4 Calculation Methodology
in Sec. 98.33(a)(4), the owner or operator may report the combined
emissions from the units sharing the
[[Page 16638]]
common stack, in lieu of reporting separately the GHG emissions from
the individual units. If this option is selected, the following
information shall be reported instead of the information in paragraph
(b) of this section:
(i) Common stack ID number, beginning with the prefix ``CS''.
(ii) ID numbers of the units sharing the common stack.
(iii) Maximum rated heat input capacity of each unit sharing the
common stack (mmBtu/hr).
(iv) Each type of fuel combusted in the units during the year.
(v) The methodology used to calculate the CO2 mass
emissions (i.e., CEMS or the Tier 4 Calculation Methodology).
(vi) The total CO2 mass emissions measured at the common
stack for the year, expressed in metric tons of CO2e.
(vii) The combined annual CH4 and N2O
emissions from the units sharing the common stack, expressed in metric
tons of each gas and in metric tons of CO2e.
(A) If the monitoring is done according to part 75 of this chapter,
use Equation C-8 of this subpart, where the term ``(HI)A''
is the cumulative annual heat input measured at the common stack.
(B) For the Tier 4 calculation methodology, use Equation C-9, C-10a
or C-10b of this subpart separately for each type of fuel combusted in
the units during the year, and then sum the emissions for all fuel
types.
(viii) The total GHG emissions for the year from the units that
share the common stack, i.e., the sum of the CO2,
CH4, and N2O emissions, expressed in metric tons
of CO2e.
(3) Common pipe configurations. When two or more oil-fired or gas-
fired stationary combustion units at a facility combust the same type
of fuel and that fuel is fed to the individual units through a common
supply line or pipe, the owner or operator may report the combined
emissions from the units served by the common supply line, in lieu of
reporting separately the GHG emissions from the individual units,
provided that the total amount of fuel combusted by the units is
accurately measured at the common pipe or supply line using a
calibrated fuel flow meter. If this option is selected, the following
information shall be reported instead of the information in paragraph
(b) of this section:
(i) Common pipe ID number, beginning with the prefix ``CP''.
(ii) ID numbers of the units served by the common pipe.
(iii) Maximum rated heat input capacity of each unit served by the
common pipe (mmBtu/hr).
(iv) The type of fuel combusted in the units during the reporting
year.
(v) The methodology used to calculate the CO2 mass
emissions.
(vi) The total CO2 mass emissions from the units served
by the common pipe for the reporting year, expressed in metric tons of
CO2e.
(vii) The combined annual CH4 and N2O
emissions from the units served by the common pipe, expressed in metric
tons of each gas and in metric tons of CO2e.
(viii) The total GHG emissions for the reporting year from the
units served by the common pipe, i.e., the sum of the CO2,
CH4, and N2O emissions, expressed in metric tons
of CO2e.
(d) Verification data. The owner or operator shall report
sufficient data and supplementary information to verify the reported
GHG emissions.
(1) For stationary combustion sources using the Tier 1, Tier 2,
Tier 3, or Tier 4 Calculation Methodology in Sec. 98.33(a)(4) to
quantify CO2 emissions, the following additional information
shall be included in the GHG emissions report:
(i) For the Tier 1 Calculation Methodology, report the total
quantity of each type of fuel combusted during the reporting year, in
short tons for solid fuels, gallons for liquid fuels and scf for
gaseous fuels.
(ii) For the Tier 2 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted during each
month (except for MSW). Express the quantity of each fuel combusted
during the measurement period in short tons for solid fuels, gallons
for liquid fuels, and scf for gaseous fuels.
(B) The number of required high heat value determinations for each
type of fuel for the reporting year (i.e., ``n'' in Equation C-2a of
this subpart, corresponding (as applicable) to the number of operating
days or months when each type of fuel was combusted, in accordance with
Sec. Sec. 98.33(a)(2) and 98.34(c).
(C) For each month, the high heat value used in Equation C-2a of
this subpart for each type of fuel combusted, in mmBtu per short ton
for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf
for gaseous fuels.
(D) For each reported HHV, indicate whether it is an actual
measured value or a substitute data value.
(E) Each method from Sec. 98.7 used to determine the HHV for each
type of fuel combusted.
(F) For MSW, the total quantity (i.e., lb) of steam produced from
MSW combustion during the year, and ``B'', the ratio of the unit's
maximum rate heat input capacity to its design rated steam output
capacity, in mmBtu per lb of steam.
(iii) For the Tier 3 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted during each
month or day (as applicable), in metric tons for solid fuels, gallons
for liquid fuels, and scf for gaseous fuels.
(B) The number of required carbon content determinations for each
type of fuel for the reporting year, corresponding (as applicable) to
the number of operating days or months when each type of fuel was
combusted, in accordance with Sec. Sec. 98.33(a)(3) and 98.34(d).
(C) For each operating month or day, the carbon content (CC) value
used in Equation C-3, C-4, or C-5 of this subpart (as applicable),
expressed as a decimal fraction for solid fuels, kg C per gallon for
liquid fuels, and kg C per kg of fuel for gaseous fuels.
(D) For gaseous fuel combustion, the molecular weight of the fuel
used in Equation C-5 of this subpart, for each operating month or day,
in kg per kg-mole.
(E) For each reported CC value, indicate whether it is an actual
measured value or a substitute data value.
(F) For liquid and gaseous fuel combustion, the dates and results
of the initial calibrations and periodic recalibrations of the fuel
flow meters used to measure the amount of fuel combusted.
(G) For fuel oil combustion, each method from Sec. 98.7 used to
make tank drop measurements (if applicable).
(H) Each method from Sec. 98.7 used to determine the CC for each
type of fuel combusted.
(I) Each method from Sec. 98.7 used to calibrate the fuel flow
meters (if applicable).
(iv) For the Tier 4 Calculation Methodology, report:
(A) The total number of source operating days and the total number
of source operating hours in the reporting year.
(B) Whether the CEMS certification and quality assurance procedures
of part 75 of this chapter, part 60 of this chapter, or an applicable
State continuous monitoring program have been selected.
(C) The CO2 emissions on each operating day, i.e., the
sum of the hourly values calculated from Equation C-6 or C-7 (as
applicable), in metric tons.
(D) For CO2 concentration, stack gas flow rate, and (if
applicable) stack gas moisture content, the number of source operating
hours in which a substitute
[[Page 16639]]
data value of each parameter was used in the emissions calculations.
(E) The dates and results of the initial certification tests of the
CEMS, and
(F) The dates and results of the major quality assurance tests
performed on the CEMS during the reporting year, i.e., linearity
checks, cylinder gas audits, and relative accuracy test audits (RATAs).
(v) If CO2 emissions that are generated from acid gas
scrubbing with sorbent injection are not captured using CEMS, report:
(A) The total amount of sorbent used during the report year, in
metric tons.
(B) The molecular weight of the sorbent.
(C) The ratio (``R'') in Equation C-11 of this subpart.
(vi) When ASTM methods D7459-08 and D6866-06a are used to determine
the biogenic portion of the annual CO2 emissions from MSW
combustion, as described in Sec. Sec. 98.33(e) and 98.34(f), the owner
or operator shall report:
(A) The results of each quarterly sample analysis, expressed as a
decimal fraction, e.g., if the biogenic fraction of the CO2
emissions from MSW combustion is 30 percent, report 0.30.
(B) The total quantity of MSW combusted during the reporting year,
in short tons if the Tier 2 Calculation Methodology is used or in
metric tons if the Tier 3 calculation methodology is used.
(vii) For units that combust both fossil fuel and biogenic fuel,
when CEMS are used to quantify the annual CO2 emissions, the
owner or operator shall report the following additional information, as
applicable:
(A) The annual volume of CO2 emitted from the combustion
of all fuels, i.e., Vtotal, in scf.
(B) The annual volume of CO2 emitted from the combustion
of fossil fuels, i.e., Vff, in scf. If more than one type of
fossil fuel was combusted, report the combustion volume of
CO2 for each fuel separately as well as the total.
(C) The annual volume of CO2 emitted from the combustion
of biogenic fuels, i.e., Vbio, in scf.
(D) The carbon-based F-factor used in Equation C-14 of this
subpart, for each type of fossil fuel combusted, in scf CO2
per mmBtu.
(E) The annual average GCV value used in Equation C-14 of this
subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or
Btu/scf, as appropriate.
(F) The total quantity of each type of fossil fuel combusted during
the reporting year, in lb, gallons, or scf, as appropriate.
(G) The total annual biogenic CO2 mass emissions, in
metric tons.
(2) Within 7 days of receipt of a written request (e.g., a request
by electronic mail) from the Administrator or from the applicable State
or local air pollution control agency, the owner or operator shall
submit the explanations described in Sec. 98.34(a) and (b), as
follows:
(i) A detailed explanation of how company records are used to
quantify fuel consumption, if Calculation Methodology Tier 1 or Tier 2
of this subpart is used to calculate CO2 emissions.
(ii) A detailed explanation of how company records are used to
quantify fuel consumption, if solid fuel is combusted and the Tier 3
Calculation Methodology in Sec. 98.33(a)(3) is used to calculate
CO2 emissions.
(iii) A detailed explanation of how sorbent usage is quantified, if
the methodology in Sec. 98.33(d) is used to calculate CO2
emissions from sorbent.
(iv) A detailed explanation of how company records are used to
quantify fossil fuel consumption, when, as described in Sec. 98.33(e),
the owner or operator of a unit that combusts both fossil fuel and
biogenic fuel uses CEMS to quantify CO2 emissions.
Sec. 98.37 Records that must be retained.
The recordkeeping requirements of Sec. 98.3(g) and, if applicable,
Sec. 98.34(a) and (b) shall be fully met for affected facilities with
stationary combustion sources. Also, the records required under Sec.
98.35(a)(1), documenting the data substitution procedures for missing
stack flow rate, fuel flow rate, fuel usage and (if applicable) sorbent
usage information and site-specific source testing (as allowed in Sec.
98.33(c)(4)), shall be retained. No special recordkeeping beyond that
specified in Sec. Sec. 98.3, 98.35(a)(4), and 98.34(a) and (b) is
required. All required records must be retained for a period of five
years.
Sec. 98.38 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table C-1 of Subpart C--Default CO2 Emission Factors and High Heat
Values for Various Types of Fuel
------------------------------------------------------------------------
Default high heat Default CO2
Fuel type value emission factor
------------------------------------------------------------------------
Coal and Coke mmBtu/short ton kg CO2/mmBtu
------------------------------------------------------------------------
Anthracite........................ 25.09 103.54
Bituminous........................ 24.93 93.40
Sub-bituminous.................... 17.25 97.02
Lignite........................... 14.21 96.36
Unspecified (Residential/ 22.24 95.26
Commercial)......................
Unspecified (Industrial Coking)... 26.28 93.65
Unspecified (Other Industrial).... 22.18 93.91
Unspecified (Electric Power)...... 19.97 94.38.
Coke.............................. 24.80 102.04
------------------------------------------------------------------------
Natural Gas mmBtu/scf kg CO2/mmBtu.
------------------------------------------------------------------------
Unspecified (Weighted U.S. 1.027 x 10-\3\ 53.02
Average).........................
------------------------------------------------------------------------
Petroleum Products mmBtu/gallon kg CO2/mmBtu
------------------------------------------------------------------------
Asphalt & Road Oil................ 0.158 75.55
Aviation gasoline................. 0.120 69.14
Distillate Fuel Oil ( 1, 0.139 73.10
2, & 4)..........................
Jet Fuel.......................... 0.135 70.83
Kerosene.......................... 0.135 72.25
LPG (energy use).................. 0.092 62.98
[[Page 16640]]
Propane........................... 0.091 63.02
Ethane............................ 0.069 59.54
Isobutane......................... 0.099 65.04
n-Butane.......................... 0.103 64.93
Lubricants........................ 0.144 74.16
Motor Gasoline.................... 0.124 70.83
Residual Fuel Oil ( 5 & 0.150 78.74
6)...............................
Crude Oil......................... 0.138 74.49
Naphtha (< 401 deg. F)............ 0.125 66.46
Natural Gasoline.................. 0.110 66.83
Other Oil (> 401 deg. F).......... 0.139 73.10
Pentanes Plus..................... 0.110 66.83
Petrochemical Feedstocks.......... 0.129 70.97
Petroleum Coke.................... 0.143 102.04
Special Naphtha................... 0.125 72.77
Unfinished Oils................... 0.139 74.49
Waxes............................. 0.132 72.58
------------------------------------------------------------------------
Biomass-derived Fuels (solid) mmBtu/short Ton kg CO2/mmBtu
------------------------------------------------------------------------
Wood and Wood waste (12% moisture 15.38 93.80
content) or other solid biomass-
derived fuels....................
------------------------------------------------------------------------
Biomass-derived Fuels (Gas) mmBtu/scf kg CO2/mmBtu
------------------------------------------------------------------------
Biogas............................ Varies 52.07
------------------------------------------------------------------------
Note: Heat content factors are based on higher heating values (HHV).
Also, for petroleum products, the default heat content values have
been converted from units of mmBtu per barrel to mmBtu per gallon.
Table C-2 of Subpart C--Default CO2 Emission Factors for the Combustion
of Alternative Fuels
------------------------------------------------------------------------
Default CO2
Fuel type emission factor
(kg CO2/mmBtu)
------------------------------------------------------------------------
Waste Oil........................................... 74
Tires............................................... 85
Plastics............................................ 75
Solvents............................................ 74
Impregnated Saw Dust................................ 75
Other Fossil based wastes........................... 80
Dried Sewage Sludge................................. 110
Mixed Industrial waste.............................. 83
Municipal Solid Waste............................... 90.652
------------------------------------------------------------------------
Note: Emission factors are based on higher heating values (HHV). Values
were converted from LHV to HHV assuming that LHV are 5 percent lower
than HHV for solid and liquid fuels.
Table C-3 of Subpart C--Default CH4 and N2O Emission Factors for Various
Types of Fuel
------------------------------------------------------------------------
Default CH4 Default N2O
Fuel type emission factor emission factor
(kg CH4/mmBtu) (kg N2O/mmBtu)
------------------------------------------------------------------------
Asphalt........................... 3.0 x 10-\3\ 6.0 x 10-\4\
Aviation Gasoline................. 3.0 x 10-\3\ 6.0 x 10-\4\
Coal.............................. 1.0 x 10-\2\ 1.5 x 10-\3\
Crude Oil......................... 3.0 x 10-\3\ 6.0 x 10-\4\
Digester Gas...................... 9.0 x 10-\4\ 1.0 x 10-\4\
Distillate........................ 3.0 x 10-\3\ 6.0 x 10-\4\
Gasoline.......................... 3.0 x 10-\3\ 6.0 x 10-\4\
Jet Fuel.......................... 3.0 x 10-\3\ 6.0 x 10-\4\
Kerosene.......................... 3.0 x 10-\3\ 6.0 x 10-\4\
Landfill Gas...................... 9.0 x 10-\4\ 1.0 x 10-\4\
LPG............................... 1.0 x 10-\3\ 1.0 x 10-\4\
Lubricants........................ 3.0 x 10-\3\ 6.0 x 10-\4\
Municipal Solid Waste............. 3.0 x 10-\2\ 4.0 x 10-\3\
Naphtha........................... 3.0 x 10-\3\ 6.0 x 10-\4\
Natural Gas....................... 9.0 x 10-\4\ 1.0 x 10-\4\
Natural Gas Liquids............... 3.0 x 10-\3\ 6.0 x 10-\4\
Other Biomass..................... 3.0 x 10-\2\ 4.0 x 10-\3\
[[Page 16641]]
Petroleum Coke.................... 3.0 x 10-\3\ 6.0 x 10-\4\
Propane........................... 1.0 x 10-\3\ 1.0 x 10-\4\
Refinery Gas...................... 9.0 x 10-\4\ 1.0 x 10-\4\
Residual Fuel Oil................. 3.0 x 10-\3\ 6.0 x 10-\4\
Tites............................. 3.0 x 10-\3\ 6.0 x 10-\4\
Waste Oil......................... 3.0 x 10-\2\ 4.0 x 10-\3\
Waxes............................. 3.0 x 10-\3\ 6.0 x 10-\4\
Wood and Wood Waste............... 3.0 x 10-\2\ 4.0 x 10-\3\
------------------------------------------------------------------------
Note: Values were converted from LHV to HHV assuming that LHV are 5
percent lower than HHV for solid and liquid fuels and 10 percent lower
for gaseous fuels. Those employing this table are assumed to fall
under the IPCC definitions of the ``Energy Industry'' or
``Manufacturing Industries and Construction''. In all fuels except for
coal the values for these two categories are identical. For coal
combustion, those who fall within the IPCC ``Energy Industry''
category may employ a value of 1 g of CH4/MMBtu.
Subpart D--Electricity Generation
Sec. 98.40 Definition of the source category.
(a) The electricity generation source category comprises all
facilities with one or more electricity generating units, including
electricity generating units that are subject to the requirements of
the Acid Rain Program.
(b) This source category does not include portable equipment or
generating units designated as emergency generators in a permit issued
by a State or local air pollution control agency.
Sec. 98.41 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains one or more electricity generating units and the facility
meets the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.42 GHGs to report.
The annual mass emissions of CO2, N2O, and
CH4 shall be reported for each electricity generating unit.
Sec. 98.43 Calculating GHG emissions.
(a) For each electricity generating unit subject to the
requirements of the Acid Rain Program, the owner or operator shall
continue to monitor and report CO2 mass emissions as
required under Sec. Sec. 75.13 and 75.64 of this chapter.
CO2 emissions for the purposes of the GHG emissions reports
required under Sec. Sec. 98.3 and 98.36 shall be calculated as
follows:
(1) The owner or operator shall convert the cumulative annual
CO2 mass emissions reported in the fourth quarter electronic
data report required under Sec. 75.64 of this chapter from units of
short tons to metric tons. To convert tons to metric tons, divide by
1.1023.
(2) The annual CH4 and N2O mass emissions
shall be calculated using the methods specified in Sec. 98.33 for
stationary fuel combustion units.
(b) For each unit that is not subject to the reporting requirements
of the Acid Rain Program, the annual CO2, CH4,
and N2O mass emissions shall be calculated using the methods
specified in Sec. 98.33 for stationary fuel combustion units.
Sec. 98.44 Monitoring and QA/QC requirements.
(a) For electricity generation units subject to the requirements of
the Acid Rain Program, the CO2 emissions data shall be
quality assured according to the applicable procedures in appendices B,
D, and G to part 75 of this chapter.
(b) For electricity generating units that are not subject to the
requirements of the Acid Rain Program, the quality assurance and
quality control procedures specified in Sec. 98.34 for stationary fuel
combustion units shall be followed.
Sec. 98.45 Procedures for estimating missing data.
(a) For electricity generation units subject to the requirements of
the Acid Rain Program, the applicable missing data substitution
procedures in part 75 of this chapter shall be followed for
CO2 concentration, stack gas flow rate, fuel flow rate,
gross calorific value (GCV), and fuel carbon content.
(b) For each electricity generating unit that is not subject to the
requirements of the Acid Rain Program, the missing data substitution
procedures specified in Sec. 98.35 for stationary fuel combustion
units shall be implemented.
Sec. 98.46 Data reporting requirements.
(a) For electricity generation units subject to the requirements of
the Acid Rain Program, the owner or operator of a facility containing
one or more electricity generating units shall meet the data reporting
requirements specified in Sec. 98.36(b) and, if applicable, Sec.
98.36(c)(2) or (3).
(b) For electricity generating units not subject to the
requirements of the Acid Rain Program, the owner or operator of a
facility containing one or more electricity generating units shall meet
the data reporting and verification requirements specified in Sec.
98.36.
Sec. 98.47 Records that must be retained.
The owner or operator of a facility containing one or more
electricity generating units shall meet the recordkeeping requirements
of Sec. 98.3(g) and, if applicable, Sec. 98.37.
Sec. 98.48 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart E--Adipic Acid Production
Sec. 98.50 Definition of source category.
The adipic acid production source category consists of all adipic
acid production facilities that use oxidation to produce adipic acid.
Sec. 98.51 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an adipic acid production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.52 GHGs to report.
(a) You must report N2O process emissions from adipic
acid production as required by this subpart.
(b) You must report CO2, CH4, and
N2O emissions from each stationary combustion unit that uses
a carbon-based fuel, following the requirements of subpart C of this
part.
Sec. 98.53 Calculating GHG emissions.
You must determine annual N2O emissions from adipic acid
production using a facility-specific emission factor according to
paragraphs (a) through (e) of this section.
(a) You must conduct an annual performance test to measure
N2O emissions from the waste gas streams of
[[Page 16642]]
each adipic acid oxidation process. You must conduct the performance
test under normal process operating conditions.
(b) You must conduct the emissions test using the methods specified
in Sec. 98.54(b).
(c) You must measure the adipic acid production rate for the
facility during the test and calculate the production rate for the test
period in metric tons per hour.
(d) You must calculate an average facility-specific emission factor
according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.018
Where:
EFN2O = Average facility-specific N2O
emissions factor (lb N2O/ton adipic acid produced).
CN2O = N2O concentration during performance
test (ppm N2O).
1.14x10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas (dscf/hr).
P = Production rate during performance test (tons adipic acid
produced/hr).
n = Number of test runs.
(e) You must calculate annual adipic acid production process
emissions of N2O for the facility by multiplying the
emissions factor by the total annual adipic acid production at the
facility, according to Equation E-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.019
Where:
EN2O = N2O mass emissions per year (metric
tons of N2O).
EFN2O = Facility-specific N2O emission factor
(lb N2O/ton adipic acid produced).
Pa = Total production for the year (ton adipic acid
produced).
DFN = Destruction factor of N2O abatement
technology (abatement device manufacturer's specified destruction
efficiency, percent of N2O removed from air stream).
AFN = Abatement factor of N2O abatement
technology (percent of year that abatement technology was used).
2205 = Conversion factor (lb/metric ton).
Sec. 98.54 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test and calculate a new
facility-specific emissions factor at least annually. You must also
conduct a new performance test whenever the production rate is changed
by more than 10 percent from the production rate measured during the
most recent performance test. The new emissions factor may be
calculated using all available performance test data (i.e., average
with the data from previous years), except in cases where process
modifications have occurred or operating conditions have changed. Only
the data consistent with the reporting period after the changes were
implemented shall be used.
(b) You must conduct each emissions test using EPA Method 320 in 40
CFR part 63, Appendix A or ASTM D6348-03 (incorporated by reference--
see Sec. 98.7) to measure the N2O concentration in
conjunction with the applicable EPA methods in 40 CFR part 60,
appendices A-1 through A-4. Conduct three emissions test runs of 1 hour
each.
(c) Each facility must conduct all required performance tests
according to a test plan and EPA Method 320 in 40 CFR part 63, appendix
A or ASTM D6348-03 (incorporated by reference-see Sec. 98.7). All QA/
QC procedures specified in the reference test methods and any
associated performance specifications apply. For each test, the
facility must prepare an emission factor determination report that must
include the items in paragraphs (c)(1) through (3) of this section:
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor.
(3) The production rate during the test and how it was determined.
The production rate can be determined through sales records, or through
direct measurement using flow meters or weigh scales.
Sec. 98.55 Procedures for estimating missing data.
Procedures for estimating missing data are not provided for
N2O process emissions for adipic acid production facilities
calculated according to Sec. 98.53. A complete record of all measured
parameters used in the GHG emissions calculations is required.
Sec. 98.56 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (h) of this section for each adipic acid production facility:
(a) Annual N2O emissions from adipic acid production in
metric tons.
(b) Annual adipic acid production capacity (in metric tons).
(c) Annual adipic acid production, in units of metric tons of
adipic acid produced.
(d) Number of facility operating hours in calendar year.
(e) Emission rate factor used (lb N2O/ton adipic acid).
(f) Abatement technology used (if applicable).
(g) Abatement technology efficiency (percent destruction).
(h) Abatement utilization factor (percent of time that abatement
system is operating).
Sec. 98.57 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (f) of this
section at the facility level:
(a) Annual N2O emissions from adipic acid production, in
metric tons.
(b) Annual adipic acid production capacity, in metric tons.
(c) Annual adipic acid production, in units of metric tons of
adipic acid produced.
(d) Number of facility operating hours in calendar year.
(e) Measurements, records and calculations used to determine the
annual production rate.
[[Page 16643]]
(f) Emission rate factor used and supporting test or calculation
information including the annual emission rate factor determination
report specified in Sec. 98.54(c). This report must be available upon
request.
Sec. 98.58 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart F--Aluminum Production
Sec. 98.60 Definition of the source category.
(a) A primary aluminum production facility manufactures primary
aluminum using the Hall-H[eacute]roult manufacturing process. The
primary aluminum manufacturing process comprises the following
operations:
(1) Electrolysis in prebake and S[oslash]derberg cells.
(2) Anode baking for prebake cells.
(b) This source category does not include experimental cells or
research and development process units.
Sec. 98.61 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an aluminum production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.62 GHGs to report.
You must report:
(a) Total perfluoromethane (CF4), and perfluoroethane
(C2F6) emissions from anode effects in all
prebake and S[oslash]derberg electrolysis cells.
(b) Total CO2 emissions from anode consumpton during
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
(c) Total CO2 emissions from anode baking for all
prebake cells.
(d) For CO2, N2O, and CH4
emissions from stationary fuel combustion units, you must follow the
requirements in subpart C of this part.
Sec. 98.63 Calculating GHG emissions.
(a) Use Equation F-1 of this section to estimate CF4
emissions from anode effects, and use Equation F-2 to estimate
C2F6 emissions from anode effects from each
prebake and S[oslash]derberg electrolysis cell.
[GRAPHIC] [TIFF OMITTED] TP10AP09.020
Where:
ECF4 = Monthly CF4 emissions from aluminum
production (metric tons CF4).
SCF4 = The slope coefficient ((kg CF4/metric
ton Al)/(AE-Mins/cell-day)).
AEM = The anode effect minutes per cell-day (AE-Mins/cell-day).
MP = Metal production (metric tons Al). where AEM and MP are
calculated monthly.
[GRAPHIC] [TIFF OMITTED] TP10AP09.021
Where:
EC2F6 = Monthly C2F6 emissions from
aluminum production (metric tons C2F6).
ECF4 = CF4 emissions from aluminum production
(kg CF4).
FC2F6/CF4 = The weight fraction of
C2F6/CF4 (kg
C2F6/kg CF4).
0.001 = Conversion factor from kg to metric tons, where
ECF4 is calculated monthly.
(b) Use the following procedures to calculate CO2
emissions from anode consumption during electrolysis:
(1) For Prebake cells: You must calculate CO2 emissions
from anode consumption using Equation F-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.022
Where:
ECO2 = Annual CO2 emissions from prebaked
anode consumption (metric tons CO2).
NAC = Net annual prebaked anode consumption per metric ton Al
(metric tons C/metric tons Al).
MP = Total annual metal production (metric tons Al).
Sa = Sulfur content in baked anode (percent weight).
Asha = Ash content in baked anode (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.
(2) For S[oslash]derberg cells you must calculate CO2
emissions using Equation F-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.023
Where:
ECO2 = Annual CO2 emissions from paste
consumption (metric ton CO2).
PC = Annual paste consumption (metric ton/metric ton Al).
MP = Total annual metal production (metric ton Al).
CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton
Al).
BC = Binder content of paste (percent weight).
Sp = Sulfur content of pitch (percent weight).
Ashp = Ash content of pitch (percent weight).
Hp = Hydrogen content of pitch (percent weight).
Sc = Sulfur content in calcined coke (percent weight).
Ashc = Ash content in calcined coke (percent weight).
CD = Carbon in skimmed dust from S[oslash]derberg cells (metric ton
C/metric ton Al).
44/12 = Ratio of molecular weights, CO2 to carbon.
(c) Use the following procedures to calculate CO2 emissions
from anode baking of prebake cells:
[[Page 16644]]
(1) Use Equation F-5 of this section to calculate emissions from pitch
volatiles.
[GRAPHIC] [TIFF OMITTED] TP10AP09.024
Where:
ECO2PV = Annual CO2 emissions from pitch
volatiles combustion (metric tons CO2).
GA = Initial weight of green anodes (metric tons).
Hw = Annual hydrogen content in green anodes (metric
tons).
BA = Annual baked anode production (metric tons).
WT = Annual waste tar collected (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(2) Use Equation F-6 of this section to calculate emissions from
bake furnace packing material.
[GRAPHIC] [TIFF OMITTED] TP10AP09.025
Where:
ECO2PC = Annual CO2 emissions from bake
furnace packing material (metric tons CO2).
PCC = Annual packing coke consumption (metric tons/metric ton baked
anode).
BA = Annual baked anode production (metric tons).
Spc = Sulfur content in packing coke (percent weight).
Ashpc = Ash content in packing coke (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.
Sec. 98.64 Monitoring and QA/QC requirements.
(a) The smelter-specific slope coefficient must be measured at
least every 36 months in accordance with the EPA/IAI Protocol for
Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from
Primary Aluminum Production (2008).
(b) The minimum frequency of the measurement and analysis is
annually except as follows: Monthly--anode effect minutes per cell day,
production.
(c) Sources may use smelter-specific values from annual
measurements of parameters needed to complete the equations in Sec.
98.63 (e.g., sulfur, ash, and hydrogen contents), or may use default
values from Volume III, Section 4.4, in Chapter 4, of the 2006 IPCC
Guidelines for National Greenhouse Gas Inventories.
Sec. 98.65 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required sample measurement
is not taken), a substitute data value for the missing parameter shall
be used in the calculations, according to the following requirements:
(a) Where anode or paste consumption data are missing,
CO2 emissions can be estimated from aluminum production
using Tier 1 method per Equation F-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.026
Where:
ECO2 = CO2 emissions from anode and/or paste
consumption, tonnes CO2.
EFp = Prebake technology specific emission factor (1.6
tonnes CO2/tonne aluminum produced).
MPp = Metal production from prebake process (tonnes Al).
EFs = S[oslash]derberg technology specific emission
factor (1.7 tonnes CO2/tonne Al produced).
MPs = Metal production from S[oslash]derberg process
(tonnes Al).
(b) For other parameters, use the average of the two most recent
data points.
Sec. 98.66 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), you must
report the following information at the facility level:
(a) Annual aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on an annual basis:
(1) Perfluoromethane emissions and perfluoroethane emissions from
anode effects in all prebake and all S[oslash]derberg electolysis cells
combined.
(2) Anode effect minutes per cell-day, anode effect frequency (AE/
cell-day), anode effect duration (minutes).
(3) Smelter-specific slope coefficient and the last date when the
smelter-specific-slope coefficient was measured.
(d) Method used to measure the frequency and duration of anode
effects.
(e) The following CO2-specific information for prebake
cells on an annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the smelter.
(f) The following CO2-specific information for
S[oslash]derberg cells on an annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the smelter.
(g) Smelter-specific inputs to the CO2 process equations
(e.g., levels of sulfur and ash) that were used in the calculation, on
an annual basis.
(h) Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or S[oslash]derberg).
Sec. 98.67 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) Monthly aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on a monthly basis:
(1) Perfluoromethane and perfluoroethane emissions from anode
effects in each prebake and S[oslash]derberg electolysis cells.
(2) Anode effect minutes per cell-day, anode effect frequency (AE/
cell-day), anode effect duration (minutes) from each prebake and
S[oslash]derberg electolysis cells.
[[Page 16645]]
(3) Smelter-specific slope coefficient and the last date when the
smelter-specific-slope coefficient was measured.
(d) Method used to measure the frequency and duration of anode
effects.
(e) The following CO2-specific information for prebake
cells on an annual basis:
(1) Total anode consumption.
(2) Total CO2 emissions from the smelter.
(f) The following CO2-specific information for
S[oslash]derberg cells on an annual basis:
(1) Total paste consumption.
(2) Total CO2 emissions from the smelter.
(g) Smelter-specific inputs to the CO2 process equations
(e.g., levels of sulfur and ash) that were used in the calculation, on
an annual basis.
(h) Exact data elements required will vary depending on smelter
technology (e.g., point-feed prebake or S[oslash]derberg).
Sec. 98.68 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart G--Ammonia Manufacturing
Sec. 98.70 Definition of source category.
The ammonia manufacturing source category comprises the process
units listed in paragraphs (a) and (b) of this section.
(a) Ammonia manufacturing processes in which ammonia is
manufactured from a fossil-based feedstock produced via steam reforming
of a hydrocarbon.
(b) Ammonia manufacturing processes in which ammonia is
manufactured through the gasification of solid raw material.
Sec. 98.71 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an ammonia manufacturing process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.72 GHGs to report.
You must report:
(a) Carbon dioxide (CO2) process emissions from steam
reforming of a hydrocarbon or the gasification of solid raw material,
reported for each ammonia manufacturing process unit.
(b) CO2, N2O, and CH4 emissions
from fuel combustion at ammonia manufacturing processes and any other
stationary fuel combustion units. You must follow the requirements of
40 CFR 98, subpart C (General Stationary Fuel Combustion Sources).
(c) For CO2 collected and used on site or transferred
off site, you must follow the requirements of subpart PP (Suppliers of
CO2) of this part.
Sec. 98.73 Calculating GHG emissions.
You must determine CO2 process emissions in accordance
with the procedures specified in either paragraph (a) or (b) of this
section.
(a) Any ammonia manufacturing process unit that meets the
conditions specififed in Sec. 98.33(b)(5)(iii)(A), (B), and (C), or
Sec. 98.33(b)(5)(ii)(A) through (F) shall calculate total
CO2 emissions using a continuous emissions monitoring system
according to the Tier 4 Calculation Methodology specified in Sec.
98.33(a)(4).
(b) If the facility does not measure total emissions with a CEMS,
you must calculate the annual CO2 process emissions from
feedstock used for ammonia manufacturing.
(1) Gaseous feedstock. You must calculate the total CO2
process emissions from gaseous feedstock according to Equation G-1 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.027
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the gaseous feedstock used in month
n (scf of feedstock).
(CC)n = Average carbon content of the gaseous feedstock,
from the analysis results for month n (kg C per kg of feedstock).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(2) Liquid feedstock. You must calculate the total CO2
process emissions from liquid feedstock according to Equation G-2 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.028
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock used in month n
(gallons of feedstock).
(CC)n = Average carbon content of the liquid feedstock,
from the analysis results for month n (kg C per gallon of
feedstock).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(RCO2)n = CO2 captured or recovered for use in
urea or methanol production for month n, kg CO2.
(3) Solid feedstock. You must calculate the total CO2
process emissions from solid feedstock according to Equation G-3 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.029
[[Page 16646]]
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Mass of the solid feedstock used in month n
(kg of feedstock).
(CC)n = Average carbon content of the solid feedstock,
from the analysis results for month n (kg C per kg of feedstock).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(RCO2)n = CO2 captured or recovered
for use in urea or methanol production for month n, kg
CO2.
Sec. 98.74 Monitoring and QA/QC requirements.
(a) Facilities must continuously measure the quantity of gaseous or
liquid feedstock consumed using a flow meter. The quantity of solid
feedstock consumed can be obtained from company records and aggregated
on a monthly basis.
(b) You must collect a sample of each feedstock on a monthly basis
and analyze the carbon content using any suitable method incorporated
by reference in Sec. 98.7.
(c) All fuel flow meters and gas composition monitors shall be
calibrated prior to the first reporting year, using a suitable method
published by a consensus standards organization (e.g., ASTM, ASME, API,
AGA, or others). Alternatively, calibration procedures specified by the
flow meter manufacturer may be used. Fuel flow meters and gas
composition monitors shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer, whichever is more
frequent.
(d) You must document the procedures used to ensure the accuracy of
the estimates of feedstock consumption.
Sec. 98.75 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation), a substitute data value for the
missing parameter shall be used in the calculations, according to the
requirements in paragraphs (a) and (b) of this section.
(a) For missing feedstock supply rates, use the lesser of the
maximum supply rate that the unit is capable of processing or the
maximum supply rate that the meter can measure.
(b) There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are
determined to be invalid.
Sec. 98.76 Data reporting requirements.
In addition to the information required by Sec. 98.3(c) of subpart
A of this part, each annual report must contain the information
specified in paragraphs (a) through (c) for each ammonia manufacturing
process unit:
(a) Annual CO2 process emissions (metric tons).
(b) Total quantity of feedstock consumed for ammonia manufacturing.
(c) Monthly analyses of carbon content for each feedstock used in
ammonia manufacturing (kg carbon/kg of feedstock).
Sec. 98.77 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) and (b) of this section.
(a) Method used for determining quantity of feedstock used.
(b) Monthly analyses of carbon content for each feedstock used in
ammonia manufacturing.
Sec. 98.78 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart H--Cement Production
Sec. 98.80 Definition of the source category.
The cement production source category consists of each kiln and
each in-line kiln/raw mill at any portland cement manufacturing
facility including alkali bypasses, and includes kilns and in-line
kiln/raw mills that burn hazardous waste.
Sec. 98.81 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a cement production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.82 GHGs to report.
Carbon dioxide (CO2) process emissions from calcination,
reported for all kilns combined.
CO2, N2O, and CH4 emissions from
fuel combustion at each kiln and any other stationary combustion units,
by following the requirements of 40 CFR 98, subpart C (General
Stationary Fuel Combustion Sources).
Sec. 98.83 Calculating GHG emissions.
(a) Cement kilns that meet the conditions specified in Sec.
98.33(b)(5)(ii) or (iii) shall calculate total CO2 emissions
using the Tier 4 Calculation Methodology specified in Sec.
98.33(a)(4).
(b) If CEMS are not used to determine the total annual
CO2 emissions from kilns, then you must calculate process
CO2 emissions by following paragraphs (b)(1) through (3) of
this section.
(1) Calculate CO2 process emissions from all kilns at
the facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.030
Where:
CO2 CMF = Total annual emissions of
CO2 from cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of
CO2 from clinker production from kiln m, metric tons.
CO2 rm = Total annual emissions of
CO2 from raw materials, metric tons.
k = Total number of kilns at a cement manufacturing facility.
(2) CO2 emissions from clinker production. Calculate CO2
emissions from each kiln using Equations H-2 and H-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.031
[[Page 16647]]
Where:
Cli,j = Quantity of clinker produced in month j from kiln
m, metric tons.
EFCli,j = Kiln specific clinker emission factor for month
j for kiln m, metric tons CO2/metric ton clinker computed
as specified in Equation H-3 of this section.
CKDi = Cement kiln dust (CKD) discarded in quarter i from
kiln m, metric tons.
EFCKD,i = Kiln specific fraction of calcined material in
CKD not recycled to the kiln, for quarter i from kiln m, as
determined in paragraph (c)(2)(i).
p = Number of months for clinker calculation, 12.
r = Number of quarters for CKD calculation, 4.
[GRAPHIC] [TIFF OMITTED] TP10AP09.032
Where:
CliCaO = Monthly CaO content of Clinker, wt% as
determined in Sec. 98.84(b).
MRCaO = Molecular Ratio of CO2/CaO = 0.785.
CliMgO = Monthly MgO content of Clinker, wt% as
determined in Sec. 98.84(b).
MRMgO = Molecular Ratio of CO2/MgO = 1.092.
ClincCaO = Monthly non-carbonate CaO of Clinker, wt% as
determined in Sec. 98.84(b).
ClincMgO = Monthly non-carbonate MgO of Clinker, wt% as
determined in Sec. 98.84(b).
(i) EFCKD must be determined through X-ray fluorescence
(XRF) test or other testing method specified in Sec. 98.84(a), except
as provided in paragraph (c)(2)(ii) of this section.
(ii) A default factor of 1.0, which assumes that 100 percent of all
carbonates in CKD are calcined, may be used instead of testing to
determine EFCKD.
(iii) The weight percents of CaO, MgO, non-carbonate CaO, and non-
carbonate MgO of clinker used in Equation H-3 must be determined using
the measurement methods specified in Sec. 98.84(b).
(3) CO2 emissions from raw materials. Calculate CO2
emissions using Equation H-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.033
Where:
rm = The amount of raw material consumed annually, metric tons/yr.
TOCrm = Organic carbon content of raw material, as
determined in Sec. 98.84(c) or using a default factor of 0.2
percent of total raw material weight.
3.664 = The CO2 to carbon molar ratio.
Sec. 98.84 Monitoring and QA/QC requirements.
(a) You must determine the plant-specific fraction of calcined
material in cement kiln dust (CKD) not recycled to the kiln (EFCKD)
using an x-ray fluorescence test or other enhanced testing method. The
monitoring must be conducted quarterly for each kiln from a CKD sample
drawn from bulk CKD storage.
(b) You must determine the weight percents of CaO, MgO, non-
carbonate CaO, and non-carbonate MgO in clinker from each kiln using an
x-ray fluorescence test or other enhanced testing method. The
monitoring must be conducted monthly for each kiln from a clinker
sample drawn from bulk clinker storage.
(c) The total organic carbon contents of raw materials must be
determined annually using ASTM Method C114-07 or a similar ASTM method
approved for total organic carbon determination in raw mineral
materials. The analysis must be conducted on sample material drawn from
bulk raw material storage for each category of raw material (i.e.
limestone, sand, shale, iron oxide, and alumina).
(d) The quantity of clinker produced monthly by each kiln must be
determined by direct weight measurement using the same plant
instruments used for accounting purposes, such as weigh hoppers or belt
weigh feeders.
(e) The quantity of CKD discarded quarterly by each kiln must be
determined by direct weight measurement using the same plant
instruments used for accounting purposes, such as weigh hoppers or belt
weigh feeders.
(f) The quantity of each category of raw materials consumed
annually by the facility (i.e. limestone, sand, shale, iron oxide, and
alumina) must be determined by direct weight measurement using the same
plant instruments used for accounting purposes, such as weigh hoppers
or belt weigh feeders.
Sec. 98.85 Procedures for estimating missing data.
If the CEMS approach is used to determine CO2 emissions,
the missing data procedures in Sec. 98.35 apply. Procedures for
estimating missing data do not apply to CO2 process
emissions from cement manufacturing facilities calculated according to
Sec. 98.83(b). If data on the carbonate content or organic carbon
content is missing, facilities must undertake a new analysis.
Sec. 98.86 Data reporting requirements.
In addition to the information required by Sec. 98.3(b) of this
part, each annual report must contain the information specified in
paragraphs (a) through (k) of this section for each portland cement
manufacturing facility.
(a) The total combined CO2 emissions from all kilns at
the facility (in metric tons).
(b) Annual clinker production (tons).
(c) Number of kilns.
(d) Annual CKD production (in metric tons).
(e) Total annual fraction of CKD recycled to the kilns (as a
percentage).
(f) Annual weighted average carbonate composition (by carbonate).
(g) Annual weighted average fraction of calcination achieved (for
each carbonate, percent).
(h) Site-specific emission factor (metric tons CO2/
metric ton clinker produced).
(i) Organic carbon content of the raw material (percent).
(j) Annual consumption of raw material (metric tons).
(k) Facilities that use CEMS must also comply with the data
reporting requirements specified in Sec. 98.36(d)(iv).
Sec. 98.87 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (i) of this
section for each portland cement manufacturing facility.
(a) Monthly carbonate consumption.
(b) Monthly clinker production (tons).
(c) Monthly CKD production (in metric tons).
(d) Total annual fraction of CKD recycled to the kiln (as a
percentage).
(e) Monthly analysis of carbonate composition in clinker (by
carbonate).
(f) Monthly analysis of fraction of calcination achieved for CKD
and each carbonate.
[[Page 16648]]
(g) Monthly cement production.
(h) Documentation of calculated site-specific clinker emission
factor.
(i) Facilities that use CEMS must also comply with the
recordkeeping requirements specified in Sec. 98.37.
Sec. 98.88 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart I--Electronics Manufacturing
Sec. 98.90 Definition of the source category.
(a) The electronics source category consists of any of the
processes listed in paragraphs (a)(1) through (5) of this section.
Electronics manufacturing facilities include but are not limited to
facilities that manufacture semiconductors, liquid crystal displays
(LCD), microelectromechanical systems (MEMs), and photovoltaic (PV)
cells.
(1) Each electronics manufacturing production process in which the
etching process uses plasma-generated fluorine atoms, which chemically
react with exposed thin films (e.g., dielectric, metals) and silicon to
selectively remove portions of material.
(2) Each electronics manufacturing production process in which
chambers used for depositing thin films are cleaned periodically using
plasma-generated fluorine atoms from fluorinated and other gases.
(3) Each electronics manufacturing production process in which some
fluorinated compounds can be transformed in the plasma processes into
different fluorinated compounds which are then exhausted, unless
abated, into the atmosphere.
(4) Each electronics manufacturing production process in which the
chemical vapor deposition process uses nitrous oxide.
(5) Each electronics manufacturing production process in which
fluorinated GHGs are used as heat transfer fluids (HTFs) to cool
process equipment, control temperature during device testing, and
solder semiconductor devices to circuit boards.
Sec. 98.91 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an electronics manufacturing process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.92 GHGs to report.
(a) You shall report emissions of nitrous oxide and fluorinated
GHGs (as defined in Sec. 98.6). The fluorinated GHGs that are emitted
from electronics production processes include but are not limited to
those listed in Table I-1 of this subpart. You must report:
(1) Fluorinated GHGs from plasma etching.
(2) Fluorinated GHGs from chamber cleaning.
(3) Nitrous oxide from chemical vapor deposition.
(4) Fluorinated GHGs from heat transfer fluid use.
(b) You shall report CO2, N2O and
CH4 combustion-related emissions, if any, at electronics
manufacturing facilities. For stationary fuel combustion sources,
follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements in subpart C of this part.
Sec. 98.93 Calculating GHG emissions.
(a) You shall calculate annual facility-level F-GHG emissions of
each F-GHG from all etching processes using Equations I-1 and I-2 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.034
Where:
etchEi = Annual emissions of input gas i from all etch
processes
Eij = Annual emissions of input gas i from etch process j
(metric tons), calculated in equation I-5.
[GRAPHIC] [TIFF OMITTED] TP10AP09.035
Where:
etchBEk = Annual emissions of by-product gas k from all
etch processes (metric tons).
BEkij = Annual emissions of by-product k formed from
input gas i during etch process j (metric tons), calculated in
equation I-6.
(b) You shall calculate annual facility-level F-GHG emissions of
each F-GHG from all CVD chamber cleaning processes using Equations I-3
and I-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.036
Where:
cleanEi = Annual emissions of input gas i from all CVD
cleaning processes (metric tons).
Eij = Annual emissions of input gas i from CVD cleaning
process j (metric tons), calculated in equation I-5.
[GRAPHIC] [TIFF OMITTED] TP10AP09.037
Where:
cleanBEk = Annual emissions of by-product gas k from all
CVD cleaning processes (metric tons)
BEkij = Annual emissions of by-product k formed from
input gas i during CVD cleaning process j (metric tons), calculated
in equation I-6.
(c) You shall calculate annual facility-level F-GHG emissions for
each etching process and each chamber cleaning process using Equations
I-5 and I-6 of this section.
(1) Semiconductor facilities that have an annual capacity of
greater than 10,500 m\2\ silicon shall use process-specific process
utilization and by-product formation factors determined as specified in
Sec. 98.94(b).
(2) All other electronics facilities shall use the default emission
factors for process utilization and by-production formation shown in
Tables I-2, I-3, and I-4 of subpart I for semiconductor and MEMs, LCD,
and PV manufacturing, respectively.
[GRAPHIC] [TIFF OMITTED] TP10AP09.038
Where:
Eij = Annual emissions of input gas i from process j
(metric tons).
Cij = Amount of input gas i consumed in process j, (kg).
Uij = Process utilization rate for input gas i during
process j.
aij = Fraction of input gas i used in process j with
abatement devices.
dij = Fraction of input gas i destroyed in abatement
devices connected to process j (defined in Equation I-11). This is
zero unless the facility verifies the DRE of the device pursuant to
Sec. 98.94(c) of Subpart I.
0.001 = Conversion factor from kg to metric tons.
[GRAPHIC] [TIFF OMITTED] TP10AP09.039
[[Page 16649]]
Where:
BEkij = Annual emissions of by-product k formed from
input gas i during process j (metric tons).
Bkij = Kg of gas k created as a by-product per kg of
input gas i consumed in process j.
Cij = Amount of input gas i consumed in process j (kg).
aij = Fraction of input gas i used in process j with
abatement devices.
dkj = Fraction of by-product gas k destroyed in abatement
devices connected to process (j). This is zero unless the facility
verifies the DRE of the device pursuant to Sec. 98.94(c) of Subpart
I.
0.001 = Conversion factor from kg to metric tons.
(d) You shall report annual N2O facility-level emissions
during chemical vapor deposition using Equation I-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.040
Where:
E(N2O) = Annual emissions of N2O (metric tons/
year).
CN2O = Annual Consumption of N2O
(kg).
0.001 = Conversion factor from kg to metric tons.
(e) For facilities that use heat transfer fluids, you shall report
the annual emissions of fluorinated GHG heat transfer fluids using
Equation I-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.041
Where:
EHi = Emissions of fluorinated GHG heat transfer fluid i,
(metric tons/year).
Density = Density of heat transfer fluid i (kg/l).
Iio = Inventory of heat transfer fluid i at the end of
previous reporting period (l).
Pit = Net purchases of heat transfer fluid i during the
current reporting period (l).
Nit = Total nameplate capacity [charge] of equipment that
contains heat transfer fluid i and that is installed during the
current reporting period.
Rit = Total nameplate capacity [charge] of equipment that
contains heat transfer fluid i and that is retired during the
current reporting period.
Iit = Inventory of heat transfer fluid i at the end of
current reporting period (l).
Dit = Amount of heat transfer fluid i recovered and sent
off site during current reporting period, (l).
0.001 = Conversion factor from kg to metric tons.
Sec. 98.94 Monitoring and QA/QC requirements.
(a) You must estimate gas consumption according to the requirements
in paragraph (a)(1) or (a)(2) of this section for each process or
process type, as appropriate.
(1) Monitor changes in container mass and inventories for each gas
using weigh scales with an accuracy and precision of one percent of
full scale or better. Calculate the gas consumption using Equation I-9
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.042
Where:
Ci = Annual consumption of input gas i (metric tons/
year).
IBi = Inventory of input gas i stored in cylinders or
other containers at the beginning of the year, including heels (kg).
IEi = Inventory of input gas i stored in cylinders or
other containers at the end of the year, including heels (kg).
A = Acquisitions of that gas during the year through purchases or
other transactions, including heels in cylinders or other containers
returned to the electronics production facility (kg).
D = Disbursements of gas through sales or other transactions during
the year, including heels in cylinders or other containers returned
by the electronics production facility to the gas distributor (kg).
0.001 = Conversion factor from kg to metric tons.
(2) Monitor the mass flow of the pure gas into the system using
flowmeters. The flowmeters must have an accuracy and precision of one
percent of full scale or better.
(b) If you use fluorinated GHG utilization rates and by-product
emission factors other than the defaults in Tables I-2, I-3, or I-4 of
Subpart I, you must use fluorinated GHG utilization rates and by-
product emission factors that have been measured using the
International SEMATECH Manufacturing Initiative's Guideline for
Environmental Characterization of Semiconductor Process Equipment. You
may use fluorinated GHG utilization rates and by-product emission
factors measured by manufacturing equipment suppliers if the conditions
in paragraph (b)(1) and (2) of this section are met.
(1) The manufacturing equipment supplier has measured the GHG
utilization rates and by-product emission factors using the
International SEMATECH Guideline.
(2) The conditions under which the measurements were made are
representative of your facility's F-GHG emitting processes.
(c) If your facility employs abatement devices and you wish to
reflect the emission reductions due to these devices in Sec. 98.93(c),
you must verify the destruction or removal efficiency (DRE) of the
devices using the methods in either paragraph (c)(1) or (2) of this
section.
(1) Experimentally determine the effective dilution through the
abatement device and measure abatement DRE during actual or simulated
process conditions by following the procedures of this paragraph.
(i) Measure the concentrations of F-GHGs exiting the process tool
and entering and exiting the abatement system under operating process
and abatement system conditions that are representative of those for
which F-GHG emissions are estimated and abatement-system DRE is used
for the F-GHG reporting period.\1\
---------------------------------------------------------------------------
\1\ Abatement system means a point-of-use (POU) abatement system
whereby a single abatement system is attached to a single process
tool or single process chamber of a multi-chamber tool.
---------------------------------------------------------------------------
(ii) Measure the dilution through the abatement system and
calculate the dilution factor under the representative operating
conditions given in paragraph (c)(i) of this section by using the
tracer method. This method consists of injecting known flows of a non-
reactive gas (such as krypton) at the inlet of the abatement system,
measuring the time-averaged concentrations of krypton entering
([Kr]in) and exiting ([Kr]out) the abatement
system, and calculating the dilution factor (DF) as the ratio of the
time-averaged measured krypton concentrations entering and exiting the
abatement system, using equation I-10 of this section.
[[Page 16650]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.043
(iii) Measure the F-GHG concentrations in and out of the device
with all process chambers connected to the F-GHG abatement system and
under the production and abatement system conditions for which F-GHG
emissions are estimated for the reporting period.\2\
---------------------------------------------------------------------------
\2\ Most process tools have multiple chambers. For combustion-
type abatement systems, the outlets of each chamber separately enter
the destruction-reactor because premixing of certain gaseous
mixtures may be conducive to fire or explosion. For the less-
frequently used plasma-type POU abatement systems, there is one
system per chamber.
---------------------------------------------------------------------------
(iv) Calculate abatement system DRE using Equation I-11 of this
section, where it is assumed that the measurement pressure and
temperature at the inlet and outlet of the abatement system are
identical and where the relative precision ([egr]) of the quantity
ci-out*DF/ci-in shall not exceed 10
percent (two standard deviations) using proper statistical methods.
[GRAPHIC] [TIFF OMITTED] TP10AP09.044
Where:
dij = Destruction or removal efficiency (DRE)
ci-in = Concentration of gas i in the inflow to the
abatement system (ppm).
ci-out = Concentration of gas i in the outflow from the
abatement system (ppm).
DF = Dilution Factor calculated using Equation I-10.
(v) The DF may not be obtained by calculation from flows other than
those obtained by using the tracer method described in paragraph (ii)
of this section.
(2) Install abatement devices that have been tested by a third
party (e.g., UL) according to EPA's Protocol for Measuring Destruction
or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement
Equipment in Electronics Manufacturing. This testing may be obtained by
the manufacturer of the equipment.
(d) Abatement devices must be operated within the manufacturer's
specified equipment lifetime and gas flow and mix limits and must be
maintained according to the manufacturer's guidelines.
(e) You shall adhere to the QA/QC procedures of this paragraph when
estimating F-GHG and N2O emissions from cleaning/etching
processes:
(1) You shall follow the QA/QC procedures in the International
SEMATECH Manufacturing Initiative's Guideline for Environmental
Characterization of Semiconductor Process Equipment when estimating
facility-specific gas process utilization and by-product gas formation.
(2) You shall follow the QA/QC procedures in the EPA DRE
measurement protocol when estimating abatement device DRE.
(3) You shall certify that abatement devices are maintained in
accordance with manufacturer specified guidelines.
(4) You shall certify that gas consumption is tracked to a high
degree of precision as part of normal facility operations and that
further QA/QC is not required.
(f) You shall adhere to the QA/QC procedures of this paragraph when
estimating F-GHG emissions from heat transfer fluid use:
(1) You shall review all inputs to Equation I-4 of this section to
ensure that all inputs and outputs to the facility's system are
accounted for.
(2) You shall not enter negative inputs into the mass balance
Equation I-4 of this section and shall ensure that no negative
emissions are calculated.
(3) You shall ensure that the beginning of year inventory matches
the end of year inventory from previous year.
(g) All flowmeters, scales, load cells, and volumetric and density
measures used to measure quantities that are to be reported under Sec.
98.92 and Sec. 98.96 shall be calibrated using suitable NIST-traceable
standards and suitable methods published by a consensus standards
organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively,
calibration procedures specified by the flowmeter, scale, or load cell
manufacturer may be used. Calibration shall be performed prior to the
first reporting year. After the initial calibration, recalibration
shall be performed at least annually or at the minimum frequency
specified by the manufacturer, whichever is more frequent.
(h) All instruments (e.g., mass spectrometers and fourier transform
infrared measuring systems) used to determine the concentration of
fluorinated greenhouse gases in process streams shall be calibrated
just prior to DRE, gas utilization, or product formation measurement
through analysis of certified standards with known concentrations of
the same chemicals in the same ranges (fractions by mass) as the
process samples. Calibration gases prepared from a high-concentration
certified standard using a gas dilution system that meets the
requirements specified in Test Method 205, 40 CFR Part 51, Appendix M
may also be used.
Sec. 98.95 Procedures for estimating missing data.
(a) For semiconductor facilities that have an annual capacity of
greater than 10,500 m2 silicon, you shall estimate missing
site-specific gas process utilization and by-product formation using
default factors from Tables I-2 through I-4 of this subpart. However,
use of these default factors shall be restricted to less than 5 percent
of the total facility emissions.
(b) For facilities using heat transfer fluids and missing data for
one or more of the parameters in Equation I-8, you shall estimate heat
transfer fluid emissions using the arithmetic average of the emission
rates for the year immediately preceding the period of missing data and
the months immediately following the period of missing data.
Alternatively, you may estimate missing information using records from
the heat transfer fluid supplier. You shall document the method used
and values estimated for all missing data values.
(c) If the methods specified in paragraphs (a) and (b) of this
section are likely to significantly under- or overestimate the value of
the parameter during the period when data were missing (e.g., because
the monitoring failure was linked to a process disturbance that is
likely to have significantly increased the F-GHG emission rate), you
shall develop a best estimate of the parameter, documenting the methods
used, the rationale behind them, and the reasons why the methods
specified in paragraphs (a) and (b) of this section would lead to a
significant under-or overestimate of the parameter.
Sec. 98.96 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), you shall
include in each annual report the following information for each
electronics manufacturer.
(a) Emissions of each GHG emitted from all plasma etching
processes, all chamber cleaning, all chemical vapor deposition
processes, and all heat transfer fluid use, respectively.
(b) The method, mass of input F-GHG gases, and emission factors
used for estimating F-GHG emissions.
(c) Production in terms of substrate surface area (e.g., silicon,
PV-cell, LCD).
(d) Factors used for gas process utilization and by-product
formation, and the source and uncertainty for each factor.
(e) The verified DRE and its uncertainty for each abatement device
used, if you have verified the DRE pursuant to Sec. 98.94(c).
[[Page 16651]]
(f) Fraction of each gas fed into each process type with abatement
devices.
(g) Description of abatement devices, including the number of
devices of each manufacturer and model.
(h) For heat transfer fluid emissions, inputs in the mass-balance
Equation.
(i) Example calculations for F-GHG, N2O, and heat
transfer fluid emissions.
(j) Estimate of the overall uncertainty in the emissions estimate.
Sec. 98.97 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) Data used to estimate emissions including all spreadsheets and
copies of calculations used to estimate emissions.
(b) Documentation for the values used for GHG utilization rates and
by-product emission factors, including documentation that these were
measured using the the International SEMATECH Manufacturing
Initiative's Guideline for Environmental Characterization of
Semiconductor Process Equipment.
(c) The date and results of the initial and any subsequent tests of
emission control device DRE, including the following information:
(1) Dated certification, by the technician who made the
measurement, that the dilution factor was determined using the tracer
method.
(2) Dated certification, by the technician who made the
measurement, that the DRE was calculated using the formula given in
Sec. 98.94(c)(1)(iv).
(3) Documentation of the measured flows, concentrations and
calculations used to calculate DF, relative precision ([egr]), and DRE.
(d) The date and results of the initial and any subsequent tests to
determine process tool gas utilization and by-product formation
factors.
(e) Abatement device calibration and maintenance records.
Sec. 98.98 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table I-1 of Subpart I--GHGs Typically Used by the Electronics Industry
------------------------------------------------------------------------
Product type F-GHGs Used during manufacture
------------------------------------------------------------------------
Electronics....................... CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
C4F6, C5F8, CHF3, CH2F2, NF3, SF6,
and HTFs (CF3-(O-CF(CF3)-CF2)n-(O-
CF2)m-O-CF3, CnF2n+2,
CnF2n+1(O)CmF2m+1, CnF2nO,
(CnF2n+1)3N)
------------------------------------------------------------------------
Table I-2 of Subpart I--Default Emission Factors for Semiconductor and MEMs Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
Factors
Process gases -----------------------------------------------------------------------------------------------
Etch 1-Ui CVD 1-Ui Etch BCF4 Etch BC2F6 CVD BCF4 CVD BC3F8
--------------------------------------------------------------------------------------------------------------------------------------------------------
CF4..................................................... 0.7 0.9 NA NA NA NA
C2F6.................................................... 0.4* 0.6 0.4* NA 0.1 NA
CHF3.................................................... 0.4* NA 0.07* NA NA NA
CH2F2................................................... 0.06* NA 0.08* NA NA NA
C3F8.................................................... NA 0.4 NA NA 0.1 NA
c-C4F8.................................................. 0.2* 0.1 0.2 0.2 0.1 NA
NF3..................................................... NA 0.02 NA NA [dagger] 0.02 NA
Remote
NF3..................................................... 0.2 0.2 NA NA [dagger] 0.1 NA
SF6..................................................... 0.2 NA NA NA NA NA
C4F6a................................................... 0.1 NA 0.3* 0.2* NA NA
C5F8a................................................... 0.2 0.1 0.2 0.2 0.1 NA
C4F8Oa.................................................. NA 0.1 NA NA 0.1 0.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
* Estimate includes multi-gas etch processes.
[dagger] Estimate reflects presence of low-k, carbide and multi-gas etch processes that may contain a C-containing FC additive.
Table I-3 of Subpart I--Default Emission Factors for LCD Manufacturing
----------------------------------------------------------------------------------------------------------------
Factors
Process gases -------------------------------------------------------------------------------
Etch 1-Ui CVD 1-Ui Etch BCF4 Etch BCHF3 Etch BC2F6
----------------------------------------------------------------------------------------------------------------
CF4............................. 0.6 NA NA NA NA
C2F6............................ NA NA NA NA NA
CHF3............................ 0.2 NA 0.07 NA 0.05
CH2F2........................... NA NA NA NA NA
C3F8............................ NA NA NA NA NA
c-C4F8.......................... 0.1 NA 0.009 0.02 NA
NF3 Remote...................... NA 0.03 NA NA NA
NF3............................. NA 0.3 NA NA NA
SF6............................. 0.3 0.9 NA NA NA
----------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
[[Page 16652]]
Table I-4 of Subpart I--Default Emission Factors for PV Manufacturing
----------------------------------------------------------------------------------------------------------------
Factors
Process gases -------------------------------------------------------------------------------
Etch 1-Ui CVD 1-Ui Etch BCF4 Etch BC2F6 CVD BCF4
----------------------------------------------------------------------------------------------------------------
CF4............................. 0.7 NA NA NA NA
C2F6............................ 0.4 0.6 0.2 NA 0.2
CHF3............................ 0.4 NA NA NA NA
CH2F2........................... NA NA NA NA NA
C3F8............................ NA 0.1 NA NA 0.2
c-C4F8.......................... 0.2 0.1 0.1 0.1 0.1
NF3 Remote...................... NA NA NA NA NA
NF3............................. NA 0.3 NA NA NA
SF6............................. 0.4 0.4 NA NA NA
----------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
Subpart J--Ethanol Production
Sec. 98.100 Definition of the source category.
An ethanol production facility is a facility that produces ethanol
from the fermentation of sugar, starch, grain, or cellulosic biomass
feedstocks; or produces ethanol synthetically from ethylene or hydrogen
and carbon monoxide.
Sec. 98.101 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an ethanol production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.102 GHGs to report.
You must report:
(a) Emissions of CO2, N2O, and CH4 from on-site stationary
combustion. You must follow the calculation procedures, monitoring and
QA/QC methods, missing data procedures, reporting requirements, and
recordkeeping requirements of subpart C of this part.
(b) Emissions of CH4 from on-site landfills. You must follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
subpart HH of this part.
(c) Emissions of CH4 from on-site wastewater treatment.
You must follow the calculation procedures, monitoring and QA/QC
methods, missing data procedures, reporting requirements, and
recordkeeping requirements of subpart II of this part.
Sec. 98.103 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart K--Ferroalloy Production
Sec. 98.110 Definition of the source category.
The ferroalloy production source category consists of any facility
that uses pyrometallurgical techniques to produce any of the following
metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel,
ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium,
silicomanganese, or silicon metal.
Sec. 98.111 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a ferroalloy production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.112 GHGs to report.
(a) You must report the CO2 emissions from each electric
arc furnace used for ferroalloy production.
(b) You must report the CH4 emissions from each electric
arc furnace used for the production of any ferroalloy listed in Table
K-1 of this subpart.
(c) You must report the CO2, CH4, and
N2O emissions from each stationary combustion unit following
the requirements specified in subpart C of this part.
Sec. 98.113 Calculating GHG emissions.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must estimate total CO2 emissions
according to the requirements in Sec. 98.33.
(b) If you do not operate and maintain a CEMS that measures total
CO2 process emissions consistent with the requirements in
subpart C, you must determine using the procedure specified in
paragraphs (b)(1) and (2) of this section the total CO2
emissions from all electric arc furnaces that are used for ferroalloy
production.
(1) For each EAF at your facility used for ferroalloy production,
you must determine the mass of carbon in each carbon-containing input
and output material for the electric arc furnace for each calendar
month using Equation K-1 of this section. Carbon containing input
materials include carbon eletrodes and carbonaceous reducing agents.
[[Page 16653]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.045
Where:
ECO2 = Annual CO2 mass emissions from an
individual EAF, metric tons.
Mreducing agenti = Mass of reducing agent i fed, charged,
or otherwise introduced into the EAF, metric tons.
Creducing agenti = Carbon content in reducing agent i,
metric tons of C/metric ton reducing agent.
Melectrodem = Mass of carbon electrode m consumed in the
EAF, metric tons.
Celectrodem = Carbon content of the carbon electrode m,
percent by weight, expressed as a decimal fraction.
Moreh = Mass of ore h charged to the EAF, metric tons.
Coreh = Carbon content in ore h, metric tons of C/metric
ton ore.
Mfluxj = Mass of flux material j fed, charged, or
otherwise introduced into the EAF to facilitate slag formation,
metric tons.
Cfluxj = Carbon content in flux material j, metric tons
of C/metric ton material.
Mproductk = Mass of alloy product k tapped from EAF,
metric tons.
Cproductk = Carbon content in alloy product k, metric
tons of C/metric ton product.
Mnon-product outgoingl = Mass of non-product outgoing
material l removed from EAF, metric tons.
Cnon-product outgoingl = Carbon content in non-product
outgoing material l, metric tons of C/metric ton.
(2) You must determine the total CO2 emissions from
the electric arc furnaces using Equation K-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.046
Where:
CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions calcaluated using
Equation K-1 of this supart, metric tons/year.
k = Total number of EAFs at facility used for the ferroalloy
production.
(c) For the electric arc furnaces used at your facility for the
production of any ferroalloy listed in Table K-1 of this subpart, you
must determine the total CH4 emissions using the procedure
specified in paragraphs (c)(1) and (2) of this section.
(1) For each EAF, calculate annual CH4 emissions using
Equation K-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.047
Where:
ECH4 = Annual CH4 emissions from an individual
EAF, metric tons.
Mproducti = Annual mass of alloy product i produced in
the EAF, metric tons.
EFproducti = CH4 emission factor for alloy
product i from Table K-1 of this subpart, kg of CH4
emissions per metric ton of alloy product i.
(2) You must determine the total CH4 emissions using
Equation K-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.048
Where:
CH4 = Total annual CH4 emissions, metric tons/
year.
ECH4j = Annual CH4 emissions from EAF k
calculated using Equation K-3 of this section, metric tons/year.
j = Total number of EAFs at facility used for the production of
ferroalloys listed in Table K-1 of this subpart.
Sec. 98.114 Monitoring and QA/QC requirements.
If you determine CO2 emissions using the carbon balance
procedure in Sec. 98.113(b), you must meet the requirements specified
in paragraphs (a) through (c) of this section.
(a) Determine the mass of each solid carbon-containing process
input and output material by direct measurements or calculations using
process operating information, and record the total mass
[[Page 16654]]
of each material consumed or produced for each calendar month.
(b) For each process input and output material identified in
paragraph (a) of this section, you must determine the average carbon
content of the material for the specified period using information
provided by your material supplier or by collecting and analyzing a
representative sample of the material.
(c) For each input material identified in paragraph (a) of this
section for which the carbon content is not provided by your material
supplier, the carbon content of the material must be analyzed by an
independent certified laboratory at least annually using the test
methods (and their QA/QC procedures) in Sec. 98.7. Use ASTM E1941-04
(``Standard Test Method for Determination of Carbon in Refractory and
Reactive Metals and Their Alloys'') for analysis of metal ore and alloy
product; ASTM D5373-02 (``Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal and Coke'') for analysis of carbonaceous reducing agents and
carbon electrodes, and ASTM C25-06 (``Standard Test Methods for
Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'') for
analysis of flux materials such as limestone or dolomite.
Sec. 98.115 Procedures for estimating missing data.
For the carbon input procedure in Sec. 98.113(b), a complete
record of all measured parameters used in the GHG emissions
calculations is required (e.g., raw materials carbon content values,
etc.). Therefore, whenever a quality-assured value of a required
parameter is unavailable, a substitute data value for the missing
parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute
data value shall be the arithmetic average of the quality-assured
values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input or
output material consumption, the substitute data value shall be the
best available estimate of the mass of the input or output material.
The owner or operator shall document and keep records of the procedures
used for all such estimates.
(c) If you are required to calculate CH4 emissions for
the electric arc furnace as specified in Sec. 98.113(c), then you are
required to have 100 percent of the specified data for each reporting
period.
Sec. 98.116 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (f) of this section.
(a) Annual CO2 emissions from each electric arc furnace
used for ferroalloy production, in metric tons and the method used to
estimate these emissions.
(b) Annual CH4 emissions from each electric arc furnace
used for the production of any ferroalloy listed in Table K-1 of this
subpart.
(c) Facility ferroalloy product production capacity (metric tons).
(d) Annual facility production quantity for each ferroalloy product
(metric tons).
(d) Number of facility operating hours in calendar year.
(f) If you use the carbon balance procedure, report for each
carbon-containing input and output material consumed or used (other
than fuel), the information specified in paragraphs (g)(1) and (2) of
this section.
(1) Annual material quantity (in metric tons).
(2) Annual average of the monthly carbon content determinations for
each material and the method used for the determination (e.g., supplier
provided information, analyses of representative samples you
collected).
Sec. 98.117 Records that must be retained.
In addition to the records required by Sec. 98.3(g) of this part,
you must retain the records specified in paragraphs (a) through (e) of
this section.
(a) Monthly facility production quantity for each ferroalloy
product (in metric tons).
(b) Number of facility operating hours each month.
(c) If you use the carbon balance procedure, record for each
carbon-containing input and output material consumed or used (other
than fuel), the information specified in paragraphs (c)(1) and (2) of
this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and
records of the supplier provided information or analyses used for the
determination.
(d) You must keep records that include a detailed explanation of
how company records of measurements are used to estimate the carbon
input input and output to each electric arc furnace. You also must
document the procedures used to ensure the accuracy of the measurements
of materials fed, charged, or placed in an affected unit including, but
not limited to, calibration of weighing equipment and other measurement
devices. The estimated accuracy of measurements made with these devices
must also be recorded, and the technical basis for these estimates must
be provided.
(e) If you are required to calculate CH4 emissions for
the electric arc furnace as specified in Sec. 98.113(c), you must
maintain records of the total amount of each alloy product produced for
the specified reporting period, and the appropriate alloy-product
specific emission factor used to calculate CH4 emissions.
Sec. 98.118 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table K-1 of Subpart K--Electric Arc Furnace (EAF) CH\4\ Emission Factors
----------------------------------------------------------------------------------------------------------------
CH4 Emission factor (kg CH4 per metric ton
product)
-----------------------------------------------
EAF operation
Alloy product produced in EAF -----------------------------------------------
Sprinkle-
Batch-charging Sprinkle- charging and
charging a >750 [deg] Cb
----------------------------------------------------------------------------------------------------------------
silicon metal................................................... 1.5 1.2 0.7
ferrosilicon 90%................................................ 1.4 1.1 0.6
ferrosilicon 75%................................................ 1.3 1.0 0.5
[[Page 16655]]
ferrosilicon 65%................................................ 1.3 1.0 0.5
----------------------------------------------------------------------------------------------------------------
\a\ Sprinkle-charging is charging intermittently every minute.
\b\ Temperature measured in off-gas channel downstream of the furnace hood.
Subpart L--Fluorinated Greenhouse Gas Production
Sec. 98.120 Definition of the source category.
The fluorinated gas production source category consists of
facilities that produce a fluorinated GHG from any raw material or
feedstock chemical. Producing a fluorinated GHG does not include the
reuse or recycling of a fluorinated GHG or the generation of HFC-23
during the production of HCFC-22.
Sec. 98.121 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a fluorinated greenhouse gas production process and the
facility meets the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.122 GHGs to report.
(a) You must report the CO2, N2O, and
CH4 emissions from each on-site stationary combustion unit.
For these stationary combustion units, you must follow the applicable
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
subpart C of this part.
(b) You must report the total mass of each fluorinated GHG emitted
from each fluorinated GHG production process and from all fluorinated
GHG production processes at the facility.
Sec. 98.123 Calculating GHG emissions.
(a) The total mass of each fluorinated GHG product emitted annually
from all fluorinated GHG production processes shall be estimated by
using Equation L-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.049
Where:
EP = Total mass of each fluorinated GHG product emitted
annually from all production processes (metric tons).
EPip = Total mass of the fluorinated GHG product emitted
from production process i over the period p (metric tons, defined in
Equation L-3 of this section).
n = Number of concentration and flow measurement periods for the
year.
m = Number of production processes.
(b) The total mass of fluorinated GHG by-product k emitted annually
from all fluorinated GHG production processes shall be estimated by
using Equation L-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.050
Where:
EBk = Total mass of fluorinated GHG by-product k emitted
annually from all production processes (metric tons).
EBkip = Total mass of fluorinated GHG by-product k
emitted from production process i over the period p (metric tons,
defined in Equation L-8 on this section).
n = Number of concentration and flow measurement periods for the
year.
m = Number of production processes.
(c) The total mass of each fluorinated GHG product emitted from
production process i over the period p shall be estimated at least
daily by calculating the difference between the expected production of
the fluorinated GHG based on the consumption of reactants (e.g., HF and
a chlorocarbon reactant) and the measured production of the fluorinated
GHG, accounting for yield losses related to by-products and wastes.
This calculation shall be performed for each reactant, using Equation
L-3 of this section. Estimated emissions shall equal the average of the
results obtained for each reactant.
[GRAPHIC] [TIFF OMITTED] TP10AP09.051
Where:
EPip = Total mass of each fluorinated GHG product emitted
from production process i over the period p (metric tons).
P = Total mass of the fluorinated GHG produced by production process
i over the period p (metric tons).
R = Total mass of the reactant that is consumed by production
process i over the period p (metric tons, defined in Equation L-4).
MWR = Molecular weight of the reactant.
MWP = Molecular weight of the fluorinated GHG produced.
SCR = Stoichiometric coefficient of the reactant.
SCP = Stoichiometric coefficient of the fluorinated GHG
produced.
CP = Concentration (mass fraction) of the fluorinated GHG
product in stream j of destroyed wastes. If this concentration is
only a trace concentration, CP is equal to zero.
WDj = Mass of wastes removed from production process i in
stream j and destroyed over the period p (metric tons, defined in
Equation L-5 of this section).
LBkip = Yield loss related to by-product k for production
process i over the period p (metric tons, defined in Equation L-6 of
this section).
q = Number of waste streams destroyed in production process i.
u = Number of by-products generated in production process i.
(d) The total mass of the reactant that is consumed by production
process i over the period p shall be estimated by using Equation L-4 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.052
Where:
R = Total mass of the reactant that is consumed by production
process i over the period p (metric tons).
RF = Total mass of the reactant that is fed into
production process i over the period p (metric tons).
[[Page 16656]]
RR = Total mass of the reactant that is permanently
removed from production process i over the period p (metric tons).
(e) The mass of wastes removed from production process i in stream
j and destroyed over the period p shall be estimated using Equation L-5
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.053
Where:
WDj = The mass of wastes removed from production process
i in stream j and destroyed over the period p (metric tons).
WFj = The total mass of wastes removed from production
process i in stream j and fed into the destruction device over the
period p (metric tons).
DE = Destruction Efficiency of the destruction device (fraction).
(f) Yield loss related to by-product k for production process i
over period p shall be estimated using Equation L-6 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.054
Where:
LBkip = Yield loss related to by-product k for production
process i over the period p (metric tons).
Bkip = Mass of by-product k generated by production
process i over the period p (metric tons, defined in Equation L-7 of
this section).
MWP = Molecular weight of the fluorinated GHG produced.
MWBk = Molecular weight of by-product k.
MEBk = Moles of the element shared by the reactant,
product, and by-product k per mole of by-product k.
MEP = Moles of the element shared by the reactant,
product, and by-product k per mole of the product.
(g) If by-product k is responsible for yield loss in production
process i and occurs in any process stream in more than trace
concentrations, the mass of by-product k generated by production
process i over the period p shall be estimated using Equation L-7 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.055
Where:
Bkip = Mass of by-product k generated by production
process i over the period p (metric tons).
CBkj = Concentration (mass fraction) of the by-product k
in stream j of production process i over the period p. If this
concentration is only a trace concentration, CBkj is
equal to zero.
Sj = Mass flow of process stream j of production process
i over the period p.
q = Number of streams in production process i.
(h) If by-product k is responsible for yield loss, is a fluorinated
GHG, occurs in any process stream in more than trace concentrations,
and is not completely recaptured or completely destroyed; the total
mass of by-product k emitted from production process i over the period
p shall be estimated at least daily using Equation L-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.056
Where:
EBkip = Mass of by-product k emitted from production
process i over the period p (metric tons).
Bkip = Mass of by-product k generated by production
process i over the period p (metric tons).
CBkj = Concentration (mass fraction) of the by-product k
in stream j of destroyed wastes over the period p. If this
concentration is only a trace concentration, CBj is equal
to zero.
WDj = The mass of wastes that are removed from production
process i in stream j and that are destroyed over the period p
(metric tons, defined in Equation L-5 of this section).
CBkl = The concentration (mass fraction) of the by-
product k in stream l of recaptured material over the period p. If
this concentration is only a trace concentration, CBkl is
equal to zero.
SRl = The mass of materials that are removed from
production process i in stream l and that are recaptured over the
period p.
q = Number of waste streams destroyed in production process i.
v = Number of streams recaptured in production process i.
Sec. 98.124 Monitoring and QA/QC requirements.
(a) The total mass of fluorinated GHGs produced over the period p
shall be estimated at least daily using the methods and measurements
set forth in Sec. Sec. 98.413(b) and 98.414.
(b) The total mass of each reactant fed into the production process
shall be measured at least daily using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 0.2 percent of full scale or better.
(c) The total mass of each reactant permanently removed from the
production process shall be measured at least daily using flowmeters,
weigh scales, or a combination of volumetric and density measurements
with an accuracy and precision of 0.2 percent of full scale or better.
If the measured mass includes more than trace concentrations of
materials other than the reactant, the concentration of the reactant
shall be measured at least daily using equipment and methods (e.g., gas
chromatography) with an accuracy and precision of 5 percent or better
at the concentrations of the process samples. This concentration (mass
fraction) shall be multiplied by the mass measurement to obtain the
mass of the reactant permanently removed from the production process.
(d) If the waste permanently removed from the production process
and fed into the destruction device contains more than trace
concentrations of the fluorinated GHG product, the mass of waste fed
into the destruction device shall be measured at least daily using
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of 0.2 percent of full
scale or better. If the measured mass includes more than trace
concentrations of materials other than the product, the concentration
of the product shall be measured at least daily using equipment and
methods (e.g., gas chromatography) with an accuracy and precision of 5
percent or better at the concentrations of the process samples.
[[Page 16657]]
(e) If a by-product is responsible for yield loss and occurs in any
process stream in more than trace concentrations, the mass flow of each
process stream that contains more than trace concentrations of the by-
product shall be measured at least daily using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of 0.2 percent of full scale or better. If the
measured mass includes more than trace concentrations of materials
other than the by-product, the concentration of the by-product shall be
measured at least daily using equipment and methods (e.g., gas
chromatography) with an accuracy and precision of 5 percent or better
at the concentrations of the process samples.
(f) If a by-product is a fluorinated GHG, occurs in more than trace
concentrations in any process stream, occurs in more than trace
concentrations in any stream that is recaptured or is fed into a
destruction device, and is not completely recaptured or completely
destroyed; the mass flow of each stream that contains more than trace
concentrations of the by-product and that is recaptured or is fed into
the destruction device or shall be measured at least daily using
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of 0.2 percent of full
scale or better. If the measured mass includes more than trace
concentrations of materials other than the by-product, the
concentration of the by-product shall be measured at least daily using
equipment and methods (e.g., gas chromatography) with an accuracy and
precision of 5 percent or better at the concentrations of the process
samples.
(g) All flowmeters, scales, load cells, and volumetric and density
measures used to measure quantities that are to be reported under Sec.
98.126 shall be calibrated using suitable NIST-traceable standards and
suitable methods published by a consensus standards organization (e.g.,
ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures
specified by the flowmeter, scale, or load cell manufacturer may be
used. Calibration shall be performed prior to the first reporting year.
After the initial calibration, recalibration shall be performed at
least annually or at the minimum frequency specified by the
manufacturer, whichever is more frequent.
(h) All gas chromatographs used to determine the concentration of
fluorinated greenhouse gases in process streams shall be calibrated at
least monthly through analysis of certified standards with known
concentrations of the same chemicals in the same ranges (fractions by
mass) as the process samples. Calibration gases prepared from a high-
concentration certified standard using a gas dilution system that meets
the requirements specified in Test Method 205, 40 CFR Part 51, Appendix
M may also be used.
(i) For purposes of equation L-5, the destruction efficiency can
initially be equated to the destruction efficiency determined during a
previous performance test of the destruction device or, if no
performance test has been done, the destruction efficiency provided by
the manufacturer of the destruction device. Fluorinated GHG production
facilities that destroy fluorinated GHGs shall conduct annual
measurements of mass flow and fluorinated GHG concentrations at the
outlet of the thermal oxidizer in accordance with EPA Method 18 at 40
CFR part 60, appendix A-6. Tests shall be conducted under conditions
that are typical for the production process and destruction device at
the facility. The sensitivity of the emissions tests shall be
sufficient to detect emissions equal to 0.01 percent of the mass of
fluorinated GHGs being fed into the destruction device. If the test
indicates that the actual DE of the destruction device is lower than
the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for
the previously determined DE in the calculations in Sec. 98.123, or
(2) Perform more extensive performance testing of the DE of the
oxidizer and use the DE determined by the more extensive testing in the
calculations in Sec. 98.123.
(j) In their estimates of the mass of fluorinated GHGs destroyed,
fluorinated GHG production facilities that destroy fluorinated GHGs
shall account for any temporary reductions in the destruction
efficiency that result from any startups, shutdowns, or malfunctions of
the destruction device, including departures from the operating
conditions defined in state or local permitting requirements and/or
oxidizer manufacturer specifications.
(k) Fluorinated GHG production facilities shall account for
fluorinated GHG emissions that occur as a result of startups,
shutdowns, and malfunctions, either recording fluorinated GHG emissions
during these events, or documenting that these events do not result in
significant fluorinated GHG emissions.
Sec. 98.125 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required process sample is
not taken), a substitute data value for the missing parameter shall be
used in the calculations, according to the following requirements:
(1) For each missing value of the mass of fluorinated GHG produced,
the mass of reactants fed into the production process, the mass of
reactants permanently removed from the production process, the mass
flow of process streams containing more than trace concentrations of
by-products that lead to yield losses, or the mass of wastes fed into
the destruction device; the substitute value of that parameter shall be
a secondary mass measurement taken during the period the primary mass
measurement was not available. For example, if the mass produced is
usually measured with a flowmeter at the inlet to the day tank and that
flowmeter fails to meet an accuracy or precision test, malfunctions, or
is rendered inoperable; then the mass produced may be estimated by
calculating the change in volume in the day tank and multiplying it by
the density of the product.
(2) For each missing value of fluorinated GHG concentration, the
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately
following the missing data incident. If no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-assured value obtained after the missing
data period.
(3) If the methods specified in paragraphs (a)(1) and (2) of this
section are likely to significantly under- or overestimate the value of
the parameter during the period when data were missing, you shall
develop a best estimate of the parameter, documenting the methods used,
the rationale behind them, and the reasons why the methods specified in
(a)(1) and (2) would lead to a significant under- or overestimate of
the parameter.
Sec. 98.126 Data reporting requirements.
(a) In addition to the information required by Sec. 98.3(c), you
shall report the following information for each production process at
the facility.
[[Page 16658]]
(1) The total mass of the fluorinated GHG produced in metric tons,
by chemical.
(2) The total mass of each reactant fed into the production process
in metric tons, by chemical.
(3) The total mass of each reactant permanently removed from the
production process in metric tons, by chemical.
(4) The total mass of the fluorinated GHG product removed from the
production process and destroyed.
(5) The mass of each by-product generated.
(6) The mass of each by-product destroyed at the facility.
(7) The mass of each by-product recaptured and sent off-site for
destruction.
(8) The mass of each by-product recaptured for other purposes.
(9) The mass of each fluorinated GHG emitted.
(b) Where missing data have been estimated pursuant to Sec.
98.125, you shall report the information specified in paragraphs (b)(1)
and (2) of this section.
(1) The reason the data were missing, the length of time the data
were missing, the method used to estimate the missing data, and the
estimates of those data.
(2) Where the missing data have been estimated pursuant to Sec.
98.125(a)(3), you shall also report the rationale for the methods used
to estimate the missing data and why the methods specified in Sec.
98.125 (a)(1) and (2) would lead to a significant under- or
overestimate of the parameter(s).
(c) A fluorinated GHG production facility that destroys fluorinated
GHGs shall report the results of the annual fluorinated GHG
concentration measurements at the outlet of the destruction device,
including:
(1) Flow rate of fluorinated GHG being fed into the destruction
device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at the outlet
of the destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate calculated from paragraphs(c)(2) and (c)(3) of
this section in kg/hr.
(d) A fluorinated GHG production facility that destroys fluorinated
GHGs shall submit a one-time report containing the following
information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the
performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may
apply to the destruction process.
(6) If any process changes affect unit destruction efficiency or
the methods used to record mass of fluorinated GHG destroyed, then a
revised report must be submitted to reflect the changes. The revised
report must be submitted to EPA within 60 days of the change.
Sec. 98.127 Records that must be retained.
(a) In addition to the data required by Sec. Sec. 98.123 and
98.126, you shall retain the following records:
(1) Dated records of the data used to estimate the data reported
under Sec. Sec. 98.123 and 98.126.
(2) Dated records documenting the initial and periodic calibration
of the gas chromatographs, weigh scales, flowmeters, and volumetric and
density measures used to measure the quantities reported under this
subpart, including the industry standards or manufacturer directions
used for calibration pursuant to Sec. 98.124(g) and (h).
(b) In addition to the data required by paragraph (a) of this
section, the designated representative of a fluorinated GHG production
facility that destroys fluorinated GHGs shall keep records of test
reports and other information documenting the facility's one-time
destruction efficiency report and annaul destruction device outlet
reports in Sec. 98.126(c) and (d).
Sec. 98.128 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart M--Food Processing
Sec. 98.130 Definition of the source category.
Food processing facilities prepare raw ingredients for consumption
by animals or humans. Food processing facilities transform raw
ingredients into food, transform food into other forms for consumption
by humans or animals, or transform food for further processing by the
food processing industry.
Sec. 98.131 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a food processing operation and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.132 GHGs to report.
You must report:
(a) Emissions of CO2, N2O, and CH4
from on-site stationary combustion. You must follow the requirements of
subpart C of this part.
(b) Emissions of CH4 from on-site landfills. You must
follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of subpart HH of this part.
(c) Emissions of CH4 from on-site wastewater treatment.
You must follow the requirements of subpart II of this part.
Sec. 98.133 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart N--Glass Production
Sec. 98.140 Definition of the source category.
(a) A glass manufacturing facility manufactures flat glass,
container glass, pressed and blown glass, or wool fiberglass by melting
a mixture of raw materials to produce molten glass and form the molten
glass into sheets, containers, fibers, or other shapes. A glass
manufacturing facility uses one or more continuous glass melting
furnaces to produce glass.
(b) A glass melting furnace that is an experimental furnace or a
research and development process unit is not subject to this subpart.
Sec. 98.141 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a glass production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.142 GHGs to report.
(a) You must report CO2 process emissions from each
continuous glass melting furnace at your glass manufacturing facility
as required by this subpart.
(b) You must report the CO2, N2O, and CH\4\
emissions from fuel combustion at each continuous glass melting furnace
and at any other on-site stationary fuel combustion unit. For each
stationary fuel combustion unit, you must follow the requirements of
subpart C of this part.
Sec. 98.143 Calculating GHG emissions.
(a) If you operate and maintain a continuous emission monitoring
system (CEMS) that measures total CO2 emissions consistent
with the requirements in subpart C of this part, you must estimate
total CO2 emissions according to the requirements in Sec.
98.33.
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you shall calculate process emissions of CO2
from each glass melting furnace
[[Page 16659]]
according to paragraphs (b)(1) through (5) of this section, except as
specified in paragraph (c) of this section.
(1) For each carbonate-based raw material charged to the furnace,
obtain from the supplier of the raw material the carbonate-based
mineral mass fraction.
(2) Determine the quantity of each carbonate-based raw material
charged to the furnace.
(3) Apply the appropriate emission factor for each carbonate-based
raw material charged to the furnace, as shown in Table N-1 to this
subpart.
(4) Use Equation N-1 of this subpart to calculate process mass
emissions of CO2 for each furnace:
[GRAPHIC] [TIFF OMITTED] TP10AP09.057
Where:
ECO2 = Process mass emissions of CO2 (metric
ton/yr) from the furnace.
n = Number of carbonate-based raw materials charged to furnace.
MFi = Mass fraction of carbonate-based mineral i in
carbonate-based raw material i (dimensionless unit).
Mi = Mass of carbonate-based raw material i charged to
furnace (metric ton/yr).
EFi = Emission factor for carbonate-based raw material i
(metric ton CO2/metric ton carbonate-based raw material).
Fi = Fraction of calcination achieved for carbonate-based
raw material i, assumed to be equal to 1.0 (dimensionless unit).
(5) You must determine the total process CO2 emissions
from continuous glass melting furnaces at the facility using Equation
N-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.058
Where:
CO2 = Total annual process CO2 emissions from
glass manufacturing facility (metric tons/year).
ECO2i = Annual CO2 emissions from glass
melting furnace i (metric tons CO2/year).
k = Number of continuous glass melting furnaces.
(c) As an alternative to data provided by the raw material
supplier, a value of 1.0 can be used for the mass fraction
(MFi) of carbonate-based mineral i in Equation N-1 of this
section.
Sec. 98.144 Monitoring and QA/QC requirements.
(a) You shall determine annual amounts of carbonate-based raw
materials charged to each continuous glass melting furnace using
calibrated scales or weigh hoppers. Total annual mass charged to glass
melting furnaces at the facility shall be compared to records of raw
material purchases for the year.
(b) If raw material supplier data are used to determine carbonate-
based mineral mass fractions according to Sec. 98.143(b)(1),
measurements of the mass fraction of each carbonate-based mineral in
the carbonate-based raw materials shall be made at least annually to
verify the mass fraction data provided by the supplier of the raw
material; such measurements shall be based on sampling and chemical
analysis conducted by a certified laboratory using a suitable method
published by a consensus standards organization (e.g., ASTM Method
D3682, Test Method for Major and Minor Elements in Coal and Coke Ash by
Atomic Absorption Method).
Sec. 98.145 Procedures for estimating missing data.
(a) Missing data on the monthly amounts of carbonate-based raw
materials charged to any continuous glass melting furnace shall be
replaced by the average of the data from the previous month and the
following month for each carbonate-based raw material charged.
(b) Missing data on the mass fractions of carbonate-based minerals
in the carbonate-based raw materials shall be replaced using the
assumption that the mass fraction of each carbonate based mineral is
1.0.
Sec. 98.146 Data reporting requirements.
You shall report the information specified in paragraphs (a)
through (d) of this section for each continuous glass melting furnace.
(a) Annual process emissions of CO2, in metric tons/yr.
(b) Annual quantity of each carbonate-based raw material charged,
in metric tons/yr.
(c) Annual quantity of glass produced, in metric tons/yr.
(d) If process CO2 emissions are calculated based on
data provided by the raw material supplier according to Sec.
98.143(a)(1), the carbonate-based mineral mass fraction (as percent)
for each carbonate-based raw material charged to a continuous glass
melting furnace.
Sec. 98.147 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the records listed in paragraphs (a) through (e) of this
section.
(a) Total number of continuous glass melting furnaces.
(b) Monthly glass production rate for each continuous glass melting
furnace.
(c) Monthly amount of each carbonate-based raw material charged to
each continuous glass melting furnace.
(d) If process CO2 emissions are calculated using data
provided by the raw material supplier according to Sec. 98.143(b)(1),
you must retain the records in paragraphs (d)(1) and (2) of this
section.
(1) Data on carbonate-based mineral mass fractions provided by the
raw material supplier.
(2) Results of all tests used to verify the carbonate-based mineral
mass fraction for each carbonate-based raw material charged to a
continuous glass melting furnace.
(e) All other documentation used to support the reported GHG
emissions.
Sec. 98.148 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table N-1 of Subpart N--CO2 Emission Factors for Carbonate-Based Raw
Materials
------------------------------------------------------------------------
CO2 Emission
Carbonate-based raw material--mineral factor a
------------------------------------------------------------------------
Limestone--CaCO3........................................ 0.440
[[Page 16660]]
Dolomite--CaMg(CO3)2.................................... 0.477
Sodium carbonate/soda ash--Na2CO3....................... 0.415
------------------------------------------------------------------------
a Emission factors in units of metric tons of CO2 emitted per metric ton
of carbonate-based raw material charged to the furnace.
Subpart O--HCFC-22 Production and HFC-23 Destruction
Sec. 98.150 Definition of the source category.
The HCFC-22 production and HFC-23 destruction source category
consists of HCFC-22 production processes and HFC-23 destruction
processes.
(a) An HCFC-22 production process produces HCFC-22
(chlorodifluoromethane, or CHClF2) from chloroform
(CHCl3) and hydrogen fluoride (HF).
(b) An HFC-23 destruction process is any process in which HFC-23
undergoes destruction. An HFC-23 destruction process may or may not be
co-located with an HCFC-22 production process at the same facility.
Sec. 98.151 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a HCFC-22 production or HFC-23 destruction process and the
facility meets the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.152 GHGs to report.
(a) You must report the CO2, N2O, and
CH4 emissions from each on-site stationary combustion unit.
For these stationary combustion units, you must follow the applicable
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
subpart C of this part.
(b) You must report HFC-23 emissions from HCFC-22 production
processes and HFC-23 destruction processes.
Sec. 98.153 Calculating GHG emissions.
(a) The total mass of HFC-23 generated from each HCFC-22 production
process shall be estimated by using one of two methods, as applicable:
(1) Where the mass flow of the combined stream of HFC-23 and
another reaction product (e.g., HCl) is measured, multiply the daily
(or more frequent) HFC-23 concentration measurement (which may be the
average of more frequent concentration measurements) by the daily (or
more frequent) mass flow of the combined stream of HFC-23 and the other
product. To estimate annual HFC-23 production, sum the daily (or more
frequent) estimates of the quantities of HFC-23 produced over the year.
This calculation is summarized in Equation O-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.059
Where:
G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HFC-23/other product
stream.
Fp = Mass flow of HFC-23/other product stream during the
period p (kg).
p = Period over which mass flows and concentrations are measured.
n = Number of concentration and flow measurement periods for the
year.
10-3 = Conversion factor from kilograms to metric tons.
(2) Where the mass of only a reaction product other than HFC-23
(either HCFC-22 or HCl) is measured, multiply the ratio of the daily
(or more frequent) measurement of the HFC-23 concentration and the
daily (or more frequent) measurement of the other product concentration
by the daily (or more frequent) mass produced of the other product. To
estimate annual HFC-23 production, sum the daily (or more frequent)
estimates of the quantities of HFC-23 produced over the year. This
calculation is summarized in Equation O-2 of this section, assuming
that the other product is HCFC-22. If the other product is HCl, HCl may
be substituted for HCFC-22 in Equations O-2 and O-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.060
Where:
G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream.
c22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23
stream.
P22 = Mass of HCFC-22 produced over the period p (kg).
p = Period over which masses and concentrations are measured.
n = Number of concentration and mass measurement periods for the
year.
10-3 = Conversion factor from kilograms to metric tons.
(b) The mass of HCFC-22 produced over the period p shall be
estimated by using Equation O-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.061
Where:
P22 = Mass of HCFC-22 produced over the period p (kg).
O22 = mass of HCFC-22 that is measured coming out of the
Production process over the period p (kg).
U22 = Mass of used HCFC-22 that is added to the
production process upstream of the output measurement over the
period p (kg).
LF = Factor to account for the loss of HCFC-22 upstream of the
measurement. The value for LF shall be determined pursuant to Sec.
98.154(e).
(c) For HCFC-22 production facilities that do not use a thermal
oxidizer or have a thermal oxidizer that is not directly connected to
the HCFC-22 production equipment, HFC-23 emissions shall be estimated
using Equation O-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.062
Where:
E23 = Mass of HFC-23 emitted annually (metric tons).
G23 = Mass of HFC-23 generated annually (metric tons).
S23 = Mass of HFC-23 packaged for sale annually (metric
tons).
OD23 = Mass of HFC-23 sent off-site for destruction
(metric tons).
D23 = Mass of HFC-23 destroyed on-site (metric tons).
[[Page 16661]]
(d) For HCFC-22 production facilities that use a thermal oxidizer
connected to the HCFC-22 production equipment, HFC-23 emissions shall
be estimated using Equation O-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.063
Where:
E23 = Mass of HFC-23 emitted annually (metric tons).
EL = Mass of HFC-23 emitted annually from equipment
leaks, calculated using Equation O-6 (metric tons).
EPV = Mass of HFC-23 emitted annually from process vents,
calculated using Equation O-7 (metric tons).
ED = Mass of HFC-23 emitted annually from thermal
oxidizer (metric tons), calculated using Equation O-9 of this
section.
(e) The mass of HFC-23 emitted annually from equipment leaks (for
use in Equation O-5 of this section) shall be estimated by using
Equation O-6 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.064
Where:
EL = Mass of HFC-23 emitted annually from equipment leaks
(metric tons).
c23 = Fraction HFC-23 by weight in the stream(s) in the
equipment.
FGt = The applicable leak rate specified in table O-1 for
each source of equipment type and service t with a screening value
greater than or equal to 10,000 ppmv (kg/hr/source).
NGt = The number of sources of equipment type and service
t with screening values greater than or equal to 10,000 ppmv as
determined according to Sec. 98.154(h).
FLt = The applicable leak rate specified in table O-1 for
each source of equipment type and service t with a screening value
of less than 10,000 ppmv (kg/hr/source).
NLt = The number of sources of equipment type and service
t with screening values less than 10,000 ppmv as determined
according to Sec. 98.154(i).
p = One hour.
n = Number of hours during the year during which equipment contained
HFC-23.
t = Equipment type and service as specified in Table O-1.
10-3 = Factor converting kg to metric tons.
Table O-1 of Subpart O--Emission Factors for Equipment Leaks
----------------------------------------------------------------------------------------------------------------
Emission factor (kg/hr/source)
Equipment type Service -----------------------------------
>=10,000 ppmv <10,000 ppmv
----------------------------------------------------------------------------------------------------------------
Valves...................................... Gas........................... 0.0782 0.000131
Valves...................................... Light liquid.................. 0.0892 0.000165
Pump seals.................................. Light liquid.................. 0.243 0.00187
Compressor seals............................ Gas........................... 1.608 0.0894
Pressure relief valves...................... Gas........................... 1.691 0.0447
Connectors.................................. All........................... 0.113 0.0000810
Open-ended lines............................ All........................... 0.01195 0.00150
----------------------------------------------------------------------------------------------------------------
(f) The mass of HFC-23 emitted annually from process vents (for use
in Equation O-5 of this section) shall be estimated by using Equation
O-7 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.065
Where:
EPV = Mass of HFC-23 emitted annually from process vents
(metric tons).
ERT = The HFC-23 emission rate from the process vents
during the period of the most recent test (kg/hr).
PRp = The HCFC-22 production rate during the period p
(kg/hr).
PRT = The HCFC-22 production rate during the most recent
test period (kg/hr).
lp = The length of the period p (hours).
10-3= Factor converting kg to metric tons.
n = The number of periods in a year.
(g) For facilities that destroy HFC-23, the total mass of HFC-23
destroyed shall be estimated by using Equation O-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.066
Where:
D = Mass of HFC-23 destroyed annually (metric tons).
FD = Mass of HFC-23 fed into the destruction device
annually (metric tons).
DE = Destruction Efficiency of the destruction device (fraction).
(h) The total mass of HFC-23 emitted from destruction devices shall
be estimated by using Equation O-9 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.067
Where:
ED = Mass of HFC-23 emitted annually from the destruction
device (metric tons).
FD = Mass of HFC-23 fed into the destruction device
annually (metric tons).
D = Mass of HFC-23 destroyed annually (metric tons).
Sec. 98.154 Monitoring and QA/QC requirements.
These requirements apply to measurements that are reported under
this subpart or that are used to estimate reported quantities pursuant
to Sec. 98.153.
(a) The concentrations (fractions by weight) of HFC-23 and HCFC-22
in the product stream shall be measured at least daily using equipment
and methods (e.g., gas chromatography) with an accuracy and precision
of 5 percent or better at the concentrations of the process samples.
(b) The mass flow of the product stream containing the HFC-23 shall
be measured continuously using a flow meter with an accuracy and
precision of 1.0 percent of full scale or better.
[[Page 16662]]
(c) The mass of HCFC-22 or HCl coming out of the production process
shall be measured at least daily using weigh scales, flowmeters, or a
combination of volumetric and density measurements with an accuracy and
precision of 1.0 percent of full scale or better.
(d) The mass of any used HCFC-22 added back into the production
process upstream of the output measurement in paragraph (c) of this
section shall be measured at least daily (when being added) using
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of 1.0 percent of full
scale or better.
(e) The loss factor LF in Equation O-3 of this subpart for the mass
of HCFC-22 produced shall have the value 1.015 or another value that
can be demonstrated, to the satisfaction of the Administrator, to
account for losses of HCFC-22 between the reactor and the point of
measurement at the facility where production is being estimated.
(f) The mass of HFC-23 packaged for sale shall be measured at least
daily (when being packaged) using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 1.0 percent of full scale or better.
(g) The mass of HFC-23 sent off-site for destruction shall be
measured at least daily (when being packaged) using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of 1.0 percent of full scale or better. If the
measured mass includes more than trace concentrations of materials
other than HFC-23, the concentration of the fluorinated GHG shall be
measured at least daily using equipment and methods (e.g., gas
chromatography) with an accuracy and precision of 5 percent or better
at the concentrations of the process samples. This concentration (mass
fraction) shall be multiplied by the mass measurement to obtain the
mass of the HFC-23 sent to another facility for destruction.
(h) The number of sources of equipment type t with screening values
greater than or equal to 10,000 ppmv shall be determined using EPA
Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as
follows:
(1) A leak source that could emit HFC-23, and
(2) A leak source at whose surface a concentration of fluorocarbons
equal to or greater than 10,000 ppm is measured.
(i) The number of sources of equipment type t with screening values
less than 10,000 ppmv shall be the difference between the number of
leak sources of equipment type t that could emit HFC-23 and the number
of sources of equipment type t with screening values greater than or
equal to 10,000 ppmv as determined under paragraph (h) of this section.
(j) The mass of HFC-23 emitted from process vents shall be
estimated at least monthly by conducting emissions tests at process
vents at least annually and by incorporating the results of the most
recent emissions test into Equation O-6 of this subpart. Emissions
tests shall be conducted in accordance with EPA Method 18 at 40 CFR
part 60, appendix A-6, under conditions that are typical for the
production process at the facility. The sensitivity of the tests shall
be sufficient to detect an emission rate that would result in annual
emissions of 200 kg of HFC-23 if sustained over one year.
(k) For purposes of Equation O-8, the destruction efficiency can
initially be equated to the destruction efficiency determined during a
previous performance test of the destruction device or, if no
performance test has been done, the destruction efficiency provided by
the manufacturer of the destruction device. HFC-23 destruction
facilities shall conduct annual measurements of mass flow and HFC-23
concentrations at the outlet of the thermal oxidizer in accordance with
EPA Method 18 at 40 CFR part 60, appendix A-6. Tests shall be conducted
under conditions that are typical for the production process and
destruction device at the facility. The sensitivity of the emissions
tests shall be sufficient to detect emissions equal to 0.01 percent of
the mass of HFC-23 being fed into the destruction device. If the test
indicates that the actual DE of the destruction device is lower than
the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for
the previously determined DE in the calculations in Sec. 98.153.
(2) Perform more extensive performance testing of the DE of the
oxidizer and use the DE determined by the more extensive testing in the
calculations in Sec. 98.153.
(l) Designated representatives of HCFC-22 production facilities
shall account for HFC-23 generation and emissions that occur as a
result of startups, shutdowns, and malfunctions, either recording HFC-
23 generation and emissions during these events, or documenting that
these events do not result in significant HFC-23 generation and/or
emissions.
(m) The mass of HFC-23 fed into the destruction device shall be
measured at least daily using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 1.0 percent of full scale or better. If the measured mass
includes more than trace concentrations of materials other than HFC-23,
the concentrations of the HFC-23 shall be measured at least daily using
equipment and methods (e.g., gas chromatography) with an accuracy and
precision of 5 percent or better at the concentrations of the process
samples. This concentration (mass fraction) shall be multiplied by the
mass measurement to obtain the mass of the HFC-23 destroyed.
(n) In their estimates of the mass of HFC-23 destroyed, designated
representatives of HFC-23 destruction facilities shall account for any
temporary reductions in the destruction efficiency that result from any
startups, shutdowns, or malfunctions of the destruction device,
including departures from the operating conditions defined in state or
local permitting requirements and/or oxidizer manufacturer
specifications.
(o) All flowmeters, scales, and load cells used to measure
quantities that are to be reported under Sec. 98.156 shall be
calibrated using suitable NIST-traceable standards and suitable methods
published by a consensus standards organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively, calibration procedures specified by
the flowmeter, scale, or load cell manufacturer may be used.
Calibration shall be performed prior to the first reporting year. After
the initial calibration, recalibration shall be performed at least
annually or at the minimum frequency specified by the manufacturer,
whichever is more frequent.
(p) All gas chromatographs used to determine the concentration of
HFC-23 in process streams shall be calibrated at least monthly through
analysis of certified standards (or of calibration gases prepared from
a high-concentration certified standard using a gas dilution system
that meets the requirements specified in Test Method 205, 40 CFR part
51, appendix M) with known HFC-23 concentrations that are in the same
range (fractions by mass) as the process samples.
Sec. 98.155 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required process
[[Page 16663]]
sample is not taken), a substitute data value for the missing parameter
shall be used in the calculations, according to the following
requirements:
(1) For each missing value of the HFC-23 or HCFC-22 concentration,
the substitute data value shall be the arithmetic average of the
quality-assured values of that parameter immediately preceding and
immediately following the missing data incident. If, for a particular
parameter, no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
(2) For each missing value of the product stream mass flow or
product mass, the substitute value of that parameter shall be a
secondary product measurement. If that measurement is taken
significantly downstream of the usual mass flow or mass measurement
(e.g., at the shipping dock rather than near the reactor), the
measurement shall be multiplied by 1.015 to compensate for losses.
(3) Notwithstanding paragraphs (a)(1) and (2) of this section, if
the owner or operator has reason to believe that the methods specified
in paragraphs (a)(1) and (2) of this section are likely to
significantly under- or overestimate the value of the parameter during
the period when data were missing (e.g., because the monitoring failure
was linked to a process disturbance that is likely to have
significantly increased the HFC-23 generation rate), the designated
representative of the HCFC-22 production facility shall develop his or
her best estimate of the parameter, documenting the methods used, the
rationale behind them, and the reasons why the methods specified in
(a)(1) and (2) would probably lead to a significant under- or
overestimate of the parameter.
Sec. 98.156 Data reporting requirements.
(a) In addition to the information required by Sec. 98.3(c), the
designated representative of an HCFC-22 production facility shall
report the following information at the facility level:
(1) The mass of HCFC-22 produced in metric tons.
(2) The mass of reactants fed into the process in metric tons of
reactant.
(3) The mass (in metric tons) of materials other than HCFC-22 and
HFC-23 (i.e., unreacted reactants, HCl and other by-products) that
occur in more than trace concentrations and that are permanently
removed from the process.
(4) The method for tracking startups, shutdowns, and malfunctions
and HFC-23 generation/emissions during these events.
(5) The names and addresses of facilities to which any HFC-23 was
sent for destruction, and the quantities of HFC-23 (metric tons) sent
to each.
(6) The total mass of the HFC-23 generated in metric tons.
(7) The mass of any HFC-23 packaged for sale in metric tons.
(8) The mass of any HFC-23 sent off site for destruction in metric
tons.
(9) The mass of HFC-23 emitted in metric tons.
(10) The mass of HFC-23 emitted from equipment leaks in metric
tons.
(11) The mass of HFC-23 emitted from process vents in metric tons.
(b) Where missing data have been estimated pursuant to Sec.
98.155, the designated representative of the HCFC-22 production
facility or HCF-23 destruction facility shall report the reason the
data were missing, the length of time the data were missing, the method
used to estimate the missing data, and the estimates of those data.
(1) Where the missing data have been estimated pursuant to Sec.
98.155(a)(3), the designated representative shall also report the
rationale for the methods used to estimate the missing data and why the
methods specified in Sec. 98.155(a)(1) and (2) would probably lead to
a significant under- or overestimate of the parameter(s).
(c) In addition to the information required by Sec. 98.3(c), the
designated representative of a facility that destroys HFC-23 shall
report the following for each HFC-23 destruction process:
(1) The mass of HFC-23 fed into the thermal oxidizer.
(2) The mass of HFC-23 destroyed.
(3) The mass of HFC-23 emitted from the thermal oxidizer.
(d) The designated representative of each HFC-23 destruction
facility shall report the results of the facility's annual HFC-23
concentration measurements at the outlet of the destruction device,
including:
(1) The flow rate of HFC-23 being fed into the destruction device
in kg/hr.
(2) The concentration (mass fraction) of HFC-23 at the outlet of
the destruction device.
(3) The flow rate at the outlet of the destruction device in kg/hr.
(4) The emission rate calculated from paragraphs (c)(2) and (3) of
this section in kg/hr.
(e) The designated representative of an HFC-23 destruction facility
shall submit a one-time report including the following information:
(1) The destruction unit's destruction efficiency (DE).
(2) The methods used to determine the unit's destruction
efficiency.
(3) The methods used to record the mass of HFC-23 destroyed.
(4) The name of other relevant federal or state regulations that
may apply to the destruction process.
(5) If any changes are made that affect HFC-23 destruction
efficiency or the methods used to record volume destroyed, then these
changes must be reflected in a revision to this report. The revised
report must be submitted to EPA within 60 days of the change.
Sec. 98.157 Records that must be retained.
(a) In addition to the data required by Sec. 98.3(g), the
designated representative of an HCFC-22 production facility shall
retain the following records:
(1) The data used to estimate HFC-23 emissions.
(2) Records documenting the initial and periodic calibration of the
gas chromatographs, weigh scales, volumetric and density measurements,
and flowmeters used to measure the quantities reported under this rule,
including the industry standards or manufacturer directions used for
calibration pursuant to Sec. 98.154(o) and (p).
(b) In addition to the data required by Sec. 98.3(g), the
designated representative of a HFC-23 destruction facility shall retain
the following records:
(1) Records documenting their one-time and annual reports in Sec.
98.156(c), (d), and (e).
(2) Records documenting the initial and periodic calibration of the
gas chromatographs, weigh scales, volumetric and density measurements,
and flowmeters used to measure the quantities reported under this
subpart, including the industry standards or manufacturer directions
used for calibration pursuant to Sec. 98.154(o) and (p).
Sec. 98.158 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart P--Hydrogen Production
Sec. 98.160 Definition of the source category.
(a) A hydrogen production source category produces hydrogen gas
that is consumed at sites other than where it is produced.
(b) This source category comprises process units that produce
hydrogen by oxidation, reaction, or other transformations of
feedstocks.
(c) This source category includes hydrogen production facilities
located within a petroleum refinery and that are not owned or under the
direct control of the refinery owner and operator.
[[Page 16664]]
Sec. 98.161 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a hydrogen production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.162 GHGs to report.
You must report:
(a) CO2 process emissions for each hydrogen production process
unit.
(b) CO2, CH4, and N2O emissions from the combustion of fuels in
each hydrogen production unit and any other stationary combustion units
by following the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of subpart C of this part.
(c) For CO2 collected and used on site or transferred off site, you
must follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of subpart PP of this part.
Sec. 98.163 Calculating GHG emissions.
You must determine CO2 emissions in accordance with the procedures
specified in either paragraph (a) or (b) of this section.
(a) Continuous emission monitoring system. Any hydrogen process
unit that meets the conditions specified in Sec. 98.33(b)(5)(iii)(A),
(B), and (C), or Sec. 98.33(b)(5)(ii)(A) through (F) shall calculate
total CO2 emissions using a continuous emissions monitoring system
according to the Tier 4 Calculation Methodology specified in Sec.
98.33(a)(4).
(b) Feedstock material balance approach. If you do not measure
total emissions with a CEMS, you must calculate the annual CO2 process
emissions from feedstock used for hydrogen production.
(1) Gaseous feedstock. You must calculate the total CO2
process emissions from gaseous feedstock according to Equation P-1 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.068
Where:
CO2 = Annual CO2 process emissions arising
from feedstock consumption (metric tons).
(Fdstk)n = Volume of the gaseous feedstock used in month
n (scf of feedstock).
(CC)n = Average carbon content of the gaseous feedstock, from the
analysis results for month n (kg C per kg of feedstock).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon. and
0.001 = Conversion factor from kg to metric tons.
(2) Liquid feedstock. You must calculate the total CO2
process emissions from liquid feedstock according to Equation P-2 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.069
Where:
CO2 = Annual CO2 emissions arising from
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock used in month n (gallons
of feedstock).
(CC)n = Average carbon content of the liquid feedstock, from the
analysis results for month n (kg C per gallon of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(3) Solid feedstock. You must calculate the total CO2
process emissions from solid feedstock according to Equation P-3 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.070
Where:
CO2 = Annual CO2 emissions from feedstock
consumption in metric tons per month (metric tons).
(Fdstk)n = Mass of solid feedstock used in month n (kg of
feedstock).
(CC)n = Average carbon content of the solid feedstock, from the
analysis results for month n (kg C per kg of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
Sec. 98.164 Monitoring and QA/QC requirements.
(a) Facilities that use CEMS must comply with the monitoring and
QA/QC procedures specified in Sec. 98.34(e).
(b) The quantity of gaseous or liquid feedstock consumed must be
measured continuously using a flow meter. The quantity of solid
feedstock consumed can be obtained from company records and aggregated
on a monthly basis.
(c) You must collect a sample of each feedstock and analyze the
carbon content of each sample using appropriate test methods
incorporated by reference in Sec. 98.7. The minimum frequency of the
fuel sampling and analysis is monthly.
(d) All fuel flow meters, gas composition monitors, and heating
value monitors shall be calibrated prior to the first reporting year,
using a suitable method published by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration
procedures specified by the flow meter manufacturer may be used. Fuel
flow
[[Page 16665]]
meters, gas composition monitors, and heating value monitors shall be
recalibrated either annually or at the minimum frequency specified by
the manufacturer.
(e) You must document the procedures used to ensure the accuracy of
the estimates of feedstock consumption.
Sec. 98.165 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation), a substitute data value for the
missing parameter shall be used in the calculations, according to the
following requirements:
(a) For missing feedstock supply rates, use the lesser of the
maximum supply rate that the unit is capable of processing or the
maximum supply rate that the meter can measure.
(b) There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are
determined to be invalid.
(c) For missing CEMS data, you must use the missing data procedures
in Sec. 98.35.
Sec. 98.166 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each process
unit:
(a) Facilities that use CEMS must comply with the procedures
specified in Sec. 98.36(a)(1)(iv).
(b) Annual total consumption of feedstock for hydrogen production;
annual total of hydrogen produced; and annual total of ammonia
produced, if applicable.
(c) Monthly analyses of carbon content for each feedstock used in
hydrogen production (kg carbon/kg of feedstock).
Sec. 98.167 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) For all CEMS, you must comply with the CEMS recordkeeping
requirements in Sec. 98.37.
(b) Monthly analyses of carbon content for each feedstock used in
hydrogen production.
Sec. 98.168 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart Q--Iron and Steel Production
Sec. 98.170 Definition of the source category.
The iron and steel production source category includes facilities
with any of the following processes: Taconite iron ore processing,
integrated iron and steel manufacturing, cokemaking not colocated with
an integrated iron and steel manufacturing process, and electric arc
furnace (EAF) steelmaking not colocated with an integrated iron and
steel manufacturing process. Integrated iron and steel manufacturing
means the production of steel from iron ore or iron ore pellets. At a
minimum, an integrated iron and steel manufacturing process has a basic
oxygen furnace for refining molten iron into steel. Each cokemaking
process and EAF process located at a facility with an integrated iron
and steel manufacturing process is part of the integrated iron and
steel manufacturing facility.
Sec. 98.171 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains an iron and steel production process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.172 GHGs to report.
(a) You must report combustion-related CO2, CH4, and N2O
emissions from each stationary combustion unit and follow the
requirements in subpart C of this part. Stationary combustion units
include, but are not limited to, by-product recovery coke oven battery
combustion stacks, blast furnace stoves, boilers, process heaters,
reheat furnaces, annealing furnaces, flares, flame suppression, ladle
reheaters, and other miscellaneous combustion sources.
(b) You must report process-related CO2 emissions from
each taconite indurating furnace; basic oxygen furnace; non-recovery
coke oven battery combustion stack; sinter process; EAF; argon-oxygen
decarburization vessel; and direct reduction furnace by following the
procedures in this subpart.
(c) You must report CO2 emissions from each coke pushing
process by following the procedures in this subpart.
Sec. 98.173 Calculating GHG emissions.
(a) For each taconite indurating furnace, basic oxygen furnace,
non-recovery coke oven battery, sinter process, EAF, argon-oxygen
decarburization vessel, and direct reduction furnace, you must
determine CO2 emissions using the procedures in paragraph
(a)(1), (a)(2), or (3) of this section as appropriate.
(1) Continuous emissions monitoring system (CEMS). If you operate
and maintain a CEMS that measures CO2 emissions consistent
with the requirements in subpart C, you must estimate total
CO2 emissions according to the requirements in Sec. 98.33.
(2) Carbon mass balance method. For the carbon balance method,
calculate the mass emissions rate of CO2 in each calendar
month for each process as specified in paragraphs (a)(2)(i) through
(vii) of this section. The calculations are based on the monthly mass
of inputs and outputs to each process and the respective weight
fraction of carbon. If you have a process input or output that contains
carbon that is not included in the Equations, you must account for the
carbon and mass rate of that process input or output in your
calculations.
(i) For taconite indurating furnaces, estimate CO2
emissions using Equation Q-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.071
Where:
CO2 = Annual CO2 mass emissions from the
indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fs)n = Mass of the solid fuel combusted in month ``n'' (metric
tons).
(Csf)n = Carbon content of the solid fuel, from the fuel analysis
results for month ``n'' (percent by weight, expressed as a decimal
fraction, e.g., 95% = 0.95).
(Fg)n = Volume of the gaseous fuel combusted in month ``n'' (scf).
(Cgf)n = Average carbon content of the gaseous fuel, from the fuel
analysis results for month ``n'' (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
0.001 = Conversion factor from kg to metric tons.
[[Page 16666]]
(Fl)n = Volume of the liquid fuel combusted in month
``n'' (gallons).
(Clf)n = Carbon content of the liquid fuel, from the fuel analysis
results for month ``n'' (kg C per gallon of fuel).
(O)n = Mass of greenball (taconite) pellets fed to the furnace in
month ``n'' (metric tons).
(C0)n = Carbon content of the greenball (taconite) pellets, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(P)n = Mass of fired pellets produced by the furnace in month ``n''
(metric tons).
(Cp)n = Carbon content of the fired pellets, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(ii) For basic oxygen process furnaces, estimate CO2
emissions using Equation Q-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.072
Where:
CO2 = Annual CO2 mass emissions from the basic
oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron)n = Mass of molten iron charged to the furnace in month ``n''
(metric tons).
(CIron)n = Carbon content of the molten iron, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to the furnace in month
``n'' (metric tons).
(CScrap)n = Average carbon content of the ferrous scrap, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke)
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Steel)n = Mass of molten steel produced by the furnace in month
``n'' (metric tons).
(CSteel)n = Average carbon content of the steel, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(Slag)n = Mass of slag produced by the furnace in month ``n''
(metric tons).
(CSlag)n = Average carbon content of the slag, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(iii) For non-recovery coke oven batteries, estimate CO2
emissions using Equation Q-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.073
Where:
CO2 = Annual CO2 mass emissions from the non-
recovery coke oven battery (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Coal)n = Mass of coal charged to the battery in month ``n'' (metric
tons).
(CCoal)n = Carbon content of the coal, from the carbon analysis
results for month ``n'' (percent by weight, expressed as a decimal
fraction).
(Coke)n = Mass of coke produced by the battery in month ``n''
(metric tons).
(CCoke)n = Carbon content of the coke, from the carbon analysis
results for month ``n'' (percent by weight, expressed as a decimal
fraction).
(iv) For sinter processes, estimate CO2 emissions using
Equation Q-4 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.074
Where:
CO2 = Annual CO2 mass emissions from the
sinter process (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg)n = Volume of the gaseous fuel combusted in month ``n'' (scf).
(Cgf)n = Average carbon content of the gaseous fuel, from the fuel
analysis results for month ``n'' (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
0.001 = Conversion factor from kg to metric tons.
(Feed)n = Mass of sinter feed material in month ``n'' (metric tons).
(CFeed)n = Carbon content of the sinter feed material, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Sinter)n = Mass of sinter produced in month ``n'' (metric tons).
(CSinter)n = Carbon content of the sinter pellets, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(v) For EAFs, estimate CO2 emissions using Equation Q-5
of this section.
[[Page 16667]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.075
Where:
CO2 = Annual CO2 mass emissions from the EAF
(metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron)n = Mass of direct reduced iron (if any) charged to the
furnace in month ``n'' (metric tons).
(CIron)n = Carbon content of the molten iron, from the carbon
analysis results for month ``n'' (percent by weight, expressed as a
decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to the furnace in month
``n'' (metric tons).
(CScrap)n = Average carbon content of the ferrous scrap, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials, from the
carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Electrode)n= Mass of carbon electrode consumed in month ``n''
(metric tons).
(CElectrode)n = Average carbon content of the carbon electrode, from
the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke)
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Steel)n = Mass of molten steel produced by the furnace
in month ``n'' (metric tons).
(CSteel)n = Average carbon content of the
steel, from the carbon analysis results for month ``n'' (percent by
weight, expressed as a decimal fraction).
(Slag)n = Mass of slag produced by the furnace in month
``n'' (metric tons).
(CSlag)n = Average carbon content of the slag,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(vi) For argon-oxygen decarburization vessels, estimate
CO2 emissions using Equation Q-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.076
Where:
CO2 = Annual CO2 mass emissions from the
argon-oxygen decarburization vessel (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Steel)n = Mass of molten steel charged to the vessel in
month ``n'' (metric tons).
(CSteelin)n = Carbon content of the molten
steel before decarburization, from the carbon analysis results for
month ``n'' (percent by weight, expressed as a decimal fraction).
(CSteelout)n = Average carbon content of the
molten steel after decarburization, from the carbon analysis results
for month ``n'' (percent by weight, expressed as a decimal
fraction).
[GRAPHIC] [TIFF OMITTED] TP10AP09.077
(vii) For direct reduction furnaces, estimate CO2
emissions using Equation Q-7 of this section.
Where:
CO2 = Annual CO2 mass emissions from the
direct reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg)n = Volume of the gaseous fuel combusted
on day ``n'' or in month ``n'', as applicable (scf).
(Cgf)n = Average carbon content of the gaseous
fuel, from the fuel analysis results for month ``n'' (kg C per kg of
fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
0.001 = Conversion factor from kg to metric tons.
(Ore)n = Mass of iron ore or iron ore pellets fed to the
furnace in month ``n'' (metric tons).
(COre)n = Carbon content of the iron ore, from
the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal,
coke) charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon analysis results for month
``n'' (percent by weight, expressed as a decimal fraction).
(Other)n = Mass of other materials charged to the furnace
in month ``n'' (metric tons).
(COther)n = Average carbon content of the
other materials charged to the furnace, from the carbon analysis
results for month ``n'' (percent by weight, expressed as a decimal
fraction).
(Iron)n = Mass of iron produced in month ``n'' (metric
tons).
(CIron)n = Carbon content of the iron, from
the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(NM)n = Mass of non-metallic materials produced by the
furnace in month ``n'' (metric tons).
[[Page 16668]]
(CNM)n = Average carbon content of the non-
metallic materials, from the carbon analysis results for month ``n''
(percent by weight, expressed as a decimal fraction).
(3) Site-specific emission factor method. You must conduct a
performance test and measure CO2 emissions from all exhaust
stacks for the process and measure either the feed rate of materials
into the process or the production rate during the test as described in
paragraphs (a)(3)(i) through (iv) of this section.
(i) You must measure the production rate or feed rate, as
applicable, during the test and calculate the average rate for the test
period in metric tons per hour.
(ii) You must calculate the hourly CO2 emission rate
using Equation Q-8 and determine the average hourly CO2
emission rate for the test.
[GRAPHIC] [TIFF OMITTED] TP10AP09.078
Where:
CO2 = CO2 mass emission rate (metric tons/hr).
5.18 x 10\-7\ = Conversion factor (tons/scf-% CO2).
CCO2 = Hourly CO2 concentration (%
CO2).
Q = Hourly stack gas volumetric flow rate (scfh).
%H2O = Hourly moisture percentage in the stack gas.
(iii) You must calculate a site-specific emission factor for the
process in metric tons of CO2 per metric ton of feed or
production, as applicable, by dividing the average hourly
CO2 emission rate during the test by the average hourly feed
or production rate during the test.
(iv) You must calculate CO2 emissions for the process by
multiplying the emission factor by the total amount of feed or
production, as applicable, for the reporting period.
(b) You must determine emissions of CO2 from the coke
pushing process in mtCO2e by multiplying the metric tons of
coal charged to the coke ovens during the reporting period by 0.008.
Sec. 98.174 Monitoring and QA/QC requirements.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with subpart C of this part, you
must meet the monitoring and QA/QC requirements of Sec. 98.34(e).
(b) If you determine CO2 emissions using the carbon
balance procedure in Sec. 98.173(a)(2), you must:
(1) For each process input and output other than fuels, determine
the mass rate of each process input and output and record the totals
for each process input and output for each calendar month. Determine
the mass rate of fuels using the procedures for combustion units in
Sec. 98.34.
(2) For each process input and output other than fuels, sample each
process input and output weekly and prepare a monthly composite sample
for carbon analysis. For each process input that is a fuel, determine
the carbon content using the procedures for combustion units in Sec.
98.34.
(3) For each process input and output other than fuels, the carbon
content must be analyzed by an independent certified laboratory using
test method ASTM C25-06 (``Standard Test Methods for Chemical Analysis
of Limestone, Quicklime, and Hydrated Lime'').
(3) For each process input and output other than fuels, the carbon
content must be analyzed by an independent certified laboratory using
the test methods specified in this paragraph.
(A) Use ASTM C25-06 (``Standard Test Methods for Chemical Analysis
of Limestone, Quicklime, and Hydrated Lime'') for:
(i) Limestone, dolomite, and slag; ASTM D5373-08 (``Standard Test
Methods for Instrumental Determination of Carbon, Hydrogen, and
Nitrogen in Laboratory Samples of Coal and Coke'') for coal, coke, and
other carbonaceous materials; ASTM E1915-07a (``Standard Test Methods
for Analysis of Metal Bearing Ores and Related Materials by Combustion
Infrared-Absorption Spectrometry'') for iron ore, taconite pellets, and
other iron-bearing materials.
(ii) ASTM E1019-03 (``Standard Test Methods for Determination of
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and
Cobalt Alloys'') for iron and ferrous scrap.
(iii) ASTM E1019-03 (``Standard Test Methods for Determination of
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and
Cobalt Alloys''), ASTM CS-104 (``Carbon Steel of Medium Carbon
Content''), ISO/TR 15349-1:1998 (``Unalloyed steel--Determination of
low carbon content. Part 1''), or ISO/TR 15349-3: 1998 (``Unalloyed
steel--Determination of low carbon content. Part 3'') as applicable for
steel.
(c) If you determine CO2 emissions using the site-
specific emission factor procedure in Sec. 98.173(a)(3), you must:
(1) Conduct an annual performance test under normal process
operating conditions and at a production rate no less than 90 percent
of the process rated capacity.
(2) For the furnace exhaust from basic oxygen furnaces, EAFs,
argon-oxygen decarburization vessels, and direct reduction furnaces,
sample the furnace exhaust for at least nine complete production cycles
that start when the furnace is being charged and end after steel or
iron and slag have been tapped. For EAFs that produce both carbon steel
and stainless or specialty (low carbon) steel, develop an emission
factor for the production of both types of steel.
(3) For taconite indurating furnaces, non-recovery coke batteries,
and sinter processes, sample for at least 9 hours.
(4) Conduct the stack test using EPA Method 3A in 40 CFR part 60,
Appendix A-2 to measure the CO2 concentration, Method 2, 2A, 2C, 2D, or
2F in appendix A-1 or Method 26, appendix A-2 of 40 CFR part 60 to
determine the stack gas volumetric flow rate, and Method 4 in appendix
A-3 of 40 CFR part 60 to determine the moisture content of the stack
gas.
(5) Conduct a new performance test and calculate a new site-
specific emission factor if your fuel type or fuel/feedstock mix
changes, the process changes in a manner that affects energy efficiency
by more than 10 percent, or the process feed materials change in a
manner that changes the carbon content of the fuel or feed by more than
10 percent.
(6) The results of a performance test must include the analysis of
samples, determination of emissions, and raw data. The performance test
report must contain all information and data used to derive the
emission factor.
(d) For CH4, and N2O emissions, you must meet the monitoring and
QA/QC requirements of Sec. 98.34.
(e) For a coke pushing process, determine the metric tons of coal
charged to the coke ovens and record the totals for each pushing
process for each calendar month. Coal charged to coke ovens can be
measured using weigh belts or a combination of measuring volume and
bulk density.
[[Page 16669]]
Sec. 98.175 Procedures for estimating missing data.
There are no allowances for missing data for facilities that
estimate emissions using the carbon balance procedure in Sec.
98.173(a)(2) or the site-emission factor procedure in Sec.
98.133(a)(3); 100 percent data availability is required.
Sec. 98.176 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information required in paragraphs (a)
through (g) of this section for coke pushing and for each taconite
indurating furnace; basic oxygen furnace; non-recovery coke oven
battery; sinter process; EAF; argon-oxygen decarburization vessel; and
direct reduction furnace, as applicable:
(a) Annual CO2 emissions by calendar quarters.
(b) Annual total for all process inputs and outputs when the carbon
balance is used for specific processes by calendar quarters (short
tons).
(c) Annual production quantity (in metric tons) for taconite
pellets, coke, sinter, iron, and raw steel by calendar quarters.
(d) Production capacity (in tons per year) for the production of
taconite pellets, coke, sinter, iron, and raw steel.
(e) Annual operating hours for taconite furnaces, coke oven
batteries, sinter production, blast furnaces, direct reduced iron
furnaces, and electric arc furnaces.
(f) Site-specific emission factor for all process units for which
the site-specific emission factor approach is used.
(g) Facilities that use CEMS must also comply with the data
reporting requirements specified in Sec. 98.36(d)(iv).
Sec. 98.177 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (f) of this
section, as applicable.
(a) Annual CO2 emissions as measured or determined for
each calendar quarter.
(b) Monthly total for all process inputs and outputs for each
calendar quarter when the carbon balance is used for specific
processes.
(c) Monthly analyses of carbon content for each calendar quarter
when the carbon balance is used for specific processes.
(d) Site-specific emission factor for all process units for which
the site-specific emission factor approach is used.
(e) Annual production quantity for taconite pellets, coke, sinter,
iron, and raw steel with records for each calendar quarter.
(f) Facilities must keep records that include a detailed
explanation of how company records or measurements are used to
determine all sources of carbon input and output and the metric tons of
coal charged to the coke ovens (e.g., weigh belts, a combination of
measuring volume and bulk density). The owner or operator also must
document the procedures used to ensure the accuracy of the measurements
of fuel usage including, but not limited to, calibration of weighing
equipment, fuel flow meters, coal usage including, but not limited to,
calibration of weighing equipment and other measurement devices. The
estimated accuracy of measurements made with these devices must also be
recorded, and the technical basis for these estimates must be provided.
Sec. 98.178 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart R--Lead Production
Sec. 98.180 Definition of the source category.
The lead production source category consists of primary lead
smelters and secondary lead smelters. A primary lead smelter is a
facility engaged in the production of lead metal from lead sulfide ore
concentrates through the use of pyrometallurgical techniques. A
secondary lead smelter is a facility at which lead-bearing scrap
materials (including but not limited to, lead-acid batteries) are
recycled by smelting into elemental lead or lead alloys.
Sec. 98.181 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a lead production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.182 GHGs to report.
(a) You must report the CO2 process emissions from each
smelting furnace used for lead production as required by this subpart.
(b) You must report the CO2, CH4, and
N2O emissions from each stationary combustion unit following
the requirements specified in subpart C of this part.
Sec. 98.183 Calculating GHG emissions.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must estimate total CO2 emissions
according to the requirements in Sec. 98.33.
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must determine using the procedure specified in
paragraphs (b)(1) and (2) of this section the total CO2
emissions from the smelting furnaces at your facility used for lead
production.
(1) For each smelting furnace at your facility used for lead
production, you must determine the mass of carbon in each carbon-
containing material, other than fuel, that is fed, charged, or
otherwise introduced into the smelting furnaces used at your facility
for lead production for each calendar month and estimate total
CO2 process emissions from the affected units at your
facility using Equation R-1 of this section. Carbon containing input
materials include carbonaceous reducing agents.
[GRAPHIC] [TIFF OMITTED] TP10AP09.079
Where:
CO2 = Total annual CO2 process emissions from
the individual smelting furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Lead)n = Mass of lead ore charged to the smelting
furnace in month ``n'' (metric tons).
(CLead)n = Carbon content of the lead ore,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Scrap)n = Mass of lead scrap charged to the furnace in
month ``n'' (metric tons).
(CScrap)n = Average carbon content of the lead
scrap, from the carbon analysis results for month ``n'' (percent by
weight, expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone,
dolomite) charged to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux
materials, from the carbon analysis results for month ``n'' (percent
by weight, expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal,
coke) charged to the furnace in month ``n'' (metric tons).
[[Page 16670]]
(CCarbon)n = Average carbon content of the
carbonaceous materials, from the carbon analysis results for month
``n'' (percent by weight, expressed as a decimal fraction).
(Other)n = Mass of any other materials charged to the
furnace in month ``n'' (metric tons).
(COther)n = Average carbon content of any
other materials from the carbon analysis results for month ``n''
(percent by weight, expressed as a decimal fraction).
(2) You must determine the total CO2 emissions from the
smelting furnaces using Equation R-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.080
Where:
CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions from smelting
furnace k calculated using Equation R-1 of this subpart, metric
tons/year.
k = Total number of smelting furnaces at facility used for the lead
production.
Sec. 98.184 Monitoring and QA/QC requirements.
If you determine CO2 emissions using the carbon input
procedure in Sec. 98.183(b), you must meet the requirements specified
in paragraphs (a) through (c) of this section.
(a) Determine the mass of each solid carbon-containing input
material by direct measurement of the quantity of the material placed
in the unit or by calculations using process operating information, and
record the total mass for the material for each calendar month.
(b) For each input material identified in paragraph (a) of this
section, you must determine the average carbon content of the material
for each calendar month using information provided by your material
supplier or by collecting and analyzing a representative sample of the
material.
(c) For each input material identified in paragraph (a) of this
section for which the carbon content is not provided by your material
supplier, the carbon content of the material must be analyzed by an
independent certified laboratory each calendar month using the test
methods and their QA/QC procedures in Sec. 98.7. Use ASTM E1941-04
(``Standard Test Method for Determination of Carbon in Refractory and
Reactive Metals and Their Alloys'') for analysis of lead bearing ore,
lead scrap, and lead ingot; ASTM D5373-02 (``Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Laboratory Samples of Coal and Coke'') for analysis of carbonaceous
reducing agents, and ASTM C25-06 (``Standard Test Methods for Chemical
Analysis of Limestone, Quicklime, and Hydrated Lime'') for analysis of
flux materials such as limestone or dolomite.
Sec. 98.185 Procedures for estimating missing data.
For the carbon input procedure in Sec. 98.183(b), a complete
record of all measured parameters used in the GHG emissions
calculations is required (e.g., raw materials carbon content values,
etc.). Therefore, whenever a quality-assured value of a required
parameter is unavailable, a substitute data value for the missing
parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute
data value shall be the arithmetic average of the quality-assured
values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input
material consumption, the substitute data value shall be the best
available estimate of the mass of the input material. The owner or
operator shall document and keep records of the procedures used for all
such estimates.
Sec. 98.186 Data Reporting Procedures.
In addition to the information required by Sec. 98.3(c) of this
part, each annual report must contain the information specified in
paragraphs (a) through (e) of this section.
(a) Total annual CO2 emissions from each smelting
furnace operated at your facility for lead production (metric tons and
the method used to estimate emissions).
(b) Facility lead product production capacity (metric tons).
(c) Annual facility production quantity (metric tons).
(d) Number of facility operating hours in calendar year.
(e) If you use the carbon input procedure, report for each carbon-
containing input material consumed or used (other than fuel), the
following information:
(1) Annual material quantity (in metric tons).
(2) Annual weighted average carbon content determined for material
and the method used for the determination (e.g., supplier provided
information, analyses of representative samples you collected).
Sec. 98.187 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section.
(a) Monthly facility production quantity for each lead product (in
metric tons).
(b) Number of facility operating hours each month.
(c) If you use the carbon input procedure, record for each carbon-
containing input material consumed or used (other than fuel), the
information specified in paragraphs (c)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and
records of the supplier provided information or analyses used for the
determination.
(d) You must keep records that include a detailed explanation of
how company records of measurements are used to estimate the carbon
input to each smelting furnace. You also must document the procedures
used to ensure the accuracy of the measurements of materials fed,
charged, or placed in an affected unit including, but not limited to,
calibration of weighing equipment and other measurement devices. The
estimated accuracy of measurements made with these devices must also be
recorded, and the technical basis for these estimates must be provided.
Sec. 98.188 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart S--Lime Manufacturing
Sec. 98.190 Definition of the source category.
Lime manufacturing processes use a rotary lime kiln to produce a
lime product (e.g., calcium oxide, high-calcium quicklime, calcium
hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or
other products) from limestone or dolomite by means of calcination. The
lime manufacturing source category consists of marketed lime
manufacturing facilities and non-marketed lime manufacturing
facilities.
Sec. 98.191 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a lime manufacturing process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.192 GHGs to report.
(a) You must report CO2 process emissions from each lime
kiln as specified in this subpart.
[[Page 16671]]
(b) You must report CO2, N2O, and CH4 emissions from fuel
combustion at each lime kiln and any other stationary combustion unit.
You must follow the requirements of subpart C of this part.
Sec. 98.193 Calculating GHG emissions.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must estimate total CO2 emissions
according to the requirements in Sec. 98.33.
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you shall calculate CO2 process emissions
based on the production of each type of lime and calcined by-products/
wastes produced at each kiln according to the procedures in paragraphs
(b)(1) through (4) of this section.
(1) You must calculate a monthly emission factor for each kiln for
each type of lime produced using Equation S-1 of this section. Calcium
oxide and magnesium oxide content must be analyzed monthly for each
kiln:
[GRAPHIC] [TIFF OMITTED] TP10AP09.081
Where:
EFk = Emission factor for kiln k for lime type i, metric tons
CO2/metric ton lime.
SRCaO = Stoichiometric ratio of CO2 and CaO for lime type
i (see Table S-1 of this subpart), metric tons CO2/
metric tons CaO.
SRMgO= Stoichiometric ratio of CO2 and MgO for lime type
i (See Table S-1 of this subpart), metric tons CO2/
metric tons MgO.
CaOi= Calcium oxide content for lime type i determined according to
Sec. 98.194(b), metric tons CaO/ton lime.
MgOi = Magnesium oxide content for lime type i determined according
to Sec. 98.194(b), metric tons MgO/ metric ton lime.
(2) You must calculate the correction factor for by-product/waste
products at the kiln (monthly) using Equation S-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.082
Where:
CFlkd,k = Correction factor for by-products/waste products (such as
lime kiln dust, LKD) at kiln k.
Md,i = Weight of by-product/waste product not recycled to the kiln
from lime type i, (tons of lime).
Mlime,i= Weight of lime produced at the kiln from lime type i, (tons
of lime).
Cd,i = Fraction of original carbonate in the LKD for lime type i,
(fraction).
Fd,i = Fraction of calcination of the original. carbonate in the LKD
of lime type i, assumed to be 1.00 (fraction).
(3) You must calculate annual CO2 process emissions for
each kiln using Equation S-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.083
Where:
Ek = Annual CO2 process emissions from lime production at
kiln k (metric tons/year).
EFk,n = Emission factor for lime in calendar month n(tons
CO2/tons carbonate) from Equation S-1.
Mk,n = Weight or mass of lime produced in calendar month n (tons/
calendar month) from Equation S-3.
CFlkd,k,n = Correction factor for LKD for lime in calendar month n
from Equation S-2.
0.97 = Default correction factor for the proportion of hydrated lime
(Assuming 90 percent of hydrated lime produced is high-calcium lime
with a water content of 28 percent).
2000/2205
= Conversion factor for tons to metric tons.
= Number of lime types produced at kiln k.
(4) You must determine the total CO2 process emissions
for the facility using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.084
Where:
CO2 = Annual CO2 process emissions from lime
production (metric tons/year).
Ek = Annual CO2 emissions from lime production at kiln k
(metric tons/year).
z = Number of kilns for lime production.
Sec. 98.194 Monitoring and QA/QC requirements.
(a) Determine the quantity of each type of lime produced at each
kiln and the quantity of each type of calcined by-product/waste
produced for each lime type, such as LKD, at the kiln on a monthly
basis. The quantity of each type of calcined by-product/waste produced
at the kiln must include material that is sold or used in a product,
inventoried, or disposed of. The quantity of lime types and LKD
produced monthly by each kiln must be determined by direct weight
measurement using the same plant instruments used for accounting
purposes, such as weigh hoppers or belt weigh feeders.
(b) You must determine the chemical composition (percent total CaO
and percent total MgO) of each type of lime and each type of calcined
by-product/waste produced from each lime type by an off-site laboratory
analysis on a monthly basis. This determination must be performed
according to the requirements of ASTM C25-06, ``Standard Test Methods
for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime''
(incorporated by reference--see Sec. 98.7) and the procedures in
``CO2 Emissions Calculation Protocol for the Lime Industry
English Units Version'', February 5, 2008 Revision (incorporated by
reference--see Sec. 98.7).
(c) You must use the most recent analysis of calcium oxide and
magnesium oxide content of each lime product in monthly calculations.
[[Page 16672]]
(d) You must follow the quality assurance/quality control
procedures (including documentation) in the National Lime Association's
``CO2 Emissions Calculation Protocol for the Lime Industry-
English Units Version'', February 5, 2008 Revision (incorporated by
reference--see Sec. 98.7).
Sec. 98.195 Procedures for estimating missing data.
For the procedure in Sec. 98.193(b), a complete record of all
measured parameters used in the GHG emissions calculations is required
(e.g., raw materials carbon content values, etc.). Therefore, whenever
a quality-assured value of a required parameter is unavailable, a
substitute data value for the missing parameter shall be used in the
calculations.
(a) For each missing value of quantity of lime types, CaO and MgO
content, and quantity of LKD the substitute data value shall be the
arithmetic average of the quality-assured values of that parameter
immediately preceding and immediately following the missing data
incident. If, for a particular parameter, no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-assured value obtained after the missing
data period.
(b) For missing records of mass of raw material consumption, the
substitute data value shall be the best available estimate of the mass
of inputs. The owner or operator shall document and keep records of the
procedures used for all such estimates.
Sec. 98.196 Data reporting requirements.
(a) In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs
(a)(1) through (5) of this section for each lime kiln:
(1) Annual CO2 process emissions;
(2) Annual lime production (in metric tons);
(3) Annual lime production capacity (in metric tons) per facility;
(4) All monthly emission factors, and;
(5) Number of operating hours in calendar year.
(b) Facilities that use CEMS must also comply with the data
reporting requirements specified in Sec. 98.36.
Sec. 98.197 Records that must be retained.
(a) In addition to the records required by Sec. 98.3(g), you must
retain the following records specified in paragraphs (a)(1) through (4)
of this section for each lime kiln:
(1) Annual calcined by-products/waste products (by lime type summed
from monthly data.
(2) Lime production (by lime type) per month (metric tons).
(3) Calculation of emission factors.
(4) Results of chemical composition analysis (by lime product) per
month.
(5) Monthly correction factors for by-products/waste products for
each kiln.
(b) Facilities that use CEMS must also comply with the
recordkeeping requirements specified in Sec. 98.37.
Sec. 98.198 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table S-1 of Subpart S--Basic Parameters for the Calculation of
Emission Factors for Lime Production
------------------------------------------------------------------------
Stoichiometric
Variable ratio
------------------------------------------------------------------------
SRCaO................................................. 0.7848
SRMgO................................................. 1.0918
------------------------------------------------------------------------
Subpart T--Magnesium Production
Sec. 98.200 Definition of source category.
The magnesium production and processing source category consists of
the following facilities:
(a) Any site where magnesium metal is produced through smelting
(including electrolytic smelting), refining, or remelting operations.
(b) Any site where molten magnesium is used in alloying, casting,
drawing, extruding, forming, or rolling operations.
Sec. 98.201 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a magnesium production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.202 GHGs to report.
(a) You must report emissions of the following gases in kilograms
and metric tons CO2e per year resulting from their use as
cover gases or carrier gases in magnesium production or processing:
(1) Sulfur hexafluoride (SF6).
(2) HFC-134a.
(3) The fluorinated ketone, FK 5-1-12.
(4) Any other fluorinated GHGs.
(5) Carbon dioxide (CO2).
(b) You must report CO2, N2O, and
CH4 emissions from each combustion unit on site by following
the calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
subpart C of this part.
Sec. 98.203 Calculating GHG emissions.
(a) Calculate CO2e GHG emissions from magnesium
production or processing using Equation T-1 of this section. For
Equation T-1 of this section, use the procedures of either paragraph
(b) or (c) of this section to estimate consumption of cover gas or
carrier gas.
[GRAPHIC] [TIFF OMITTED] TP10AP09.186
Where:
EGHG = GHG emissions from magnesium production and
processing (mtCO2e).
ESF6 = SF6 emissions from magnesium production
and processing (mtCO2e).
E134a = HFC-134a emissions from magnesium production and
processing (mtCO2e).
[[Page 16673]]
EFK = FK 5-1-12 emissions from magnesium production and
processing (mtCO2e).
ECO2 = CO2 emissions from magnesium production
and processing (mtCO2e).
EOG = Emissions of other fluorinated GHGs from magnesium
production and processing (mtCO2e).
CSF6 = Consumption of SF6 (kg).
C134a = Consumption of HFC-134a (kg).
CFK = Consumption of FK 5-1-12 (kg).
CCO2 = Consumption of CO2 (kg).
COG = Consumption of other fluorinated GHGs (kg).
GWPOG = The Global Warming Potential of the other
fluorinated GHG provided in Table A-1 in subpart A of this part.
(b) To estimate consumption of cover gases or carrier gases by
monitoring changes in container masses and inventories, consumption of
each cover gas or carrier gas shall be estimated using Equation T-2 of
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.085
Where:
C = Consumption of any cover gas or carrier gas in kg over the
period (e.g., 1 year).
IB = Inventory of any cover gas or carrier gas stored in
cylinders or other containers at the beginning of the period (e.g.,
1 year), including heels, in kg.
IE = Inventory of any cover gas or carrier gas stored in
cylinders or other containers at the end of the period (e.g., 1
year), including heels, in kg.
A = Acquisitions of any cover gas or carrier gas during the period
(e.g., 1 year) through purchases or other transactions, including
heels in cylinders or other containers returned to the magnesium
production or processing facility, in kg.
D = Disbursements of cover gas or carrier gas to sources and
locations outside the facility through sales or other transactions
during the period, including heels in cylinders or other containers
returned by the magnesium production or processing facility to the
gas distributor, in kg.
(c) To estimate consumption of cover gases or carrier gases by
monitoring changes in the masses of individual containers as their
contents are used, consumption of each cover gas or carrier gas shall
be estimated using Equation T-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.086
Where:
CGHG = The consumption of the cover gas over the period
(kg).
Qp = The mass of the cover gas used over the period (kg).
n = The number of periods in the year.
(d) For purposes of Equation T-3 of this section, the mass of the
cover gas used over the period p shall be estimated by using Equation
T-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.087
Where:
Qp = The mass of the cover gas used over the period (kg).
MB = The mass of the contents of the cylinder at the
beginning of period p.
ME = The mass of the contents of the cylinder at the end
of period p.
Sec. 98.204 Monitoring and QA/QC requirements.
(a) Consumption of cover gases and carrier gases may be estimated
by monitoring the changes in container weights and inventories using
Equation T-2 of this subpart, by monitoring the changes in individual
container weights as the contents of each container are used using
Equations T-3 and T-4 of this subpart, or by monitoring the mass flow
of the pure cover gas or carrier gas into the cover gas distribution
system. Consumption must be estimated at least annually.
(b) When estimating consumption by monitoring the mass flow of the
pure cover gas or carrier gas into the cover gas distribution system,
you must use gas flow meters with an accuracy of one percent of full
scale or better.
(c) When estimating consumption using Equation T-2 of this subpart,
you must ensure that all the quantities required by Equation T-2 of
this subpart have been measured using scales or load cells with an
accuracy of one percent of full scale or better, accounting for the
tare weights of the containers. You may accept gas masses or weights
provided by the gas supplier (e.g., for the contents of containers
containing new gas or for the heels remaining in containers returned to
the gas supplier); however, you remain responsible for the accuracy of
these masses and weights under this subpart.
(d) When estimating consumption using Equations T-3 and T-4 of this
subpart, you must monitor and record container identities and masses as
follows:
(1) Track the identities and masses of containers leaving and
entering storage with check-out and check-in sheets and procedures. The
masses of cylinders returning to storage shall be measured immediately
before the cylinders are put back into storage.
(2) Ensure that all the quantities required by Equations T-3 and T-
4 of this subpart have been measured using scales or load cells with an
accuracy of one percent of full scale or better, accounting for the
tare weights of the containers. You may accept gas masses or weights
provided by the gas supplier (e.g., for the contents of cylinders
containing new gas or for the heels remaining in cylinders returned to
the gas supplier); however, you remain responsible for the accuracy of
these masses or weights under this subpart.
(e) All flowmeters, scales, and load cells used to measure
quantities that are to be reported under this subpart shall be
calibrated using suitable NIST-traceable standards and suitable methods
published by a consensus standards organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively, calibration procedures specified by
the flowmeter, scale, or load cell manufacturer may be used.
Calibration shall be performed prior to the first reporting year. After
the initial calibration, recalibration shall be performed at least
annually or at the minimum frequency specified by the manufacturer,
whichever is more frequent.
Sec. 98.205 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emission calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data
value for the missing parameter will be used in the calculations as
specified in paragraph (b) of this section.
(b) Replace missing data on the consumption of cover gases by
multiplying magnesium production during the missing data period by the
average cover gas usage rate from the most recent period when operating
conditions were similar to those for the period for which the data are
missing. Calculate the usage rate for each cover gas using Equation T-5
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.088
Where:
RGHG = The usage rate for a particular cover gas over the
period.
CGHG = The consumption of that cover gas over the period
(kg).
Mg = The magnesium produced or fed into the casting process over the
period (metric tons).
Sec. 98.206 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must include the following information for the magnesium
production and processing facility:
(a) Total GHG emissions for your facility by gas in metric tons and
CO2e.
(b) Type of production process (e.g. primary, secondary, die
casting).
(c) Magnesium production amount in metric tons for each process
type.
(d) Cover gas flow rate and composition.
(e) Amount of CO2 used as a carrier gas during the
reporting period.
[[Page 16674]]
(f) For any missing data, you must report the length of time the
data were missing, the method used to estimate emissions in their
absence, and the quantity of emissions thereby estimated.
(g) The facility's cover gas usage rate.
(h) If applicable, an explanation of any change greater than 30
percent in the facility's cover gas usage rate (e.g., installation of
new melt protection technology or leak discovered in the cover gas
delivery system that resulted in increased consumption).
(i) A description of any new melt protection technologies adopted
to account for reduced GHG emissions in any given year.
Sec. 98.207 Records that must be retained.
In addition to the records specified in Sec. 98.3(g), you must
retain the following information for the magnesium production or
processing facility:
(a) Check-out and weigh-in sheets and procedures for cylinders.
(b) Accuracy certifications and calibration records for scales.
(c) Residual gas amounts in cylinders sent back to suppliers.
(d) Invoices for gas purchases and sales.
Sec. 98.208 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart U--Miscellaneous Uses of Carbonate
Sec. 98.210 Definition of the source category.
(a) This source category consists of any equipment that uses
limestone, dolomite, ankerite, magnesite, silerite, rhodochrosite,
sodium carbonate, or any other carbonate in a manufacturing process.
(b) This source category does not include carbonates consumed for
producing cement, glass, ferroalloys, iron and steel, lead, lime, pulp
and paper, or zinc.
Sec. 98.211 Reporting threshold.
You must report GHG emissions from miscellaneous uses of carbonate
if your facility meets the requirements of either Sec. 98.2(a)(1) or
(2).
Sec. 98.212 GHGs to report.
You must report CO2 emissions aggregated for all
miscellaneous carbonate use at the facility.
Sec. 98.213 Calculating GHG emissions.
Calculate process emissions of CO2 using Equation U-1 of
this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.089
Where:
ECO2 = Annual CO2 mass emissions from
consumption of carbonates (metric tons).
Mi = Annual Mass of carbonate type i consumed (tons).
EFi = Emission factor for the carbonate type i, as
specified in Table U-1 to this subpart, metric tons CO2/
metric ton carbonate consumed.
Fi = Fraction calcination achieved for each particular
carbonate type i.
i = number of the carbonate types.
2000/2205 = Conversion factor to convert tons to metric tons.
As an alternative to measuring the calcination fraction
(Fi), a value of 1.0 can be used in Equation U-1 of this
section.
Sec. 98.214 Monitoring and QA/QC requirements.
(a) The total mass of carbonate consumed can be determined by
direct weight measurement using the same plant instruments used for
accounting purposes, such as weigh hoppers or belt weigh feeders, or
purchase records.
(b) Determine on an annual basis the calcination fraction for each
carbonate consumed based on sampling and chemical analysis conducted by
a certified laboratory using a suitable method such as using an x-ray
fluorescence test or other enhanced testing method published by a
consensus standards organization (e.g., ASTM, ASME, API, etc.).
Sec. 98.215 Procedures for estimating missing data.
There are no missing data procedures for miscellaneous uses of
carbonates. A complete record of all measured parameters used in the
GHG emissions calculations is required. A re-test must be performed if
the data from any measurements are determined to be invalid.
Sec. 98.216 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (d) of this section at the facility level.
(a) Annual CO2 emissions from miscellaneous carbonate
use (in metric tons).
(b) Annual carbonate consumption (by carbonate type in tons).
(c) Annual fraction calcinations.
(d) Average annual mass fraction of carbonate-based mineral in
carbonate-based raw material by carbonate type.
Sec. 98.217 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (c) of this
section.
(a) Records of monthly carbonate consumption (by carbonate type).
You must also document the procedures used to ensure the accuracy of
monthly carbonate consumption.
(b) Annual chemical analysis of mass fraction of carbonate-based
mineral in carbonate-based raw material by carbonate type.
(c) Records of all carbonate purchases and deliveries.
Sec. 98.218 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table U-1 of Subpart U--CO2 Emission Factors for Common Carbonates
------------------------------------------------------------------------
CO2 emission
Mineral name--carbonate factor (tons CO2/
ton carbonate)
------------------------------------------------------------------------
Limestone--CaCO3...................................... 0.43971
Magnesite--MgCO3...................................... 0.52197
Dolomite--CaMg(CO3)2.................................. 0.47732
Siderite--FeCO3....................................... 0.37987
Ankerite--Ca(Fe,Mg,Mn) (CO3)2......................... 0.44197
Rhodochrosite--MnCO3.................................. 0.38286
Sodium Carbonate/Soda Ash--Na2CO3..................... 0.41492
------------------------------------------------------------------------
Subpart V--Nitric Acid Production
Sec. 98.220 Definition of source category.
A nitric acid production facility uses oxidation, condensation, and
absorption to produce a weak nitric acid (30 to 70 percent in
strength).
Sec. 98.221 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a nitric acid production
[[Page 16675]]
process and the facility meets the requirements of either Sec.
98.2(a)(1) or (2).
Sec. 98.222 GHGs to report.
(a) You must report N2O process emissions from each
nitric acid production line as required by this subpart.
(b) You must report CO2, CH4, and
N2O emissions from each stationary combustion unit. You must
follow the requirements of subpart C of this part.
Sec. 98.223 Calculating GHG emissions.
You must determine annual N2O process emissions from
each nitric acid production line using a site-specific emission factor
according to paragraphs (a) through (e) of this section.
(a) You must conduct an annual performance test to measure
N2O emissions from the absorber tail gas vent for each
nitric acid production line. You must conduct the performance test(s)
under normal process operating conditions.
(b) You must conduct the emissions test(s) using either EPA Method
320 in 40 CFR part 63, appendix A or ASTM D6348-03 incorporated by
reference in Sec. 98.7 to measure the N2O concentration in
conjunction with the applicable EPA Methods in 40 CFR part 60,
Appendices A-1 through A-4. Conduct three emissions test runs of 1 hour
each.
(c) You must measure the production rate during the test(s) and
calculate the production rate for the test period in tons (100 percent
acid basis) per hour.
(d) You must calculate a site-specific emission factor for each
nitric acid production line according to Equation V-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.090
Where:
EFN2O = Site-specific N2O emissions factor (lb
N2O/ton nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration during performance
test (ppm N2O).
1.14x10-7 = Conversion factor (lb/dscf-ppm
N2O).
Q = Volumetric flow rate of effluent gas (dscf/hr).
P = Production rate during performance test (tons nitric acid
produced per hour (100 percent acid basis)).
n = Number of test runs.
(e) You must calculate N2O emissions for each nitric
acid production line by multiplying the emissions factor by the total
annual production from that production line, according to Equation V-2
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.091
Where:
EN2O = N2O mass emissions per year
(metric tons of N2O).
EFN2O = Site-specific N2O emission
factor for the production line (lb N2O/ton acid produced,
100 percent acid basis).
Pa = Total production for the year from the production
line (ton acid produced, 100 percent acid basis).
DFN = Destruction factor of N2O abatement
technology, 'as specified by the abatement device manufacturer
(percent of N2O removed from air stream).
AFN = Abatement factor of N2O abatement
technology (percent of year that abatement technology was used).
2205 = Conversion factor (lb/metric ton).
Sec. 98.224 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test and calculate a new
site-specific emissions factor at least annually. You must also conduct
a new performance test whenever the production rate of a production
line is changed by more than 10 percent from the production rate
measured during the most recent performance test. The new emissions
factor may be calculated using all available performance test data
(i.e., averaged with the data from previous years), except in cases
where process modifications have occurred or operating conditions have
changed. Only the data consistent with the period after the changes
were implemented shall be used.
(b) Each facility must conduct the performance test(s) according to
a test plan and EPA Method 320 in 40 CFR part 63, Appendix A or ASTM
D6348-03 (incorporated by reference--see Sec. 98.7). All QA/QC
procedures specified in the reference test methods and any associated
performance specifications apply. The report must include the items in
paragraphs (b)(1) through (3) of this section.
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions
factor(s).
(3) The production rate during each test and how it was determined.
The production rate can be determined through sales records or by
direct measurement using flow meters or weigh scales.
Sec. 98.225 Procedures for estimating missing data.
Procedures for estimating missing data are not provided for
N2O process emissions from nitric acid production lines. A
complete record of all measured parameters used in the GHG emissions
calculations is required.
Sec. 98.226 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (h) of this section for each nitric acid production line:
(a) Annual nitric acid production capacity (metric tons).
(b) Annual nitric acid production (metric tons).
(c) Number of operating hours in the calendar year (hours).
(d) Emission factor(s) used (lb N2O/ton of nitric acid
produced).
(e) Type of nitric acid process used.
(f) Abatement technology used (if applicable).
(g) Abatement utilization factor (percent of time that abatement
system is operating).
(h) Abatement technology efficiency.
Sec. 98.227 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a)
[[Page 16676]]
through (c) of this section for each nitric acid production line:
(a) Records of significant changes to process.
(b) Annual test reports of N2O emissions.
(c) Calculations of the site-specific emissions factor(s).
Sec. 98.228 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart W--Oil and Natural Gas Systems
Sec. 98.230 Definition of the source category.
This source category consists of the following facilities:
(a) Offshore petroleum and natural gas production facilities.
(b) Onshore natural gas processing facilities.
(c) Onshore natural gas transmission compression facilities.
(d) Underground natural gas storage facilities.
(e) Liquefied natural gas storage facilities.
(f) Liquefied natural gas import and export facilities.
Sec. 98.231 Reporting threshold.
You must report GHG emissions from oil and natural gas systems if
your facility meets the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.232 GHGs to report.
(a) You must report CO2 and CH4 emissions in metric tons
per year from sources specified in Sec. 98.232(a)(1) through (23) at
offshore petroleum and natural gas production facilities, onshore
natural gas processing facilities, onshore natural gas transmission
compression facilities, underground natural gas storage facilities,
liquefied natural gas storage facilities and liquefied natural gas
import and export facilities.
(1) Acid gas removal (AGR) vent stacks.
(2) Blowdown vent stacks.
(3) Centrifugal compressor dry seals.
(4) Centrifugal compressor wet seals.
(5) Compressor fugitive emissions.
(6) Compressor wet seal degassing vents.
(7) Dehydrator vent stacks.
(8) Flare stacks.
(9) Liquefied natural gas import and export facilities fugitive
emissions.
(10) Liquefied natural gas storage facilities fugitive emissions.
(11) Natural gas driven pneumatic pumps.
(12) Natural gas driven pneumatic manual valve actuator devices.
(13) Natural gas driven pneumatic valve bleed devices.
(14) Non-pneumatic pumps.
(15) Offshore platform pipeline fugitive emissions.
(16) Open-ended lines (oels).
(17) Pump seals.
(18) Platform fugitive emissions.
(19) Processing facility fugitive emissions.
(20) Reciprocating compressor rod packing.
(21) Storage station fugitive emissions.
(22) Storage tanks.
(23) Storage wellhead fugitive emissions.
(24) Transmission station fugitive emissions.
(b) You must report the CO2, CH4, and N2O emissions for
stationary combustion sources, by following the calculation procedures,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of subpart C of this part.
Sec. 98.233 Calculating GHG emissions.
(a) Estimate emissions using either an annual direct measurement,
as specified in Sec. 98.234, or an engineering estimation method
specified in this section. You may use the engineering estimation
method only for sources for which a method is specified in this
section.
(b) You may use engineering estimation methods described in this
section to calculate emissions from the following fugitive emissions
sources:
(1) Acid gas removal vent stacks.
(2) Natural gas driven pneumatic pumps.
(3) Natural gas driven pneumatic manual valve actuator devices.
(4) Natural gas driven pneumatic valve bleed devices.
(5) Blowdown vent stacks.
(6) Dehydrator vent stacks.
(c) A combination of engineering estimation described in this
section and direct measurement described in Sec. 98.234 shall be used
to calculate emissions from the following fugitive emissions sources:
(1) Flare stacks.
(2) Storage tanks.
(3) Compressor wet seal degassing vents.
(d) You must use the methods described in Sec. 98.234 (d) or (e)
to conduct annual leak detection of fugitive emissions from all sources
listed in Sec. 98.232(a). If fugitive emissions are detected,
engineering estimation methods may be used for sources listed in
paragraphs (b) and (c) of this section. If engineering estimation is
used, emissions must be calculated using the appropriate method from
paragraphs (d)(1) through (9) of this section:
(1) Acid gas removal vent stack. Calculate acid gas removal vent
stack fugitive emissions using simulation software packages, such as
ASPENTM or AMINECalcTM. Any standard simulation
software may be used provided it accounts for the following parameters:
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or
standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate and weight.
(vii) If the acid gas removal unit is capturing CO2 and
transferring it off site, then refer to subpart OO of this part for
calculating transferred CO2.
(2) Natural gas driven pneumatic pump. Calculate fugitive emissions
from a natural gas driven pneumatic pump as follows:
(i) Calculate fugitive emissions using manufacturer data.
(A) Obtain from the manufacturer specific pump model natural gas
emission per unit volume of liquid pumped at operating pressures.
(B) Maintain a log of the amount of liquid pumped annually from
individual pumps.
(C) Calculate the natural gas fugitive emissions for each pump
using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.092
Where:
Es,n = Natural gas fugitive emissions at standard
conditions.
Fs = Natural gas driven pneumatic pump gas emission in
``emission per volume of liquid pumped at discharge pressure'' units
at standard conditions, as provided by the manufacturer.
V = Volume of liquid pumped annually.
(D) Both CH4 and CO2 volumetric and mass
fugitive emissions shall be calculated from volumetric natural gas
fugitive emissions using calculations in paragraphs (f) and (g) of this
section.
(ii) If manufacturer data for Fs are not available,
follow the method in Sec. 98.234 (i)(1).
(3) Natural gas driven pneumatic manual valve actuator devices.
Calculate fugitive emissions from a natural gas driven pneumatic manual
valve actuator device as follows:
(i) Calculate fugitive emissions using manufacturer data.
[[Page 16677]]
(A) Obtain from the manufacturer specific pneumatic device model
natural gas emission per actuation.
(B) Maintain a log of the number of times the pneumatic device was
actuated throughout the reporting period.
(C) Calculate the natural gas fugitive emissions for each manual
valve actuator using Equation W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.093
Where:
Es,n = Natural gas fugitive emissions at standard
conditions.
As = Natural gas driven pneumatic valve actuator natural
gas emission in ``emission per actuation'' units at standard
conditions, as provided by the manufacturer.
N = Number of times the pneumatic device was actuated in a way that
vented natural gas to the atmosphere through the reporting period.
(D) Calculate both CH4 and CO2 volumetric and
mass fugitive emissions from volumetric natural gas fugitive emissions
using calculations in paragraphs (f) and (g) of this section.
(ii) Follow the method in Sec. 98.234(i)(2) if manufacturer data
are not available.
(4) Natural gas driven pneumatic valve bleed devices. Calculate
fugitive emissions from a natural gas driven pneumatic valve bleed
device as follows:
(i) Calculate fugitive emissions using manufacturer data.
(A) Obtain from the manufacturer specific pneumatic device model
natural gas bleed rate during normal operation.
(B) Calculate the natural gas fugitive emissions for each valve
bleed device using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.094
Where:
Es,n = Natural gas fugitive emissions at standard
conditions.
Bs = Natural gas driven pneumatic device bleed rate in
``emission per unit time'' units at standard conditions, as provided
by the manufacturer.
T = Amount of time the pneumatic device has been operational through
the reporting period.
(C) Calculate both CH4 and CO2 volumetric
and mass fugitive emissions from volumetric natural gas fugitive
emissions using calculations in paragraphs (f) and (g) of this
section.
(ii) Follow the method in Sec. 98.234(i)(3) if manufacturer
data are not available.
(5) Blowdown vent stacks. Calculate fugitive emissions from
blowdown vent stacks as follows:
(i) Calculate the total volume (including, but not limited to
pipelines and vessels) between isolation valves (Vv in
Equation W-4 of this subpart).
(ii) Retain logs of the number of blowdowns for each equipment
type.
(iii) Calculate the total annual fugitive emissions using the
following Equation W-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.095
Where:
Ea,n = Natural gas fugitive emissions at ambient
conditions from blowdowns.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume of blowdown equipment chambers
(including, but not limited to, pipelines and vessels) between
isolation valves.
(iv) Calculate natural gas volumetric fugitive emissions at
standard conditions using calculations in paragraph (e) of this
section.
(v) Calculate both CH4 and CO2 volumetric and
mass fugitive emissions from volumetric natural gas fugitive emissions
using calculations in paragraphs (f) and (g) of this section.
(6) Dehydrator vent stacks. Calculate fugitive emissions from a
dehydrator vent stack using a simulation software packages, such as
GLYCalcTM. Any standard simulation software may be used
provided it accounts for the following parameters:
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (natural gas pneumatic/air
pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type: Including, but not limited to, triethylene
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
(vii) Use of stripping natural gas.
(viii) Use of flash tank separator (and disposition of recovered
gas).
(ix) Hours operated.
(x) Wet natural gas temperature, pressure, and composition.
(7) Flare stacks. Calculate fugitive emissions from a flare stack
as follows:
(i) Determine flare combustion efficiency from manufacturer. If not
available, assume that flare combustion efficiency is 95 percent for
non-steam aspirated flares and 98 percent for steam aspirated or air
injected flares.
(ii) Calculate volume of natural gas sent to flare from velocity
measurement in Sec. 98.234(j) using manufacturer's manual for the
specific meter used to measure velocity.
(iii) Calculate GHG volumetric fugitive emissions at actual
conditions using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.096
Where:
Ea,i = Annual fugitive emissions from flare stack.
Va = Volume of natural gas sent to flare stack determined
from Sec. 98.234(j)(1).
[eta] = Percent of natural gas combusted by flare (default is 95
percent for non-steam aspirated flares and 98 percent for steam
aspirated or air injected flares).
Xi = Concentration of GHG i in the flare gas determined
from Sec. 98.234(j)(1).
Yj = Concentration of natural gas hydrocarbon
constituents j (such as methane, ethane, propane, butane, and
pentanes plus).
Rj,i = Number of carbon atoms in the natural gas
hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for
propane, 4 for butane, and 5 for pentanes plus).
K = ``1'' when GHG i is CH4 and ``0'' when GHG i is
CO2.
(iv) Calculate GHG volumetric fugitive emissions at standard
conditions using Equation W-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.097
Where:
Es,i = Natural gas volumetric fugitive emissions at
standard temperature and pressure (STP) conditions.
Ea,i = Natural gas volumetric fugitive emissions at
actual conditions.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (inches of
Hg).
Pa = Absolute pressure at ambient conditions (inches of
Hg).
(v) Calculate both CH4 and CO2 mass fugitive
emissions from volumetric CH4 and CO2 fugitive
emissions using calculations in paragraph (g) of this section.
(8) Storage tanks. Calculate fugitive emissions from a storage tank
as follows:
(i) Calculate the total annual hydrocarbon vapor fugitive emissions
using Equation W-7 of this section:
[[Page 16678]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.098
Where:
Ea,h = Hydrocarbon vapor fugitive emissions at actual
conditions.
Q = Storage tank total annual throughput.
ER = Measured hydrocarbon vapor emissions rate per throughput (e.g.
cubic feet/barrel) determined from Sec. 98.234(j)(2).
(ii) Estimate hydrocarbon vapor volumetric fugitive emissions at
standard conditions using calculations in paragraph (e) of this
section.
(iii) Estimate CH4 and CO2 volumetric
fugitive emissions from volumetric hydrocarbon fugitive emissions using
Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.099
Where:
Es,i = GHG i (either CH4 or CO2)
volumetric fugitive emissions at standard conditions.
Es,h = Hydrocarbon vapor volumetric fugitive emissions at
standard conditions.
Mi = Mole percent of a particular GHG i in the
hydrocarbon vapors; hydrocarbon vapor analysis shall be conducted in
accordance with ASTM D1945-03.
(iv) Estimate CH4 and CO2 mass fugitive
emissions from GHG volumetric fugitive emissions using calculations in
paragraph (g) of this section.
(9) Compressor wet seal degassing vents. Calculate fugitive
emissions from compressor wet seal degassing vents as follows:
(i) Calculate volume of natural gas sent to vent from velocity
measurement in Sec. 98.234(j) using manufacturer's manual for the
specific meter used to measure velocity.
(ii) Calculate natural gas volumetric fugitive emissions at
standard conditions using calculations in paragraph (e) of this
section.
(iii) Calculate both CH4 and CO2 volumetric
and mass fugitive emissions from volumetric natural gas fugitive
emissions using calculations in paragraphs (f) and (g) of this section.
(e) Calculate natural gas volumetric fugitive emissions at standard
conditions by converting ambient temperature and pressure of natural
gas fugitive emissions to standard temperature and pressure natural
using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.100
Where:
Es,n = Natural gas volumetric fugitive emissions at
standard temperature and pressure (STP) conditions.
Ea,n = Natural gas volumetric fugitive emissions at
actual conditions.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (inches of
Hg).
Pa = Absolute pressure at ambient conditions (inches of
Hg).
(f) Calculate GHG volumetric fugitive emissions at standard
conditions as specified in paragraphs (f)(1) and (2) of this section.
(1) Estimate CH4 and CO2 fugitive emissions
from natural gas fugitive emissions using Equation W-10 of this
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.101
Where:
Es,i = GHG i (either CH4 or CO2)
volumetric fugitive emissions at standard conditions.
Es,n = Natural gas volumetric fugitive emissions at
standard conditions.
Mi = Mole percent of GHG i in the natural gas.
(2) For Equation W-10 of this section, the mole percent,
Mi, shall be the annual average mole percent for each
facility, as specified in paragraphs (f)(2)(i) through (vi) of this
section.
(i) GHG mole percent in produced natural gas for offshore petroleum
and natural gas production facilities.
(ii) GHG mole percent in feed natural gas for all fugitive
emissions sources upstream of the de-methanizer and GHG mole percent in
facility specific residue gas to transmission pipeline systems for all
fugitive emissions sources downstream of the de-methanizer for onshore
natural gas processing facilities.
(iii) GHG mole percent in transmission pipeline natural gas that
passes through the facility for onshore natural gas transmission
compression facilities.
(iv) GHG mole percent in natural gas stored in underground natural
gas storage facilities.
(v) GHG mole percent in natural gas stored in LNG storage
facilities.
(vi) GHG mole percent in natural gas stored in LNG import and
export facilities.
(g) Calculate GHG mass fugitive emissions at standard conditions by
converting the GHG volumetric fugitive emissions into mass fugitive
emissions using Equation W-11 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.102
Where:
Masss,i = GHG i (either CH4 or CO2)
mass fugitive emissions at standard conditions.
Es,i = GHG i (either CH4 or CO2)
volumetric fugitive emissions at standard conditions.
[rho]i = Density of GHG i;1.87 kg/m\3\ for CO2
and 0.68 kg/m\3\ for CH4.
Sec. 98.234 Monitoring and QA/QC requirements.
(a) You must use the methods described in paragraphs (d) or (e) in
this section to conduct annual leak detection of fugitive emissions
from all sources listed in Sec. 98.232(a), whether in operation or on
standby. If fugitive emissions are detected for sources listed in
paragraph (b) of this section, you must use the measurement methods
described in paragraph(c) of this section to measure emissions from
each source with fugitive emissions.
(b) You shall use detection instruments described in paragraphs (d)
and (e) of this section to monitor the following fugitive emissions:
(1) Centrifugal compressor dry seals fugitive emissions.
(2) Centrifugal compressor wet seals fugitive emissions.
(3) Compressor fugitive emissions.
(4) LNG import and export facility fugitive emissions.
(5) LNG storage station fugitive emissions.
(6) Non-pneumatic pumps fugitive emissions.
(7) Open-ended lines (OELs) fugitive emissions.
(8) Pump seals fugitive emissions.
(9) Offshore platform pipeline fugitive emissions.
(10) Platform fugitive emissions.
(11) Processing facility fugitive emissions.
(12) Reciprocating compressor rod packing fugitive emissions.
(13) Storage station fugitive emissions.
(14) Transmission station fugitive emissions.
(15) Storage wellhead fugitive emissions.
(c) You shall use a high volume sampler, described in paragraph (f)
of this section, to measure fugitive emissions from the sources
detected in Sec. 98.234(b), except as provided in paragraphs (c)(1)
and (2) of this section:
(1) Where high volume samplers cannot capture all of the fugitive
emissions, you shall use calibrated bags described in paragraph (g) of
this section or meters described in paragraph (h) of this section to
measure the following fugitive emissions:
(i) Open-ended lines (OELs).
(ii) Centrifugal compressor dry seals fugitive emissions.
(iii) Centrifugal compressor wet seals fugitive emissions.
(iv) Compressor fugitive emissions.
(v) Pump seals fugitive emissions.
(vi) Reciprocating compressor rod packing fugitive emissions.
(vii) Flare stacks and storage tanks, except that you shall use
meters in
[[Page 16679]]
combination with engineering estimation methods to calculate fugitive
emissions.
(2) Use hot wire anemometer to calculate fugitive emissions from
centrifugal compressor wet seal degassing vents and flares where it is
unsafe or too high a flow rate to use calibrated bags.
(d) Infrared Remote Fugitive Emissions Detection.
(1) Use infrared fugitive emissions detection instruments that can
identify specific equipment sources as emitting. Such instruments must
have the capability to trace a fugitive emission back to the specific
point where it escapes the process and enters the atmosphere.
(2) If you are using instruments that visually display an image of
fugitive emissions, you shall inspect the emissions source from
multiple angles or locations until the entire source has been viewed
without visual obstructions at least once annually.
(3) If you are using any other infrared detection instruments, such
as those based on infrared laser reflection, you shall monitor all
potential emission points at least once annually.
(4) Perform fugitive emissions detection under favorable
conditions, including but not limited to during daylight hours, in the
absence of precipitation, in the absence of high wind, and, for active
laser devices, in front of appropriate reflective backgrounds within
the detection range of the instrument.
(5) Use fugitive emissions detection and measurement instrument
manuals to determine optimal operating conditions.
(e) Use organic vapor analyzers (OVAs) and toxic vapor analyzers
(TVAs) for all fugitive emissions detection that are safely accessible
at close-range.
(1) Check each potential emissions source, all joints, connections,
and other potential paths to the atmosphere for emissions.
(2) Evaluate the lag time between the instrument sensing and
alerting caused by the residence time of a sample in the probe shall be
evaluated; upon alert, the instrument shall be slowly retraced over the
source to pinpoint the location of fugitive emissions.
(3) Use Method 21 of 40 CFR part 60, appendix A-7, Determination of
Volatile Organic Compound Leaks to calibrate OVAs and TVAs.
(f) Use a high volume sampler to measure only cold and steady
emissions within the capacity of the instrument.
(1) A trained technician shall conduct measurements. The technician
shall be conversant with all operating procedures and measurement
methodologies relevant to using a high volume sampler, including, but
not limited to, positioning the instrument for complete capture of the
fugitive emissions without creating backpressure on the source.
(2) If the high volume sampler, along with all attachments
available from the manufacturer, is not able to capture all the
emissions from the source then you shall use anti-static wraps or other
aids to capture all emissions without violating operating requirements
as provided in the instrument manufacturer's manual.
(3) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in Sec. 98.233(f) and (g).
(4) Calibrate the instrument at 2.5 percent methane with 97.5
percent air and 100 percent CH4 by using calibrated gas
samples and by following manufacturer's instructions for calibration.
(g) Use calibrated bags (also known as vent bags) only where the
emissions are at near-atmospheric pressures and the entire fugitive
emissions volume can be captured for measurement.
(1) Hold the bag in place enclosing the emissions source to capture
the entire emissions and record the time required for completely
filling the bag.
(2) Perform three measurements of the time required to fill the
bag; report the emissions as the average of the three readings.
(3) Estimate natural gas volumetric emissions at standard
conditions using calculations in Sec. 98.233(e).
(4) Estimate CH4 and CO2 volumetric and mass
emissions from volumetric natural gas emissions using the calculations
in Sec. 98.233(f) and (g).
(5) Obtain consistent results when measuring the time it takes to
fill the bag with fugitive emissions.
(h) Channel all emissions from a single source directly through the
meter when using metering (e.g., rotameters, turbine meters, and
others).
(1) Use an appropriately sized meter so that the flow does not
exceed the full range of the meter in the course of measurement and
conversely has sufficient momentum for the meter to register
continuously in the course of measurement.
(2) Estimate natural gas volumetric fugitive emissions at standard
conditions using calculations in Sec. 98.233(f).
(3) Estimate CH4 and CO2 volumetric and mass
fugitive emissions from volumetric natural gas fugitive emissions using
calculations in Sec. 98.233(f) and (g).
(4) Calibrate the meter using either one of the two methods
provided as follows:
(i) Develop calibration curves by following the manufacturer's
instruction.
(ii) Weigh the amount of gas that flows through the meter into or
out of a container during the calibration procedure using a master
weigh scale (approved by National Institute of Standards and Technology
(NIST) or calibrated using standards traceable by NIST). Determine
correction factors for the flow meter according to the manufacturer's
instructions. Record deviations from the correct reading at several
flow rates. Plot the data points, comparing the flowmeter output to the
actual flowrate as determined by the master weigh scale and use the
difference as a correction factor.
(i) Where engineering estimation as described in Sec. 98.233 is
not possible, use direct measurement methods as follows:
(1) If manufacturer data on pneumatic pump natural gas emission are
not available, conduct a one-time measurement to determine natural gas
emission per unit volume of liquid pumped using a calibrated bag for
each pneumatic pump, when it is pumping liquids. Determine the volume
of liquid being pumped from the manufacturer's manual to provide the
amount of natural gas emitted per unit of liquid pumped.
(i) Record natural gas conditions (temperature and pressure) and
convert natural gas emission per unit volume of liquid pumped at actual
conditions into natural gas emission per pumping cycle at standard
conditions using Equation W-9 of Sec. 98.233.
(ii) Calculate annual fugitive emissions from the pump using
Equation W-1, by replacing the manufacturer's data on emission
(variable Fs) in the Equation with the standard conditions
natural gas emission calculated in Sec. 98.234(i)(1)(i).
(iii) Estimate CH4 and CO2 volumetric and
mass fugitive emissions from volumetric natural gas fugitive emissions
using calculations in Sec. 98.233(f) and (g).
(2) If manufacturer data on pneumatic manual valve actuator device
natural gas emission are not available, conduct a one-time measurement
to determine natural gas emission per actuation using a calibrated bag
for each pneumatic device per actuation.
(i) Record natural gas conditions (temperature and pressure) and
convert natural gas emission at actual conditions into natural gas
emission per
[[Page 16680]]
actuation at standard conditions using Equation W-9 of this subpart.
(ii) Calculate annual fugitive emissions from the pneumatic device
using Equation W-2 of this section, by replacing the manufacturer's
data on emission (variable As) in the Equation with the
standard conditions natural gas emission calculated in Sec.
98.234(i)(2)(i).
(iii) Estimate CH4 and CO2 volumetric and
mass emissions from volumetric natural gas fugitive emissions using the
calculations in Sec. 98.233(f) and (g).
(3) If manufacturer data on natural gas driven pneumatic valve
bleed rate is not available, conduct a one-time measurement to
determine natural gas bleed rate using a high volume sampler or
calibrated bag or meter for each pneumatic device.
(i) Record natural gas conditions (temperature and pressure) to
convert natural gas bleed rate at actual conditions into natural gas
bleed rate at standard conditions using Equation W-9 of this subpart.
(ii) Calculate annual fugitive emissions from the pneumatic device
using Equation W-3 of this subpart, by replacing the manufacturer's
data on bleed rate (variable B) in the equation with the standard
conditions bleed rate calculated in Sec. 98.234(i)(3)(i).
(iii) Estimate CH4 and CO2 volumetric and
mass fugitive emissions from volumetric natural gas fugitive emissions
using calculations in Sec. 98.233(f) and (g).
(j) Parameters for calculating emissions from flare stacks,
compressor wet seal degassing vents, and storage tanks.
(1) Estimate fugitive emissions from flare stacks and compressor
wet seal degassing vents as follows:
(i) Insert flow velocity measuring device (such as hot wire
anemometer or pitot tube) directly upstream of the flare stack or
compressor wet seal degassing vent to determine the velocity of gas
sent to flare or vent.
(ii) Record actual temperature and pressure conditions of the gas
sent to flare or vent.
(iii) Sample representative gas to the flare stack or compressor
wet seal degassing vent every quarter to evaluate the composition of
GHGs present in the stream. Record the average of the most recent four
gas composition analyses, which shall be conducted using ASTM D1945-03
(incorporated by reference, see Sec. 98.7).
(2) Estimate fugitive emissions from storage tanks as follows:
(i) Measure the hydrocarbon vapor emissions from storage tanks
using a flow meter described in paragraph (h) of this section for a
test period that is representative of the normal operating conditions
of the storage tank throughout the year and which includes a complete
cycle of accumulation of hydrocarbon liquids and pumping out of
hydrocarbon liquids from the storage tank.
(ii) Record the net (related to working loss) and gross (related to
flashing loss) input of the storage tank during the test period.
(iii) Record temperature and pressure of hydrocarbon vapors emitted
during the test period.
(iv) Collect a sample of hydrocarbon vapors for composition
analysis
(k) Component fugitive emissions sources that are not safely
accessible within the operator's arm's reach from the ground or
stationary platforms are excluded from the requirements of this
section.
(1) Determine annual emissions assuming that the fugitive emissions
were continuous from the beginning of the reporting period or last
recorded zero detection in the current reporting period and continuing
until the fugitive emissions is repaired.
Sec. 98.235 Procedures for estimating missing data.
There are no missing data procedures for this source category. A
complete record of all measured parameters used in the GHG emissions
calculations is required. If data are lost or an error occurs during
annual emissions measurements, you must repeat the measurement activity
for those sources until a valid measurement is obtained.
Sec. 98.236 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must report emissions data as specified in this section.
(a) Annual emissions reported separately for each of the operations
listed in paragraphs (a)(1) through (6) of this section. Within each
operation, emissions from each source type must be reported in the
aggregate. For example, an underground natural gas storage facility
with multiple reciprocating compressors must report emissions from all
reciprocating compressors as an aggregate number.
(1) Offshore petroleum and natural gas production facilities.
(2) Onshore natural gas processing facilities.
(3) Onshore natural gas transmission compression facilities.
(4) Underground natural gas storage facilities.
(5) Liquefied natural gas storage facilities.
(6) Liquefied natural gas import and export facilities.
(b) Emissions reported separately for standby equipment.
(c) Emissions calculated for these sources shall assume no
CO2 capture and transfer off site.
(d) Activity data for each aggregated source type level for which
emissions are being reported.
(e) Engineering estimate of total component count.
(f) Total number of compressors and average operating hours per
year for compressors for each operation listed in paragraphs (a)(1)
through (6) of this section.
(g) Minimum, maximum and average throughput for each operation
listed in paragraphs (a)(1) through (6) of this section.
(h) Specification of the type of any control device used, including
flares, for any source type listed in 98.232(a).
(i) For offshore petroleum and natural gas production facilities,
the number of connected wells, and whether they are producing oil, gas,
or both.
(j) Detection and measurement instruments used.
Sec. 98.237 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected, whether quantification was
made pursuant to Sec. 98.234(k) and measurements.
(c) Calibration reports for detection and measurement instruments
used.
(d) Inputs and outputs of calculations or emissions computer model
runs used for engineering estimation of emissions.
Sec. 98.238 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart X--Petrochemical Production
Sec. 98.240 Definition of the source category.
(a) The petrochemical production source category consists of any
facility that produces acrylonitrile, carbon black, ethylene, ethylene
dichloride, ethylene oxide, or methanol as an intended product, except
as specified in paragraph (b) of this section.
(b) An integrated process is part of the petrochemical source
category only if the petrochemical is the primary product of the
integrated process.
Sec. 98.241 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a petrochemical production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
[[Page 16681]]
Sec. 98.242 GHGs to report.
You must report the information in paragraphs (a) through (d) of
this section:
(a) CO2 emissions from each petrochemical process unit,
following the methods and procedures in Sec. Sec. 98.243 through
98.248. You must include the volume of any CO2 captured from
process off-gas in the reported CO2 emissions.
(b) CO2, CH4, and N2O emissions
from stationary combustion units. For each stationary combustion unit,
you must follow the calculation methods and other requirements
specified in subpart C of this part. If you determine CO2
process-based emissions in accordance with Sec. 98.243(a)(2), then for
each stationary combustion unit that burns off-gas from a petrochemical
process, estimate CO2, CH4, and N2O
emissions for the combustion of supplemental fuel in accordance with
subpart C of this part. In addition, estimate CH4 and
N2O emissions from combusting off-gas according to the
requirements in Sec. 98.33(c)(2) and (3) using the emission factors
for Refinery Gas in Table C-3 in subpart C of this part.
(c) CO2 captured. You must follow the calculation
procedures, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements specified in
subpart PP of this part.
(d) CH4 emissions for each on-site wastewater treatment
system. For wastewater treatment systems, you must follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements
specified in subpart II of this part.
Sec. 98.243 Calculating GHG emissions.
(a) Determine process-based GHG emissions in accordance with the
procedures specified in either paragraph (a)(1) or (2) of this section,
and if applicable, comply with the procedures in paragraph (b) of this
section.
(1) Continuous emission monitoring system (CEMS).
(i) If you operate and maintain a CEMS that measures total
CO2 emissions from process vents and combustion sources
according to subpart C of this part, you must estimate total
CO2 emissions according to the Tier 4 Calculation
Methodology requirements in Sec. 98.33(a)(4). For each flare, estimate
CO2, CH4, and N2O emissions using the
methodology specified in Sec. 98.253(b)(1) and (2).
(ii) If you elect to install CEMS to comply with this subpart, you
must route all process vent emissions to one or more stacks and use a
CEMS on each stack (except flare stacks) to measure CO2
emissions. You must estimate total CO2 emissions according
to the Tier 4 Calculation Methodology requirements in Sec.
98.33(a)(4). For each flare, estimate CO2, CH4,
and N2O emissions using the methodology specified in Sec.
98.253(b)(1) and (2) of subpart Y of this part.
(2) Mass balance for each petrochemical process unit. Estimate the
emissions of CO2 from each process unit, for each calendar
week as described in paragraphs (a)(2)(i) through (v) of this section.
(i) Measure the volume of each gaseous and liquid feedstock and
product continuously with a flow meter by following the procedures
outlined in Sec. 98.244(b)(2). Fuels used for combustion purposes are
not considered to be feedstocks.
(ii) Measure the mass rate of each solid feedstock and product by
following the procedures outlined in Sec. 98.244(b)(1) and record the
total for each calendar week.
(iii) Collect a sample of each feedstock and product at least once
per week and determine the carbon content of each sample according to
the procedures in Sec. 98.244(b)(3).
(iv) If you determine that the weekly average concentration of a
specific compound in a feedstock or product is always greater than 99.5
percent by volume (or mass for liquids and solids), then as an
alternative to the sampling and analysis specified in paragraph
(a)(2)(iii) of this section, you may calculate the carbon content
assuming 100 percent of that feedstock or product is the specific
compound during periods of normal operation. You must maintain records
of any determination made in accordance with this paragraph along with
all supporting data, calculations, and other information. This
alternative may not be used for products during periods of operation
when off-specification product is produced. You must reevaluate
determinations made under this paragraph after any process change that
affects the feedstock or product composition. You must keep records of
the process change and the corresponding composition determinations. If
the feedstock or product composition changes so that the average weekly
concentration falls below 99.5 percent, you are no longer permitted to
use this alternative method.
(v) Estimate CO2 mass emissions for each petrochemical
process unit using Equations X-1 through X-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.103
Where:
Cg = Annual net contribution to estimated emissions from carbon (C)
in gaseous feedstocks (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i
introduced in week ``n'' (standard cubic feet, scf).
(CCgf)i,n = Average carbon content of the
gaseous feedstock i for week ``n'' (kg C per kg of feedstock).
(MWf)i = Molecular weight of gaseous feedstock
i (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at
standard conditions).
(Pgp)i,n = Volume of gaseous product i
produced in week ``n'' (scf).
(CCgp)i,n = Average carbon content of gaseous
product i, including streams containing CO2 recovered for
sale or use in another process, for week ``n'' (kg C per kg of
product).
(MWp)i = Molecular weight of gaseous product i
(kg/kg-mole).
j = Number of feedstocks.
k = Number of products.
[GRAPHIC] [TIFF OMITTED] TP10AP09.104
[[Page 16682]]
Where:
Cl = Annual net contribution to estimated emissions from
carbon in liquid feedstocks (kg/yr).
(Flf)i,n = Volume of liquid feedstock i
introduced in week ``n'' (gallons).
(CClf)i,n = Average carbon content of liquid
feedstock i for week ``n'' (kg C per gallon of feedstock).
(Plp)i,n = Volume of liquid product i produced
in week ``n'' (gallons).
(CClp)i,n = Average carbon content of liquid
product i, including organic liquid wastes, for week ``n'' (kg C per
gallon of product).
[GRAPHIC] [TIFF OMITTED] TP10AP09.105
Where:
Cs = Annual net contribution to estimated emissions from
carbon in solid feedstocks (kg/yr).
(Fsf)i,n = Mass of solid feedstock i
introduced in week ``n'' (kg).
(CCsf)i,n = Average carbon content of solid
feedstock i for week ``n'' (kg C per kg of feedstock).
(Psp)i,n = Mass of solid product i produced in
week ``n'' (kg).
(CCsp)i,n = Average carbon content of solid
product i in week ``n'' (kg C per kg of product).
[GRAPHIC] [TIFF OMITTED] TP10AP09.106
Where:
CO2 = Annual CO2 mass emissions from process
operations and fuel gas combustion (metric tons/year).
0.001 = Conversion factor from kg to metric tons.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of carbon (C) (kg/kg-mole).
(b) If you have an integrated process unit that is determined to be
part of the petrochemical production source category, comply with
paragraph (a) of this section by including terms for additional carbon-
containing products in Equations X-1 through X-3 of this section as
necessary.
Sec. 98.244 Monitoring and QA/QC requirements.
(a) Each facility that uses CEMS to estimate emissions from process
vents must comply with the procedures specified in Sec. 98.34(e).
(b) Facilities that use the mass balance methodology in Sec.
98.243(a)(2) must comply with paragraphs (b)(1) through (3) of this
section.
(1) Measure the mass rate of each solid feedstock and product
(e.g., using belt scales or weighing at the loadout points of your
process unit) and record the total for each calendar week. You must
document procedures used to ensure the accuracy of the measurements of
the feedstock and product flows including, but not limited to,
calibration of all weighing equipment and other measurement devices.
The estimated accuracy of measurements made with these devices shall be
recorded, and the technical basis for these estimates shall be
recorded.
(2) Measure the volume of each gaseous and liquid feedstock and
product for each process unit continuously with a flow meter. All
feedstock and product flow meters must be calibrated prior to the first
reporting year, using any applicable method incorporated by reference
in Sec. 98.7(b)(1) through (6), (c)(1), (f)(3)(i) through (ii), or
(g)(1). You should use the flow meter accuracy test procedures in
appendix D to part 75 of this chapter. Alternatively, calibration
procedures specified by the equipment manufacturer may be used. Flow
meters and gas composition monitors shall be recalibrated annually or
at the frequency specified by another applicable rule or the
manufacturer, whichever is more frequent.
(3) Collect a sample of each feedstock and product for each process
unit at least once per week and determine the carbon content of each
sample using an applicable ASTM method incorporated by reference in
Sec. 98.7(a)(15), (23), or (24). Alternatively, you may determine the
composition of the sample using a gas chromatograph and then calculate
the carbon content based on the composition and molecular weights for
compounds in the sample. Determine the composition of gas and liquid
samples using either: ASTM D1945-03 incorporated by reference in Sec.
98.7 (a)(8) of subpart A of this part; ASTM D6060-96(2001) incorporated
by reference in Sec. 98.7; ASTM D2502-88(2004)e1 incorporated by
reference in Sec. 98.7; method UOP539-97 incorporated by reference in
Sec. 98.7; or EPA Method 18, 40 CFR part 60, appendix A-6; or Methods
8031, 8021, or 8015 in ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' EPA Publication No. SW-846, Third Edition,
September 1986, as amended by Update I, November 15, 1992. Calibrate
the gas chromatograph using the procedures in the method prior to each
use. For coal used as a feedstock, the samples for carbon content
determinations shall be taken at a location that is representative of
the coal feedstock used during the corresponding weekly period. For
carbon black products, samples shall be taken of each grade or type of
product produced during the weekly period. Samples of coal feedstock or
carbon black product for carbon content determinations may be either
grab samples collected and analyzed weekly or a composite of samples
collected more frequently and analyzed weekly.
Sec. 98.245 Procedures for estimating missing data.
(a) For missing feedstock flow rates, product flow rates, and
carbon contents, use the same procedures as for missing flow rates and
carbon contents for fuels as specified in Sec. 98.35.
(b) For missing CO2 concentration, stack gas flow rate,
and moisture content for CEMS on any process vent stack, follow the
applicable procedures specified in Sec. 98.35.
Sec. 98.246 Data reporting requirements.
(a) Facilities using the mass balance methodology in Sec.
98.243(a)(2) must report the information specified in paragraphs (a)(1)
through (9) of this section for each type of petrochemical produced,
reported by process unit.
(1) Identification of the petrochemical process.
(2) Annual CO2e emissions calculated using Equation X-4
of this subpart.
(3) Methods used to determine feedstock and product flows and
carbon contents.
[[Page 16683]]
(4) Number of actual and substitute data points for each measured
parameter.
(5) Annual quantity of each feedstock consumed.
(6) Annual quantity of each product and by-product produced,
including all products from integrated processes that are part of the
petrochemical production source category.
(7) Each carbon content measurement for each feedstock, product,
and by-product.
(8) All calculations, measurements, equipment calibrations,
certifications, and other information used to assess the uncertainty in
emission estimates and the underlying volumetric flow rates, mass flow
rates, and carbon contents of feedstocks and products.
(9) Identification of any combustion units that burned process off-
gas.
(b) Each facility that uses CEMS to determine emissions from
process vents must report the verification data specified in Sec.
98.36(d)(1)(iv).
Sec. 98.247 Records that must be retained.
In addition to the recordkeeping requirements in Sec. 98.3(g), you
must retain the following records:
(a) The CEMS recordkeeping requirements in Sec. 98.37, if you
operate a CEMS on process vents.
(b) Results of feedstock or product composition determinations
conducted in accordance with Sec. 98.243(a)(2)(iv).
(c) Start and end times and calculated carbon contents for time
periods when off-specification product is produced, if you comply with
the alternative methodology in Sec. 98.243(a)(2)(iv) for determining
carbon content of feedstock or product.
Sec. 98.248 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart Y--Petroleum Refineries
Sec. 98.250 Definition of source category.
(a) A petroleum refinery is any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, asphalt (bitumen) or other products through distillation of
petroleum or through redistillation, cracking, or reforming of
unfinished petroleum derivatives.
(b) This source category consists of the following sources at
petroleum refineries: Catalytic cracking units; fluid coking units;
delayed coking units; catalytic reforming units; coke calcining units;
asphalt blowing operations; blowdown systems; storage tanks; process
equipment components (compressors, pumps, valves, pressure relief
devices, flanges, and connectors) in gas service; marine vessel, barge,
tanker truck, and similar loading operations; flares; land disposal
units; sulfur recovery plants. hydrogen plants (non-merchant plants
only).
Sec. 98.251 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a petroleum refineries process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.252 GHGs to report.
You must report:
(a) CO2, CH4, and N2O combustion
emissions from stationary combustion sources and from each flare. For
each stationary combustion unit, you must follow the calculation
procedures, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements specified in
subpart C of this part.
(b) CO2, CH4, and N2O coke burn-
off emissions from each catalytic cracking unit, fluid coking unit, and
catalytic reforming unit.
(c) CO2 emissions from sour gas sent off site for sulfur
recovery operations. You must follow the calculation procedures from
Sec. 98.253(f) of this subpart and the monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of this subpart of this part.
(d) CO2 process emissions from each on-site sulfur
recovery plant.
(e) CO2, CH4, and N2O emissions
from each coke calcining unit.
(f) CO2 emissions from asphalt blowing operations
controlled using a combustion device and CH4 emissions from
asphalt blowing operations not controlled by a combustion device.
(g) CH4 fugitive emissions from equipment leaks, storage
tanks, loading operations, delayed coking units, and uncontrolled
blowdown systems.
(h) CO2, CH4, and N2O emissions
from each process vent not specifically included in paragraphs (a)
through (g) of this section.
(i) CH4 emissions from on-site landfills. You must
follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of subpart HH of this part.
(j) CO2 and CH4 emissions from on-site
wastewater treatment. You must follow the calculation procedures,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of subpart II of this
part.
(k) CO2 and CH4 emissions from non-merchant
hydrogen production. You must follow the calculation procedures,
monitoring and QA/QC methods, missing data procedures, reporting
requirements, and recordkeeping requirements of subpart P of this part.
Sec. 98.253 Calculating GHG emissions.
(a) For stationary combustion sources, if you operate and maintain
a CEMS that measures total CO2 emissions according to
subpart C of this part, you must estimate total CO2
emissions according to the requirements in Sec. 98.33(a)(4).
(b) For flares, calculate GHG emissions according to the
requirements in paragraphs (b)(1) and (2) of this section for
combustion systems fired with refinery fuel gas.
(1) Calculate the CO2 emissions according to the applicable
requirements in paragraphs (b)(1)(i) through (iii) of this section.
(i) Flow measurement. If you have a continuous flow monitor on the
flare, you must use the measured flow rates when the monitor is
operational, to calculate the flare gas flow. If you do not have a
continuous flow monitor on the flare, you must use engineering
calculations, company records, or similar estimates of volumetric flare
gas flow.
(ii) Carbon content. If you have a continuous higher heating value
monitor or carbon content monitor on the flare or if you monitor these
parameters at least daily, you must use the measured heat value or
carbon content value in calculating the CO2 emissions from the flare.
If you monitor carbon content, calculate the CO2 emissions from the
flare using the applicable equation in Sec. 98.33(a). If you monitor
heat content, calculate the CO2 emissions from the flare using the
applicable equation in Sec. 98.33(a) and the default emission factor
of 60 kilograms CO2/MMBtu on a higher heating value basis.
(iii) Startup, shutdown, malfunction. If you do not measure the
higher heating value or carbon content of the flare gas at least daily,
determine the quantity of gas discharged to the flare separately for
periods of routine flare operation and for periods of start-up,
shutdown, or malfunction, and calculate the CO2 emissions as specified
in paragraphs (b)(1)(iii)(A) through (C) of this section.
(A) For periods of start-up, shutdown, or malfunction, use
engineering calculations and process knowledge to estimate the carbon
content of the flared gas for each start-up, shutdown, or malfunction
event.
[[Page 16684]]
(B) For periods of normal operation, use the average heating value
measured for the refinery fuel gas for the heating value of the flare
gas.
(C) Calculate the CO2 emissions using Equation Y-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.107
Where:
CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
FlareN = Annual volume of flare gas combusted during
normal operations from company records, (million (MM) standard cubic
feet per year, MMscf/year).
HHV = Higher heating value for refinery fuel or flare gas from
company records (British thermal units per scf, Btu/scf = MMBtu/
MMscf).
EmF = Default CO2 emission factor of 60 kilograms
CO2/MMBtu (HHV basis).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of start-up, shutdown, and malfunction events during the
reporting year.
p = Start-up, shutdown, and malfunction event index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
FlareSSM = Volume of flare gas combusted during a start-
up, shutdown, or malfunctions from engineering calculations, (MMscf/
event).
(CC)p = Average carbon content of the gaseous fuel, from
the fuel analysis results or engineering calculations for the event
(gram C per scf = metric tons C per MMscf).
(2) Calculate CH4 and N2O emissions according to the requirements
in Sec. 98.33(c)(2) using the emission factors for Refinery Gas in
Table C-3 in subpart C of this part.
(c) For catalytic cracking units and traditional fluid coking
units, calculate the GHG emissions using the applicable methods
described in paragraphs (c)(1) through (4) of this section.
(1) For catalytic cracking units and fluid coking units that use a
continuous CO2 CEMS for the final exhaust stack, calculate
the combined CO2 emissions from each catalytic cracking or
fluid coking unit and CO boiler (if present) using the CEMS according
to the Tier 4 Calculation Methodology requirements in Sec.
98.33(a)(4). For units that do not have a CO boiler or other post-
combustion device, Equation Y-3 of this section may be used as an
alternative to a continuous flow monitor, if one is not already
present.
(2) For catalytic cracking units and fluid coking units that do not
use a continuous CO2 CEMS for the final exhaust stack, you
must continuously monitor the O2, CO, and CO2
concentrations in the exhaust stack from the catalytic cracking unit
regenerator or fluid coking unit burner prior to the combustion of
other fossil fuels and calculate the CO2 emissions according
to the requirements of paragraphs (c)(2)(i) through (iii) of this
section:
(i) Calculate the CO2 emissions from each catalytic
cracking unit and fluid coking unit using Equation Y-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.108
Where:
CO2 = Annual CO2 mass emissions (metric tons/
year).
Qr = Volumetric flow rate of exhaust gas from the fluid
catalytic cracking unit regenerator or fluid coking unit burner
prior to the combustion of other fossil fuels (dry standard cubic
feet per hour, dscfh).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream from the fluid catalytic
cracking unit regenerator or fluid coking unit burner (percent by
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas
stream from the fluid catalytic cracking unit regenerator or fluid
coking unit burner (percent by volume--dry basis). When no auxiliary
fuel is burned and a continuous CO monitor is not required, assume
%CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
n = Number of hours in calendar year.
(ii) Either continuously monitor the volumetric flow rate of
exhaust gas from the fluid catalytic cracking unit regenerator or fluid
coking unit burner prior to the combustion of other fossil fuels or
calculate the volumetric flow rate of this exhaust gas stream using
Equation Y-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.109
Where:
Qr = Volumetric flow rate of exhaust gas from the fluid
catalytic cracking unit regenerator or fluid coking unit burner
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic
cracking unit regenerator or fluid coking unit burner, as determined
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the
fluid catalytic cracking unit regenerator or fluid coking unit
burner as determined from control room instrumentation (dscfh).
%O2 = Hourly average percent oxygen concentration in
exhaust gas stream from the fluid catalytic cracking unit
regenerator or fluid coking unit burner (percent by volume--dry
basis).
%Ooxy = O2 concentration in oxygen enriched
gas stream inlet to the fluid catalytic cracking unit regenerator or
fluid coking unit burner based on oxygen purity specifications of
the oxygen supply used for enrichment (percent by volume--dry
basis).
%CO2 = Hourly average percent CO2
concentration in the exhaust gas stream from the fluid catalytic
cracking unit regenerator or fluid coking unit burner (percent by
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas
stream
[[Page 16685]]
from the fluid catalytic cracking unit regenerator or fluid coking
unit burner (percent by volume--dry basis). When no auxiliary fuel
is burned and a continuous CO monitor is not required, assume %CO to
be zero.
(iii) If a CO boiler or other post-combustion device is used,
calculate the GHG emissions from the fuel fired to the CO boiler or
post-combustion device using the methods for stationary combustion
sources in paragraph (a) of this section and report this separately for
the combustion unit.
(3) Calculate CH4 emissions using Equation Y-4 of this
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.110
Where:
CH4 = Annual methane emissions from coke burn-off (metric
tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off
calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or
(g)(2) of this section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C-1 of subpart C of this part (kg
CO2/MMBtu).
EmF2 = Default CH4 emission factor for
petroleum coke from Table C-3 of subpart C of this part (kg
CH4/MMBtu).
(4) Calculate N2O emissions using Equation Y-5 of this
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.111
Where:
N2O = Annual nitrous oxide emissions from coke burn-off
(mt N2O/year).
EmF1 = Default CO2 emission factor for
petroleum coke from Table C-1 of subpart C of this part (kg
CO2/MMBtu).
EmF2 = Default N2O emission factor for
petroleum coke from Table C-3 of subpart C of this part (kg
N2O/MMBtu).
(d) For fluid coking units that use the flexicoking design, the GHG
emissions from the resulting use of the low value fuel gas must be
accounted for only once. Typically, these emissions will be accounted
for using the methods described in subpart C of this part for
combustion sources. Alternatively, you may use the methods in paragraph
(c) of this section provided that you do not otherwise account for the
subsequent combustion of this low value fuel gas.
(e) For catalytic reforming units, calculate the CO2
emissions using either the methods described in paragraphs (e)(1) or
(2) of this section and calculate the CH4 and N2O
emissions using the Equations Y-4 and Y-5 of this section,
respectively.
(1) Calculate CO2 emissions from the catalytic reforming
unit catalyst regenerator using the methods in paragraphs (c)(1) or (2)
of this section, or
(2) Calculate CO2 emissions from the catalytic reforming
unit catalyst regenerator using Equation Y-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.112
Where:
CO2 = Annual CO2 emissions (metric tons/year).
CBQ = Coke burn-off quantity per regeneration cycle (kg
coke/cycle).
CF = Site-specific fraction carbon content of produced coke, use
0.94 if site-specific fraction carbon content is unavailable (kg C
per kg coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
n = Number of regeneration cycles in the calendar year.
0.001 = Conversion factor (mt/kg).
(f) For on-site sulfur recovery plants, calculate CO2
process emissions from sulfur recovery plants according to the
requirements in paragraphs (f)(1) through (4) of this section. Except
as provided in paragraph (f)(4) of this section, combustion emissions
from the sulfur recovery plant (e.g., from fuel combustion in the Claus
burner or the tail gas treatment incinerator) must be reported under
subpart C of this part. For the purposes of this subpart, the sour gas
stream for which monitoring is required according to paragraphs (f)(1)
through (3) of this section is not considered a fuel.
(1) Flow measurement. If you have a continuous flow monitor on the
sour gas feed to the sulfur recovery plant, you must use the measured
flow rates when the monitor is operational to calculate the sour gas
flow rate. If you do not have a continuous flow monitor on the sour gas
feed to the sulfur recovery plant, you must use engineering
calculations, company records, or similar estimates of volumetric sour
gas flow.
(2) Carbon content. If you have a continuous compositional or
carbon content monitor on the sour gas feed to the sulfur recovery
plant or if you monitor these parameters on a routine basis, you must
use the measured carbon content value. Alternatively, you may develop a
site-specific carbon content factor or use the default factor of 0.20.
(3) Calculate the CO2 emissions from each sulfur
recovery plant using Equation Y-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.113
Where:
CO2 = Annual CO2 emissions (metric tons/year).
FSG = Volumetric flow rate of sour gas feed to the sulfur
recovery plant (scf/year).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFC = Mole fraction of carbon in the sour gas to the
sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20.
0.001 = Conversion factor, kg to metric tons.
(4) As an alternative to the monitoring methods in paragraphs
(f)(1) through (3) of this section, you may use a continuous flow
monitor and CO2 CEMS in the final exhaust stack from the
sulfur recovery plant according to the requirements in Sec.
98.33(a)(4) to calculate the combined process and combustion emissions
for the sulfur recovery plant. You must monitor fuel use in the Claus
burner, tail gas incinerator, or other combustion sources that
discharge via the final exhaust stack from the sulfur recovery plant
and calculate the combustion emissions from the fuel use according to
subpart C of this part. You must report the process emissions from the
sulfur recovery plant as the difference in the CO2 CEMS
emissions and the calculated combustion emissions associated with the
sulfur recovery plant final exhaust stack.
[[Page 16686]]
(g) For coke calcining units, calculate GHG emissions according to
the applicable provisions in paragraphs (g)(1) through (3) of this
section.
(1) For coke calcining units that use a continuous CO2
CEMS for the final exhaust stack, calculate the combined CO2
emissions from the coke calcining process and any auxiliary fuel
combusted using the CEMS according to the requirements in Sec.
98.33(a)(4).
(2) For coke calcining units that do not use a continuous
CO2 CEMS for the final exhaust stack, calculate
CO2 emissions from the coke calcining unit according to the
requirements in paragraphs (g)(2)(i) and (ii) of this section.
(i) Calculate the CO2 emissions for any auxiliary fuel
fired to the calcining unit using the applicable methods in subpart C
of this part.
(ii) Calculate the CO2 emissions from the coke calcining
process using Equation Y-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.114
Where:
CO2 = Annual CO2 emissions (metric tons/year).
Min = Annual mass of green coke fed to the coke calcining unit from
facility records (metric tons/year).
CCGC = Average mass fraction carbon content of green coke
from facility measurement data (metric ton carbon/metric ton green
coke).
Mout = Annual mass of marketable petroleum coke produced
by the coke calcining unit from facility records (metric tons
petroleum coke/year).
Mdust = Annual mass of petroleum coke dust collected in
the dust collection system of the coke calcining unit from facility
records (metric ton petroleum coke dust/year).
CCMPC = Average mass fraction carbon content of
marketable petroleum coke produced by the coke calcining unit from
facility measurement data (metric ton carbon/metric ton petroleum
coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(3) For all coke calcining units, use the CO2 emissions
from the coke calcining unit calculated in paragraphs (g)(1) or (2), as
applicable, and calculate CH4 using Equation Y-4 of this
section and N2O emissions using Equation Y-5 of this
section.
(h) For asphalt blowing operations, calculate GHG emissions
according to the applicable provisions in paragraphs (h)(1) and (2) of
this section.
(1) For uncontrolled asphalt blowing operations, calculate
CH4 emissions using Equation Y-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.115
Where:
CH4 = Annual methane emissions from uncontrolled asphalt
blowing (metric tons CH4/year).
QAB = Quantity of asphalt blown (million barrels per
year, MMbbl/year).
EFAB = Emission factor for asphalt blowing from facility-
specific test data (scf CH4/MMbbl); use 2,555,000 scf
CH4/MMbbl if facility-specific test data are unavailable.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(2) For controlled asphalt blowing operations, calculate
CO2 emissions using Equation Y-10 of this section, provided
these emissions are not already included in the flare emissions
calculated in paragraph (b) of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.116
Where:
CO2 = Annual CO2 emissions (metric ton/year).
QAB = Quantity of asphalt blown (MMbbl/year).
EFAB = Default emission factor (2,555,000 scf
CH4/MM bbl).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
1 = Assumed conversion efficiency (kg-mole CO2/kg-mole
CH4).
0.001 = Conversion factor (metric tons/kg).
(i) For delayed coking units, calculate the CH4
emissions from the depressurization of the coking unit vessel to
atmosphere using the process vent method in paragraph (j) of this
section and calculate the CH4 emissions from the subsequent
opening of the vessel for coke cutting operations using Equation Y-11
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.117
Where:
CH4 = Annual methane emissions from the delayed coking
unit vessel opening (metric ton/year).
N = Total number of vessel openings for all delayed coking unit
vessels of the same dimensions during the year.
H = Height of coking unit vessel (feet).
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFCH4 = Mole fraction of methane in coking vessel gas
(kg-mole CH4/kg-mole gas); default value is 0.03.
0.001 = Conversion factor (metric ton/kg).
[[Page 16687]]
(j) For each process vent not covered in paragraphs (a) through (i)
of this section, calculate GHG emissions using the Equation Y-12 of
this section. You must use Equation Y-12 for catalytic reforming unit
depressurization and purge vents when methane is used as the purge gas.
[GRAPHIC] [TIFF OMITTED] TP10AP09.118
Where:
Ex = Annual emissions of each GHG from process vent
(metric ton/yr).
N = Number of venting events per year.
VRn = Volumetric flow rate of process vent (scf per hour
per event).
44 = Molecular weight of CO2 (kg/kg-mole).
MFx = Mole fraction of GHG x in process vent.
MWx = Molecular weight of GHG x (kg/kg-mole); use 44 for
CO2 or N2O and 16 for CH4.
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
VTn = Venting time, (hours per event).
0.001 = Conversion factor (metric ton/kg)
(k) For uncontrolled blowdown systems, you must either use the
methods for process vents in paragraph (j) of this section or calculate
CH4 emissions using Equation Y-13 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.119
Where:
CH4 = Methane emission rate from blowdown systems (mt
CH4/year).
QRef = Quantity of crude oil plus the quantity of
intermediate products received from off site that are processed at
the facility (MMbbl/year).
EFBD = Methane emission factor for uncontrolled blown
systems (scf CH4/MMbbl); default is 137,000.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(l) For equipment leaks, calculate CH4 emissions using
the method specified in either paragraph (l)(1) or (l)(2) of this
section.
(1) Use process-specific methane composition data (from measurement
data or process knowledge) and any of the emission estimation
procedures provided in the Protocol for Equipment Leak Emissions
Estimates (EPA-453/R-95-017, NTIS PB96-175401).
(2) Use Equation Y-14 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.120
Where:
CH4 = Annual methane emissions from fugitive equipment
leaks (metric tons/year)
NCD = Number of atmospheric crude oil distillation
columns at the facility.
NPU1 = Cumulative number of catalytic cracking units,
coking units (delayed or fluid), hydrocracking, and full-range
distillation columns (including depropanizer and debutanizer
distillation columns) at the facility.
NPU2 = Cumulative number of hydrotreating/hydrorefining
units, catalytic reforming units, and visbreaking units at the
facility.
NH2 = Total number of hydrogen plants at the facility.
NFGS = Total number of fuel gas systems at the facility.
(m) For storage tanks, calculate CH4 emissions using the
applicable methods in paragraphs (m)(1) and (2) of this section.
(1) For storage tanks other than those processing unstabilized
crude oil, you must either calculate CH4 emissions from
storage tanks that have a vapor-phase methane concentration of 0.5
volume percent or more using tank-specific methane composition data
(from measurement data or product knowledge) and the TANKS Model
(Version 4.09D) or estimate CH4 emissions from storage tanks
using Equation Y-15 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.121
Where:
CH4 = Annual methane emissions from storage tanks (metric
tons/year).
0.1 = Default emission factor for storage tanks (metric ton
CH4/MMbbl).
QRef = Quantity of crude oil plus the quantity of
intermediate products received from off site that are processed at
the facility (MMbbl/year).
(2) For storage tanks that process unstabilized crude oil,
calculate CH4 emissions from the storage of unstabilized
crude oil using either tank-specific methane composition data (from
measurement data or product knowledge) and direct measurement of the
gas generation rate or by using Equation Y-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.122
Where:
CH4 = Annual methane emissions from storage tanks (metric
tons/year).
Qun = Quantity of unstabilized crude oil received at the
facility (MMbbl/year).
[Delta]P = Pressure differential from the previous storage pressure
to atmospheric pressure (pounds per square inch, psi).
MFCH4 = Mole fraction of CH4 in vent gas from
the unstabilized crude oil storage tank from facility measurements
(kg-mole CH4/kg-mole gas); use 0.27 as a default if
measurement data are not available.
995,000 = Correlation Equation factor (scf gas per MMbbl per psi)
16 = Molecular weight of CH4 (kg/kg-mole).
[[Page 16688]]
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
(n) For crude oil, intermediate, or product loading operations for
which the equilibrium vapor-phase concentration of methane is 0.5
volume percent or more, calculate CH4 emissions from loading
operations using product-specific, vapor-phase methane composition data
(from measurement data or process knowledge) and the emission
estimation procedures provided in Section 5.2 of the AP-42:
``Compilation of Air Pollutant Emission Factors, Volume 1: Stationary
Point and Area Sources''. For loading operations in which the
equilibrium vapor-phase concentration of methane is less than 0.5
volume percent, report zero methane emissions.
Sec. 98.254 Monitoring and QA/QC requirements.
(a) All fuel flow meters, gas composition monitors, and heating
value monitors that are used to provide data for the GHG emissions
calculations shall be calibrated prior to the first reporting year,
using a suitable method published by a consensus standards organization
(e.g., ASTM, ASME, API, AGA, etc.). Alternatively, calibration
procedures specified by the flow meter manufacturer may be used. Fuel
flow meters, gas composition monitors, and heating value monitors shall
be recalibrated either annually or at the minimum frequency specified
by the manufacturer.
(b) The owner or operator shall document the procedures used to
ensure the accuracy of the estimates of fuel usage, gas composition,
and heating value including but not limited to calibration of weighing
equipment, fuel flow meters, and other measurement devices. The
estimated accuracy of measurements made with these devices shall also
be recorded, and the technical basis for these estimates shall be
provided.
(c) All CO2 CEMS and flow rate monitors used for direct
measurement of GHG emissions must comply with the QA procedures in
Sec. 98.34(e).
Sec. 98.255 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required (e.g., concentrations, flow rates,
fuel heating values, carbon content values). Therefore, whenever a
quality-assured value of a required parameter is unavailable (e.g., if
a CEMS malfunctions during unit operation or if a required fuel sample
is not taken), a substitute data value for the missing parameter shall
be used in the calculations.
(a) For each missing value of the heat content, carbon content, or
molecular weight of the fuel, the substitute data value shall be the
arithmetic average of the quality-assured values of that parameter
immediately preceding and immediately following the missing data
incident. If, for a particular parameter, no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-assured value obtained after the missing
data period.
(b) For missing oil and gas flow rates, use the standard missing
data procedures in section 2.4.2 of appendix D to part 75 of this
chapter.
(c) For missing CO2, CO, or O2,
CH4, and N2O concentrations, stack gas flow rate,
and stack gas moisture content values, use the applicable initial
missing data procedures in Sec. 98.35 of subpart C of this part.
(d) For hydrogen plants, use the missing data procedures in subpart
P of this part.
(e) For petrochemical production units, use the missing data
procedures in subpart X of this part.
(f) For on-site landfills, use the missing data procedures in
subpart HH of this part.
(g) For on-site wastewater treatment systems, use the missing data
procedures in subpart II of this part.
Sec. 98.256 Data reporting requirements.
In addition to the reporting requirements of Sec. 98.3(c), you
must report the information specified in paragraphs (a) through (e) of
this section.
(a) For combustion sources, including flares, use the data
reporting requirements in Sec. 98.36.
(b) For hydrogen plants, use the data reporting requirements in
subpart P of this part.
(c) For petrochemical production units, use the data reporting
requirements in subpart X of this part.
(d) For on-site landfills, use the data reporting requirements in
subpart HH of this part.
(e) For on-site wastewater treatment systems, use the data
reporting requirements in subpart II of this part.
(f) For catalytic cracking units, traditional fluid coking units,
catalytic reforming units, sulfur recovery plants, and coke calcining
units, owners and operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit (fluid catalytic cracking
unit, thermal catalytic cracking unit, traditional fluid coking unit,
catalytic reforming unit, sulfur recovery plant, or coke calcining
unit).
(3) Maximum rated throughput of the unit, in bbl/stream day, metric
tons sulfur produced/stream day, or metric tons coke calcined/stream
day, as applicable.
(4) The calculated CO2, CH4, and N2O annual emissions
for each unit, expressed in metric tons of each pollutant emitted.
(5) A description of the method used to calculate the
CO2 emissions for each unit (e.g., reference section and
Equation number).
(g) For fluid coking unit of the flexicoking type, the owner or
operator shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) Indicate whether the GHG emissions from the low heat value gas
are accounted for in subpart C of this part or Sec. 98.253(c).
(5) If the GHG emissions for the low heat value gas are calculated
at the flexicoking unit, also report the calculated annual
CO2, CH4, and N2O emissions for each unit, expressed in
metric tons of each pollutant emitted.
(h) For asphalt blowing operations, the owner or operator shall
report:
(1) The unit ID number (if applicable).
(2) The quantity of asphalt blown.
(3) The type of control device used to reduce methane (and other
organic) emissions from the unit.
(4) The calculated annual CO2, CH4, and N2O emissions for each
unit, expressed in metric tons of each pollutant emitted.
(i) For process vents subject to Sec. 98.253(j), the owner or
operator shall report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated with the emissions.
(3) The type of control device used to reduce methane (and other
organic) emissions from the unit, if applicable.
(4) The calculated annual CO2, CH4, and N2O emissions for each
unit, expressed in metric tons of each pollutant emitted.
(j) For equipment leaks, storage tanks, uncontrolled blowdown
systems, delayed coking units, and loading operations, the owner or
operator shall report:
(1) The total quantity (in Million bbl) of crude oil plus the
quantity of intermediate products received from off-site that are
processed at the facility in the reporting year.
(2) The method used to calculate equipment leak emissions and the
[[Page 16689]]
calculated, cumulative CH4 emissions (in metric tons of each
pollutant emitted) for all equipment leak sources.
(3) The cumulative annual CH4 emissions (in metric tons
of each pollutant emitted) for all storage tanks, except for those used
to process unstabilized crude oil.
(4) The quantity of unstabilized crude oil received during the
calendar year and the cumulative CH4 emissions (in metric tons of each
pollutant emitted) for storage tanks used to process unstabilized crude
oil.
(5) The cumulative annual CH4 emissions (in metric tons of each
pollutant emitted) for uncontrolled blowdown systems.
(6) The total number of delayed coking units at the facility, the
number of delayed coking drums per unit, the dimensions and annual
number of coke-cutting cycles for each drum, and the cumulative annual
CH4 emissions (in metric tons of each pollutant emitted) for delayed
coking units.
(7) The quantity and types of materials loaded that have an
equilibrium vapor-phase concentration of methane of 0.5 volume percent
or greater, and the type of vessels in which the material is loaded.
(8) The type of control system used to reduce emissions from the
loading of material with an equilibrium vapor-phase concentration of
methane of 0.5 volume percent or greater, if any.
(9) The cumulative annual CH4 emissions (in metric tons of each
pollutant emitted) for loading operations.
(k) If you have a CEMS that measures CO2 emissions but that is not
required to be used for reporting GHG emissions under this subpart
(i.e., a CO2 CEMS on a process heater stack but the combustion
emissions are calculated based on the fuel gas consumption), you must
identify the emission source that has the CEMS and report the CO2
emissions as measured by the CEMS for that emissions source.
Sec. 98.257 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records of all parameters monitored under Sec. 98.255.
Sec. 98.258 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart Z--Phosphoric Acid Production
Sec. 98.260 Definition of the source category.
The phosphoric acid production source category consists of
facilities with a wet-process phosphoric acid process line used to
produce phosphoric acid. A wet-process phosphoric acid process line is
any system of operation that manufactures phosphoric acid by reacting
phosphate rock and acid.
Sec. 98.261 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a phosphoric acid production process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.262 GHGs to report.
(a) You must report CO2 process emissions from each wet-
process phosphoric acid production line.
(b) You must report CO2, N2O, and CH4 emissions from
each stationary combustion unit. You must follow the calculation
methods and all other requirements of subpart C of this part.
Sec. 98.263 Calculating GHG emissions.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must estimate total CO2 emissions
according to the requirements in Sec. Sec. 98.33(a) and 98.35.
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must calculate process emissions of CO2
from each wet-process phosphoric acid process line using Equation Z-1
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.123
Where:
Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
ICn = Inorganic carbon content of the batch of phosphate rock used
during month n, from the carbon analysis results (percent by weight,
expressed as a decimal fraction).
Pn = Mass of phosphate rock consumed in month n by wet-
process phosphoric acid process line m (tons).
m = Each wet-process phosphoric acid process line.
z = Number of months during which the process line m operates.
2000/2205 = Conversion factor to convert tons to metric tons.
(c) You must determine the total emissions from the facility using
Equation Z-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.124
Where:
CO2 = Annual process CO2 emissions from
phosphoric acid production facility(metric tons/year)
Em = Annual process CO2 emissions from wet-process
phosphoric acid process line m (metric tons/year)
p = Number of wet-process phosphoric acid process lines.
Sec. 98.264 Monitoring and QA/QC requirements.
(a) Determine the inorganic carbon content of each batch of
phosphate rock consumed in the production of phosphoric acid using the
applicable test method in section IX of the ``Book of Methods Used and
Adopted by the Association of Florida Phosphate Chemists'', Seventh
Edition, 1991.
(b) If more than one batch of phosphate rock is consumed in a
month, use the highest inorganic carbon content measured during that
month in Equation Z-1 of this subpart.
(c) Record the mass of phosphate rock consumed each month in each
wet-process phosphoric acid process line.
Sec. 98.265 Procedures for estimating missing data.
There are no missing data procedures for wet-process phosphoric
acid production facilities estimated according to Sec. 98.263(b). A
complete record of all measured parameters used in the GHG emissions
calculations is required. A re-test must be performed if the data from
the measurement are determined to be unacceptable.
Sec. 98.266 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (e) of this section for each wet-process phosphoric acid
production line:
(a) Annual phosphoric acid production by origin of the phosphate
rock (metric tons).
[[Page 16690]]
(b) Annual phosphoric acid production by concentration of
phosphoric acid produced (metric tons).
(c) Annual phosphoric acid production capacity.
(d) Annual arithmetic average percent inorganic carbon in phosphate
rock from batch records.
(e) Annual average phosphate rock consumption from monthly
measurement records (in metric tons).
Sec. 98.267 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (h) of this
section for each wet-process phosphoric acid production facility:
(a) Total annual CO2 emissions from all wet-process
phosphoric acid process lines (in metric tons).
(b) Phosphoric acid production (by origin of the phosphate rock)
and concentration.
(c) Phosphoric acid production capacity (in metric tons/year).
(d) Number of wet-process phosphoric acid process lines.
(e) Monthly phosphate rock consumption (by origin of phosphate
rock).
(f) Measurements of percent inorganic carbon in phosphate rock for
each batch consumed for phosphoric acid production.
(g) Records of all phosphate rock purchases and/or deliveries (if
vertically integrated with a mine).
(h) Documentation of the procedures used to ensure the accuracy of
monthly phosphate rock consumption.
Sec. 98.268 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart AA--Pulp and Paper Manufacturing
Sec. 98.270 Definition of source category.
(a) The pulp and paper manufacturing source category consists of
facilities that produce market pulp (i.e., stand-alone pulp
facilities), manufacture pulp and paper (i.e., integrated facilities),
produce paper products from purchased pulp, produce secondary fiber
from recycled paper, convert paper into paperboard products (e.g.,
containers), and operate coating and laminating processes.
(b) The emission units for which GHG emissions must be reported are
listed in paragraphs (b)(1) through (6) of this section:
(1) Chemical recovery furnaces at kraft and sodamills (including
recovery furnaces that burn spent pulping liquor produced by both the
kraft and semichemical process).
(2) Chemical recovery combustion units at sulfite facilities.
(3) Chemical recovery combustion units at stand-alone semichemical
facilities.
(4) Pulp mill lime kilns at kraft and soda facilities.
(5) Systems for adding makeup chemicals (CaCO3, Na2CO3).
Sec. 98.271 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a pulp and paper manufacturing process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.272 GHGs to report.
You must report the emissions listed in paragraphs (a) through (h)
of this section:
(a) CO2, biogenic CO2, CH4, and N2O emissions
from each kraft or soda chemical recovery furnace.
(b) CO2, biogenic CO2, CH4, and N2O emissions
from each sulfite chemical recovery combustion unit.
(c) CO2, biogenic CO2, CH4, and N2O emissions
from each semichemical chemical recovery combustion unit.
(d) CO2, biogenic CO2, CH4, and N2O emissions
from each kraft or soda pulp mill lime kiln.
(e) CO2 emissions from addition of makeup chemicals
(CaCO3, Na2CO3).
(f) Emissions of CO2, N2O, and CH4 from any other on-
site stationary fuel combustion units (boilers, gas turbines, thermal
oxiders, and other sources). You must follow the calculation
procedures, monitoring and QA/QC methods, missing data procedures,
reporting requirements, and recordkeeping requirements of subpart C of
this part.
(g) Emissions of CH4 from on-site landfills. You must follow the
calculation procedures, monitoring and QA/QC methods, missing data
procedures, reporting requirements, and recordkeeping requirements of
subpart HH of this part.
(h) Emissions of CH4 from on-site wastewater treatment. You must
follow the calculation procedures, monitoring and QA/QC methods,
missing data procedures, reporting requirements, and recordkeeping
requirements of subpart II of this part.
Sec. 98.273 Calculating GHG emissions.
(a) For each chemical recovery furnace located at a kraft or soda
facility, you must determine CO2, biogenic CO2,
CH4, and N2O emissions using the procedures in paragraphs (a)(1)
through (3) of this section. CH4 and N2O emissions must be calculated
as the sum of emissions from combustion of fossil fuels and combustion
of biomass in spent liquor solids.
(1) Calculate fossil fuel-based CO2 emissions from
direct measurement of fossil fuels consumed and default emissions
factors according to the Tier 1 methodology for stationary combustion
sources in Sec. 98.33(a)(1).
(2) Calculate fossil fuel-based CH4 and N2O emissions from direct
measurement of fossil fuels consumed, default HHV, and default
emissions factors and convert to metric tons of CO2
equivalent according to the methodology for stationary combustion
sources in Sec. 98.33(c)(2) and (3).
(3) Calculate biogenic CO2, CH4, and N2O emissions from
biomass using measured quantities of spent liquor solids fired, site-
specific HHV, and default or site-specific emissions factors, according
to Equation AA-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.125
Where:
CH4, or N2O, from Biomass = Biogenic CO2, CH4, or N2O
mass emissions from spent liquor solids combustion (metric tons).
(Solids)p = Mass of spent liquor solids combusted per month p (short
tons per month).
(HHV)p = High heat value of the spent liquor solids for month p
(mmBtu per mass).
EF = Default emission factor for CO2, CH4, or N2O, from
Table AA-1 of this subpart (kg CO2, CH4, or N2O per
mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons.
907 = Conversion factor from tons to kilograms.
(b) For each chemical recovery combustion unit located at a sulfite
or stand-alone semichemical facility, you must determine
CO2, CH4, and N2O emissions using the procedures in
[[Page 16691]]
paragraphs (b)(1) through (4) of this section:
(1) Calculate fossil CO2 emissions from fossil fuels
from direct measurement of fossil fuels consumed and default emissions
factors according to the Tier 1 Calculation Methodology for stationary
combustion sources in Sec. 98.33(a)(1).
(2) Calculate CH4 and N2O emissions from fossil fuels from direct
measurement of fossil fuels consumed, default HHV, and default
emissions factors and convert to metric tons of CO2
equivalent according to the methodology for stationary combustion
sources in Sec. 98.33(c)(2).
(3) Calculate biogenic CO2 emissions using measured
quantities of spent liquor solids fired and the carbon content of the
spent liquor solids, according to Equation AA-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.126
Where:
Biogenic CO2 = Annual CO2 mass emissions for
spent liquor solids combustion (metric tons).
(Solids)p = Mass of the spent liquor solids combusted in month p
(metric tons per month).
(CC)p = Carbon content of the spent liquor solids, from the fuel
analysis results for the month p (percent by weight, expressed as a
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
(4) Calculate CH4 and N2O emissions from biomass using Equation AA-
1 and the default CH4 and N2O emissions factors for kraft facilities in
Table AA-1 of this subpart and convert the CH4 or N2O emissions to
metric tons of CO2 equivalent according to the methodology
for stationary combustion sources in Sec. 98.2(b)(4).
(c) For each pulp mill lime kiln located at a kraft or soda
facility, you must determine CO2, CH4, and N2O emissions
using the procedures in paragraphs (c)(1) through (3) of this section:
(1) Calculate CO2 emissions from fossil fuel from direct
measurement of fossil fuels consumed and default HHV and default
emissions factors, according to the Tier 1 Calculation Methodology for
stationary combustion sources in Sec. 98.33(a)(1); use the default HHV
listed in Table C-1 of subpart C of this part and the default
CO2 emissions factors listed in Table AA-2 of this subpart.
(2) Calculate CH4 and N2O emissions from fossil fuel from direct
measurement of fossil fuels consumed, default HHV, and default
emissions factors and convert to metric tons of CO2
equivalent according to the methodology for stationary combustion
sources in Sec. 98.33(c)(2) and (3); use the default HHV listed in
Table C-1 of subpart C of this part and the default CH4 and N2O
emissions factors listed in Table AA-2 of this subpart.
(3) Biogenic CO2 emissions from conversion of CaCO3 to
CaO are calculated as part of the chemical recovery furnace biogenic
CO2 estimates in paragraph (a)(3) of this section.
(d) For makeup chemical use, you must calculate CO2
emissions by using direct or indirect measurement of the quantity of
chemicals added and ratios of the molecular weights of CO2
and the makeup chemicals, according to Equation AA-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.127
Where:
CO2 = CO2 mass emissions from makeup chemicals
(kilograms/yr).
M (caCO3) = Make-up quantity of CaCO3 used for the
reporting year (metric tons).
M (NaCO3) = Make-up quantity of Na2CO3 used for the reporting year
(metric tons).
44 = Molecular weight of CO2.
180 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.
Sec. 98.274 Monitoring and QA/QC requirements.
(a) Each facility subject to this subpart must quality assure the
GHG emissions data according to the applicable requirements in Sec.
98.34. All QA/QC data must be available for inspection upon request.
(b) High heat values of black liquor must be determined once per
month using TAPPI Method T 684. The mass of spent black liquor solids
must be determined once per month using TAPPI Method T 650. Carbon
analyses for spent pulping liquor must be determined once per month
using ASTM method D5373-08.
(c) Each facility must keep records that include a detailed
explanation of how company records of measurements are used to estimate
GHG emissions. The owner or operator must also document the procedures
used to ensure the accuracy of the measurements of fuel and makeup
chemical usage, including, but not limited, to calibration of weighing
equipment, fuel flow meters, and other measurement devices. The
estimated accuracy of measurements made with these devices must be
recorded and the technical basis for these estimates must be provided.
The procedures used to convert spent liquor flow rates to units of mass
(i.e., spent liquor solids firing rates) also must be documented.
(d) Records must be made available upon request for verification of
the calculations and measurements.
Sec. 98.275 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations, according to the requirements of paragraphs (a)
through (c) of this section:
(a) There are no missing data procedures for measurements of heat
content and carbon content of spent pulping liquor. A re-test must be
performed if the data from any monthly measurements are determined to
be invalid.
(b) For missing spent pulping liquor flow rates, use the lesser
value of either the maximum fuel flow rate for the combustion unit, or
the maximum flow
[[Page 16692]]
rate that the fuel flow meter can measure.
(c) For the use of makeup chemicals (carbonates), the substitute
data value shall be the best available estimate of makeup chemical
consumption, based on available data (e.g., past accounting records,
production rates). The owner or operator shall document and keep
records of the procedures used for all such estimates.
Sec. 98.276 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information in paragraphs (a) through
(e) of this section for each GHG emission unit listed in Sec.
98.270(b).
(a) Annual emissions of CO2, biogenic CO2,
CH4, and N2O presented by calendar quarter.
(b) Total consumption of all biomass fuels by calendar quarter.
(c) Total annual quantity of spent liquor solids fired at the
facility by calendar quarter.
(d) Total annual steam purchases.
(e) Total annual quantities of makeup chemicals (carbonates) used.
Sec. 98.277 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the records in paragraphs (a) through (h) of this section.
(a) GHG emission estimates (including separate estimates of
biogenic CO2) by calendar quarter for each emissions source
listed under Sec. 98.270(b) of this subpart.
(b) Monthly total consumption of all biomass fuels for each biomass
combustion unit.
(c) Monthly analyses of spent pulping liquor HHV for each chemical
recovery furnace at kraft and soda facilities.
(d) Monthly analyses of spent pulping liquor carbon content for
each chemical recovery combustion unit at a sulfite or semichemical
pulp facility.
(e) Monthly quantities of spent liquor solids fired in each
chemical recovery furnace and chemical recovery combustion unit.
(f) Monthly and annual steam purchases.
(g) Monthly and annual steam production for each biomass combustion
unit.
(h) Monthly quantities of makeup chemicals used.
Sec. 98.278 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table AA-1 of Subpart AA--Kraft Pulping Liquor Emissions Factors for
Biomass-Based CO2, CH4, and N2O
------------------------------------------------------------------------
Biomass-based emissions factors
(kg/mmBtu HHV)
Wood furnish --------------------------------
CO2\a\ CH4 N2O
------------------------------------------------------------------------
North American Softwood................ 94.4 0.030 0.005
North American Hardwood................ 93.7
Bagasse................................ 95.5
Bamboo................................. 93.7
Straw.................................. 95.1
------------------------------------------------------------------------
a Includes emissions from both the recovery furnace and pulp mill lime
kiln.
Table AA-2 of Subpart AA--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CO2, CH4, and N2O
----------------------------------------------------------------------------------------------------------------
Fossil fuel-based emissions factors (kg/mmBtu HHV)
-----------------------------------------------------------------
Fuel Kraft Lime Kilns Kraft Calciners
-----------------------------------------------------------------
CO2 CH4 N2O CO2 CH4 N2O
----------------------------------------------------------------------------------------------------------------
Residual Oil.................................. 76.7 0.0027 0 76.7 0.0027 0.0003
Distillate Oil................................ 73.5 ......... ......... 73.5 ......... 0.0004
Natural Gas................................... 56.0 ......... ......... 56.0 ......... 0.0001
Biogas........................................ 0 ......... ......... 0 ......... 0.0001
----------------------------------------------------------------------------------------------------------------
Subpart BB--Silicon Carbide Production
Sec. 98.280 Definition of the source category.
Silicon carbide production includes any process that produces
silicon carbide for abrasive purposes.
Sec. 98.281 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a silicon carbide production process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.282 GHGs to report.
(a) You must report CO2 and CH4 process
emissions from all silicon carbide process units combined, as set forth
in this subpart.
(b) You must report CO2, N2O, and
CH4 emissions from each stationary combustion unit by
following all of the requirements of subpart C of this part.
Sec. 98.283 Calculating GHG emissions.
You must determine CO2 emissions in accordance with the
procedures specified in either paragraph (a) or (b) of this section.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements of Sec.
98.33(b)(5)(iii)(A), (B), and (C), you must estimate total
CO2 emissions according to the requirements for the Tier 4
Calculation Methodology in Sec. 98.33(a)(4).
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must calculate the annual process CO2
emissions from all silicon carbide production processes at the facility
combined, using a facility-specific emission factor according to the
procedures in paragraphs (b)(1) and (2) of this section.
(1) Use Equation BB-1 of this section to calculate the facility-
specific emissions factor for determining CO2 emissions. The
carbon content must be
[[Page 16693]]
determined quarterly and used to calculate a quarterly CO2
emisssions factor:
[GRAPHIC] [TIFF OMITTED] TP10AP09.128
Where:
EFCO2 = CO2 emissions factor (metric tons
CO2/metric ton of petroleum coke consumed).
0.65 = Adjustment factor for the amount of carbon in silicon carbide
product (assuming 35 percent of carbon input is in the carbide
product).
CCF = Carbon content factor of petroleum coke from the supplier or
as measured by the applicable method incorporated by reference in
Sec. 98.7.
44/12 = Ratio of molecular weights, CO2 to carbon.
(2) Use Equation BB-2 of this section to calculate CO2
process emissions (quarterly) from all silicone carbide production:
[GRAPHIC] [TIFF OMITTED] TP10AP09.129
Where:
CO2 = Annual CO2 mass production emissions
(metric tons CO2/year).
Tn = Petroleum coke consumption in calendar quarter n
(tons coke).
EFCO2, n = CO2 emissions factor from calendar
quarter n (calculated in Equation BB-1 of this section).
2000/2205 = Conversion factor to convert tons to metric tons.
q = Number of quarters.
(c) You must determine annual process CH4 emissions from
all silicon carbide production processes combined using Equation BB-3
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.130
Where:
CH4 = Annual CH4 mass emissions (metric tons
CH4, year).
Tn = Petroleum coke consumption in calendar quarter n
(tons coke).
10.2 = CH4 emissions factor (kg CH4/metric ton
coke).
2000/2205 = Conversion factor to convert tons to metric tons.
0.001 = Conversion factor from kilograms to metric tons.
q = Number of quarters.
Sec. 98.284 Monitoring and QA/QC requirements.
(a) You must determine the quantity of petroleum coke consumed each
quarter (tons coke/quarter).
(b) For CO2 process emissions, you must determine the
carbon content of the petroleum coke for four calendar quarters per
year based on reports from the supplier or by measurement of the carbon
content by an off-site laboratory using the applicable test method
incorporated by reference in Sec. 98.7.
Sec. 98.285 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. There are no missing value
provisions for the carbon content factor or coke consumption. A re-test
must be performed if the data from the quarterly carbon content
measurements are determined to be unacceptable or not representative of
typical operations.
Sec. 98.286 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (e) of this section.
(a) Annual CO2 and CH4 emissions from all silicon
carbide production processes combined (in metric tons).
(b) Annual production of silicon carbide (in metric tons).
(c) Annual capacity of silicon carbide production (in metric tons).
(d) Annual operating hours.
(e) Quarterly facility-specific emission factors.
Sec. 98.287 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (c) of this
section for all silicon carbide production processes combined.
(a) Annual consumption of petroleum coke (in metric tons).
(b) Quarterly analyses of carbon content for consumed coke
(averaged to an annual basis).
(c) Quarterly facility-specific emission factor calculations.
Sec. 98.288 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart CC--Soda Ash Manufacturing
Sec. 98.290 Definition of the source category.
A soda ash manufacturing facility is any facility with a
manufacturing line that calcines trona to produce soda ash.
Sec. 98.291 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a soda ash manufacturing process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.292 GHGs to report.
(a) You must report CO2 process emissions from each soda
ash manufacturing line as required in this subpart.
(b) You must report the CO2, N2O, and
CH4 emissions from fuel combustion at each kiln and from
each stationary combustion unit by following the requirements of
subpart C of this part.
Sec. 98.293 Calculating GHG emissions.
You must determine CO2 emissions in accordance with the
procedures specified in either paragraph (a) or (b) of this section.
[[Page 16694]]
(a) Any soda ash manufacturing line that meets the conditions
specified in Sec. 98.33(b)(5)(iii)(A),(B), and (C), or Sec.
98.33(b)(5)(ii)(A) through (F) shall calculate total CO2
emissions using a continuous emissions monitoring system according to
the Tier 4 Calculation Methodology specified in Sec. 98.33(a)(4).
(b) If the facility does not measure total emissions with a CEMS,
you must determine the total process emissions from the facility using
Equation CC-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.131
Where:
CO2 = Annual process CO2 emissions from soda
ash manufacturing facility (metric tons/year).
Ek = Annual CO2 process emissions from each
calciner (kiln), k (in metric tons/year), using either Equation CC-2
or CC-3.
n = Number of calciners (kilns) located at the facility.
(c) Calculate the annual CO2 process emissions from each
kiln using either Equation CC-2 or CC-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.132
[GRAPHIC] [TIFF OMITTED] TP10AP09.133
Where:
CO2 = Annual CO2 process emissions (metric
tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(ICT)n = Inorganic carbon content in trona
input, from the carbon analysis results for month n (percent by
weight, expressed as a decimal fraction).
(ICsa)n = Inorganic carbon content in soda ash
output, from the carbon analysis results for month n (percent by
weight, expressed as a decimal fraction).
(Tt)n = Mass of trona input in month n (tons).
(Tsa)n = Mass of soda ash output in month n
(tons).
2000/2205 = Conversion factor to convert tons to metric tons.
0.097/1 = Ratio of ton of CO2 emitted for each ton of
trona.
0.138/1 = Ratio of ton of CO2 emitted for each ton of
natural soda ash produced.
Sec. 98.294 Monitoring and QA/QC requirements.
(a) You must determine the inorganic carbon content of the trona or
soda ash on a daily basis and determine the monthly average value for
each soda ash manufacturing line.
(b) If you calculate CO2 process emissions based on
trona input, you must determine the inorganic carbon content of the
trona using a total organic carbon analyzer according to the
ultraviolet light/chemical (sodium persulfate) oxidation method
(utilizing ASTM D4839-03).
(c) If you calculate CO2 process emissions based on soda
ash production, you must determine the inorganic carbon content of the
soda ash using ASTM E359-00 (2005). The inorganic carbon content of
soda ash can be directly expressed as the total alkalinity of the soda
ash.
(d) You must measure the mass of trona input or soda ash produced
by each soda ash manufacturing line on a monthly basis using either
belt scales or by weighing the soda ash at the truck or rail loadout
points of your facility.
(e) You must keep a record of all trona consumed and soda ash
production. You also must document the procedures used to ensure the
accuracy of the monthly measurements of trona consumed soda ash
production.
Sec. 98.295 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. There are no missing value
provisions for the carbon content of trona or soda ash. A re-test must
be performed if the data from the daily carbon content measurements are
determined to be unacceptable.
Sec. 98.296 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (f) of this section for each soda ash manufacturing line.
(a) Annual CO2 process emissions (metric tons).
(b) Number of soda ash manufacturing lines.
(c) Annual soda ash production (metric tons) and annual soda ash
production capacity.
(d) Annual consumption of trona from monthly measurements (metric
tons).
(e) Fractional purity (i.e., inorganic carbon content) of trona or
soda ash (by daily measurements and by monthly average) depending on
the components used in Equation CC-2 or CC-3 of this subpart).
(f) Number of operating hours in calendar year.
Sec. 98.297 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (d) of this
section for each soda ash manufacturing line.
(a) Monthly production of soda ash (metric tons).
(b) Monthly consumption of trona (metric tons).
(c) Daily analyses for inorganic carbon content of trona or soda
ash (as fractional purity), depending on the components used in
Equation CC-2 or CC-3 of this subpart.
(d) Number of operating hours in calendar year.
Sec. 98.298 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart DD--Sulfur Hexafluoride (SF6) From Electrical
Equipment
Sec. 98.300 Definition of the source category.
The electric power system source category includes electric power
transmission and distribution systems that operate gas-insulated
substations, circuit breakers, other switchgear, gas-insulated lines,
or power transformers containing sulfur-hexafluoride (SF6) or
perfluorocarbons (PFCs).
Sec. 98.301 Reporting threshold.
You must report GHG emissions from electric power systems if the
total nameplate capacity of SF6 and PFC containing equipment
in the system exceeds 17,820 lbs (7,838 kg).
Sec. 98.302 GHGs to report.
You must report total SF6 and PFC emissions (including
emissions from fugitive equipment leaks, installation,
[[Page 16695]]
servicing, equipment decommissioning and disposal, and from storage
cylinders) from the following types of equipment:
(a) Gas-insulated substations.
(b) Circuit breakers.
(c) Switchgear.
(d) Gas-insulated lines.
(d) Electrical transformers.
Sec. 98.303 Calculating GHG emissions.
(a) For each electric power system, you must estimate the annual
SF6 and PFC emissions using the mass-balance approach in
Equation DD-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.134
Where:
Decrease in SF6 Inventory = (SF6 stored in
containers, but not in equipment, at the beginning of the year)--
(SF6 stored in containers, but not in equipment, at the
end of the year).
Acquisitions of SF6 = (SF6 purchased from
chemical producers or distributors in bulk) + (SF6
purchased from equipment manufacturers or distributors with or
inside equipment) + (SF6 returned to site after off-site
recycling).
Disbursements of SF6 = (SF6 in bulk and
contained in equipment that is sold to other entities) +
(SF6 returned to suppliers) + (SF6 sent off
site for recycling) + (SF6 sent to destruction
facilities).
Net Increase in Total Nameplate Capacity of Equipment Operated =
(The Nameplate Capacity of new equipment)--(Nameplate Capacity of
retiring equipment). (Note that Nameplate Capacity refers to the
full and proper charge of equipment rather than to the actual
charge, which may reflect leakage.)
(b) The mass-balance method in paragraph (a) of this section shall
be used to estimate emissions of PFCs from power transformers,
substituting the relevant PFC(s) for SF6 in equation DD-1.
Sec. 98.304 Monitoring and QA/QC requirements.
(a) You must adhere to the following QA/QC methods for reviewing
the completeness and accuracy of reporting:
(1) Review inputs to Equation DD-1 to ensure inputs and outputs to
the company's system are included.
(2) Do not enter negative inputs and confirm that negative
emissions are not calculated. However, the Decrease in SF6
Inventory and the Net Increase in Total Nameplate Capacity may be
calculated as negative numbers.
(3) Ensure that beginning-of-year inventory matches end-of-year
inventory from the previous year.
(4) Ensure that in addition to SF6 purchased from bulk
gas distributors, SF6 purchased from Original Equipment
Manufacturers (OEM) and SF6 returned to the facility from
off-site recycling are also accounted for among the total additions.
(b) Ensure the following QA/QC methods are employed throughout the
year:
(1) Ensure that cylinders returned to the gas supplier are
consistently weighed on a scale that is certified to be accurate and
precise to within 1 percent of the true weight and is periodically
recalibrated per the manufacturer's specifications. Either measure
residual gas (the amount of gas remaining in returned cylinders) or
have the gas supplier measure it. If the gas supplier weighs the
residual gas, obtain from the gas supplier a detailed monthly
accounting, within 1 percent, of residual gas amounts in the cylinders
returned to the gas supplier.
(2) Ensure that procedures are in place and followed to track and
weigh all cylinders as they are leaving and entering storage. Cylinders
shall be weighed on a scale that is certified to be accurate to within
1 percent of the true weight and the scale shall be recalibrated at
least annually or at the minimum frequency specified by the
manufacturer, whichever is more frequent. All scales used to measure
quantities that are to be reported under Sec. 98.306 shall be
calibrated using suitable NIST-traceable standards and suitable methods
published by a consensus standards organization (e.g., ISWM, ISDA,
NCWM, or others). Alternatively, calibration procedures specified by
the scale manufacturer may be used. Calibration shall be performed
prior to the first reporting year.
(3) Ensure all substations have provided information to the manager
compiling the emissions report (if it is not already handled through an
electronic inventory system).
Sec. 98.305 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Replace missing data, if needed,
based on data from equipment with a similar nameplate capacity for
SF6 and PFC, and from similar equipment repair, replacement,
and maintenance operations.
Sec. 98.306 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each electric
power system, by chemical:
(a) Nameplate capacity of equipment containing SF6 and
nameplate capacity of equipment containing each PFC:
(1) Existing as of the beginning of the year.
(2) New during the year.
(3) Retired during the year.
(b) Transmission miles (length of lines carrying voltages at or
above 34.5 kV).
(c) SF6 and PFC sales and purchases.
(d) SF6 and PFC sent off site for destruction.
(e) SF6 and PFC sent off site to be recycled.
(f) SF6 and PFC returned from off site after recycling.
(g) SF6 and PFC stored in containers at the beginning
and end of the year.
(h) SF6 and PFC with or inside new equipment purchased
in the year.
(i) SF6 and PFC with or inside equipment sold to other
entities.
(j) SF6 and PFC returned to suppliers.
Sec. 98.307 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain records of the information reported and listed in Sec. 98.306.
Sec. 98.308 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart EE--Titanium Dioxide Production
Sec. 98.310 Definition of the source category.
The titanium dioxide production source category consists of
facilities that use the chloride process to produce titanium dioxide.
Sec. 98.311 Reporting threshold.
You must report GHG emissions under this subpart if your facility
[[Page 16696]]
contains a titanium dioxide production process and the facility meets
the requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.312 GHGs to report.
(a) You must report CO2 process emissions from each
chloride process line as required in this subpart.
(b) Report the CO2, N2O, and CH4
emissions from each stationary combustion unit. You must follow the
requirements of subpart C of this part.
Sec. 98.313 Calculating GHG emissions.
You must determine CO2 emissions for each process line
in accordance with the procedures specified in either paragraph (a) or
(b) of this section.
(a) If the facility operates and maintains a continuous emission
monitoring system (CEMS) that meets the conditions specififed in Sec.
98.33(b)(5)(ii) or (iii), then you must calculate total CO2
emissions using the Tier 4 Calculation Methodology specified in Sec.
98.33(a)(4).
(b) If the facility does not measure total emissions with a CEMS,
you must calculate the process CO2 emissions for each
calcined petroleum coke process line by determining the mass of
calcined petroleum coke consumed in line. Use Equation EE-1 of this
section to calculate annual CO2 process emissions for each
process line:
[GRAPHIC] [TIFF OMITTED] TP10AP09.135
Where:
Ep = Annual CO2 mass emissions from each
chloride process line (metric tons).
Cn = Calcined petroleum coke consumption in month n,
tons.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion of tons to metric tons.
(c) You must determine the total CO2 process emissions
from the facility using Equation EE-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.136
Where:
CO2 = Annual CO2 emissions from titanium
dioxide production facility (metric tons/year).
Ep = Annual CO2 emissions from each chloride
process line, p (in metric tons/year), determined using Equation EE-
1.
n = Number of separate chloride process lines located at the
facility.
Sec. 98.314 Monitoring and QA/QC requirements.
(a) You must measure your consumption of calcined petroleum coke
either by weighing the petroleum coke fed into your process (by belt
scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of
monthly calcined petroleum coke consumption.
Sec. 98.315 Procedures for estimating missing data.
There are no missing data procedures for the measurement of
petroleum coke consumption. A complete record of all measured
parameters used in the GHG emissions calculations is required.
Sec. 98.316 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information specified in
paragraphs (a) through (e) for each titanium dioxide production line.
(a) Annual CO2 emissions (metric tons).
(b) Annual consumption of calcined petroleum coke (metric tons).
(c) Annual production of titanium dioxide (metric tons).
(d) Annual production capacity of titanium dioxide (metric tons).
(e) Annual operating hours for each titanium dioxide process line.
Sec. 98.317 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the following records specified in paragraphs (a) through (e) of
this section for each titanium dioxide production facility.
(a) Monthly production of titanium dioxide (metric tons).
(b) Production capacity of titanium dioxide (metric tons).
(c) Records of all calcined petroleum coke purchases.
(d) Records of monthly calcined petroleum coke consumption (metric
tons).
(e) Annual operating hours for each titanium dioxide process line.
Sec. 98.318 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart FF--Underground Coal Mines
Sec. 98.320 Definition of the source category.
(a) This source category consists of active underground coal mines
and any underground mines under development that have operational pre-
mining degasification systems. An underground coal mine is a mine at
which coal is produced by tunneling into the earth to a subsurface coal
seam, where the coal is then mined with equipment such as cutting
machines, and transported to the surface. Active underground coal mines
are mines categorized by MSHA as active and where coal is currently
being produced or has been produced within the previous 90 days.
(b) This source category comprises the following emission points:
(1) Each ventilation well or shaft.
(2) Each degasification system well or shaft, including
degasification systems deployed before, during, or after mining
operations are conducted in a mine area.
(c) This source category does not include abandoned (closed) mines,
surface coal mines, or post-coal mining activities.
Sec. 98.321 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a underground coal mining process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.322 GHGs to report.
You must report the following:
(a) CH4 emissions from each ventilation well or shaft
and each degasification system (this includes degasification systems
deployed before, during, or after mining operations are conducted in a
mine area).
(b) CO2 emissions from coal mine gas CH4
destruction, where the gas is not a fuel input for energy generation or
use.
(c) CO2, CH4, and N2O emissions
from stationary fuel combustion devices. You must follow the
requirements of subpart C of this part.
Sec. 98.323 Calculating GHG emissions.
(a) For each ventilation well or shaft, you must estimate the
quarterly CH4 liberated from the mine ventilation system
using the measured CH4 content and flow rate, and Equation
FF-1 of this section. You must measure CH4 content, flow
rate, temperature, and pressure of the gas using the procedures
outlined in Sec. 98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.137
[[Page 16697]]
Where:
CH4V = Quarterly CH4 liberated from
ventilation systems (metric tons CH4).
V = Measured volumetric flow rate of active ventilation of mining
operations (cfm).
C = Measured CH4 concentration of ventilation gas during
active ventilation of mining operations (%, wet basis).
n = The number of days in the quarter where active ventilation of
mining operations is taking place.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1
atm (lb/scf).
T = Temperature at which flow is measured ([deg]R).
P = Pressure at which flow is measured (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).
(b) For each degasification system, you must estimate the quarterly
CH4 liberated from the mine degasification system using
measured CH4 content, flow rate, temperature, and pressure,
and Equation FF-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.138
Where:
CH4D = Quarterly CH4 liberated from the
degasification system (metric tons CH4).
V = Measured average volumetric flow rate for the days in the
quarter when the degasification system is in operation and the
continuous monitoring equipment is properly functioning (cfm).
C = Estimated or measured average CH4 concentration of
gas for the days in the quarter when the degasification system is in
operation and the continuous monitoring equipment is properly
functioning (%, wet basis).
n = The number of days in the quarter.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1
atm (lb/scf).
T = Measured average temperature at which flow is measured ([deg]R).
P = Measured average pressure at which flow is measured (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).
(c) If gas from degasification system wells or ventilation shafts
is destroyed you must calculate the quarterly CH4 destroyed
using Equation FF-3 of this section. You must measure CH4
content and flowrate according to the provisions in Sec. 98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.139
Where:
CH4 destroyed = Quantity of CH4 liberated from
mine that is destroyed (metric tons).
CH4 = Amount of CH4 collected for
destruction(metric tons).
DE = Destruction efficiency of the destruction equipment, based on
the lesser of the manufacturer's specified destruction efficiency or
98 percent (%)'.
(d) You must calculate the quarterly net CH4 emissions
to the atmosphere using Equation FF-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.140
Where:
CH4 emitted (net) = Quarterly CH4 emissions
from mine ventilation and degasification systems (metric tons).
CH4V = Quarterly CH4 liberated from mine
ventilation systems, calculated using Equation FF-1 of this section
(metric tons).
CH4D = Quarterly CH4 liberated from mine
degasification systems, calculated using Equation FF-2 of this
section (metric tons).
CH4 destroyed = Quarterly CH4 destroyed,
calculated using Equation FF-3 of this section (metric tons).
(e) For each degasification or ventilation system with on-site coal
mine gas CH4 destruction, where the gas is not a fuel input
for energy generation or use, you must estimate the CO2
emissions using Equation FF-5 of this section. You must measure the
CH4 content and the flow rate according to the provisions in
Sec. 98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.141
Where:
CO2 = Quarterly CO2 emissions from
CH4 destruction (metric tons).
CH4o = CH4 destroyed, calculated using
Equation FF-3 of this section (metric tons).
DE = Destruction efficiency, based on the lesser of the
manufacturer's specified destruction efficiency or 98 percent (%).
44/16 = Ratio of molecular weights of CO2 to
CH4.
Sec. 98.324 Monitoring and QA/QC requirements.
(a) The flow and CH4 content of coal mine gas destroyed
must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test
Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas
Chromatography (incorporated by reference, see Sec. 98.7).
(b) For liberation of methane from ventilation systems, you must do
one of the following:
(1) Monitor emissions from each well or shaft where active
ventilation is taking place by collecting quarterly grab samples and
making quarterly measurements of flow rate, temperature, and pressure.
The sampling and measurements must be made at the same location as MSHA
inspection samples are taken. You must follow MSHA sampling procedures
as set forth in the MSHA Handbook entitled, General Coal Mine
Inspection Procedures and Inspection Tracking System Handbook Number:
PH-08-V-1, January 1, 2008. You must record the airflow, temperature,
and pressure measured, the hand-held methane and oxygen readings in
percentile, the bottle number of samples collected, and the location of
the measurement or collection.
(2) Obtain results of the quarterly testing performed by MSHA.
(c) For liberation of methane at degasification systems, you must
monitor methane concentrations and flow rate from each degasification
well or shaft using any of the oil and gas flow
[[Page 16698]]
meter test methods incorporated by reference in Sec. 98.7.
(d) All fuel flow meters and gas composition monitors monitors
shall be calibrated prior to the first reporting year, using a suitable
method published by a consensus standards organization (e.g., ASTM,
ASME, API, AGA, MSHA, or others). Alternatively, calibration procedures
specified by the flow meter manufacturer may be used. Fuel flow meters,
and gas composition monitors shall be recalibrated either annually or
at the minimum frequency specified by the manufacturer or other
applicable standards.
(e) All temperature and pressure monitors must be calibrated using
the procedures and frequencies specified by the manufacturer.
(f) If applicable, the owner or operator shall document the
procedures used to ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure measurements. These procedures
include, but are not limited to, calibration of fuel flow meters, and
other measurement devices. The estimated accuracy of measurements, and
the technical basis for the estimated accuracy shall be recorded.
Sec. 98.325 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations, in accordance with paragraph (b) of this section.
(b) For each missing value of CH4 concentration, flow
rate, temperature, and pressure for ventilation and degasification
systems, the substitute data value shall be the arithmetic average of
the quality-assured values of that parameter immediately preceding and
immediately following the missing data incident. If, for a particular
parameter, no quality-assured data are available prior to the missing
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
Sec. 98.326 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each mine:
(a) Quarterly volumetric flow rate measurement results for all
ventilation systems, including date and location of measurement.
(b) Quarterly CH4 concentration measurement results for all
ventilation systems, including date and location of measurement.
(c) Quarterly CEMS volumetric flow data used to calculate CH4
liberated from degasification systems (summed from daily data).
(d) Quarterly CEMS CH4 concentration data used to calculate CH4
liberated from degasification systems (average from daily data).
(e) Quarterly CH4 destruction at ventilation and degasification
systems.
(f) Dates in reporting period where active ventilation of mining
operations is taking place.
(g) Dates in reporting period when continuous monitoring equipment
is not properly functioning.
(h) Quarterly averages of temperatures and pressures at the time
and at the conditions for which all measurements are made.
(i) Quarterly CH4 liberated from each ventilation well or shaft,
and from each degasification system (this includes degasification
systems deployed before, during, or after mining operations are
conducted in a mine area).
(j) Quarterly CH4 emissions (net) from each ventilation well or
shaft, and from each degasification system (this includes
degasification systems deployed before, during, or after mining
operations are conducted in a mine area).
(k) Quarterly CO2 emissions from on-site destruction of
coal mine gas CH4, where the gas is not a fuel input for energy
generation or use.
Sec. 98.327 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the following records:
(a) Calibration records for all monitoring equipment.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
Sec. 98.328 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart GG--Zinc Production
Sec. 98.330 Definition of the source category.
The zinc production source category consists of zinc smelters and
secondary zinc recycling facilities.
Sec. 98.331 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a zinc production process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.332 GHGs to report.
(a) You must report the CO2 process emissions from each
Waelz kiln and electrothermic furnace used for zinc production, as
applicable to your facility.
(a) You must report the CO2, CH4, and N2O emissions from
each stationary combustion unit, following requirements of subpart C of
this part.
Sec. 98.333 Calculating GHG emissions.
(a) If you operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must estimate total CO2 emissions
according to the requirements in Sec. 98.33(a).
(b) If you do not operate and maintain a CEMS that measures total
CO2 emissions consistent with the requirements in subpart C
of this part, you must determine the total CO2 emissions
from the Waelz kilns or electrothermic furnaces at your facility used
for zinc production using the procedures specified in paragraphs (b)(1)
and (2) of this section.
(1) For each Waelz kiln or electrothermic furnace at your facility
used for zinc production, you must determine the mass of carbon in each
carbon-containing material, other than fuel, that is fed, charged, or
otherwise introduced into each Waelz kiln and electrothermic furnace at
your facility for each calendar month and estimate total annual
CO2 process emissions from each affected unit at your
facility using Equation GG-1. For electrothermic furnaces, carbon
containing input materials include carbon eletrodes and carbonaceous
reducing agents. For Waelz kilns, carbon containing input materials
include carbonaceous reducing agents.
[GRAPHIC] [TIFF OMITTED] TP10AP09.142
[[Page 16699]]
Where:
ECO2 = Total CO2 process emissions from an
individual Waelz kiln or electrothermic furnace (metric tons per
year).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Zinc)n = Mass of zinc bearing material charged to the furnace in
month ``n'' (metric tons).
(CZinc)n = Carbon content of the zinc bearing material,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(Electrode)n = Mass of carbon electrode consumed in month ``n'', for
electrothermic furnace (metric tons).
(CElectrode)n = Average carbon content of the carbon electrode, from
the carbon analysis results for month ``n'', for electrothermic
furnace (percent by weight, expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke)
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials,
from the carbon analysis results for month ``n'' (percent by weight,
expressed as a decimal fraction).
(2) You must determine the total CO2 emissions from the
Waelz kilns or electrothermic furnaces at your facility using Equation
GG-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.143
Where:
CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions from Waelz kiln
or electrothermic furnace k calculated using Equation GG-1 of this
section, metric tons/year.
k = Total number of Waelz kilns or electrothermic furnaces at
facility used for the zinc production.
Sec. 98.334 Monitoring and QA/QC requirements.
If you determine CO2 emissions using the carbon input
procedure in Sec. 98.333(b)(1), you must meet the requirements
specified in paragraphs (a) through (c) of this section.
(a) Determine the mass of each solid carbon-containing input
material by direct measurement of the quantity of the material placed
in the unit or by calculations using process operating information, and
record the total mass for the material for each calendar month.
(b) For each input material identified in paragraph (a) of this
section, you must determine the average carbon content of the material
for each calendar month using information provided by your material
supplier or by collecting and analyzing a representative sample of the
material using an analysis method appropriate for the material.
(c) For each input material identified in paragraph (a) of this
section for which the carbon content is not provided by your material
supplier, the carbon content of the material must be analyzed by an
independent certified laboratory each calendar month using the test
methods (and their QA/QC procedures) in Sec. 98.7. Use ASTM E1941-04
(``Standard Test Method for Determination of Carbon in Refractory and
Reactive Metals and Their Alloys'') for analysis of zinc bearing
materials; ASTM D5373-02 (``Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal and Coke'') for analysis of carbonaceous reducing agents and
carbon electrodes, and ASTM C25-06 (``Standard Test Methods for
Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'') for
analysis of flux materials such as limestone or dolomite.
Sec. 98.335 Procedures for estimating missing data.
For the carbon input procedure in Sec. 98.333(b), a complete
record of all measured parameters used in the GHG emissions
calculations is required (e.g., raw materials carbon content values,
etc.). Therefore, whenever a quality-assured value of a required
parameter is unavailable, a substitute data value for the missing
parameter shall be used in the calculations.
(a) For each missing value of the carbon content the substitute
data value shall be the arithmetic average of the quality-assured
values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.
(b) For missing records of the mass of carbon-containing input
material consumption, the substitute data value shall be the best
available estimate of the mass of the input material. The owner or
operator shall document and keep records of the procedures used for all
such estimates.
Sec. 98.336 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the information specified in paragraphs (a)
through (e) of this section for each Waelz kiln or electrothermic
furnace.
(a) Annual CO2 emissions in metric tons, and the method
used to estimate emissions.
(b) Annual zinc product production capacity (in metric tons).
(c) Total number of Waelz kilns and electrothermic furnaces at the
facility.
(d) Number of facility operating hours in calendar year.
(e) If you use the carbon input procedure, report for each carbon-
containing input material consumed or used (other than fuel), the
information specified in paragraphs (e)(1) and (2) of this section.
(1) Annual material quantity (in metric tons).
(2) Annual average of the monthly carbon content determinations for
each material and the method used for the determination (e.g., supplier
provided information, analyses of representative samples you
collected).
Sec. 98.337 Records that must be retained.
In addition to the records required by Sec. 98.3(g) of subpart A
of this part, you must retain the records specified in paragraphs (a)
through (d) of this section.
(a) Monthly facility production quantity for each zinc product (in
metric tons).
(b) Number of facility operating hours each month.
(c) Annual production Quantity for each zinc product (in metric
tons).
(d) If you use the carbon input procedure, record for each carbon-
containing input material consumed or used (other than fuel), the
information specified in paragraphs (d)(1) and (2) of this section.
(1) Monthly material quantity (in metric tons).
(2) Monthly average carbon content determined for material and
records of the supplier provided information or analyses used for the
determination.
(e) You must keep records that include a detailed explanation of
how company records of measurements are used to estimate the carbon
input to each Waelz kiln or electrothermic furnace, as applicable to
your facility. You also must document the procedures used to ensure the
accuracy of the measurements of materials fed, charged, or placed in an
affected unit including, but not limited to, calibration of weighing
equipment and other measurement devices. The estimated accuracy of
measurements made with these devices must also be recorded, and the
technical basis for these estimates must be provided.
[[Page 16700]]
Sec. 98.338 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart HH--Landfills
Sec. 98.340 Definition of the source category.
(a) This source category consists of the following sources at
municipal solid waste (MSW) landfill facilities: landfills, landfill
gas collection systems, and landfill gas combustion systems (including
flares). This source category also includes industrial landfills
(including, but not limited to landfills located at food processing,
pulp and paper, and ethanol production facilities).
(b) This source category does not include hazardous waste landfills
and construction and demolition landfills.
Sec. 98.341 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a landfill process and the facility meets the requirements of
either Sec. 98.2(a)(1) or (2).
Sec. 98.342 GHGs to report.
(a) You must report CH4 generation and CH4 emissions from
landfills.
(b) You must report CH4 destruction resulting from landfill gas
collection and combustion systems.
(c) You must report CO2, CH4, and N2O emissions from
stationary fuel combustion devices. This includes emissions from the
combustion of fuels used in flares (e.g., for pilot gas or to
supplement the heating value of the landfill gas). Follow the
requirements of subpart C of this part. Do not calculate CO2
emissions resulting from the flaring of landfill gas.
Sec. 98.343 Calculating GHG emissions.
(a) For all landfills subject to the reporting requirements of this
subpart, calculate annual modeled CH4 generation according to the
applicable requirements in paragraphs (a)(1) through (4) of this
section.
(1) Calculate annual modeled CH4 generation using recorded or
estimated waste disposal quantities, default values from Table HH-1,
and Equation HH-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.144
Where:
GCH4 = Modeled methane generation rate in reporting year
T (metric tons CH4).
X = Year in which waste was disposed.
S = Start year of calculation. Use the year 50 years prior to the
year of the emissions estimate, or the opening year of the landfill,
whichever is more recent.
T = Reporting year for which emissions are calculated.
Wx = Quantity of waste disposed in the landfill in year X from
tipping fee receipts or other company records (metric tons, as
received (wet weight)).
L0 = CH4 generation potential (metric tons CH4/metric ton
waste) = MCF*DOC*DOCF*F*16/12.
MCF = Methane correction factor (fraction).
DOC = Degradable organic carbon [fraction (metric tons C/metric ton
waste)].
DOCF = Fraction of DOC dissimilated (fraction).
F = Fraction by volume of CH4 in landfill gas.
k = Rate constant (yr-1).
(2) For years when material-specific waste quantity data are
available, and for industrial waste landfills, apply Equation HH-1 of
this section for each waste quantity type and sum the CH4
generation rates for all waste types to calculate the total modeled
CH4 generation rate for the landfill. Use the appropriate
parameter values for k, DOC, MCF, DOCF, and F shown in Table
HH-1. The annual quantity of each type of waste disposed must be
calculated as the sum of the daily quantities of waste (of that type)
disposed. For both MSW and industrial landfills, you may use the bulk
waste parameters for a portion of your waste materials when using the
material-specific modeling approach for mixed waste streams that cannot
be designated to a specific material type. For years when waste
composition data are not available, use the bulk waste parameter values
for k and L0 in Table HH-1 of this subpart for the total
quantity of waste disposed in those years.
(3) For years prior to reporting for which waste disposal
quantities are not readily available for MSW landfills, Wx
shall be estimated using the estimated population served by the
landfill in each year, the values for national average per capita waste
disposal and fraction of generated waste disposed of in solid waste
disposal sites found in Table HH-2 of this subpart.
(4) For industrial landfills, Wx in reporting years must
be determined by direct mass measurement of waste entering the landfill
using industrial scales with a manufacturer's stated accuracy of 2 percent. For previous years, where data are unavailable on
waste disposal quantities, estimate the waste quantities according to
the requirements in paragraphs (a)(4)(i) and (ii) of this section.
(i) Calculate the average waste disposal rate per unit of
production for the first applicable reporting year using Equation HH-2
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.145
Where:
WDF = Average waste disposal factor determined on the first year of
reporting (metric tons per production unit). The average waste
disposal factor should not be re-calculated in subsequent reporting
years.
N = Number of years for which disposal and production data are
available.
Wn = Quantity of waste placed in the industrial landfill
in year n (metric tons).
Pn = Quantity of product produced in year n (production
units).
(ii) Calculate the waste disposal quantities for historic years in
which direct waste disposal measurements are not available using
historical production data and Equation HH-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.146
Where:
X = Historic year in which waste was disposed.
Wx = Projected quantity of waste placed in the landfill
in year X (metric tons).
WDF = Average waste disposal factor from Equation HH-1 of this
section (metric tons per production unit).
Px = Production quantity for the facility in year X from
company records (production units).
(b) For landfills with gas collection systems, calculate the
quantity of CH4 destroyed according to the requirements in
paragraphs (b)(1) through (4) of this section.
(1) Measure continuously the flow rate, CH4
concentration, temperature, and pressure, of the collected landfill gas
(before any treatment equipment) using a monitoring meter specifically
for CH4 gas, as specified in Sec. 98.344.
(2) Calculate the quantity of CH4 recovered for
destruction using Equation HH-4 of this section.
[[Page 16701]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.147
Where:
R = Annual quantity of recovered CH4 (metric tons
CH4).
Vn = Daily average volumetric flow rate for day n (acfm).
Cn = Daily average CH4 concentration of
landfill gas for day n (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520[deg]R or 60[deg]F
and 1 atm).
Tn = Temperature at which flow is measured for day n
([deg]R).
Pn = Pressure at which flow is measured for day n (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).
(c) Calculate CH4 generation (adjusted for oxidation in
cover materials) and actual CH4 emissions (taking into
account any CH4 recovery, and oxidation in cover materials)
according to the applicable methods in paragraphs (d)(1) through (4) of
this section.
(1) Calculate CH4 generation, adjusted for oxidation,
from the modeled CH4 (GCH4 from Equation HH-1)
using Equation HH-5 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.148
Where:
MG = Methane generation from the landfill in the reporting year,
adjusted for oxidation (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year
from Equation HH-1 of this section (metric tons CH4).
OX = Oxidation fraction default rate is 0.1 (10%).
(2) For landfills that do not have landfill gas collection systems,
the CH4 emissions are equal to the CH4 generation
calculated in Equation HH-5 of this section.
(3) For landfills with landfill gas collection systems, calculate
CH4 emissions using the methodologies specified in
paragraphs (c)(3)(i) and (ii) of this section.
(i) Calculate CH4 emissions from the modeled
CH4 generation and measured CH4 recovery using
Equation HH-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.149
Where:
Emissions = Methane emissions from the landfill in the reporting
year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year
from Equation HH-1 of this section or the quantity of recovered
CH4 from Equation HH-4 of this section, whichever is
greater (metric tons CH4).
R = Quantity of recovered CH4 from Equation HH-4 of this
section (metric tons).
OX = Oxidation fraction default rate is 0.1 (10%).
DE = Destruction efficiency (lesser of manufacturer's specified
destruction efficiency and 0.99)
(ii) Calculate CH4 generation and CH4
emissions using measured CH4 recovery and estimated gas
collection efficiency and Equations HH-7 and HH-8, of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.150
[GRAPHIC] [TIFF OMITTED] TP10AP09.151
Where:
MG = Methane generation from the landfill in the reporting year
(metric tons CH4).
Emissions = Methane emissions from the landfill in the reporting
year (metric tons CH4).
R = Quantity of recovered CH4 from Equation HH-4 of this
section (metric tons CH4).
CE = Collection efficiency estimated at landfill, taking into
account system coverage, operation, and cover system materials.
(Default is 0.75).
OX = Oxidation fraction (default rate is 0.1 (10%)).
DE = Destruction efficiency, (lesser of manufacturer's specified
destruction efficiency and 0.99).
Sec. 98.344 Monitoring and QA/QC requirements.
(a) The quantity of waste landfilled must be determined using mass
measurement equipment meeting the requirements for commercial weighing
equipment as described in ``Specifications, Tolerances, and Other
Technical Requirements For Weighing and Measuring Devices'' NIST
Handbook 44, 2008.
(b) The quantity of landfill gas CH4 destroyed must be
determined using ASTM D1945-03 (Reapproved 2006), Standard Test Method
for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas
Chromatography (incorporated by reference, see Sec. 98.7).
(c) All fuel flow meters and gas composition monitors shall be
calibrated prior to the first reporting year, using ASTM D1945-03
(Reapproved 2006), Standard Test Method for Analysis of Natural Gas by
Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice
for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89
(Reapproved 2006), Standard Test Method for Heating Value of Gases in
Natural Gas Range by Stoichiometric Combustion; or UOP539-97 Refinery
Gas Analysis by Gas Chromatography (incorporated by reference, see
Sec. 98.7). Alternatively, calibration procedures specified by the
flow meter manufacturer may be used. Fuel flow meters, and gas
composition monitors shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer.
(d) All temperature and pressure monitors must be calibrated using
the procedures and frequencies specified by the manufacturer.
(e) The owner or operator shall document the procedures used to
ensure the accuracy of the estimates of disposal
[[Page 16702]]
quantities and, if applicable, gas flow rate, gas composition,
temperature, and pressure measurements. These procedures include, but
are not limited to, calibration of weighing equipment, fuel flow
meters, and other measurement devices. The estimated accuracy of
measurements made with these devices shall also be recorded, and the
technical basis for these estimates shall be provided.
Sec. 98.345 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations, according to the requirements in paragraphs (a)
through (c) of this section.
(a) For each missing value of the CH4 content, the
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately
following the missing data incident. If, for a particular parameter, no
quality-assured data are available prior to the missing data incident,
the substitute data value shall be the first quality-assured value
obtained after the missing data period.
(b) For missing gas flow rates, the substitute data value shall be
the arithmetic average of the quality-assured values of that parameter
immediately preceding and immediately following the missing data
incident. If, for a particular parameter, no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-assured value obtained after the missing
data period.
(c) For missing daily waste disposal data for disposal in reporting
years, the substitute value shall be the average daily waste disposal
quantity for that day of the week as measured on the week before and
week after the missing daily data.
Sec. 98.346 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for each landfill.
(a) Waste disposal for each year of landfilling.
(b) Method for estimating waste disposal.
(c) Waste composition, if available, in percentage categorized as--
(1) Municipal,
(2) Construction and demolition,
(3) Biosolids or biological sludges,
(4) Industrial, inorganic,
(5) Industrial, organic,
(6) Other, or more refined categories, such as those for which k
rates are available in Table HH-1 of this subpart.
(d) Method for estimating waste composition.
(e) Fraction of CH4 in landfill gas based on measured
values if the landfill has a gas collection system or a default.
(f) Oxidation fraction used in the calculations.
(g) Degradable organic carbon (DOC) used in the calculations.
(h) Decay rate k used in the calculations.
(i) Fraction of DOC dissimilated used in the calculations.
(j) Methane correction factor used in the calculations.
(k) Annual methane generation and methane emissions (metric tons/
year) according to the methodologies in Sec. 98.343(c)(1) through (3).
Landfills with gas collection system must separately report methane
generation and emissions according to the methodologies in Sec.
98.343(c)(3)(i) and (ii) and indicate which values are calculated using
the methodologies in Sec. 98.343(c)(ii).
(l) Landfill design capacity.
(m) Estimated year of landfill closure.
(n) Total volumetric flow of landfill gas for landfills with gas
collection systems.
(o) CH4 concentration of landfill gas for landfills with
gas collection systems.
(p) Monthly average temperature at which flow is measured for
landfills with gas collection systems.
(q) Monthly average pressure at which flow is measured for
landfills with gas collection systems.
(r) Destruction efficiency used for landfills with gas collection
systems.
(s) Methane destruction for landfills with gas collection systems
(total annual, metric tons/year).
(t) Estimated gas collection system efficiency for landfills with
gas collection systems.
(u) Methodology for estimating gas collection system efficiency for
landfills with gas collection systems.
(v) Cover system description.
(w) Number of wells in gas collection system.
(x) Acreage and quantity of waste covered by intermediate cap.
(y) Acreage and quantity of waste covered by final cap.
(z) Total CH4 generation from landfills.
(aa) Total CH4 emissions from landfills.
Sec. 98.347 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the calibration records for all monitoring equipment.
Sec. 98.348 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table HH-1 of Subpart HH--Emissions Factors, Oxidation Factors and
Methods
------------------------------------------------------------------------
Factor Default value Units
------------------------------------------------------------------------
Waste model--bulk waste option
------------------------------------------------------------------------
k (precipitation <20 inches/ 0.02................ yr-1
year).
k (precipitation 20-40 0.038............... yr-1
inches/year).
k (precipitation >40 inches/ 0.057............... yr-1
year).
L0 (Equivalent to DOC = 0.067............... metric tons CH4/
0.2028 when MCF=1, metric ton waste.
DOCF=0.5, and F=0.5).
------------------------------------------------------------------------
Waste model--All MSW and industrial waste landfills
------------------------------------------------------------------------
MCF......................... 1................... ....................
DOCF........................ 0.5................. ....................
F........................... 0.5................. ....................
------------------------------------------------------------------------
[[Page 16703]]
Waste model--MSW using waste composition option
------------------------------------------------------------------------
DOC (food waste)............ 0.15................ Weight fraction, wet
basis.
DOC (garden)................ 0.2................. Weight fraction, wet
basis.
DOC (paper)................. 0.4................. Weight fraction, wet
basis.
DOC (wood and straw)........ 0.43................ Weight fraction, wet
basis.
DOC (textiles).............. 0.24................ Weight fraction, wet
basis.
DOC (diapers)............... 0.24................ Weight fraction, wet
basis.
DOC (sewage sludge)......... 0.05................ Weight fraction, wet
basis.
DOC (bulk waste)............ 0.20................ Weight fraction, wet
basis.
k (food waste).............. 0.06 to 0.185 \a\... yr-1
k (garden).................. 0.05 to 0.10 \a\.... yr-1
k (paper)................... 0.04 to 0.06 \a\.... yr-1
k (wood and straw).......... 0.02 to 0.03 \a\.... yr-1
k (textiles)................ 0.04 to 0.06 \a\.... yr-1
k (diapers)................. 0.05 to 0.10 \a\.... yr-1
k (sewage sludge)........... 0.06 to 0.185 \a\... yr-1
------------------------------------------------------------------------
Waste model--Industrial waste landfills
------------------------------------------------------------------------
DOC (food processing)....... 0.15................ Weight fraction, wet
basis.
DOC (pulp and paper)........ 0.2................. Weight fraction, wet
basis.
k (food processing)......... 0.185............... yr-1
k (pulp and paper).......... 0.06................ yr-1
------------------------------------------------------------------------
Calculating methane generation and emissions
------------------------------------------------------------------------
OX.......................... 0.1.................
DE.......................... 0.99................
------------------------------------------------------------------------
\a\ Use the lesser value when the potential evapotranspiration rate
exceeds the mean annual precipitation rate and the greater value when
it does not.
Table HH-2 of Subpart HH--U.S. Per Capita Waste Disposal Rates
------------------------------------------------------------------------
Waste per
Year capita ton/cap/ % to SWDS
yr
------------------------------------------------------------------------
1940.................................... 0.64 100
1941.................................... 0.64 100
1942.................................... 0.64 100
1943.................................... 0.64 100
1944.................................... 0.63 100
1945.................................... 0.64 100
1946.................................... 0.64 100
1947.................................... 0.63 100
1948.................................... 0.63 100
1949.................................... 0.63 100
1950.................................... 0.63 100
1951.................................... 0.63 100
1952.................................... 0.63 100
1953.................................... 0.63 100
1954.................................... 0.63 100
1955.................................... 0.63 100
1956.................................... 0.63 100
1957.................................... 0.63 100
1958.................................... 0.63 100
1959.................................... 0.63 100
1960.................................... 0.63 100
1961.................................... 0.64 100
1962.................................... 0.64 100
1963.................................... 0.65 100
1964.................................... 0.65 100
1965.................................... 0.66 100
1966.................................... 0.66 100
1967.................................... 0.67 100
1968.................................... 0.68 100
1969.................................... 0.68 100
1970.................................... 0.69 100
1971.................................... 0.69 100
1972.................................... 0.70 100
1973.................................... 0.71 100
[[Page 16704]]
1974.................................... 0.71 100
1975.................................... 0.72 100
1976.................................... 0.73 100
1977.................................... 0.73 100
1978.................................... 0.74 100
1979.................................... 0.75 100
1980.................................... 0.75 100
1981.................................... 0.76 100
1982.................................... 0.77 100
1983.................................... 0.77 100
1984.................................... 0.78 100
1985.................................... 0.79 100
1986.................................... 0.79 100
1987.................................... 0.80 100
1988.................................... 0.80 100
1989.................................... 0.85 84
1990.................................... 0.84 77
1991.................................... 0.78 76
1992.................................... 0.76 72
1993.................................... 0.78 71
1994.................................... 0.77 67
1995.................................... 0.72 63
1996.................................... 0.71 62
1997.................................... 0.72 61
1998.................................... 0.78 61
1999.................................... 0.78 60
2000.................................... 0.84 61
2001.................................... 0.95 63
2002.................................... 1.06 66
2003.................................... 1.06 65
2004.................................... 1.06 64
2005.................................... 1.06 64
2006.................................... 1.06 64
------------------------------------------------------------------------
Subpart II--Wastewater Treatment
Sec. 98.350 Definition of source category.
(a) A wastewater treatment system is the collection of all
processes that treat or remove pollutants and contaminants, such as
soluble organic matter, suspended solids, pathogenic organisms, and
chemicals from waters released from industrial processes. This source
category applies to on-site wastewater treatment systems at pulp and
paper mills, food processing plants, ethanol production plants,
petrochemical facilities, and petroleum refining facilities.
(b) This source category does not include centralized domestic
wastewater treatment plants.
Sec. 98.351 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a wastewater treatment process and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.352 GHGs to report.
(a) You must report annual CH4 emissions from anaerobic
wastewater treatment processes.
(b) You must report annual CO2 emissions from oil/water
separators at petroleum refineries.
(c) You must report CO2, CH4, and
N2O emissions from the combustion of fuels in stationary
combustion devices and fuels used in flares by following the
requirements of subpart C of this part. For flares, calculate the
CO2 emissions only from pilot gas and other auxiliary fuels
combusted in the flare, as specified in subpart C of this part. Do not
include CO2 emissions resulting from the combustion of
anaerobic digester gas.
Sec. 98.353 Calculating GHG emissions.
(a) Estimate the annual CH4 mass emissions from systems
other than digesters using Equation II-1 of this section. The value of
flow and COD must be determined in accordance with the monitoring
requirements specified in Sec. 98.354. The flow and COD should reflect
the wastewater treated anaerobically on site in anaerobic systems such
as lagoons.
[GRAPHIC] [TIFF OMITTED] TP10AP09.152
Where:
CH4 = Annual CH4 mass emissions from the
wastewater treatment system (metric tons).
Flown = Volumetric flow rate of wastewater sent to an
anaerobic treatment system in month n (m\3\/month).
COD = Average monthly value for chemical oxygen demand of wastewater
entering anaerobic treatment systems other than digesters (kg/m\3\).
B0 = Maximum CH4 producing potential of
wastewater (kg CH4/kg COD), default is 0.25.
[[Page 16705]]
MCF = CH4 conversion factor, based on relevant values in
Table II-1.
0.001 = Conversion factor from kg to metric tons.
(b) For each petroleum refining facility having an on-site oil/
water separator, estimate the annual CO2 mass emissions
using Equation II-2 using measured values for the volume of wastewater
treated, and default values for emission factors by separator type from
Table II-1 of this subpart. The flow should reflect the wastewater
treated in the oil/water separator.
[GRAPHIC] [TIFF OMITTED] TP10AP09.153
Where:
CO2 = Annual emissions of CO2 from oil/water
separators (metric tons/yr).
EFsep = Emissions factor for the type of separator (kg
NMVOC/m\3\ wastewater treated).
VH20 = Volumetric flow rate of wastewater treated through
oil/water separator in month m (m\3\/month).
C = Carbon fraction in NMVOC (default = 0.6).
44/12 = Conversion factor for carbon to carbon dioxide.
0.001 = Conversion factor from kg to metric tons.
(c) For each anaerobic digester, estimate the annual mass of
CH4 destroyed using Equations II-3 and II-4 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.154
Where:
CH4d = Annual quantity of CH4 destroyed (kg/
yr).
CH4AD = Annual quantity of CH4 generated by
anaerobic digester, as calculated in Equation II-4 of this section
(metric tons CH4).
DE = CH4 destruction efficiency from flaring or burning
in engine (lesser of manufacturer's specified destruction efficiency
and 0.99).
[GRAPHIC] [TIFF OMITTED] TP10AP09.155
Where:
CH4AD = Annual quantity of CH4 generated by
anaerobic digestion (metric tons CH4/yr).
Vn = Daily average volumetric flow rate for day n, as
determined from daily monitoring specified in Sec. 98.354 (acfm).
Cn = Daily average CH4 concentration of
digester gas for day n, as determined from daily monitoring
specified in Sec. 98.354 (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60
[deg]F and 1 atm).
Tn = Temperature at which flow is measured for day n
([deg]R).
Pn = Pressure at which flow is measured for day n (atm).
Sec. 98.354 Monitoring and QA/QC requirements.
(a) The quantity of COD treated anaerobically must be determined
using analytical methods for industrial wastewater pollutants and must
be conducted in accordance with the methods specified in 40 CFR part
136.
(b) All flow meters must be calibrated using the procedures and
frequencies specified by the device manufacturer.
(c) For anaerobic treatment systems, facilities must monitor the
wastewater flow and COD no less than once per week. The sample location
must represent the influent to anaerobic treatment for the time period
that is monitored. The flow sample must correspond to the location used
to measure the COD. Facilities must collect 24-hour flow-weighted
composite samples, unless they can demonstrate that the COD
concentration and wastewater flow into the anaerobic treatment system
does not vary. In this case, facilities must collect 24-hour time-
weighted composites to characterize changes in wastewater due to
production fluctuations, or a grab sample if the influent flow is
equalized resulting in little variability.
(d) For oil/water separators, facilities must monitor the flow no
less than once per week. The sample location must represent the
influent to oil/water separator for the time period that is monitored.
(e) The quantity of gas destroyed must be determined using any of
the oil and gas flow meter test methods incorporated by reference in
Sec. 98.7.
(f) All gas flow meters and gas composition monitors shall be
calibrated prior to the first reporting year, using a suitable method
published by a consensus standards organization (e.g., ASTM, ASME, API,
AGA, or others). Alternatively, calibration procedures specified by the
flow meter manufacturer may be used. Gas flow meters and gas
composition monitors shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer.
(g) All temperature and pressure monitors must be calibrated using
the procedures and frequencies specified by the device manufacturer.
(h) All equipment (temperature and pressure monitors and gas flow
meters and gas composition monitors) shall be maintained as specified
by the manufacturer.
(i) If applicable, the owner or operator shall document the
procedures used to ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure measurements. These procedures
include, but are not limited to, calibration fuel flow meters, and
other measurement devices. The estimated accuracy of measurements made
with these devices shall also be recorded, and the technical basis for
these estimates shall be provided.
Sec. 98.355 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations, according to the following requirements in
paragraphs (a) and (b) of this section:
(a) For each missing monthly value of COD or wastewater flow
treated, the substitute data value shall be the arithmetic average of
the quality-assured values of those parameters for the weeks
immediately preceding and immediately following the missing data
incident. For each missing value of the CH4 content or gas
flow rates, the substitute data value shall be the arithmetic average
of the quality-assured values of that parameter immediately preceding
and
[[Page 16706]]
immediately following the missing data incident.
(b) If, for a particular parameter, no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-assured value obtained after the missing
data period.
Sec. 98.356 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information for the wastewater
treatment system.
(a) Type of wastewater treatment system.
(b) Percent of wastewater treated at each system component.
(c) COD.
(d) Influent flow rate.
(e) B0.
(f) MCF.
(g) Methane emissions.
(h) Type of oil/water separator (petroleum refineries).
(i) Emissions factor for the type of separator (petroleum
refineries).
(j) Carbon fraction in NMVOC (petroleum refineries).
(k) CO2 emissions (petroleum refineries).
(l) Total volumetric flow of digester gas (facilities with
anaerobic digesters).
(m) CH4 concentration of digester gas (facilities with
anaerobic digesters).
(n) Temperature at which flow is measured (facilities with
anaerobic digesters).
(o) Pressure at which flow is measured (facilities with anaerobic
digesters).
(p) Destruction efficiency used (facilities with anaerobic
digesters).
(q) Methane destruction (facilities with anaerobic digesters).
(r) Fugitive methane (facilities with anaerobic digesters).
Sec. 98.357 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the calibration records for all monitoring equipment.
Sec. 98.358 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table II-1 of Subpart II--Emission Factors
------------------------------------------------------------------------
Default
Factors value Units
------------------------------------------------------------------------
B0............................... 0.25 Kg CH4/kg COD.
MCF--anaerobic deep lagoon, 0.8 Fraction.
anaerobic reactor (e.g., upflow
anaerobic sludge blanket, fixed
film).
MCF--anaerobic shallow lagoon 0.2 Fraction.
(less than 2 m).
MCF--centralized aerobic 0 Fraction.
treatment system, well managed.
MCF--Centralized aerobic 0.3 Fraction.
treatment system, not well
managed (overloaded).
Anaerobic digester for sludge.... 0.8 Fraction.
C fraction in NMOC............... 0.6 Fraction.
EF sep--Gravity Type (Uncovered). 1.11E-01 Kg NMVOC/m\3\ wastewater
EF sep--Gravity Type (Covered)... 3.30E-03 Kg NMVOC/m\3\
wastewater.
EF sep--Gravity Type--(Covered 0 Kg NMVOC/m\3\
and Connected to a Destruction wastewater.
Device).
DAF or IAF--uncovered............ 4.00E-34 Kg NMVOC/m\3\
wastewater.
DAF or IAF--covered.............. 1.20E-44 Kg NMVOC/m\3\
wastewater.
DAF or IAF--covered and connected 0 Kg NMVOC/m\3\
to a destruction device. wastewater.
------------------------------------------------------------------------
DAF = dissolved air flotation type.
IAF = induced air flotation type.
Subpart JJ--Manure Management
Sec. 98.360 Definition of the source category.
(a) This source category consists of manure management systems for
livestock manure.
(b) A manure management system is as a system that stabilizes or
stores livestock manure in one or more of the following system
components: uncovered anaerobic lagoons, liquid/slurry systems, storage
pits, digesters, drylots, solid manure storage, feedlots and other dry
lots, high rise houses for poultry production (poultry without litter),
poultry production with litter, deep bedding systems for cattle and
swine, and manure composting. This definition of manure management
system encompasses the treatment of wastewaters from manure.
(c) This source category does not include components at a livestock
operation unrelated to the stabilization or storage of manure such as
daily spread or pasture/range/paddock systems.
Sec. 98.361 Reporting threshold.
You must report GHG emissions under this subpart if your facility
contains a manure management system and the facility meets the
requirements of either Sec. 98.2(a)(1) or (2).
Sec. 98.362 GHGs to report.
(a) You must report annual aggregate CH4 and
N2O emissions for each of the following manure management
system (MMS) components at the facility:
(1) Liquid/slurry systems such as tanks and ponds.
(2) Storage pits.
(3) Uncovered anaerobic lagoons used for stabilization or storage
or both.
(4) Digesters, including covered anaerobic lagoons.
(5) Solid manure storage including feedlots and other dry lots,
high rise houses for caged laying hens, broiler and turkey production
on litter, and deep bedding systems for cattle and swine.
(6) Manure composting.
(b) You must report CO2, CH4, and
N2O emissions from the combustion of supplemental fuels used
in flares by following the requirements of subpart C of this part. For
flares, calculate the CO2 emissions only from pilot gas and
other auxiliary fuels combusted in the flare, as specified in subpart C
of this part. Do not include CO2 emissions resulting from
the combustion of digester gas in flares.
(c) A facility that is subject to this rule only because of
emissions from manure management systems is not required to report
emissions from fuels used in stationary combustion devices other than
flares.
[[Page 16707]]
Sec. 98.363 Calculating GHG emissions.
(a) For manure management systems except digesters, estimate the
annual CH4 emissions using Equation JJ-1.
[GRAPHIC] [TIFF OMITTED] TP10AP09.156
Where:
TVS = Total volatile solids excreted by animal type, calculated
using Equation JJ-2 of this section (kg/day).
VSMMS = Percent of manure that is managed in each MMS
(decimal) (assumed to be equivalent to the amount of VS in each
system).
B0 = Maximum CH4-producing capacity, as
specified in Table JJ-1 of this section (m\3\ CH4/kg VS).
MCFMMS = CH4 conversion factor for MMS, as
specified in Table JJ-2 of this section (decimal).
[GRAPHIC] [TIFF OMITTED] TP10AP09.187
Where:
TVS = Total volatile solids excreted per animal type (kg/day).
%TVS = Annual average percent total volatile solids by animal type,
as determined from monthly manure monitoring as specified in Sec.
98.364 (decimal).
Population = Average annual animal population (head).
TAM = Typical animal mass, using either default values in Table JJ-1
of this section or farm-specific data (kg/head).
MER = Manure excretion rate, using either default values in Table
JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg
animal mass).
(b) For each digester, estimate the annual CH4 flow to
the combustion device using Equation JJ-3 of this section, the amount
of CH4 destroyed using Eq JJ-4 of this section, and the
amount of CH4 leakage using Equation JJ-5 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.157
Where:
CH4D = Methane flow to digester combustion device (metric
tons CH4/yr)
Vn = Daily average volumetric flow rate for day n, as
determined from daily monitoring as specified in Sec. 98.364
(acfm).
Cn = Daily average CH4 concentration of
digester gas for day n, as determined from daily monitoring as
specified in Sec. 98.364 (%, wet basis)
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60
[deg]F and 1 atm).
Tn = Temperature at which flow is measured for day
n([deg]R).
Pn = Pressure at which flow is measured for day n (atm).
[GRAPHIC] [TIFF OMITTED] TP10AP09.158
Where:
CH4D = Annual quantity of CH4 flow to digester
combustion device, as calculated in Equation JJ-4 of this section
(metric tons CH4).
DE = CH4 destruction efficiency from flaring or burning
in engine (lesser of manufacturer's specified destruction efficiency
and 0.99).
OH = Number of hours combustion device is functioning in reporting
year.
Hours = Hours in reporting year.
[GRAPHIC] [TIFF OMITTED] TP10AP09.159
CH4D = Annual quantity of CH4 combusted by
digester, as calculated in Equation JJ-4 of this section (metric
tons CH4).
CE = CH4 collection efficiency of anaerobic digester, as
specified in Table JJ-3 of this section (decimal).
(c) For each manure management system type, estimate the annual
N2O emissions using Equation JJ-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.160
[[Page 16708]]
Where:
Nex = Total nitrogen excreted per animal type, calculated
using Equation JJ-7 of this section (kg/day).
Nex,MMS = Percent of manure that is managed in each MMS
(decimal) (assumed to be equivalent to the amount of Nex
in each system).
EFMMS = Emission factor for MMS, as specified in Table
JJ-4 of this section (kg N2O-N/kg N).
[GRAPHIC] [TIFF OMITTED] TP10AP09.161
Where:
Nex = Total nitrogen excreted per animal type (kg/day).
NManure = Annual average percent of nitrogen present in
manure by animal type, as determined from monthly manure monitoring,
as specified in Sec. 98.364 (decimal).
Population = Average annual animal population (head).
TAM = Typical animal mass, using either default values in Table JJ-1
of this section or farm-specific data (kg/head).
MER = Manure excretion rate, using either default values in Table
JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg
animal mass).
(d) Estimate the annual total annual emissions using Equation JJ-8
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.162
Where:
CH4 emissions = From Equation JJ-1 of this section.
CH4 flow to digester combustion device = From Equation
JJ-3 of this section.
CH4 destruction of digester = From Equation JJ-4 of this
section.
CH4 leakage of digester = From Equation JJ-5 of this
section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = from Equation JJ-6 of this
section.
310 = Global Warming Potential of N2O.
Sec. 98.364 Monitoring and QA/QC requirements.
(a) Perform a one-time analysis on your operation to determine the
percent of total manure by weight that is managed in each on-site
manure management system.
(b) Determine the annual average percent total volatile solids by
animal type, (%TVS) by analysis of a representative sample using Method
160.4 (Residue, Volatile) as described in Methods for Chemical Analysis
of Water and Wastes, EPA-600/4-79/020, Revised March 1983. The
laboratory performing the analyses should be certified for analysis of
waste for National Pollutant Discharge Elimination System compliance
reporting. The sample analyzed should be a representative composite of
freshly excreted manure from each animal type contributing to the
manure management system. Total volatile solids of manure must be
sampled and analyzed monthly.
(c) Determine the annual average percent of nitrogen present in
manure by animal type (NManure) by analysis of a
representative sample using Method 351.3 as described in Methods for
Chemical Analysis of Water and Wastes, EPA-600/4-79-020, Revised March
1983. The laboratory performing the analyses should be certified for
analysis of waste for National Pollutant Discharge Elimination System
compliance reporting. The sample analyzed should be a representative
composite of freshly excreted manure from each animal type contributing
to the manure management system. Sample collection and analysis must be
monthly.
(d) The flow and CH4 concentration of gas from digesters
must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test
Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test
Method for Heating Value of Gases in Natural Gas Range by
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas
Chromatography (incorporated by reference in Sec. 98.7).
(e) All temperature and pressure monitors must be calibrated using
the procedures and frequencies specified by the manufacturer.
(f) All gas flow meters and gas composition monitors shall be
calibrated prior to the first reporting year, using a suitable method
published by a consensus standards organization (e.g., ASTM, ASME, API,
AGA, or others). Alternatively, calibration procedures specified by the
flow meter manufacturer may be used. Gas flow meters and gas
composition monitors shall be recalibrated either annually or at the
minimum frequency specified by the manufacturer.
(g) All equipment (temperature and pressure monitors and gas flow
meters and gas composition monitors) shall be maintained as specified
by the manufacturer.
(h) If applicable, the owner or operator shall document the
procedures used to ensure the accuracy of gas flow rate, gas
composition, temperature, and pressure measurements. These procedures
include, but are not limited to, calibration of fuel flow meters, and
other measurement devices. The estimated accuracy of measurements made
with these devices shall also be recorded, and the technical basis for
these estimates shall be provided.
Sec. 98.365 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions during unit operation or if a required fuel sample is not
taken), a substitute data value for the missing parameter shall be used
in the calculations, according to the requirements in paragraph (b) of
this section.
(b) For missing gas flow rates, volatile solids, or nitrogen or
methane content data, the substitute data value shall be the arithmetic
average of the quality-assured values of that parameter immediately
preceding and immediately following the missing data incident. If, for
a particular parameter, no quality-assured data are available prior to
the missing data incident, the substitute data value shall be the first
quality-assured value obtained after the missing data period.
Sec. 98.366 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report
[[Page 16709]]
must contain the following information for each manure management
system component:
(a) Type of manure management system component.
(b) Animal population (by animal type).
(c) Monthly total volatile solids content of excreted manure.
(d) Percent of manure handled in each manure management system
component.
(e) B0 value used.
(f) Methane conversion factor used.
(g) Average animal mass (for each type of animal).
(h) Monthly nitrogen content of excreted manure.
(i) N2O emission factor selected.
(j) CH4 emissions
(k) N2O emissions.
(l) Total annual volumetric biogas flow (for systems with
digesters).
(m) Average annual CH4 concentration (for systems with
digesters).
(n) Temperature at which gas flow is measured (for systems with
digesters).
(o) Pressure at which gas flow is measured (for systems with
digesters).
(p) Destruction efficiency used (for systems with digesters).
(q) Methane destruction (for systems with digesters).
(r) Methane generation from the digesters.
Sec. 98.367 Records that must be retained.
In addition to the information required by Sec. 98.3(g), you must
retain the calibration records for all monitoring equipment.
Sec. 98.368 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table JJ-1 of Subpart JJ--Waste Characteristics Data
------------------------------------------------------------------------
Maximum
Animal Manure methane
group excretion generation
Animal group typical rate (kg/ potential,
animal mass day/1000 kg Bo (m3 CH4/
(kg) animal kg VS
mass) added)
------------------------------------------------------------------------
Dairy Cows....................... 604 80.34 0.24
Dairy Heifers.................... 476 85 0.17
Feedlot Steers................... 420 51.2 0.33
Feedlot Heifers.................. 420 51.2 0.33
Market Swine <60 lbs............. 16 106 0.48
Market Swine 60-119 lbs.......... 41 63.4 0.48
Market Swine 120-179 lbs......... 68 63.4 0.48
Market Swine >180 lbs............ 91 63.4 0.48
Breeding Swine................... 198 31.8 0.48
Feedlot Sheep.................... 25 40 0.36
Goats............................ 64 41 0.17
Horses........................... 450 51 0.33
Hens >/= 1 yr.................... 1.8 60.5 0.39
Pullets.......................... 1.8 45.6 0.39
Other Chickens................... 1.8 60.5 0.39
Broilers......................... 0.9 80 0.36
Turkeys.......................... 6.8 43.6 0.36
------------------------------------------------------------------------
[[Page 16710]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.163
Table JJ-3 of Subpart JJ--Collection Efficiencies of Anaerobic Digesters
------------------------------------------------------------------------
Methane
System type Cover type collection
efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon.......... Bank to bank, 0.975
impermeable.
(biogas capture).................. Modular, impermeable 0.70
Complete mix, fixed film, or plug Enclosed Vessel..... 0.99
flow digester.
------------------------------------------------------------------------
Table JJ-4 of Subpart JJ--Nitrous Oxide Emission Factors (kg N2O-N/kg
Kjdl N)
------------------------------------------------------------------------
N2O
Waste management system emission
factor
------------------------------------------------------------------------
Aerobic Treatment (forced aeration)........................ 0.005
Aerobic Treatment (natural aeration)....................... 0.01
Digester................................................... 0
Uncovered Anaerobic Lagoon................................. 0
Cattle Deep Bed (active mix)............................... 0.07
Cattle Deep Bed (no mix)................................... 0.01
Manure Composting (in vessel).............................. 0.006
Manure Composting (intensive).............................. 0.1
Manure Composting (passive)................................ 0.01
Manure Composting (static)................................. 0.006
[[Page 16711]]
Deep Pit................................................... 0.002
Dry Lot.................................................... 0.02
Liquid/Slurry.............................................. 0.005
Poultry with bedding....................................... 0.001
Poultry without bedding.................................... 0.001
Solid Storage.............................................. 0.005
------------------------------------------------------------------------
Subpart KK--Supplies of Coal
Sec. 98.370 Definition of the source category.
(a) This source category comprises coal mines, coal importers, coal
exporters, and waste coal reclaimers.
(b) Coal mine means any active U.S. coal mine engaged in the
production of coal within the U.S. during the calendar year regardless
of the rank of coal produced, e.g., bituminous, sub-bituminous,
lignite, anthracite. Any coal mine categorized as an active coal mine
by MSHA is included.
(c) Coal importer has the same meaning given in Sec. 98.6 and
includes any U.S. coal mining company, wholesale coal dealer, retail
coal dealer, or other organization that imports coal into the U.S.
``Importer'' includes the person primarily liable for the payment of
any duties on the merchandise or an authorized agent acting on his or
her behalf.
(d) Coal exporter has the same meaning given in Sec. 98.6 and
includes any U.S. coal mining company, wholesale coal dealer, retail
coal dealer, or other organization that exports coal from the U.S.
(e) Waste coal reclaimer means any U.S. facility that reclaims or
recovers waste coal from waste coal piles from previous mining
operations and sells or delivers to an end-user.
Sec. 98.371 Reporting threshold.
Any supplier of coal who meets the requirements of Sec. 98.2(a)(4)
must report GHG emissions.
Sec. 98.372 GHGs to report.
You must report the CO2 emissions that would result from
the complete combustion or oxidation of coal supplied during the
calendar year.
Sec. 98.373 Calculating GHG emissions.
(a) For coal mines producing 100,000 short tons of coal or more
annually, the estimate of CO2 emissions shall be calculated
using either Calculation Methodology 1 or Calculation Methodology 2 of
this subpart.
(b) For coal mines producing less than 100,000 short tons of coal
annually, and for coal exporters, coal importers, and waste coal
reclaimers; CO2 emissions shall be calculated using either
Calculation Methodology 1, 2, or 3 of this subpart.
(c) For Calculation Methodology 1, 2, and 3 of this subpart,
emissions of CO2 shall be calculated using Equation KK-1 of
this section. The difference between Calculation Methodology 1, 2, and
3 of this subpart, is the method for determining the carbon content in
coal, as specified in paragraphs (d), (e), and (f) of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.164
Where:
CO2 = Annual CO2 mass emissions from the
combustion of coal (metric tons/yr).
44/12 = Ratio of molecular weights, CO2 to carbon.
Mass = Quantity of coal produced from company records (short tons/
yr).
Carbon = Annual weighted average fraction of carbon in the coal
(decimal value).
0.907 = Conversion factor from short tons to metric tons.
(d) For coal mines using Calculation Methodology 1 of this subpart,
the annual weighted average of the mass fraction of carbon in the coal
shall be based on daily measurements and calculated using Equation KK-2
of this section. For importers, exporters, and waste coal reclaimers
using Methodology 1 of this subpart, measurements of each shipment can
be used in place of daily measurements:
[GRAPHIC] [TIFF OMITTED] TP10AP09.165
Where:
Carbon = Annual mass fraction of coal carbon (dimensionless).
Xi = Daily or per shipment mass fraction of carbon in coal for day i
measured by ultimate analysis (decimal value).
Yi = Amount of coal supplied on day i(short tons) as measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short tons).
(e) For coal mines using Calculation Methodology 2 of this subpart,
the annual weighted average of the mass fraction of carbon in the coal
shall be calculated on the basis of daily measurements of the gross
calorific value (GCV) of the coal and a statistical relationship
between carbon content and GCV (higher heating value). For importers,
exporters, and waste coal reclaimers using Calculation Methodology 2 of
this subpart, measurements of each shipment can be used in place of
daily measurements.
(1) Equation KK-3 shall be used to determine the weighted annual
average GCV of the coal, and the individual daily or per shipment
values shall be determined according to the monitoring methodology for
gross calorific values in Sec. 98.374(f).
(2) The statistical relationship between GCV and carbon content
shall be established according to the requirements in Sec. 98.374(f).
(3) The estimated annual weighted average of the mass fraction of
carbon in the coal shall be calculated by applying the slope
coefficient, determined according to the requirements of Sec.
98.374(f)(4), to the weighted annual average GCV of the coal determined
according to Equation KK-3 of this section.
(f) For coal mines using Calculation Methodology 3 of this subpart,
the annual weighted average of the mass fraction of carbon in the coal
shall be calculated on the basis of daily measurements of GCV of the
coal and a default fraction of carbon in coal from Table KK-1 of this
subpart. For importers, exporters, and waste coal reclaimers using
Methodology 3 of this subpart, measurements of each shipment can be
used in place of daily measurements.
(1) Equation KK-3 shall be used to determine the weighted annual
average
[[Page 16712]]
GCV of the coal, and the individual daily or per shipment values shall
be determined according to the monitoring methodology for gross
calorific values in Sec. 98.374(g).
(2) The estimated annual weighted average of the mass fraction of
carbon in the coal shall be identified from Table KK-1 of this subpart
using annual weighted GCV of the coal determined according to Equation
KK-3 of this section.
(g) For Calculation Methodologies 2 and 3 of this subpart, the
weighted annual average gross calorific value (GCV) or higher heating
value of the coal shall be calculated using Equation KK-3 of this
section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.166
Where:
GCV = the weighted annual average gross calorific value or higher
heating value of the coal (Btu/lb).
zi = Daily or per shipment GCV or HHV of coal for day i
measured by proximate analysis (decimal value).
yi = Amount of coal supplied on day i (short tons) as
measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short tons).
Sec. 98.374 Monitoring and QA/QC requirements.
(a) The most current version of the NIST Handbook published by
Weights and Measures Division, National Institute of Standards and
Technology shall be used as the standard practice for all coal
weighing.
(b) For all coal mines, the quantity of coal shall be determined as
the total mass of coal in short tons sold and removed from the facility
during the calendar year.
(c) For coal importers, the quantity of coal shall be determined as
the total mass of coal in short tons imported into the U.S. during the
calendar year, as reported to U.S. Customs.
(d) For coal exporters, the quantity of coal shall be determined as
the total mass of coal in short tons sold and exported from the U.S.,
as reported to U.S. Customs.
(e) For waste coal reclaimers, the quantity of coal shall be
determined as the total mass of coal in short tons sold for use as
reported to state agencies.
(f) For reporters using Calculation Methodology 1 of this subpart,
the carbon content shall be determined as follows:
(1) Representative coal samples shall be collected daily or per
shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or
D7430-08 from coal loaded on the conveyor belt.
(2) Daily or per shipment coal carbon content shall be determined
using ASTM D5373 (Test Methods for Instrumental Determination of Carbon
Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke).
(g) For reporters using Calculation Methodology 2 of this subpart,
the carbon content shall be determined as follows:
(1) Representative samples of coal shall be collected daily or per
shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or
D7430-08.
(2) Coal gross calorific value (GCV) shall be determined on the set
of samples collected in paragraph (f)(1) of this section using ASTM
D5865-07a, ``Standard Test Method for Gross Calorific Value of Coal and
Coke to record the heat content of the coal produced.
(3) Coal carbon content shall be determined at a minimum once each
month on one set of daily or per shipment samples collected in
paragraph (f)(1) of this section using ASTM D5373 (Test Methods for
Instrumental Determination of Carbon Hydrogen and Nitrogen in
Laboratory Samples of Coal and Coke).
(4) The individual samples for which both carbon content and GCV
were determined according to paragraphs (f)(2) and (f)(3) of this
section respectively, shall be used to establish a statistical
relationship between the heat content and the carbon content of the
coal produced. The owner or operator shall statistically plot the
correlation of Btu/lb of coal vs. percent carbon (as a decimal value),
where the x-axis is Btu/lb coal and the y-axis is percent carbon (as
decimal value), then fit a line to the data points, then calculate the
slope and the coefficient of determination, and the R-square (R\2\) of
that line using the Btu/lb and percent carbon.
(5) Calculation Methodology 2 of this subpart can be used only if
all of the following four conditions are met:
(i) At least 12 samples per reporting year from 12 different months
of data must be used to construct the correlation graph.
(ii) The correlation graph must be constructed using all paired
data points from the first reporting year and all subsequent reporting
years.
(iii) There must be a linear relationship between percent carbon
and Btu/lb of coal.
(iv) For the second and subsequent years, R-square (R\2\) must be
greater than or equal to 0.90. This R-square requirement does not apply
during the first reporting year.
(6) If all of the conditions specified in paragraph (f)(5) of this
section are met, the weighted annual average gross calorific value or
higher heating value (Btu/lb) calculated according to Equation KK-3 of
this section shall be used to determine the corresponding annual
average coal carbon content using the correlation graph plotted
according to paragraph (f)(4) of this section.
(h) Reporters complying with Calculation Methodology 3 of this
subpart shall determine gross calorific value of the coal by collecting
representative daily or per shipment samples of coal using either ASTM
D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or D7430-08; and
testing using ASTM D5865-07a, ``Standard Test Method for Gross
Calorific Value of Coal and Coke to record the heat content of the coal
produced.''
(i) Coal exporters shall calculate carbon content for each shipment
of coal using information on the carbon content of the exported coal
provided by the source mine, according to Calculation Methodology 1, 2,
or 3 of this subpart, as appropriate.
(j) Coal importers shall calculate carbon content for each shipment
of coal using Calculation Methodology 1, 2, or 3 of this subpart.
(k) Waste coal reclaimers shall calculate carbon content for each
shipment of coal using Calculation Methodology 1, 2, or 3 of this
subpart.
(l) Each owner or operator using mechanical coal sampling systems
shall perform quality assurance and quality control according to ASTM
D4702-07 and ASTM D6518-07.
Sec. 98.375 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data
value for the missing parameter shall be used in the calculations.
(b) Whenever a quality-assured value for coal production during any
time period is unavailable, you must use the average of the parameter
values recorded immediately before and after the missing data period in
the calculations.
(c) Facilities using Calculation Methodology 1 of this subpart
shall develop the statistical relationship between GCV and carbon
content according to Sec. 98.274(e), and use this statistical
relationship to estimate daily carbon content for any day for which
[[Page 16713]]
measured carbon content is not available.
(d) Facilities, importers and exporters using Calculation
Methodology 2 or 3 of this subpart shall estimate the missing GCV
values based on a weighted average value for the previous seven days.
(e) Estimates of missing data shall be documented and records
maintained showing the calculations.
Sec. 98.376 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information.
(a) Each coal mine owner or operator shall report the following
information for each coal mine:
(1) The name and MSHA ID number of the mine.
(2) The name of the operating company.
(3) Annual CO2 emissions.
(4) By rank, the total annual quantity in tons of coal produced.
(5) The annual weighted carbon content of the coal as calculated
according to Sec. 98.373.
(6) If Calculation Methodology 1 of this subpart was used to
determine CO2 mass emissions, you must report daily mass
fraction of carbon in coal measured by ultimate analysis and daily
amount of coal supplied.
(7) If Calculation Methodology 2 of this subpart was used to
determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb
correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R\2\) value of the correlation.
(8) If Calculation Methodology 3 of this subpart was used to
determine CO2 mass emissions, you must report daily GCV of
coal measured by proximate analysis and daily amount of coal supplied.
(b) Coal importers shall report the following information at the
corporate level:
(1) The total annual quantity in tons of coal imported into the
U.S. by the importer, by rank, and country of origin.
(2) Annual CO2 emissions.
(3) The annual weighted carbon content of the coal as calculated
according to Sec. 98.373.
(4) If Calculation Methodology 1 of this subpart was used to
determine CO2 mass emissions, you must report mass fraction
of carbon in coal per shipment measured by ultimate analysis and amount
of coal supplied per shipment.
(5) If Calculation Methodology 2 of this subpart was used to
determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb
correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R\2\) value of the correlation.
(6) If Calculation Methodology 3 of this subpart was used to
determine CO2 mass emissions, you must report GCV in coal
per shipment measured by proximate analysis and amount of coal supplied
per shipment.
(d) Coal exporters shall report the following information at the
corporate level:
(1) The total annual quantity in tons of coal exported from the
U.S. by rank and by coal producing company and mine.
(2) Annual CO2 emissions.
(3) The annual weighted carbon content of the coal as calculated
according to Sec. 98.373.
(4) If Calculation Methodology 1 of this subpart was used to
determine CO2 mass emissions, you must report mass fraction
of carbon in coal per shipment measured by ultimate analysis and amount
of coal supplied per shipment.
(5) If Calculation Methodology 2 of this subpart was used to
determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb
correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squared (R\2\) value of the correlation.
(6) If Calculation Methodology 3 of this subpart was used to
determine CO2 mass emissions, you must report GCV in coal
per shipment measured by proximate analysis and amount of coal supplied
per shipment.
(e) Waste coal reclaimers shall report the following information
for each reclamation site:
(1) By rank, the total annual quantity in tons of waste coal
produced.
(2) Mine and state of origin if waste coal is reclaimed from mines
that are no longer operating.
(3) Annual CO2 emissions.
(4) The annual weighted carbon content of the coal as calculated
according to Sec. 98.373.
(5) If Calculation Methodology 1 of this subpart was used to
determine CO2 mass emissions, you must report mass fraction
of carbon in coal per shipment measured by ultimate analysis and amount
of coal supplied per shipment.
(6) If Calculation Methodology 2 of this subpart was used to
determine CO2 mass emissions, you must report:
(i) All of the data used to construct the carbon vs. Btu/lb
correlation graph.
(ii) Slope of the correlation line.
(iii) The R-squre (R \2\) value of the correlation.
(7) If Calculation Methodology 3 of this subpart was used to
determine CO2 mass emissions, you must report GCV in coal
per shipment measured by proximate analysis and amount of coal supplied
per shipment.
Sec. 98.377 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the following information:
(a) A complete record of all measured parameters used in the
reporting of fuel quantities, including all sample results and
documentation to support quantities that are reported under this part.
(b) Records documenting all calculations of missing data.
(c) Calculations and worksheets used to estimate the CO2
emissions.
(d) Calibration records of any instruments used on site and
calibration records of scales or other equipment used to weigh coal.
Sec. 98.378 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table KK-1 of Subpart KK--Default Carbon Content of Coal for Method 3
(CO2 lbs/MMBtu1)
------------------------------------------------------------------------
Mass fraction
Weighted annual average GCV of coal Btu/lb\1\ of carbon in
coal (decimal)
------------------------------------------------------------------------
2,000................................................... 0.1140
2,250................................................... 0.1283
2,500................................................... 0.1425
2,750................................................... 0.1568
3,000................................................... 0.1710
3,250................................................... 0.1853
3,500................................................... 0.1995
3,750................................................... 0.2138
4,000................................................... 0.2280
4,250................................................... 0.2423
4,500................................................... 0.2565
4,750................................................... 0.2708
5,000................................................... 0.2850
5,250................................................... 0.2993
5,500................................................... 0.3135
5,750................................................... 0.3278
6,000................................................... 0.3420
6,250................................................... 0.3563
6,500................................................... 0.3705
6,750................................................... 0.3848
7,000................................................... 0.3990
7,250................................................... 0.4133
7,500................................................... 0.4275
7,750................................................... 0.4418
8,000................................................... 0.4560
8,250................................................... 0.4703
8,500................................................... 0.4845
8,750................................................... 0.4988
9,000................................................... 0.5130
9,250................................................... 0.5273
9,500................................................... 0.5415
9,750................................................... 0.5558
10,000.................................................. 0.5700
10,250.................................................. 0.5843
10,500.................................................. 0.5985
10,750.................................................. 0.6128
[[Page 16714]]
11,000.................................................. 0.6270
11,250.................................................. 0.6413
11,500.................................................. 0.6555
11,750.................................................. 0.6698
12,000.................................................. 0.6840
12,250.................................................. 0.6983
12,500.................................................. 0.7125
12,750.................................................. 0.7268
13,000.................................................. 0.7410
13,250.................................................. 0.7553
13,500.................................................. 0.7695
13,750.................................................. 0.7838
14,000.................................................. 0.7980
14,250.................................................. 0.8123
14,500.................................................. 0.8265
14,750.................................................. 0.8408
15,000.................................................. 0.8550
15,250.................................................. 0.8693
15,500.................................................. 0.8835
------------------------------------------------------------------------
\1\ Based on high heating values.
Subpart LL--Suppliers of Coal-based Liquid Fuels
Sec. 98.380 Definition of the source category.
This source category consists of producers, importers, and
exporters of coal-based liquids.
(a) A producer is the owner or operator of a coal-to-liquids
facility. A coal-to-liquids facility is any facility engaged in
coverting coal into liquid fuels such as gasoline and diesel using the
Fischer-Tropsch process or an alternative process, involving conversion
of coal into gas and then into liquids or conversion of coal directly
into liquids (direct liquefaction).
(b) An importer or exporter shall have the same meaning given in
Sec. 98.6.
Sec. 98.381 Reporting threshold.
Any supplier of coal-based liquid fuels who meets the requirements
of Sec. 98.2(a)(4) must report GHG emissions.
Sec. 98.382 GHGs to report.
You must report the CO2 emissions that would result from
the complete combustion or oxidation of coal-based liquids during the
calendar year.
Sec. 98.383 Calculating GHG emissions.
(a) Coal-to-liquid producers, importers and exporters must
calculate CO2 emissions using Equation LL-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.167
Where:
CO2 = Annual CO2 mass emissions from the
combustion of fuel (metric tons).
Producti = Total annual volume (in standard barrels) of a
coal-based liquid fuel ``i'' produced, imported, or exported.
EFi = CO2 emission factor (metric tons
CO2 per barrel) specific to liquid fuel ``i''.
(b) The emission factor (EF) for each type of coal-based liquid
shall be determined using either of the calculation methodologies
described in paragraphs (a) and (b) of this section. The same
calculation methodology must be used for the entire volume of the
product for the reporting year.
(1) Calculation Methodology 1. Use the default CO2
emission factor listed in column C of Table MM-1 of subpart MM
(Suppliers of Petroleum Products) that most closely represents the
coal-based liquid.
(2) Calculation Methodology 2. Develop a CO2 emission
factor according to Equation LL-2 of this section using direct
measurement of density and carbon share according to methods set forth
in Sec. 98.394(c) or a combination of direct measurement and the
default factor listed in columns A or B of Table MM-1 of subpart MM
that most closely represents the coal-based liquid.
[GRAPHIC] [TIFF OMITTED] TP10AP09.168
Where:
EF = Emission factor of coal-based liquid (metric tons
CO2 per barrel).
Density = Density of coal-based liquid (metric tons per barrel).
Wt% = Percent of total mass that carbon represents in coal-based
liquid.
Sec. 98.384 Monitoring and QA/QC requirements.
(a) Producers must measure the quantity of coal-based liquid fuels
using procedures for flow meters as described in subpart MM of this
part.
(b) Importers and exporters must determine the quantity of coal-
based liquid fuels using sales contract information on the volume
imported or exported during the reporting period.
(1) The quantity of coal-based liquid fuels must be measured using
sales contract information.
(2) The minimum frequency of the measurement of quantities of coal-
based liquid fuels shall be the number of sales contracts executed in
the reporting period.
(c) All flow meters and product monitors shall be calibrated prior
to use for reporting, using a suitable method published by a consensus
standards organization (e.g., ASTM, ASME, API, NAESB, or others).
Alternatively, calibration procedures specified by the flow meter
manufacturer may be used. Fuel flow meters shall be recalibrated either
annually or at the minimum frequency specified by the manufacturer.
(d) Reporters shall take the following steps to ensure the quality
and accuracy of the data reported under these rules:
(1) For all volumes of coal-based liquid fuels, reporters shall
maintain meter and such other records as are normally maintained in the
course of business to document fuel flows.
(2) For all estimates of CO2 mass emissions, reporters
shall maintain calculations and worksheets used to calculate the
emissions.
Sec. 98.385 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the
reporting of fuel volumes and the calculations of CO2 mass
emissions is required. Therefore, whenever a quality-assured
measurement of the quantity of coal-based liquid fuels is unavailable a
substitute data value for the missing quantity measurement shall be
calculated and used in the calculations.
(b) For coal-to-liquids facilities, the last quality assured
reading shall be
[[Page 16715]]
used. If substantial variation in the flow rate is observed or if a
quality assured measurement of quantity is unavailable for any other
reason, the average of the last and the next quality assured reading
shall be used to calculate a substitute measurement of quantity.
(c) Calculation of substitute data shall be documented and records
maintained showing the calculations.
Sec. 98.386 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information:
(a) Producers shall report the following information for each
facility:
(1) The total annual volume of each coal-based liquid supplied to
the economy (in standard barrels).
(2) The total annual CO2 emissions in metric tons
associated with each coal-based liquid supplied to the economy,
calculated according to Sec. 98.383(a).
(b) Importers shall report the following information at the
corporate level:
(1) The total annual volume of each imported coal-based liquid (in
standard barrels).
(2) The total annual CO2 emissions in metric tons
associated with each imported coal-based liquid, calculated according
to Sec. 98.383(a).
(c) Exporters shall report the following information at the
corporate level:
(1) The total annual volume of each exported coal-based liquid (in
standard barrels).
(2) The total annual CO2 emissions in metric tons
associated with each exported coal-based liquid, calculated according
to Sec. 98.383(a).
Sec. 98.387 Records that must be retained.
Reporters shall retain copies of all reports submitted to EPA.
Reporters shall maintain records to support volumes that are reported
under this part, including records documenting any calculation of
substitute measured data. Reporters shall also retain calculations and
worksheets used to estimate the CO2 equivalent of the
volumes reported under this part. These records shall be retained for
five (5) years similar to 40 CFR part 80 fuels compliance reporting
program.
Sec. 98.388 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart MM--Suppliers of Petroleum Products
Sec. 98.390 Definition of the source category.
This source category consists of petroleum refineries and importers
and exporters of petroleum products.
(a) A petroleum refinery is any facility engaged in producing
gasoline, kerosene, distillate fuel oils, residual fuel oils,
lubricants, asphalt (bitumen) or other products through distillation of
petroleum or through redistillation, cracking, or reforming of
unfinished petroleum derivatives.
(b) A refiner is the owner or operator of a petroleum refinery.
(c) Importer has the same meaning given in Sec. 98.6 and includes
any blender or refiner of refined or semi-refined petroleum products.
(d) Exporter has the same meaning given in Sec. 98.6 and includes
any blender or refiner of refined or semi-refined petroleum products.
Sec. 98.391 Reporting threshold.
Any supplier of petroleum products who meets the requirements of
Sec. 98.2(a)(4) must report GHG emissions.
Sec. 98.392 GHGs to report.
You must report the CO2 emissions that would result from
the complete combustion or oxidation of each petroleum product and
natural gas liquid produced, used as feedstock, imported, or exported
during the calendar year. Additionally, if you are a refiner, you must
report CO2 emissions that would result from the complete
combustion or oxidation of any biomass co-processed with petroleum
feedstocks.
Sec. 98.393 Calculating GHG emissions.
(a) Except as provided in paragraph (g) of this section, any
refiner, importer, or exporter shall calculate CO2 emissions
from each individual petroleum product and natural gas liquid using
Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.169
Where:
CO2i = Annual potential CO2 emissions from the
complete combustion or oxidation of each petroleum product or
natural gas liquid ``i'' (metric tons).
Producti = Total annual volume of product ``i'' produced,
imported, or exported by the reporting party (barrels). For
refiners, this volume only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
(b) Except as provided in paragraph (g) of this secton, any refiner
shall calculate CO2 emissions from each non-crude feedstock
using Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.170
Where:
CO2j = Annual potential CO2 emissions from the
complete combustion or oxidation of each non-crude feedstock ``j''
(metric tons).
Feedstockj = Total annual volume of a petroleum product
or natural gas liquid ``j'' that enters the refinery as a feedstock
to be further refined or otherwise used on site (barrels). Any waste
feedstock (see definitions) that enters the refinery must also be
included.
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
(c) Refiners shall calculate CO2 emissions from all
biomass co-processed with petroleum feedstocks using Equation MM-3 of
this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.171
Where:
CO2m = Annual potential CO2 emissions from the
complete combustion or oxidation of biomass ``m'' (metric tons).
Biomassm = Total annual volume of a specific type of
biomass that enters the refinery to be co-processed with petroleum
feedstocks to produce a petroleum product reported under paragraph
(a) of this section (barrels).
EFm = Biomass-specific CO2 emission factor
(metric tons CO2 per barrel).
(d) Refiners shall calculate total CO2 emissions from
all products using Equation MM-4 of this section.
[[Page 16716]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.172
Where:
CO2r = Total annual potential CO2 emissions
from the complete combustion or oxidation of all petroleum products
and natural gas liquids (ex refinery gate) minus non-crude
feedstocks and any biomass to be co-processed with petroleum
feedstocks.
CO2i = Annual potential CO2 emissions from the
complete combustion or oxidation of each petroleum product or
natural gas liquid ``i'' (metric tons).
CO2j = Annual potential CO2 emissions from the
complete combustion or oxidation of each non-crude feedstock ``j''
(metric tons).
CO2m = Annual potential CO2 emissions from the
complete combustion or oxidation of biomass ``m'' (metric tons).
(e) Importers and exporters shall calculate total CO2
emissions from all petroleum products and natural gas liquids imported
or exported, respectively, using Equations MM-1 and MM-5 of this
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.173
Where:
CO2i = Annual potential CO2 emissions from the
complete combustion or oxidation of each petroleum product or
natural gas liquid ``i'' (metric tons).
CO2x = Total annual potential CO2 emissions
from the complete combustion or oxidation of all petroleum products
and natural gas liquids.
(f) Except as provided in paragraph (g) of this section, the
emission factor (EF) for each petroleum product and natural gas liquid
shall be determined using either of the calculation methodologies
described in paragraphs (f)(1) or (f)(2) of this section. The same
calculation methodology must be used for the entire volume of the
product for the reporting year.
(1) Calculation Methodology 1. Use the appropriate default
CO2 emission factors listed in column C of Tables MM-1 and
MM-2 of this subpart.
(2) Calculation Methodology 2. Develop emission factors according
to Equation MM-6 of this section using direct measurements of density
and carbon share according to methods set forth in Sec. 98.394(c) or a
combination of direct measurements and default factors listed in
columns A and B of Tables MM-1 and MM-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP10AP09.174
Where:
EF = Emission factor of petroleum or natural gas product or non-
crude feedstock (metric tons CO2 per barrel).
Density = Density of petroleum product or natural gas liquid or non-
crude feedstock (metric tons per barrel).
Wt% = Percent of total mass that carbon represents in petroleum
product or natural gas liquid or non-crude feedstock.
44/12 = Conversion factor for carbon to carbon dioxide.
(g) In the event that some portion of a petroleum product or
feedstock is biomass-based and was not derived by co-processing biomass
and petroleum feedstocks together (i.e., the petroleum product or
feedstock was produced by blending a petroleum-based product with a
biomass-based product), the reporting party shall calculate emissions
for the petroleum product or feedstock according to one of the methods
in paragraph (g)(1) or (2) of this section, as appropriate.
(1) A reporting party using Calculation Methodology 1 of this
subpart to determine the emission factor of a petroleum product shall
calculate the CO2 emissions associated with that product
using Equation MM-7 of this section in place of Equation MM-1 of this
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.175
Where:
CO2i = Annual potential CO2 emissions from the
complete combustion or oxidation of petroleum product ``i'' (metric
tons).
Producti = Total annual volume of petroleum product ``i''
produced, imported, or exported by the reporting party (barrels).
For refiners, this volume only includes products ex refinery gate.
EFi = Petroleum product-specific CO2 emission
factor (metric tons CO2 per barrel) from MM-1.
%Voli = Percent volume of product ``i'' that is
petroleum-based.
(2) A refinery using Calculation Methodology 1 of this subpart to
determine the emission factor of a non-crude petroleum feedstock shall
calculate the CO2 emissions associated with that feedstock
using Equation MM-8 in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.176
Where:
CO2j = Annual potential CO2 emissions from the
complete combustion or oxidation of each non-crude feedstock ``j''
(metric tons).
Feedstockj = Total annual volume of a petroleum product
``j'' that enters the refinery as a feedstock to be further refined
or otherwise used on site (barrels).
EFj = Non-crude petroleum feedstock-specific
CO2 emission factor (metric tons CO2 per
barrel).
%Volj = Percent volume of feedstock ``j'' that is
petroleum-based.
(3) A reporter using Calculation Methodology 2 of this subpart to
determine the emission factor of a petroleum product must calculate the
CO2 emissions associated with that product using Equation
MM-9 of this section in place of Equation MM-1 of this section.
[[Page 16717]]
[GRAPHIC] [TIFF OMITTED] TP10AP09.177
Where:
CO2i = Annual potential CO2 emissions from the
complete combustion or oxidation of product ``i'' (metric tons).
Producti = Total annual volume of petroleum product ``i''
produced, imported, or exported by the reporting party (barrels).
For refiners, this volume only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-3 that most closely represents the component of product ``i''
that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is
biomass-based.
(4) A refiner using Calculation Methodology 2 of this subpart to
determine the emission factor of a non-crude petroleum feedstock must
calculate the CO2 emissions associated with that feedstock
using Equation MM-10 in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.178
Where:
CO2j = Annual potential CO2 emissions from the
complete combustion or oxidation of non-crude feedstock ``j''
(metric tons).
Feedstockj = Total annual volume of non-crude feedstock
``j'' that enters the refinery as a feedstock to be further refined
or otherwise used on site (barrels). Any waste feedstock (see
definitions) that enters the refinery must also be included.
EFj = Feedstock-specific CO2 emission factor
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table
MM-3 of subpart MM that most closely represents the component of
product ``i'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that
is biomass-based.
(h) Refiners shall use the most appropriate default CO2
emission factor (EFm) for biomass in Table MM-3 to calculate
CO2 emissions in paragraph (c) of this section.
Sec. 98.394 Monitoring and QA/QC requirements.
(a) The quantity of petroleum products, natural gas liquids,
biomass, and all feedstocks shall be determined using either a flow
meter or tank gauge, depending on the reporters existing equipment and
preferences.
(1) For flow meters any one of the following test methods can be
used to determine quantity:
(i) Ultra-sonic flow meter: AGA Report No. 9 (2007)
(ii) Turbine meters: American National Standards Institute, ANSI/
ASME MFC-4M-1986
(iii) Orifice meters: American National Standards Institute, AINSI/
API 2530 (also called AGA-3) (1991)
(iv) Coriolis meters: ASME MFC-11 (2006)
(2) For tank gauges any one of the following test methods can be
used to determine quantity:
(i) API-2550: Measurements and Calibration of Petroleum Storage
Tanks (1965)
(ii) API MPMS 2.2: A Manual of Petroleum Measurement Standards
(1995)
(iii) API-653: Tank Inspection, Repair, Alteration and
Reconstruction, 3rd edition (2008)
(b) All flow meters and tank gauges shall be calibrated prior to
use for reporting, using a suitable method published by a consensus
standards organization (e.g., ASTM, ASME, API, or NAESB).
Alternatively, calibration procedures specified by the flow meter
manufacturer may be used. Product flow meters and tank gauges shall be
recalibrated either annually or at the minimum frequency specified by
the manufacturer, whichever is more frequent.
(c) For Calculation Methodology 2 of this subpart, samples of each
petroleum product and natural gas liquid shall be taken each month for
the reporting year. The composite sample shall be tested at the end of
the reporting year using ASTM D1298 (2003), ASTM D1657-02 (2007), ASTM
D4052-96 (2002)el, ASTM D5002-99 (2005), or ASTM D5004-89 (2004)el for
density, as appropriate, and ASTM D5291 (2005) or ASTM D6729-(2004)el
for carbon share, as appropriate (see Technical Support Document).
Reporters must sample seasonal gasoline each month of the season and
then test the composite sample at the end of the season.
Sec. 98.395 Procedures for estimating missing data.
Whenever a metered or quality-assured value of the quantity of
petroleum products, natural gas liquids, biomass, or feedstocks during
any period is unavailable, a substitute data value for the missing
quantity measurement shall be used in the calculations contained in
Sec. 98.393.
(a) For marine-imported and exported refined and semi-refined
products, the reporting party shall attempt to reconcile any
differences between ship and shore volume readings. If the reporting
party is unable to reconcile the readings, the higher of the two volume
values shall be used for emission calculation purposes.
(b) For pipeline imported and exported refined and semi-refined
products, the last valid volume reading based on the company's
established procedures for purposes of product tracking and billing
shall be used. If the pipeline experiences substantial variations in
flow rate, the average of the last valid volume reading and the next
valid volume reading shall be used for emission calculation purposes.
(c) For petroleum refineries, the last valid volume reading based
on the facility's established procedures for purposes of product
tracking and billing shall be used. If substantial variation in the
flow rate is observed, the average of the last and the next valid
volume reading shall be used for emission calculation purposes.
Sec. 98.396 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), the
following requirements apply.
(a) Refiners shall report the following information for each
facility:
(1) CO2 emissions in metric tons for each petroleum
product and natural gas liquid (ex refinery gate), calculated according
to Sec. 98.393(a) or (g).
(2) CO2 emissions in metric tons for each petroleum
product or natural gas liquid that enters the refinery annually as a
feedstock to be further refined or otherwise used on site, calculated
according to Sec. 98.393(b) or (g).
(3) CO2 emissions in metric tons from each type of
biomass feedstock co-processed with petroleum feedstocks, calculated
according to Sec. 98.393(c).
(4) The total sum of CO2 emissions from all products,
calculated according to Sec. 98.393(d).
(5) The total volume of each petroleum product and natural gas
liquid associated with the CO2 emissions reported in
paragraphs (a)(1)
[[Page 16718]]
and (2) of this section, seperately, and the volume of the biomass-
based component of each petroleum product reported in this paragraph
that was produced by blending a petroleum-based product with a biomass-
based product. If a determination cannot be made whether the material
is a petroleum product or a natural gas liquid, it shall be reported as
a petroleum product.
(6) The total volume of any biomass co-processed with a petroleum
product associated with the CO2 emissions reported in
paragraph (a)(3) of this section.
(7) The measured density and/or mass carbon share for any petroleum
product or natural gas liquid for which CO2 emissions were
calculated using Calculation Methodology 2 of this subpart, along with
the selected method from Sec. 98.394(c) and the calculated EF.
(8) The total volume of each distillate fuel oil product or
feedstock reported in paragraph (a)(5) of this section that contains
less than 15 ppm sulfur content and is free from marker solvent yellow
124 and dye solvent red 164.
(9) All of the following information for all crude oil feedstocks
used at the refinery:
(i) Batch volume (in standard barrels).
(ii) API gravity of the batch.
(iii) Sulfur content of the batch.
(iv) Country of origin of the batch.
(b) In addition to the information required by Sec. 98.3(c), each
importer shall report all of the following information at the corporate
level:
(1) CO2 emissions in metric tons for each imported
petroleum product and natural gas liquid, calculated according to Sec.
98.393(a).
(2) Total sum of CO2 emissions, calculated according to
Sec. 98.393(e).
(3) The total volume of each imported petroleum product and natural
gas liquid associated with the CO2 emissions reported in
paragraph (b)(1) of this section as well as the volume of the biomass-
based component of each petroleum product reported in this paragraph
that was produced by blending a petroleum-based product with a biomass-
based product. If you cannot determine whether the material is a
petroleum product or a natural gas liquid, you shall report it as a
petroleum product.
(4) The measured density and/or mass carbon share for any imported
petroleum product or natural gas liquid for which CO2
emissions were calculated using Calculation Methodology 2 of this
subpart, along with the selected method from Sec. 98.394(c) and the
calculated EF.
(5) The total volume of each distillate fuel oil product reported
in paragraph (b)(1) of this section that contains less than 15 ppm
sulfur content and is free from marker solvent yellow 124 and dye
solvent red 164.
(c) In addition to the information required by Sec. 98.3(c), each
exporter shall report all of the following information at the corporate
level:
(1) CO2 emissions in metric tons for each exported
petroleum product and natural gas liquid, calculated according to Sec.
98.393(a).
(2) Total sum of CO2 emissions, calculated according to
Sec. 98.393(e).
(3) The total volume of each exported petroleum product and natural
gas liquid associated with the CO2 emissions reported in
paragraph (c)(1) of this section as well as the volume of the biomass-
based component of each petroleum product reported in this paragraph
that was produced by blending a petroleum-based product with a biomass-
based product. If you cannot determine whether the material is a
petroleum product or a natural gas liquid, you shall report it as a
petroleum product.
(4) The measured density and/or mass carbon share for any petroleum
product or natural gas liquid for which CO2 emissions were
calculated using Calculation Methodology 2 of this subpart, along with
the selected method from Sec. 98.394(c) and the calculated EF.
(5) The total volume of each distillate fuel oil product reported
in paragraph (c)(1) of this section that contains less than 15 ppm
sulfur content and is free from marker solvent yellow 124 and dye
solvent red 164.
Sec. 98.397 Records that must be retained.
(a) Any reporter described in Sec. 98.391 shall retain copies of
all reports submitted to EPA under Sec. 98.396. In addition, any
reporter under this subpart shall maintain sufficient records to
support information contained in those reports, including but not
limited to information on the characteristics of their feedstocks and
products.
(b) Reporters shall maintain records to support volumes that are
reported under this part, including records documenting any estimations
of missing metered data. For all volumes of petroleum products, natural
gas liquids, biomass, and feedstocks, reporters shall maintain meter
and other records normally maintained in the course of business to
document product and feedstock flows.
(c) Reporters shall also retain laboratory reports, calculations
and worksheets used to estimate the CO2 emissions of the
volumes reported under this part.
(d) Estimates of missing data shall be documented and records
maintained showing the calculations.
(e) Reporters described in this subpart shall also retain all
records described in Sec. 98.3(g).
Sec. 98.398 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table MM-1 of Subpart MM--Default CO2 Factors for Petroleum Products 1, 2
----------------------------------------------------------------------------------------------------------------
Column C:
emission
Column A: factor
density Column B: (metric tons
Refined and semi-refined petroleum products (metric tons/ carbon share CO2/bbl)
bbl) (% of mass) [Column A *
Column B/100 *
44/12]
----------------------------------------------------------------------------------------------------------------
Motor Gasoline \3\
----------------------------------------------------------------------------------------------------------------
Conventional--Summer........................................ 0.12 86.96 0.38
Conventional--Winter........................................ 0.12 86.96 0.37
Reformulated--Summer........................................ 0.12 86.60 0.37
Reformulated--Winter........................................ 0.12 86.60 0.37
Finished Aviation Gasoline.................................. 0.11 85.00 0.35
----------------------------------------------------------------------------------------------------------------
[[Page 16719]]
Blendstocks
----------------------------------------------------------------------------------------------------------------
RBOB........................................................ 0.12 86.60 0.38
CBOB........................................................ 0.12 85.60 0.37
Others...................................................... 0.11 84.00 0.34
----------------------------------------------------------------------------------------------------------------
Oxygenates
----------------------------------------------------------------------------------------------------------------
Methanol.................................................... 0.13 37.50 0.17
GTBA........................................................ 0.12 64.90 0.29
t-butanol................................................... 0.12 64.90 0.29
MTBE........................................................ 0.12 68.20 0.29
ETBE........................................................ 0.12 70.50 0.30
TAME........................................................ 0.12 70.50 0.31
DIPE........................................................ 0.12 70.60 0.30
Kerosene-Type Jet Fuel...................................... 0.13 86.30 0.41
Naptha-Type Jet Fuel........................................ 0.12 85.80 0.39
Kerosene.................................................... 0.13 86.01 0.41
----------------------------------------------------------------------------------------------------------------
Distillate Fuel Oil
----------------------------------------------------------------------------------------------------------------
Diesel No. 1................................................ 0.13 86.40 0.43
Diesel No. 2................................................ 0.13 86.34 0.43
Diesel No. 4................................................ 0.15 86.47 0.46
Fuel Oil No. 1.............................................. 0.13 86.40 0.43
Fuel Oil No. 2.............................................. 0.13 86.34 0.43
Fuel Oil No. 4.............................................. 0.15 86.47 0.46
Residual Fuel Oil No. 5 (Navy Special)...................... 0.14 85.81 0.43
Residual Fuel Oil No. 6 (a.k.a. Bunker C)................... 0.16 85.68 0.49
----------------------------------------------------------------------------------------------------------------
Petrochemical Feedstocks
----------------------------------------------------------------------------------------------------------------
Naphthas (< 401 [deg]F).................................... 0.12 84.11 0.36
Other Oils (> 401 [deg]F)................................... 0.13 86.34 0.43
Special Naphthas............................................ 0.12 84.76 0.38
Lubricants.................................................. 0.14 85.80 0.45
Waxes....................................................... 0.13 85.29 0.40
Petroleum Coke.............................................. 0.07 92.28 0.23
Asphalt and Road Oil........................................ 0.16 83.47 0.50
Still Gas................................................... 0.07 24.40 0.06
Ethane...................................................... 0.06 80.00 0.17
Ethylene.................................................... 0.09 85.71 0.28
Propane..................................................... 0.08 81.80 0.24
Propylene................................................... 0.08 85.71 0.26
Butane...................................................... 0.09 82.80 0.28
Butylene.................................................... 0.11 85.71 0.35
Isobutane................................................... 0.09 82.80 0.27
Isobutylene................................................. 0.09 85.71 0.29
Pentanes Plus............................................... 0.11 83.70 0.32
Miscellaneous Products...................................... 0.14 85.49 0.43
Unfinished Oils............................................. 0.14 85.49 0.43
Naphthas.................................................... 0.12 85.70 0.37
Kerosenes................................................... 0.13 85.80 0.41
Heavy Gas Oils.............................................. 0.15 85.80 0.46
Residuum.................................................... 0.16 85.70 0.51
Waste Feedstocks............................................ 0.14 85.70 0.45
----------------------------------------------------------------------------------------------------------------
\1\ In the case of transportation fuels blended with some portion of biomass-based fuel, the carbon share in
Table MM-1 represents only the petroleum-based components.
\2\ Products that are derived entirely from biomass should not be reported, but products that were derived from
both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it
most closely represents.
[[Page 16720]]
Table MM-2 of Subpart MM--Default CO2 Factors for Natural Gas Liquids
----------------------------------------------------------------------------------------------------------------
Column C:
computed
emission
Column A: Column B: factor
Natural gas liquids density carbon share (tonnes CO2/
tonnes/barrel (% of mass) bbl) [Column
A * Column B/
100 * 44/12]
----------------------------------------------------------------------------------------------------------------
C2+............................................................. 0.08 81.79 0.24
C4+............................................................. 0.10 83.15 0.30
C5+............................................................. 0.11 83.70 0.32
C6+............................................................. 0.11 84.04 0.34
----------------------------------------------------------------------------------------------------------------
Table MM-3 of Subpart MM--Default CO2 Factors for Biomass-based Fuel and
Biomass Feedstock
------------------------------------------------------------------------
Column A:
emission
Biomass products and feedstock factor
(tonnes CO2/
bbl)
------------------------------------------------------------------------
Ethanol (100%).......................................... 0.23
Biodiesel (100%, methyl ester).......................... 0.40
Rendered Animal Fat..................................... 0.37
Vegetable Oil........................................... 0.41
------------------------------------------------------------------------
Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
Sec. 98.400 Definition of the source category.
This supplier category consists of natural gas processing plants
and local natural gas distribution companies.
(a) Natural Gas Processing Plants are installations designed to
separate and recover natural gas liquids (NGLs) or other gases and
liquids from a stream of produced natural gas through the processes of
condensation, absorption, adsorption, refrigeration, or other methods
and to control the quality of natural gas marketed. This does not
include field gathering and boosting stations.
(b) Local Distribution Companies are companies that own or operate
distribution pipelines, not interstate pipelines or intrastate
pipelines, that physically deliver natural gas to end users and that
are regulated as separate operating companies by State public utility
commissions or that operate as independent municipally-owned
distribution systems.
Sec. 98.401 Reporting threshold.
Any supplier of natural gas and natural gas liquids that meets the
requirements of Sec. 98.2(a)(4) must report GHG emissions.
Sec. 98.402 GHGs to report.
(a) Natural gas processing plants must report the CO2
emissions that would result from the complete combustion or oxidation
of the annual quantity of propane, butane, ethane, isobutane and bulk
NGLs sold or delivered for use off site.
(b) Local distribution companies must report the CO2
emissions that would result from the complete combustion or oxidation
of the annual volumes of natural gas provided to end-users.
Sec. 98.403 Calculating GHG emissions.
(a) For each type of fuel or product reported under this part,
calculate the estimated CO2 equivalent emissions using
either of Calculation Methodology 1 or 2 of this subpart:
(1) Calculation Methodology 1. Estimate CO2 emissions
using Equation NN-1. For Equation NN-1, use the default values for
higher heating values and CO2 emission factors in Table NN-1
to this subpart. Alternatively, reporter-specific higher heating values
and CO2 emission factors may be used, provided they are
developed using methods outlined in Sec. 98.404. For Equation NN-2 of
this section, use the default values for the CO2 emission
factors found in Table NN-2 of this subpart. Alternatively, reporter-
specific CO2 emission factors may be used, provided they are
developed using methods outlined in Sec. 98.404.
[GRAPHIC] [TIFF OMITTED] TP10AP09.179
Where:
CO2 = Annual potential CO2 mass emissions from
the combustion of fuel (metric tons).
Fuel = Total annual volume of fuel or product (volume per year,
typically in Mcf for gaseous fuels and bbl for liquid fuels).
HHV = Higher heat value of the fuel supplied (MMBtu/Mcf or MMBtu/
bbl).
EF = Fuel-specific CO2 emission factor (kg
CO2/MMBtu).
1 x 10-3 = Conversion factor from kilograms to metric
tons (MT/kg).
(2) Calculation Methodology 2. Estimate CO2 emissions
using Equation NN-2.
[GRAPHIC] [TIFF OMITTED] TP10AP09.180
Where:
CO2 = Annual CO2 mass emissions from the
combustion of fuel supplied (metric tons)
Fuel = Total annual volume of fuel or product supplied (bbl or Mcf
per year)
EF = Fuel-specific CO2 emission factor (MT
CO2/bbl, or MT CO2/Mcf)
Sec. 98.404 Monitoring and QA/QC requirements.
(a) The quantity of natural gas liquids and natural gas must be
determined
[[Page 16721]]
using any of the oil and gas flow meter test methods that are in common
use in the industry and consistent with the Gas Processors Association
Technical Manual and the American Gas Association Gas Measurement
Committee reports.
(b) The minimum frequency of the measurements of quantities of
natural gas liquids and natural gas shall be based on the industry
standard practices for commercial operations. For natural gas liquids
these are measurements taken at custody transfers summed to the annual
reportable volume. For natural gas these are daily totals of continuous
measurements, and summed to the annual reportable volume.
(c) All flow meters and product or fuel composition monitors shall
be calibrated prior to the first reporting year, using a suitable
method published by the American Gas Association Gas Measurement
Committee reports on flow metering and heating value calculations and
the Gas Processors Association standards on measurement and heating
value. Alternatively, calibration procedures specified by the flow
meter manufacturer may be used. Fuel flow meters shall be recalibrated
either annually or at the minimum frequency specified by the
manufacturer.
(d) Reporter-specific emission factors or higher heating values
shall be determined using industry standard practices such as the
American Gas Association (AGA) Gas Measurement Committee Report on
heating value and the Gas Processors Association (GPA) Technical
Standards Manual for NGL heating value; and ASTM D-2597-94 and ASTM D-
1945-03 for compositional analysis necessary for estimating
CO2 emission factors.
Sec. 98.405 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the
reporting of fuel volumes and in the calculations of CO2
mass emissions is required. Therefore, whenever a quality-assured value
of the quantity of natural gas liquids or natural gas during any period
is unavailable (e.g., if a flow meter malfunctions), a substitute data
value for the missing quantity measurement must be used in the
calculations according to paragraphs (b) and (c) of this section.
(b) For NGLs, natural gas processing plants shall substitute meter
records provided by pipeline(s) for all pipeline receipts of NGLs; by
manifests for deliveries made to trucks or rail cars; or metered
quantities accepted by the entities purchasing the output from the
processing plant whether by pipeline or by truck or rail car. In cases
where the metered data from the receiving pipeline(s) or purchasing
entities are not available, natural gas processors may substitute
estimates based on contract quantities required to be delivered under
purchase or delivery contracts with other parties.
(c) Natural gas local distribution companies may substitute the
metered quantities from the delivering pipelines for all deliveries
into the distribution system. In cases where the pipeline metered
delivery data are not available, local distribution companies may
substitute their pipeline nominations and scheduled quantities for the
period when metered values of actual deliveries are not available.
(d) Estimates of missing data shall be documented and records
maintained showing the calculations of the values used for the missing
data.
Sec. 98.406 Data reporting requirements.
(a) In addition to the information required by Sec. 98.3(c), the
annual report for each natural gas processing plant must contain the
following information.
(1) The total annual quantity in barrels of NGLs produced for sale
or delivery on behalf of others in the following categories: Propane,
natural butane, ethane, and isobutane, and all other bulk NGLs as a
single category.
(2) The total annual CO2 mass emissions associated with
the volumes in paragraph (a)(1) of this section and calculated in
accordance with Sec. 98.403.
(b) In addition to the information required by Sec. 98.3(c), the
annual report for each local distribution company must contain the
following information.
(1) The total annual volume in Mcf of natural gas received by the
local distribution company for redelivery to end users on the local
distribution company's distribution system.
(2) The total annual CO2 mass emissions associated with
the volumes in paragraph (b)(1) of this section and calculated in
accordance with Sec. 98.403.
(3) The total natural gas volumes received for redelivery to
downstream gas transmission pipelines and other local distribution
companies.
(4) The name and EPA and EIA identification code of each individual
covered facility, and the name and EIA identification code of any other
end-user for which the local gas distribution company delivered greater
than or equal to 460,000 Mcf during the calendar year, and the total
natural gas volumes actually delivered to each of these end-users.
(5) The annual volume in Mcf of natural gas delivered by the local
distribution company to each of the following end-use categories. For
definitions of these categories, refer to EIA Form 176 and
Instructions.
(i) Residential consumers.
(ii) Commercial consumers.
(iii) Industrial consumers.
(iv) Electricity generating facilities.
(6) The total annual CO2 mass emissions associated with
the volumes in paragraph (b)(5) of this section and calculated in
accordance with Sec. 98.403.
Sec. 98.407 Records that must be retained.
In addition to the information required by Sec. 98.3(g), each
annual report must contain the following information:
(a) Records of all daily meter readings and documentation to
support volumes of natural gas and NGLs that are reported under this
part.
(b) Records documenting any estimates of missing metered data.
(c) Calculations and worksheets used to estimate CO2
emissions for the volumes reported under this part.
(d) Records related to the large end-users identified in Sec.
98.406(b)(4).
(e) Records relating to measured Btu content or carbon content.
Sec. 98.408 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Table NN-1 of Subpart NN--Default Factors for Calculation Methodology 1
of this Subpart
------------------------------------------------------------------------
Default CO2
Default high heating emission
Fuel value factor factor (kg
CO2/MMBtu)
------------------------------------------------------------------------
Natural Gas........................ 1.027 MMBtu/Mcf....... 53.02
Propane............................ 3.836 MMBtu/bbl....... 63.02
Butane............................. 4.326 MMBtu/bbl....... 64.93
[[Page 16722]]
Ethane............................. 3.082 MMBtu/bbl....... 59.58
Isobutane.......................... 3.974 MMBtu/bbl....... 65.08
Natural Gas Liquids................ 4.140 MMBtu/bbl....... 63.20
------------------------------------------------------------------------
Table NN-2 of Subpart NN--Lookup Default Values for Calculation
Methodology 2 of this Subpart
------------------------------------------------------------------------
Default CO2
emission
Fuel Unit value (MT
CO2/Unit)
------------------------------------------------------------------------
Natural Gas........................ Mcf................... 0.054452
Propane............................ Barrel................ 0.241745
Butane............................. Barrel................ 0.280887
Ethane............................. Barrel................ 0.183626
Isobutane.......................... Barrel................ 0.258628
Natural Gas Liquids................ Barrel................ 0.261648
------------------------------------------------------------------------
Subpart OO--Suppliers of Industrial Greenhouse Gases
Sec. 98.410 Definition of the source category.
(a) The industrial gas supplier source category consists of any
facility that produces a fluorinated GHG or nitrous oxide, any bulk
importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of
fluorinated GHGs or nitrous oxide.
(b) To produce a fluorinated GHG means to manufacture a fluorinated
GHG from any raw material or feedstock chemical. Producing a
fluorinated GHGs does not include the reuse or recycling of a
fluorinated GHG or the generation of HFC-23 during the production of
HCFC-22.
(c) To produce nitrous oxide means to produce nitrous oxide by
thermally decomposing ammonium nitrate (NH4NO3).
Producing nitrous oxide does not include the reuse or recycling of
nitrous oxide or the creation of by-products that are released or
destroyed at the production facility.
Sec. 98.411 Reporting threshold.
Any supplier of industrial greenhouse gases who meets the
requirements of Sec. 98.2(a)(4) must report GHG emissions.
Sec. 98.412 GHGs to report.
You must report the GHG emissions that would result from the
release of the nitrous oxide and each fluorinated GHG that you produce,
import, export, transform, or destroy during the calendar year.
Sec. 98.413 Calculating GHG emissions.
(a) The total mass of each fluorinated GHG or nitrous oxide
produced annually shall be estimated by using Equation OO-1 of this
section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.181
Where:
P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp = Mass of fluorinated GHG or nitrous oxide produced
over the period ``p''.
(b) The total mass of each fluorinated GHG or nitrous oxide
produced over the period ``p'' shall be estimated by using Equation OO-
2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.182
Where:
Pp = Mass of fluorinated GHG or nitrous oxide produced
over the period ``p'' (metric tons).
Op = Mass of fluorinated GHG or nitrous oxide that is
measured coming out of the production process over the period p
(metric tons).
Up = Mass of used fluorinated GHG or nitrous oxide that
is added to the production process upstream of the output
measurement over the period ``p'' (metric tons).
(c) The total mass of each fluorinated GHG or nitrous oxide
transformed shall be estimated by using Equation OO-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.183
Where:
T = Mass of fluorinated GHG or nitrous oxide transformed annually
(metric tons).
FT = Mass of fluorinated GHG fed into the transformation
process annually (metric tons).
R = Mass of residual, unreacted fluorinated GHG or nitrous oxide
that is permanently removed from the transformation process (metric
tons).
(d) The total mass of each fluorinated GHG destroyed shall be
estimated by using Equation OO-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.184
Where:
D = Mass of fluorinated GHG destroyed annually (metric tons).
FD = Mass of fluorinated GHG fed into the destruction
device annually (metric tons).
DE = Destruction efficiency of the destruction device (fraction).
Sec. 98.414 Monitoring and QA/QC requirements.
(a) The mass of fluorinated GHGs or nitrous oxide coming out of the
production process shall be measured at least daily using flowmeters,
weigh scales, or a combination of volumetric and density measurements
with an accuracy and precision of 0.2 percent of full scale or better.
(b) The mass of any used fluorinated GHGs or used nitrous oxide
added back into the production process upstream of the output
measurement in paragraph (a) of this section shall be measured at least
daily (when being added) using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 0.2 percent of full scale or better.
(c) The mass of fluorinated GHGs or nitrous oxide fed into
transformation processes shall be measured at least daily using
flowmeters, weigh scales, or a combination of volumetric and density
[[Page 16723]]
measurements with an accuracy and precision of 0.2 percent of full
scale or better.
(d) If unreacted fluorinated GHGs or nitrous oxide are permanently
removed (recovered, destroyed, or emitted) from the transformation
process, the mass removed shall be measured using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of 0.2 percent of full scale or better. If the
measured mass includes more than trace concentrations of materials
other than the unreacted fluorinated GHG or nitrous oxide, the
concentration of the unreacted fluorinated GHG or nitrous oxide shall
be measured at least daily using equipment and methods (e.g., gas
chromatography) with an accuracy and precision of 5 percent or better
at the concentrations of the process samples. This concentration (mass
fraction) shall be multiplied by the mass measurement to obtain the
mass of the fluorinated GHG or nitrous oxide permanently removed from
the transformation process.
(e) The mass of fluorinated GHG or nitrous oxide sent to another
facility for transformation shall be measured at least daily using
flowmeters, weigh scales, or a combination of volumetric and density
measurements with an accuracy and precision of 0.2 percent of full
scale or better.
(f) The mass of fluorinated GHG sent to another facility for
destruction shall be measured at least daily using flowmeters, weigh
scales, or a combination of volumetric and density measurements with an
accuracy and precision of 0.2 percent of full scale or better. If the
measured mass includes more than trace concentrations of materials
other than the fluorinated GHG, the concentration of the fluorinated
GHG shall be measured at least daily using equipment and methods (e.g.,
gas chromatography) with an accuracy and precision of 5 percent or
better at the concentrations of the process samples. This concentration
(mass fraction) shall be multiplied by the mass measurement to obtain
the mass of the fluorinated GHG sent to another facility for
destruction.
(g) The mass of fluorinated GHGs fed into the destruction device
shall be measured at least daily using flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of 0.2 percent of full scale or better. If the measured mass
includes more than trace concentrations of materials other than the
fluorinated GHG being destroyed, the concentrations of fluorinated GHG
being destroyed shall be measured at least daily using equipment and
methods (e.g., gas chromatography) with an accuracy and precision of 5
percent or better at the concentrations of the process samples. This
concentration (mass fraction) shall be multiplied by the mass
measurement to obtain the mass of the fluorinated GHG destroyed.
(h) For purposes of Equation OO-4, the destruction efficiency can
initially be equated to the destruction efficiency determined during a
previous performance test of the destruction device or, if no
performance test has been done, the destruction efficiency provided by
the manufacturer of the destruction device. Fluorinated GHG production
facilities that destroy fluorinated GHGs shall conduct annual
measurements of mass flow and fluorinated GHG concentrations at the
outlet of the thermal oxidizer in accordance with EPA Method 18 at 40
CFR part 60, appendix A-6. Tests shall be conducted under conditions
that are typical for the production process and destruction device at
the facility. The sensitivity of the emissions tests shall be
sufficient to detect emissions equal to 0.01 percent of the mass of
fluorinated GHGs being fed into the destruction device. If the test
indicates that the actual DE of the destruction device is lower than
the previously determined DE, facilities shall either:
(1) Substitute the DE implied by the most recent emissions test for
the previously determined DE in the calculations in Sec. 98.413, or
(2) Perform more extensive performance testing of the DE of the
oxidizer and use the DE determined by the more extensive testing in the
calculations in Sec. 98.413.
(i) In their estimates of the mass of fluorinated GHGs destroyed,
designated representatives of fluorinated GHG production facilities
that destroy fluorinated GHGs shall account for any temporary
reductions in the destruction efficiency that result from any startups,
shutdowns, or malfunctions of the destruction device, including
departures from the operating conditions defined in state or local
permitting requirements and/or oxidizer manufacturer specifications.
(j) All flowmeters, weigh scales, and combinations of volumetric
and density measurements that are used to measure or calculate
quantities that are to be reported under this subpart shall be
calibrated using suitable NIST-traceable standards and suitable methods
published by a consensus standards organization (e.g., ASTM, ASME,
ASHRAE, or others). Alternatively, calibration procedures specified by
the flowmeter, scale, or load cell manufacturer may be used.
Calibration shall be performed prior to the first reporting year. After
the initial calibration, recalibration shall be performed at least
annually or at the minimum frequency specified by the manufacturer,
whichever is more frequent.
(k) All gas chromatographs that are used to measure or calculate
quantities that are to be reported under this subpart shall be
calibrated at least monthly through analysis of certified standards
with known concentrations of the same chemical(s) in the same range(s)
(fractions by mass) as the process samples. Calibration gases prepared
from a high-concentration certified standard using a gas dilution
system that meets the requirements specified in Test Method 205, 40 CFR
Part 51, Appendix M may also be used.
Sec. 98.415 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter
malfunctions), a substitute data value for the missing parameter shall
be used in the calculations, according to the following requirements:
(1) For each missing value of the mass produced, fed into the
production process (for used material being reclaimed), fed into
transformation processes, fed into destruction devices, sent to another
facility for transformation, or sent to another facility for
destruction, the substitute value of that parameter shall be a
secondary mass measurement. For example, if the mass produced is
usually measured with a flowmeter at the inlet to the day tank and that
flowmeter fails to meet an accuracy or precision test, malfunctions, or
is rendered inoperable, then the mass produced may be estimated by
calculating the change in volume in the day tank and multiplying it by
the density of the product.
(2) For each missing value of fluorinated GHG concentration, except
the annual destruction device outlet concentration measurement
specified in Sec. 98.414(h), the substitute data value shall be the
arithmetic average of the quality-assured values of that parameter
immediately preceding and immediately following the missing data
incident. If, for a particular parameter, no quality-assured data are
available prior to the missing data incident, the substitute data value
shall be the first quality-
[[Page 16724]]
assured value obtained after the missing data period. There are no
missing value allowances for the annual destruction device outlet
concentration measurement. A re-test must be performed if the data from
the annual destruction device outlet concentration measurement are
determined to be unacceptable or not representative of typical
operations.
(3) Notwithstanding paragraphs (a)(1) and (2) of this section, if
the owner or operator has reason to believe that the methods specified
in paragraphs (a)(1) and (2) of this section are likely to
significantly under- or overestimate the value of the parameter during
the period when data were missing, the designated representative of the
fluorinated GHG production facility shall develop his or her best
estimate of the parameter, documenting the methods used, the rationale
behind them, and the reasons why the methods specified in paragraphs
(a)(1) and (2) of this section would probably lead to a significant
under- or overestimate of the parameter. EPA may reject the alternative
estimate and replace it with an estimate based on the applicable method
in paragraph (a)(1) or (2) if EPA does not agree with the rationale or
method for the alternative estimate.
Sec. 98.416 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information:
(a) Each fluorinated GHG or nitrous oxide production facility shall
report the following information at the facility level:
(1) Total mass in metric tons of each fluorinated GHG or nitrous
oxide produced at that facility.
(2) Total mass in metric tons of each fluorinated GHG or nitrous
oxide transformed at that facility.
(3) Total mass in metric tons of each fluorinated GHG destroyed at
that facility.
(4) Total mass in metric tons of any fluorinated GHG or nitrous
oxide sent to another facility for transformation.
(5) Total mass in metric tons of any fluorinated GHG sent to
another facility for destruction.
(6) Total mass in metric tons of each reactant fed into the
production process.
(7) Total mass in metric tons of each non-GHG reactant and by-
product permanently removed from the process.
(8) Mass of used product added back into the production process
(e.g., for reclamation).
(9) Names and addresses of facilities to which any nitrous oxide or
fluorinated GHGs were sent for transformation, and the quantities
(metric tons) of nitrous oxide and of each fluorinated GHG that were
sent to each for transformation.
(10) Names and addresses of facilities to which any fluorinated
GHGs were sent for destruction, and the quantities (metric tons) of
nitrous oxide and of each fluorinated GHG that were sent to each for
destruction.
(11) Where missing data have been estimated pursuant to Sec.
98.415, the reason the data were missing, the length of time the data
were missing, the method used to estimate the missing data, and the
estimates of those data. Where the missing data have been estimated
pursuant to Sec. 98.415(a)(3), the report shall explain the rationale
for the methods used to estimate the missing data and why the methods
specified in Sec. 98.415(a)(1) and (2) would lead to a significant
under- or overestimate of the parameters.
(b) A fluorinated GHG production facility that destroys fluorinated
GHGs shall report the results of the annual fluorinated GHG
concentration measurements at the outlet of the destruction device,
including:
(1) Flow rate of fluorinated GHG being fed into the destruction
device in kg/hr.
(2) Concentration (mass fraction) of fluorinated GHG at the outlet
of the destruction device.
(3) Flow rate at the outlet of the destruction device in kg/hr.
(4) Emission rate calculated from (b)(2) and (b)(3) in kg/hr.
(c) A fluorinated GHG production facility that destroys fluorinated
GHGs shall submit a one-time report containing the following
information:
(1) Destruction efficiency (DE) of each destruction unit.
(2) Test methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the
performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may
apply to the destruction process.
(6) If any process changes affect unit destruction efficiency or
the methods used to record mass of fluorinated GHG destroyed, then a
revised report must be submitted to reflect the changes. The revised
report must be submitted to EPA within 60 days of the change.
(d) A bulk importer of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes their imports at the corporate
level, except for transshipments and heels. The report shall contain
the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated
GHG imported in bulk.
(2) Total mass in metric tons of nitrous oxide and each fluorinated
GHG imported in bulk and sold or transferred to persons other than the
importer for use in processes resulting in the transformation or
destruction of the chemical.
(3) Date on which the fluorinated GHGs or nitrous oxide were
imported.
(4) Port of entry through which the fluorinated GHGs or nitrous
oxide passed.
(5) Country from which the imported fluorinated GHGs or nitrous
oxide were imported.
(6) Commodity code of the fluorinated GHGs or nitrous oxide
shipped.
(7) Importer number for the shipment.
(8) If applicable, the names and addresses of the persons and
facilities to which the nitrous oxide or fluorinated GHGs were sold or
transferred for transformation, and the quantities (metric tons) of
nitrous oxide and of each fluorinated GHG that were sold or transferred
to each facility for transformation.
(9) If applicable, the names and addresses of the persons and
facilities to which the nitrous oxide or fluorinated GHGs were sold or
transferred for destruction, and the quantities (metric tons) of
nitrous oxide and of each fluorinated GHG that were sold or transferred
to each facility for destruction.
(e) A bulk exporter of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes their exports at the corporate
level, except for transshipments and heels. The report shall contain
the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated
GHG exported in bulk.
(2) Names and addresses of the exporter and the recipient of the
exports.
(3) Exporter's Employee Identification Number.
(4) Quantity exported by chemical in metric tons of chemical.
(5) Commodity code of the fluorinated GHGs and nitrous oxide
shipped.
(6) Date on which, and the port from which, fluorinated GHGs and
nitrous oxide were exported from the United States or its territories.
(7) Country to which the fluorinated GHGs or nitrous oxide were
exported.
Sec. 98.417 Records that must be retained.
(a) In addition to the data required by Sec. 98.3(g), the
designated representative of a fluorinated GHG production facility
shall retain the following records:
[[Page 16725]]
(1) Dated records of the data used to estimate the data reported
under Sec. 98.416, and
(2) Records documenting the initial and periodic calibration of the
gas chromatographs, weigh scales, flowmeters, and volumetric and
density measures used to measure the quantities reported under this
subpart, including the industry standards or manufacturer directions
used for calibration pursuant to Sec. 98.414(j) and (k).
(b) In addition to the data required by paragraph (a) of this
section, the designated representative of a fluorinated GHG production
facility that destroys fluorinated GHGs shall keep records of test
reports and other information documenting the facility's one-time
destruction efficiency report and annual destruction device outlet
reports in Sec. 98.416(b) and (c).
(c) In addition to the data required by Sec. 98.3(g), the
designated representative of a bulk importer shall retain the following
records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by Sec. 98.3(g), the
designated representative of a bulk exporter shall retain the following
records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the import.
(e) Every person who imports a container with a heel shall keep
records of the amount brought into the United States that document that
the residual amount in each shipment is less than 10 percent of the
volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
Sec. 98.418 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
Subpart PP--Suppliers of Carbon Dioxide
Sec. 98.420 Definition of the source category.
(a) The carbon dioxide (CO2) supplier source category consists of
the following:
(1) Production process units that capture a CO2 stream for purposes
of supplying CO2 for commercial applications. Capture refers to the
separation and removal of CO2 from a manufacturing process; fuel
combustion source; or a waste, wastewater, or water treatment process.
(2) Facilities with CO2 production wells.
(3) Importers or exporters of bulk CO2.
(b) This source category does not include the following:
(1) Geologic sequestration (long term storage) of CO2.
(2) Injection and subsequent production and/or processing of
CO2 for enhanced oil and gas recovery.
(3) Above ground storage of CO2.
(4) Transportation or distribution of CO2 via pipelines,
vessels, motor carriers, or other means.
(5) Purification, compression, or processing of CO2.
(6) CO2 imported or exported in equipment.
Sec. 98.421 Reporting threshold.
Any supplier of CO2 who meets the requirements of Sec.
98.2(a)(4) must report GHG emissions.
Sec. 98.422 GHGs to report.
You must report the mass of carbon dioxide captured from production
process units, the mass of carbon dioxide extracted from carbon dioxide
production wells, and the mass of carbon dioxide imported and exported
regardless of the degree of impurities in the carbon dioxide stream.
Sec. 98.423 Calculating GHG emissions.
(a) Facilities with production process units must calculate
quarterly the total mass of carbon dioxide in a carbon dioxide stream
in metric tons captured, prior to any subsequent purification,
processing, or compressing, based on multiplying the mass flow by the
composition data, according to Equation PP-1 of this section. Mass flow
and composition data measurements are made in accordance with Sec.
98.424.
[GRAPHIC] [TIFF OMITTED] TP10AP09.185
Where:
CO2 = CO2 mass emission (metric tons per
year).
CCO2 = Quarterly average CO2 concentration in
flow (wt. % CO2).
Q = Quarterly mass flow rate (metric tons per quarter).
(b) CO2 production well facilities must calculate
quarterly the total mass of carbon dioxide in a carbon dioxide stream
from wells in metric tons, prior to any subsequent purification,
processing, or compressing, based on multiplying the mass flow by the
composition data, according to Equation PP-1. Mass flow and composition
data measurements are made in accordance with Sec. 98.424.
(c) Importers or exporters of a carbon dioxide stream must
calculate quarterly the total mass of carbon dioxide imported or
exported in metric tons, based on multiplying the mass flow by the
composition data, according to Equation PP-1. Mass flow and composition
data measurements are made in accordance with Sec. 98.424. The
quantities of CO2 imported or exported in equipment, such as
fire extinguishers, need not be calculated or reported.
Sec. 98.424 Monitoring and QA/QC requirements.
(a) Facilities with production process units that capture a carbon
dioxide stream must measure on a quarterly basis using a mass flow
meter the mass flow of the CO2 stream captured. If
production process units do not have mass flow meters installed to
measure the mass flow of the CO2 stream captured,
measurements shall be based on the mass flow of gas transferred off
site using a mass flow meter. In either case, sampling also must be
conducted on at least a quarterly basis to determine the composition of
the captured or transferred CO2 stream.
(b) Carbon dioxide production well facilities must measure on a
quarterly basis the mass flow of the CO2 stream extracted
using a mass flow meter. If the CO2 production wells do not
have mass flow meters installed to measure the mass flow of the
CO2 stream extracted, measurements shall be based on mass
flow of gas transferred off site using a mass flow meter. In either
case, sampling must be conducted on at least a quarterly basis to
determine the composition of the extracted or transferred carbon
dioxide.
(c) Importers or exporters of bulk CO2 must measure on a
quarterly basis the mass flow of the CO2 stream imported or
exported using a mass flow meter and must conduct sampling on at least
a quarterly basis to determine the composition of the imported or
exported CO2 stream. If the importer of a CO2
stream does not have mass flow meters installed to measure the mass
flow of gas imported, the measurements shall be based on the mass flow
of the imported CO2 stream transferred off site or used in
on-site processes, as measured by mass flow meters. If an exporter of a
CO2 stream does not have mass flow meters installed to
measure the mass flow exported, the measurements shall be based on the
mass flow of the CO2 stream received for export, as measured
by mass flow meters. In all cases, sampling on at least a quarterly
basis also must be conducted to determine the composition of the
CO2 stream.
[[Page 16726]]
(d) Mass flow meter calibrations must be NIST traceable.
(e) Methods to measure the composition of the carbon dioxide
captured, extracted, transferred, imported, or exported must conform to
applicable chemical analytical standards. Acceptable methods include
U.S. Food and Drug Administration food-grade specifications for carbon
dioxide (see 21 CFR 184.1250) and ASTM standard E-1745-95 (2005).
Sec. 98.425 Procedures for estimating missing data.
(a) Missing quarterly monitoring data on mass flow of
CO2 streams captured, extracted, imported, or exported shall
be substituted with the greater of the following values:
(1) Quarterly CO2 mass flow of gas transferred off site
measured during the current reporting year.
(2) Quarterly or annual average values of the monitored
CO2 mass flow from the past calendar year.
(b) Missing monitoring data on the mass flow of the CO2
stream transferred off site shall be substituted with the quarterly or
annual average values from off site transfers from the past calendar
year.
(c) Missing data on composition of the CO2 stream
captured, extracted, transferred, imported, or exported may be
substituted for with quarterly or annual average values from the past
calendar year.
Sec. 98.426 Data reporting requirements.
In addition to the information required by Sec. 98.3(c), each
annual report must contain the following information.
(a) Each facility with production process units or CO2
production wells must report the following information:
(1) Total annual mass in metric tons and the weighted average
composition of the CO2 stream captured, extracted, or
transferred in either gas, liquid, or solid forms.
(2) Annual quantities in metric tons transferred to the following
end use applications by end-use, if known:
(i) Food and beverage.
(ii) Industrial and municipal water/wastewater treatment.
(iii) Metal fabrication, including welding and cutting.
(iv) Greenhouse uses for plant growth.
(v) Fumigants (e.g., grain storage) and herbicides.
(vi) Pulp and paper.
(vii) Cleaning and solvent use.
(viii) Fire fighting.
(ix) Transportation and storage of explosives.
(x) Enhanced oil and natural gas recovery.
(xi) Long-term storage (sequestration).
(xii) Research and development.
(b) CO2 importers and exporters must report the
information in paragraphs (a)(1) and (a)(2) at the corporate level.
Sec. 98.427 Records that must be retained.
In addition to the records required by Sec. 98.3(g), you must
retain the records specified in paragraphs (a) through (c) of this
section.
(a) The owner or operator of a facility containing production
process units must retain quarterly records of captured and transferred
CO2 streams and composition.
(b) The owner or operator of a carbon dioxide production well
facility must maintain quarterly records of the mass flow of the
extracted and transferred CO2 stream and composition.
(c) Importers or exporters of CO2 must retain quarterly
records of the mass flow and composition of CO2 streams
imported or exported.
Sec. 98.428 Definitions.
All terms used in this subpart have the same meaning given in the
Clean Air Act and subpart A of this part.
PART 600--[AMENDED]
27. The authority citation for part 600 continues to read as
follows:
Authority: 49 U.S.C. 32901-23919q, Pub. L. 109-58.
Subpart A--[Amended]
28. Section 600.006-08 is amended by revising paragraph (c)
introductory text and adding paragraph (c)(5) to read as follows:
Sec. 600.006-08 Data and information requirements for fuel economy
vehicles.
* * * * *
(c) The manufacturer shall submit the following data:
* * * * *
(5) Starting with the 2011 model year, the data submitted according
to paragraphs (c)(1) through (c)(4) of this section shall include
CO2, N2O, and CH4 in addition to fuel
economy. Use the procedures specified in 40 CFR part 1065 as needed to
measure N2O and CH4. Round the test results as
follows:
(i) Round CO2 to the nearest 1 g/mi.
(ii) Round N2O to the nearest 0.001 g/mi.
(iii) Round CH4 to the nearest 0.001g/mi.
* * * * *
PART 1033--[AMENDED]
29. The authority citation for part 1033 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
30. Section 1033.205 is amended by revising paragraph (d)(8) to
read as follows:
Sec. 1033.205 Applying for a certificate of conformity.
* * * * *
(d) * * *
(8)(i) All test data you obtained for each test engine or
locomotive. As described in Sec. 1033.235, we may allow you to
demonstrate compliance based on results from previous emission tests,
development tests, or other testing information. Include data for
NOX, PM, HC, CO, and CO2.
(ii) Starting in the 2011 model year, report measured
N2O and CH4 as described in Sec. 1033.235. Small
manufacturers/remanufacturers may omit this requirement.
* * * * *
31. Section 1033.235 is amended by adding paragraph (i) to read as
follows:
Sec. 1033.235 Emission testing required for certification.
* * * * *
(i) Starting in the 2011 model year, measure N2O, and
CH4 with each low-hour certification test using the
procedures specified in 40 CFR part 1065. Small manufacturers/
remanufacturers may omit this requirement. Use the same units and modal
calculations as for your other results to report a single weighted
value for CO2, N2O, and CH4. Round the
final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001g/kW-hr.
Subpart J--[Amended]
32. Section 1033.905 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 1033.905 Symbols, acronyms, and abbreviations.
* * * * *
* * * * * * *
CH4 methane.
* * * * * * *
N2O nitrous oxide.
* * * * * * *
PART 1039--[AMENDED]
33. The authority citation for part 1039 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
[[Page 16727]]
Subpart C--[Amended]
34. Section 1039.205 is amended by revising paragraph (r) to read
as follows:
Sec. 1039.205 What must I include in my application?
* * * * *
(r) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured CO2
, N2O, and CH4 as described in Sec. 1039.235.
Small-volume engine manufacturers may omit this requirement.
* * * * *
35. Section 1039.235 is amended by adding paragraph (g) to read as
follows:
Sec. 1039.235 What emission testing must I perform for my application
for a certificate of conformity?
* * * * *
(g) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each low-hour certification
test using the procedures specified in 40 CFR part 1065. Small-volume
engine manufacturers may omit this requirement. These measurements are
not required for NTE testing. Use the same units and modal calculations
as for your other results to report a single weighted value for each
constituent. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001g/kW-hr.
Subpart I--[Amended]
36. Section 1039.805 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 1039.805 What symbols, acronyms, and abbreviations does this
part use?
* * * * *
* * * * * * *
CH4 methane.
* * * * * * *
N2O nitrous oxide.
* * * * * * *
PART 1042--[AMENDED]
37. The authority citation for part 1042 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
38. Section 1042.205 is amended by revising paragraph (r) to read
as follows:
Sec. 1042.205 Application requirements.
* * * * *
(r) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured
CO2, N2O, and CH4 as described in
Sec. 1042.235. Small-volume engine manufacturers may omit this
requirement.
* * * * *
39. Section 1042.235 is amended by adding paragraph (g) to read as
follows:
Sec. 1042.235 Emission testing required for a certificate of
conformity.
* * * * *
(g) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each low-hour certification
test using the procedures specified in 40 CFR part 1065. Small-volume
engine manufacturers may omit this requirement. These measurements are
not required for NTE testing. Use the same units and modal calculations
as for your other results to report a single weighted value for each
constituent. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001g/kW-hr.
Subpart J--[Amended]
40. Section 1042.905 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 1042.905 Symbols, acronyms, and abbreviations.
* * * * *
* * * * * * *
CH4 methane.
* * * * * * *
N2O nitrous oxide.
* * * * * * *
PART 1045--[AMENDED]
41. The authority citation for part 1045 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
42. Section 1045.205 is amended by revising paragraph (q) to read
as follows:
Sec. 1045.205 What must I include in my application?
* * * * *
(q) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year, report measured
CO2, N2O, and CH4 as described in
Sec. 1045.235. Small-volume engine manufacturers may omit this
requirement.
* * * * *
43. Section 1045.235 is amended by adding paragraph (g) to read as
follows:
Sec. 1045.235 What emission testing must I perform for my application
for a certificate of conformity?
* * * * *
(g) Measure CO2, N2O, and CH4 with
each low-hour certification test using the procedures specified in 40
CFR part 1065. Small-volume engine manufacturers may omit this
requirement. These measurements are not required for NTE testing. Use
the same units and modal calculations as for your other results to
report a single weighted value for each constituent. Round the final
values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001g/kW-hr.
PART 1048--[AMENDED]
44. The authority citation for part 1048 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
45. Section 1048.205 is amended by revising paragraph (s) to read
as follows:
[[Page 16728]]
Sec. 1048.205 What must I include in my application?
* * * * *
(s) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR part 1065.
(2) Starting in the 2011 model year, report measured
CO2, N2O, and CH4 as described in
Sec. 1048.235. Small-volume engine manufacturers may omit this
requirement.
* * * * *
46. Section 1048.235 is amended by adding paragraph (g) to read as
follows:
Sec. 1048.235 What emission testing must I perform for my application
for a certificate of conformity?
* * * * *
(g) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each low-hour certification
test using the procedures specified in 40 CFR part 1065. Small-volume
engine manufacturers may omit this requirement. These measurements are
not required for measurements using field-testing procedures. Use the
same units and modal calculations as for your other results to report a
single weighted value for each constituent. Round the final values as
follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001g/kW-hr.
Subpart I--[Amended]
47. Section 1048.805 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 1048.805 What symbols, acronyms, and abbreviations does this
part use?
* * * * *
* * * * * * *
CH4 methane.
* * * * * * *
N2O nitrous oxide.
* * * * * * *
PART 1051--[AMENDED]
48. The authority citation for part 1051 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
49. Section 1051.205 is amended by revising paragraph (p) to read
as follows:
Sec. 1051.205 What must I include in my application?
* * * * *
(p) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR parts 86 and 1065.
(2) Starting in the 2011 model year, report measured
CO2, N2O, and CH4 as described in
Sec. 1051.235. Small-volume manufacturers may omit this requirement.
* * * * *
50. Section 1051.235 is amended by adding paragraph (i) to read as
follows:
Sec. 1051.235 What emission testing must I perform for my application
for a certificate of conformity?
* * * * *
(i) Starting in the 2011 model year, measure CO2,
N2O, and CH4 with each low-hour certification
test using the procedures specified in 40 CFR part 1065. Small-volume
manufacturers may omit this requirement. Use the same units and modal
calculations as for your other results to report a single weighted
value for each constituent. Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr or 1 g/km, as
appropriate.
(2) Round N2O to the nearest 0.001 g/kW-hr or 0.001 g/
km, as appropriate.
(3) Round CH4 to the nearest 0.001g/kW-hr or 0.001 g/km,
as appropriate.
Subpart I--[Amended]
51. Section 1051.805 is amended by adding the abbreviations
CH4 and N2O in alphanumeric order to read as
follows:
Sec. 1051.805 What symbols, acronyms, and abbreviations does this
part use?
* * * * *
* * * * * * *
CH4 methane.
* * * * * * *
N2O nitrous oxide.
* * * * * * *
PART 1054--[AMENDED]
52. The authority citation for part 1054 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
53. Section 1054.205 is amended by revising paragraph (p) to read
as follows:
Sec. 1054.205 What must I include in my application?
* * * * *
(p) Report test results as follows:
(1) Report all test results involving measurement of pollutants for
which emission standards apply. Include test results from invalid tests
or from any other tests, whether or not they were conducted according
to the test procedures of subpart F of this part. We may ask you to
send other information to confirm that your tests were valid under the
requirements of this part and 40 CFR parts 1060 and 1065.
(2) Starting in the 2011 model year, report measured
CO2, N2O, and CH4 as described in
Sec. 1054.235. Small-volume engine manufacturers may omit this
requirement.
* * * * *
54. Section 1054.235 is amended by adding paragraph (g) to read as
follows:
Sec. 1054.235 What exhaust emission testing must I perform for my
application for a certificate of conformity?
* * * * *
(g) Measure CO2, N2O, and CH4 with
each low-hour certification test using the procedures specified in 40
CFR part 1065. Small-volume engine manufacturers may omit this
requirement. Use the same units and modal calculations as for your
other results to report a single weighted value for each constituent.
Round the final values as follows:
(1) Round CO2 to the nearest 1 g/kW-hr.
(2) Round N2O to the nearest 0.001 g/kW-hr.
(3) Round CH4 to the nearest 0.001 g/kW-hr.
55. A new part 1064 is added to subchapter U of chapter I to read
as follows:
PART 1064--VEHICLE TESTING PROCEDURES
Subpart A--Applicability and general provisions
Sec.
1064.1 Applicability.
Subpart B--Air Conditioning Systems
1064.201 Method for calculating emissions due to air conditioning
leakage.
[[Page 16729]]
Authority: 42 U.S.C. 7401-7671q.
Subpart A--Applicability and General Provisions
Sec. 1064.1 Applicability.
(a) This part describes procedures that apply to testing we require
for 2011 and later model year light-duty vehicles, light-duty trucks,
and medium-duty personal vehicles (see 40 CFR part 86).
(b) See 40 CFR part 86 for measurement procedures related to
exhaust and evaporative emissions.
Subpart B--Air Conditioning Systems
Sec. 1064.201 Method for calculating emissions due to air
conditioning leakage.
Determine a refrigerant leakage rate from vehicle-based air
conditioning units as described in this section.
(a) Emission totals. Calculate an annual rate of refrigerant
leakage from an air conditioning system using the following equation:
Grams/YRTOT = Grams/YRRP + Grams/YRSP
+ Grams/YRFH + Grams/YRMC + Grams/YRC
Where:
Grams/YRRP = Emission rate for rigid pipe connections as
described in paragraph (b) of this section.
Grams/YRSP = Emission rate for service ports and
refrigerant control devices as described in paragraph (c) of this
section.
Grams/YRFH = Emission rate for flexible hoses as
described in paragraph (d) of this section.
Grams/YRMC = Emission rate for heat exchangers, mufflers,
receiver/driers, and accumulators as described in paragraph (e) of
this section.
Grams/YRC = Emission rate for compressors as described in
paragraph (f) of this section.
(b) Fittings. Determine the emission rate for rigid pipe
connections using the following Equation:
Grams/YRRP = 0.00522 [middot] [(125 [middot] SO) + (75
[middot] SCO) + (50 [middot] MO) + (10 [middot] SW) + (5 [middot] SWO)
+ (MG)]
Where:
SO = The number of single O-ring connections.
SCO = The number of single captured O-ring connections.
MO = The number of multiple O-ring connections.
SW = The number of seal washer connections.
SWO = The number of seal washer with O-ring connections.
MG = The number of metal gasket connections.
(c) Service ports and refrigerant control devices. Determine the
emission rate for service ports and refrigerant control devices using
the following Equation:
Grams/YRSP = (0.3 [middot] HSSP) + (0.2 [middot] LSSP) +
(0.2 [middot] STV) + (0.2 [middot] TXV)
Where:
HSSP = The number of high side service ports.
LSSP = The number of low side service ports.
STV = The total number of switches, transducers, and expansion
valves.
TXV = The number of TXV refrigerant control devices.
(d) Flexible hoses. Determine the permeation emission rate for each
segment of flexible hose using the following Equation, then add those
values to calculate a total emission rate for the system:
Grams/YRFH = 0.00522 [middot] (3.14159 [middot] ID [middot]
L [middot] ER)
Where:
ID = Inner diameter of hose, in millimeters.
L = Length of hose, in millimeters.
ER = Emission rate per unit internal surface area of the hose, in g/
mm\2\. Select the appropriate value from the following table:
------------------------------------------------------------------------
ER
-----------------------------------
Material/configuration High-pressure Low-pressure
side side
------------------------------------------------------------------------
Rubber.............................. 0.0216 0.0144
Standard barrier or veneer hose..... 0.0054 0.0036
Ultra-low permeation barrier or 0.00225 0.00167
veneer hose........................
------------------------------------------------------------------------
(e) Heat exchangers, mufflers, receiver/driers, and accumulators.
Use an emission rate of 0.5 grams per year as a combined value for all
heat exchangers, mufflers, receiver/driers, and accumulators (Grams/
YRMC).
(f) Compressors. Determine the emission rate for compressors using
the following equation:
Grams/YRC = 0.00522 [middot] [(300 [middot] OHS) + (200
[middot] MHS) + (150 [middot] FAP) + (100 [middot] GHS) + (1500/SSL)]
Where:
OHS = The number of O-ring housing seals.
MHS = The number of molded housing seals.
FAP = The number of fitting adapter plates.
GHS = The number of gasket housing seals.
SSL = The number of lips on shaft seal (for belt-driven compressors
only).
PART 1065--[AMENDED]
56. The authority citation for part 1065 continues to read as
follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart C--[Amended]
57. A new Sec. 1065.257 is added to subpart C to read as follows:
Sec. 1065.257 Nondispersive N2O infrared analyzer.
(a) Application. Use a nondispersive infrared (NDIR) analyzer to
measure N2O concentrations in diluted exhaust for batch
sampling. Batch sampling may be performed in a single bag covering all
phases of the test procedure.
(b) Component requirements. We recommend that you use an NDIR
analyzer that meets the specifications in Table 1 of Sec. 1065.205.
Note that your NDIR-based system must meet the calibration and
verification in Sec. 1065.357 and it must also meet the linearity
verification in Sec. 1065.307. You may use an NDIR analyzer that has
compensation algorithms that are functions of other gaseous
measurements and the engine's known or assumed fuel properties. The
target value for any compensation algorithm is 0.0 % (that is, no bias
high and no bias low), regardless of the uncompensated signal's bias.
(c) Artifact formation, SO2, and H2O removal.
SO2, NOX, and H2O have been shown to
react in the sample bag to form N2O. SO2 and
H2O must therefore be sequentially removed from the sample
gas before the sample enters the bag. SO2 can be neutralized
from the sample gas by passing the sample through a sorbent cartridge
packed with 120 cc of a 10:1 ratio of 18-20 mesh sand and
Ca(OH)2. This sorbent works only in the presence of
H2O so the H2O sorbent cartridge must be located
downstream of the SO2 sorbent cartridge. H2O can
be removed by passing the sample through a sorbent cartridge packed
with 120 cc of P2O5.
58. A new Sec. 1065.357 is added to subpart D to read as follows:
Sec. 1065.357 CO and Co2 interference verification for
N2O NDIR analyzers.
(a) Scope and frequency. If you measure CO using an NDIR analyzer,
[[Page 16730]]
verify the amount of CO and Co2 interference after initial
analyzer installation and after major maintenance.
(b) Measurement principles. CO and Co2 can positively
interfere with an NDIR analyzer by causing a response similar to
N2O. If the NDIR analyzer uses compensation algorithms that
utilize measurements of other gases to meet this interference
verification, simultaneously conduct these other measurements to test
the compensation algorithms during the analyzer interference
verification.
(c) System requirements. A N2O NDIR analyzer must have
combined CO and Co2 interference that is within 2 percent of the flow-weighted mean concentration of
N2O expected at the standard, though we strongly recommend a
lower interference that is within 1 percent.
(d) Procedure. Perform the interference verification as follows:
(1) Start, operate, zero, and span the N2O NDIR analyzer
as you would before an emission test.
(2) Introduce a CO span to the analyzer.
(3) Allow time for the analyzer response to stabilize.
Stabilization time may include time to purge the transfer line and to
account for analyzer response.
(4) While the analyzer measures the sample's concentration, record
its output for 30 seconds. Calculate the arithmetic mean of this data.
(5) Scale the CO interference by multiplying this mean value (from
paragraph (d)(7) of this section) by the ratio of expected CO to span
gas CO concentration. In other words, estimate the flow-weighted mean
dry concentration of CO expected during testing, and then divide this
value by the concentration of CO in the span gas used for this
verification. Then multiply this ratio by the mean value recorded
during this verification (from paragraph (d)(7) of this section).
(6) Repeat the steps in paragraphs (d)(2) through (5) of this
section, but with a CO2 analytical gas mixture instead of CO
and without humidifying the sample through the distilled water in a
sealed vessel.
(7) Add together the CO and CO2-scaled result of
paragraphs (d)(5) and (6) of this section.
(8) The analyzer meets the interference verification if the result
of paragraph (d)(7) of this section is within 2 percent of
the flow-weighted mean concentration of N2O expected at the
standard.
(e) Exceptions. The following exceptions apply:
(1) You may omit this verification if you can show by engineering
analysis that for your N2O sampling system and your emission
calculations procedures, the combined CO, CO2, and
H2O interference for your N2O NDIR analyzer
always affects your brake-specific N2O emission results
within 0.5 percent of the applicable N2O
standard.
(2) You may use a N2O NDIR analyzer that you determine
does not meet this verification, as long as you try to correct the
problem and the measurement deficiency does not adversely affect your
ability to show that engines comply with all applicable emission
standards.
Subpart H--[Amended]
59. Section 1065.750 is amended by revising paragraph (a)(1)(ii)
and adding paragraph (a)(3)(xi) to read as follows:
Sec. 1065.750 Analytical gases.
* * * * *
(a) * * *
(1) * * *
(ii) Contamination as specified in the following table:
Table 1 of Sec. 1065.750--General Specifications for Purified Gases
------------------------------------------------------------------------
Purified synthetic
Constituent air \1\ Purified N2\1\
------------------------------------------------------------------------
THC (C1 equivalent)............. <0.05 [mu]mol/mol. <0.05 [mu]mol/mol
CO.............................. <1 [mu]mol/mol.... <1 [mu]mol/mol.
CO2............................. <10 [mu]mol/mol... <10 [mu]mol/mol.
O2.............................. 0.205 to 0.215 mol/ <2 [mu]mol/mol.
mol.
NOX............................. <0.02 [mu]mol/mol. <0.02 [mu]mol/mol.
N2O............................. <0.05 [mu]mol/mol. <0.05 [mu]mol/mol.
------------------------------------------------------------------------
\1\ We do not require these levels of purity to be NIST-traceable.
* * * * *
(3) * * *
(xi) N2O, balance purified N2.
* * * * *
Subpart K--[Amended]
60. Section 1065.1001 is amended by revising the definition for
``Oxides of nitrogen'' to read as follows:
Sec. 1065.1001 Definitions.
* * * * *
Oxides of nitrogen means NO and NO2 as measured by the
procedures specified in Sec. 1065.270. Oxides of nitrogen are
expressed quantitatively as if the NO is in the form of NO2,
such that you use an effective molar mass for all oxides of nitrogen
equivalent to that of NO2.
* * * * *
61. Section 1065.1005 is amended by adding items to the table in
paragraph (b) in alphanumeric order to read as follows:
Sec. 1065.1005 Symbols, abbreviations, acronyms, and units of
measure.
* * * * *
(b) * * *
[[Page 16731]]
------------------------------------------------------------------------
Symbol Species
------------------------------------------------------------------------
* * * * * * *
Ca(OH)2................................ calcium hydroxide
* * * * * * *
P2O5................................... phosphorous pentoxide
* * * * * * *
SO2.................................... sulfur dioxide
* * * * * * *
------------------------------------------------------------------------
* * * * *
[FR Doc. E9-5711 Filed 4-9-09; 8:45 am]
BILLING CODE 6560-50-P