[Federal Register Volume 75, Number 154 (Wednesday, August 11, 2010)]
[Proposed Rules]
[Pages 48744-48814]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-18354]
[[Page 48743]]
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Part II
Environmental Protection Agency
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40 CFR Part 98
Mandatory Reporting of Greenhouse Gases; Proposed Rule
Federal Register / Vol. 75, No. 154 / Wednesday, August 11, 2010 /
Proposed Rules
[[Page 48744]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2008-0508; FRL-9179-8]
RIN 2060-AQ33
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Proposed Rule.
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SUMMARY: EPA is proposing to amend specific provisions in the GHG
reporting rule to clarify certain provisions, to correct technical and
editorial errors, and to address certain questions and issues that have
arisen since promulgation. These proposed changes include providing
additional information and clarity on existing requirements, allowing
greater flexibility or simplified calculation methods for certain
sources in a facility, amending data reporting requirements to provide
additional clarity on when different types of GHG emissions need to be
calculated and reported, clarifying terms and definitions in certain
equations, and technical corrections.
DATES: Comments. Comments must be received on or before September 27,
2010.
Public Hearing. EPA does not plan to conduct a public hearing
unless requested. To request a hearing, please contact the person
listed in the FOR FURTHER INFORMATION CONTACT section by August 18,
2010. If requested, the hearing will be conducted August 26, 2010, at
1310 L St., NW., Washington, DC 20005 starting at 9 a.m., local time.
EPA will provide further information about the hearing on its Web page
if a hearing is requested.
ADDRESSES: You may submit your comments, identified by docket ID No.
EPA-HQ-OAR-2008-0508 by any of the following methods:
Federal eRulemaking Portal: http://www.regulations.gov.
Follow the online instructions for submitting comments.
E-mail: [email protected]. Include docket ID No. EPA-
HQ-OAR-2008-0508 [and/or RIN number 2060-aq33] in the subject line of
the message.
Fax: (202) 566-1741.
Mail: Environmental Protection Agency, EPA Docket Center
(EPA/DC), Mailcode 2822T, Attention Docket ID No. EPA-HQ-OAR-2008-0508,
1200 Pennsylvania Avenue, NW., Washington, DC 20004.
Hand/Courier 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, Revision of Certain GHGMRR Provisions and Other Corrections.
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 confidential
business information (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 Building, Room 3334, 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 GENERAL 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.
Worldwide Web (WWW). In addition to being available in the docket,
an electronic copy of today's proposal will also be available through
the WWW. Following the Administrator's signature, a copy of this action
will be posted on EPA's greenhouse gas reporting rule Web site at
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
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 address:
[email protected].
Regulated Entities. The Administrator determined that this action
is subject to the provisions of Clean Air Act (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''). These are
proposed amendments to existing regulations. If finalized, these
amended regulations would affect owners or operators of certain fossil
fuel and industrial gas suppliers, and direct emitters of GHGs.
Regulated categories and entities include those listed in Table 1 of
this preamble:
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Table 1--Examples of Affected Entities by Category
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Category NAICS Examples of affected facilities
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General Stationary Fuel Combustion Sources.. .................. Facilities operating 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.
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 production
facilities.
Cement Production........................... 327310 Portland Cement manufacturing plants.
Ferroalloy Production....................... 331112 Ferroalloys manufacturing 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 Destruction... 325120 Chlorodifluoromethane manufacturing
facilities.
Hydrogen Production......................... 325120 Hydrogen production 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.
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.
Nitric Acid Production...................... 325311 Nitric acid production facilities.
Petrochemical Production.................... 32511 Ethylene dichloride production facilities.
325199 Acrylonitrile, ethylene oxide, methanol
production facilities.
325110 Ethylene production facilities.
325182 Carbon black production 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.
212391 Soda ash, natural, mining and/or
beneficiation.
Titanium Dioxide Production................. 325188 Titanium dioxide manufacturing facilities.
Zinc Production............................. 331419 Primary zinc refining facilities.
331492 Zinc dust reclaiming facilities, recovering
from scrap and/or alloying purchased metals.
Municipal Solid Waste Landfills............. 562212 Solid waste landfills.
221320 Sewage treatment facilities.
Manure Management\1\........................ 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 Natural Gas and NGLs........... 221210 Natural gas distribution facilities.
211112 Natural gas liquid extraction facilities.
Suppliers of Industrial GHGs................ 325120 Industrial gas production facilities.
Suppliers of Carbon Dioxide (CO2)........... 325120 Industrial gas production facilities.
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\1\ EPA will not be implementing subpart JJ of Part 98 using funds provided in its FY2010 appropriations due to
a Congressional restriction prohibiting the expenditure of funds for this purpose.
[[Page 48746]]
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities likely to be
affected by this action. Table 1 of this preamble lists the types of
facilities that EPA is now aware could potentially be affected by the
reporting requirements. Other types of facilities than those listed in
the table could also be subject to reporting requirements. To determine
whether you are affected by this action, you should carefully examine
the applicability criteria found in 40 CFR part 98, subpart A or the
relevant criteria in the sections related to fossil fuel and industrial
gas suppliers, and direct emitters of GHGs. If you have questions
regarding the applicability of this action to a particular facility,
consult the person listed in the preceding FOR FURTHER GENERAL
INFORMATION CONTACT Section.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
ACC American Chemistry Council
AGA American Gas Association
API American Petroleum Institute
ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BAMM best available monitoring method
Btu/scf British thermal unit per standard cubic foot
CAA Clean Air Act
CAIR Clean Air Interstate Rule
CBI confidential business information
cc cubic centimeters
CE calibration error
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CGA Cylinder gas audit
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
CO2e CO2-equivalent
CWPB center worked prebake
EGU electricity generating unit
EIA Energy Information Administration
EO Executive Order
EPA U.S. Environmental Protection Agency
ERC Energy Recovery Council
FGD flue gas desulfurization
FR Federal Register
FTIR fourier transform infrared
GC gas chromatography
GHG greenhouse gas
GPA Gas Processors Association
GWP global warming potential
HCl hydrogen chloride
HHV high heat value
HSS horizontal stud S[oslash]derberg
IPCC Intergovernmental Panel on Climate Change
IR infrared
LDCs local natural gas distribution companies
mmBtu/hr million British thermal units per hour
mscf thousand standard cubic feet
MSW municipal solid waste
mtCO2e metric tons of CO2 equivalents
MVC molar volume conversion factor
MWC municipal waste combustor
NESHAP National Emission Standards for Hazardous Air Pollutants
NIST National Institute of Standards and Technology
NMR nuclear magnetic resonance
NSPS New Source Performance Standards
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
O2 oxygen
O&M operation and maintenance
OMB Office of Management and Budget
PFC perfluorocarbon
psia pounds per square inch absolute
QA quality assurance
QA/QC quality assurance/quality control
RATA relative accuracy test audit
RFA Regulatory Flexibility Act
RFG Refinery fuel gas
RGGI Regional Greenhouse Gas Initiative
scf standard cubic feet
scfm standard cubic feet per minute
SO2 sulfur dioxide
SWPB side worked prebake
U.S. United States
UMRA Unfunded Mandates Reform Act of 1995
VSS vertical stud S[oslash]derberg
Table of Contents
I. Background
A. How is this preamble organized?
B. Background on This Action
C. Legal Authority
D. How would these amendments apply to 2011 reports?
II. Revisions and Other Amendments
A. Subpart A (General Provisions): Best Available Monitoring
Methods
B. Subpart A (General Provisions): Calibration Requirements
C. Subpart A (General Provisions): Reporting of Biogenic
Emissions
D. Subpart A (General Provisions): Requirements for Correction
and Resubmission of Annual Reports
E. Subpart A (General Provisions): Information To Record for
Missing Data Events
F. Subpart A (General Provisions): Other Technical Corrections
and Amendments
G. Subpart C (General Stationary Fuel Combustion)
H. Subpart D (Electricity Generation)
I. Subpart F (Aluminum Production)
J. Subpart G (Ammonia Manufacturing)
K. Subpart P (Hydrogen Production)
L. Subpart V (Nitric Acid Production)
M. Subpart X (Petrochemical Production)
N. Subpart Y (Petroleum Refineries)
O. Subpart AA (Pulp and Paper Manufacturing)
P. Subpart NN (Suppliers of Natural Gas and Natural Gas Liquids)
Q. Subpart OO (Suppliers of Industrial Greenhouse Gases)
R. Subpart PP (Suppliers of Carbon Dioxide)
III. 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
A. How is this preamble organized?
The first section of this preamble contains the basic background
information about the origin of these proposed rule amendments and
request for public comment. This section also discusses EPA's use of
our legal authority under the Clean Air Act to collect data on GHGs.
The second section of this preamble describes in detail the changes
that are being proposed to correct technical errors or to address
implementation issues identified by EPA and others. This section also
presents EPA's rationale for the proposed changes and identifies issues
on which EPA is particularly interested in receiving public comments.
Finally, the last (third) section discusses the various statutory
and executive order requirements applicable to this proposed
rulemaking.
B. Background on This Action
The final Part 98 was signed by EPA Administrator Lisa Jackson on
September 22, 2009 and published in the Federal Register on October 30,
2009 (74 FR 56260-56519, October 30, 2009). Part 98, which became
effective on December 29, 2009, included reporting of GHG information
from facilities and suppliers, consistent with the 2008 Consolidated
Appropriations Act. \1\ These source categories capture approximately
85 percent of U.S. GHG emissions through reporting by direct emitters
as well as suppliers of fossil fuels and industrial gases.
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\1\ Consolidated Appropriations Act, 2008, Public Law 110-161,
121 Stat. 1844, 2128.
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This is the second time that EPA has published a notice proposing
amendments to Part 98 to, among other things, correct certain technical
and editorial errors that have been identified since promulgation and
clarify or
[[Page 48747]]
propose amendments to certain provisions that have been the subject of
questions from reporting entities. The first proposal was published on
June 15, 2010 (75 FR 33950). This proposal complements the proposal
published on June 15, 2010 and is not intended to duplicate or replace
the proposed amendments published on June 15, 2010. We are seeking
public comment only on the issues specifically identified in this
proposal for the identified subparts. We will not respond to any
comments addressing other aspects of Part 98 or any other related
rulemakings.
C. Legal Authority
EPA is proposing these rule amendments under its existing CAA
authority, specifically authorities provided in section 114 of the CAA.
As stated in the preamble to the final Part 98 (74 FR 56260,
October 30, 2009), CAA section 114 provides EPA broad authority to
require the information proposed to be gathered by Part 98 because such
data would inform and are relevant to EPA's obligation to carry out a
wide variety of CAA provisions. As discussed in the preamble to the
initial proposal (74 FR 16448, April 10, 2009), section 114(a)(1) of
the CAA authorizes the Administrator to require emissions sources,
persons subject to the CAA, manufacturers of control equipment, or
persons whom the Administrator believes may have necessary information
to monitor and report emissions and provide such other information the
Administrator requests for the purposes of carrying out any provision
of the CAA. For further information about EPA's legal authority, see
the preambles to the proposed and final rule, and Response to Comments
Documents.\2\
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\2\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30,
2009). Response to Comments Documents can be found at http://www.epa.gov/climatechange/emissions/responses.html.
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D. How would these amendments apply to 2011 reports?
EPA is planning to address the comments on these proposed
amendments and publish the final amendments before the end of 2010.
Therefore, reporters would be expected to calculate emissions and other
relevant data for the reports that are submitted in 2011 using Part 98,
as amended by this and the other revisions package (75 FR 33950), as
finalized. We have determined that it is feasible for the sources to
implement these changes for the 2010 reporting year since the revisions
primarily provide additional clarifications or flexibility regarding
the existing regulatory requirements, generally do not affect the type
of information that must be collected, and do not substantially affect
how emissions are calculated.
For example, many proposed revisions simply provide additional
information and clarity on existing requirements. For example, we are
proposing to amend 40 CFR 98.3(c)(5)(i) to clarify that suppliers of
industrial flourinated GHGs need to calculate and report GHG emissions
in metric tons of CO2 equivalents (mtCO2e) only
for those flourinated GHGs that are listed in Table A-1. This proposed
clarification is consistent with clarifications we have issued in
response to industry questions and would not change how facilities
collected data during 2010.
Some of the proposed amendments provide greater flexibility or
simplified calculation methods for certain facilities. For example, we
are proposing to amend subpart C by adding a new equation that would
enable sources that receive natural gas billing data from their
suppliers in therms to calculate CO2 mass emissions directly
from the information on the billing records, without having to request
or obtain additional data from the fuel suppliers.
Some proposed amendments are to the data reporting requirements to
provide additional clarity on when different types of GHG emissions
need to be calculated and reported. For example, in subpart G, Ammonia
Manufacturing, we are proposing to eliminate the calculation and
reporting of CO2 emissions associated with the use of the
waste recycle stream or ``purge'' as fuel under subpart C because these
emissions are already accounted for in the calculation of total process
emissions in subpart G, which includes CO2 emissions
resulting from the use of purge gas as a fuel. We have concluded that
amendments such as these can be implemented for the reports submitted
to EPA in 2011 because the proposed changes are consistent with the
calculation methodologies already in part 98 and the owners or
operators are not required to actually report until March 2011, several
months after we expect this proposal to be finalized.
For some subparts, we are proposing amendments to address issues
identified as a result of working with the affected sources during rule
implementation. These proposed revisions provide additional flexibility
to the sources, or reduce the reporting burden. For example, in
subparts X (Petrochemical Production) and Y (Petroleum Refineries),
reporters have requested that allowance be made for alternative
standard conditions within the molar volume conversion factor (MVC)
used in various equations. Therefore, we are proposing to amend those
subparts to include MVCs at standard conditions defined at both
60[ordm]F or 68[ordm]F, so the facilities will not have to make those
corrections in their data.
We are also proposing corrections to terms and definitions in
certain equations. For example, in subpart Y, Petroleum Refineries, we
are proposing to clarify in an equation that for coke calcining units
that recycle the collected coke dust, the mass of coke dust removed
from the process is the mass of coke dust collected less the mass of
coke dust recycled to the process. These clarifications do not result
in additional requirements; therefore, we have concluded that reporters
can follow Part 98, as amended, in submitting their first reports in
2011.
Finally, we are proposing other technical corrections that have no
impact on facility's data collection efforts in 2010. For example, we
are proposing to amend subpart C to remove a second copy of Table C-2
that was inadvertently included in the final Part 98 published on
October 30, 2009.
In summary, these amendments would not require any additional
monitoring or information collection above what was already included in
Part 98. Therefore, we expect that sources can use the same information
that they have been collecting under the current version of Part 98 to
calculate and report GHG emissions for 2010 and submit reports in 2011
under the amended Part 98.
We seek comment on the conclusion that it is appropriate to
implement these amendments and incorporate the requirements in the data
reported to EPA by March 31, 2011. Further, we seek comment on whether
there are specific subparts of Part 98 for which this timeline may not
be feasible or appropriate due to the nature of the proposed changes or
the way in which data have been collected thus far in 2010. We request
that commenters provide specific examples of how the proposed
implementation schedule would or would not work.
II. Revisions and Other Amendments
Following promulgation of Part 98, we have identified errors in the
regulatory language that we are now proposing to correct. These errors
were identified as a result of working with affected industries to
implement the various subparts of Part 98. We have also identified
certain rule provisions that should be amended to provide greater
clarity. We are also proposing revisions to provide additional
[[Page 48748]]
flexibility for certain requirements based in part on our better
understanding of various industries. Finally, we are also proposing to
revise or remove certain applicability thresholds (for example for
local distribution companies subject to subpart NN (Suppliers of
Natural Gas and Natural Gas Liquids)) and monitoring thresholds and
reporting requirements (for example for municipal solid waste
combusters subject to subpart C (General Stationary Fuel Combustion)
and for certain small sources subject to subpart X (Petrochemicals) or
subpart Y (Petroleum Refineries)). The amendments we are now proposing
include the following types of changes:
Changes to correct cross references within and between
subparts.
Additional information to better or more fully understand
compliance obligations in a specific provision, such as the reference
to a standardized method that must be followed.
Amendments to certain equations to better reflect actual
operating conditions.
Corrections to terms and definitions in certain equations.
Corrections to data reporting requirements so that they
more closely conform to the information used to perform emission
calculations.
Other amendments related to certain issues identified as a
result of working with the affected sources during rule implementation
and outreach.
As mentioned above in section I of this preamble, we published an
earlier proposed rulemaking proposing technical corrections and other
amendments to Part 98 on June 15, 2010 (75 FR 33950). This proposal
complements the notice published on June 15, 2010 and is not intended
to duplicate or replace the proposed amendments published on June 15,
2010. We are seeking public comment only on the issues specifically
identified in this notice for the identified subparts. We will not
respond to any comments addressing other aspects of Part 98 or any
other related rulemakings.
A. Subpart A (General Provisions): Best Available Monitoring Methods
Certain owners and operators in the more complex hydrogen,
petrochemical, and petroleum refinery industries have expressed
concerns regarding the timing of the requirements to install meters and
other measurement devices to comply with Part 98. Specifically, they
were concerned that the safe installation of required measurement
devices requires detailed engineering and planning and, therefore,
stated that EPA should provide sufficient time for designing and safely
engineering instrumentation installations or upgrades. Further, they
claimed that in continuously operated plants there is typically not a
scheduled shutdown for an entire facility and unit maintenance and
turnarounds are not an annual occurrence for all units. Reporters in
these industries have asserted that EPA has properly recognized this
operational reality in the context of instrument calibration by
allowing calibration to be delayed until the next scheduled shutdown.
The reporters have noted, however, that parallel requirements have not
been developed for installation of monitoring devices. Specifically,
they requested that EPA should provide approval criteria for extending
the use of ``best available monitoring methods'' (BAMM) beyond December
31, 2010 for equipment installation.
These types of concerns were the reason owners and operators were
given the opportunity in Part 98 to request an extension from EPA to
use BAMM beyond March 31, 2010 in situations where it was not
reasonably feasible to acquire, install and operate the required
monitoring equipment by that date. We recognize, however, that
instances may occur where facilities subject to Part 98 may not have
been scheduled to shutdown during 2010, and requiring the facility to
shutdown solely to install the required measurement devices during 2010
could impose an unnecessary burden.
Therefore, we are proposing that a new petition process be
established in a new paragraph 40 CFR 98.3(j) that would allow use of
BAMM past December 31, 2010 for owners and operators required to report
under subpart P (Hydrogen Production), subpart X (Petrochemicals
Production), or subpart Y (Petroleum Refineries), under limited
circumstances. We are proposing that owners or operators subject to
these subparts could petition EPA to extend use of BAMM past December
31, 2010, if compliance with a specific provision in the regulation
required measurement device installation, and installing the device(s)
would necessitate an unscheduled process equipment or unit shutdown or
could only be installed through a hot tap. If the petition is approved,
the owner or operator could postpone installation of the measurement
device until the next scheduled maintenance outage, but initially no
later than December 31, 2013. If, in 2013, owners or operators still
determine and certify that a scheduled shutdown will not occur by
December 31, 2013, they may re-apply to use best available monitoring
methods for an additional two years.
The initial process for use of best available monitoring methods in
Part 98 ended December 31, 2010, because we concluded that it is
important to establish a date by which all equipment must be installed
and operating in order to ensure that consistent data are collected by
all reporters. We maintain that it is important to have consistent
methods being used by all reporters. However, we also recognize that
some complex facilities have unique operating circumstances that
justify additional flexibility. Therefore, although we are proposing to
initially approve extension requests no later than December 31, 2013,
owners or operators subject to these subparts would have a one time
opportunity to re-apply for the extension request for an additional two
years, with approval being granted no later than December 31, 2015. We
believe that a date of December 31, 2013, four years after the
effective date of Part 98, would accommodate the shutdown schedules for
most, if not all facilities subject to subparts P, X, and/or Y. Because
we recognize that all such facilities subject to Part 98 may not have a
planned process equipment or unit shutdown prior to December 31, 2013,
we have has concluded that it is reasonable to propose that owners or
operators could re-apply one time for an additional two years. This
timeline balances the need to gather consistent data, while recognizing
the operational reality of such facilities.
Process for Requesting an Extension of Best Available Monitoring
Methods. We are proposing to add a similar petition process to that
recently concluded for the use of BAMM for 2010 in the new paragraph 40
CFR 98.3(j). The process would be available solely for facilties
subject to subparts P, X and/or Y, and solely for the installation of
measurement devices that cannot be installed safely except during full
process equipment or unit shutdown or through installation via a hot
tap. BAMM would be allowable initially until December 31, 2013. Subpart
P, X, and/or Y owners or operators requesting to use BAMM beyond 2010
would be required to electronically notify EPA by January 1, 2011 that
they intend to apply for BAMM for installation of measurement devices
and certify that such installation would require a hot tap or
unscheduled shutdown.
Owners or operators would be required to submit the full extension
request for BAMM by February 15, 2011. The full extension requests
would
[[Page 48749]]
include a description of the measurement devices that could not be
installed in 2010 without a process equipment or unit shutdown, or
through a hot tap, a clear explanation of why that activity would not
be accomplished in 2010 with supporting material, an estimated date for
the next planned maintenance outage, and a discussion of how emissions
would be calculated in the interim. More specifically, the full
extension request would need to identify the specific monitoring
instrumentation for which the request is being made, indicate the
locations where each piece of monitoring instrumentation will be
installed, and note the specific rule requirements (by rule subpart,
section, and paragraph numbers) for which the instrumentation is
needed. The extension requests would also be required to include
supporting documentation demonstrating that it is not practicable to
isolate the equipment and install the monitoring instrument without a
full process equipment or unit shutdown, or through a hot tap, as well
as providing the dates of the three most recent process equipment or
unit shutdowns, the typical frequency of shutdowns for the respective
equipment or unit, and the date of the next planned shutdown.
Once subpart P, X, and/or Y owners or operators have notified EPA
of their plan to apply for BAMM for measurement device installation, by
January 1, 2011, and subsequently submitted a full extension request,
by February 15, 2011, they would automatically be able to use BAMM
through June 30, 2011. All measurement devices would need to be
installed by July 1, 2011 unless EPA approves the BAMM request before
that date.
Approval of Extension Requests. In an approval of an extension
request, EPA would approve the extension itself, establish a date by
which all measurement devices must be installed, and indicate the
approved alternate method for calculating GHG emissions in the interim.
If EPA approves an extension request, the owner/operator would have
until the date approved by EPA to install any remaining meters or other
measurement devices, however initial approvals would not grant
extensions beyond December 31, 2013. An owner/operator that already
received approval from EPA to use BAMM during part or all of 2010 would
be required to submit a new request for use of BAMM beyond 2010. Unless
EPA has approved an extension request, all owners or operators that
submit a timely request under this new proposed process for BAMM would
be required to install all measurement devices by July 1, 2011.
We recognize that occasionally a facility may plan a scheduled
process equipment or unit shutdown and the installation of required
monitoring equipment, but the date of the scheduled shutdown is
changed. We are proposing to include a process by which owners or
operators who had received an extension would have the opportunity to
extend the use of BAMM beyond the date approved by EPA if they can
demonstrate to the Administrator's satisfaction that they are making a
good faith effort to install the required equipment. At a minimum,
facilities that determine that the date of a scheduled shutdown will be
moved would be required to notify EPA within 4 weeks of such a
determination, but no later than 4 weeks before the date of which the
planned shutdown was scheduled.
One-time request to extend best available monitoring methods past
December 31, 2013. If subpart P, X, and/or Y owners or operators
determine that a scheduled shutdown will not occur by December 31,
2013, they would be required to re-apply to use best available
monitoring methods for one additional time period, not to extend beyond
December 31, 2015. To extend use of best available monitoring methods
past December 13, 2013, owners or operators would be required to submit
a new extension request by June 1, 2013 that contains the information
required in proposed 40 CFR 98.3(j)(4). All owners or operators that
submit a request under this paragraph to extend use of best available
monitoring methods for measurement device installation would be
required to install all measurement devices by December 31, 2013,
unless the extension request under this paragraph is approved by EPA.
We seek comment on this approach to extend the deadline for
installation of measurement devices in cases where such installation
would require an unscheduled process equipment or unit shutdown at a
subpart P, X, and/or Y facility. The proposed approach is consistent
with the language and intent in Part 98 to defer calibration of
required monitors in order to avoid unnecessary and unplanned
shutdowns. The proposed approach is also modeled after the provision to
request EPA to use BAMM during 2010. We considered, but did not
propose, limiting this provision to only those subpart P, X, and/or Y
owners and operators who submitted a request for use of BAMM by January
28, 2010. This option was considered based on an assumption that the
full universe of reporters that had difficulty installing the necessary
measurement devices according to the schedule in the rule would have
already submitted a request for the use of BAMM in 2010. We still
believe that all owners or operators that required a process equipment
or unit shutdown to install measurement devices should have submitted
an extension request to EPA by January 28, 2010. Nevertheless, we also
recognize that this is a new regulation and facilities subject to Part
98 are making good faith efforts to understand all requirements. After
careful consideration we are proposing to initiate a new process for
BAMM, providing all facilties with units subject to subpart P, subpart
X or subpart Y the opportunity to apply.
We are proposing to limit the provision to facilities with units
subject to one or more of these three subparts because, based on
questions received during implementation, the concerns raised about
installation of measurement devices necessitating process equipment or
unit shutdown have been from facilities subject to these subparts. A
clear case was not presented by other industries as to any unique
circumstances in those industries (e.g., safety concerns associated
with installation of measurement devices, frequency of shutdowns,
complexities associated with shutting down, etc.) that might
necessitate extending the deadline for BAMM for these other industries.
We are seeking comment on this conclusion and whether there are other
facilities beyond these subparts P, X, and Y that would need a
shutdown, or a hot tap, in order to install the required measurement
devices. If providing comments, please provide information on
additional subparts, if any, that would need this flexibility, and
include information on why installation could not be done in the
absence of such a shutdown or why such shutdowns did not or could not
occur in 2010 without unreasonable burden on the facility.
We are generally seeking comment on this new petition process for
BAMM.
B. Subpart A (General Provisions): Calibration Requirements
Since the rule was published on October 30, 2009, EPA has received
numerous questions about the intent and extent of the equipment
calibration requirements specified in 40 CFR 98.3(i). The current rule
could be interpreted to require all types of measurement equipment that
provide data for the GHG emissions calculations, including flow meters
and ``other devices'' such as belt scales, to be
[[Page 48750]]
calibrated to a specified accuracy (i.e., 5.0 percent in most cases).
The perceived universal nature of the calibration requirements in
40 CFR 98.3(i) has caused a great deal of concern in the regulated
community. For example, the appropriateness of a 5.0 percent accuracy
specification for a wide variety of measurement devices has been
questioned. Specifically, reporters have recommended that the initial
and on-going calibration requirements be modified to allow the accuracy
to be determined within an appropriate error range for each measurement
technology, based on an applicable standard.
Also, for small combustion units using the Tier 1 or Tier 2
CO2 calculation methodologies in 40 CFR 98.33(a), reporters
were concerned that the calibration requirements and accuracy
specifications appear to apply to flow meters that are used to quantify
liquid and gaseous fuel usage. This contradicts the clear statements in
the nomenclature of Equations C-1 and C-2a of Subpart C that company
records can be used to measure fuel consumption for Tier 1 and 2 units.
We note that the definition of ``company records'' in 40 CFR 98.6 is
quite flexible and it does not require that any particular calibration
methods be used or that specific accuracy percentages be met.
In view of these considerations, we are proposing to amend 40 CFR
98.3(i) as follows, to more clearly define the scope of the calibration
requirements:
(a) We are proposing to amend 40 CFR 98.3(i)(1) to specify that the
calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) would
be required only for flow meters that measure liquid and gaseous fuel
feed rates, feedstock flow rates, or process stream flow rates that are
used in the GHG emissions calculations, and only when the calibration
accuracy requirement is specified in an applicable subpart of Part 98.
For instance, the QA/QC requirements in 40 CFR 98.34(b)(1) of Subpart C
require all flow meters that measure liquid and gaseous fuel flow rates
for the Tier 3 CO2 calculation methodology to be calibrated
according to 40 CFR 98.3(i); therefore, the accuracy standards in 40
CFR 98.3(i)(2) and (i)(3) would continue to apply to these meters. EPA
has many years of experience with fuel flow meter calibration, for
example in the Acid Rain and NOX Budget Programs, and the
Agency is confident that the accuracy requirements specified in 40 CFR
98.3(i) are both reasonable and achievable for such meters. For more
information please refer to the Background Technical Support Document
at EPA-HQ-OAR-2008-0508. We are also proposing to add statements to 40
CFR 98.3(i) to clarify that the calibration accuracy specifications of
40 CFR 98.3(i)(2) and (i)(3) do not apply where the use of company
records or the use of best available information is specified to
quantify fuel usage or other parameters, nor do they apply to sources
that use Part 75 methodologies to calculate CO2 mass
emissions because the Part 75 quality-assurance is sufficient. Although
calibration accuracy requirements are not applicable for these data
sources, per the requirements of 98.3(g)(5), reporters are still
required to explain in their monitoring plan the processes and methods
used to collect the necessary data for the GHG calculations.
(b) We are proposing to further amend 40 CFR 98.3(i)(1) to clarify
that the calibration accuracy specifications in 40 CFR 98.3(i)(2) and
(i)(3) do not apply to other measurement devices (e.g., weighing
devices) that provide data for the GHG emissions calculations. Rather,
these devices would have to be calibrated to meet the accuracy
requirements of the relevant subpart(s), or, in the absence of such
requirements, to meet appropriate, technology-based error-limits, such
as industry consensus standards or manufacturer's accuracy
specifications. Consistent with 40 CFR 98.3(g)(5)(i)(C), the procedures
and methods used to quality-assure the data from the measurement
devices would be documented in the written monitoring plan.
(c) We are proposing to add a new paragraph 40 CFR 98.3(i)(1)(ii)
to clarify that flow meters and other measurement devices need to be
installed and calibrated by the date on which data collection needs to
begin, if a facility or supplier becomes subject to Part 98 after April
1, 2010.
(d) We are proposing to add a new paragraph 40 CFR 98.3(i)(1)(iii)
to specify the frequency at which subsequent recalibrations of flow
meters and other measurement devices need to be performed.
Recalibration would be at the frequency specified in each applicable
subpart, or at the frequency recommended by the manufacturer or by an
industry consensus standard practice, if no recalibration frequency was
specified in an applicable subpart.
(e) We are proposing to specify the consequences of a failed flow
meter calibration in a new paragraph 40 CFR 98.3(i)(7). Data would
become invalid prospectively, beginning at the hour of the failed
calibration and continuing until a successful calibration is completed.
Appropriate substitute data values would be used during the period of
data invalidation.
(f) In 40 CFR 98.3(i)(2) and (3), we are proposing to add absolute
value signs to the numerators of Equations A-2 and A-3. These were
inadvertently omitted in the October 30, 2009 Part 98.
(g) We are proposing to amend 40 CFR 98.3(i)(3) to increase the
alternative accuracy specification for orifice, nozzle, and venturi
flow meters (i.e., the arithmetic sum of the three transmitter
calibration errors (CE) at each calibration level) from 5.0 percent to
6.0 percent, since each transmitter is individually allowed an accuracy
of 2.0 percent. We are also proposing to amend 40 CFR 98.3(i)(3) for
orifice, nozzle, and venturi flow meters to account for cases where not
all three transmitters for total pressure, differential pressure, and
temperature are located in the vicinity of a flow meter's primary
element. Instead of being required to install additional transmitters,
reporters would, as described below, conditionally be allowed to use
assumed values for temperature and/or total pressure based on
measurements of these parameters at remote locations. If only two of
the three transmitters are installed and an assumed value is used for
temperature or total pressure, the maximum allowable calibration error
would be 4.0 percent. If two assumed values are used and only the
differential pressure transmitter is calibrated, the maximum allowable
calibration error would be 2.0 percent. We note that the use of an
arithmetic sum of the calibration errors is consistent with the
approach in Part 75, and is designed to introduce flexibility, by
allowing the results of a calibration to be accepted as valid when the
calibration error of one (or in some cases, two) of the transmitters
exceeds 2.0 percent. We did not intend to introduce an uncertainty
analysis, such as the square root of the sum of the squares, for
quantifying uncertainty.
We are also proposing to amend 40 CFR 98.3(i)(3) to add five
conditions that must be met in order for a source to use assumed values
for temperature and/or total pressure at the flow meter location, based
on measurements of these parameters at a remote location (or
locations).
The owner or operator would have to demonstrate that the
remote readings, when corrected, are truly representative of the actual
temperature and/or total pressure at the flow meter location, under all
expected ambient conditions. Pressure and temperature surveys could be
performed to determine the difference between the readings obtained
with the remote transmitters
[[Page 48751]]
and the actual conditions at the flow meter location.
All temperature and/or total pressure measurements in the
demonstration must be made with calibrated gauges, sensors,
transmitters, or other appropriate measurement devices.
The methods used for the demonstration, along with the
data from the demonstration, supporting engineering calculations (if
any), and the mathematical relationship(s) between the remote readings
and the actual flow meter conditions derived from the demonstration
data would have to be documented in the monitoring plan for the unit
and maintained in a format suitable for auditing and inspection.
The temperature and/or total pressure at the flow meter
must be calculated on a daily basis from the remotely measured values,
and the measured flow rates must then be corrected to standard
conditions.
The mathematical correlation(s) between the remote
readings and actual flow meter conditions must be checked at least once
a year, and any necessary adjustments must be made to the
correlation(s) going forward.
(h) We are proposing to amend 40 CFR 98.3(i)(4) to include an
additional exemption from the calibration requirements of 40 CFR
98.3(i) for flow meters that are used exclusively to measure the flow
rates of fuels used for unit startup or ignition. For instance, a meter
that is used only to measure the flow rate of startup fuel (e.g.,
natural gas) to a coal-fired unit would be exempted. This proposed
revision is modeled after a similar calibration exemption in section
2.1.4.1 of Appendix D to 40 CFR Part 75, for fuel flow meters that
measure startup and ignition fuels. The amount of fuel used for
ignition and startup generally provides a very small percentage of the
annual unit heat input (less than 1 percent in most cases). Therefore,
rigorous calibration of meters used exclusively for startup and
ignition fuels is unnecessary. Paragraph 98.3(i)(4) would be further
amended to clarify that gas billing meters are exempted from the
monitoring plan and record keeping provisions of 40 CFR
98.3(g)(5)(i)(c) and (g)(7), which require, respectively, that a
description of the methods used to quality-assure data from instruments
used to provide data for the GHG emissions calculations be included in
the written monitoring plan, and that maintenance records be kept for
those instruments. We are proposing these changes because operation,
maintenance, and quality assurance of gas billing meters is the
responsibility of the fuel supplier, not the consumer.
(i) We are proposing to amend 40 CFR 98.3(i)(5) to clarify that
flow meters that were already calibrated according to 40 CFR 98.3(i)(1)
following a manufacturer's recommended calibration schedule or an
industry consensus calibration schedule do not need to be recalibrated
by the date specified in 40 CFR 98.3(i)(1) as long as the flow meter is
still within the recommended calibration interval. This paragraph would
also be amended to clarify that the deadline for successive
calibrations would be according to the a manufacturer's recommended
calibration schedule or an industry consensus calibration schedule.
(j) We are proposing to amend 40 CFR 98.3(i)(6) to account for
units and processes that operate continuously with infrequent outages
and cannot meet the flow meter calibration deadline without disrupting
normal process operation. Part 98 currently allows the owner or
operator to postpone the initial calibration until the next scheduled
maintenance outage. The rule did not require shutdown for calibration
of equipment because it was determined to be an unnecessary burden to
require shutdown for calibration given that all measurement equipment
required for GHG emissions would be required to be calibrated if they
did not have an active calibration, necessitating a potentially large
number of shutdowns.
Although the rule allows postponement of calibration, it does not
specify how to report fuel consumption for the entire time period
extending from January 1, 2010 until the next maintenance outage.
Section 98.3(d) of subpart A allows sources to use the ``best available
monitoring methods'' (BAMM) until April 1, 2010, and to petition the
Administrator to continue using the BAMM through December 31, 2010, but
not beyond that date.
In view of this, we are proposing to amend 40 CFR 98.3(i)(6) to
permit sources to use the best available data from company records to
quantify fuel usage until the next scheduled maintenance outage. This
proposed revision would address situations where the next scheduled
outage is in 2011, or later.
C. Subpart A (General Provisions): Reporting of Biogenic Emissions
Reporters have noted that in the final Part 98 a new requirement
was introduced that requires separate reporting of biogenic emissions
from facilities (40 CFR 98.3(c)). They have noted that had EPA sought
comment on this requirement in the proposal, they may have commented
that units subject to subpart D (Electricity Generation) should not be
required to report biogenic emissions separately, as this is not
currently required under Part 75, which generally established the
procedures for measuring data under subpart D. Or, they may have
recommended specific methods for calculating biogenic emissions from
Part 75 units. Owners and operators have stated that it is not clear in
Part 98 which method is required for estimating these emissions from
units subject to subpart D.
EPA has subsequently provided guidance that separate reporting of
biogenic emissions for units subject to subpart D is optional; however,
in order to provide clarity and remove any potential inconsistencies,
we are proposing revisions to subpart A and soliciting comment.
We intended that units subject to subpart D would continue to
monitor and report CO2 mass emissions as required under 40
CFR 75.13 or section 2.3 of apppendix G to 40 CFR part 75, and 40 CFR
75.64. These provisions do not require separate accounting of biogenic
emissions, and we did not intend to require additional accounting
methods for these units under Part 98. We intended for the reporting of
biogenic CO2 emissions to be optional for units subject to
subpart D. However, the current rule does not consistently affirm this.
Section 98.3(c)(4) of subpart A requires sources to report facility-
wide GHG emissions, excluding biogenic CO2, and to report
CO2 emissions for each source category excluding biogenic
CO2. To meet these reporting requirements, facilities with
subpart D and/or other Part 75 units on-site would have to separately
account for the biogenic CO2 emissions (if any) from those
units.
To address these concerns, we are proposing to amend the data
elements in subparts A and C that currently require separate accounting
and reporting of biogenic CO2 emissions so that it would be
optional for Part 75 units. All units, except Part 75 units, would
still be required to calculate and report biogenic CO2
emissions separately under subpart C. We are proposing to amend the
following sections of subparts A and C to reflect these changes:
40 CFR 98.3(c)(4)(i) would be revised to no longer require
facilities to report annual emissions, excluding biogenic
CO2; instead, it would require all owners or operators to
report annual facility-wide emissions, including biogenic
CO2.
[[Page 48752]]
40 CFR 98.3(c)(4)(ii) and (c)(4)(iii)(A) would be amended
to state that separate reporting of biogenic CO2 emissions
is not required for units using part 75 methodologies to calculate
CO2 mass emissions.
40 CFR 98.3(c)(4)(ii)(B) would be revised to no longer
require reporting of the annual CO2 emissions from subparts
C through JJ, excluding biogenic CO2; instead, it would
require reporting of the total annual CO2 emissions for each
subpart, including biogenic CO2.
40 CFR 98.33(a)(5)(iii)(D) would be redesignated as 40 CFR
98.33(a)(5)(iv) and amended to state that separate reporting of
biogenic CO2 emissions is optional for part 75 units that
qualify for and elect to use the alternative CO2 mass
emissions reporting options in 40 CFR 98.33(a)(5).
A statement would be added to 40 CFR 98.33(e) to indicate
that separate reporting of biogenic CO2 emissions is not
required for units subject to subpart D of part 98, and for part 75
units using the alternative CO2 mass emissions reporting
options in 40 CFR 98.33(a)(5). However, if the owner or operator elects
to report biogenic CO2 emissions, the methods in Sec.
98.33(e) would be used.
Three paragraphs of the data reporting section of subpart
C, specifically 40 CFR 98.36(d)(1)(ii), (d)(2)(ii)(I), and
(d)(2)(iii)(I), would be amended to reinforce that separate reporting
of biogenic CO2 emissions is optional for part 75 units.
The proposed amendments would not affect the burden for existing
facilities, as existing non-Part 75 facilities were always required to
calculate and report biogenic emissions separately. The amendments
would simply require them to include those biogenic emissions in
facility-wide and source category (subpart) totals, as opposed to
subtracting them out. The proposed amendments would also address the
inconsistency that appeared in Part 98 regarding separate reporting of
biogenic emissions for electric generating units subject to subpart D
or other units subject to Part 75, as these facilities would no longer
be required to report facility emissions excluding biogenic
CO2, although they retain the option to report biogenic
CO2 separately.
D. Subpart A (General Provisions): Requirements for Correction and
Resubmission of Annual Reports
Subpart A requires that an ``owner or operator shall submit a
revised report within 45 days of discovering or being notified by EPA
of errors in an annual GHG report. The revised report must correct all
identified errors. The owner or operator shall retain documentation for
3 years to support any revisions made to an annual GHG report.''
Some owners and operators have asserted that the requirements for
resubmission of annual reports within 45 days of discovering an error
or being notified by EPA of an error, and the requirement to correct
all errors, is overly broad and could trigger a resubmission for
virtually any error. They were also concerned that these requirements
are made more burdensome by the fact that the data system is not yet
developed, and some identified ``errors'' may not in fact be errors,
but rather software bugs that are most likely to happen in the first
year of operation of the data system. They have also observed that the
regulatory requirement is more burdensome than the Acid Rain Program
(ARP), which has operated for more than 15 years without such a
requirement in the regulation.
We included this correction requirement in Part 98 because we
determined that it is important to ensure that the most accurate data
are available, in a timely fashion, for developing future GHG policies
and programs. Generally, adding a requirement to resubmit data is also
consistent with other EPA reporting programs, such as the ARP and the
Toxic Release Inventory, as well as State and other GHG programs. While
it is true that the ARP does not have a specific time requirement for
resubmission in the regulation, in practice revised data have been
submitted in less than 45 days after notification or identification of
an error. While we maintain that it is important to retain a deadline
for resubmission of the report after an error is identified in order to
ensure EPA receives timely submission of data, we also recognize that
certain circumstances may exist in which owners or operators cannot
correct the identified errors within the 45 days. Therefore, we are
proposing to amend 40 CFR 98.3(h) to clarify how a resubmission is
triggered and the process for resubmitting annual GHG reports.
First, reports would only have to be resubmitted when the owner or
operator or the Administrator determines that a substantive error
exists. A substantive error would be defined as one that impacts the
quantity of GHG emissions reported or otherwise prevents the reported
data from being validated or verified. This clarification is important
because some errors are not significant (e.g., an error in the zip
code) and do not impact emissions. Such ``errors'' would not obligate
the owner or operator to resubmit the annual report.
The owner or operator would be required to resubmit the report
within 45 days of identifying the substantive error, or the
Administrator notifying them of a substantive error, unless the owner
or operator provides information demonstrating that the previously
submitted report does not contain the identified substantive error or
that the identified error is not a substantive error. This proposed
change would provide owners or operators the opportunity to demonstrate
that what the Administrator has deemed to be substantive errors are
not, in fact, substantive errors.
Finally, we are also proposing to introduce the opportunity for
owners or operators to request an extension on the 45-day resubmission
deadline to address facility-specific circumstances that arise in
either correcting an error or determining whether or not an identified
error is, in fact, a substantive error. Owners or operators would be
required to notify EPA by e-mail at least two business days prior to
the end of the 45-day resubmission deadline if they seek an extension.
An automatic 30-day extension would be granted if EPA does not respond
to the extension request by the end of the 45-day period.
We are proposing the opportunity to extend the period for
resubmission in recognition that the data system is still under
development and we do not yet fully know the full range of errors that
will be identified, and therefore the time required to address such
errors. Verification and quality assurance and quality control checks
are currently under development in the data system. Some flags that the
data system might generate will not necessarily reflect substantive
errors, but rather would be flags to alert the owner or operator to
review the submission carefully to make sure the information provided
is correct. On the other hand, some flags could identify substantive
errors that affect the overall GHG emissions reported to EPA. Although
we have concluded that it is important to provide facilities the
opportunity to extend this deadline, we believe that the 45-day time
period is a sufficient time period for the vast majority of facilities.
E. Subpart A (General Provisions): Information To Record for Missing
Data Events
Certain reporters have suggested that the recordkeeping
requirements related to missing data events are overly burdensome.
Specifically, 40 CFR 98.3(g)(4) of Part 98 specifies that the owner or
operator must keep records of the cause and duration of each event, the
actions taken to restore
[[Page 48753]]
malfunctioning monitoring equipment, and actions taken to prevent or
minimize future occurrences. They have asserted that compared to Part
98, Part 75 requires only reporting of the cause of the missing data
event and the corrective actions taken, but does not require separate
accounting of the duration of the event or the actions taken to
minimize occurrence in the future. They have further claimed that most
missing data events associated with the use of continuous emissions
monitors are due to routine activities or calibration failures for
which there are no clear measures to avoid similar occurrences in the
future. Therefore, according to the owners and operators, the final
recordkeeping requirements are overly burdensome and add little value.
After reviewing these requirements, we agree with the claims and we
are proposing to amend 40 CFR 98.3(g)(4) by requiring that records be
kept of only the cause of each missing data event and the corrective
actions taken. We have concluded that this information is sufficient
for operating the program and that making this change will reduce the
reporting burden for all reporters. This proposed revision would make
the Part 98 recordkeeping provisions for missing data events consistent
with those in 40 CFR Part 75 (specifically 40 CFR 75.57(h)). We further
propose to clarify that the records retained pursuant to 40 CFR
75.57(h) may be used to meet the recordkeeping requirements under Part
98 for the same missing data events.
F. Subpart A (General Provisions): Other Technical Corrections and
Amendments
We are proposing several amendments to subpart A, as follows. We
are proposing to amend 40 CFR 98.3(c)(1) by adding a requirement to
report a facility or supplier ID number. We expect to receive GHG
emissions data in electronic format from thousands of facilities and
suppliers. Therefore, a unique ID number must be assigned to each
facility or supplier, for administrative purposes, to facilitate
program implementation. This approach has worked well in other EPA
programs that require electronic data reporting from large numbers of
facilities (e.g., the Acid Rain and NOX Budget Programs).
The exact mechanism for assigning the ID numbers has not yet been
determined. EPA will provide the necessary guidance later this year.
We are proposing to amend the elements required with a certificate
of representation under 40 CFR 98.4(i)(2) to include organization name
(company affiliation-employer). We are also proposing to add the same
element to the delegation by designated representative and alternate
designated representative under 40 CFR 98.4(m)(2). This information
will help EPA and reporting system users to correctly identify persons
during the designated representative appointment or agent delegation
process. Part 98 and the proposed amendments would not require the
designated representative, alternate designated representative or agent
to be an employee of the reporting entity. When a designated
representative further delegates their authority to an agent, the agent
would gain access to all data for that facility or supplier. To
underline the importance of granting access to the correct person, EPA
would require the designated representative (or alternate) to confirm
each agent delegation. Adding organization name to the certificate of
representation and notice of delegation will add a level of assurance
to the confirmation process.
We are proposing to amend 40 CFR 98.3(c)(5)(i) to clarify that for
the purposes of meeting the requirements of this paragraph, suppliers
of industrial flourinated GHGs only need to calculate and report GHG
emissions in mtCO2e for those flourinated GHGs that are
listed in Table A-1. This amendment is proposed because in order to
incorporate additional fluorinated GHGs not listed in Table A-1 into
the supplier's total GHG emissions in mtCO2e, the reporter
would be required to propose a GWP for the gas or use an established
factor developed by the Intergovernmental Panel on Climate Change or
another entity. EPA does not believe it is necessary to require
reporters to develop a GWP for these gases at this time. Further, it is
important to note that these gases would still be required to be
reported under 40 CFR 98.3(c)(5)(ii) (in metric tons of GHG).
Therefore, EPA could calculate mtCO2e emissions from these
gases in the future as GWP's become available or are updated.
Finally, we are proposing to amend 40 CFR Part 98.6 (Definitions)
and 40 CFR Part 98.7 (What Standardized Methods are Incorporated by
Reference into this Part?). We are proposing to add or change several
definitions to Subpart A, which are needed to clarify terms used in
other subparts of Part 98. Similarly, we are proposing to amend 40 CFR
98.7 (incorporation by reference) to accommodate changes in the
standard methods that are allowed by other subparts of the rule.
We are proposing to amend 40 CFR 98.3(d)(3) to correct the year in
which reporters that submit an abbreviated report for 2010 must submit
a full, report from 2011 to 2012. The full report submitted in 2012
will be for the 2011 reporting year.
We are proposing to amend 40 CFR 98.3(f) to correct the cross-
reference from ``Sec. 98.3(c)(8)'' to ``Sec. 98.3(c)(9).''
We are proposing to amend the definitions of several terms in 40
CFR 98.6:
Bulk Natural Gas Liquid,
Distillate fuel oil,
Fossil fuel,
Mscf,
Municipal solid waste or MSW, and
Natural gas.
Bulk Natural Gas Liquid. Owners and operators have objected to the
definition of ``bulk natural gas liquid or NGL.'' Section 98.6 in
subpart A defines ``bulk natural gas liquid or NGL'' as a product which
``refers to mixtures of hydrocarbons that have been separated from
natural gas as liquids through the process of absorption, condensation,
adsorption, or other methods at lease separators and field
facilities.'' The owners and operators have requested we remove the
phrase ``or other methods at lease separators and field facilities''
from the above definition. They assert that these processes are not
simple separation processes, but rather, NGL extraction processes that
are typically performed at ``gas plants'' and not at ``lease separators
and field facilities.''
We agree that the separation processes listed in the definition of
``bulk natural gas liquid or NGL'' are associated with gas plants, and
not lease separators and field facilities. It was not EPA's intent to
require the reporting of emissions associated with these processes at
lease separators and field facilities. In fact, in 40 CFR 98.400, we
specifically state that the supplier category consists only of natural
gas liquids fractionators and local natural gas distribution companies.
Under 40 CFR 98.400(c), we specify that field gathering and boosting
stations, as well as natural gas processing plants that ``separate NGLs
from natural gas * * * but do not fractionate these NGLs into their
constituent products'' do not meet the source category's definition.
Therefore, we are proposing to strike ``lease separators and field
facilities'' from the definition of ``bulk natural gas liquid or NGL,''
as well as from the definition of ``natural gas liquids (NGL)'' for
enhanced clarity. However, we have determined that the words ``or other
methods'' should remain in the above definition because the list of
separation processes listed in the definition (absorption,
condensation, adsorption) is not exhaustive, and other separation/
extraction processes may be employed at some facilities. We do not wish
to exclude the reporting of emissions
[[Page 48754]]
associated with products separated/extracted by means not explicitly
stated in the rule.
Distillate Fuel Oil. We are proposing to expand the definition of
``Distillate fuel oil'' to include kerosene-type jet fuel.
Fossil Fuel. Some reporters have noted that the proposed rule set
forth the same definition of ``fossil fuel'' that applies in the New
Source Performance Standards program: ``Fossil fuel means natural gas,
petroleum, coal, or any form of solid, liquid, or gaseous fuel derived
from such materials for the purpose of creating useful heat'' (74 FR
16621).
However, the final Part 98 includes the following definition,
which, according to certain Parties, has no precedent in Clean Air Act
(CAA) regulations: ``Fossil fuel means natural gas, petroleum, coal, or
any form of solid, liquid, or gaseous fuel derived from such material,
including for example, consumer products that are derived from such
materials and are combusted.''
These owners and operators have asserted that the public did not
have sufficient opportunity to comment on these changes, which
together, they claimed, re-classify municipal solid waste (MSW) and
tires as fossil fuel and could set an unintended precedent for other
CAA programs. Further, they claimed that EPA changed the designation of
MSW and tires from being classified as ``alternative fuels'' in the
proposal to being classified as ``fossil fuel-derived fuels (solid)''
in the final Part 98.
We did not intend to ``re-classify'' MSW and tires between the
proposal and final Part 98 in any meaningful way. Rather, any changes
made were due to the overall restructuring of the General Stationary
Fuel Combustion source category in response to comments and were
intended to expand the use of Tier 1 and Tier 2, and to remove some
requirements that would subject units to Tier 3. Based on the above
concerns, however, it has become apparent that stakeholders believe the
changes had unintended consequences. Therefore, we have reevaluated
this issue and are proposing amendments to the classification of fuels
in Table C-1, as well as the definition of fossil fuel. We note that
overall we do not believe that the changes between the proposed and
final Part 98, nor the amendments described below, have a substantive
impact on the calculation requirements or the reporting of emissions
for MSW or tires under this rule.
We made several changes from proposal in Part 98 in response to
comments about use of the Tiers. In subpart C, in order for facilities
to use Tier 1 or Tier 2, the fuel combusted had to be included in Table
C-1. MSW and tires were not included in Table C-1; rather they were
included in the proposed Table C-2, which was generically labeled
``alternative fuels.'' The restructuring of the Tiers in subpart C
necessitated moving all fuels for which Tier 1 and Tier 2 were allowed
into Table C-1. Table C-1 labeled these fuels as ``fossil fuel-
derived'' to reflect the methods used to calculate emissions, noting
the related provisions for determining the biogenic portions of fuels
in subpart C.
In order to address the above concerns raised with subpart C, we
are now proposing to change the heading for these fuels from ``fossil
fuel-derived'' to ``Other fuels (solid)'' in Table C-1.
Further, we are proposing to amend the definition of fossil fuel to
return to the initial proposed definition. After proposal, we altered
the definition in subpart A intending to provide clarity to facilities
subject to Subpart C in the reporting of CO2 emissions per
the requirements of 40 CFR 98.36, specifically, intending to clarify
what was meant in the proposed definition by `` * * * solid, liquid, or
gaseous fuel derived from such materials.'' We also changed the
definition in subpart A to better align the definition of fossil fuel
with the definition of the general stationary fuel combustion sources
in 40 CFR 98.30 (i.e., ``devices that combust solid, liquid, or gaseous
fuels, 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 materials'').
We believe that the definition included in subpart A may have not
added the clarity expected and that the definition of general
stationary fuel combustion sources provided in subpart C is sufficient.
We are soliciting comment on the proposed changes in the definition of
fossil fuel in subpart A in the context of the calculation methods
provided for these fuels in subpart C, and ask commenters to provide
additional information if they believe that emissions from combusting
these fuels should be estimated differently.
Mscf. We are proposing to amend the definition of ``Mscf'' in 40
CFR 98.6 to indicate that ``Mscf'' means thousand standard cubic feet,
and not, as incorrectly noted in the final rule, a million standard
cubic feet.
Municipal Solid Waste. We have received many questions regarding
the definition of ``Municipal solid waste or MSW'' in Part 98.
Specifically, the brevity of the definition makes it difficult to
determine whether certain types of waste constitute MSW. We are
proposing to amend the definition to closely match the definition of
``municipal solid waste'' in Subpart Ea of the NSPS regulations (40 CFR
60.51a). The amended definition would explain what is meant by
``household waste,'' ``commercial/retail waste,'' and ``institutional
waste.'' It would also provide a comprehensive list of materials that
are excluded from these categories (e.g., industrial process or
manufacturing wastes and medical waste).
Natural Gas. We have also received many questions indicating that
the definition of ``Natural gas'' is too inclusive and in some respects
counterintuitive. The current definition begins with a statement that
natural gas is a naturally occurring mixture of hydrocarbon and non-
hydrocarbon gases found beneath the earth's surface. However, it ends
by equating ``process gas'' and ``fuel gas'' (neither of which is a
naturally occurring gas mixture) with natural gas. We are proposing to
amend the definition of ``Natural gas'' in 40 CFR 98.6 to be consistent
with definitions found in 40 CFR Parts 60 and 75. The amended
definition would remove the references to process gas and fuel gas, and
would specify that natural gas must be at least 70 percent methane or
have a high heat value between 910 and 1150 Btu/scf.
We are proposing to add definitions of the following terms to 40
CFR 98.6 due to the large number of questions received requesting
clarification of the definition of these terms:
Agricultural byproducts,
Primary fuel,
Solid byproducts,
Waste oil, and
Wood residuals.
The terms ``Agricultural byproducts,'' ``Solid byproducts,'' and
``Wood residuals'' are used to describe three types of solid biomass
fuels listed in Table C-1 of Subpart C, but they are not defined in 40
CFR 98.6. The proposed definitions are based on the results of an
Internet search and IPCC inventory guidelines (see EPA-HQ-OAR-2008-
0508). For the purposes of Part 98, ``Agricultural byproducts'' would
include the parts of crops that are not ordinarily used for food (e.g.,
corn straw, peanut shells, pomace, etc.). ``Solid byproducts'' would
include plant matter such as vegetable waste, animal materials/wastes,
and other solid biomass, except for wood, wood waste and sulphite lyes
(black liquor). ``Wood residuals'' would include waste wood
[[Page 48755]]
recovered primarily from MSW streams, construction and demolition
debris, and primary timber processing. Wastewater process sludge
generated at pulp and paper mills would also be included; however, we
are soliciting comment on whether the default emission factors for wood
and wood residuals are appropriate for paper mill wastewater sludge,
and, if not, what those emission factors should be.
``Primary fuel'' would be defined as the fuel that contributes the
greatest percentage of the annual heat input to a combustion unit.
``Waste oil,'' which we are proposing to add to Table C-1 as a new fuel
type, would be defined as oil whose physical properties have changed,
either through storage, handling, or use, so that the oil can no longer
be used for its original purpose. Waste oil would include both
automotive and industrial oils of various types.
G. Subpart C (General Stationary Fuel Combustion)
Numerous issues have been raised by owners and operators in
relation to the requirements in subpart C for general stationary fuel
combustion. The issues being addressed by the proposed amendments
include the following:
Definition of the source category.
GHGs to report.
Calculating GHG emissions.
Natural gas consumption expressed in therms.
Use of Equation C-2b to calculate weighted annual average
HHV.
Categories of gaseous fuels.
Use of mass-based gas flow meters.
Site-specific stack gas moisture content values.
Determining emissions from an exhaust stream diverted from
a CEMS monitored stack.
Biomass combustion in units with CEMS.
Use of Tier 3.
Tier 4 requirements for units that combust greater than
250 tons of MSW per day.
Applicability of Tier 4 to common stack configurations.
Starting dates for the use of Tier 4.
CH4 and N2O calculations.
CO2 emissions from sorbent.
Biogenic CO2 emissions from biomass combustion.
Fuel sampling for coal and fuel oil.
Tier 3 sampling frequency for gaseous fuels.
CO2 emissions from blended fuel combustion.
Use of consensus standard methods.
CO2 monitor span values.
CEMS data validation.
Use of ASTM Methods D7459-08 and D6866-08.
Electronic data reporting and recordkeeping.
Common stack reporting option.
Common fuel supply pipe reporting option.
Table C-1 default HHV and CO2 emission factors.
Table C-2 default CH4 and N2O
emission factors.
Definition of the source category. We are proposing to add a new
paragraph 40 CFR 98.30(d), clarifying that the GHG emissions from a
pilot light need not be included in the emissions totals for the
facility. Section 98.30(a) of subpart C defines a stationary fuel
combustion source as a device that combusts `` * * * 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 * * * ''. A pilot light is a small
permanent auxiliary flame that simply ignites the burner of a
combustion process in a boiler, turbine, or other fuel combustion
device, and is not used to produce electricity or steam, or to provide
useful energy to an industrial process, or to reduce waste by removing
combustible matter. Therefore, we are clarifying that, for the purposes
of Part 98, a pilot light is not considered to be a stationary fuel
combustion source and pilot gas consumption would not be required to be
included in the GHG emissions calculations.
GHGs to Report. We are proposing to amend 40 CFR 98.32 to clarify
that CO2, CH4, and N2O mass emissions
from a stationary fuel combustion unit do not need to be reported under
subpart C if such an exclusion is indicated elsewhere in subpart C.
Calculating GHG emissions. We are proposing to amend 40 CFR
98.33(a) to provide additional detail and clarify who may (or must) use
the calculation methods in the subsequent paragraphs to calculate and
report GHG emissions. Specifically, we are proposing to amend this
paragraph to point out that certain sources may use the methods in 40
CFR part 75 to calculate CO2 emissions, if they are already
using Part 75 to report heat input data year-round under another Clean
Air Act program. Paragraph 98.33(a) would also be amended to clarify
the reporting of CO2 emissions from biomass combustion when
a unit combusts both biomass and fossil fuels.
Natural gas consumption expressed in therms. Subpart C of Part 98
allows the use of fuel billing records to quantify natural gas
consumption, for the purposes of calculating CO2 mass
emissions. On the billing records provided by natural gas suppliers,
fuel usage is often expressed in units of ``therms,'' rather than
standard cubic feet (scf). A therm is equal to 100,000 Btu, or 0.1
mmBtu. Therefore, the equations for calculating CO2 mass
emissions in Subpart C (e.g., Equation C-1), which require fuel usage
to be in units of scf, are not suitable when fuel consumption is
expressed in therms.
In view of this, we are proposing to amend 40 CFR 98.33(a)(1) by
adding a new equation, C-1a, to Tier 1. When natural gas consumption is
expressed in therms, equation C-1a would enable sources to calculate
CO2 mass emissions directly from the information on the
billing records, without having to request or obtain additional data
from the fuel suppliers.
We are proposing to allow Equation C-1a to be used for units of any
size when the fuel usage information on natural gas billing records is
expressed in units of therms. A new paragraph, (b)(1)(v), would be
added to 40 CFR 98.33 to reflect this. Section 98.36(e)(2)(i) would
also be amended to allow gaseous fuel consumption to be reported in
units of therms.
Use of Equation C-2b. Whenever HHV data are received on a monthly
or more frequent basis, the Tier 2 CO2 emissions calculation
methodology requires the owner or operator to use Equation C-2b to
calculate the annual average HHV, weighted according to monthly fuel
usage. The fuel-weighted annual average HHV is then substituted into
Equation C-2a. If HHV data are received less frequently than monthly,
an arithmetic average HHV is used in the emissions calculations (see 40
CFR 98.33(a)(2)(ii)).
However, we have learned that in cases where a facility includes
part 75 units (i.e., boilers and/or combustion turbines) and small
combustion sources such as space heaters that share a common natural
gas or oil supply, the use of Tier 2 may be triggered for the small
combustion sources when the part 75 units use the appendix D
methodology to quantify heat input. This is because appendix D of Part
75 requires periodic sampling of the heating value of fuel oil and
natural gas. Tier 2 will be triggered for the small combustion units if
the Part 75 fuel sampling frequency is equal to or greater than the
minimum frequency specified in Sec. 98.34(a). Further, if the part 75
fuel sampling frequency is monthly or greater, Equation C-2b would have
to be used to calculate fuel-weighted annual average HHVs for the small
combustion sources.
Requiring small, low-emitting combustion sources to calculate
CO2
[[Page 48756]]
mass emissions using fuel-weighted annual average HHVs instead of
arithmetic average values will not significantly enhance data quality.
In view of this, we are proposing to amend 40 CFR 98.33(a)(2)(ii), to
require calculation of a weighted HHV only for individual Tier 2 units
with a maximum rated heat input capacity greater than or equal to 100
mmBtu/hr, and for groups of units that contain at least one unit of
that size. For Tier 2 units smaller than 100 mmBtu/hr and for
aggregated groups of Tier 2 units under Sec. 98.36(c)(1) in which all
units in the group are smaller than 100 mmBtu/hr, the annual arithmetic
average HHV, rather than the annual fuel-weighted average HHV, would be
used in Equation C-2a.
Categories of Gaseous Fuels. Section 98.34(a)(2)(iii) of subpart C
requires quarterly HHV sampling for liquid fuels other than fuel oil,
for fossil fuel-derived gaseous fuels, and for biogas, when the Tier 2
methodology is used to calculate CO2 mass emissions. The
term ``fossil fuel-derived gaseous fuels'' has caused considerable
confusion among regulated sources. The nomenclature and organization of
Table C-1 of Subpart C makes it hard to determine which fuels are
included in this category. Currently, only two fuels are listed in
Table C-1 under the heading of fossil fuel-derived gaseous fuels: blast
furnace gas and coke oven gas. However, a number of other gaseous fuels
that are derived from petroleum, such as butane, are not listed there,
but are listed under a different heading for ``petroleum products.''
We are proposing to revise 40 CFR 98.33(a)(2)(iii) by replacing the
term ``fossil fuel-derived gaseous fuels'' with a more inclusive term,
i.e., ``gaseous fuels other than natural gas.'' Corresponding changes
would also be made to Table C-1 for consistency, placing blast furnace
gas, coke oven gas, fuel gas, and propane in a new category, ``Other
fuels (gaseous).''
Use of Mass-Based Gas Flow Meters. The Tier 3 CO2
emissions calculation methodology in 40 CFR 98.33(a)(3) currently
allows flow meters that measure mass flow rates of liquid fuels to be
used to quantify fuel consumption, provided that the density of the
fuel is determined and the measured mass of fuel is converted to units
of volume (i.e., gallons), for use in Equation C-4. In response to a
number of requests, we are proposing to amend 40 CFR 98.33(a)(3)(iv),
to conditionally allow flow meters that measure mass flow rates of
gaseous fuels to be used for Tier 3 applications. To use mass flow
meters, the density of the gaseous fuel would have to be measured,
either with a calibrated density meter or by using a consensus standard
method or standard industry practice, in order to convert the measured
mass of fuel to units of standard cubic feet, for use in Equation C-5.
Site-Specific Stack Gas Moisture Content Values. The Tier 4
calculation methodology in 40 CFR 98.33(a)(4) requires a CO2
CEMS to be used together with a stack gas flow rate monitor to measure
CO2 mass emissions. If the CO2 monitor measures
on a dry basis, corrections for the stack gas moisture content are
needed, because the flow monitor measures on a wet basis.
Part 98 currently requires that the moisture corrections be made
either by installing a continuous moisture monitoring system or by
using a default moisture value from 40 CFR Part 75 (specifically 40 CFR
75.11(b)(1)) in the calculations. However, the default moisture
constants from Part 75 only apply to various grades of coal, and to
wood and natural gas.
Recently, we have received inquiries from a number of sources that
currently have dry-basis CO2 monitors in place and are
required to use Tier 4. These sources have requested that EPA allow the
use of site-specific default moisture values, in cases where no
applicable default value is specified in Part 75 for the type(s) of
fuel(s) combusted, or where the Part 75 moisture values are believed to
be unrepresentative.
EPA has approved many petitions for site-specific moisture content
default values under the ARP. Therefore, we believe it is reasonable to
allow Part 98 sources to develop such default values, using an approach
similar to the one that has been approved under the ARP.
In view of this, we are proposing to amend 40 CFR 98.33(a)(4)(iii)
to allow the use of site-specific moisture constants under the Tier 4
methodology. The site-specific moisture default value(s) would have to
represent the fuel(s) or fuel blends that are combusted in the unit
during normal, stable operation, and would have to account for any
distinct difference(s) in stack gas moisture content associated with
different process operating conditions.
For each site-specific default moisture percentage, at least nine
runs would be required using EPA Method 4--Determination Of Moisture
Content In Stack Gases (40 CFR Part 60, Appendix A-3). Moisture data
from the relative accuracy test audit (RATA) of a CEMS could be used
for this purpose. Each site-specific default moisture value would be
calculated by taking the arithmetic average of the Method 4 runs.
Each site-specific moisture default value would be updated at least
annually, and whenever the current value is believed to be non-
representative, due to changes in unit or process operation. The
updated moisture value would be used in the subsequent CO2
emissions calculations.
Determining Emissions from an Exhaust Stream Diverted from a CEMS
Monitored Stack. We are proposing to amend 40 CFR 98.33(a)(4) by adding
a new paragraph, (a)(4)(viii), to address the determination of
CO2 mass emissions from a unit subject to the Tier 4
calculation methodology when a portion of the flue gases generated by
the unit exhaust through a stack that is not equipped with a CEMS to
measure CO2 emissions (herein referred to as an
``unmonitored stack'') The paragraph is intended to address situations
where a portion of the stack gas generated by the Tier 4 unit is
diverted for the purpose of drying fuels, recovering heat, or some
other process-related activity. The provisions of the new paragraph
would not apply when CO2 is removed or chemically altered in
a way that significantly changes the CO2 concentration at
the outlet of the unmonitored stack, compared to the outlet
CO2 concentration at the stack equipped with a CEMS. The
owner or operator would be required to use the best available
information to estimate the hourly stack gas volumetric flow rates
exhausting through the unmonitored stack. Best available information
would include, but would not be limited to, correlation of operating
parameters with flow rate, periodic flow rate measurements made with
EPA Method 2, engineering analysis, etc. The estimated flow rates of
the diverted gas stream would be made at the point where the diverted
stream exits the main flue gas exhaust system. Each hourly volumetric
flow rate value used in Equation C-6 of Subpart C would be the sum of
the flow rate measured at the stack equipped with a CEMS and the
estimated flow rate of the diverted gas stream. All procedures used to
estimate the volumetric flow rate of the diverted gas stream would be
documented in the monitoring plan required under 40 CFR 98.3(g)(5).
Biomass Combustion in Units With CEMS. We are proposing to amend 40
CFR 98.33(a)(5)(iii)(D) to redesignate it as 40 CFR 98.33(a)(5)(iv).
This is to correct a paragraph numbering error in subpart C, because
this paragraph applies to all of 40 CFR 98.33(a)(5) and not just to 40
CFR 98.33(a)(5)(iii). As discussed above in section II.C of the
preamble, we are also proposing to amend 40 CFR 98.3(c) in subpart A
and
[[Page 48757]]
40 CFR 98.33(a)(5) to clarify that the separate reporting of biogenic
CO2 is optional for units that are not subject to the Acid
Rain Program, but are using Part 75 methodologies to calculate
CO2 mass emissions, as described in 40 CFR 98.33(a)(5)(i)
through (a)(5)(iii). As discussed above, separate reporting of biogenic
CO2 emissions is also optional for units subject to subpart
D.
Use of Tier 3. Section 98.33(b)(3)(iii) of subpart C currently
requires the use of Tier 3 when a fuel that is not listed in Table C-1
of Subpart C is combusted in a unit with a maximum rated heat input
capacity greater than 250 mmBtu/hr, if two conditions are met: (a) The
use of Tier 4 is not required; and (b) the fuel provides at least 10
percent of the annual heat input to the unit.
However, 40 CFR 98.33(b)(3)(iii)(B) refers to the annual heat input
to a group of units served by a common supply pipe, in addition to the
heat input to an individual unit. The text of 40 CFR 98.33(b)(3)(iii)
is not consistent with 40 CFR 98.33(b)(3)(iii)(B) because it does not
mention common pipe configurations.
We are proposing to amend 40 CFR 98.33(b)(3)(iii) to clarify that
the paragraph applies also to common pipe configurations where at least
one unit served by the common pipe has a heat input capacity greater
than 250 mmBtu/hr.
The Agency also proposes to add a new paragraph, (b)(3)(iv), to 40
CFR 98.33, requiring Tier 3 to be used when specified in another
subpart of Part 98, regardless of fuel type or unit size. For example,
Subpart Y requires certain units that combust refinery fuel gas (RFG)
to use Equation C-5 in Subpart C (which is the Tier 3 equation for
gaseous fuel combustion) to calculate CO2 mass emissions,
without regard to unit size.
Tier 4 Requirements for Units That Combust Greater Than 250 Tons of
MSW per Day. Owners and operators of units that combust municipal solid
waste have contended that, because Part 98 requires that units that
combust MSW must follow Tier 4 if they meet the requirements in 40 CFR
98.33(b)(4)(ii) or 40 CFR 98.33(b)(4)(iii), it entails a
disproportionate burden for municipal waste combustors (MWCs). One
element of their argument was that a threshold of greater than 250 tons
per day of MSW was a more stringent threshold than the 250 mmbtu/hr
heat input threshold for other stationary combustion units and,
therefore, a disproportionate burden for MWCs. Further, they stated
that the industry did not have the necessary emission monitoring
equipment in place and would, therefore, be required to install new
equipment in order to meet the requirements of the rule.
Part 98 included a threshold of 250 tons of MSW per day because it
was consistent with the threshold applied in the EPA New Source
Performance Standards (NSPS). Under that program, units combusting
greater than 250 tons per day of MSW are considered ``large'' units. We
did not believe that subpart C applied a disproportionate burden to
municipal waste combustors because all ``large'' units (whether 250
tons of MSW per day or with a heat input capacity greater than 250
mmBtu/hr) would only be subject to Tier 4 if they met the other
conditions outlined in 40 CFR 98.33(b)(4). We have reevaluated this
issue based on the fact that while a threshold of 250 tons of MSW may
be appropriate for the purposes of NSPS, it is not necessarily
appropriate for a GHG emissions reporting program. We also recognize
that a large majority of the units may have to install either a flow
meter or a concentration monitor, and in some cases both, to comply
with subpart C.
Based on these concerns, we are proposing to amend 40 CFR
98.33(b)(4)(ii)(A) to change the 250 tons MSW per day threshold to 600
tons MSW per day, based on further analysis that this value is
approximately equivalent to the 250 mmBtu/hr heat input requirements
for other large stationary combustion units. For more information,
please refer to the Background Technical Support Document (EPA-HQ-OAR-
2008-0508). Units less than 600 tons MSW per day, that do not meet the
requirements in 40 CFR 98.33(b)(4)(iii) could use Tier 2. We believe
that this proposal still meets the desired goal to obtain high quality
data from larger units, while not applying unnecessary burden. With
this proposed amendment, MWCs would be subject to comparable monitoring
thresholds and conditions as other general stationary combustion units.
Applicability of Tier 4 to Common Stack Configurations. Section
98.36(c)(2) of Subpart C allows the owner or operator of stationary
combustion units that share a common stack (or duct) and use the Tier 4
methodology to calculate CO2 mass emissions to continuously
monitor and report the combined CO2 mass emissions at the
common stack (or duct), in lieu of separately monitoring and reporting
the CO2 emissions from the individual units.
Several other Subparts of Part 98 either: (1) Allow a particular
process or manufacturing unit to use Tier 4 to quantify CO2
mass emissions, as an alternative to using a mass balance approach (for
instance, Subpart G allows this option for an ammonia manufacturing
unit--see 40 CFR 98.73(a) and (b)); or (2) require Tier 4 to be used in
certain instances when a process unit and a stationary combustion unit
share a common stack (e.g., see 40 CFR 98.63(g) and 98.73(c)).
Subpart C sets forth the applicability of Tier 4 in 40 CFR
98.33(b)(4)(ii) and (b)(4)(iii). However, note that 40 CFR 98.33(b)(4)
focuses exclusively on individual stationary fuel combustion units; no
mention is made of common stack configurations.
In view of this, we are proposing to amend 40 CFR 98.33(b)(4) by
adding provisions to clarify how the Tier 4 criteria apply to common
stack configurations. Paragraph (b)(4)(i) would be expanded to include
monitored common stack configurations that consist of stationary
combustion units, process units, or both types of units. A new
paragraph, (b)(4)(iv) would also be added, describing the following
three distinct common stack configurations to which Tier 4 might apply.
The first, most basic configuration is one in which the combined
effluent gas streams from two or more stationary fuel combustion units
are vented through a monitored common stack (or duct). In this case,
Tier 4 would apply if:
There is at least one large unit in the configuration that
has a maximum rated heat input capacity greater than 250 mmBtu/hr or an
input capacity greater than 600 tons/day of MSW (as applicable);
At least one large combustion unit in the configuration
meets the conditions of 40 CFR 98.33(b)(4)(ii)(A) through
(b)(4)(ii)(C); and
The CEMS installed at the common stack (or duct) meets all
of the requirements of 40 CFR 98.33 (b)(4)(ii)(D) through
(b)(4)(ii)(F).
Tier 4 would also apply when all of the combustion units in the
configuration are small (<= 250 mmBtu/hr or <= 600 tons/day of MSW), if
at least one of the units meets the conditions of 40 CFR
98.33(b)(4)(iii).
The second configuration is one in which the combined effluent gas
streams from a stationary combustion unit and a process or
manufacturing unit are vented through a common stack or duct. Many
subparts of part 98 describe this situation (see subparts F, G, K, Q,
Z, BB, EE, and GG). In this case, the use of Tier 4 would be required
if the stationary combustion unit and the monitors installed at the
common stack or duct meet the applicability criteria of 40 CFR
98.33(b)(4)(ii) or 98.33(b)(4)(iii). If multiple stationary combustion
units
[[Page 48758]]
and a process unit (or units) are vented through a common stack or
duct, Tier 4 would be required if at least one of the combustion units
and the monitors installed at the common stack or duct meet the
conditions of 40 CFR 98.33(b)(4)(ii) or 98.33(b)(4)(iii).
The third configuration is one in which the combined effluent
streams from two or more process or manufacturing units are vented
through a common stack or duct. In this case, if any of these units is
required to use Tier 4 under an applicable subpart of Part 98, the
owner or operator could either monitor the CO2 mass
emissions at the Tier 4 unit(s) before the effluent streams are
combined together, or monitor the combined CO2 mass
emissions from all units at the common stack or duct. However, if it is
not feasible to monitor the individual units, the combined
CO2 mass emissions would have to be monitored at the common
stack or duct, using Tier 4.
Starting Dates for the Use of Tier 4. Section 98.33(b)(5) of
subpart C currently states that units that are required to use the Tier
4 methodology must begin using it on January 1, 2010 if all required
CEMS are in place. Otherwise, use of Tier 4 begins on January 1, 2011,
and Tier 2 or Tier 3 may be used to report CO2 mass
emissions in 2010. Recently, a number of sources have asked EPA whether
Tier 4 may be used prior to January 1, 2011 if the required CEMS are
certified some time in 2010, or whether Tier 2 or Tier 3 must be used
for the entire year.
We believe that it is reasonable for sources to begin reporting
CO2 emissions data prior to 2011 from CEMS that successfully
complete certification testing in 2010. Therefore, we are proposing to
amend 40 CFR 98.33(b)(5) accordingly. Note that changes in methodology
during a reporting year are allowed by Part 98, and must be documented
in the annual GHG emissions report (see 40 CFR 98.3(c)(6)).
The proposed revisions would allow sources to discontinue using
Tier 2 or 3 and begin reporting their 2010 emissions under Tier 4 as of
the date on which all required certification tests are passed. CEMS
data recorded during the certification test period could also be used
for Part 98 reporting, provided that: (a) All required certification
tests are passed in sequence, with no test failures; and (b) no
unscheduled maintenance or repair of the CEMS is required during the
test period.
We are also proposing to amend 40 CFR 98.33(b)(5) by adding a new
paragraph, (b)(5)(iii), to address situations where the owner or
operator of an affected unit that has been using Tier 1, 2, or 3 to
calculate CO2 mass emissions makes a change that triggers
Tier 4 applicability by changing: (1) The primary fuel, (2) the manner
of unit operation, or (3) the installed continuous monitoring
equipment. In such cases, the owner or operator would be required to
begin using Tier 4 no later than 180 days from the date on which the
change is implemented. This would allow adequate time for the owner or
operator to obtain and/or certify any of the required Tier 4 continuous
monitors.
Methane and Nitrous Oxide Calculations. The equations for
calculating CH4 and N2O emissions from stationary
combustion sources are found in 40 CFR 98.33(c). Calculation of these
emissions is required only for fuels listed in Table C-2 of Subpart C.
When either the Tier 1 or the Tier 3 methodology is used to determine
CO2 mass emissions, Equation C-8 is used to calculate
CH4 and N2O emissions. Equation C-8 includes the
term ``HHV,'' which is defined as the applicable default high heat
value (HHV) from Table C-1 for a particular type of fuel. Owners and
operators have asserted that they should be able to use actual HHV data
for Tier 3 units, in lieu of using the Table C-1 default values, and
noted that site-specific values would be more accurate.
We agree that this would result in more accurate estimates of
emissions and are proposing to revise the definition of the term
``HHV'' in the Equation C-8 nomenclature. The proposed amendment would
allow Tier 3 units to use actual HHV data to calculate CH4
and N2O emissions. If multiple HHV values are obtained
during the year, the arithmetic average would be used in Equation C-8.
Units that monitor heat input year-round according to 40 CFR Part
75 or that use the Tier 4 CO2 calculation methodology are
required to use Equation C-10 in Subpart C to calculate CH4
and N2O emissions. When more than one type of fuel listed in
Table C-2 is combusted in these units during normal operation, 40 CFR
98.33(c)(4)(ii) requires Equation C-10 to be used separately for each
fuel.
Owners and operators have asked EPA to clarify what is meant by
``normal operation,'' and whether any fuel(s) should be excluded from
the emissions calculations. Today's proposed amendments would clarify
the Agency's intent by removing the term ``normal operation'' from 40
CFR 98.33(c)(4)(i) and (c)(4)(ii). Therefore, calculation of
CH4 and N2O emissions would simply be required
for each Table C-2 fuel combusted in the unit during the reporting
year.
We are also proposing to further amend 40 CFR 98.33(c)(4)(ii), to
allow additional reporting flexibility for certain units that combust
more than one type of fuel; specifically, for units that report heat
input data to EPA year-round using part 75 CEMS. For all multi-fuel
units that use CEMS to comply with Part 98, subpart C requires the
``best available information'' to be used to determine the percentage
of the annual unit heat input contributed by each type of fuel, for the
purposes of calculating CH4 and N2O mass
emissions.
For part 75 units that use CEMS to quantify unit heat input, the
fuel-specific annual heat input values needed for the CH4
and N2O emissions calculations can, in most cases, be
determined from information in the part 75 electronic data reports--
specifically, from the ``F-factors'' reported for each unit operating
hour. These F-factors, which are fuel-specific, are used in the hourly
heat input calculations. Therefore, it is possible to use the reported
F-factors to group the annual unit operating hours according to fuel
type, and to sum the reported hourly heat input values for each group.
However, if the owner or operator elects to use the reporting option in
section 3.3.6.5 of part 75, appendix F, the fuel-specific heat input
values cannot be determined from the emissions reports. This is because
section 3.3.6.5 of appendix F allows the owner or operator to calculate
all hourly heat input values using the ``worst-case'' (highest) F-
factor for any fuel combusted in the unit. A situation where this
reporting option is likely to be implemented is for a coal-fired
utility boiler that uses small amounts of natural gas for unit startup.
A second example where the worst-case F-factor option is sometimes used
is for a unit that combusts a blend of bituminous coal and sub-
bituminous coal, in varying proportions. The F-factors for these two
grades of coal are nearly the same. For the examples cited, the impact
on the reported annual unit heat input is generally very small (1 to 2
percent at most). In view of this, we are proposing to allow part 75
units that use the worst-case F-factor reporting option to attribute
100 percent of the unit's annual heat input to the fuel with the
highest F-factor, as though it were the only fuel combusted during the
report year.
For Tier 4 units, the requirement to use the best available
information to determine the annual heat input from each type of fuel
is being retained in 40
[[Page 48759]]
CFR 98.33(c)(4)(i), and we are proposing to allow it under 40 CFR
98.33(c)(4)(ii)(D) as an alternative for part 75 units, in cases where
fuel-specific heat input values cannot be determined directly from the
part 75 electronic data reports.
Carbon Dioxide Emissions from Sorbent. Section 98.33(d) of subpart
C currently requires the following sources to use Equation C-11 to
calculate and report CO2 mass emissions from sorbent, except
where the total CO2 emissions are measured using CEMS: (a)
Fluidized bed combustion units; (b) units with wet flue gas
desulfurization (FGD) systems; and (c) units equipped with ``other acid
gas emission controls with sorbent injection.'' Equation C-11 includes
the term ``R,'' which is defined as ``1.00, the calcium to sulfur
stoichiometric ratio.''
Industry members have noted that some sorbents that reduce acid gas
emissions do not produce CO2 (for instance,
Ca(OH)2 does not). Further, the 1.00 value of R in Equation
C-11 applies only to SO2 removal, indicating that one mole
of CO2 is produced for every mole of SO2 removed.
We have also been informed that CO2-producing sorbents such
as sodium bicarbonate are sometimes injected to remove other acid gas
species (e.g., HCl).
In view of these considerations, we are proposing to amend 40 CFR
98.33(d) by making it more generally applicable to different types of
CO2-producing sorbents. The term ``R'' would be redefined as
the number of moles of CO2 released upon capture of one mole
of acid gas. When the sorbent is CaCO3, the value of R would
be 1.00. For other CO2-producing sorbents, a specific value
of R would be determined by the reporting facility from the chemical
formula of the sorbent and the chemical reaction with the acid gas
species that is being removed.
Biogenic CO2 Emissions From Biomass Combustion. In
response to questions about the methodologies in 40 CFR 98.33(e) for
calculating biogenic CO2 mass emissions from biomass
combustion, we are proposing a number of technical corrections and
clarifications to that section of the rule.
The title and introductory text of 40 CFR 98.33(e) would be amended
to more precisely define the requirements for reporting biogenic
CO2 emissions. In general, biogenic CO2 emissions
reporting would be required only for the combustion of the biomass
fuels listed in Table C-1 and for municipal solid waste (which consists
partly of biomass and partly of fossil fuel derivatives).
We are also proposing to amend 40 CFR 98.33(e) to describe three
cases in which units that combust biomass would not need to report
biogenic CO2 emissions separate from total CO2
emissions:
1. If a biomass fuel is not listed in Table C-1, the biogenic
CO2 emissions would need to be reported separately from
total CO2 emissions only if:
-- The fuel is combusted in a large unit (greater than 250 mmBtu/hr
heat input capacity);
--The biomass fuel accounts for 10 percent or more of the annual heat
input to the unit; and
--The unit does not use CEMS to quantify its annual CO2 mass
emissions.
In that case, according to 40 CFR 98.33(b)(3)(iii), Tier 3 would
have to be used to determine the carbon content of the biomass fuel and
to calculate the biogenic CO2 emissions.
2. If a unit is subject to Subpart C or D and uses the
CO2 mass emissions calculation methodologies in 40 CFR Part
75 to satisfy the Part 98 reporting requirements, the reporting of
biogenic CO2 emissions would be optional.
3. For the combustion of tires, which are also partly biogenic
(typically 10-20 percent biomass, for car and truck tires), separate
reporting of the biogenic CO2 emissions would be optional,
but could be done following provisions in 40 CFR 98.33(e).
We are proposing to amend 40 CFR 98.33(e)(1) by removing the
restriction against using Tier 1 to calculate biogenic CO2
emissions on units that use CEMS to measure the total CO2
mass emissions. There is no technical basis for this restriction,
provided that biomass consumption can be accurately quantified.
However, the use of Tier 1 would not be allowed for combustion of MSW,
as originally specified in 40 CFR 98.33(e)(1) of subpart C, and would
also not be allowed for the combustion of tires, if biogenic
CO2 emissions are calculated for tires.
We are proposing to amend the methodology in 40 CFR 98.33(e)(2),
which is specifically for units using a CEMS to measure CO2
mass emissions, by:
1. Limiting it to cases where the CO2 emissions measured
by the CEMS are solely from combustion, i.e., the stack gas contains no
additional process CO2 or CO2 from sorbent; and
2. Prohibiting its use if the unit combusts MSW or tires.
Section 98.33(e)(2) of subpart C currently requires the total
volume of CO2 produced from fossil fuel combustion (which is
based on estimated fuel usage, measured HHVs and F-factors) to be
subtracted from the total volume of CO2 from the combustion
of all fuels (as determined from the CEMS data). The difference is
assumed to be the volume of biogenic CO2. However, this
approach is only viable if all of the CO2 emissions are from
the combustion of fossil fuels and biomass, and if no fuels (such as
MSW and tires) that are a mixture of biomass and fossil fuel
derivatives are combusted in the unit.
If there are any process CO2 emissions or CO2
emissions from sorbent in the stack effluent, the volumes of those
CO2 emissions would have to be subtracted from the total
volume of CO2 derived from the CEMS data in order to
determine the biogenic CO2 volume. Further, if any partly
biogenic fuels (such as MSW and tires) are combusted in the unit, the
fossil component of each of these fuels would have to be characterized.
We are not aware of any method that is economically feasible for
reporting sources to determine the mass percentage of the fossil fuel
component of fuels such as MSW and tires. In addition, we are not aware
of any practical method for quantifying CO2 volumes from
sorbent or from non-combustion industrial processes. For these reasons,
we are proposing restrictions ``1'' and ``2'' above on the use of the
methodology in 40 CFR 98.33(e)(2).
For sources that are combusting MSW, we are proposing to amend 40
CFR 98.33(e)(3) to require the use of ASTM methods D7459-08 and D6866-
08 quarterly, as described in 40 CFR 98.34(d), when any MSW is
combusted, either as the primary fuel or as the only fuel with a
biogenic component. We are proposing to further amend 40 CFR
98.33(e)(3) to allow the ASTM methods to be used, as described in 40
CFR 98.34(e), for any unit in which biogenic (or partly biogenic)
fuels, and non-biogenic fuels are combusted, in any proportions.
We are also proposing to delete and reserve 40 CFR 98.33(e)(4) and
the related subparagraphs. Although 40 CFR 98.33(e)(4) allows the ASTM
methods to be used to determine biogenic CO2 emissions for
various combinations of biogenic and fossil fuels, we are proposing to
delete and reserve it because the paragraph also includes an
unnecessary restriction, i.e., it only applies to units that use CEMS
to measure total CO2 mass emissions. The proposed amendments
to 40 CFR 98.33(e)(3) described above would achieve the same intended
purpose as 40 CFR 98.33(e)(4), without imposing this restriction, so 40
CFR 98.33(e)(4) is no longer needed.
Finally, we are proposing to amend 40 CFR 98.33(e)(5) so that it
would also
[[Page 48760]]
apply to units that are using Tier 2 (Equation C-2a), as well as Tier 1
(Equation C-1), for calculating biogenic CO2 mass emissions.
The approach in 40 CFR 98.33(e)(5) for estimating solid biomass fuel
consumption is equally applicable to units using those two equations to
calculate biogenic CO2 emissions. Equation C-2a would apply
when HHV data for a biomass fuel are available at the minimum frequency
specified in 40 CFR 98.34(a)(2).
Fuel Sampling for Coal and Fuel Oil. We are proposing to amend 40
CFR 98.34(a)(2), to clarify the frequency at which the HHV needs to be
determined for different types of fuels.
In subpart C, the Tier 2 calculation methodology in 40 CFR
98.33(a)(2) requires periodic fuel sampling and analysis to determine
HHVs. Section 98.34(a)(2) specifies the minimum required sampling
frequency for various fuel types. For coal and fuel oil, at least one
representative sample must be obtained and analyzed for each fuel lot.
A ``fuel lot'' is defined as a shipment or delivery of a particular
type of fuel, and may consist of a ship load, a barge load, a group of
trucks, or a group of railroad cars.
Several reporters have noted that some facilities receive fuel
deliveries by truck, rail or pipeline quite frequently--even daily in
some cases. The reporters have expressed the concern that, under
subpart C, daily fuel deliveries appear to trigger a requirement for
daily sampling and analysis, according to the definition of a fuel lot.
Reporters have also noted that coal and petroleum derivatives such as
coke and petroleum coke are often delivered in lots. Further, the
Agency has received inquiries asking why a commonly-used fuel oil
sampling strategy is not included in subpart C, i.e., taking a sample
whenever oil is added to the storage tank.
It is not our intent to require an excessive amount of HHV sampling
for coal and fuel oil (or for any other solid or liquid fuel that is
delivered in lots), or to prohibit the use of viable sampling options.
Therefore, we are proposing, first, to amend 40 CFR 98.34(a)(2)(ii) to
expand the list of fuels for which sampling of each fuel lot is
sufficient to include other solid or liquid fuels that are delivered in
lots.
Second, we are proposing to more precisely define the term ``fuel
lot'' in 40 CFR 98.34(a)(2)(ii), as it pertains to facilities that
receive multiple deliveries of a particular fuel from the same supply
source each month, either by truck, rail, or pipeline. The proposed
amendment would clarify that a fuel lot consists of all of the
deliveries for a given calendar month. Thus, for these facilities, the
required HHV sampling frequency would be no greater than once per
month. We are proposing to add parallel language to 40 CFR
98.34(b)(3)(ii), the Tier 3 fuel sampling provisions for coal and fuel
oil, for consistency with the proposed revisions to 40 CFR
98.34(a)(2)(ii).
Third, we are proposing to further revise 40 CFR 98.34(a)(2)(ii)
and 98.34(b)(3)(ii) to allow manual oil samples to be taken after each
addition of oil to the storage tank. Daily manual sampling, flow-
proportional sampling, and continuous drip sampling would also be
allowed.
Tier 3 Sampling Frequency for Gaseous Fuels. Section
98.34(b)(3)(ii) of subpart C specifies the minimum required frequency
for determining the carbon content and molecular weight of various
types of fuel, when using the Tier 3 methodology to calculate
CO2 mass emissions. For gaseous fuels, daily sampling is
required if ``the necessary equipment is in place to make these
measurements.'' Otherwise, weekly sampling is required.
EPA has received a number of questions from owners and operators
about the meaning of ``necessary equipment.'' In particular, sources
have asked whether this refers only to continuous, on-line equipment
such as gas chromatographs, or whether daily, manual sampling is
required where such capability exists.
We are proposing to amend 40 CFR 98.34(b)(3)(ii)(E) to clarify that
daily sampling of gaseous fuels for carbon content and molecular weight
is only required where continuous, on-line equipment is in place;
weekly sampling would be required in all other cases. This has always
been the Agency's intent.
CO2 Emissions From Blended Fuel Combustion. One of the
most frequently asked questions by the regulated community since the
October 30, 2009 publication of Part 98 is, ``How does one calculate
CO2 mass emissions from the combustion of blended fuels?''
Subpart C provided only limited guidance on this issue. First, 40 CFR
98.34(a)(3) stated that when different types of fuel are blended (e.g.,
different ranks of coal or different grades of fuel oil), two options
could be used for determining the HHV for Tier 2 applications: (a) Use
a weighted HHV in the emissions calculations; or (b) take a
representative sample of the blend and analyze it for HHV. Second, 40
CFR 98.34(b)(3)(v) stated that these same two options apply to carbon
content and molecular weight determinations under Tier 3. Third, for
Tier 3 common pipe applications, 40 CFR 98.34(b)(1)(vi) required that
fuels either be metered individually before blending, or that the
blended fuel and a subset of the individual fuels be metered so that
the volume of each fuel in the blend can be determined.
Based on the number of questions received, we have concluded that
these rule provisions do not adequately address the complexities
associated with blended fuels. Therefore, we are proposing substantive
amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v). The
proposed amendments would make a clear distinction between cases where
the mass or volume of each fuel in the blend is accurately measured
prior to mixing (e.g., using individual flow meters for each component)
and cases where the exact composition of the blend is not known. In the
former case, the fact that the fuels are blended is of no consequence;
because the exact quantity of each fuel in the blend is known, the
CO2 emissions from combustion of each component would be
calculated separately. In the latter case, we are proposing that the
blend be considered to be a distinct ``fuel type,'' and that its mass
or volume and essential properties (e.g., HHV, carbon content, etc.) be
measured at a prescribed frequency.
When the mass or volume of each individual component of a blend is
not precisely known prior to mixing, the appropriate method used to
calculate the CO2 mass emissions from combustion of the
blend would be as follows. For smaller combustion units (heat input
capacity not more than 250 mmBtu/hr), we are proposing that Tier 2 (or
possibly Tier 1) be used when all components of the blend are listed in
Table C-1 of Subpart C. In order to perform these CO2
emissions calculations for the blend, a reasonable estimate of the
percentage composition of the blend would be required, using the best
available information (e.g., from the typical or expected range of
values of each component). A heat-weighted CO2 emission
factor would be calculated, using proposed Equation C-16. For Tier 1
applications, a heat-weighted default HHV would also have to be
determined, using proposed Equation C-17.
In cases where a fuel blend consists of a mixture of fuel(s) listed
in Table C-1 and fuel(s) not listed in Table C-1, calculation of
CO2 and other GHG emissions from combustion of the blend
would be required only for the Table C-1 fuel(s), using the best
available estimate of the mass or volume percentage(s) of the Table C-1
fuel(s) in the blend. In these cases, the use of Tier 1 would be
required, with modifications to certain terms in Equations C-17 and
[[Page 48761]]
C-1, to account for the fact that the blend is not composed entirely of
Table C-1 fuels. An example calculation is provided in proposed 40 CFR
98.34(a)(3)(iv).
For larger combustion units (heat input capacity greater than 250
mmBtu/hr) that do not qualify to use Tier 1 or 2, we are proposing that
the owner or operator would use Tier 3 to calculate the CO2
mass emissions from combustion of a blended fuel. The mathematics for
Tier 3 would be much simpler than for Tiers 1 and 2, since no default
values are used in the calculations, and an estimate of the percentage
composition of the blend is not required. To apply Tier 3, the only
requirements would be to accurately measure the annual consumption of
the blended fuel and to determine its carbon content and (if necessary)
molecular weight, at a prescribed frequency. By considering the blended
fuel to be a distinct ``fuel type,'' in cases where that fuel is not
listed in Table C-1, GHG emissions reporting would be required in
accordance with 40 CFR 98.33(b)(3)(iii), if the blended fuel (as
opposed to each individual component of the blend) provides at least 10
percent of the annual heat input to a unit or group of units, and if
the use of Tier 4 is not required.
To address the calculation of CH4 and N2O
mass emissions from the combustion of blended fuels, we are proposing
to add a new paragraph, (c)(6), to 40 CFR 98.33. Calculation of
CH4 and N2O emissions would be required only for
components of a blend that are listed in Table C-2 of Subpart C.
If the mass or volume of each component of a blend is measured
before the fuels are mixed and combusted, the existing CH4
and N2O mass emissions calculation procedures in 40 CFR
98.33(c)(1) through (5) would be followed for each component
separately. The fact that the fuels are mixed prior to combustion is of
no consequence in this case.
If the mass or volume of each individual component is not measured
prior to mixing, a reasonable estimate of the percentage composition of
the blend would be required, based on the best available information,
and the procedures in 40 CFR 98.33(c)(6)(ii) would be followed. First,
the annual consumption of each component fuel in the blend would be
calculated by multiplying the total quantity of the blend combusted
during the reporting year by the estimated mass or volume percentage of
that component. Next, the annual heat input from the combustion of each
component would be calculated by multiplying its annual consumption by
the appropriate HHV (either the default HHV from Table C-1 or, if
available, the measured annual average value). The annual
CH4 and N2O mass emissions for each component
would then be calculated using the applicable equation in 40 CFR
98.33(c), i.e., Equation C-8, C-9a, or C-10. Finally, the calculated
CH4 and N2O emissions would be summed across all
components, and these sums would be reported as the annual
CH4 and N2O mass emissions for the blend.
Use of Consensus Standard Methods. Sections 98.34(a)(6), (b)(4),
and (b)(5) of subpart C specify acceptable methods for determining fuel
HHV, carbon content, and molecular weight, and methods for calibrating
fuel flow meters. The methods listed in those sections are from
consensus standards organizations such as ASTM, ASME, AGA, and GPA.
Although we attempted to assemble a comprehensive list of methods and
provide appropriate alternatives, it is possible that other valid
methods from these organizations and practices have been overlooked, or
that in some cases, industry consensus standard methods may be more
appropriate than the methods listed. In view of this, we are proposing
to remove the specific method lists from 40 CFR 98.34 and to amend 40
CFR 98.34(a)(6) and (b)(1)(i)(A), delete paragraph (b)(4), redesignate
paragraph (b)(5) as (b)(4), and amend newly designated paragraph
(b)(4). These proposed amendments would allow the owner or operator to
either: (1) Use appropriate methods published by consensus standards
organizations such as ASTM, ASME, API, AGA, ISO, etc.; or (2) use
industry standard practice. The methods used would be documented in the
monitoring plan under 40 CFR 98.3(g)(5).
CO2 Monitor Span Values. The Tier 4 calculation method
in 40 CFR 98.33(a)(4) requires a CO2 concentration monitor
and a stack gas flow rate monitor to measure CO2 mass
emissions. The CO2 monitor must be certified and quality-
assured according to one of the following: 40 CFR Part 60, 40 CFR Part
75, or an applicable State CEM program. When the Part 60 option is
selected, one of the required quality assurance (QA) tests of the
CO2 monitor is a cylinder gas audit (CGA). The CGA checks
the response of the CO2 analyzer at two calibration gas
concentrations, i.e., one between 5 and 8 percent CO2 and
one between 10 and 14 percent CO2. These CO2
concentration levels are appropriate for most stationary combustion
applications. For example, a typical span value for a CO2
monitor installed on a coal-fired boiler is 20 percent CO2;
therefore, the CGA concentrations represent 25 to 40 percent of span
and 50 to 70 percent of span. However, when CO2 emissions
from an industrial process (e.g., cement manufacturing) are combined
with combustion CO2 emissions, the resultant CO2
concentration in the stack gas can be substantially higher than for the
combustion emissions alone. In such cases, a span value of 30 percent
CO2 (or higher) may be required.
When the CO2 span exceeds 20 percent CO2, the
CGA concentrations specified in Part 60 only evaluate the lower portion
of the measurement scale and are no longer representative. Therefore,
we are proposing to amend 40 CFR 98.34(c) by adding a new paragraph
(c)(6), which would allow the CGAs of a CO2 monitor to be
performed using calibration gas concentrations of 40 to 60 percent of
span and 80 to 100 percent of span, when the CO2 span value
is set higher than 20 percent CO2.
CEMS Data Validation. The Tier 4 methodology in 40 CFR 98.33(a)(4)
requires the use of CEMS to measure CO2 mass emissions. For
each unit operating hour, the CO2 mass emissions are
determined using either valid CEMS data or appropriate substitute data
values when monitors malfunction. For a Tier 4 unit, the owner or
operator has the option to follow the CEMS certification and QA
provisions of 40 CFR Part 60, 40 CFR Part 75, or an applicable State
CEM program. This includes the criteria in those regulations pertaining
to validation of the hourly CEMS data.
The provisions for hourly CEMS data validation in Part 60 are found
in 40 CFR 60.13(h)(2)(i) through (h)(2)(vi). For Part 75, hourly data
validation is addressed in 40 CFR 75.10(d)(1). The CEMS data validation
criteria in these sections of Parts 60 and 75 are virtually identical.
The basic requirement to validate an hour is that at least one data
point must be obtained in each 15-minute quadrant of the hour in which
the unit operates. There is one notable exception to this. For
operating hours in which required maintenance or QA testing is
performed, obtaining a valid data point in two of the four quadrants is
sufficient.
In subpart C, 40 CFR 98.34(c) provides the monitoring and QA
requirements for Tier 4. However, no criteria for hourly CEMS data
validation are specified. In view of this, we are proposing to add a
new paragraph, (c)(7), to 40 CFR 98.34(c), which would require hourly
CEMS data validation to be consistent with the sections of Part 60 or
Part 75 cited in the preceding paragraph. Alternatively, the hourly
[[Page 48762]]
data validation procedures in an applicable State CEM program could be
followed.
Use of ASTM Methods D7459-08 and D6866-08. Sections 98.34(d) and
(e) of subpart C, respectively, outline procedures for quantifying
biogenic CO2 emissions for units that combust municipal
solid waste (MSW) and other units that combust combinations of fossil
fuels and biomass. As specified in Part 98, flue gas samples are taken
quarterly using ASTM Method D7459-08 and analyzed using ASTM Method
D6866-08. We are proposing to amend 40 CFR 98.34(d) and (e), as
discussed in the following paragraphs.
The proposed amendments to 40 CFR 98.34(d) would require the ASTM
methods to be used when MSW is combusted in a unit, either as the
primary fuel, or as the only fuel with a biogenic component. Quarterly
sampling with ASTM Method D7459-08 would still be required, for a
minimum of 24 consecutive operating hours. However, we are proposing to
add an alternative to allow the owner or operator to collect an
integrated sample by extracting a small amount of flue gas (1 to 5
cubic centimeters (cc)) during every unit operating hour in the
quarter, in order to obtain a more representative sample for analysis.
This sampling approach is recommended by experts on the use of ASTM
Methods D7459-08 and D6866-08 when the types of fuel and their
composition are variable over time, as is the case with MSW combustion.
For more information please refer to the Background Technical Support
Document (EPA-HQ-OAR-2008-0508).
We are proposing to amend 40 CFR 98.34(e) to remove the restriction
limiting the use of ASTM Methods D7459-08 and D6866-08 to units with
CEMS. Rather, any unit that combusts combinations of fossil and
biogenic fuels (or partly biogenic fuels, such as tires), in any
proportions, would be allowed to determine biogenic CO2
emissions using the ASTM methods on a quarterly basis. At least 24
consecutive hours of sampling is currently specified in 40 CFR
98.34(e). This is appropriate if the types of fuels and their relative
proportions are consistent throughout the quarter. If the relative
proportions are not consistent throughout the quarter, it may be more
appropriate to consider collecting more frequent samples, however this
is not required. Therefore, we are also amending 40 CFR 98.34(e) to
recommend that a small (1 to 5 cc) flue gas sample be taken during each
unit operating hour in the quarter.
Electronic Data Reporting and Recordkeeping. EPA will rely on
Agency verification of the electronic data provided in the annual GHG
emission reports, in lieu of implementing third party verification. In
order for Agency verification to be effective, sufficient information
must be included in the electronic reports, at the facility, source
category, and unit levels, to enable EPA to recalculate the reported
GHG emissions and to quality-assure the data.
Section 98.36 of subpart C provides several lists of data elements
that must be reported for stationary combustion units. These lists are
specific to the CO2 emissions calculation method employed
(e.g., one of the four Tiers in 40 CFR 98.33(a) or a method in 40 CFR
Part 75), and to the type(s) of electronic data report(s) that are
submitted (e.g., individual unit reports, aggregated group reports,
common pipe reports, etc).
EPA has begun developing software to check and verify the
electronic data in the GHG emissions reports. As this effort has
progressed, it has come to light that a number of important data
elements are missing from the lists in 40 CFR 98.36, and that some of
the data elements on the lists are either not needed or require an
excessive amount of non-essential data to be reported.
To address these issues, we are proposing to amend the data element
lists in 40 CFR 98.36 by adding a number of essential data elements and
eliminating or modifying others. The most significant revisions to the
data element lists are discussed in paragraphs (a) through (g), below.
We are also proposing to add an additional alternative reporting option
to 40 CFR 98.36(c) to reduce the reporting burden for certain
facilities. This option is described in paragraph (h), below.
(a) We are proposing to add the reporting of methodology start and
end dates in several places throughout 40 CFR 98.36(b), (c), and (d).
These data elements are needed to accommodate changes in the methods
used to calculate GHG emissions, when such changes occur during a
reporting year or from one year to the next.
(b) We are proposing to amend the data element lists in 40 CFR
98.36 to be consistent with respect to reporting of emissions by fuel
type and reporting of biogenic CO2 emissions.
(c) We are proposing to amend 40 CFR 98.36(b)(10) to remove the
requirement to report the customer meter number for units that combust
natural gas.
(d) We are proposing to amend a number of data elements to reduce
the reporting burden. For example, when small combustion units are
aggregated into a group, 40 CFR 98.36(c)(1)(ii) currently requires the
ID number of each unit in the group to be reported. This requirement is
unreasonable for facilities that have large numbers of very small
combustion sources, many of which do not have unique ID numbers. We
are, therefore, proposing to amend this data element to require that
only the total number of units in the group be reported, instead of the
ID number of each unit in the group. As a second example, for the
common pipe option described in 40 CFR 98.36(c)(3), only the total
number of units served by the common pipe would be reported, instead of
reporting an ID number for each unit, and only the highest maximum
rated heat input capacity of any unit served by the common pipe would
be reported, rather than reporting the rated heat input capacity of
each individual unit.
(e) We are proposing to amend 40 CFR 98.36 to remove the
requirement to report the combined annual GHG emissions from fossil
fuel combustion in metric tons of CO2e (i.e., the sum of the
CO2, CH4, and N2O emissions) from 40
CFR 98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data
elements are duplicative of requirements in subpart A.
(f) We are proposing to amend 40 CFR 98.36(b), (c), and (d) to
require reporting the fuel-specific annual heat input estimates, for
the purpose of verifying the reported CH4 and N2O
emissions. Also, we are proposing to amend 40 CFR 98.36(e)(2)(iv) to
require reporting of the annual average HHV when measured HHV data are
used to calculate CH4 and N2O emissions for a
Tier 3 unit, in lieu of using a default HHV from Table C-1.
(g) We are proposing to amend 40 CFR 98.36(b) and (d) to make the
data elements reported under Tiers 1 through 4 consistent for the
reporting of biogenic CO2 emissions and CO2 from
fossil fuel combustion. Also, as previously noted in section III.C of
this preamble, the proposed amendments to 40 CFR 98.36(d) would state
that reporting of biogenic CO2 emissions is optional for
units using the CO2 mass emissions calculation methods in 40
CFR Part 75.
(h) For units that use the Tier 4 methodology to calculate
CO2 mass emissions, we are proposing to amend 40 CFR
98.36(b)(7)(i) and (b)(7)(ii) (redesignated as 40 CFR 98.36(b)(9)(i)
and (b)(9)(ii), respectively) and 40 CFR 98.36 (c)(2)(vi) (redesignated
as 40 CFR 98.36 (c)(2)(viii)). The proposed amendments to these
sections will require the annual ``non-biogenic'' CO2 mass
emissions to be reported instead of reporting the annual CO2
mass emissions from fossil fuel combustion.
[[Page 48763]]
These revisions are being proposed because the total annual
CO2 mass emissions measured by CEMS sometimes includes
CO2 from sorbent or process CO2 emissions in
addition to CO2 from fossil fuel combustion. The effect of
the proposed amendments would be to simplify reporting for Tier 4 units
that have sorbent or process CO2 emissions in the flue gas
stream. These units would be required only to report the combined
annual non-biogenic CO2 mass emissions, rather than having
to separately account for the fossil CO2 emissions. Tier 4
units that do not have any sorbent or process CO2 emissions
in the flue gas would be unaffected by these proposed revisions,
because their non-biogenic CO2 emissions are entirely from
fossil fuel.
(i) We are proposing to add a new alternative reporting option,
under 40 CFR 98.36(c)(4). This new option would apply to specific
situations where a common liquid or gaseous fuel supply is shared
between large combustion units such as boilers or combustion turbines
(including Acid Rain Program units and other combustion units that use
the methods in 40 CFR Part 75 to calculate CO2 mass
emissions), and small combustion sources such as space heaters, hot
water heaters, etc. In such cases, you could simplify reporting by
attributing all of the GHG emissions from combustion of the shared fuel
to the large combustion unit(s), provided that:
The total quantity of the shared fuel supply that is
combusted during the report year is measured, either at the ``gate'' to
the facility or at a point inside the facility, using a fuel flow
meter, a billing meter or tank drop measurements; and
On an annual basis, at least 95 percent of the shared fuel
supply (by mass or volume) is burned in the large combustion unit(s)
and the remainder of the fuel is fed to the small combustion sources.
Use of company records would be allowed to determine the percentage
distribution of the shared fuel to the large and small units.
Facilities using this reporting option would be required to document in
their monitoring plan which units share the common fuel supply and the
method used to determine that the reporting option applies. For the
small combustion sources, a description of the type(s) and approximate
number of units involved would suffice.
(j) Finally, we are proposing to simplify the record keeping
requirements in 40 CFR 98.36(e)(2)(iii), in cases where the results of
fuel analyses for HHV are provided by the fuel supplier. Parallel
language would be added in a new paragraph, (e)(2)(v)(E), for the
results of carbon content and molecular weight analyses received from
the fuel supplier. In both cases, the owner or operator would be
required to keep records of only the dates on which the fuel sampling
results are received, rather than keeping records of the dates on which
the supplier's fuel samples were taken (which dates may not be readily
available).
We believe that these proposed amendments to the recordkeeping and
reporting requirements of 40 CFR 98.36 are needed for data verification
purposes. The proposed amendments are not likely to increase the
reporting burden on industry. In some cases, as previously noted, the
proposed amendments would actually reduce the amount of information
that must be collected or reported and the associated burden.
Common Stack Reporting Option. Section 98.36(c)(2) of subpart C
currently allows Subpart C stationary fuel combustion units that share
a common stack or duct to use the Tier 4 Calculation Methodology to
monitor and report the combined CO2 mass emissions at the
common stack or duct, in lieu of monitoring each unit individually.
However, 40 CFR 98.36(c)(2) does not address circumstances where at
least one of the units sharing the common stack is not a Subpart C
stationary fuel combustion unit, but is subject to another subpart of
Part 98. For example, if a Subpart G ammonia manufacturing unit shares
a common stack with a Subpart C stationary combustion unit, the use of
Tier 4 may be required (see 40 CFR 98.73(c)).
In view of this, we are proposing to amend 40 CFR 98.36(c)(2) by
extending the applicability of the common stack monitoring and
reporting option to situations where off-gases from multiple process
units or mixtures of combustion products and process off-gases are
combined together and vented through a common stack or duct.
The proposed amendments to 40 CFR 98.36(c)(2) would not only apply
to ordinary common stack or duct situations where the gas streams from
multiple units are combined together, but would also apply when process
and combustion gas streams from a single unit (e.g., from a kiln,
furnace, or smelter) are combined. To accommodate this variation on the
traditional concept of a common stack, 40 CFR 98.36(c)(2)(ii) would be
amended to require sources to report ``1'' as the ``Number of units
sharing the common stack or duct'' when process and combustion
emissions from a single unit are combined and vented through the same
stack or duct.
Finally, since the concept of maximum rated heat input capacity may
not be applicable to certain types of process or manufacturing units,
we are proposing to amend 40 CFR 98.36(c)(2)(iii), to require that the
``Combined maximum rated heat input capacity of the units sharing the
common stack or duct'' only be reported when all of the units sharing
the common stack or duct are stationary fuel combustion units.
Common Fuel Supply Pipe Reporting Option. Section 98.36(c)(3) of
subpart C currently allows units that are served by a common fuel
supply pipe to report the combined CO2 emissions from all of
the units in lieu of reporting CO2 emissions separately from
each unit. To use this reporting option, the total amount of fuel
combusted in the units must be accurately measured with a flow meter
calibrated according to the requirements in 40 CFR 98.34. Section
98.36(c)(3) also states that the applicable Tier to use for this
reporting option is based on the maximum rated heat input of the
largest unit in the group.
We are proposing to amend 40 CFR 98.36(c)(3) as follows. First, the
erroneous citation of ``Sec. 98.34(a)'' would be corrected to read
``Sec. 98.34(b).'' Second, we are proposing to amend the requirement
in 40 CFR 98.36(c)(3) to calibrate the fuel flow meter to the accuracy
required by 40 CFR 98.34(b) (which cross-references the accuracy
specifications in 40 CFR 98.3(i)), so that this calibration requirement
would apply only when Tier 3 is the required tier for calculating
CO2 mass emissions. The Agency believes that this
clarification is needed, since the common pipe option can apply to Tier
1, 2, or 3, depending on the rated heat input capacities of the units
served by the common pipe. Tiers 1 and 2 rely on company records to
quantify fuel usage. Therefore, as noted in today's proposed amendments
to 40 CFR 98.3(i), the equipment used to generate company records under
Tier 1 and 2 is not required to meet the calibration accuracy
specifications of 40 CFR 98.3(i).
As previously noted, the applicable measurement Tier for the common
pipe option, according to subpart C, is based on the rated heat input
capacity of the largest unit in the group. On the surface, this appears
to mean that the use of Tiers 1 and 2 is restricted to common pipe
configurations where the highest rated heat input capacity of any unit
is
[[Page 48764]]
250 mmBtu/hr or less, and that Tier 3 is required if any unit has a
maximum rated heat input capacity greater than 250 mmBtu/hr. In
general, this is true. However, there is one exception in the current
rule and we are proposing to add a second one. First, 40 CFR
98.33(b)(2)(ii) allows the use of Tier 2 instead of Tier 3 for the
combustion of natural gas and/or distillate oil in a unit with a rated
heat input capacity greater than 250 mmBtu/hr. Second, proposed 40 CFR
98.33(b)(1)(v) would allow Tier 1 to be used when natural gas
consumption is determined from billing records, and fuel usage on those
records is expressed in units of therms. Therefore, we are also
proposing to amend 40 CFR 98.36(c)(3) to reflect these two exceptions
for common pipe configurations that include a unit with a maximum rated
heat input capacity greater than 250 mmBtu/hr.
Finally, we are proposing to amend the provision in 40 CFR
98.36(c)(3) regarding the partial diversion of a fuel stream such as
natural gas that is measured ``at the gate'' to a facility, (e.g.,
using a calibrated flow meter or a gas billing meter). Subpart C
specifies that when part of a fuel stream is diverted to a chemical or
industrial process where it is used but not combusted, and the
remainder of the fuel is sent to a group of combustion units, you may
subtract the diverted portion of the fuel stream from the total
quantity of the fuel measured at the gate before applying the common
pipe methodology to the combustion units. We are proposing to expand
this provision to include cases where the diverted portion of the fuel
stream is sent either to a flare or to another stationary combustion
unit (or units) on-site, including units that use Part 75 methodologies
to calculate annual CO2 mass emissions (e.g., Acid Rain
Program units). Provided that the GHG emissions from the flare and/or
other combustion unit(s) are properly accounted for according to the
applicable subpart(s) of Part 98, you would be allowed to subtract the
diverted portion of the fuel stream from the total quantity of the fuel
measured at the gate, and then apply the common pipe reporting option
to the group of combustion units served by the common pipe, using the
Tier 1, Tier 2, or Tier 3 calculation methodology (as applicable).
Table C-1. Table C-1 of Subpart C provides default HHV values and
default CO2 emission factors for various types of fuel.
These default values are needed to calculate CO2 mass
emissions when the Tier 1 and Tier 2 methodologies in 40 CFR 98.33(a)
are used. The fuels listed in Table C-1 are grouped into general
categories (e.g., coal and coke, petroleum products, biomass fuels).
Some distinctions are made within these categories, based on the state
of matter (e.g., biomass fuels--liquid, fossil fuel-derived fuels
(solid), etc.).
Since publication of the final Part 98, EPA has received many
questions about the content and structure of Table C-1. Owners and
operators in various industries have raised a number of issues
concerning the way that fuels are categorized, the description of
certain fuels, the units of measure of some of the default HHV values,
and the absence of some fuels that were listed in Table C-2 of the
April 10, 2009 proposed rule. In particular:
(a) The categories ``fossil fuel-derived fuels (solid)'' and
``fossil fuel-derived fuels (gaseous)'' did not appear in the April 10,
2009 proposed rule and have been the source of some confusion. For
instance, only two fuels, MSW and tires, are listed under ``fossil
fuel-derived fuels (solid),'' and neither of these is derived entirely
from fossil fuels. Both of these fuels have a biogenic component. There
are also only two fuels, blast furnace gas and coke oven gas, listed in
the ``fossil fuel-derived fuels (gaseous)'' category. Several other
fuels that are derived from petroleum and qualify as fossil fuel-
derived gaseous fuels (e.g., still gas) are listed in a different
category, ``petroleum products.''
(b) Questions have arisen about the revised description of
``natural gas'' in Table C-1. The word ``pipeline,'' which was not in
the April 10, 2009 proposed rule, was added in the final subpart C.
(c) The Agency has received questions about the meaning of the
terms ``wood residuals,'' ``solid byproducts,'' and ``agricultural
byproducts,'' none of which appeared in the April 10, 2009 proposed
rule.
(d) Questions have been asked why certain fuels that were listed in
Table C-2 of the April 10, 2009 proposed rule do not appear in Table C-
1. These include waste oil and plastics.
(e) Owners and operators have questioned the appropriateness of the
units of measure for still gas listed under ``petroleum products.'' The
HHV for still gas, which is in the gaseous state at ambient
temperatures, is given in mmBtu per gallon, as though it were in the
liquid state.
(f) Some industry questions indicate that reporters believe that
the footnote beneath Table C-1 appears to prohibit MWC units that
produce steam from using the default CO2 emission factor in
the Table. This emission factor is needed to apply the Tier 2
CO2 emissions calculation methodology (specifically,
Equation C-2c) to those units.
(g) EPA has received questions regarding the significance of
indicating one hundred percent for ethanol and biodiesel, as well as
questions regarding which emission factors to use for petroleum-derived
ethanol.
In view of these considerations, we are proposing the following
revisions to Table C-1:
The categories ``fossil fuel-derived fuels (solid)'' and
``fossil fuel-derived fuels (gaseous)'' would be replaced with more
inclusive terms, i.e., ``other fuels (solid)'' and ``other fuels
(gaseous).'' The ``other fuels (solid)'' category would include four
fuels: Plastics, municipal solid waste, tires, and petroleum coke. The
``other fuels (gaseous)'' category would include blast furnace gas,
coke oven gas, propane gas, and fuel gas.
The word ``pipeline'' would be removed from the
description of natural gas.
The following fuels: ``wood residuals,'' ``agricultural
byproducts,'' and ``solid byproducts'' would be retained, but
definitions of these terms would be added to 40 CFR 98.6.
``Waste oil'' would be added to the list of petroleum
products, and a definition would be added to 40 CFR 98.6.
Still gas would be removed from the list of petroleum
products.
The footnote regarding MWC units would be revised to make
it clear that MWC units that produce steam are only prohibited from
using the default HHV for MSW in Table C-1; MWC units that produce
steam can still use the default CO2 emission factor for MSW.
The qualifier of one hundred percent for ethanol and
biodiesel would be removed since these fuel types should be treated in
the same way as other fuel types included in Table C-1. Removing this
qualifier would clarify this without affecting any other provisions the
rule.
A default CO2 emission factor and a default
high heat value would be added to the Table for petroleum-derived
ethanol. These would be the same as the default values for biomass-
derived ethanol.
We are soliciting comment on these proposed amendments to Table C-
1. Specifically, we request comment on: (1) The new and revised fuel
categories; (2) the appropriateness of the HHVs and CO2
emission factors for the fuels listed in these categories; and (3)
whether additional fuels should be included in Table C-1, and if so,
what the HHVs and CO2 emission factors for those fuels
should be.
[[Page 48765]]
Table C-2. In the October 30, 2009 publication of Part 98, two
essentially identical iterations of Table C-2 of Subpart C were
printed. The first iteration of Table C-2 was a printing error. We are
proposing to remove the first iteration of the Table and to make minor
corrections to the second one. The proposed amendments consist of
correcting the exponents of the emission factors. The powers of ten in
the right-hand column of the Table currently have an ``underscore''
character where there should be a minus sign, and one of the exponents
is missing a zero.
Miscellaneous Proposed Revisions. In addition to the more
substantive proposed amendments to Subpart C, we are proposing to
correct a number of typographical errors, and to re-word the rule text
in a few places for added clarity. We are also proposing to amend 40
CFR 98.34(c) by adding the citations from 40 CFR Part 75 that pertain
to the initial certification of Tier 4 moisture monitoring systems.
Although these rule citations were inadvertently omitted from the
October 30, 2009 publication of Part 98, we believe that Tier 4 sources
understand that all required CEMS, including moisture monitoring
systems, must be initially certified.
How Would These Amendments to Subpart C Apply to the 2011 GHG
Emissions Reports? EPA plans to address the comments on the proposed
amendments to Subpart C and to publish the final amendments before the
end of 2010. Therefore, reporters would be expected to use provisions
of Part 98, as amended, to collect the relevant data and to calculate
GHG emissions for the reports that are submitted in 2011. We believe it
is feasible for the sources to use the proposed changes to Subpart C
for the 2010 reporting year, because the proposed revisions, to a great
extent, simply clarify existing regulatory requirements. Further, the
proposed amendments do not substantially affect the type of information
that must be collected or how emissions are calculated.
The following are examples of how the proposed amendments to
Subpart C would clarify existing regulatory requirements. The
amendments would clarify:
That reporting of biogenic CO2 emissions is
optional for units using the CO2 mass emissions calculation
methodologies in 40 CFR Part 75.
How CH4 and N2O emissions are
calculated for multi-fuel units that use the Tier 4 CO2 mass
emissions calculation methodology.
How to determine whether Tier 4 applies to various common
stack configurations.
How to determine which Tier (i.e., 1, 2, or 3) applies to
common pipe configurations.
How to calculate biogenic emissions for various types of
units and fuels. Unnecessary restrictions on the use of certain
calculation methods would be removed.
How to apply the definition of a ``fuel lot'' at
facilities that receive frequent deliveries of coal or fuel oil.
How to calculate CO2, CH4, and
N2O emissions for blended fuels.
The proposed amendments to 40 CFR 98.36, the data reporting section
of Subpart C, would achieve two main purposes: (1) To ensure that
enough data are provided to enable the Agency to recalculate and verify
the emissions data; and (2) to reduce burden, by removing the
requirement to report certain non-essential data elements and by
modifying other data elements.
For example, the proposed amendments would:
Require methodology start and end dates to be reported.
This will enable us to track changes in emissions calculation
methodologies (e.g., switching from a lower Tier to a higher Tier).
Generally require reporting of fuel-specific
CH4 and N2O emissions. This requirement was
inconsistently applied in Part 98.
Eliminate the need to report individual unit ID numbers
and unit heat input capacities for groups of aggregated units, common
pipe configurations, and common stack configurations.
Remove the unnecessary requirement to report unit-level
combined CO2, CH4, and N2O emissions
from fossil fuel combustion.
Remove the requirement for natural gas users to report
their customer meter ID numbers.
Emphasize that biogenic CO2 emissions reporting
is optional for Part 75 units.
EPA believes that amendments such as these can be implemented for
the reports submitted to EPA in 2011 because the proposed changes are
either consistent with or have no significant effect upon the
calculation methodologies in Part 98. Since owners or operators are not
required to report until March 2011, which is several months after we
expect this proposal to be finalized, sources should have sufficient
time to adjust to the revisions.
Several other proposed amendments to Subpart C address issues
identified as a result of working with the affected sources during rule
implementation. These proposed amendments would add flexibility to the
rule. Owners or operators would be free to implement these new rule
provisions once they are finalized. The following are examples of how
today's proposed Subpart C amendments would make the rule more
flexible. The proposed amendments would:
Allow fuel flow meters that measure on a mass basis to be
used for gaseous fuels as well as liquid fuels, provided that the flow
rate measurements are corrected for density.
Allow the span of CO2 monitors to be set higher
than 20 percent CO2 if necessary, when process
CO2 and combustion CO2 emissions exit to the
atmosphere through a common stack.
Allow the use of site-specific default moisture values for
Tier 4 units that measure CO2 concentration on a dry basis.
Provide a new Tier 1 equation for calculating
CO2 mass emissions when fuel usage data obtained from gas
billing records is expressed in units of therms.
Allow smaller Tier 2 units (less than 100 mmBtu/hr) that
receive monthly (or more frequent) HHV data to use an arithmetic
average annual HHV in the emissions calculations instead of a fuel-
weighted average HHV.
Allow Tier 4 units to use an alternative (non-CEMS) method
to account for the volumetric flow rate of a slip stream, when a
portion of the flue gas is diverted and exhausts through a separate
stack.
Allow fuel oil sampling to be performed upon each addition
of oil to the storage tank, as an alternative to sampling each fuel
lot.
Remove the lists of specific methods for determining HHV
and carbon content and for fuel flow meter calibration, and specify
instead that sources must either use appropriate methods from consensus
standards organizations if such methods exist, or standard industry
practice.
Add a new reporting option for configurations in which a
common supply of gaseous or liquid fuel is shared between large
combustion units and a group of smaller units such as space heaters,
hot water heaters, etc. If at least 95 percent of the shared fuel is
used by the large units, 100 percent of the GHG emissions from
combustion of that fuel may be attributed to the large units.
In some cases, facilities may have been following their current
data collection practices during 2010, as well as using the methods
required by Part 98. If a facility's current practice provides the
necessary data to implement the new options described immediately
above, or if such data could be obtained and processed prior
[[Page 48766]]
to the March 31, 2011 reporting deadline, the new options could be used
for the reports submitted to EPA in 2011.
Finally, the proposed amendments would make minor corrections to
terms and definitions in certain Subpart C equations, and other
technical corrections that would have no impact on facility's data
collection efforts in 2010.
In summary, EPA believes that, in general, the proposed amendments
to Subpart C would not require monitoring or information collection
above what is already required by Part 98. Therefore, we expect that
sources will be able to use the same information that they have been
collecting under Part 98 to calculate and report GHG emissions for
2010.
EPA seeks comment on its conclusion that the amendments to Subpart
C can be implemented and incorporated into the initial GHG emissions
reports by the due date of March 31, 2011. Specifically, we seek
comment on whether this timeline is feasible or appropriate,
considering the nature of the proposed changes and the way in which
data have been collected thus far in 2010. We request that commenters
provide specific reasons why they believe that the proposed
implementation schedule would or would not be feasible.
H. Subpart D (Electricity Generation)
We are proposing to amend 40 CFR 98.40(a) by adding the word
``mass'' between the words ``CO2'' and ``emissions'' to make
it clear that Subpart D applies only to units in two categories: (a)
ARP units; and (b) non-ARP electricity generating units (EGUs) that are
required to report CO2 mass emissions data to EPA year-
round. At present, category ``(b)'' includes only non-ARP units that
are subject to the Regional Greenhouse Gas Initiative (RGGI) in the
northeastern United States.
Many non-ARP EGUs that are not in the RGGI are subject to the Clean
Air Interstate Rule (CAIR). Some of these CAIR units report
CO2 concentration data to EPA year-round, for the purposes
of calculating NOX emission rates in lb/mmBtu and/or heat
input rates in mmBtu/hr. However, they do not report CO2
mass emissions data to the Agency. Therefore, they are subject to
Subpart C of Part 98, not Subpart D.
Data Reporting Requirements. Section 98.46 of subpart D currently
specifies that the owner or operator of a Subpart D unit must comply
with the data reporting requirements of 40 CFR 98.36(b) and, if
applicable, 40 CFR 98.36(c)(2) or (c)(3). These section citations are
incorrect. Subpart D units all use the CO2 mass emissions
calculation methodologies in 40 CFR Part 75. Therefore, the applicable
data reporting section for these units is 40 CFR 98.36(d), not 40 CFR
98.36(b), 40 CFR 98.36(c)(2), or 40 CFR 98.36(c)(3). We are proposing
to amend 40 CFR 98.46 to correct this error.
Recordkeeping. We are proposing to amend 40 CFR 98.47 to state that
the records kept under 40 CFR 75.57(h) for missing data events satisfy
the recordkeeping requirements of 40 CFR 98.3(g)(4) for those same
events. We believe that, as a practical matter, the missing data
records required to be kept under 40 CFR 75.57(h) are substantially
equivalent to the records required under 40 CFR 98.3(g)(4).
I. Subpart F (Aluminum Production)
Throughout Subpart F we are proposing corrections as needed for
typographical errors and alphanumeric sequencing. We are proposing to
amend 40 CFR 98.63, Calculating GHG Emissions, to clarify that each
perfluorocarbon (PFC) compound (CF4,
C2F6) must be quantified and reported and to
clarify in 40 CFR 98.63(c) that reporters must use CEMS if the process
CO2 emissions from anode consumption during electrolysis or
anode baking of prebake cells are vented through the same stack as a
combustion unit required to use CEMS. This requirement existed in the
final rule, however, the cross-reference was omitted from the
introductory language of 40 CFR 98.63(c).
We are proposing to amend 40 CFR 98.64, Monitoring and QA/QC, to
clarify the type of parameters that must be measured in accordance with
the recommendations of the EPA/IAI Protocol for Measurement of
Tetrafluoromethane (CF4) and Hexafluoroethane
(C2F6) Emissions from Primary Aluminum Production
(2008), and the frequency of monitoring for those parameters which are
not measured annually, but are instead measured on a more or less
frequent basis. We are proposing a modification to Table F-2 to clarify
that default CO2 emissions from pitch volatiles combustion
are relevant only for center work pre-bake (CWPB) and side work pre-
bake (SWPB) technologies.
We are also proposing to amend Table F-1 to spell out the acronyms
for the technologies covered by that table; i.e., CWPB, side worked
prebake (SWPB), vertical stud S[oslash]derberg (VSS), and horizontal
stud S[oslash]derberg (HSS).
J. Subpart G (Ammonia Manufacturing)
We are proposing to amend subpart G to remove reporting of the
waste recycle stream or purge, and to make subpart G conform to the
proposed amendments to the calibration requirements in Subpart A. With
respect to the waste recycle stream, we are proposing to eliminate the
calculation, monitoring and reporting of the emissions associated with
the waste recycle stream or purge currently required by Equation G-6
from 40 CFR 98.73, 98.74, 98.75, and 98.76. Carbon dioxide emissions
from waste recycle stream or purge gas used as fuel will still be
accounted for accurately using Equation G-5 in Subpart G. Because total
process emissions, calculated using Equation G-5, will also account for
emissions associated with use of the purge gas as a fuel, we are
proposing to amend 40 CFR 98.72(b) so that subpart C does not apply to
CO2 emissions resulting from the use of purge gas as a fuel.
With respect to calibration requirements, we are proposing to
clarify the calibration requirements for gas and oil flow meters used
in the ammonia manufacturing process. Section 98.74(d) of subpart G
currently states that all oil and gas flow meters except for gas
billing meters must be calibrated according to the requirements for the
Tier 3 methodology in 40 CFR 98.34(b). The Agency believes that the
words ``all oil and gas flow meters'' in this subpart G provision are
too inclusive and subject to misinterpretation. Therefore, we are
proposing to amend 40 CFR 98.74(d) to limit the flow meter calibration
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to only meters
that are used to measure liquid and gaseous feedstock volumes. In
accordance with 40 CFR 98.3(i)(1), each measurement device that is not
used to measure liquid and gaseous feedstock volumes, but is used to
provide data for the GHG emissions calculations would have to be
calibrated to an accuracy within the appropriate error range for the
specific measurement technology, based on an applicable operating
standard, such as the manufacturer's specifications.
We are proposing to note through parentheticals in a number of
places that the CO2 emissions estimates may include
CO2 that is later consumed on-site for urea production and
therefore not released to the atmosphere from the ammonia manufacturing
process unit. This proposed change does not impact the total
CO2 emissions that are quantified and reported to EPA under
the calculation equations in 40 CFR 98.73. The clarification is
proposed so
[[Page 48767]]
that it is transparent for stakeholders who ultimately use these data
that some CO2 process emissions reported by the ammonia
manufacturing process unit under this subpart may not be released from
ammonia manufacturing, but at the point of urea application. To further
enhance this transparency, EPA is also proposing to require reporting
under 40 CFR 98.76 of the CO2 from the ammonia manufacturing
process unit that is then used to produce urea and the method used to
determine that quantity of CO2 consumed.
In addition, we are proposing to amend Subpart G to correct several
typographical errors and an incorrect cross-reference to another
subpart in Part 98. We are proposing to correct the terms and
definitions for annual CO2 emissions arising from gaseous,
liquid, and solid fuel feedstock consumption in Equations G-1, G-2, and
G-3, respectively, in 40 CFR 98.73. We are proposing to correct 40 CFR
98.76(a) by changing the cross-reference from ``Sec. 98.37(e)(2)(vi)''
to ``Sec. 98.37.''
We are proposing to amend the data reporting requirements in 40 CFR
98.76(b)(6) and (15) for consistency with the calculation procedures in
40 CFR 98.73(b)(6). We are proposing to amend 40 CFR 98.76(b)(6) to
change ``petroleum coke'' to ``feedstock'' because petroleum coke is
the incorrect term, and to amend 40 CFR 98.76(b)(15) to specify that
the carbon content analysis method being reported is for each month.
We are proposing to remove 40 CFR 98.76(b)(17) for the reporting of
urea produced, if known. EPA finalized reporting of this information to
help improve methodologies for calculating emissions from ammonia
manufacturing, urea production and urea consumption. Reporters stated
that these data are already reported periodically to EPA under the
Toxic Substances Control Act (TSCA) Inventory Update Rule (IUR).
Although the TSCA IUR does not provide the full range of information
that may ultimately be useful for informing future policy, EPA believes
that the TSCA IUR provides adequate information at this time and,
therefore, we are proposing to delete that requirement.
Finally, 40 CFR part 98, subpart G (Ammonia Manufacturing) and
subpart V (Nitric Acid Production) require that facilities report total
pounds of synthetic fertilizer and total nitrogen contained in that
fertilizer. After considering additional information provided by
stakeholders, as well as other available information, we are proposing
to remove the requirement from both subparts. EPA's rationale for
removing the requirement is as follows
(i) The data that would be reported under these subparts do not
provide directly applicable information with which to determine
N2O emissions from application of fertilizer because the
data are incomplete. Domestic producers of synthetic nitrogen-based
fertilizer make up less than one-half of the total amount of synthetic
nitrogen-based fertilizer used in the United States. The remaining
share is made up by synthetic nitrogen-based fertilizer imports, as
well as fertilizer produced domestically outside of the Nitric Acid and
Ammonia production industries using imported ammonia and nitric acid.
(ii) EPA has information on the total supply and use of synthetic
nitrogen-based fertilizer from other data sources that addresses near-
term analytical needs, particularly for calculating national emissions
of N2O. We obtain current sales data from Association of
American Plant Food Control Officials (AAPFCO). The sales data is
equivalent to fertilizer application since the sales are from the last
licensed dealer.
EPA remains very interested in obtaining better data on
N2O emissions. Nitrous oxide emissions from agricultural
soils are an important source of greenhouse gas emissions in the United
States (approximately 3 percent in 2008), and the application to soils
of synthetic nitrogen-based fertilizer represents 26 percent of total
N2O emissions from this source.
EPA will continue to assess the need for a fertilizer reporting
requirement from domestic producers in the future in light of new
information or identification of policy or program needs. Further, EPA
recognizes that States play an important role in collecting the data
EPA currently uses, and the AAPFCO has indicated in a published article
that recent stresses on state budgets potentially threaten the
continued availability of these data.\3\ If data collection is
compromised further due to reduced state funding or other
circumstances, EPA will need to initiate a fertilizer reporting
requirement.
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\3\ D. Terry, 2006. ``Fertilizer Tonnage Reporting in the U.S.--
Basis and Current Need.'' Better Crops. 90(4). pp 14-17.
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EPA will also assess the need for information on the total supply
of synthetic nitrogen-based fertilizer, including imports, production
of fertilizer using imported feedstock, domestically-produced
fertilizer that is not in the agriculture sector, and fertilizer
exports.
Additionally, EPA will also assess the need for other types of
information (i.e., not related to fertilizer supply) relevant to
determining emissions and assessing mitigation opportunities for
N2O emissions from agricultural soils, consistent with the
Clean Air Act. Examples of other types of information that is relevant
to N2O oxide emissions from agricultural soils can be found
in the ``Technical Support Document for Biologic Process Sources
Excluded from this Rule,'' and include elements such as fertilizer
application rates, timing of application, and the use of slow-release
fertilizers and nitrification/urease inhibitors (Docket ID No. EPA-HQ-
OAR-2008-0508).
If EPA were to decide in the future to add a requirement to report
fertilizer production under the Mandatory GHG Reporting Rule, or any
other new requirement related to N2O emissions from
agricultural soils, it would initiate a new rulemaking process.
K. Subpart P (Hydrogen Production)
We are proposing several conforming amendments to be consistent
with the proposed amendments to the calibration requirements of 40 CFR
98.3(i). Section 98.164(b)(1) of subpart P currently specifies that all
oil and gas flow meters (except for gas billing meters), solids
weighing equipment, and oil tank drop measurements must be calibrated
according to 40 CFR 98.3(i). We are proposing to amend 40 CFR
98.164(b)(1) to make it consistent with today's proposed amendments to
40 CFR 98.3(i). First, we would limit the flow meter calibration
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to meters that
are used to measure liquid and gaseous feedstock volumes. In accordance
with 40 CFR 98.3(i)(1), all other measurement device that are used to
provide data for the GHG emissions calculations would have to be
calibrated to an accuracy within the appropriate error range for the
specific measurement technology, based on an applicable operating
standard, such as the manufacturer's specifications. Second, we would
remove the requirements for solids weighing equipment and oil tank drop
measurements to be calibrated according to 40 CFR 98.3(i), because the
provisions of 40 CFR 98.3(i) would apply only to gas and liquid flow
meters. For oil tank drop measurements, the QA requirements of 40 CFR
98.34(b)(2) would apply.
L. Subpart V (Nitric Acid Production)
We are proposing to amend 40 CFR 98.226 to remove the synthetic
fertilizer and total nitrogen reporting requirement in 40 CFR
98.226(o). The detailed rationale for this proposed amendment is
provided in section II.K of this preamble.
[[Page 48768]]
M. Subpart X (Petrochemical Production)
Numerous issues have been raised by owners and operators in
relation to the requirements in subpart X for petrochemical production
facilities. The issues being addressed by the proposed amendments
include the following:
Distillation and recycling of waste solvent.
Process vent emissions monitored by CEMS.
Process off-gas combustion in flares.
CH4 and N2O emissions from
combustion of process off-gas.
Molar volume conversion (MVC) factors.
Methodology for small ethylene off-gas streams.
Monitoring and QA/QC requirements.
Reporting requirements under the CEMS compliance option.
Reporting requirements for the ethylene-specific option.
Reporting measurement device calibrations.
Distillation and Recycling of Waste Solvent. We are proposing to
add a new paragraph 40 CFR 98.240(g) to specify that a process that
distills or recycles waste solvent that contains a petrochemical is not
part of the petrochemical production source category. Some processes
that distill or recycle waste solvents may produce products that
contain methanol or another petrochemical. Under the current subpart X,
such processes might be considered part of the petrochemical source
category because 40 CFR 98.240(a) specifies that all processes that
produce a petrochemical are part of the source category unless
specifically excluded. Although not specifically excluded in subpart X,
we did not intend to include waste solvent purification processes in
the petrochemical source category for the following reasons. First, in
processes subject to subpart X, the petrochemical is formed from other
chemicals, whereas in waste solvent purification processes the
petrochemical is not formed because it is present in the feedstock.
Second, processes that are in the source category generate significant
amounts of process-based GHG emissions as byproducts of reaction and/or
from the combustion of process off-gas for energy recovery. In
contrast, the only process-based GHG emissions, if any, from waste
solvent purification processes are from combustion of organic compounds
in process vent emissions that are routed to a combustion-based air
pollution control device.
Process vent emissions monitored by CEMS. We are proposing to add a
sentence to 40 CFR 98.242(a)(1) that specifies CO2 emissions
from process vents routed to stacks that are not associated with
stationary combustion units must be reported under subpart X when you
comply with the CEMS option in 40 CFR 98.243(b). Section 98.242(a)(1)
in the current subpart X specified that GHG emissions from stationary
combustion sources and flares that burn any amount of petrochemical
off-gas are to be reported under subpart X. However, we neglected to
specify reporting requirements under the CEMS option for process
emissions that are not associated with combustion units. The proposed
amendment would correct this oversight.
Process off-gas combustion in flares. We are proposing to amend 40
CFR 98.242(b) by removing the reference to flares. Section 98.242(b) in
subpart X specifies that CO2, CH4, and
N2O combustion emissions from stationary combustion units
and flares must be reported. However, the intent of 40 CFR 98.242(b) is
to identify only the GHGs from the combustion of supplemental fuels
that are to be reported under subpart C. Emissions from the combustion
of petrochemical process off-gas in a flare are process-based emissions
that are to be reported under subpart X as specified in 40 CFR
98.242(a). Therefore, the reference to flares in 40 CFR 98.242(b) is
incorrect and should be removed.
CH4 and N2O Emissions From Combustion Of
Process Off-Gas. We are proposing to amend 40 CFR 98.243(b) to clarify
procedures for calculating CH4 and N2O emissions
from combustion units that burn petrochemical process off-gas and are
monitored with a CO2 CEMS. Section 98.243(b) in subpart X
specifies that CH4 and N2O emissions from the
non-flare combustion of petrochemical process off-gas are to be
calculated using the Tier 3 procedures in subpart C, with the default
emission factors for ``Petroleum'' in Table C-2 of subpart C. This
procedure requires the use of equation C-8 to calculate the emissions.
One of the inputs for this equation is the default HHV of the fuel, and
default values for various fuels are listed in Table C-1 of subpart C.
As discussed in section II.H of this preamble, we have added a default
HHV for fuel gas in Table C-1, and we have revised the definition of
HHV for equation C-8 to allow the use of a site-specific calculated HHV
as an alternative to using a default value from Table C-1. Using either
a default HHV or a site-specific calculated value is also acceptable
when calculating CH4 and N2O emissions from the
combustion of fuel gas that contains petrochemical process off-gas.
Therefore, to clarify this point, we are proposing to add language to
40 CFR 98.243(b) specifying that either the default HHV for fuel gas in
Table C-1 or a site-specific calculated HHV is to be used in equation
C-8 when calculating CH4 and N2O emissions.
For the ethylene-specific option, 40 CFR 98.243(d) in subpart X
specifies the same procedures for calculating CH4 and
N2O emissions from non-flare combustion of process off-gas
as in 40 CFR 98.243(b). Therefore, we are proposing the same change to
40 CFR 98.243(d) as noted above for 40 CFR 98.243(b) to clarify that
either the default HHV for fuel gas or a site-specific calculated HHV
should be used for Tier 3 calculations.
Molar volume conversion (MVC) factors. Owners and operators have
requested that allowance be made for alternative standard conditions
within the molar volume conversion factor (MVC) used in Equation X-1 in
40 CFR 98.243(c). Equation X-1 of subpart X specified using an MVC of
849.5 scf/kgmole, which converts the volumetric flow from standard
cubic feet to kgmoles assuming the standard volume was determined at 68
[deg]F. Exhaust stack volumes are generally corrected using 68 [deg]F
as the standard temperature, and some petrochemical producers may also
use 68 [deg]F when expressing process volumes at standard conditions.
However, we recognize that the oil and gas industry and other
hydrocarbon processing facilities commonly express gaseous volumes
using 60 [deg]F as the standard temperature. Thus, many existing flow
monitors for gaseous feedstocks and products at petrochemical
facilities may be programmed to output volumes at standard conditions
of 60 [deg]F. It is impractical and unnecessary to either reprogram
these monitors to provide volumes corrected to standard conditions at
68 [deg]F or to require reporters to convert the output volumes from
one set of standard conditions to another before using Equation X-1
because an alternative MVC can be provided to yield the identical mass
emissions from the calculation.
Consequently, we are proposing to amend Equation X-1 to provide two
alternative values of MVC that correspond to the two most common
standard conditions output by the flow monitors. Additionally, the
reporting requirements related to this equation would be amended to
include reporting of the standard temperature at which the gaseous
feedstock and product volumes were determined (either 60 [deg]F or 68
[deg]F) and to afford verification of the reported emissions.
[[Page 48769]]
Methodology for small ethylene off-gas streams. Owners and
operators have suggested that EPA should allow the use of alternative
calculation methods for small emission sources. Specifically, they have
asserted that units subject to only subpart C are allowed to use Tier 1
or Tier 2 for units less than or equal to 250 mmbtu/hr heat input.
However, if those same units are at a petrochemical production facility
and combusting ethylene process off-gas, they are required to use Tier
3 or Tier 4.
We still believe that it is important to use Tier 3 or Tier 4 for
most units that burn ethylene process off-gas because combustion of
process off-gas is the primary source of GHG process emissions for
ethylene processes, the carbon content may vary among facilities
depending on the type of feedstock to the ethylene process units, and
the ratio of ethylene process off-gas to other fuels may vary in each
fuel gas system.
However, we recognize that some ethylene process off gas that is
burned in process heaters or boilers may not enter the fuel gas system
and that the lines conveying these off-gas streams may not have flow
monitors. For example, 40 CFR part 63, subpart YY, requires control of
process vent emissions from ethylene production process units; these
streams may be controlled by venting to a process heater or boiler, but
subpart YY does not require monitoring of the vent stream flow rate. It
was not our intent to require the installation of flow meters on these
ancillary gas streams that do not significantly contribute to the
overall heat input of the stationary combustion unit. In addition, we
recognize that facilities may only meter the primary fuel flow at
relatively large combustion units that are subject to emission
limitations that are related to the heat input rate. About one-third of
the ethylene production capacity is at petroleum refineries, and much
of the rest is at large integrated chemical manufacturing facilities.
Based on an analysis of process heaters at petroleum refineries (see
section II.O of this preamble), it appears that process heaters less
than 30 mmBtu/hr are often not subject to emission limitations and,
therefore, may not have metered flow. Furthermore, such combustion
units appear to represent only a small percentage of the total fuel use
at refineries. Given the large size of most other chemical
manufacturing facilities that make ethylene, it is likely that such
combustion units represent only a small percentage of total fuel use at
these facilities as well. Thus, easing the Tier 3 monitoring
requirements for these small combustion units would reduce the
compliance burden without significantly impacting the accuracy of the
nationwide GHG emission inventories for ethylene production.
Notwithstanding the above discussion, if a flow meter is installed
in the fuel gas line, including any common pipe, then we consider that
the Tier 3 monitoring requirements are reasonable and justified. In
such cases there will not be a significant burden to use the Tier 3
method, and the reported GHG emissions will be more accurate.
Therefore, we are proposing to amend 40 CFR 98.243(d) to allow the
use of Tier 1 or Tier 2 methods for small flows (in cases where a flow
meter is not already installed). Specifically, we are proposing that
Tier 1 or Tier 2 methods may be used for ethylene process off-gas
streams that meet either of the following conditions:
(1) The annual average flow rate of fuel gas (that contains
ethylene process off-gas) in the fuel gas line to the combustion unit,
prior to any split to individual burners or ports, does not exceed 345
scfm at 60 [deg]F and 14.7 pounds per square inch absolute, psia, and a
flow meter is not installed at any point in the line supplying fuel gas
or an upstream common pipe; or
(2) The combustion unit has a maximum rated heat input capacity of
less than 30 mmBtu/hr, and a flow meter is not installed at any point
in the line supplying fuel gas (that contains ethylene process off-gas)
or an upstream common pipe.
This amendment would also specify how to calculate the annual
average flow rate under the first condition. Specifically, the total
flow obtained from company records is to be evenly distributed over
525,600 minutes per year. We are also proposing a number of editorial
changes to 40 CFR 98.243(d) to clearly integrate the proposed option
with the existing requirements. Finally, we are proposing to amend 40
CFR 98.246(c)(2) and 98.247(c) to add reporting and recordkeeping
requirements that are related to the proposed amendments in 40 CFR
98.243(d)(2).
Monitoring Methods for Determining Carbon Content and Composition.
Owners and operators have suggested that EPA should not limit the use
of gas chromatograph methods for determining the carbon content,
composition, and the average molecular weight of feedstocks and
products to those methods listed in 40 CFR 98.244(b)(4). We are
proposing to add the method, ``ASTM D2593-93 (Reapproved 2009) Standard
Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas
Chromatography,'' to 40 CFR 98.244(b)(4). Butadiene is a by-product of
the ethylene production process, and after reviewing the method, we
have determined that it is an acceptable method for determining the
carbon content of that stream. We will consider including additional
methods in the final amendments after reviewing comments on this issue.
In order to evaluate this issue, we seek comments providing copies of
calibration procedures that gas chromatograph manufacturers supply with
their equipment, calibration procedures in any published or unpublished
industry consensus (or site-specific) methods not currently listed in
40 CFR 98.244(b)(4), and an assessment of how such procedures compare
to the currently specified methods and why they are applicable for
instruments used to measure petrochemical feedstocks and products.
We are proposing to further amend 40 CFR 98.244(b)(4) by adding a
new paragraph that would allow the use of industry consensus standard
methods to determine the carbon content or composition of carbon black
feedstock oils and carbon black products. Carbon black manufacturers
have reported that none of the listed methods are specific to carbon
black materials, and they have stated that such methods will provide
less accurate results than modified versions of some of the methods.
For example, the industry has reported that when they need to determine
the carbon content of their feedstocks or products they often use
modified versions of ASTM D5291-02. One difference is that the modified
methods use carbon or carbon/sulfur analyzers instead of the carbon,
hydrogen, and nitrogen analyzer that is specified in ASTM D5291-02.
These modified methods have been submitted to ASTM for review. If ASTM
publishes methods before the proposed amendments are finalized, we will
consider including them in the final amendments. The industry has also
reported that they often use other published methods to determine the
sulfur, ash, and water content of the material and then calculate the
carbon content as the difference between the mass of these compounds
and the total mass of the sample. This approach would also be allowed
under the proposed change to 40 CFR 98.244(b)(4). We seek comment on
the need for the proposed option. In particular, we are interested in
data that compare specified methods such as ASTM D5291-02 with industry
consensus methods. We are also interested in
[[Page 48770]]
obtaining copies of industry consensus standard methods.
We are also proposing to amend 40 CFR 98.244(b)(4) to provide
facilities the option of, under certain circumstances, the use of
alternative analytical methods in addition to the methods listed in 40
CFR 98.244(b)(4)(i) through (b)(4)(xi) for determining the carbon
content or composition of feedstocks or products. We recognize that the
applicability of the methods listed in 40 CFR 98.244(b)(4)(i) through
(b)(4)(xi) may be restricted for certain process streams due to the
analytical limitations of those methods and/or the instrumentation. As
a result, we are proposing to allow a facility to use an alternative
analytical method in cases where the methods listed in 40 CFR
98.244(b)(4)(i) through (b)(4)(xi) are not appropriate because the
relevant compounds cannot be detected, the quality control requirements
are not technically feasible, or use of the method would be unsafe.
We are proposing to amend the reporting requirements in 40 CFR
98.246(a)(11) so that if an alternative method is used, facilities
would include in the annual report the name or title of the method
used, and the first time it is used, a copy of the method and an
explanation of why the use of the alternative method is necessary.
We solicit comment on whether the flexibility provided by this
option is needed. If commenters believe that to be the case, please
provide information on the specific need for flexibility, why the
existing listed analytical methods are not sufficient, and whether the
proposed flexibility meets the needs identified.
We are proposing to make the amendments to 40 CFR 98.244(b)(4) as
described above retroactive to January 1, 2010. We have received
feedback that some reporters are using a method currently allowed in
Part 98 while concurrently also using a method that would be allowed by
today's action. Should these amendments be finalized, making these
amendments effective January 1, 2010 would allow reporters to use the
results from the methods included in today's amendments for the entire
year of 2010.
QA/QC Requirements. As mentioned in Section II.B of this preamble,
owners and operators have raised several issues regarding the
calibration requirements in Part 98, and we are proposing a number of
changes to 40 CFR 98.3(i) of subpart A to address those issues. To
maintain consistency with the proposed amendments to 40 CFR 98.3(i), we
are also proposing amendments to the QA/QC provisions for weighing
devices, flow meters, and tank level measurement devices in paragraphs
(b)(1), (b)(2), and (b)(3) of 40 CFR 98.244. Other proposed amendments
to these paragraphs are editorial in nature and intended to clarify the
requirements. Specific changes are as follows:
In 40 CFR 98.244(b), each of the three subparagraphs incorrectly
required compliance with calibration requirements in 40 CFR 98.3(i), or
with any of the following: procedures specified by equipment
manufacturers, industry consensus standard procedures, or procedures in
listed methods. We are proposing to amend these subparagraphs such that
the procedures in 40 CFR 98.3(i) would apply in addition to the other
required procedures.
We are proposing to amend 40 CFR 98.244(b)(1) to allow
recalibration at the interval specified by the industry consensus
standard practice used in addition to either biennially or at the
minimum frequency specified by the manufacturer. Note that the
requirements of 40 CFR 98.3(i) for other measurement devices would
apply as well.
Section 98.244(b)(2) in subpart X specifies that flow meters are to
be operated and maintained using the procedures in 40 CFR 98.3(i) and
either any one of several listed methods, a method published by a
consensus-based standards organization, or procedures specified by the
flow meter manufacturer. Although 40 CFR 98.244(b)(2) references 40 CFR
98.3(i), it does not explicitly specify calibration requirements, and
this reference incorrectly implies that 40 CFR 98.3(i) specifies
procedures other than calibration requirements. In addition, the option
to follow procedures in any of the listed methods is redundant because
it overlaps with the option to use a method published by a consensus
standards-based organization. To clarify these requirements we are
proposing several amendments to 40 CFR 98.244(b)(2). One would specify
that flow meters are to be operated and maintained according to
manufacturer's recommended procedures. A second would specify that flow
meters are to be calibrated following either an industry consensus
standard practice or procedures specified by the flow meter
manufacturer, and must meet the accuracy specification in 40 CFR
98.3(i). Finally, the list of specified methods would be deleted.
Section 98.244(b)(2) in subpart X specifies that flow meters are to
be recalibrated either biennially or at the minimum frequency specified
by the flow meter manufacturer. Since 40 CFR 98.244(b)(2) specifies
that flow meters may be calibrated following procedures in industry
consensus standard practices, we are proposing to also allow
recalibration at the frequency specified in such methods. This would
also make the recalibration requirements in 40 CFR 98.244(b)(2)
consistent with the proposed amendment in 40 CFR 98.3(i)(1)(iii)(B).
Section 98.244(b)(3) in subpart X specifies that tank level
measurement devices are to be calibrated prior to the effective date of
the rule. We are proposing to delete this statement because 40 CFR
98.3(i) specifies the date by which initial calibration must be
completed. Note that the requirements for other measurement devices in
40 CFR 98.3(i) apply as well.
Reporting Requirements Under The CEMS Compliance Option. We are
proposing a number of changes in 40 CFR 98.246(b)(1) through (b)(5) to
clarify the reporting requirements under the CEMS compliance option.
First, we are proposing to move the requirement for reporting of
the petrochemical process ID from 40 CFR 98.246(b)(3) to 40 CFR
98.246(b)(1) to be consistent with the structure in other reporting
sections, and we are renumbering the existing paragraphs (b)(1) and
(b)(2).
Second, we are proposing to add a statement in the renumbered
paragraph 40 CFR 98.246(b)(2) to specify that the reporting
requirements in 40 CFR 98.36(b)(9)(iii) (as numbered in today's
proposed action) for CH4 and N2O do not apply
under subpart X. This reporting requirement in subpart C is not
relevant in subpart X because 40 CFR 98.246(b)(5) specifies the
reporting requirements for CH4 and N2O under
subpart X.
Third, in the renumbered 40 CFR 98.246(b)(3), we are proposing to
delete the requirement to report information required under 40 CFR
98.36(e)(2)(vii) because the referenced section specifies recordkeeping
requirements, not reporting requirements; note that you still must keep
the applicable records because 40 CFR 98.247(a) references 40 CFR
98.37, which in turn requires you to keep all of the applicable records
in 40 CFR 98.36(e). We are also proposing to amend the reference to 40
CFR 98.36(e)(2)(vii) to a more general reference of 40 CFR 98.36. This
makes the reporting requirements consistent with the methodology for
calculating emissions in 40 CFR 98.243(b).
Fourth, we are proposing changes to 40 CFR 98.246(b)(4) to clarify
our intent. The first sentence in 40 CFR 98.246(b)(4) requires
reporting of the total CO2 emissions from each stack that
[[Page 48771]]
is monitored with CO2 CEMS; this requirement would be
unchanged. We are proposing changes to the second sentence in 40 CFR
98.246(b)(4) to clarify that for each CEMS that monitors a combustion
unit stack you must estimate the fraction of the total CO2
emissions that is from combustion of the petrochemical process off-gas
in the fuel gas. This estimate will give an indication of the total
petrochemical process emissions, whereas the CEMS data alone would also
include emissions from combustion of supplemental fuel (if any).
Finally, we are proposing several amendments to 40 CFR
98.246(b)(5). In general, as noted above, the requirements in this
paragraph are consistent with the requirements in 40 CFR
98.36(b)(9)(iii) (as numbered in this proposed action). Most of the
proposed amendments to 40 CFR 98.246(b)(5) restate requirements from 40
CFR 98.36(b)(9)(iii); for example, the proposed amendments clarify that
emissions are to be reported in metric tons of each gas and in metric
tons of CO2e. However, because 40 CFR 98.36(b)(9)(iii)
allows you to consider petrochemical process off-gas as a part of
``fuel gas'' rather than as a separate fuel, 40 CFR 98.246(b)(5) also
would require you to estimate the fraction of total CH4 and
N2O emissions in the exhaust from each stack that is from
combustion of the petrochemical process off-gas. In addition, because
40 CFR 98.243(b) requires you to determine CH4 and
N2O emissions using Equation C-8 in subpart C (rather than
Equation C-10), the amendments to 40 CFR 98.246(b)(5) would require
reporting of the HHV that you use in Equation C-8. This change also
would delete the erroneous reference to Equation C-10 that was included
in 40 CFR 98.246(b)(5).
Reporting Requirements for the Ethylene-Specific Option. We are
proposing several changes to clarify the reporting requirements in 40
CFR 98.246(c) for the ethylene-specific option. First, we are proposing
to add a requirement to report each ethylene process ID to allow
identification of the applicable process units at facilities with more
than one ethylene process unit. Second, we are proposing editorial
changes to clarify that you must estimate the fraction of total
combustion emissions that is due to combustion of ethylene process off-
gas, consistent with the requirements described above for combustion
units that are monitored with CEMS. Third, because ethylene is the only
petrochemical product for process units that can comply with the
ethylene-specific option, we are proposing to replace the requirement
to report the ``annual quantity of each type of petrochemical produced
from each process unit'' with a requirement to report the ``annual
quantity of ethylene produced from each process unit.''
Reporting Measurement Device Calibrations. In 40 CFR 98.246(a)(7)
we are proposing to delete the requirement for reporting of the dates
and summarized results of calibrations of each measurement device under
the mass balance option. We have determined that maintaining records of
this information will be sufficient. Thus, we are also proposing to add
40 CFR 98.247(b)(4) to require retention of these records.
N. Subpart Y (Petroleum Refineries)
Numerous issues have been raised by owners and operators in
relation to the requirements in subpart Y for petroleum refineries. The
issues being addressed by the proposed amendments include the
following:
GHG emissions from flares.
GHG emissions to report from combustion of fuel gas.
GHG emissions to report from non-merchant hydrogen
production process units.
Calculating GHG emissions from fuel gas combustion.
Calculating combustion GHG emissions from flares and
thermal oxidizers.
Molar volume conversion factors.
Combined stacks monitored by CEMS.
Nitrogen concentration monitoring to determine exhaust gas
flow rate.
Calculating CO2 emissions from catalytic
reforming units.
Calculating GHG emissions from sulfur recovery plants.
Calculating CO2 emissions from coke calcining
units.
Calculating CO2 emissions from process vents.
Reactor vessels using methane as a blanket or purge gas.
Monitoring and QA/QC requirements.
Reporting requirements.
GHG Emissions From Flares. We are proposing several corrections to
40 CFR 98.252(a) (GHGs to report) to clarify the required emissions
methods for flares. From the first sentence in 40 CFR 98.252(a), it is
clear that CO2, CH4, and N2O
combustion emissions are to be calculated for stationary combustion
units and for each flare. However, the second sentence suggests that
petroleum refinery owners or operators are to ``[c]alculate and report
these emissions under subpart C * * *'' (emphasis added). After the
first sentence, the remainder of 40 CFR 98.252(a) specifically
addresses how petroleum refinery owners or operators are to calculate
and report stationary combustion unit emissions. Flare emissions are to
be calculated using the methods provided in subpart Y, not the methods
provided in subpart C. Consequently, we are proposing to amend the
second sentence in 40 CFR 98.252(a) to correctly require reporters to
``Calculate and report the emissions from stationary combustion units
under subpart C * * *'' and we are proposing to add an additional
sentence at the end of this section to clarify that reports must
``Calculate and report the emissions from flares under this subpart.''
GHG Emissions to Report From Combustion of Fuel Gas. We are
proposing to amend 40 CFR 98.252(a) to clarify that reporting of
CH4 and N2O emissions is required for the
stationary combustion units fired with fuel gas. It was always our
intent that the emissions of these pollutants be reported for
stationary combustion sources that used fuel gas. However, as no
default factors for fuel gas were previously included in Table C-1 of
subpart C, it could be interpreted that these emissions were not
required to be reported, even though the first sentence clearly
indicates that emissions of all three pollutants were to be reported
for stationary combustion units and flares. While the proposed
amendment to Table C-1 to include default factors for ``fuel gas'' is
expected to correct this misinterpretation, we are also proposing to
add the following sentence to 40 CFR 98.252(a) to clarify these
reporting requirements: ``For CH4 and N2O
emissions from combustion of fuel gas, use the applicable procedures in
40 CFR 98.33(c) for the same tier methodology that was used for
calculating CO2 emissions (use the default CH4
and N2O emission factors for ``Petroleum (All fuel types in
Table C-1)'' in table C-2 of subpart C of this part and for Tier 3,
either the default high heat value for fuel gas in Table C-1 of subpart
C of this part or a calculated HHV, as allowed in Equation C-8 of
subpart C of this part.''.
GHG Emissions To Report From Non-Merchant Hydrogen Production
Process Units. We are also proposing to amend 40 CFR 98.252(i) to
clarify that reporting of only CO2 emissions from non-
merchant hydrogen production process units is required. The inclusion
of ``and CH4'' emissions was an inadvertent error. We are
also proposing to amend 40 CFR 98.252(i) to clarify that catalytic
reforming units (although they produce hydrogen as an important by-
product) are not considered hydrogen production
[[Page 48772]]
process units that are required to report under 40 CFR 98.252(i).
Calculating GHG Emissions From Fuel Gas Combustion. Owners and
operators have suggested that EPA should allow the use of alternative
calculation methods for small emission sources from the combustion of
fuel gas. Specifically, they have asserted that units subject to only
subpart C may use Tier 1 or Tier 2 if the units are less than or equal
to 250 mmbtu/hr heat input. However, if those same units are at a
petroleum refinery and combusting fuel gas, they are required to use
Tier 3 or Tier 4. We still believe that it is important to use Tier 3
or Tier 4 for most units at a petroleum refinery because of the
variability in carbon content in fuel gas (both between different
refineries and at different times within the same refinery). However,
we recognize that some flows of fuel gas to process heaters or boilers
may not necessarily enter the refinery's fuel gas system and that these
fuel gas lines may not have flow monitors. For example, 40 CFR part 63
subpart UUU requires the control of purging operations associated with
the catalytic reforming unit. Among the control options for these
emissions are provisions to vent these gases to a boiler or process
heater. If the stationary combustion source has a design capacity of 44
MW or greater or if the gases are introduced into the flame zone of the
unit, then direct monitoring of these gas streams is not required under
subpart UUU. Similar provisions that may pertain to petroleum
refineries are in other rules (e.g., 40 CFR part 60, subparts III and
NNN; 40 CFR part 63, subparts G and CC). It is not our intent to
require direct flow monitoring of these ancillary gas streams,
particularly if they do not significantly contribute to the overall
heat input of the stationary combustion unit.
In addition, while we anticipate that most refineries can use a
common-pipe monitoring approach for stationary combustion sources
supplied by the refinery's fuel gas system(s), we recognize that some
refineries may meter fuel usage at the stationary combustion sources
and, in some cases, only meter fuel usage at the larger units. Based on
a review of consent decrees and permits pertaining to process heaters,
it appears that process heaters less than 30 mmBtu/hr are often not
subject to emission limitations, and therefore may not have metered
flow. We performed an analysis of fuel use requirements by process
unit. From this analysis, we project that more than 95 percent of
nationwide fuel gas consumption at petroleum refineries would occur in
process heaters with a rated heat capacity of 30 mmBtu/hr or greater.
For additional detail on the consent decree review as well as the
analysis of fuel use requirements, please see the Background Technical
Support Document (EPA-HQ-OAR-2008-0508). While these small process
heaters represent only a small percentage of the fuel use on a national
level, most process heaters at petroleum refineries with capacities
under 25,000 barrels per day (which represents about 20 percent of the
refineries, but only 2 percent of the refining capacity) are expected
to have rated heat capacity of less than 30 mmBtu/hr. Thus, easing the
Tier 3 monitoring requirements for these smaller process heaters would
significantly ease the burden for small refineries without
significantly impacting the accuracy of the nationwide GHG inventories
for petroleum refineries.
If flow meters are in place at the process heater or at a common
pipe location, we consider that the Tier 3 monitoring requirements are
reasonable and justified. There will not be a significant burden to use
the Tier 3 method and the reported GHG emissions will be more accurate
given the fluctuations expected in fuel gas compositions.
Therefore, we are proposing to amend 40 CFR 98.252(a) so that
petroleum refineries subject to subpart Y could use the Tier 1 or 2
methodologies for combustion of fuel gas when either of the following
conditions exists:
(1) The annual average fuel gas flow rate in the fuel gas line to
the combustion unit, prior to any split to individual burners or ports,
does not exceed 345 scfm at 60[deg]F and 14.7 psia and either of the
following conditions exist:
A flow meter is not installed at any point in the line
supplying fuel gas or an upstream common pipe; or
The fuel gas line contains only vapors from loading or
unloading, waste or wastewater handling, and remediation activities
that are combusted in a thermal oxidizer or thermal incinerator.
(2) The combustion unit has a maximum rated heat input capacity of
less than 30 mmBtu/hr and either of the following conditions exist:
A flow meter is not installed at any point in the line
supplying fuel gas or an upstream common pipe; or
The fuel gas line contains only vapors from loading or
unloading, waste or wastewater handling, and remediation activities
that are combusted in a thermal oxidizer or thermal incinerator.
These amendments, combined with the revisions to Table C-1 of
subpart C, reflect our original intent to require Tier 3 or 4
monitoring and calculation methods for large fuel gas streams such as
those anticipated in the refinery's fuel gas system(s), but to allow
Tier 1 or 2 monitoring methods for smaller fuel gas streams that are
segregated from the fuel gas system or for small combustion sources at
refineries where flow monitors are installed at the majority of
individual combustion sources, but not at the smaller combustion
sources or the common pipe (i.e., fuel gas system).
Calculating Combustion GHG Emissions From Flares And Thermal
Oxidizers. It has been brought to our attention that it is
inappropriate to apply the 98 percent combustion efficiency to the
carbon as CO2 that already exists in the gas stream in
Equations Y-1 and Y-16 in 40 CFR 98.253. While the correction is
expected to be minor in most cases, we agree that all of the
CO2 that already exists in the gas stream will be emitted as
CO2 from these sources. However, we are concerned that,
depending on the method used to determine the carbon content, some
facilities may not have collected the specific CO2 data
needed to implement the revised equations. Therefore, we are proposing
to amend 40 CFR 98.253 by retaining the existing Equations Y-1 and Y-
16, re-numbering them as Equations Y-1a and Y-16a, and to add the more
detailed equations that specifically consider the CO2 that
already exists in the gas stream prior to the flare or thermal
combustion device as Equations Y-1b and Y-16b. Facilities that were
required to or elected to use Equation Y-1 to report flare emissions
would be able to choose to report these emissions using either Equation
Y-1a or Y-1b, as proposed in today's amendments. Similarly, we are
proposing to allow facilities required to report CO2
emissions from asphalt blowing operations controlled by a thermal
oxidizer or flare to use either Equation Y-16a or Y-16b. We are
proposing corresponding amendments in 40 CFR 98.256 to require
reporting of which equation was used and, if the new equations are
used, reporting of the additional equation parameters.
We request comment on the need to retain the previously promulgated
equations. As gas composition data are expected to be determined using
gas chromatographic methods, the required CO2 data may
already be collected. Thus, we are particularly interested to determine
if there are facilities that cannot implement the new equations based
on the measurement data already
[[Page 48773]]
collected for these sources during the 2010 reporting year.
Molar volume conversion factors. Owners and operators have
suggested that allowance be made for alternative ``standard
conditions'' within the MVC factor used in several of the equations in
40 CFR 98.253. We recognize that natural gas and fuel gas volumes are
commonly determined using 60[deg]F as the standard temperature whereas
exhaust stack volumes are commonly determined using 68[deg]F as the
standard temperature. Both of these volume measurements are specified
in subpart Y. It is impractical and unnecessary for existing fuel gas
monitors, most of which have been installed to correct volumes to
standard conditions at 60[deg]F, to be reprogrammed to output these
volumes corrected to standard conditions at 68[deg]F when an
alternative MVC can be provided to yield the identical mass emissions
from the calculation. Consequently, we are proposing to amend equations
Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y-20, and Y-23 in subpart Y to provide
two alternative values of MVC depending on the standard conditions
output by the flow monitors. Additionally, the reporting requirements
related to each of these equations would be amended to include
reporting of the value of MVC used to support the calculations and to
afford verification of the reported emissions.
Combined Stacks Monitored By CEMS. We received several questions
regarding whether or not discharges through a combined stack are
allowable when CEMS are used, particularly for the catalytic cracking
unit. We never intended to limit the use of combined stacks and CEMS at
the refinery. In fact, we specifically attempted to address this issue
in subpart Y with respect to the combined catalytic cracking unit and
CO boiler emissions in 40 CFR 98.253(c)(1)(ii). However, we have
determined that the current language in 40 CFR 98.253(c)(1)(ii) may
inadvertently be interpreted to exclude other CO2 emission
sources that may be mixed with the catalytic cracking unit process
(e.g., coke burn-off) emissions.
Consequently, we are proposing to amend the language in 40 CFR
98.253(c)(1)(ii) and also the reporting requirements in 40 CFR
98.256(f)(6) to generalize the language to include other CO2
emission sources, not just a CO boiler. The proposed amendments would
clarify that when a CEMS is used to measure the CO2
emissions from the catalytic cracking unit and these emissions are
combined with ``other CO2 emissions,'' the owner or operator
must calculate the ``other CO2 emissions'' using the
applicable methods for the applicable subpart (e.g., subpart C of this
part in the case of a CO boiler), and determine the process emissions
from the catalytic cracking unit (or fluid coking unit) as the
difference in the CO2 CEMS measurements and the calculated
emissions associated with the ``other CO2 emissions.''
Nitrogen Concentration Monitoring To Determine Exhaust Gas Flow
Rate. We also received questions regarding the use of nitrogen
(N2) concentration monitoring for Equation Y-7 in 40 CFR
98.253(c)(2)(ii). Equation Y-7 uses an inert balance to calculate the
exhaust gas flow rate, and a similar calculation can be performed using
a nitrogen balance. We agree that the nitrogen monitoring approach
would provide an equivalent measure of the exhaust gas flow rate as
Equation Y-7. We promulgated Equation Y-7 because we anticipated
several facilities used this monitoring approach as this equation is
provided in the 40 CFR part 63 subpart UUU (see Equation 2 of 40 CFR
63.1573). However, we note that 40 CFR 63.1573 also allows facilities
to request alternative monitoring methods. There are no similar
provisions in subpart A or subpart Y of part 98, so this monitoring
alternative could not be used without amending the rule. As we find the
N2 concentration monitoring approach to be equivalent to
Equation Y-7, we are proposing to amend 40 CFR 98.253(c)(2)(ii) to
renumber Equation Y-7 as Equation Y-7a and adding an Equation Y-7b to
provide this N2 concentration monitoring approach. We are
also proposing to add reporting requirements in 40 CFR 98.256(f) to
report the input parameters for Equation Y-7b if it is used.
Calculating CO2 Emissions from Catalytic Reforming
Units. We are proposing to revise the definition of the coke burn-off
quantity, CBQ, the term ``n'' in Equation Y-11 in 40 CFR
98.253(e)(3) to clarify the application of Equation Y-11 to
continuously regenerated catalytic reforming units. Continuously
regenerated catalytic reforming units do not have specific cycles, so
the reference to ``regeneration cycle'' in the definition of these
terms was ambiguous or meaningless for continuously regenerated
catalytic reforming units. We are proposing to replace the phrase
``regeneration cycle'' with ``regeneration cycle or measurement
period'' in the definition of the coke burn-off quantity and to revise
the definition of ``n'' to be the ``Number of regeneration cycles or
measurement periods in the calendar year.'' A measurement period may be
a day, week, month, or other time interval over which process
measurements are made on the unit by which the coke burn-off rate is
determined. We are similarly proposing to clarify 40 CFR 98.256(f)(13)
(formerly designated 40 CFR 98.256(f)(12)) to require reporting of ``*
* * the number of regeneration cycles or measurement periods during the
reporting year, the average coke burn-off quantity per cycle or
measurement period, and the average carbon content of the coke'' when
Equation Y-11 is used.
Calculating GHG Emissions From Sulfur Recovery Plants. With respect
to requirements for sour gas sent off-site for sulfur recovery and for
on-site sulfur recovery plants, we intended these requirements to be
identical and that the petroleum refinery would report these emissions
regardless of whether the sour gas feed is used at an on-site sulfur
recovery plant within the refinery facility or the sour gas feed is
sent to an off-site facility. However, we do note that the requirements
were developed considering Claus sulfur recovery plants and that the
methods in 40 CFR 98.253(f) may not be appropriate for all other types
of sulfur recovery plants. To clarify the requirements for sulfur
recovery plants, we are proposing to amend 40 CFR 98.253(f) to add
``and for sour gas sent off-site for sulfur recovery'' to clarify that
this calculation methodology applies ``For on-site sulfur recovery
plants and for sour gas sent off-site for sulfur recovery, * * *'' and
to allow non-Claus sulfur recovery plants to alternatively follow the
requirements in 40 CFR 98.253(j) for process vents. We also are
proposing to amend the reporting requirements in 40 CFR 98.256(h) to
include the type of sulfur recovery plant and an indication of the
method used to calculate CO2 emissions as well as reporting
requirements for non-Claus sulfur recovery plants that elect to follow
the requirements in 40 CFR 98.253(j) for process vents. While we
believe the calculation methodology needs no further regulatory text
amendments, we do clarify in this preamble that the phrase ``the sulfur
recovery plant'' in 40 CFR 98.253(f) refers to either the on-site or
off-site sulfur recovery plant, as applicable. We further clarify in
this preamble that the sour gas flow and carbon content measurements
for sour gas sent off-site for sulfur recovery may be made at either
the refinery or the off-site sulfur recovery plant provided these
measurements are representative of the flow and carbon content of the
sour gas sent off-site for sulfur recovery.
Calculating CO2 Emissions From Coke Calcining Units. We
are proposing to amend the definition of Mdust (the mass
[[Page 48774]]
of dust collected in the dust collection system) in Equation Y-13 in 40
CFR 98.253(g). It was brought to our attention that dust collected by
the control systems may be recycled back to the coke calciner, raising
the issue of how Mdust should be determined in this
situation: Is it the mass of dust collected in the dust collection
system or is it the mass of dust that is discarded from the system? The
mass balance represented by Equation Y-13 should be applied external to
this recycle loop, so that Mdust is the quantity of dust
removed from the overall process, which would be the mass of the dust
collected in the control system minus the mass of dust recycled. We
are, therefore, proposing to amend the definition of Mdust
in Equation Y-13 to clarify this interpretation of Mdust
when all or a portion of the collected dust is recycled back to the
coke calciner. We also are proposing to amend 40 CFR 98.256(i)(5) to
require facilities that use Equation Y-13 to indicate whether or not
the collected dust is recycled to the coke calciner.
Calculating CO2 Emissions From Process Vents. We are
proposing to amend the process vent requirements in 40 CFR 98.253(j)
due to the additional sources that may elect to use Equation Y-19,
specifically non-Claus sulfur recovery units (as previously described)
and uncontrolled blowdown vents (inadvertently not referenced). This
amendment clarifies that the emissions from the sources that elect to
use the process vent method in 40 CFR 98.253(j), must use Equation Y-19
to calculate the emissions for the pollutants required to be reported
under the cross-referencing section, regardless of whether the
concentration thresholds in 40 CFR 98.253(j) are exceeded. We are also
proposing to amend the definition of Equation Y-19's parameters of VR
(the volumetric flow rate) and MFx (the mole fraction of the
GHG in the vent). For these parameters we are proposing to clarify that
these values are to be determined ``from measurement data, process
knowledge, or engineering estimates.'' We are also proposing to amend
the reporting requirements for process vents to clarify that the
requirements apply to each process vent as well as to provide an
indication of the measurement of estimation method.
Finally, we are proposing to amend 40 CFR 98.253(n) to delete the
words ``equilibrium'' and ``product-specific'' to clarify that the true
vapor phase of the loading operation system should be used when
determining whether the vapor-phase concentration of methane is 0.5
volume percent or more. We affirm that process knowledge may be used to
determine which loading operations have a vapor-phase concentration of
methane of 0.5 volume percent, but this determination must be made
considering both the material being loaded and the conditions of the
loading operations. Equilibrium vapor-phase concentrations can be used
as process knowledge to determine if the concentration of methane is
0.5 volume percent or more.
Monitoring and QA/QC Requirements. In subpart Y, 40 CFR 98.254
currently specifies QA/QC requirements for fuel flow meters, gas
composition monitors, and heating value monitors that provide data for
the GHG emissions calculations. A distinction is made in paragraphs (a)
and (b) between measurement devices associated with stationary
combustion sources, which are required to follow the QA/QC procedures
in 40 CFR 98.34, and devices associated with other GHG emissions
sources at the refinery, which are to be quality-assured according to
40 CFR 98.254(c) through (e). Paragraphs (f), (g), and (h) of 40 CFR
98.254 QA/QC requirements for:
Stack gas flow rate monitors that are used to comply with
the requirements of 40 CFR 98.253(c)(2)(ii);
CO2/CO/O2 composition monitors used
to comply with 40 CFR 98.253(c)(2); and
Weighing devices that are used to measure the mass of
petroleum coke when CO2 emissions from a coke calcining unit
are calculated using Equation Y-13.
In subpart Y, 40 CFR 98.254(l) provides QA/QC requirements for
CO2 CEMS and flow monitors used for direct measurement of
CO2 emissions following the Tier 4 methodology in subpart C.
We are proposing to amend 40 CFR 98.254(a) through (h), and (l) as
follows, to make them consistent with today's proposed revisions to 40
CFR 98.3(i), and to make some necessary technical corrections and
clarifications:
Paragraph (a) of 40 CFR 98.254 would be amended to also include the
phrase ``sources that use a CEMS to measure CO2 emissions
according to subpart C of this part * * *'' to further separate these
sources from those that are covered by 40 CFR 98.254(b). Although the
CEMS monitoring requirements are specified in 40 CFR 98.254(l), these
requirements are more clearly specified by the proposed amendments to
40 CFR 98.254(a) so that all sources required to meet the methods
provided in subpart C are identified in a single paragraph. We also are
proposing to re-word the phrase ``follow the monitoring and QA/QC
requirements in 40 CFR 98.34'' with ``meet the applicable monitoring
and QA/QC requirements in 40 CFR 98.34'' to clarify that the monitors
must meet the requirements for the specific Tier for which monitoring
was required (Tier 3 sources would comply with the Tier 3 requirements;
Tier 4 sources would comply with the Tier 4 requirements; etc.).
Because the QA/QC requirements for CO2 CEMS that were
formerly included in 40 CFR 98.254(l) would be included in the amended
paragraph 40 CFR 98.254(a), we are proposing to delete 40 CFR
98.254(l).
Paragraph (b) of 40 CFR 98.254 would be amended to clarify that
these requirements apply to gas flow meters, gas composition monitors,
and heating value monitors other than those subject to 40 CFR
98.254(a). We would correct the reference to ``paragraphs (c) through
(e)'' to correctly reference ``paragraphs (c) through (g)'' as gas
monitoring system requirements are specified in 40 CFR 98.254(c)
through (g). We would also clarify that the calibration requirements in
40 CFR 98.3(i) only apply to gas flow meters and to allow recalibration
of gas flow meters biennially (every two years), at the minimum
frequency specified by the manufacturer, or at the interval specified
by the industry consensus standard practice used. Paragraph (b) of 40
CFR 98.254 would also be amended to clarify that gas composition and
heating value monitors must be recalibrated either annually, at the
minimum frequency specified by the manufacturer, or at the interval
specified by the industry consensus standard practice used.
Paragraph (c) of 40 CFR 98.254 would be amended to clarify that the
flare or sour gas flow meters must be calibrated (in addition to
operated and maintained) using either a method published by a
consensus-based standards organization (e.g., ASTM, API, etc.) or the
procedures specified by the flow meter manufacturer. The 5
percent accuracy specification would be removed from 40 CFR 98.254(c),
because the accuracy requirement for these flow meters is stated in the
general provisions at 40 CFR 98.3(i) and is referenced in 40 CFR
98.254(b). We are also proposing to amend 40 CFR 98.254(c) by removing
the list of methods as this is redundant with the existing phrase, ``a
method published by a consensus-based standards organization.''
Paragraphs (d) and (e) of 40 CFR 98.254 would be amended to allow
the use of any chromatographic analysis to determine flare gas
composition and high heat value, as an alternative to the methods
listed in 40 CFR 98.254(d) and
[[Page 48775]]
(e) provided that the gas chromatograph is operated, maintained, and
calibrated according to the manufacturer's instructions; and the
methods used for operation, maintenance, and calibration of the GC are
documented in the written monitoring plan for the unit under 40 CFR
98.3(g)(5). Paragraph (d) in 40 CFR 98.254 would also be amended to
apply to all gas composition monitors, other than those included in 40
CFR 98.254(g), and not just flare gas composition monitors. This is
needed to address gas composition monitors that may already be in place
on process vents subject to reporting under 40 CFR 98.253(j), so that
these monitors can use alternatives to the methods in 40 CFR 98.254(d).
We are also proposing to amend 40 CFR 98.254(d) to specify that the
methods in this paragraph are also to be used for determining average
molecular weight of the gas, which is needed in Equations Y-1a and Y-3.
We are also proposing to add an additional method (ASTM D2503-92) to
this section for determining average molecular weight. Methods for
determining average molecular weight were inadvertently omitted from
this section.
We are proposing a number of amendments to 40 CFR 98.254(f). First,
the applicability of this paragraph would be expanded to include all
gas flow meters on process vents subject to reporting under 40 CFR
98.253(j). The term ``exhaust gas flow meter'' would be replaced with
the term ``gas flow meter,'' because not all process vents that would
report under 40 CFR 98.253(j) are combustion (``exhaust'') related gas
streams.
Subpart Y currently allows an option to follow 40 CFR 63.1572(c)
(in the NESHAP for Petroleum Refineries) for installation, operation,
and calibration of the stack gas flow rate monitor or the requirements
in 40 CFR 98.254(f)(1) through (f)(4). In our review of these
requirements, we found that 40 CFR 98.254(f)(1) and (f)(3) were
important requirements that were not delineated in 40 CFR 63.1572(c).
However, 40 CFR 98.254(f)(2) is not appropriate (accuracy requirements
for these flow meters are already provided in the general provisions in
40 CFR 98.3(i) and are referenced in 40 CFR 98.254(b)), and 40 CFR
98.254(f)(4) is duplicative of the requirements in 40 CFR 63.1572(c).
We are proposing to retain portions of 40 CFR 98.254(f)(1) and (3),
but only as general, supplementary guidelines for flow monitor
installation and operation. Thus, we are proposing that these stack
flow monitors must:
Install, operate, calibrate, and maintain each stack gas
flow meter according to the requirements in 40 CFR 63.1572(c);
Locate the flow monitor at a site that provides
representative flow rates (avoiding locations where there is swirling
flow or abnormal velocity distributions); and
Use a monitoring system capable of correcting for the
temperature, pressure, and moisture content to output flow in dry
standard cubic feet (standard conditions as defined in 40 CFR 98.6).
We are proposing to make a technical correction to 40 CFR
98.254(g). Subpart Y currently requires the CO2/CO/
O2 composition monitors that are used to comply with the
requirements of 40 CFR 98.253(c)(2) be installed, operated, maintained,
and calibrated according to either 40 CFR 60.105a(b)(2) (in the NSPS
for Petroleum Refineries) or 40 CFR 63.1572(a), or according to the
manufacturer's specifications and requirements. The reference to 40 CFR
63.1572(a) was in error and should be 40 CFR 63.1572(c). In the NESHAP
for Petroleum Refineries (40 CFR part 63 subpart UUU), these monitors
are used to calculate coke burn-off rates, which are monitored to
ensure the control device is operated within specified limits. Thus,
these monitors are subject to 40 CFR 63.1572(c) within the NESHAP for
Petroleum Refineries, and this is the level of QA that these monitoring
systems are expected to be currently following. We note that
CO2 monitors that are certified and calibrated as CEMS (with
the appropriate flow monitoring system) would be subject to the
requirements in 40 CFR 98.253(c)(1), not 40 CFR 98.253(c)(2).
Consequently, we specifically refer to the monitors within this 40 CFR
98.254(g) as ``CO2/CO/O2 composition monitors''
rather than CEMS to avoid confusion that these monitors must be
operated according to CEMS requirements. In developing Part 98, we
required CO2/CO/O2 composition monitors for
catalytic cracking units and fluid coking units with rated capacities
greater than 10,000 barrels per stream day because these monitors were
expected to be in-place to comply with the NESHAP for Petroleum
Refineries. We did not include additional costs to upgrade the existing
CO2/CO/O2 composition monitors in our impact
analysis because we intended to use the same monitoring requirements as
in the NESHAP for Petroleum Refineries. Therefore, we are proposing to
amend 40 CFR 98.254(g) to refer to 40 CFR 63.1572(c), rather than
63.1572(a), for these O2/CO/O2 composition
monitors.
Paragraph (h) of 40 CFR 98.254 specifies calibration procedures for
weighing devices that are used to determine the mass of petroleum coke
fed to the coke calcining unit, as required by Equation Y-13. Subpart Y
currently provides three calibration options: (1) Follow the procedures
in NIST Handbook 44; (2) follow the manufacturer's recommended
procedures; or (3) follow the procedures in 40 CFR 98.3(i). We are
proposing to amend 40 CFR 98.254(h) to require calibration according to
the procedures specified by NIST Handbook 44 or the procedures
specified by the manufacturer. Note that the requirements of 40 CFR
98.3(i) for other measurement devices would apply as well.
Reporting Requirements. This section covers reporting requirements
that have not been described in previous sections of this preamble.
We are proposing to amend the reporting requirements for Equation
Y-1 (renumbered to Y-1a) and Y-2 to require reporting of whether daily
or weekly measurement periods are used, for verification purposes.
In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 CFR
98.256(i)(6), we are proposing to amend the references to 40 CFR
98.36(e)(2)(vi) to reference 40 CFR 98.36 more generally. This would
make the references consistent with the associated requirements in 40
CFR 98.253.
In our review of the reporting requirements in 40 CFR 98.256(f), we
noted an inadvertent error in 40 CFR 98.256(f)(10) and (11) [which
would be redesignated 40 CFR 98.256(f)(11) and (12) due to the proposed
reporting requirement associated with Equation Y-7b]. In subpart Y,
facility owners and operators are required to report information about
unit-specific emission factors for CH4 and N2O,
but not necessarily report the unit-specific emission factor itself. We
are proposing to correct this inadvertent error and require direct
reporting of the unit-specific emission factor for CH4 and
N2O, if used, in the newly designated 40 CFR 98.256(f)(11)
and (12), respectively.
We are proposing to amend 40 CFR 98.256(i)(8) to make it consistent
with the information collected in 40 CFR 98.245(i)(7).
We are also proposing to amend 40 CFR 98.256(j)(2) to clarify that
the reporting requirements for asphalt blowing apply at the unit level.
We are also proposing to re-organize the reporting requirements in
40 CFR 98.256(o) to clarify, for example, that the reporting
requirement in 40 CFR 98.256(o)(7) of Part 98 pertains specifically to
tanks processing unstabilized crude oil.
[[Page 48776]]
O. Subpart AA (Pulp and Paper Manufacturing)
We are proposing to amend subpart AA in response to questions EPA
received since Part 98 was published on October 30, 2009. These
amendments are intended to provide clarification and ensure consistency
with other parts of the rule.
EPA received questions regarding the methods specified in 40 CFR
98.273 to calculate fossil-fuel based CO2 emissions from
chemical recovery furnaces, chemical recovery combustion units, and
pulp mill lime kilns. Specifically, clarification was requested as to
whether an owner or operator can choose to use a tier other than Tier 1
from 40 CFR 98.33 to calculate fossil-fuel based CO2
emissions. While it was our intent to provide this flexibility, the
rule text indicated that only Tier 1 could be used. Therefore, we are
proposing to amend 40 CFR 98.273(a)(1), (b)(1) and (c)(1) to clarify
that owners and operators may use a higher tier. This flexibility in
selecting tiers is consistent with 40 CFR 98.34. The option to use a
higher tier to calculate fossil-fuel based emissions provides
flexibility to reporters and it only affects the reporting requirements
if an owner or operator chooses to use a higher tier. EPA also received
questions regarding the prescribed emission factors to calculate
fossil-fuel based CO2 emissions from lime kilns.
Specifically, 40 CFR 98.273(c)(1) directed owners and operators to use
emission factors in Table AA-2 to calculate CO2 emissions
from lime kilns, but EPA has received requests to use the emission
factors provided in Table C-1.
The emission factors in Table AA-2 were taken from ``Calculation
Tools for Estimating Greenhouse Gas Emissions from Pulp and Paper
Mills'', Version 1.1, July 8, 2005, which was prepared by the National
Council for Air and Stream Improvement (NCASI) for the National Council
of Forest and Paper Associations (ICFPA). Part 98 incorporated these
factors in Table AA-2 because they were developed specifically for pulp
and paper lime kilns, which operate at different conditions than other
general stationary combustion units.
Upon further consideration, we have determined that the emission
factors provided in Table AA-2 are uniquely suited for calculating
CH4 and N2O emissions from lime kilns given these
emissions are significantly influenced by the operating conditions.
However, EPA has found that the same rationale does not support having
unique emission factors to calculate CO2 emissions from lime
kilns. Therefore, EPA has removed the CO2 emission factors
from Table AA-2 and, in 40 CFR 98.273(c)(1), has directed owners and
operators to use the CO2 emission factors from Table C-1 of
subpart C to calculate CO2 emissions from lime kilns.
Modifications to Table AA-2 would affect the emissions reported in
2010, but would not affect the data that are collected to report
emissions in 2010.
Related to the calculation of CH4 and N2O
emissions described above, and consistent with the proposal to allow
use of higher Tiers than Tier 1 for units subject to subpart AA, EPA is
proposing to allow reporters to also use site-specific high heating
values, as opposed to default values, when claculating CH4
and N2O emissions.
EPA has also received questions from owners and operators about
whether pulp and paper mills are required to calculate emissions from
the combustion of their wastewater treatment sludge. Specifically, they
asked for clarification of whether this type of sludge was included in
Table C-1 and, if not, should they account for emissions from the
combustion of this material. In our efforts to address this question,
we have not been able to identify emission factors developed
specifically for sludge from a pulp and paper mill wastewater facility.
However, our research indicates that the content of this sludge falls
within the definition of ``Wood and Wood Residuals'' included in Table
C-1.
Therefore, per 40 CFR 98.33(b)(1)(iii), emissions from the
combustion of this type of sludge may be determined using Tier 1 in
subpart C. In order to further clarify this, we are proposing to add
the definition of ``Wood and Wood Residuals'' to 40 CFR 98.6 and to
include wastewater process sludge from paper mills in this definition.
Clarifying that emissions from the combustion of sludge from pulp and
paper mill wastewater treatment facilities may be calculated using Tier
1 would require that owners and operators estimate the volume of sludge
combusted using company records. Given the broad definition of company
records, owners and operators should be able to develop estimates to
report these emissions in 2011. Presuming these changes are finalized
as proposed, they would be incorporated into annual GHG reports due in
March 2011.
Finally, EPA received questions regarding which emission factors to
apply when a pulp and paper mill combusts solid petroleum coke given
this fuel type was not included in Table C-1 and Table AA-2. In
response, we are proposing to add this fuel type to both tables.
However, it is noted that emission factors for petroleum coke specific
to kraft calciners were not available. EPA does not believe that any
kraft calciners are combusting petroleum coke, so we have concluded
that it is not necessary to have emission factors for this fuel in
Table AA-2. EPA seeks comment on this conclusion. Further, if
information is provided that petroleum coke is combusted at kraft
calciners, please also include any information on default
CH4 and N2O emission factors.
P. Subpart NN (Suppliers of Natural Gas and Natural Gas Liquids)
Threshold for natural gas local distribution companies. The
applicability provision in subpart A at 40 CFR 98.2(a)(4)(iii)(B)
requires all natural gas local distribution companies (LDCs),
regardless of size, to report the GHG emissions that would result from
the complete combustion or oxidation of the annual volumes of natural
gas provided to end users on their distribution systems. Owners and
operators of LDCs potentially subject to subpart NN have asserted that
this provision results in an unfair burden on many small LDCs.
They have stated that requiring all LDCs to report did not
adequately balance rule coverage of GHGs reported, while excluding
small entities. For example, they highlighted data from the Energy
Information Administration that indicated that 82 percent of facilities
are estimated to deliver less than 460,000 mscf per year of natural
gas, which is equivalent to approximately 25,000 mtCO2e.
They further noted that EPA's own estimates suggest that these
facilities would be responsible for less than 1 percent of the reported
GHG emissions associated with LDC supply. The owners and operators
concluded that this is a disproportionate burden for LDCs, particularly
if one considers that across the rule, applying a 25,000
mtCO2e threshold would exclude approximately 10 to 15
percent of GHG emissions, a much larger percentage of emissions than
would be excluded under LDCs by applying that same 25,000
mtCO2e threshold.
The owners and operators noted that inclusion of all LDCs in the
rule would also impose numerous reporting and recordkeeping
requirements, even though most of these facilities would actually be
eligible to stop reporting in three or five years, after they could
prove to EPA that emissions from their supply were less than 15,000
mtCO2e or 25,000 mtCO2e per year, respectively.
We note that the threshold requirements for LDCs did not change
[[Page 48777]]
between the initial proposal in April 2009 and Part 98 promulgated on
October 30, 2009. Further, EPA did not receive any comments opposed to
the ``all in'' designation for LDCs during the public comment period on
the proposed Part 98 and, in fact, received two comments supporting the
lack of a threshold of any kind. Therefore, EPA retained in Part 98 the
provision to require all LDCs to report the CO2 emissions
associated with their supply. EPA retained the provision in order to
maximize coverage of the GHG emissions from natural gas supplies, and
also to be consistent with other suppliers of fossil fuels and
industrial gases covered by Part 98. An ``all in'' threshold was
applied to all of these supplier categories.
Although we believe that the public had ample opportunity to
comment on the threshold for LDCs, we have reevaluated this issue in
light of the information received. We are proposing to amend 40 CFR
98.2(a)(4)(iii)(B) in subpart A to require all LDCs that deliver
460,000 mscf or more of natural gas per year to report. We are
proposing this capacity-based threshold because a capacity-based
threshold would be more familiar to LDCs. Owners and operators of LDCs
know how much natural gas they deliver to their customers and it would,
therefore, be easier for facilities to determine if they are subject to
the rule than if the threshold were emissions-based. The proposed
annual threshold is approximately equivalent to 25,000
mtCO2e.
After further consideration, we have concluded that although a
threshold would result in a loss of emissions information to EPA, the
emissions coverage lost is less than 1 percent. It is also true that
most of these facilities 460,000 mscf would be able to stop reporting
to EPA in three or five years, raising the question of whether the
burden associated with instituting a reporting program that includes
the smaller facilities is necessary. We have determined that EPA and
other stakeholders would be able to use data from external sources
(e.g., the Energy Information Administration) to estimate the less than
1 percent of GHG emissions that would no longer be reported to EPA if a
460,000 mscf annual threshold were applied. This would minimize any
concerns that the loss of emissions coverage would inhibit the use of
the data for future policy making. Finally, we have concluded that LDCs
are unique among suppliers in that a large majority of facilities would
be under a 460,000 mscf threshold, and collectively these facilities
are responsible for a relatively low percentage of emissions from the
industry.
Q. Subpart OO (Suppliers of Industrial Greenhouse Gases)
We are proposing several changes to subpart OO to (1) respond to
concerns raised by producers of fluorinated GHGs regarding the scope of
the monitoring and reporting requirements, and (2) clarify the scope
and due dates for certain reporting and recordkeeping requirements.
Producers of fluorinated GHGs requested that EPA clarify that
subpart OO does not apply to fluorinated GHGs that (1) are either
emitted or destroyed at the facility before the fluorinated GHG product
is packaged for sale or for shipment to another facility for
destruction, (2) are produced and transformed at the same facility, or
(3) occur as low-concentration constituents (impurities) in fluorinated
GHG products. The producers also requested that EPA amend the rule to
account for the fact that some fluorinated GHGs do not have global
warming potential values (GWPs) listed in Table A-1 of subpart A. For
fluorinated GHGs without GWPs in Table A-1, facilities cannot calculate
CO2-equivalent production as required by subpart A, and
importers and exporters cannot take advantage of the reporting
exemptions for small shipments under 40 CFR 98.416(c) and (d), which
are expressed in CO2-equivalents.
Regarding fluorinated GHGs that are emitted or destroyed before the
product is packaged for sale, the producers specifically requested that
EPA amend subpart OO to remove the requirements of 40 CFR 98.414(j) and
98.416(a)(4) to monitor and report the destruction of fluorinated GHGs
that are not included in the calculation of the mass produced in 40 CFR
98.413(a) because they are removed from the production process as
byproducts or wastes.
They noted that measuring the flow of such fluorinated GHGs into
the destruction device to the precision required (1 percent) posed
significant technical challenges and that such measurement was outside
the scope of subpart OO. They further stated that subpart OO was
intended to address the quantities of fluorinated GHGs exiting
production units and entering commerce, where commerce includes the
packaging and marketing or import and export of fluorinated GHGs. They
stated that the proposed subpart L was the more appropriate vehicle for
the monitoring and reporting of emissions and destruction of
fluorinated GHGs still within the production process.
However, the producers noted that it was practical and appropriate
under subpart OO to measure the quantities of fluorinated GHGs that are
returned to the production facility for destruction after entering into
commerce (e.g., because they have become irretrievably contaminated).
Regarding fluorinated GHGs that are produced and transformed at the
same facility, the fluorinated GHG producers noted that these
fluorinated GHGs never enter the U.S. supply of fluorinated GHGs
because they never leave the facility where they are produced. Thus, it
is not necessary to track them under subpart OO.
Regarding fluorinated GHGs that occur as low-concentration
constituents of fluorinated GHG products, the producers observed that
such low-concentration constituents generally consist of by-products
that are packaged along with the main constituent of the product. They
noted that exempting the production, import, and export of these low-
concentration constituents from monitoring and reporting requirements
would be consistent with the exemption of ``trace'' concentrations from
other monitoring requirements in subpart OO, such as 40 CFR 98.414(f)
and (h).
In response to the concern regarding fluorinated GHGs that are
emitted or destroyed before the product is packaged for sale, we are
proposing (1) to modify the definition of ``produce a fluorinated GHG''
at 40 CFR 98.410(b) to explicitly exclude the ``creation of fluorinated
GHGs that are released or destroyed at the production facility before
the production measurement at Sec. 98.414(a);'' (2) to remove the
requirements at 40 CFR 98.414(j) and 98.416(a)(4) to monitor and report
the destruction of fluorinated GHGs ``that are not included in the
calculation of the mass produced in 40 CFR 98.413(a) because they are
removed from the production process as byproducts or wastes;'' and (3)
to modify the requirements at 40 CFR 98.414(h) and 98.416(a)(3) to
limit them to ``the mass of each fluorinated GHGs that is fed into the
destruction device and that was previously produced as defined at Sec.
98.410(b).''
These proposed amendments would clarify that the scope of subpart
OO is that which EPA has always intended, and they would modify the
destruction monitoring and reporting requirements to be fully
consistent with that scope. As noted in the preamble to the final Part
98 (74 FR 56259), and in the response to comments document, the intent
of subpart OO is to track the quantities of fluorinated GHGs entering
and leaving the U.S. supply of
[[Page 48778]]
fluorinated GHGs. Specifically, subpart OO is intended to address
production of fluorinated GHGs, not emissions or destruction of
fluorinated GHGs that occur during the production process. To clarify
this in the regulatory text, we are proposing to amend the definition
of ``produce a fluorinated GHG'' at 40 CFR 98.410(b) to exclude the
``creation of fluorinated GHGS that are released or destroyed at the
production facility before the production measurement at Sec.
98.414(a).''
As noted in the proposed Part 98 (74 FR 16580), the production
measurement at 40 CFR 98.414(a) could occur wherever it traditionally
occurs, e.g., at the inlet to the day tank or at the shipping dock, as
long as the subpart OO monitoring requirements were met (e.g., one-
percent precision and accuracy for the mass produced and for container
heels, if applicable). As noted above, emissions upstream of the
production measurement would be subject to proposed subpart L and are
not part of the subpart OO source category.
We are also proposing to amend 40 CFR 98.416(a)(3) to limit the
monitoring and reporting of destroyed fluorinated GHGs to those
destroyed fluorinated GHGs that were previously ``produced'' under
today's revised definition.\4\ Such fluorinated GHGs include but are
not limited to quantities that are shipped to the facility by another
facility for destruction, and quantities that are returned to the
facility for reclamation but are found to be irretrievably
contaminated. While monitoring of some destroyed streams appears to
pose significant technical challenges,\5\ monitoring of quantities of
fluorinated GHGs that were previously produced does not. These
quantities can be weighed and analyzed by the facility upon receipt or
upon the facility's conclusion that they cannot be brought back to the
specifications for new or reusable product.
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\4\ In Part 98, EPA required the monitoring of all streams being
destroyed because it was our understanding, based on conversations
with fluorinated GHG producers, that the mass flow of destroyed
fluorinated GHG streams was routinely monitored. To arrive at the
quantities being removed from the supply, EPA required facilities to
estimate the share of the total quantity of fluorinated GHGs
destroyed that consisted of fluorinated GHGs that were not included
in the calculation of the mass produced. This share could then be
subtracted from the total to arrive at the amounts destroyed that
were removed from the supply. In other words, monitoring and
reporting of the destruction of fluorinated GHGs that were not
included in the mass produced was required in order to estimate the
destruction of fluorinated GHGs that had been produced.
\5\ These include (1) low-pressure conditions that make it
challenging to achieve good accuracies and precisions and under
which the installation of a flowmeter may lead to low- or no-flow
conditions, interfering with operations upstream of the meter, (2)
corrosive conditions that require the use of Tefzel-lined flow
meters, which are currently available in a limited range of sizes
and precisions, and (3) variations in stream flow rates and
compositions that are associated with purging of vessels and columns
and that make it difficult to select a meter that will measure the
full range of flows to the required accuracy and precision.
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In response to the concern regarding fluorinated GHGs that are
produced and transformed at the same facility, we are proposing to (1)
amend the definition of ``produce a fluorinated GHG'' to exclude ``the
creation of intermediates that are created and transformed in a single
process with no storage of the intermediates;'' (2) amend the
definition of ``produce a fluorinated GHG'' to explicitly include ``the
manufacture of a fluorinated GHG as an isolated intermediate for use in
a process that will result in its transformation either at or outside
of the production facility;'' (3) add a definition of ``isolated
intermediate;'' and (4) add provisions to 40 CFR 98.414, 98.416, and
98.417 to clarify that isolated intermediates that are produced and
transformed at the same facility are exempt from subpart OO monitoring,
reporting, and recordkeeping requirements respectively.
As noted by the producers, fluorinated GHGs that are produced and
transformed at the same facility never enter the U.S. supply of
industrial greenhouse gases; thus, they do not need to be reported
under subpart OO. This is true both of isolated intermediates and of
intermediates that are created and transformed in a single process with
no storage of the intermediate. However, while we are proposing to
exclude the latter from the definition of ``produce a fluorinated
GHG,'' we are proposing to include the former in that definition. This
is because the manufacture of isolated intermediates, which can lead to
emissions of those intermediates, is of interest under subpart L, and
we would like to use the same definition of ``produce a fluorinated
GHG'' for subpart L as for subpart OO for consistency and clarity.
Thus, instead of excluding the manufacture of isolated intermediates
that are transformed at the same facility from the definition of
``produce a fluorinated GHG,'' we are proposing to add provisions to
exclude it from the subpart OO monitoring, reporting, and recordkeeping
requirements. We are also proposing to add a definition of ``isolated
intermediate'' that is the same as that proposed for subpart L (75 FR
18652, April 12, 2010).
In response to the concern regarding fluorinated GHGs that occur as
low-concentration constituents of fluorinated GHG products, we are
proposing to define and exclude low-concentration constituents from the
monitoring, reporting, and recordkeeping requirements for fluorinated
GHG production, exports, and imports. For purposes of production and
export, we are proposing to define low-concentration constituent as a
fluorinated GHG constituent of a fluorinated GHG product that occurs in
the product in concentrations below 0.1 percent by mass. This
concentration is the same as that used in the definition of ``trace
concentration'' used elsewhere in subpart OO. It is also consistent
with industry purity standards for HFC refrigerants (AHRI 700), for
SF6 used as an insulator in electrical equipment (IEC
60376), and for perfluorocarbons and other fluorinated GHGs used in
electronics manufacturing (SEMI C3 series). To meet these standards,
which set limits that range from less than 0.1 percent to 0.5 percent
for all fluorinated GHG impurities combined, fluorinated GHG producers
are likely to have identified and quantified the concentrations of
impurities at concentrations at or above 0.1 percent for the products
subject to the standards. Finally, below concentrations of 0.1 percent,
fluorinated GHG impurities are not likely to have a significant impact
on the GWP of the product. For example, if a low-concentration
constituent occurs in concentrations of just under 0.1 percent and has
a GWP that is ten times as large as the GWP of the main constituent of
the product, it will increase the weighted GWP of the product by just
under one percent.
To ensure that fluorinated GHG production facilities rely on data
of known and acceptable quality when determining whether or not to
report a minor fluorinated GHG constituent of a product, we are also
proposing product sampling and analytical requirements at 40 CFR
98.414(n) and corresponding calibration requirements at 40 CFR
98.414(o).
For purposes of fluorinated GHG import, we are proposing to define
low-concentration constituent as a fluorinated GHG constituent of a
fluorinated GHG product that occurs in the product in concentrations
below 0.5 percent by mass. We are proposing a higher concentration for
fluorinated GHG imports than for fluorinated GHG production and exports
because importers are less likely than producers to have detailed
information on the identities and concentrations of minor fluorinated
GHG constituents in their products.
[[Page 48779]]
In response to the concerns regarding fluorinated GHGs that do not
have GWPs listed in Table A-1, we are proposing (1) to exempt such
compounds from the general subpart A requirement to report supply flows
in terms of CO2 equivalents and (2) to recast the reporting
exemptions for import and export of small shipments in terms of
kilograms of fluorinated GHGs or N2O rather than tons of
CO2-equivalents. The amendment to subpart A is discussed in
more detail in section II.G of this preamble. The exemptions for import
and export would be applied to shipments of less than 25 kilograms of
fluorinated GHGs or N2O rather than to shipments of less
than 250 metric tons of CO2e. This would enable small
shipments of fluorinated GHGs to be exempt from reporting regardless of
whether or not the fluorinated GHG had a GWP listed in Table A-1. Our
analysis of import and export data indicates that this change would
slightly increase both the number and total mass of the imports and
exports reported under the rule, but this analysis does not account for
fluorinated GHGs whose GWPs are not listed in Table A-1. If those
fluorinated GHGs were accounted for, we believe that the level of
reporting would increase even less and might even decrease slightly.
Other Corrections. We are also proposing to amend the reporting and
recordkeeping provisions in subpart OO to correct internal
inconsistencies in the subpart and to clarify those requirements.
We are proposing to amend the reporting requirements in 40 CFR
98.416(a)(15) and (c)(10) to remove N2O from the list of
GHGs that must be reported when they are transferred off site for
destruction, because N2O transferred off site for
destruction is not required to be monitored.
We are proposing to amend 40 CFR 98.416(b) and (e) to clarify the
due dates of the one-time reports required by those paragraphs. The
proposed due date for the one-time reports is March 31, 2011, or within
60 days of commencing fluorinated GHG destruction or production (as
applicable). The due date in 40 CFR 98.416(e) in subpart OO was April
1, 2011, and there was no provision for commencing fluorinated GHG
destruction or production after that date. The proposed amendments will
make the due dates in 40 CFR 98.416(b) and (e) consistent with each
other, with the due date for a similar report required in subpart O,
and with the due date for other reporting under the rule.
We are proposing to amend the recordkeeping requirements in 40 CFR
98.417(a)(2) to correct and update an internal reference. The correct
reference is to ``Sec. 98.414(m) and (o),'' instead of ``Sec.
98.417(j) and (k).'' We are proposing to amend 40 CFR 98.417(b) to
remove the reference to the ``annual destruction device outlet
reports'' in 40 CFR 98.416(e) since no such reporting requirement
exists.
Finally, we are proposing to amend 40 CFR 98.417(d)(2) to correct a
typographical error; that paragraph should refer to ``the invoice for
the export,'' rather than for the ``import.''
R. Subpart PP (Suppliers of Carbon Dioxide)
In subpart PP, we are proposing to remove the words ``each'' from
the list of GHGs to report in 40 CFR 98.422. This change would align
this section with the requirements of the rest of subpart PP, which
allow for monitoring of an aggregated flow of CO2 if it is
done at a gathering point downstream of individual production wells or
production process units.
We are proposing to allow those suppliers that supply
CO2 in containers to calculate the annual mass of
CO2 supplied in containers by using weigh bills, scales,
load cells, or loaded container volume readings as an alternative to
flow meters. As a result of many questions received during outreach in
support of alternative procedures for CO2 supplied in
containers, we have reevaluated the calculation procedures for
CO2 suppliers. We have concluded that measurements made with
weigh bills, scales, load cells, or loaded container volume readings
will continue to meet the level of data quality and accuracy needed by
EPA with respect to subpart PP. We have reached this conclusion with
consideration to minimizing the burden on and maximizing the
flexibility provided to industry.
We are proposing multiple amendments to the regulatory text to
accommodate this proposed provision. First, we are proposing that 40
CFR 98.423(b) be renumbered to 40 CFR 98.423(c) and that a new 40 CFR
98.423(b) be added with calculation procedures for CO2
supplied in containers. Second, we are proposing to amend the first
sentence of 40 CFR 98.423(a) to allow suppliers that supply
CO2 in containers to use the alternative procedures in 40
CFR 98.423(b). Third, we are proposing to add new QA/QC procedures for
suppliers that supply CO2 in containers to 40 CFR 98.424(a).
Fourth, we are proposing to add missing data procedures for suppliers
that supply CO2 in containers to 40 CFR 98.425(d). Finally,
we are proposing to make multiple amendments to regulatory text in 40
CFR 98.426 so that all data collected with weigh bills, scales, load
cells, or loaded container volume readings must be reported just as for
all data collected with flow meters.
We note that under the existing requirements, importers and
exporters that import and export CO2 in containers must
measure the mass of CO2 in containers using weigh bills,
scales, or load cells. In this action, we are not proposing that the
use of loaded container volume readings be allowed for such reporters
as an alternative to weigh bills, scales, or load cells because we have
received no questions from importers or exporters suggesting the need
for such an allowance. We seek comment on whether such an allowance
should be extended to importers and exporters of CO2 in
containers, and if so whether the calculation procedures, QA/QC
procedures, missing data procedures, and reporting requirements for
loaded container volume readings proposed in this action for suppliers
should be offered to importers and exporters.
We are proposing to remove the requirement that CO2
measurement must be made prior to subsequent purification, processing,
or compression at 40 CFR 98.423(a)(1), (a)(2), and (b) (which we are
proposing to redesignate as 40 CFR 98.423(c)). This provision created
confusion and conflict over where to place a flow meter. For example,
at least one reporter has indicated that only a portion of a
CO2 stream is transferred for commercial application while
the rest is retained for onsite use and emission, and this portion of
the stream is segregated only after processing. As a result of this and
other concerns that the requirement to install flow meters prior to
purification, processing, or compression could result in a requirement
to install the flow meter at a technically infeasible point, we
reevaluated the value of such a constraint on the CO2
calculations. Since the purpose of subpart PP is to collect accurate
data on CO2 supplied to the economy, we have concluded that
measurements made after purification, compression, or processing will
continue to meet the level of data quality and accuracy needed with
respect to subpart PP, while minimizing the burden on industry and
providing greater flexibility in measuring CO2 streams.
To ensure that all reporters account for the appropriate quantity
of CO2 in situations where a CO2 stream is
segregated such that only a portion is captured for commercial
application or
[[Page 48780]]
for injection and where a flow meter is used, we are proposing to add
language at 40 CFR 98.424(a) requiring the flow meter to be located
after the point of segregation. We are also proposing to amend existing
language in 40 CFR 98.424(a) to reference this new requirement.
Because the proposed amendments would allow flow meters to be
located after purification, compression, or processing, we are
proposing to add data reporting requirements in 40 CFR 98.426 to
collect additional information on flow meter location. Specifically, we
are proposing that facilities would report information on the placement
of each flow meter used in relation to the points of CO2
stream capture, deyhdration, compression, and other processing. Knowing
where in the production process the flow meter is located will enable
EPA to effectively compare data across and to learn about the efficacy
of various CO2 stream capture processes.
The current subpart PP regulatory text requires that a reporter
using a volumetric flow meter to measure the flow of a CO2
stream measure density of that CO2 stream in order to
calculate the mass of CO2 supplied. As a result of new
analysis, we have concluded that the mass of CO2 in a stream
can be adequately determined by converting the volumetric flow of
CO2 from operating conditions to standard conditions and
then applying the density value for CO2 at standard
conditions and the measured concentration of CO2 in the
flow. This approach may also be less burdensome for reporters than
directly measuring density with equipment. Therefore, we are proposing
to amend 40 CFR 98.424(a)(5) by replacing the word ``measure'' with the
word ``determine.''
We are also proposing to add a new paragraph 40 CFR 98.424(c) so
that suppliers will be able to calculate the mass of CO2 in
a stream from the measured volumetric flow (converted to standard
conditions) and CO2 concentration, and the given density of
CO2 at standard conditions.
For the calculation in the proposed paragraph 40 CFR 98.424(c),
standard conditions under subpart PP would be a temperature and an
absolute pressure of 60[deg]F and 1 atmosphere. Note that this would be
different than the standard conditions defined in subpart A (40 CFR
98.6), which are 68[deg]F and 14.7 psia. It is our understanding that
60[deg]F and 1 atmosphere (which is equivalent to 14.7 psia) are more
commonly used by the industries covered by subpart PP, and we seek
comment on this conclusion. Given these conditions, we are proposing
that reporters must use 0.0018704 metric tons per standard cubic meter
as a density value for CO2 at standard conditions if this is
the industry standard practice used to determine density.
The current subpart PP regulatory text also requires that an
appropriate method published by a consensus-based standards
organization be used to measure density if such a method exists. Where
no such method exists, an industry standard practice must be followed.
We have been unable to identify any method published by a consensus-
based standards organization that accounts for the approach for
determining density described above and have concluded that it would be
categorized as an industry standard practice. Therefore, we are
proposing to amend language in 40 CFR 98.424(a)(5) and (a)(5)(ii) to
allow reporters to choose equally from between a method published by a
consensus-based standards organization that is appropriate or an
industry standard practice to determine density.
We are proposing to amend the reference to the U.S. Food and Drug
Administration food-grade specifications for CO2 in 40 CFR
98.424(b)(2) to correct a typographical error. The correct reference is
21 CFR 184.1240, not 21 CFR 184.1250.
III. Statutory and Executive Order Reviews
A. Executive Order 12866: Regulatory Planning and Review
This action is not a ``significant regulatory action'' under the
terms of Executive Order (EO) 12866 (58 FR 51735, October 4, 1993) and
is therefore not subject to review under the EO.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
These proposed amendments do not make any substantive changes to the
reporting requirements in any of the subparts for which amendments are
being proposed. In many cases, the proposed amendments to the reporting
requirements could potentially reduce the reporting burden by making
the reporting requirements conform more closely to current industry
practices. The Office of Management and Budget (OMB) has previously
approved the information collection requirements contained in the
regulations promulgated on October 30, 2009, under 40 CFR Part 98 under
the provisions of the Paperwork Reduction Act, 44 U.S.C. 3501 et seq.
and has assigned OMB control number 2060-0629. The OMB control numbers
for EPA's regulations in 40 CFR are listed in 40 CFR part 9. Further
information on EPA's assessment on the impact on burden can be found in
the Revisions Cost Memo (EPA-HQ-OAR-2008-0508).
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 this proposed 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 these proposed rule
amendments on small entities, I certify that this action will not have
a significant economic impact on a substantial number of small
entities. The proposed rule amendments will not impose any new
requirement on small entities that are not currently required by the
rules promulgated on October 30, 2009 (i.e., calculating and reporting
annual GHG emissions).
EPA took several steps to reduce the impact of Part 98 on small
entities. For example, EPA determined appropriate thresholds that
reduced the number of small businesses reporting. In addition, EPA did
not require facilities to install CEMS if they did 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 required annual instead of more frequent reporting. Finally,
EPA continues to conduct significant outreach on the mandatory GHG
reporting rule and maintains an ``open door'' policy for stakeholders
to help inform EPA's understanding of key issues for the industries.
[[Page 48781]]
We continue to be interested in the potential impacts of the
proposed rule amendments on small entities and welcome comments on
issues related to such impacts.
D. Unfunded Mandates Reform Act (UMRA)
This proposed rule does not contain a Federal mandate that may
result in expenditures of $100 million or more for State, local, and
tribal governments, in the aggregate, or the private sector in any one
year. EPA has estimated that, overall, the proposed revisions do not
significantly change the overall costs of compliance with Part 98. The
proposed amendments include providing additional flexibility for
reporters, clarifying existing reporting requirements, and requiring
reporting of information already required to be collected under Part
98. EPA estimates that the cost for all reporters in reviewing the
proposed rule and determining if, and if so how, it applies to their
facility, is approximately $2.5 million in the first year. Considering
the additional flexibilities proposed, in sum, EPA has estimated that
the proposed rule, if finalized, would reduce the burden to reporters
as compared to the 2009 final rule. Thus, this rule is not subject to
the requirements of sections 202 or 205 of UMRA. For more information
on the cost analysis, please refer to the memorandum titled ``Mandatory
Greenhouse Gas Reporting: Changes in National Cost Estimates Associated
with the Proposed Notice of Revisions'' found in the docket at (EPA-HQ-
OAR-2008-0508).
This proposed rule is also 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
determined that the proposed rule amendments contain no regulatory
requirements that might significantly or uniquely affect small
governments because the amendments will not impose any new requirements
that are not currently required by the rules published on October 30,
2009 (i.e., calculating and reporting annual GHG emissions). EPA
concluded in the preamble to that final rule that the rule ``* * *
contains no regulatory requrements that might significantly or uniquely
affect small governments'' (40 CFR 56260). Because the final rule was
not determined to significantly or uniquely affect small governments,
and because this proposed rule generally reduces the burden associated
with the 2009 final rule, these rule amendments would not unfairly
apply to small governments.
E. Executive Order 13132: Federalism
This action 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 Executive Order 13132. However, for a more detailed
discussion about how these proposed rule amendments would relate to
existing State programs, please see Section II of the proposal preamble
for Part 98 (74 FR 16457 to 16461, April 10, 2009).
These amendments apply directly to facilities that supply fuel or
chemicals that when used emit greenhouse gases or facilities that
directly emit greenhouses gases. They do 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 action.
Although section 6 of Executive Order 13132 does not apply to this
action, EPA did consult with State and local officials or
representatives of State and local governments in developing Part 98. A
summary of EPA's consultations with State and local governments is
provided in Section VIII.E of the preamble to the final Part 98 (74 FR
56260, October 30, 2009).
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 comment on this proposed action
from State and local officials.
F. Executive Order 13175: Consultation and Coordination With Indian
Tribal Governments
This action does not have tribal implications, as specified in
Executive Order 13175 (65 FR 67249, November 9, 2000). The proposed
rule amendments would not result in any changes to the requirements of
the 2009 rule. Thus, Executive Order 13175 does not apply to this
action.
Although Executive Order 13175 does not apply to this action, EPA
sought opportunities to provide information to Tribal governments and
representatives during the development of the rules promulgated on
October 30, 2009. A summary of the EPA's consultations with Tribal
officials is provided Sections VIII.E and VIII.F of the preamble to the
final Part 98 (74 FR 56260, October 30, 2009).
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 action is not subject to Executive Order 13211 (66 FR 28355
(May 22, 2001)), because it is not a significant regulatory action
under Executive Order 12866.
I. National Technology Transfer and Advancement Act
Section 12(d) of the National Technology Transfer and Advancement
Act of 1995 (NTTAA), Public Law No. 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. No new test
methods were developed for this proposed rule; rather, EPA identified
existing means of monitoring, reporting, and keeping records of
greenhouse gas emissions. EPA proposes to use two additional voluntary
consensus standards from ASTM International. Part 98 includes the use
of over 40 voluntary consensus standards from various consensus
standards bodies, for example, ASTM International, the American Society
of Chemical Engineers, Gas Processors Association, the American Gas
Association, and the American Petroleum Institute. The proposed
addition of these two
[[Page 48782]]
voluntary consensus standards from ASTM International to Part 98 will
help petroleum refineries and petrochemical facilities monitor, report,
and keep records of greenhouse gas emissions. The test methods are
incorporated by reference into the proposed rule and are available as
specified in proposed amendments to 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
Executive Order (EO) 12898 (59 FR 7629 (Feb. 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 United States.
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 because it is a rule addressing information collection and
reporting procedures.
List of Subjects in 40 CFR Part 98
Environmental protection, Administrative practice and procedure,
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and
recordkeeping requirements.
Dated: July 20, 2010.
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 98--[AMENDED]
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401, et seq.
Subpart A--[Amended]
2. Section 98.2 is amended by revising paragraph (a)(4)(iii)(B) to
read as follows:
Sec. 98.2 Who must report?
(a) * * *
(4) * * *
(iii) * * *
(B) Local natural gas distribution companies that deliver 460,000
thousand standard cubic feet or more of natural gas per year.
* * * * *
3. Section 98.3 is amended by:
a. Revising paragraphs (c)(1), (c)(4)(i), (c)(4)(ii), (c)(4)(iii)
introductory text, (c)(4)(iii)(A), (c)(4)(iii)(B), and (c)(5)(i).
b. Revising the third sentence of paragraph (d)(3) introductory
text.
c. Revising the first sentence of paragraph (f).
d. Revising paragraphs (g)(4), (g)(5)(iii).
e. Revising paragraph (h).
f. Revising paragraph (i).
g. Adding paragraph (j).
Sec. 98.3 What are the general monitoring, reporting, recordkeeping
and verification requirements of this part?
* * * * *
(c) * * *
(1) Facility name or supplier name (as appropriate), facility or
supplier ID number, and physical street address of the facility or
supplier, including the city, state, and zip code.
* * * * *
(4) * * *
(i) Annual emissions (including biogenic CO2) aggregated
for all GHG 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) Annual emissions of biogenic CO2 aggregated for all
applicable source categories in subparts C through JJ of this part in
metric tons. Units that use the methodologies in part 75 of this
chapter to calculate CO2 mass emissions are not required to
separately report biogenic CO2 emissions, but may do so as
an option.
(iii) Annual emissions from each applicable source category in
subparts C through JJ of this part, expressed in metric tons of each
applicable GHG listed in this paragraph (4)(iii)(A) through
(4)(iii)(E).
(A) Biogenic CO2. Units that use the methodologies in
part 75 of this chapter to calculate CO2 mass emissions are
not required to separately report biogenic CO2 emissions,
but may do so as an option.
(B) CO2 (including biogenic CO2).
* * * * *
(5) * * *
(i) Total quantity of GHG aggregated for all GHG 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. For fluorinated GHGs, calculate and report
CO2e for only those fluorinated GHGs listed in Table A-1 of
this subpart.
* * * * *
(d) * * *
(3) * * * An owner or operator that submits an abbreviated report
must submit a full GHG report according to the requirements of
paragraph (c) of this section beginning in calendar year 2012. * * *
* * * * *
(f) Verification. To verify the completeness and accuracy of
reported GHG emissions, the Administrator may review the certification
statements described in paragraphs (c)(9) and (d)(3)(vi) of this
section and any other credible evidence, in conjunction with a
comprehensive review of the GHG reports and periodic audits of selected
reporting facilities. * * *
(g) * * *
(4) Missing data computations. For each missing data event, also
retain a record of the cause of the event and the corrective actions
taken to restore malfunctioning monitoring equipment.
(5) * * *
(iii) The owner or operator shall revise the GHG Monitoring Plan as
needed to reflect changes in production processes, monitoring
instrumentation, and quality assurance procedures; or to improve
procedures for the maintenance and repair of monitoring systems to
reduce the frequency of monitoring equipment downtime.
* * * * *
(h) Annual GHG report revisions.
(1) The owner or operator shall submit a revised annual GHG report
within 45 days of discovering that an annual GHG report that the owner
or operator previously submitted contains one or more substantive
errors. The revised report must correct all substantive errors.
(2) The Administrator may notify the owner or operator in writing
that an annual GHG report previously submitted by the owner or operator
contains one or more substantive errors.
[[Page 48783]]
Such notification will identify each such substantive error. The owner
or operator shall, within 45 days of receipt of the notification,
either resubmit the report that, for each identified substantive error,
corrects the identified substantive error (in accordance with the
applicable requirements of this part) or provide information
demonstrating that the previously submitted report does not contain the
identified substantive error or that the identified error is not a
substantive error.
(3) A substantive error is an error that impacts the quantity of
GHG emissions reported or otherwise prevents the reported data from
being validated or verified.
(4) Notwithstanding paragraphs (h)(1) and (h)(2) of this section,
upon request by the owner or operator, the Administrator may provide
reasonable extensions of the 45-day period for submission of the
revised report or information under paragraphs (h)(1) and (h)(2) of
this section. If the Administrator receives a request for extension of
the 45-day period, by e-mail to an address prescribed by the
Administrator, at least two business days prior to the expiration of
the 45-day period, and the Administrator does not respond to the
request by the end of such period, the extension request is deemed to
be automatically granted for 30 more days. During the automatic 30-day
extension, the Administrator will determine what extension, if any,
beyond the automatic extension is reasonable and will provide any such
additional extension.
(5) The owner or operator shall retain documentation for 3 years to
support any revision made to an annual GHG report.
(i) Calibration and accuracy requirements. The owner or operator of
a facility or supplier that is subject to the requirements of this part
must meet the applicable flow meter calibration and accuracy
requirements of this paragraph (i). The accuracy specifications in this
paragraph (i) do not apply where either the use of company records (as
defined in Sec. 98.6) or the use of ``best available information'' is
specified in an applicable subpart of this part to quantify fuel usage
and/or other parameters. Further, the provisions of this paragraph (i)
do not apply to stationary fuel combustion units that use the
methodologies in part 75 of this chapter to calculate CO2
mass emissions.
(1) Except as otherwise provided in paragraphs (i)(4) through
(i)(6) of this section, flow meters that measure liquid and gaseous
fuel feed rates, process stream flow rates, or feedstock flow rates and
provide data for the GHG emissions calculations, shall be calibrated
prior to April 1, 2010 using the procedures specified in this paragraph
(i) when such calibration is specified in a relevant subpart of this
part. Each of these flow meters shall meet the applicable accuracy
specification in paragraph (i)(2) or (i)(3) of this section. All other
measurement devices (e.g., weighing devices) that are required by a
relevant subpart of this part, and that are used to provide data for
the GHG emissions calculations, shall also be calibrated prior to April
1, 2010; however, the accuracy specifications in paragraphs (i)(2) and
(i)(3) of this section do not apply to these devices. Rather, each of
these measurement devices shall be calibrated to meet the accuracy
requirement specified for the device in the applicable subpart of this
part, or, in the absence of such accuracy requirement, the device must
be calibrated to an accuracy within the appropriate error range for the
specific measurement technology, based on an applicable operating
standard, including but not limited to industry standards and
manufacturer's specifications. The procedures and methods used to
quality-assure the data from each measurement device shall be
documented in the written Monitoring Plan, pursuant to paragraph
(g)(5)(i)(C) of this section.
(i) All flow meters and other measurement devices that are subject
to the provisions of this paragraph (i) must be calibrated according to
one of the following. You may use the manufacturer's recommended
procedures; an appropriate industry consensus standard method; or a
method specified in a relevant subpart of this part. The calibration
method(s) used shall be documented in the Monitoring Plan required
under paragraph (g) of this section.
(ii) For facilities and suppliers that become subject to this part
after April 1, 2010, all flow meters and other measurement devices (if
any) that are required by the relevant subpart(s) of this part to
provide data for the GHG emissions calculations shall be installed no
later than the date on which data collection is required to begin using
the measurement device, and the initial calibration(s) required by this
paragraph (i) (if any) shall be performed no later than that date.
(iii) Except as otherwise provided in paragraphs (i)(4) through
(i)(6) of this section, subsequent recalibrations of the flow meters
and other measurement devices subject to the requirements of this
paragraph (i) shall be performed at one of the following frequencies:
(A) You may use the frequency specified in each applicable subpart
of this part.
(B) You may use the frequency recommended by the manufacturer or by
an industry consensus standard practice, if no recalibration frequency
is specified in an applicable subpart.
(2) Perform all flow meter calibration at measurement points that
are representative of the normal operating range of the meter. Except
for the orifice, nozzle, and venturi flow meters described in paragraph
(i)(3) of this section, calculate the calibration error at each
measurement point using Equation A-2 of this section. The terms ``R''
and ``A'' in Equation A-2 must be expressed in consistent units of
measure (e.g., gallons/minute, ft\3\/min). The calibration error at
each measurement point shall not exceed 5.0 percent of the reference
value.
[GRAPHIC] [TIFF OMITTED] TP11AU10.000
Where:
CE = Calibration error (%)
R = Reference value
A = Flow meter response to the reference value
(3) For orifice, nozzle, and venturi flow meters, the initial
quality assurance consists of in-situ calibration of the differential
pressure (delta-P), total pressure, and temperature transmitters.
(i) Calibrate each transmitter at a zero point and at least one
upscale point. Fixed reference points, such as the freezing point of
water, may be used for temperature transmitter calibrations. Calculate
the calibration error of each transmitter at each measurement point,
using Equation A-3 of this subpart. The terms ``R'', ``A'', and ``FS''
in Equation A-3 of this subpart must be in consistent units of measure
(e.g., milliamperes, inches of water, psi, degrees). For each
transmitter, the CE value at each measurement point shall not exceed
2.0 percent of full-scale. Alternatively, the results are acceptable if
the sum of the calculated CE values for the three transmitters at each
calibration level (i.e., at the zero level and at each upscale level)
does not exceed: 6.0 percent.
[[Page 48784]]
[GRAPHIC] [TIFF OMITTED] TP11AU10.001
Where:
CE = Calibration error (%)
R = Reference value
A = Transmitter response to the reference value
FS = Full-scale value of the transmitter
(ii) In cases where there are only two transmitters (i.e.,
differential pressure and either temperature or total pressure) in the
immediate vicinity of the flow meter's primary element (e.g., the
orifice plate), or when there is only a differential pressure
transmitter in close proximity to the primary element, calibration of
these existing transmitters to a CE of 2.0 percent or less at each
measurement point is still required, in accordance with paragraph
(i)(3)(i) of this section; alternatively, when two transmitters are
calibrated, the results are acceptable if the sum of the CE values for
the two transmitters at each calibration level does not exceed 4.0
percent. However, note that installation and calibration of an
additional transmitter (or transmitters) at the flow monitor location
to measure temperature or total pressure or both is not required in
these cases. Instead, you may use assumed values for temperature and/or
total pressure, based on measurements of these parameters at a remote
location (or locations), provided that the following conditions are
met:
(A) You must demonstrate that measurements at the remote
location(s) can, when appropriate correction factors are applied,
reliably and accurately represent the actual temperature or total
pressure at the flow meter under all expected ambient conditions.
(B) You must make all temperature and/or total pressure
measurements in the demonstration described in paragraph (i)(3)(ii)(A)
of this section with calibrated gauges, sensors, transmitters, or other
appropriate measurement devices. At a minimum, calibrate each of these
devices to an accuracy within the appropriate error range for the
specific measurement technology, according to one of the following. You
may calibrate using an industry consensus standards or a manufacturer's
specification.
(C) You must document the methods used for the demonstration
described in paragraph (i)(3)(ii)(A) of this section in the written
Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must
also include the data from the demonstration, the mathematical
correlation(s) between the remote readings and actual flow meter
conditions derived from the data, and any supporting engineering
calculations in the Monitoring Plan. You must maintain all of this
information in a format suitable for auditing and inspection.
(D) You must use the mathematical correlation(s) derived from the
demonstration described in paragraph (i)(3)(ii)(A) of this section to
convert the remote temperature or the total pressure readings, or both,
to the actual temperature or total pressure at the flow meter, or both,
on a daily basis. You shall then use the actual temperature and total
pressure values to correct the measured flow rates to standard
conditions.
(E) You shall periodically check the correlation(s) between the
remote and actual readings (at least once a year), and make any
necessary adjustments to the mathematical relationship(s).
(4) Fuel billing meters are exempted from the calibration
requirements of this section and from the Monitoring Plan and
recordkeeping provisions of paragraphs (g)(5)(i)(C) and (g)(7) of this
section, provided that the fuel supplier and any unit combusting the
fuel do not have any common owners and are not owned by subsidiaries or
affiliates of the same company. Meters used exclusively to measure the
flow rates of fuels that are used for unit startup or ignition are also
exempted from the calibration requirements of this section.
(5) For a flow meter that has been previously calibrated in
accordance with paragraph (i)(1) of this section, an additional
calibration is not required by the date specified in paragraph (i)(1)
of this section if, as of that date, the previous calibration is still
active (i.e., the device is not yet due for recalibration because the
time interval between successive calibrations has not elapsed). In this
case, the deadline for the successive calibrations of the flow meter
shall be set according to one of the following. You may use either the
manufacturer's recommended calibration schedule or you may use the
industry consensus calibration schedule.
(6) For units and processes that operate continuously with
infrequent outages, it may not be possible to meet the April 1, 2010
deadline for the initial calibration of a flow meter or other
measurement device without disrupting normal process operation. In such
cases, the owner or operator may postpone the initial calibration until
the next scheduled maintenance outage. The best available information
from company records may be used in the interim. The subsequent
required recalibrations of the flow meters may be similarly postponed.
Such postponements shall be documented in the monitoring plan that is
required under paragraph(g)(5) of this section.
(7) If the results of an initial calibration or a recalibration
fail to meet the required accuracy specification, data from the flow
meter shall be considered invalid, beginning with the hour of the
failed calibration and continuing until a successful calibration is
completed. You shall follow the missing data provisions provided in the
relavant missing data sections during the period of data invalidation.
(j) Measurement Device Installation.
(1) General. If an owner or operator required to report under
subpart P, subpart X or subpart Y of this part has process equipment or
units that operate continuously and it is not possible to install a
required flow meter or other measurement device by April 1, 2010, (or
by any later date in 2010 approved by the Administrator as part of an
extension of best available monitoring methods per paragraph (d) of
this section) without process equipment or unit shutdown, or through a
hot tap, the owner or operator may request an extension from the
Administrator to delay installing the measurement device until the next
scheduled process equipment or unit shutdown. If approval for such an
extension is granted by the Administrator, the owner or operator must
use best available monitoring methods during the extension period.
(2) Requests for extension of the use of best available monitoring
methods for measurement device installation. The owner or operator must
first provide the Administrator an initial notification of the intent
to submit an extension request for use of best available monitoring
methods beyond December 31, 2010 (or an earlier date approved by EPA)
in cases where measurement device installation would require a process
equipment or unit shutdown, or could only be done through a hot tap.
The owner or operator must follow-up this initial notification with the
complete extension request containing the information specified in
paragraph (j)(4) of this section.
(3) Timing of request.
[[Page 48785]]
(i) The initial notice of intent must be submitted no later than
January 1, 2011, or by the end of the approved use of best available
monitoring methods extension in 2010, whichever is earlier. The
completed extension request must be submitted to the Administrator no
later than February 15, 2011.
(ii) Any subsquent extensions to the original request must be
submitted to the Administrator within 4 weeks of the owner or operator
identifying the need to extend the request, but in any event no later
than 4 weeks before the date for the planned process equipment or unit
shutdown that was provided in the original request.
(4) Content of the request. Requests must contain the following
information:
(i) Specific measurement device for which the request is being made
and the location where each measurement device will be installed.
(ii) Identification of the specific rule requirements (by rule
subpart, section, and paragraph numbers) requiring the measurement
device.
(iii) A description of the reasons why the needed equipment could
not be installed before April 1, 2010, or by the expiration date for
the use of best available monitoring methods, in cases where an
extension has been granted under Sec. 98.3(d).
(iv) Supporting documentation showing that it is not practicable to
isolate the process equipment or unit and install the measurement
device without a full shutdown or a hot tap, and that there was no
opportunity during 2010 to install the device. Include the date of the
three most recent shutdowns for each relevant process equipment or
unit, the frequency of shutdowns for each relevant process equipment or
unit, and the date of the next planned process equipment or unit
shutdown.
(v) Include a description of the proposed best available monitoring
method for estimating GHG emissions during the time prior to
installation of the meter.
(5) Approval criteria. The owner or operator must demonstrate to
the Administrator's satisfaction that it is not reasonably feasible to
install the measurement device before April 1, 2010 (or by the
expiration date for the use of best available monitoring methods, in
cases where an extension has been granted under paragraph(d) of this
section) without a process equipment or unit shutdown, or through a hot
tap, and that the proposed method for estimating GHG emissions during
the time before which the measurement device will be installed is
appropriate. The Administrator will not initially approve the use of
the proposed best available monitoring method past December 31, 2013.
(6) Measurement device installation deadline. Any owner or operator
that submits both a timely initial notice of intent and a timely
completed extension request under paragraph (j)(3) of this section to
extend use of best available monitoring methods for measurement device
installation must install all such devices by July 1, 2011 unless the
extension request under this paragraph (j) is approved by the
Administrator before July 1, 2011.
(7) One time extension past December 31, 2013. If an owner or
operator determines that a scheduled process equipment or unit shutdown
will not occur by December 31, 2013, the owner or operator may re-apply
to use best available monitoring methods for one additional time
period, not to extend beyond December 31, 2015. To extend use of best
available monitoring methods past December 31, 2013, the owner or
operator must submit a new extension request by June 1, 2013 that
contains the information required in paragraph (j)(4) of this section.
The owner or operator must demonstrate to the Administrator's
satisfaction that it continues to not be reasonably feasible to install
the measurement device before December 31, 2013 without a process
equipment or unit shutdown, or that installation of the measurement
device could only be done through a hot tap, and that the proposed
method for estimating GHG emissions during the time before which the
measurement device will be installed is appropriate. An owner or
operator that submits a request under this paragraph to extend use of
best available monitoring methods for measurement device installation
must install all such devices by December 31, 2013, unless the
extension request under this paragraph is approved by the
Administrator.
4. Section 98.4 is amended by revising paragraphs (i)(2) and
(m)(2)(i) to read as follows:
Sec. 98.4 Authorization and responsibilities of the designated
representative.
* * * * *
(i) * * *
(2) The name, organization name (company affiliation-employer),
address, e-mail address (if any), telephone number, and facsimile
transmission number (if any) of the designated representative and any
alternate designated representative.
* * * * *
(m) * * *
(2) * * *
(i) The name, organization name (company affiliation-employer)
address, e-mail address (if any), telephone number, and facsimile
transmission number (if any) of such designated representative or
alternate designated representative.
* * * * *
5. Section 98.6 is amended by:
a. Adding in alphabetical order definitions for ``Agricultural
byproducts,'' ``Primary fuel,'' ``Solid byproducts,'' ``Waste oil,''
and ``Wood residuals.''
b. Revising the definitions for ``Bulk natural gas liquid or NGL,''
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Municipal solid waste or
MSW,'' ``Natural gas,'' and ``Natural gas liquids (NGLs).''
c. Removing the definition for ``Fossil fuel-fired.''
Sec. 98.6 Definitions.
* * * * *
Agricultural byproducts means those parts of arable crops that are
not used for the primary purpose of producing food. Agricultural
byproducts include, but are not limited to, oat, corn and wheat straws,
bagasse, peanut shells, rice and coconut husks, soybean hulls, palm
kernel cake, cottonseed and sunflower seed cake, and pomace.
* * * * *
Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons
that have been separated from natural gas as liquids through the
process of absorption, condensation, adsorption, or other methods.
Generally, such liquids consist of ethane, propane, butanes, and
pentanes plus. Bulk NGL is sold to fractionators or to refineries and
petrochemical plants where the fractionation takes place.
* * * * *
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 generic term distillate
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels
(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1,
No. 2, and No. 4).
* * * * *
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.
* * * * *
Municipal solid waste or MSW means solid phase household,
commercial/retail, and/or institutional waste. Household waste includes
material discarded by single and multiple
[[Page 48786]]
residential dwellings, hotels, motels, and other similar permanent or
temporary housing establishments or facilities. Commercial/retail waste
includes material discarded by stores, offices, restaurants,
warehouses, non-manufacturing activities at industrial facilities, and
other similar establishments or facilities. Institutional waste
includes material discarded by schools, nonmedical waste discarded by
hospitals, material discarded by non-manufacturing activities at
prisons and government facilities, and material discarded by other
similar establishments or facilities. Household, commercial/retail, and
institutional waste does not include used oil, wood pellets,
construction, renovation, and demolition wastes (which includes, but is
not limited to, railroad ties and telephone poles), clean wood,
industrial process or manufacturing wastes, medical waste, or motor
vehicles (including motor vehicle parts or vehicle fluff). Household,
commercial/retail, and institutional wastes include yard waste, refuse-
derived fuel, and motor vehicle maintenance materials, limited to
vehicle batteries and tires, except where a single waste stream
consisting of tires is combusted in a unit.
* * * * *
Natural gas means a naturally occurring mixture of hydrocarbon and
non-hydrocarbon gases found in geologic formations beneath the earth's
surface, of which the principal constituent is methane. Natural gas may
be field quality or pipeline quality. Natural gas is composed of at
least 70 percent methane by volume or has a high heat value between 910
and 1150 Btu per standard cubic foot.
Natural gas liquids (NGLs) means those hydrocarbons in natural gas
that are separated from the gas as liquids through the process of
absorption, condensation, adsorption, or other methods. Generally, such
liquids consist of ethane, propane, butanes, and pentanes plus. Bulk
NGLs refers to mixtures of NGLs that are sold or delivered as
undifferentiated product from natural gas processing plants.
* * * * *
Primary fuel means the fuel that provides the greatest percentage
of the annual heat input to a stationary fuel combustion unit.
* * * * *
Solid byproducts means plant matter such as vegetable waste, animal
materials/wastes, and other solid biomass, except for wood, wood waste,
and sulphite lyes (black liquor).
* * * * *
Waste oil means a petroleum-derived or synthetically-derived oil
whose physical properties have changed as a result of storage, handling
or use, such that the oil cannot be used for its original purpose.
Waste oil consists primarily of automotive oils (e.g., used motor oil,
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial
oils (e.g., industrial engine oils, metalworking oils, process oils,
industrial grease, etc).
* * * * *
Wood residuals means wood waste recovered from three principal
sources: Municipal solid waste (MSW); construction and demolition
debris; and primary timber processing. Wood residuals recovered from
MSW include wooden furniture, cabinets, pallets and containers, scrap
lumber (from sources other than construction and demolition
activities), and urban tree and landscape residues. Wood residuals from
construction and demolition debris originate from the construction,
repair, remodeling and demolition of houses and non-residential
structures. Wood residuals from primary timber processing include bark,
sawmill slabs and edgings, sawdust, and peeler log cores. Other sources
of wood residuals include, but are not limited to, railroad ties,
telephone and utility poles, pier and dock timbers, wastewater process
sludge from paper mills, and logging residues.
* * * * *
6. Section 98.7 is amended by:
a. Removing and reserving paragraph (b).
b. Revising paragraphs (d)(1) and (d)(2).
c. Removing and reserving paragraph (d)(3).
d. Revising paragraphs (d)(4) and (d)(5).
e. Removing and reserving paragraph (d)(6).
f. Revising paragraphs (d)(7) and (d)(8).
g. Removing and reserving paragraph (d)(9).
h. Revising paragraph (d)(10).
i. Removing and reserving paragraph (d)(11).
j. Revising paragraph (e)(4).
k. Removing and reserving paragraph (e)(7).
l. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14), (e)(15),
(e)(19), (e)(20), (e)(24) through (e)(27).
m. Removing and reserving paragraph (e)(28).
n. Revising paragraph (e)(30), (e)(33), and (e)(36).
o. Adding paragraphs (e)(43) and (e)(44).
p. Removing and reserving paragraph (f)(1) and (g)(3).
q. Revising paragraph (f)(2)
r. Removing and reserving paragraph (g)(3).
s. Adding paragraph (m)(3).
Sec. 98.7 What standardized methods are incorporated by reference
into this part?
* * * * *
(d) * * *
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved
for Sec. 98.344(c) and Sec. 98.364(e).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by
Turbine Meters, IBR approved for Sec. 98.344(c) and Sec. 98.364(e).
(3) [Reserved]
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters, IBR approved for Sec. 98.344(c) and Sec.
98.364(e).
(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.
98.344(c) and Sec. 98.364(e).
(6) [Reserved]
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec. 98.344(c).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec. 98.344(c) and Sec.
98.364(e).
(9) [Reserved]
(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec. 98.344(c), and Sec. 98.364(e).
(11) [Reserved]
(e) * * *
(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR
approved for Sec. 98.254(e).
* * * * *
(7) [Reserved]
(8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous
Recording Calorimeter, IBR approved for Sec. 98.254(e).
* * * * *
(10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas
by Gas Chromatography, IBR approved for Sec. 98.74(c), Sec.
98.164(b), Sec. 98.244(b), Sec. 98.254(d), and Sec. 98.344(b).
(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography,
[[Page 48787]]
IBR approved for Sec. 98.74(c), Sec. 98.164(b), Sec. 98.254(d),
Sec. 98.344(b), and Sec. 98.364(c).
* * * * *
(14) ASTM D2502-04 Standard Test Method for Estimation of Mean
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements,
IBR approved for Sec. 98.74(c).
(15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec.
98.74(c).
* * * * *
(19) 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, IBR approved for Sec. 98.74(c) and
Sec. 98.164(b).
(20) ASTM D3588-98 (Reapproved 2003) Standard Practice for
Calculating Heat Value, Compressibility Factor, and Relative Density of
Gaseous Fuels, IBR approved for Sec. 98.254(e).
* * * * *
(24) ASTM D4809-06 Standard Test Method for Heat of Combustion of
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR
approved for Sec. 98.254(e).
(25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for
Heating Value of Gases in Natural Gas Range by Stoichiometric
Combustion, IBR approved for Sec. 98.254(e).
(26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in
Petroleum Products and Lubricants, IBR approved for Sec. 98.74(c),
Sec. 98.164(b), Sec. 98.244(b), and Sec. 98.254(i).
(27) ASTM D5373-08 Standard Test Methods for Instrumental
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples
of Coal, IBR approved for Sec. 98.74(c), Sec. 98.114(b), Sec.
98.164(b), Sec. 98.174(b), Sec. 98.184(b), Sec. 98.244(b), Sec.
98.254(i), Sec. 98.274(b), Sec. 98.284(c), Sec. 98.284(d), Sec.
98.314(c), Sec. 98.314(d), Sec. 98.314(f), and Sec. 98.334(b).
(28) [Reserved]
* * * * *
(30) ASTM D6348-03 Standard Test Method for Determination of
Gaseous Compounds by Extractive Direct Interface Fourier Transform
Infrared (FTIR) Spectroscopy, IBR approved for Sec. 98.54(b),Sec.
98.224(b), and Sec. 98.414(n).
* * * * *
(33) ASTM D6866-08 Standard Test Methods for Determining the
Biobased Content of Solid, Liquid, and Gaseous Samples Using
Radiocarbon Analysis, IBR approved for Sec. 98.34(d), Sec. 98.34(e),
and Sec. 98.36(e).
* * * * *
(36) ASTM D7459-08 Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved
for Sec. 98.34(d), Sec. 98.34(e), and Sec. 98.36(e).
* * * * *
(43) ASTM D2503-92(2007) Standard Test Method for Relative
Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric
Measurement of Vapor Pressure, IBR approved for Sec. 98.254(d).
(44) ASTM D2593-93(2009) Standard Test Method for Butadiene Purity
and Hydrocarbon Impurities by Gas Chromatography, IBR approved for
Sec. 98.244(b).
* * * * *
(f) * * *
(1) [Reserved]
(2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous
Mixtures by Gas Chromatography, IBR approved for Sec. 98.164(b), Sec.
98.254(d), and Sec. 98.344(b).
* * * * *
(g) [Reserved]
* * * * *
(k) The following material is available from the U.S. Environmental
Protection Agency, 1200 Pennsylvania Avenue, NW, Washington, D.C.
20460, (202) 272-0167, www.epa.gov.
(1) Protocol for Measuring Destruction or Removal Efficiency (DRE)
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003.
Subpart C--[Amended]
7. Section 98.30 is amended by:
a. Revising paragraph (b)(4).
b. Revising paragraph (c) introductory text.
c. Adding paragraph (d).
Sec. 98.30 Definition of the source category.
(b) * * *
(4) Flares, unless otherwise required by provisions of another
subpart of this part to use methodologies in this subpart.
* * * * *
(c) For a unit that combusts hazardous waste (as defined in Sec.
261.3 of this chapter), reporting of GHG emissions is not required
unless either of the following conditions apply:
* * * * *
(d) You are not required to report GHG emissions from pilot lights.
A pilot light is a small permanent auxiliary flame that ignites the
burner of a combustion device when the control valve opens.
8. Section 98.32 is revised to read as follows:
Sec. 98.32 GHGs to report.
You must report CO2, CH4, and N2O
mass emissions from each stationary fuel combustion unit, except as
otherwise indicated in this subpart.
9. Section 98.33 is amended by:
a. Revising paragraphs (a) introductory text and (a)(1).
b. Revising the definition of ``HHV'' in Equation C-2a of paragraph
(a)(2)(i).
c. Revising and the first two sentences of paragraph (a)(2)(ii)
introductory text.
d. In paragraph (a)(2)(ii)(A), revising the first sentence and the
definitions of ``(HHV)i,'' ``(Fuel)i,'' and ``n''
in Equation C-2b.
e. Revising paragraph (a)(2)(ii)(B).
f. Revising the definitions of ``CC'' and ``MW'' in Equation C-5 of
paragraph (a)(3)(iii).
g. Revising paragraphs (a)(3)(iv), (a)(4)(iii), and (a)(4)(iv).
h. Adding a new paragraph (a)(4)(viii).
i. Revising paragraphs (a)(5) introductory text, (a)(5)(i)
introductory text, (a)(5)(i)(A), (a)(5)(i)(B), (a)(5)(ii) introductory
text, (a)(5)(ii)(A), (a)(5)(iii) introductory text, (a)(5)(iii)(A),
(a)(5)(iii)(B).
j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv),
and revising newly designated paragraph (a)(5)(iv).
k. Revising paragraph (b)(1)(iv).
l. Adding paragraph (b)(1)(v).
m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii)
introductory text, and (b)(3)(iii)(B).
n. Adding paragraph (b)(3)(iv).
o. Adding a second sentence to paragraph (b)(4)(i).
p. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), (b)(4)(ii)(E),
(b)(4)(ii)(F), and (b)(4)(iii) introductory text.
q. Adding a new paragraph (b)(4)(iv).
r. Revising paragraph (b)(5) and the third sentence of paragraph
(b)(6).
s. In paragraph (c)(1), revising the second sentence, and revising
the definition of ``HHV'' in Equation C-8.
t. Revising the second sentence of paragraph (c)(2).
u. In paragraph (c)(4) introductory text, revising the only
sentence and revising the definition of ``(HI)A'' in
Equation C-10.
v. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
w. Adding a new paragraph (c)(6).
x. In paragraph (d)(1), revising the first sentence, adding a
second sentence, and revising the definition of ``R'' in Equation C-11.
[[Page 48788]]
y. Revising paragraphs (d)(2), (e) introductory text, (e)(1), and
(e)(2) introductory text.
z. Revising the definition of ``Fc'' in Equation C-13 of
paragraph (e)(2)(iii).
aa. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
bb. Reserving paragraph (e)(4).
cc. Revising the first sentence of paragraph (e)(5).
Sec. 98.33 Calculating GHG emissions.
* * * * *
(a) CO2 emissions from fuel combustion. Calculate
CO2 mass emissions by using one of the four calculation
methodologies in paragraphs (a)(1) through (a)(4) of this section,
subject to the applicable conditions, requirements, and restrictions
set forth in paragraph (b) of this section. Alternatively, for units
that meet the conditions of paragraph (a)(5) of this section, you may
use CO2 mass emissions calculation methods from part 75 of
this chapter, as described in paragraph (a)(5) of this section. For
units that combust both biomass and fossil fuels, you must calculate
and report CO2 emissions from the combustion of biomass
separately using the methods in paragraph (e) of this section, except
as otherwise provided in paragraphs (a)(5)(iv) and (e) of this section
and in Sec. 98.36(d).
(1) Tier 1 Calculation Methodology. Calculate the annual
CO2 mass emissions for each type of fuel by using Equation
C-1 or C-1a of this section (as applicable).
(i) Use Equation C-1 except when natural gas billing records are
used to quantify fuel usage and gas consumption is expressed in units
of therms. In that case, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TP11AU10.002
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 as defined in Sec. 98.6 (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.
(ii) If natural gas consumption is obtained from billing records
and fuel usage is expressed in therms, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TP11AU10.003
Where:
CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas consumption, from billing records (therms).
EF = Fuel-specific default CO2 emission factor for
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric
tons.
(2) * * *
(i) * * *
HHV = Annual average high heat value of the fuel (mmBtu per mass or
volume). The average HHV shall be calculated according to the
requirements of paragraph (a)(2)(ii) of this section.
* * * * *
(ii) The minimum required sampling frequency for determining the
annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot)
is specified in Sec. 98.34. The method for computing the annual
average HHV is a function of unit size and how frequently you perform
or receive from the fuel supplier the results of fuel sampling for HHV.
* * *
(A) If the results of fuel sampling are received monthly or more
frequently, then for each unit with a maximum rated heat input capacity
greater than or equal to 100 mmBtu/hr (or for a group of units that
includes at least one unit of that size), the annual average HHV shall
be calculated using Equation C-2b of this section. * * *
* * * * *
(HHV)i = Measured high heat value of the fuel, for month
``i'', or, if applicable, an appropriate substitute data value
(mmBtu per mass or volume).
(Fuel)i = Mass or volume of the fuel combusted during
month ``i,'' 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).
n = Number of months in the year that the fuel is burned in the
unit.
(B) If the results of fuel sampling are received less frequently than
monthly, or, for a unit with a maximum rated heat input capacity less
than 100 mmBtu/hr (or a group of such units) regardless of the HHV
sampling frequency, the annual average HHV shall be computed as the
arithmetic average HHV for all values for the year (including valid
samples and substitute data values under Sec. 98.35).
* * * * *
(3) * * *
(iii) * * *
CC = Annual average carbon content of the gaseous fuel (kg C per kg
of fuel). The annual average carbon content shall be determined
using the same procedures as specified for HHV in paragraph
(a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-
mole). The annual average molecular weight shall be determined using
the same procedures as specified for HHV in paragraph (a)(2)(ii) of
this section.
* * * * *
(iv) Fuel flow meters that measure mass flow rates may be used for
liquid or gaseous fuels, provided that the fuel density is used to
convert the readings to volumetric flow rates. The density shall be
measured at the same frequency as the carbon content. For liquid fuels,
you must measure the density using one of the following appropriate
methods. You may use a method published by a consensus standards
organization, if such a method exists, or you may use industry standard
practice. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
The method(s) used shall be documented in the Monitoring Plan required
under Sec. 98.3(g)(5). Alternatively, for fuel oil, you may use
[[Page 48789]]
an applicable default density value provided in paragraph (a)(3)(v) of
this section. For gaseous fuels, you may determine the density using
any of the following methods. You may use a density meter calibrated
according to the manufacturer's instructions, a method published by a
consensus standards organization, or an industry standard practice.
Document the method used to determine the fuel density in the
Monitoring Plan under Sec. 98.3(g)(5).
* * * * *
(4) * * *
(iii) If the CO2 concentration is measured on a dry
basis, a correction for the stack gas moisture content is required. You
shall either continuously monitor the stack gas moisture content as
described in Sec. 75.11(b)(2) of this chapter or use an appropriate
default moisture percentage. For coal, wood, and natural gas
combustion, you may use the default moisture values specified in Sec.
75.11(b)(1) of this chapter. Alternatively, for any type of fuel, you
may determine an appropriate site-specific default moisture value (or
values), using measurements made with EPA Method 4--Determination Of
Moisture Content In Stack Gases, in appendix A-3 to part 60 of this
chapter. If this option is selected, the site-specific moisture default
value(s) must represent the fuel(s) or fuel blends that are combusted
in the unit during normal, stable operation, and must account for any
distinct difference(s) in the stack gas moisture content associated
with different process operating conditions. For each site-specific
default moisture percentage, at least nine Method 4 runs are required.
Moisture data from the relative accuracy test audit (RATA) of a CEMS
may be used for this purpose. Calculate each site-specific default
moisture value by taking the arithmetic average of the Method 4 runs.
Each site-specific moisture default value shall be updated whenever the
owner or operator believes the current value is non-representative, due
to changes in unit or process operation, but in any event no less
frequently than annually. Use the updated moisture value in the
subsequent CO2 emissions calculations. For each unit
operating hour, a moisture correction must be applied to Equation C-6
of this section as follows:
[GRAPHIC] [TIFF OMITTED] TP11AU10.004
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 (metric 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 (i.e., no process CO2 emissions or CO2
emissions from sorbent are mixed with the 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 determined in accordance with paragraph (a)(4)(iii) of this
section.
* * * * *
(viii) If a portion of the flue gases generated by a unit subject
to Tier 4 (e.g., a slip stream) is continuously diverted from the main
flue gas exhaust system for the purpose of heat recovery or some other
similar process, and then exhausts through a stack that is not equipped
with the continuous emission monitors to measure CO2 mass
emissions, provided that the CO2 concentration in the
diverted stream is not altered in any way (e.g., by chemical reaction
or dilution) before the diverted stream exits to the atmosphere, an
estimate of the hourly average volumetric flow rate (scfh) of the
diverted gas stream shall be made at the point where it exits the main
exhaust system, by using the best available information (e.g.,
correlations of operating parameters versus flow measurements made with
EPA Method 2 in appendix A-2 to part 60 of this chapter, engineering
analysis, or other methods). Each hourly average volumetric flow rate
(scfh) measured at the main flue gas stack shall then be added to the
corresponding estimate of the hourly average flow rate of the diverted
gas stream, to determine the total hourly average stack gas volumetric
flow rate ``Q'', for use in Equation C-6 of this section. The method
use to estimate the hourly flow rate of the diverted portion of the
flue gas exhaust stream shall be documented in the Monitoring Plan
required under Sec. 98.3(g)(5).
(5) Alternative methods for certain units subject to Part 75 of
this chapter. Certain units that are not subject to subpart D of this
part and that report data to EPA according to part 75 of this chapter
may qualify to use the alternative methods in this paragraph (a)(5), in
lieu of using any of the four calculation methodology tiers.
(i) For a unit that combusts only natural gas and/or fuel oil, is
not subject to subpart D of this part, monitors and reports heat input
data year-round according to appendix D to part 75 of this chapter, but
is not required by the applicable part 75 program to report
CO2 mass emissions data, calculate the annual CO2
mass emissions for the purposes of this part as follows:
(A) Use the hourly heat input data from appendix D to part 75 of
this chapter, together with Equation G-4 in appendix G to part 75 of
this chapter to determine the hourly CO2 mass emission
rates, in units of tons/hr;
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this
chapterto calculate the quarterly and cumulative annual CO2
mass emissions, respectively, in units of short tons; and
* * * * *
(ii) For a unit that combusts only natural gas and/or fuel oil, is
not subject to subpart D of this part, monitors and reports heat input
data year-round according to Sec. 75.19 of this chapter but is not
required by the applicable part 75 program to report CO2
mass emissions data, calculate the annual CO2 mass emissions
for the purposes of this part as follows:
(A) Calculate the hourly CO2 mass emissions, in units of
short tons, using Equation LM-11 in Sec. 75.19(c)(4)(iii) of this
chapter.
* * * * *
(iii) For a unit that is not subject to subpart D of this part,
uses flow rate and CO2 (or O2) CEMS to report
heat input data year-round according to part 75 of
[[Page 48790]]
this chapter, but is not required by the applicable part 75 program to
report CO2 mass emissions data, calculate the annual
CO2 mass emissions as follows:
(A) Use Equation F-11 or F-2 (as applicable) in appendix F to part
75 of this chapter to calculate the hourly CO2 mass emission
rates from the CEMS data. If an O2 monitor is used, convert
the hourly average O2 readings to CO2 using
Equation F-14a or F-14b in appendix F to part 75 of this chapter (as
applicable), before applying Equation F-11 or F-2.
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this
chapter to calculate the quarterly and cumulative annual CO2
mass emissions, respectively, in units of short tons.
* * * * *
(iv) For units that qualify to use the alternative CO2
emissions calculation methods in paragraphs (a)(5)(i) through
(a)(5)(iii) of this section, if both biomass and fossil fuel are
combusted during the year, separate calculation and reporting of the
biogenic CO2 mass emissions (as described in paragraph (e)
of this section) is optional.
(b) * * *
(1) * * *
(iv) May not be used if you routinely perform fuel sampling and
analysis for the fuel high heat value (HHV) or routinely receive the
results of HHV sampling and analysis from the fuel supplier at the
minimum frequency specified in Sec. 98.34(a), or at a greater
frequency. In such cases, Tier 2 shall be used. This restriction does
not apply to paragraphs (b)(1)(ii) and (b)(1)(v) of this section.
(v) May be used for natural gas combustion in a unit of any size,
in cases where the annual natural gas consumption is obtained from fuel
billing records in units of therms.
(2) * * *
(ii) May be used in a unit with a maximum rated heat input capacity
greater than 250 mmBtu/hr for the combustion of natural gas and/or
distillate fuel oil.
* * * * *
(3) * * *
(ii) * * *
(A) The use of Tier 1 or 2 is permitted, as described in paragraphs
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.
* * * * *
(iii) Shall be used for a fuel not listed in Table C-1 of this
subpart if the fuel is combusted in a unit with a maximum rated heat
input capacity greater than 250 mmBtu/hr (or, pursuant to Sec.
98.36(c)(3), in a group of units served by a common supply pipe, having
at least one unit with a maximum rated heat input capacity greater than
250 mmBtu/hr), provided that both of the following conditions apply:
* * * * *
(B) The fuel provides 10% or more of the annual heat input to the
unit or, if Sec. 98.36(c)(3) applies, to the group of units served by
a common supply pipe.
(iv) Shall be used when specified in another applicable subpart of
this part, regardless of unit size.
(4) * * *
(i) * * * Tier 4 may also be used for any group of stationary fuel
combustion units, process units, or manufacturing units that share a
common stack or duct.
(ii) * * *
(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 600 tons per day of MSW.
(B) The unit combusts solid fossil fuel or MSW as the primary fuel.
* * * * *
(E) The installed CEMS include a gas monitor of any kind or a stack
gas volumetric flow rate monitor, or both and the monitors have been
certified, either 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 or stack gas volumetric flow rate monitors
are required, either by an applicable Federal or State regulation or by
the unit's operating permit, to undergo periodic quality assurance
testing in accordance with either 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 600 tons of MSW per
day or less, if the unit meets all of the following three conditions:
* * * * *
(iv) May apply to common stack or duct configurations where:
(A) The combined effluent gas streams from two or more stationary
fuel combustion units are vented through a monitored common stack or
duct. In this case, Tier 4 shall be used if all of the conditions in
paragraph (b)(4)(iv)(A)(1) of this section or all of the conditions in
paragraph (b)(4)(iv)(A)(2) of this section are met.
(1) At least one of the units meets the requirements of paragraphs
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS
installed at the common stack (or duct) meet the requirements of
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
(2) At least one of the units and the monitors installed at the
common stack or duct meet the requirements of paragraph (b)(4)(iii) of
this section.
(B) The combined effluent gas streams from a process or
manufacturing unit and a stationary fuel combustion unit are vented
through a monitored common stack or duct. In this case, Tier 4 shall be
used if the combustion unit and the monitors installed at the common
stack or duct meet the applicability criteria specified in paragraph
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
(C) The combined effluent gas streams from two or more
manufacturing or process units are vented through a common stack or
duct. In this case, if any of the units is required by an applicable
subpart of this part to use Tier 4, the CO2 mass emissions
may either be monitored at each individual unit, or the combined
CO2 mass emissions may be monitored at the common stack or
duct. However, if it is not feasible to monitor the individual units,
the combined CO2 mass emissions shall be monitored at the
common stack or duct.
(5) The Tier 4 Calculation Methodology shall be used:
(i) Starting on January 1, 2010, for a unit that 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) No later than 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,
you may use Tier 2 or Tier 3 to report GHG emissions for 2010. However,
if the required CEMS are certified some time in 2010, you need not wait
until January 1, 2011 to begin using Tier 4. Rather, you may switch
from Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing
is successfully completed. If this reporting option is chosen, you must
document the change in CO2 calculation methodology in the
Monitoring Plan required under Sec. 98.3(g)(5) and in the GHG
emissions report under Sec. 98.3(c). Data recorded by the CEMS during
a certification test period in 2010 may be used for reporting under
this part, provided that the following two conditions are met:
(A) The certification tests are passed in sequence, with no test
failures.
[[Page 48791]]
(B) No unscheduled maintenance or repair of the CEMS is performed
during the certification test period.
(iii) No later than 180 days following the date on which a change
is made that triggers Tier 4 applicability under paragraph (b)(4)(ii)
or (b)(4)(iii) of this section (e.g., a change in the primary fuel,
manner of unit operation, or installed continuous monitoring
equipment).
(6) * * * However, for units that use either the Tier 4 or the
alternative calculation methodology specified in paragraph (a)(5)(iii)
of this section, CO2 emissions from the combustion of all
fuels shall be based solely on CEMS measurements.
(c) * * *
(1) * * * Use the same values for fuel consumption that you use for
the Tier 1 or Tier 3 calculation.
* * * * *
HHV = Default high heat value of the fuel from Table C-1 of this
subpart; alternatively, for Tier 3, if actual HHV data are available
for the reporting year, you may average these data using the
procedures specified in paragraph (a)(2)(ii) of this section, and
use the average value in Equation C-8 (mmBtu per mass or volume).
* * * * *
(2) * * * Use the same values for fuel consumption and HHV that you
use for the Tier 2 calculation.
* * * * *
(4) Use Equation C-10 of this section for: units subject to subpart
D of this part; units that qualify for and elect to use the alternative
CO2 mass emissions calculation methodologies described in
paragraph (a)(5) of this section; and units that use the Tier 4
Calculation Methodology.
* * * * *
(HI)A = Cumulative annual heat input from combustion of
the fuel (mmBtu).
* * * * *
(i) If only one type of fuel listed in Table C-2 of this subpart is
combusted during the reporting year, substitute the cumulative annual
heat input from combustion of the fuel into Equation C-10 of this
section to calculate the annual CH4 or N2O
emissions. For units in the Acid Rain Program and units that report
heat input data to EPA year-round according to part 75 of this chapter,
obtain the cumulative annual heat input directly from the electronic
data reports required under Sec. 75.64 of this chapter. For Tier 4
units, use the best available information, as described in paragraph
(c)(4)(ii)(C) of this section, to estimate the cumulative annual heat
input (HI)A.
(ii) If more than one type of fuel listed in Table C-2 of this
subpart is combusted during the reporting year, use Equation C-10 of
this section separately for each type of fuel, except as provided in
paragraph (c)(4)(ii)(B) of this section. Determine the appropriate
values of (HI)A as follows:
(A) For units in the Acid Rain Program and other units that report
heat input data to EPA year-round according to part 75 of this chapter,
obtain (HI)A for each type of fuel from the electronic data
reports required under Sec. 75.64 of this chapter, except as otherwise
provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.
(B) For a unit that uses CEMS to monitor hourly heat input
according to part 75 of this chapter, the value of (HI)A
obtained from the electronic data reports under Sec. 75.64 of this
chapter may be attributed exclusively to the fuel with the highest F-
factor, when the reporting option in 3.3.6.5 of appendix F to part 75
of this chapter is selected and implemented.
(C) For Tier 4 units, use the best available information (e.g.,
fuel feed rate measurements, fuel heating values, engineering analysis)
to estimate the value of (HI)A for each type of fuel.
Instrumentation used to make these estimates is not subject to the
calibration requirements of Sec. 98.3(i) or to the QA requirements of
Sec. 98.34.
(D) Units in the Acid Rain Program and other units that report heat
input data to EPA year-round according to part 75 of this chapter may
use the best available information described in paragraph (c)(4)(ii)(C)
of this section, to estimate (HI)A for each fuel type,
whenever fuel-specific heat input values cannot be directly obtained
from the electronic data reports under Sec. 75.64 of this chapter.
* * * * *
(6) Calculate the annual CH4 and N2O mass
emissions from the combustion of blended fuels as follows:
(i) If the mass or volume of each component fuel in the blend is
measured before the fuels are mixed and combusted, calculate and report
CH4 and N2O emissions separately for each
component fuel, using the applicable procedures in this paragraph (c).
(ii) If the mass or volume of each component fuel in the blend is
not measured before the fuels are mixed and combusted, a reasonable
estimate of the percentage composition of the blend, based on best
available information, is required. Perform the following calculations
for each component fuel, ``i,'' that is listed in Table C-2:
(A) Multiply (% Fuel)i, the estimated mass or volume
percentage (decimal fraction) of component fuel ``i,'' by the total
annual mass or volume of the blended fuel combusted during the
reporting year, to obtain an estimate of the annual consumption of
component ``i;''
(B) Multiply the result from paragraph (c)(6)(ii)(A) of this
section by the HHV of the fuel (default value or, if available, the
measured annual average value), to obtain an estimate of the annual
heat input from component ``i;''
(C) Calculate the annual CH4 and N2O
emissions from component ``i,'' using Equation C-8, C-9a, or C-10 of
this section, as applicable;
(D) Sum the annual CH4 emissions across all component
fuels to obtain the annual CH4 emissions for the blend.
Similarly sum the annual N2O emissions across all component
fuels to obtain the annual N2O emissions for the blend.
Report these annual emissions totals.
(d) * * *
(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 to remove acid gases, if the chemical
reaction between the acid gas and the sorbent produces CO2
emissions, use Equation C-11 of this section to calculate the
CO2 emissions from the sorbent, except when those
CO2 emissions are monitored by CEMS. When a sorbent other
than CaCO3 is used, determine site-specific values of R and
MWS.
* * * * *
R = The number of moles of CO2 released upon capture of
one mole of the acid gas species being removed (R = 1.00 when the
sorbent is CaCO3 and the targeted acid gas species is
SO2).
* * * * *
(2) The total annual CO2 mass emissions reported for the
unit shall include the CO2 emissions from the combustion
process and the CO2 emissions from the sorbent.
(e) Biogenic CO2 emissions from combustion of biomass
with other fuels. Use the applicable procedures of this paragraph (e)
to estimate biogenic CO2 emissions from units that combust a
combination of biomass and fossil fuels (i.e., either co-fired or
blended fuels). Separate reporting of biogenic CO2 emissions
from the combined combustion of biomass and fossil fuels is required
for those biomass fuels listed in Table C-1 of this section and for
municipal solid waste. In addition, when a biomass fuel that is not
listed in Table C-1 is combusted in a unit that has a maximum rated
heat input greater than 250 mmBtu/hr, if the biomass fuel accounts for
10% or more of the annual heat input to the unit, and if the unit
[[Page 48792]]
does not use CEMS to quantify its annual CO2 mass emissions,
then, pursuant to Sec. 98.33(b)(3)(iii), Tier 3 must be used to
determine the carbon content of the biomass fuel and to calculate the
biogenic CO2 emissions from combustion of the fuel.
Notwithstanding these requirements, separate reporting of biogenic
CO2 emissions is optional for units subject to subpart D of
this part and for units that use the CO2 mass emissions
calculation methodologies in part 75 of this chapter, pursuant to
paragraph (a)(5) of this section; however, if the owner or operator
opts to report biogenic CO2 emissions separately for these
units, the appropriate method(s) in this paragraph (e) shall be used.
Separate reporting of biogenic CO2 emissions from the
combustion of tires is also optional, but may be reported by following
the provisons of paragraph (e)(3) of this section.
(1) You may use Equation C-1 of this subpart to calculate the
annual CO2 mass emissions from the combustion of the biomass
fuels listed in Table C-1 of this subpart (except MSW and tires), in a
unit of any size, including units equipped with a CO2 CEMS,
except when the use of Tier 2 is required as specified in paragraph
(b)(1)(iv) of this section. Determine the quantity of biomass combusted
using one of the following procedures in this paragraph (e)(1), as
appropriate, and document the selected procedures in the Monitoring
Plan under Sec. 98.3(g):
(i) Company records.
(ii) The procedures in paragraph (e)(5) of this section.
(iii) The best available information for premixed fuels that
contain biomass and fossil fuels (e.g., liquid fuel mixtures containing
biodiesel).
(2) You may use the procedures of this paragraph if the following
three conditions are met: first, a CO2 CEMS (or a surrogate
O2 monitor) and a stack gas flow rate monitor are used to
determine the annual CO2 mass emissions (either according to
part 75 of this chapter, the Tier 4 Calculation Methodology, or the
alternative calculation methodology specified in paragraph (a)(5)(iii)
of this section); second, neither MSW nor tires is combusted in the
unit during the reporting year; and third, the CO2 emissions
consist solely of combustion products (i.e., no process or sorbent
emissions included).
* * * * *
(iii) * * *
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 (scf CO2/mmBtu).
* * * * *
(iv) Subtract Vff from Vtotal to obtain
Vbio, the annual volume of CO2 from the
combustion of biomass.
* * * * *
(vi) * * *
(C) From the electronic data report required under Sec. 75.64 of
this chapter, for units in the Acid Rain Program and other units using
CEMS to monitor and report CO2 mass emissions according to
part 75 of this chapter. However, before calculating the annual
biogenic CO2 mass emissions, multiply the cumulative annual
CO2 mass emissions by 0.91 to convert from short tons to
metric tons.
(3) You must use the procedures in paragraphs (e)(3)(i) through
(e)(3)(iii) of this section to determine the annual biogenic
CO2 emissions from the combustion of MSW. These procedures
also may be used for any unit that co-fires biomass and fossil fuels,
including units equipped with a CO2 CEMS, and units for
which optional separate reporting of biogenic CO2 emissions
from the combustion of tires is selected.
(i) Use an applicable CO2 emissions calculation method
in this section to quantify the total annual CO2 mass
emissions from the unit.
(ii) Determine the relative proportions of biogenic and non-
biogenic CO2 emissions in the flue gas on a quarterly basis
using the method specified in Sec. 98.34(d) (for units that combust
MSW as the primary fuel or as the only fuel with a biogenic component)
or in Sec. 98.34(e) (for other units, including units that combust
tires).
(iii) Determine the annual biogenic CO2 mass emissions
from the unit by multiplying the total annual CO2 mass
emissions by the annual average biogenic decimal fraction obtained from
Sec. 98.34(d) or Sec. 98.34(e), as applicable.
(4) [Reserved]
(5) If Equation C-1 or Equation C-2a of this section is selected to
calculate the annual biogenic mass emissions for wood, wood waste, or
other solid biomass-derived fuel, Equation C-15 of this section may be
used to quantify biogenic fuel consumption, provided that all of the
required input parameters are accurately quantified. * * *
* * * * *
10. Section 98.34 is amended by:
a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) introductory
text, (b)(1)(i) introductory text, (b)(1)(i)(A), (b)(1)(i)(B),
(b)(1)(i)(C), (b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), and
(b)(3)(v).
b. Removing paragraph (b)(4).
c. Redesignating paragraph (b)(5) as (b)(4).
d. Revising newly designated paragraph (b)(4).
e. Revising paragraphs (c) introductory text, (c)(1)(i),
(c)(1)(ii), (c)(2), (c)(3), and (c)(4).
f. Adding paragraphs (c)(6) and (c)(7).
g. Revising paragraphs (d), (e), (f) introductory text, (f)(1),
(f)(3), and (f)(5).
h. Adding new paragraphs (f)(7) and (f)(8).
i. Removing paragraph (g).
Sec. 98.34 Monitoring and QA/QC requirements.
* * * * *
(a) * * *
(2) The minimum required frequency of the HHV sampling and analysis
for each type of fuel or fuel mixture (blend) is specified in this
paragraph. When the specified frequency for a particular fuel or blend
is based on a specified time period (e.g., week, month, quarter, or
half-year), fuel sampling and analysis is required only for those time
periods in which the fuel or blend is combusted. The owner or operator
may perform fuel sampling and analysis more often than the minimum
required frequency, in order to obtain a more representative annual
average HHV.
(i) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
(ii) For coal and fuel oil, and for any other solid or liquid fuel
that is delivered in lots, analysis of at least one representative
sample from each fuel lot is required. For fuel oil, as an alternative
to sampling each fuel lot, a sample may be taken upon each addition of
oil to the unit's storage tank. Flow proportional sampling, continuous
drip sampling, or daily manual oil sampling may also be used, in lieu
of sampling each fuel lot. For the purposes of this section, a fuel lot
is defined as either:
(A) A shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via
pipeline from a tank farm, etc.); or
(B) If multiple deliveries of a particular type of fuel are
received from the same supply source in a given calendar month, the
deliveries for that month are considered, collectively, to comprise a
fuel lot, requiring only one representative sample.
(iii) For liquid fuels other than fuel oil, and for gaseous fuels
other than natural gas (including biogas), sampling and analysis is
required at least once per calendar quarter. To the extent
[[Page 48793]]
practicable, consecutive quarterly samples shall be taken at least 30
days apart.
(iv) For other solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are then analyzed monthly.
(v) For fuel blends that are received already mixed, as described
in paragraph (a)(3)(ii) of this section, determine the HHV of the blend
as follows. For blends of solid fuels (except MSW), weekly sampling is
required to obtain composite samples, which are analyzed monthly. For
blends of liquid or gaseous fuels, sampling and analysis is required at
least once per calendar quarter. More frequent sampling is recommended
if the composition of the blend varies significantly during the year.
(3) Special Considerations for Blending of Fuels. In situations
where different types of fuel listed in Table C-1 of this subpart (for
example, different ranks of coal or different grades of fuel oil) are
in the same state of matter (i.e., solid, liquid, or gas), and are
blended prior to combustion, use the following procedures to determine
the appropriate CO2 emission factor and HHV for the blend.
(i) If the fuels to be blended are received separately, and if the
quantity (mass or volume) of each fuel is measured before the fuels are
mixed and combusted, then, for each component of the blend, calculate
the CO2 mass emissions separately. Substitute into Equation
C-2a of this subpart the total measured mass or volume of the component
fuel (from company records), together with the appropriate default
CO2 emission factor from Table C-1, and the annual average
HHV, calculated according to Sec. 98.33(a)(2)(ii). In this case, the
fact that the fuels are blended prior to combustion is of no
consequence.
(ii) If the fuel is received as a blend (i.e., already mixed), a
reasonable estimate of the relative proportions of the components of
the blend must be made, using the best available information (e.g., the
approximate annual average mass or volume percentage of each fuel,
based on the typical or expected range of values). Determine the
appropriate CO2 emission factor and HHV for use in Equation
C-2a of this subpart, as follows:
(A) Consider the blend to be the ``fuel type,'' measure its HHV at
the frequency prescribed in paragraph (a)(2)(v) of this section, and
determine the annual average HHV value for the blend according to Sec.
98.33(a)(2)(ii).
(B) Calculate a heat-weighted CO2 emission factor,
(EF)B, for the blend, using Equation C-16 of this section.
The heat-weighting in Equation C-16 is provided by the default HHVs
(from Table C-1) and the estimated mass or volume percentages of the
components of the blend.
(C) Substitute into Equation C-2a of this subpart, the annual
average HHV for the blend (from paragraph (a)(3)(ii)(A) of this
section) and the calculated value of (EF)B, along with the
total mass or volume of the blend combusted during the reporting year,
to determine the annual CO2 mass emissions from combustion
of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.005
Where:
(EF)B = Heat-weighted CO2 emission factor for
the blend (kg CO2/mmBtu)
(HHV)I = Default high heat value for fuel ``i'' in the
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel
``i'' (mass % or volume %, as applicable, expressed as a decimal
fraction; e.g., 25% = 0.25)
(EF)I = Default CO2 emission factor for fuel
``i'' from Table C-1 (mmBtu per mass or volume)
(HHV)B = Annual average high heat value for the blend,
calculated according to Sec. 98.33(a)(2)(ii) (mmBtu per mass or
volume)
(iii) Note that for the case described in paragraph (a)(3)(ii) of
this section, if measured HHV values for the individual fuels in the
blend or for the blend itself are not routinely received at the minimum
frequency prescribed in paragraph (a)(2) of this section (or at a
greater frequency), and if the unit qualifies to use Tier 1, calculate
(HHV)B*, the heat-weighted default HHV for the blend, using
Equation C-17 of this section. Then, use Equation C-16 of this section,
replacing the term (HHV)B with (HHV)B* in the
denominator, to determine the heat-weighted CO2 emission
factor for the blend. Finally, substitute into Equation C-1 of this
subpart, the calculated values of (HHV)B* and
(EF)B, along with the total mass or volume of the blend
combusted during the reporting year, to determine the annual
CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TP11AU10.006
Where:
(HHV)B* = Heat-weighted default high heat value for the
blend (mmBtu per mass or Volume)
(HHV)I = Default high heat value for fuel ``i'' in the
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)I = Estimated mass or volume percentage of fuel
``i'' in the blend (mass % or volume %, as applicable, expressed as
a decimal fraction)
(iv) If the fuel blend described in paragraph (a)(3)(ii) of this
section consists of a mixture of fuel(s) listed in Table C-1 of this
subpart and one or more fuels not listed in Table C-1, calculate
CO2 and other GHG emissions only for the Table C-1 fuel(s),
using the best available estimate of the mass or volume percentage(s)
of the Table C-1 fuel(s) in the blend. In this case, Tier 1 shall be
used, with the following modifications to Equations C-17 and C-1, to
account for the fact that not all of the fuels in the blend are listed
in Table C-1:
(A) In Equation C-17, apply the term (Fuel)i only to the
Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will be
the estimated mass or volume percentage of the fuel in the blend,
divided by the sum of the mass or volume percentages of the Table C-1
fuels. For example,
[[Page 48794]]
suppose that a blend consists of two Table C-1 fuels (``A'' and ``B'')
and one fuel type (``C'') not listed in the Table, and that the volume
percentages of fuels A, B, and C in the blend, expressed as decimal
fractions, are, respectively, 0.50, 0.30, and 0.20. The term
(Fuel)i in Equation C-17 for fuel A will be 0.50/(0.50 +
0.30) = 0.625, and for fuel B, (Fuel)i will be 0.30/(0.50 +
0.30) = 0.375.
(B) In Equation C-1, the term ``Fuel'' will be equal to the total
mass or volume of the blended fuel combusted during the year multiplied
by the sum of the mass or volume percentages of the Table C-1 fuels in
the blend. For the example in paragraph (a)(3)(iv)(A) of this section,
``Fuel'' = (Annual volume of the blend combusted) (0.80).
* * * * *
(6) You must use one of the following appropriate fuel sampling and
analysis methods. You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the high heat values.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International, the American National Standards
Institute (ANSI), the American Gas Association (AGA), the American
Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
Alternatively, for gaseous fuels, the HHV may be calculated using
chromatographic analysis together with standard heating values of the
fuel constituents, provided that the gas chromatograph is operated,
maintained, and calibrated according to the manufacturer's
instructions. The method(s) used shall be documented in the Monitoring
Plan required under Sec. 98.3(g)(5).
(b) * * *
(1) You must calibrate each oil and gas flow meter according to
Sec. 98.3(i) and the provisions of this paragraph (b)(1).
(i) Perform calibrations using any of the test methods and
procedures in this paragraph (b)(1)(i). The method(s) used shall be
documented in the Monitoring Plan required under Sec. 98.3(g)(5).
(A) You may use an appropriate flow meter calibration method
published by a consensus standards organization, if such a method
exists. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International, the American National
Standards Institute (ANSI), the American Gas Association (AGA), the
American Society of Mechanical Engineers (ASME), the American Petroleum
Institute (API), and the North American Energy Standards Board (NAESB).
(B) You may use the calibration procedures specified by the flow
meter manufacturer.
(C) You may use an industry-accepted or industry consensus standard
calibration practice.
(ii) In addition to the initial calibration required by Sec.
98.3(i), recalibrate each fuel flow meter (except as otherwise provided
in paragraph (b)(1)(iii) of this section) either annually, at the
minimum frequency specified by the manufacturer, or at the interval
specified by industry consensus standard practice.
(iii) Fuel billing meters are exempted from the initial and ongoing
calibration requirements of this paragraph and from the Monitoring Plan
and recordkeeping requirements of Sec. 98.3(g)(5)(i)(C) and (g)(7),
provided that the fuel supplier and the unit combusting the fuel do not
have any common owners and are not owned by subsidiaries or affiliates
of the same company. Meters used exclusively to measure the flow rates
of fuels that are only used for unit startup or ignition are also
exempted from the initial and ongoing calibration requirements of this
paragraph.
* * * * *
(vi) If a mixture of liquid or gaseous fuels is transported by a
common pipe, you may either separately meter each of the fuels prior to
mixing, using flow meters calibrated according to Sec. 98.3(i), or
consider the fuel mixture to be the ``fuel type'' and meter the mixed
fuel, using a flow meter calibrated according to Sec. 98.3(i).
* * * * *
(3) * * *
(ii) For each type of fuel, the minimum required frequency for
collecting and analyzing samples for carbon content and (if applicable)
molecular weight is specified in this paragraph. When the sampling
frequency is based on a specified time period (e.g., week, month,
quarter, or half-year), fuel sampling and analysis is required for only
those time periods in which the fuel is combusted.
(A) For natural gas, semiannual sampling and analysis is required
(i.e., twice in a calendar year, with consecutive samples taken at
least four months apart).
(B) For coal and fuel oil and for any other solid or liquid fuel
that is delivered in lots, analysis of at least one representative
sample from each fuel lot is required. For fuel oil, as an alternative
to sampling each fuel lot, a sample may be taken upon each addition of
oil to the storage tank. Flow proportional sampling, continuous drip
sampling, or daily manual oil sampling may also be used, in lieu of
sampling each fuel lot. For the purposes of this section, a fuel lot is
defined as either of the following:
(1) A shipment or delivery of a single fuel (e.g., ship load, barge
load, group of trucks, group of railroad cars, oil delivery via
pipeline from a tank farm, etc.).
(2) If multiple deliveries of a particular type of fuel are
received from the same supply source in a given calendar month, the
deliveries for that month are considered, collectively, to comprise a
fuel lot, requiring only one representative sample.
(C) For liquid fuels other than fuel oil and for biogas; sampling
and analysis is required at least once per calendar quarter. To the
extent practicable, consecutive quarterly samples shall be taken at
least 30 days apart.
(D) For other solid fuels (except MSW), weekly sampling is required
to obtain composite samples, which are then analyzed monthly.
(E) For gaseous fuels other than natural gas and biogas (e.g.,
process gas), daily sampling and analysis to determine the carbon
content and molecular weight of the fuel is required if continuous, on-
line equipment, such as a gas chromatograph, is in place to make these
measurements. Otherwise, weekly sampling and analysis shall be
performed.
(F) For mixtures (blends) of solid fuels, weekly sampling is
required to obtain composite samples, which are analyzed monthly. For
blends of liquid fuels, and for gas mixtures consisting only of natural
gas and biogas, sampling and analysis is required at least once per
calendar quarter. For gas mixtures that contain gases other than
natural gas (including biogas), daily sampling and analysis to
determine the carbon content and molecular weight of the fuel is
required if continuous, on-line equipment is in place to make these
measurements. Otherwise, weekly sampling and analysis shall be
performed.
* * * * *
(v) To calculate the CO2 mass emissions from combustion
of a blend of fuels in the same state of matter (solid, liquid, or
gas), you may either:
(A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable)
to each component of the blend, if the mass or volume, the carbon
content, and (if applicable), the molecular weight of each component
are accurately measured prior to blending; or
(B) Consider the blend to be the ``fuel type.'' Then, at the
frequency specified
[[Page 48795]]
in paragraph (b)(3)(ii)(F) of this section, measure the carbon content
and, if applicable, the molecular weight of the blend and calculate the
annual average value of each parameter in the manner described in Sec.
98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel
combusted during the reporting year. Substitute these measured values
into Equation C-3, C-4, or C-5 of this subpart (as applicable).
(4) You must use one of the following appropriate fuel sampling and
analysis methods. You may use a method published by a consensus
standards organization if such a method exists, or you may use industry
consensus standard practice to determine the carbon content and
molecular weight (for gaseous fuel) of the fuel. Consensus-based
standards organizations include, but are not limited to, the following:
ASTM International, the American National Standards Institute (ANSI),
the American Gas Association (AGA), the American Society of Mechanical
Engineers (ASME), the American Petroleum Institute (API), and the North
American Energy Standards Board (NAESB). Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions. The method(s) used shall be documented in
the Monitoring Plan required under Sec. 98.3(g)(5).
(c) For the Tier 4 Calculation Methodology, the CO2,
flow rate, and (if applicable) moisture monitors must be certified
prior to the applicable deadline specified in Sec. 98.33(b)(5).
(1) * * *
(i) Sections 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this
chapter 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 of this chapter (for the CO2 concentration monitor) and
Performance Specification 6 in appendix B to part 60 of this chapter
(for the continuous emission rate monitoring system (CERMS)).
* * * * *
(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 either 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 part 60 of this chapter is selected for on-going
quality assurance, perform daily calibration drift assessments for both
the CO2 monitor (or surrogate O2 monitor) and the
flow rate monitor, 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.
* * * * *
(6) For certain applications where combined process emissions and
combustion emissions are measured, the CO2 concentrations in
the flue gas may be considerably higher than for combustion emissions
alone. In such cases, the span of the CO2 monitor may, if
necessary, be set higher than the specified levels in the applicable
regulations. If the CO2 span value is set higher than 20
percent CO2, the cylinder gas audits of the CO2
monitor under appendix F to part 60 of this chapter may be performed at
40 to 60 percent and 80 to 100 percent of span, in lieu of the
prescribed calibration levels of 5 to 8 percent CO2 and 10
to 14 percent CO2.
(7) Hourly average data from the CEMS shall be validated in a
manner consistent with one of the following: Sec. Sec. 60.13(h)(2)(i)
through (h)(2)(vi) of this chapter; Sec. 75.10(d)(1) of this chapter;
or the hourly data validation requirements of an applicable State CEM
regulation.
(d) When municipal solid waste (MSW) is either the primary fuel
combusted in a unit or the only fuel with a biogenic component
combusted in the unit, determine the biogenic portion of the
CO2 emissions using ASTM D6866-08 Standard Test Methods for
Determining the Biobased Content of Solid, Liquid, and Gaseous Samples
Using Radiocarbon Analysis (incorporated by reference, see Sec. 98.7)
and ASTM D7459-08 Standard Practice for Collection of Integrated
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived
Carbon Dioxide Emitted from Stationary Emissions Sources (incorporated
by reference, see Sec. 98.7). Perform the ASTM D7459-08 sampling and
the ASTM D6866-08 analysis at least once in every calendar quarter in
which MSW is combusted in the unit. Collect each gas sample during
normal unit operating conditions for at least 24 consecutive hours or
for as long as is deemed necessary to obtain a representative sample.
One suggested alternative sampling approach would be to collect an
integrated sample by extracting a small amount of flue gas (e.g., 1 to
5 cc) in each unit operating hour during the quarter. Separate the
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions
of all samples analyzed during the reporting year. Express the results
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2
is biogenic). When MSW is the primary fuel for multiple units at the
facility, and the units are fed from a common fuel source, testing at
only one of the units is sufficient.
(e) For other units that combust combinations of biomass fuel(s)
(or heterogeneous fuels that have a biomass component, e.g., tires) and
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
08 and ASTM D7459-08 may be used to determine the biogenic portion of
the CO2 emissions. Perform the ASTM D7459-08 sampling and
the ASTM D6866-08 analysis in every calendar quarter in which biomass
and non-biogenic fuels are co-fired in the unit. Collect each gas
sample using ASTM D7459-08 during normal unit operation for at least 24
consecutive hours or for as long as is necessary to obtain a
representative sample. If the types of fuels combusted in the unit and
their relative proportions are not consistent throughout the quarter,
more frequent, periodic sampling of the flue gas should be considered.
For example, an integrated sample could be collected by extracting a
small amount of the flue gas (e.g., 1 to 5 cc) in each unit operating
hour of the quarter. If the primary fuel for multiple units at the
facility consists of tires, and the units are fed from a common fuel
source, testing at only one of the units is sufficient.
(f) The records required under Sec. 98.3(g)(2)(i) shall include an
explanation of how the following parameters are determined from company
records (or, if applicable, from the best available information):
(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation
Methodologies
[[Page 48796]]
are used, including cases where Sec. 98.36(c)(4) applies.
* * * * *
(3) Fossil fuel consumption when Sec. 98.33(e)(2) applies to a
unit that uses CEMS to quantify CO2 emissions and that
combusts both fossil and biomass fuels.
* * * * *
(5) Quantity of steam generated by a unit when Sec.
98.33(a)(2)(iii) applies.
* * * * *
(7) Fuel usage for CH4 and N2O emissions
calculations under Sec. 98.33(c)(4)(ii).
(8) Mass of biomass combusted, for premixed fuels that contain
biomass and fossil fuels under Sec. 98.33(e)(1)(iii).
11. Section 98.35 is amended by revising paragraph (a) to read as
follows:
Sec. 98.35 Procedures for estimating missing data.
* * * * *
(a) For all units subject to the requirements of the Acid Rain
Program, and all other stationary combustion units subject to the
requirements of this part that monitor and report emissions and heat
input data in accordance with part 75 of this chapter, the missing data
substitution procedures in part 75 of this chapter shall be followed
for CO2 concentration, stack gas flow rate, fuel flow rate,
high heating value, and fuel carbon content.
* * * * *
12. Section 98.36 is amended by:
a. Revising paragraph (b)(5).
b. Removing paragraphs (b)(9) and (b)(10).
c. Redesignating paragraphs (b)(6) through (b)(8) as paragraphs
(b)(8) through (b)(10), respectively.
d. Revising newly designated paragraphs (b)(8) and (b)(9).
e. Adding new paragraphs (b)(6) and (b)(7).
f. Revising paragraphs (c)(1)(ii), (c)(1)(vi), and (c)(1)(vii).
g. Redesignating paragraph (c)(1)(viii) as paragraph (c)(1)(x), and
revising newly designated paragraph (c)(1)(x).
h. Removing paragraph (c)(1)(ix).
i. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix).
j. Revising paragraphs (c)(2) introductory text, (c)(2)(ii),
(c)(2)(iii), and (c)(2)(v).
k. Removing paragraph (c)(2)(viii).
l. Redesignating paragraphs (c)(2)(vi) and (c)(2)(vii) as
paragraphs (c)(2)(viii) and (c)(2)(ix), and revising newly designated
paragraphs (c)(2)(viii) and (c)(2)(ix).
m. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii).
n. Revising paragraphs (c)(3) introductory text, (c)(3)(ii),
(c)(3)(iii), and (c)(3)(vii).
o. Removing paragraph (c)(3)(viii).
p. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), and (c)(4).
q. Revising paragraph (d).
r. Revising paragraphs (e)(1)(iii), (e)(2)(i), (e)(2)(ii)(C),
(e)(2)(ii)(D), (e)(2)(iii), and (e)(2)(iv)(A), (e)(2)(iv)(C).
s. Adding new paragraphs (e)(2)(iv)(F) and (e)(2)(v)(E).
t. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) introductory
text, and (e)(2)(x) introductory text.
u. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C).
v. Redesignating paragraph (e)(2)(x)(D) as (e)(2)(x)(B), and
revising newly designated paragraph (e)(2)(x)(B).
w. Revising paragraph (e)(2)(xi).
Sec. 98.36 Data reporting requirements.
* * * * *
(b) * * *
(5) The methodology (i.e., tier) used to calculate the
CO2 emissions for each type of fuel combusted (i.e., Tier 1,
2, 3, or 4).
(6) The methodology start date, for each fuel type.
(7) The methodology end date, for each fuel type.
(8) For a unit that uses Tiers 1, 2, or 3:
(i) The annual CO2 mass emissions (including biogenic
CO2), and the annual CH4, and N2O mass
emissions for each type of fuel combusted during the reporting year,
expressed in metric tons of each gas and in metric tons of
CO2e; and
(ii) Metric tons of biogenic CO2 emissions (if
applicable).
(9) For a unit that uses Tier 4:
(i) If the total annual CO2 mass emissions measured by
the CEMS consists entirely of non-biogenic CO2 (i.e.,
CO2 from fossil fuel combustion plus, if applicable,
CO2 from sorbent and/or process CO2), report the
total annual CO2 mass emissions, expressed in metric tons.
You are not required to report the combustion CO2 emissions
by fuel type.
(ii) If the total annual CO2 mass emissions measured by
the CEMS includes both biogenic and non-biogenic CO2,
separately report the annual non-biogenic CO2 mass emissions
and the annual CO2 mass emissions from biomass combustion,
each expressed in metric tons. You are not required to report the
combustion CO2 emissions by fuel type.
(iii) An estimate of the heat input from each type of fuel listed
in Table C-2 of this subpart that was combusted in the unit during the
report year, and the annual CH4 and N2O emissions
for each of these fuels, expressed in metric tons of each gas and in
metric tons of CO2e.
* * * * *
(c) * * *
(1) * * *
(ii) The number of units in the group.
* * * * *
(vi) Annual CO2 mass emissions and annual
CH4, and N2O mass emissions, aggregated for each
type of fuel combusted in the group of units during the report year,
expressed in metric tons of each gas and in metric tons of
CO2e. If any of the units burn both fossil fuels and
biomass, report also the annual CO2 emissions from
combustion of all fossil fuels combined and annual CO2
emissions from combustion of all biomass fuels combined, expressed in
metric tons.
(vii) The methodology (i.e., tier) used to calculate the
CO2 mass emissions for each type of fuel combusted in the
units (i.e., Tier 1, Tier 2, or Tier 3).
(viii) The methodology start date, for each fuel type.
(ix) The methodology end date, for each fuel type.
(x) The calculated CO2 mass emissions (if any) from
sorbent expressed in metric tons.
(2) Monitored common stack or duct configurations. When the flue
gases from two or more stationary fuel combustion units at a facility
are combined together in a common stack or duct before exiting to the
atmosphere and if CEMS are used to continuously monitor CO2
mass emissions at the common stack or duct according to the Tier 4
Calculation Methodology, you may report the combined emissions from the
units sharing the common stack or duct, in lieu of separately reporting
the GHG emissions from the individual units. This monitoring and
reporting alternative may also be used when process off-gases or a
mixture of combustion products and process gases are combined together
in a common stack or duct before exiting to the atmosphere. Whenever
the common stack or duct monitoring option is applied, the following
information shall be reported instead of the information in paragraph
(b) of this section:
* * * * *
(ii) Number of units sharing the common stack or duct. Report ``1''
when the flue gas flowing through the common stack or duct includes
both combustion products and process off-gases, and all of the effluent
comes from a single unit (e.g., a furnace, kiln, or smelter).
(iii) Combined maximum rated heat input capacity of the units
sharing the
[[Page 48797]]
common stack or duct (mmBtu/hr). This data element is required only
when all of the units sharing the common stack are stationary fuel
combustion units.
* * * * *
(v) The methodology (tier) used to calculate the CO2
mass emissions, i.e., Tier 4.
(vi) The methodology start date.
(vii) The methodology end date.
(viii) Total annual CO2 mass emissions measured by the
CEMS, expressed in metric tons. If any of the units burn both fossil
fuels and biomass, separately report the annual non-biogenic
CO2 mass emissions (i.e., CO2 from fossil fuel
combustion plus, if applicable, CO2 from sorbent and/or
process CO2) and the annual CO2 mass emissions
from biomass combustion, each expressed in metric tons.
(ix) An estimate of the heat input from each type of fuel listed in
Table C-2 of this subpart that was combusted during the report year in
the units sharing the common stack or duct during the report year, and,
for each of these fuels, the annual CH4 and N2O
mass emissions from the units sharing the common stack or duct,
expressed in metric tons of each gas and in metric tons of
CO2e.
(3) Common pipe configurations. When two or more liquid-fired or
gaseous-fired stationary combustion units at a facility combust the
same type of fuel and the fuel is fed to the individual units through a
common supply line or pipe, you may report the combined emissions from
the units served by the common supply line, in lieu of separately
reporting 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 fuel flow meter. For Tier 3
applications, the flow meter shall be calibrated in accordance with
Sec. 98.34(b). If a portion of the fuel measured at the main supply
line is diverted to either: A flare; or another stationary fuel
combustion unit (or units), including units that use a CO2
mass emissions calculation method in part 75 of this chapter; or a
chemical or industrial process (where it is used as a raw material but
not combusted), and the remainder of the fuel is distributed to a group
of combustion units for which you elect to use the common pipe
reporting option, you may use company records to subtract out the
diverted portion of the fuel from the fuel measured at the main supply
line prior to performing the GHG emissions calculations for the group
of units using the common pipe option. If the diverted portion of the
fuel is combusted, the GHG emissions from the diverted portion shall be
accounted for in accordance with the applicable provisions of this
part. When the common pipe option is selected, the applicable tier
shall be used based on the maximum rated heat input capacity of the
largest unit served by the common pipe configuration, except where the
applicable tier is based on criteria other than unit size. For example,
if the maximum rated heat input capacity of the largest unit is greater
than 250 mmBtu/hr, Tier 3 will apply, unless the fuel transported
through the common pipe is natural gas or distillate oil, in which case
Tier 2 may be used, in accordance with Sec. 98.33(b)(2)(ii). As a
second example, in accordance with Sec. 98.33(b)(1)(v), Tier 1 may be
used regardless of unit size when natural gas is transported through
the common pipe, if the annual fuel consumption is obtained from gas
billing records in units of therms. When the common pipe reporting
option is selected, the following information shall be reported instead
of the information in paragraph (b) of this section:
* * * * *
(ii) The number of units served by the common pipe.
(iii) The highest maximum rated heat input capacity of any unit
served by the common pipe (mmBtu/hr).
* * * * *
(vii) Annual CO2 mass emissions and annual
CH4 and N2O emissions from each fuel type for the
units served by the common pipe, expressed in metric tons of each gas
and in metric tons of CO2e.
(viii) Methodology start date.
(ix) Methodology end date.
(4) The following alternative reporting option applies to
situations where a common liquid or gaseous fuel supply is shared
between one or more large combustion units, such as boilers or
combustion turbines (including units subject to subpart D of this
part); and small combustion sources on-site, including but not limited
to space heaters and hot water heaters. In this case, you may simplify
reporting by attributing all of the GHG emissions from combustion of
the shared fuel to the large combustion unit(s), provided that:
(i) The total quantity of the fuel combusted during the report year
in the units sharing the fuel supply is measured, either at the
``gate'' to the facility or at a point inside the facility, using a
fuel flow meter, billing meter, or tank drop measurements (as
applicable);
(ii) On an annual basis, at least 95 percent (by mass or volume) of
the shared fuel is combusted in the large combustion unit(s), and the
remainder is combusted in the small combustion sources. Company records
may be used to determine the percentage distribution of the shared fuel
to the large and small units; and
(iii) The use of this reporting option is documented in the
Monitoring Plan required under Sec. 98.3(g)(5). Indicate in the
Monitoring Plan which units share the common fuel supply and the method
used to demonstrate that this alternative reporting option applies. For
the small combustion sources on-site, a description of the types of
units and the approximate number of units is sufficient.
(d) Units subject to part 75 of this chapter.
(1) For stationary combustion units that are subject to subpart D
of this part, you shall report the following unit-level information:
(i) Unit or stack identification numbers. Use exact same unit,
common stack, common pipe, or multiple stack identification numbers
that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001,
etc.) that are reported under Sec. 75.64 of this chapter.
(ii) Annual CO2 emissions at each monitored location,
expressed in both short tons and metric tons. Reporting of biogenic
CO2 emissions under Sec. 98.3(c)(4)(ii) and Sec.
98.3(c)(4)(iii)(A) is optional. Subpart D units are not required to
report biogenic CO2 emissions under Sec. Sec.
98.3(c)(4)(ii) and (c)(4)(iii)(A).
(iii) Annual CH4 and N2O emissions at each
monitored location, for each fuel type listed in Table C-2 that was
combusted during the year (except as otherwise provided in Sec.
98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
(iv) The total heat input from each fuel listed in Table C-2 that
was combusted during the year (except as otherwise provided in Sec.
98.33(c)(4)(ii)(B)), expressed in mmBtu.
(v) Identification of the Part 75 methodology used to determine the
CO2 mass emissions.
(vi) Methodology start date.
(vii) Methodology end date.
(viii) Acid Rain Program indicator.
(ix) Annual CO2 mass emissions from the combustion of
biomass, expressed in metric tons of CO2e (optional).
(2) For units that use the alternative CO2 mass
emissions calculation methods provided in Sec. 98.33(a)(5), you shall
report the following unit-level information:
(i) Unit, stack, or pipe ID numbers. Use exact same unit, common
stack,
[[Page 48798]]
common pipe, or multiple stack identification numbers that represent
the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are
reported under Sec. 75.64 of this chapter.
(ii) For units that use the alternative methods specified in Sec.
98.33(a)(5)(i) and (ii) to monitor and report heat input data year-
round according to appendix D to part 75 of this chapter or Sec. 75.19
of this chapter:
(A) Each type of fuel combusted in the unit during the reporting
year.
(B) The methodology used to calculate the CO2 mass
emissions for each fuel type.
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate whether heat input is calculated
according to appendix D to part 75 of this chapter or Sec. 75.19 of
this chapter.
(F) Annual CO2 emissions at each monitored location,
across all fuel types, expressed in metric tons of CO2e.
(G) Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.
(H) Annual CH4 and N2O emisions at each
monitored location, from each fuel type listed in Table C-2 of this
subpart that was combusted during the reporting year (except as
otherwise provided in Sec. 98.33(c)(4)(ii)(D)), expressed in metric
tons CO2e.
(I) Annual CO2 mass emissions from the combustion of
biomass, expressed in metric tons CO2e (optional).
(iii) For units with continuous monitoring systems that use the
alternative method for units with continuous monitoring systems in
Sec. 98.33(a)(5)(iii) to monitor heat input year-round according to
part 75 of this chapter:
(A) Each type of fuel combusted during the reporting year.
(B) Methodology used to calculate the CO2 mass
emissions.
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate that the heat input data is derived
from CEMS measurements.
(F) The total annual CO2 emissions at each monitored
location, expressed in metric tons of CO2e.
(G) Annual heat input from each type of fuel listed in Table C-2 of
this subpart that was combusted during the reporting year, expressed in
mmBtu.
(H) Annual CH4 and N2O emisions at each
monitored location, from each fuel type listed in Table C-2 of this
subpart that was combusted during the reporting year (except as
otherwise provided in Sec. 98.33(c)(4)(ii)(B)), expressed in metric
tons CO2e.
(I) Annual CO2 mass emissions from the combustion of
biomass, expressed in metric tons CO2e (optional).
(e) * * *
(1) * * *
(iii) Are not in the Acid Rain Program, but are required to monitor
and report CO2 mass emissions and heat input data year-
round, in accordance with part 75 of this chapter.
(2) * * *
(i) For the Tier 1 Calculation Methodology, report the total
quantity of each type of fuel combusted in the unit or group of
aggregated units (as applicable) during the reporting year, in short
tons for solid fuels, gallons for liquid fuels and standard cubic feet
or, if applicable, therms for gaseous fuels.
(ii) * * *
(C) The high heat values used in the CO2 emissions
calculations for each type of fuel combusted during the reporting year,
in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid
fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each
calendar month in which HHV determination is required. If multiple
values are obtained in a given month, report the arithmetic average
value for the month. Indicate whether each reported HHV is a measured
value or a substitute data value.
(D) If Equation C-2c of this subpart is used to calculate
CO2 mass emissions, report the total quantity (i.e., pounds)
of steam produced from MSW or solid fuel combustion during each month
of the reporting year, and the ratio of the maximum rate heat input
capacity to the design rated steam output capacity of the unit, in
mmBtu per lb of steam.
(iii) For the Tier 2 Calculation Methodology, keep records of the
methods used to determine the HHV for each type of fuel combusted and
the date on which each fuel sample was taken, except where fuel
sampling data are received from the fuel supplier. In that case, keep
records of the dates on which the results of the fuel analyses for HHV
are received.
(iv) * * *
(A) The quantity of each type of fuel combusted in the unit or
group of units (as applicable) during each month of the reporting year,
in short tons for solid fuels, gallons for liquid fuels, and scf for
gaseous fuels.
* * * * *
(C) The carbon content and, if applicable, gas molecular weight
values used in the emission calculations (including both valid and
substitute data values). For each calendar month of the reporting year
in which carbon content and, if applicable, molecular weight
determination is required, report a value of each parameter. If
multiple values of a parameter are obtained in a given month, report
the arithmetic average value for the month. Express carbon content as a
decimal fraction for solid fuels, kg C per gallon for liquid fuels, and
kg C per kg of fuel for gaseous fuels. Express the gas molecular
weights in units of kg per kg-mole.
* * * * *
(F) The annual average HHV, when measured HHV data, rather than a
default HHV from Table C-1 of this subpart, are used to calculate
CH4 and N2O emissions for a Tier 3 unit, in
accordance with Sec. 98.33(c)(1).
(v) * * *
(E) The date on which each fuel sample was taken, except where fuel
sampling data are received from the fuel supplier. In that case, keep
records of the dates on which the results of the fuel analyses for
carbon content and (if applicable) molecular weight are received.
* * * * *
(vii) * * *
(A) 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 were used.
* * * * *
(ix) For units that combust both fossil fuel and biomass, when
biogenic CO2 is determined according to Sec. 98.33(e)(2),
you shall report the following additional information, as applicable:
* * * * *
(x) When ASTM methods D7459-08 and D6866-08 are used to determine
the biogenic portion of the annual CO2 emissions from MSW
combustion, as described in Sec. 98.34(d), report:
* * * * *
(B) The annual biogenic CO2 mass emissions from MSW
combustion, in metric tons.
(xi) When ASTM methods D7459-08 and D6866-08 are used in accordance
with Sec. 98.34(e) to determine the biogenic portion of the annual
CO2 emissions from a unit that co-fires biogenic fuels (or
partly-biogenic fuels, including tires if you are electing to report
biogenic CO2 emissions from tire combustion) and non-
biogenic fuels, you shall report the results of each quarterly sample
analysis, expressed as a decimal fraction (e.g., if the biogenic
fraction of the CO2 emissions is 30 percent, report 0.30).
* * * * *
13. Table C-1 of Supart C of Part 98 is amended by:
[[Page 48799]]
a. Revising the title to read ``Table C-1 to Subpart C--Default
CO2 Emission Factors and High Heat Values for Various Types
of Fuel.''
b. Revising the entry for ``Pipeline (Weighted U.S. Average).''
c. Removing the entry for ``Still Gas.''
d. Adding an entry for ``Waste Oil'' to follow the entry for
``Residual Fuel Oil No. 6.''
e. Adding an entry for ``Ethanol'' to follow the entry for
``Ethane.''
f. Revising the entry for ``Fossil fuel-derived fuels (solid).''
g. Revising the entry for ``Municipal Solid Waste.''
h. Adding entries for ``Plastics'' and ``Petroleum Coke'' to follow
the entry for ``Tires.''
i. Revising the entry for ``Fossil fuel-derived fuels (gaseous).''
j. Adding entries for ``Propane Gas'' and ``Fuel Gas'' to follow
the entry for ``Coke Oven Gas.''
k. Revising the entry for ``Biomass fuels--solid.''
l. Revising the entry for ``Biomass fuels--liquid'' by centering
``Biomass fuels--liquid.''
m. Revising the entries for ``Ethanol'' and ``Biodiesel'' that
follow the entry for ``Biomass fuels--liquid.''
n. Revising footnote ``1.''
o. Adding a new footnote ``2.''
Table C-1 to Subpart C--Default CO2 Emission Factors and High Heat
Values for Various Types of Fuel
------------------------------------------------------------------------
Default high heat Default CO2 emission
Fuel type value factor
------------------------------------------------------------------------
* * * * * * *
(Weighted U.S. Average)....... 1.028 x 10-3..... 53.02.
* * * * * * *
Waste Oil..................... 0.135............ 74.00.
* * * * * * *
Ethanol....................... 0.084............ 68.44.
* * * * * * *
Other fuels (solid)........... mmBtu/short ton.. kg CO2/mmBtu.
Municipal Solid Waste......... 9.95 \1\......... 90.7.
* * * * * * *
Plastics...................... 38.00............ 75.00.
Petroleum Coke................ 30.00............ 102.41.
Other fuels (gaseous)......... mmBtu/scf........ kg CO2/mmBtu.
* * * * * * *
Propane Gas................... 2.516 x 10-3..... 61.46.
Fuel Gas \2\.................. 1.388 x 10-3..... 59.00.
Biomass fuels--solid.......... mmBtu/short ton.. kg CO2/mmBtu.
* * * * * * *
Ethanol....................... 0.084............ 68.44.
Biodiesel..................... 0.128............ 73.84.
* * * * * * *
------------------------------------------------------------------------
\1\ Use of this default HHV is allowed only for units that combust MSW,
do not generate steam, and are allowed to use Tier 1.
\2\ Reporters subject to subpart X of this part that are complying with
Sec. 98.243(d) or subpart Y of this part may only use the default
HHV and the default CO2 emission factor for fuel gas combustion under
the conditions prescribed in Sec. 98.243(d)(2)(i) and (d)(2)(ii) and
Sec. 98.252(a)(1) and (a)(2), respectively. Otherwise, Tier 3
(Equation C-5) or Tier 4 must be used.
14. The first Table C-2 is removed, and the second Table C-2 is
revised to read as follows:
Table C-2 to Subpart C--Default CH4 and N2O Emission Factors for Various Types of Fuel
----------------------------------------------------------------------------------------------------------------
Default CH4 emission Default N2O emission
Fuel type factor (kg CH4/mmBtu) factor (kg N2O/mmBtu)
----------------------------------------------------------------------------------------------------------------
Coal and Coke (All fuel types in Table C-1)................... 1.1 x 10-02 1.6 x 10-03
Natural Gas................................................... 1.0 x 10-03 1.0 x 10-04
Petroleum (All fuel types in Table C-1)....................... 3.0 x 10-03 6.0 x 10-04
Municipal Solid Waste......................................... 3.2 x 10-02 4.2 x 10-03
Tires......................................................... 3.2 x 10-02 4.2 x 10-03
Blast Furnace Gas............................................. 2.2 x 10-05 1.0 x 10-04
Coke Oven Gas................................................. 4.8 x 10-04 1.0 x 10-04
Biomass Fuels--Solid (All fuel types in Table C-1)............ 3.2 x 10-02 4.2 x 10-03
Biogas........................................................ 3.2 x 10-03 6.3 x 10-04
[[Page 48800]]
Biomass Fuels--Liquid (All fuel types in Table C-1)........... 1.1 x 10-03 1.1 x 10-04
----------------------------------------------------------------------------------------------------------------
Note: 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--[Amended]
15. Section 98.40 is amended by revising paragraph (a) to read as
follows:
Sec. 98.40 Definition of the source category.
(a) The electricity generation source category comprises
electricity generating units that are subject to the requirements of
the Acid Rain Program and any other electricity generating units that
are required to monitor and report to EPA CO2 mass emissions
year-round according to 40 CFR part 75.
* * * * *
16. Section 98.46 is revised to read as follows:
Sec. 98.46 Data reporting requirements.
The annual report shall comply with the data reporting requirements
specified in Sec. 98.36(d)(1).
17. Section 98.47 is revised to read as follows:
Sec. 98.47 Records that must be retained.
You shall comply with the recordkeeping requirements of Sec. Sec.
98.3(g) and 98.37. Records retained under Sec. 75.57(h) of this
chapter for missing data events satisfy the recordkeeping requirements
of Sec. 98.3(g)(4) for those same events.
Subpart F--[Amended]
18. Section 98.62 is amended by revising paragraphs (a) and (b) to
read as follows:
Sec. 98.62 GHGs to report.
* * * * *
(a) Perfluoromethane (CF4), and perfluoroethane
(C2F6) emissions from anode effects in all
prebake and S[oslash]derberg electrolysis cells.
(b) CO2 emissions from anode consumption during
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
* * * * *
19. Section 98.63 is amended by:
a. In paragraph (a), revising the only sentence and the definitions
of ``EPFC,'' and ``Em'' in Equation F-1.
b. Revising the only sentence of paragraph (b).
c. Revising paragraph (c).
Sec. 98.63 Calculating GHG emissions.
(a) The annual value of each PFC compound (CF4,
C2F6) shall be estimated from the sum of monthly
values using Equation F-1 of this section:
* * * * *
EPFC = Annual emissions of each PFC compound from aluminum
production (metric tons PFC).
Em = Emissions of the individual PFC compound from aluminum
production for the month ``m'' (metric tons PFC).
(b) Use Equation F-2 of this section to estimate CF4
emissions from anode effect duration or Equation F-3 of this section to
estimate CF4 emissions from overvoltage, and use Equation F-
4 of this section to estimate C2F6 emissions from
anode effects from each prebake and S[oslash]derberg electrolysis cell.
* * * * *
(c) You must calculate and report the annual process CO2
emissions from anode consumption during electrolysis and anode baking
of prebake cells using either the procedures in paragraph (d) of this
section, the procedures in paragraphs (e) and (f) of this section, or
the procedures in paragraph (g) of this section.
* * * * *
20. Section 98.64 is amended by revising the first sentence of
paragraph (a); and by revising paragraph (b) to read as follows:
Sec. 98.64 Monitoring and QA/QC requirements.
(a) Effective one year after publication of the rule for smelters
with no prior measurement or effective three years after publication
for facilities with historic measurements, the smelter-specific slope
coefficients, overvoltage emission factors, and weight fractions used
in Equations F-2, F-3, and F-4 of this subpart must be measured in
accordance with the recommendations of the EPA/IAI Protocol for
Measurement of Tetrafluoromethane (CF4) and Hexafluoroethane
(C2F6) Emissions from Primary Aluminum Production
(2008), except the minimum frequency of measurement shall be every 10
years unless a change occurs in the control algorithm that affects the
mix of types of anode effects or the nature of the anode effect
termination routine. * * *
(b) The minimum frequency of the measurement and analysis is
annually except as follows:
(1) Monthly for anode effect minutes per cell day (or anode effect
overvoltage and current efficiency).
(2) Monthly for aluminum production.
(3) Smelter-specific slope coefficients, overvoltage emission
factors, and weight fractions according to paragraph (a) of this
section.
* * * * *
21. Section 98.65 is amended by revising the only sentence of
paragraph (a) to read as follows:
Sec. 98.65 Procedures for estimating missing data.
* * * * *
(a) Where anode or paste consumption data are missing,
CO2 emissions can be estimated from aluminum production per
Equation F-8 of this section.
* * * * *
22. Section 98.66 is amended by revising paragraph (c)(1) to read
as follows:
Sec. 98.66 Data reporting requirements.
* * * * *
(c) * * *
(1) Perfluoromethane emissions and perfluoroethane emissions from
anode effects in all prebake and all S[oslash]derberg electrolysis
cells combined.
* * * * *
23. In the table to Supart F of Part 98, revise Table F-1 to read
as follows:
[[Page 48801]]
Table F-1 to Subpart F--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions from Aluminum
Production
----------------------------------------------------------------------------------------------------------------
CF4 slope
coefficient [(kg CF4 overvoltage Weight fraction
Technology CF4/metric ton Al)/ coefficient [(kg C2F6/CF4 [(kg C2F6/
(AE-Mins/cell- CF4/metric ton Al)/ kg CF4)]
day)] (mV)]
----------------------------------------------------------------------------------------------------------------
Center Worked Prebake (CWPB)........................ 0.143 1.16 0.121
Side Worked Prebake (SWPB).......................... 0.272 3.65 0.252
Vertical Stud S[oslash]derberg (VSS)................ 0.092 NA 0.053
Horizontal Stud S[oslash]derberg (HSS).............. 0.099 NA 0.085
----------------------------------------------------------------------------------------------------------------
24. Table F-2 is amended by revising the entry for ``CO2
Emissions from Pitch Volatiles Combustion (VSS and HSS)'' to read as
follows:
Table F-2 to Subpart F--Default Data Sources for Parameters Used for CO2
Emissions
------------------------------------------------------------------------
Parameter Data source
------------------------------------------------------------------------
CO2 Emissions from Prebake Cells (CWPB and SWPB)
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
CO2 Emissions from Pitch Volatiles Combustion (CWPB and SWPB)
------------------------------------------------------------------------
* * * * * * *
------------------------------------------------------------------------
Subpart G--[Amended]
25. Section 98.72 is amended by revising paragraphs (a) and (b) to
read as follows:
Sec. 98.72 GHGs to report.
* * * * *
(a) CO2 process emissions from steam reforming of a
hydrocarbon or the gasification of solid and liquid raw material,
reported for each ammonia manufacturing process unit following the
requirements of this subpart (CO2 process emissions reported
under this subpart may include CO2 that is later consumed
on-site for urea production, and therefore is not released to the
ambient air from the ammonia manufacturing process unit).
(b) CO2, CH4, and N2O emissions
from each stationary fuel combustion unit. You must report these
emissions under subpart C of this part (General Stationary Fuel
Combustion Sources), by following the requirements of subpart C, except
that for ammonia manufacturing processes subpart C does not apply to
any CO2 resulting from combustion of the waste recycle
stream (commonly referred to as the purge gas stream).
* * * * *
26. Section 98.73 is amended by:
a. Revising paragraph (b) introductory text.
b. Revising the definition of ``CO2,G'' in Equation G-1
of paragraph (b)(1).
c. Revising the definition of ``CO2,L'' in Equation G-2
of paragraph (b)(2).
d. Revising the definition of ``CO2,S'' in Equation G-3
of paragraph (b)(3).
e. Revising the definition of ``CO2'' in Equation G-5 of
paragraph (b)(5).
f. Removing paragraph (b)(6).
Sec. 98.73 Calculating GHG emissions.
* * * * *
(b) Calculate and report under this subpart process CO2
emissions using the procedures in paragraphs (b)(1) through (b)(5) of
this section for gaseous feedstock, liquid feedstock, or solid
feedstock, as applicable.
(1) * * *
CO2,G,k = Annual CO2 emissions arising from
gaseous feedstock consumption (metric tons).
* * * * *
(2) * * *
CO2,L,k = Annual CO2 emissions arising from
liquid feedstock consumption (metric tons).
* * * * *
(3) * * *
CO2,S,k = Annual CO2 emissions arising from
solid feedstock consumption (metric tons).
* * * * *
(5) * * *
CO2 = Annual combined CO2 emissions from all
ammonia processing units (metric tons) (CO2 process
emissions reported under this subpart may include CO2
that is later consumed on-site for urea production, and therefore is
not released to the ambient air from the ammonia manufacturing
process unit(s)).
* * * * *
27. Section 98.74 is amended by revising paragraph (d) and by
removing and reserving paragraph (f) to read as follows:
Sec. 98.74 Monitoring and QA/QC requirements.
* * * * *
(d) Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes and flow rates (except for gas
billing meters) according to the monitoring and QA/QC requirements for
the Tier 3 methodology in Sec. 98.34(b)(1). Perform oil tank drop
measurements (if used to quantify feedstock volumes) according to Sec.
98.34(b)(2).
* * * * *
28. Section 98.75 is amended by revising the first sentence of
paragraph (a); and by revising paragraph (b) to read as follows:
Sec. 98.75 Procedures for estimating missing data.
* * * * *
(a) For missing data on monthly carbon contents of feedstock, the
substitute data value shall be the arithmetic average of the quality-
assured values of that carbon content in the month preceding and the
month immediately following the missing data incident. * * *
[[Page 48802]]
(b) For missing feedstock supply rates used to determine monthly
feedstock consumption, you must determine the best available
estimate(s) of the parameter(s), based on all available process data.
29. Section 98.76 is amended by:
a. Revising paragraphs (a) introductory text and (b)(6).
b. Removing paragraphs (b)(12) through (b)(15).
c. Redesignating paragraph (b)(16) as paragraph (b)(12).
c. Adding a new paragraph (b)(13).
d. Removing paragraphs (b)(17) and (c).
Sec. 98.76 Data reporting requirements.
* * * * *
(a) If a CEMS is used to measure CO2 emissions, then you
must report the relevant information required under Sec. 98.36 for the
Tier 4 Calculation Methodology and the following information in this
paragraph (a):
* * * * *
(b) * * *
(6) Sampling analysis results of carbon content of feedstock as
determined for QA/QC of supplier data under Sec. 98.74(e).
* * * * *
(12) Annual urea production (metric tons) and method used to
determine urea production.
(13) CO2 from the steam reforming of a hydrocarbon or
the gasification of solid and liquid raw material at the ammonia
manufacturing process unit used to produce urea and the method used to
determine the CO2 consumed in urea production.
Subpart P--[Amended]
30. Section 98.164 is amended by revising paragraph (b)(1) to read
as follows:
Sec. 98.164 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(1) Calibrate all oil and gas flow meters that are used to measure
liquid and gaseous feedstock volumes (except for gas billing meters)
according to the monitoring and QA/QC requirements for the Tier 3
methodology in Sec. 98.34(b)(1). Perform oil tank drop measurements
(if used to quantify liquid fuel or feedstock consumption) according to
Sec. 98.34(b)(2). Calibrate all solids weighing equipment according to
the procedures in Sec. 98.3(i).
* * * * *
Subpart V--[Amended]
31. Section 98.226 is amended by removing paragraph (o).
Subpart X--[Amended]
32. Section 98.240 is amended by revising paragraph (a); and by
adding paragraph (g) to read as follows:
Sec. 98.240 Definition of the source category.
(a) The petrochemical production source category consists of all
processes that produce acrylonitrile, carbon black, ethylene, ethylene
dichloride, ethylene oxide, or methanol, except as specified in
paragraphs (b) through (g) of this section. The source category
includes processes that produce the petrochemical as an intermediate in
the onsite production of other chemicals as well as processes that
produce the petrochemical as an end product for sale or shipment
offsite.
* * * * *
(g) A process that solely distills or recycles waste solvent that
contains a petrochemical is not part of the petrochemical production
source category.
33. Section 98.242 is amended by revising paragraph (a)(1) and
paragraph (b) introductory text to read as follows:
Sec. 98.242 GHGs to report.
* * * * *
(a) * * *
(1) If you comply with Sec. 98.243(b) or (d), report under this
subpart the calculated CO2, CH4, and
N2O emissions for each stationary combustion source and
flare that burns any amount of petrochemical process off-gas. If you
comply with Sec. 98.243(b), also report under this subpart the
measured CO2 emissions from process vents routed to stacks
that are not associated with stationary combustion units.
* * * * *
(b) CO2, CH4, and N2O combustion
emissions from stationary combustion units.
* * * * *
34. Section 98.243 is amended by:
a. Revising the second sentence of paragraph (b).
b. Revising the definition of ``MVC'' in Equation X-1 in paragraph
(c)(5)(i).
c. Revising paragraph (d).
Sec. 98.243 Calculating GHG emissions.
* * * * *
(b) * * * For each stack (except flare stacks) that includes
emissions from combustion of petrochemical process off-gas, calculate
CH4 and N2O emissions in accordance with subpart
C of this part (use the Tier 3 methodology, emission factors for
``Petroleum'' in Table C-2 of subpart C of this part, and either the
default high heat value for fuel gas in Table C-1 of subpart C of this
part or a calculated HHV, as allowed in Equation C-8 of subpart C of
this part). * * *
(c) * * *
(5) * * *
(i) * * *
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68
[deg]F and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole
at 60 [deg]F and 14.7 pounds per square inch absolute).
* * * * *
(d) Optional combustion methodology for ethylene production
processes. For each ethylene production process, calculate GHG
emissions from each combustion unit that burns fuel that contains any
off-gas from the ethylene process as specified in paragraphs (d)(1)
through (d)(5) of this section.
(1) Except as specified in paragraphs (d)(2) and (d)(5) of this
section, calculate CO2 emissions using the Tier 3 or Tier 4
methodology in subpart C of this part.
(2) You may use either Equation C-1 or Equation C-2a in subpart C
of this part to calculate CO2 emissions from combustion of
any ethylene process off-gas streams that meet either of the conditions
in paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default
values in the calculation, use the defaults for fuel gas in Table C-1
of subpart C of this part). Follow the otherwise applicable procedures
in subpart C to calculate emissions from combustion of all other fuels
in the combustion unit.
(i) The annual average flow rate of fuel gas (that contains
ethylene process off-gas) in the fuel gas line to the combustion unit,
prior to any split to individual burners or ports, does not exceed 345
standard cubic feet per minute at 60[deg]F and 14.7 pounds per square
inch absolute, and a flow meter is not installed at any point in the
line supplying fuel gas or an upstream common pipe. Calculate the
annual average flow rate using company records assuming total flow is
evenly distributed over 525,600 minutes per year.
(ii) The combustion unit has a maximum rated heat input capacity of
less than 30 MMBtu/hr, and a flow meter is not installed at any point
in the line supplying fuel gas (that contains ethylene process off-gas)
or an upstream common pipe.
(3) Except as specified in paragraph (d)(5) of this section,
calculate CH4 and N2O emissions using the
applicable procedures in Sec. 98.33(c) for the same tier methodology
that you used for calculating CO2 emissions.
(i) For all gaseous fuels that contain ethylene process off-gas,
use the emission factors for ``Petroleum'' in Table C-2 of subpart C of
this part
[[Page 48803]]
(General Stationary Fuel Combustion Sources).
(ii) For Tier 3, use either the default high heat value for fuel
gas in Table C-1 of subpart C of this part or a calculated HHV, as
allowed in Equation C-8 of subpart C of this part.
(4) You are not required to use the same Tier for each stationary
combustion unit that burns ethylene process off-gas.
(5) For each flare, calculate CO2, CH4, and
N2O emissions using the methodology specified in Sec.
98.253(b)(1) through (b)(3).
35. Section 98.244 is amended by revising paragraphs (b)(1) through
(b)(3) and (b)(4) introductory text; and by adding paragraphs
(b)(4)(xi) through (b)(4)(xiii) to read as follows:
Sec. 98.244 Monitoring and QA/QC requirements.
* * * * *
(b) * * *
(1) Operate, maintain, and calibrate belt scales or other weighing
devices as described in Specifications, Tolerances, and Other Technical
Requirements For Weighing and Measuring Devices NIST Handbook 44 (2009)
(incorporated by reference, see Sec. 98.7), or follow procedures
specified by the measurement device manufacturer. You must recalibrate
each weighing device according to one of the following frequencies. You
may recalibrate either biennially (i.e., once every two years) or at
the minimum frequency specified by the manufacturer.
(2) Operate and maintain all flow meters used for gas and liquid
feedstocks and products according to the manufacturer's recommended
procedures. You must calibrate each of these flow meters according to
one of the following. You may use either an industry consensus standard
method or methods specified by the flow meter manufacturer. Each flow
meter must meet the applicable accuracy specification in Sec. 98.3(i),
except as otherwise specified in Sec. 98.3(i)(4) through (i)(6). You
must recalibrate each flow meter according to one of the following
frequencies. You may recalibrate either biennially, at the minimum
frequency specified by the manufacturer, or at the interval specified
by the industry consensus standard practice used.
(3) You must perform tank level measurements (if used to determine
feedstock or product flows) according to one of the following methods.
You may use any standard method published by a consensus-based
standards organization (e.g., ASTM, API, etc.) or you may use industry
standard practice.
(4) Use any applicable methods specified in paragraphs (b)(4)(i)
through (b)(4)(xiii) of this section to determine the carbon content or
composition of feedstocks and products and the average molecular weight
of gaseous feedstocks and products. Calibrate instruments in accordance
with paragraphs (b)(4)(i) through (b)(4)(xiii), as applicable. 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 monthly period. For carbon
black products, samples shall be taken of each grade or type of product
produced during the monthly period. Samples of coal feedstock or carbon
black product for carbon content determinations may be either grab
samples collected and analyzed monthly or a composite of samples
collected more frequently and analyzed monthly. Analyses conducted in
accordance with methods specified in paragraphs (b)(4)(i) through
(b)(4)(xiii) of this section may be performed by the owner or operator,
by an independent laboratory, or by the supplier of a feedstock.
* * * * *
(xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography,
(incorporated by reference, see Sec. 98.7), effective as of January 1,
2010.
(xii) An industry standard practice for carbon black feedstock oils
and carbon black products, effective as of January 1, 2010.
(xiii) Modifications of existing analytical methods or other
analytical methods that are applicable to your process provided that
the methods listed in Sec. 98.244(b)(4)(i) through Sec.
98.244(b)(4)(xii) are not appropriate because the relevant compounds
cannot be detected, the quality control requirements are not
technically feasible, or use of the method would be unsafe, effective
as of January 1, 2010.
36. Section 98.246 is amended by:
a. Revising paragraphs (a) introductory text and (a)(4).
b. Removing and reserving paragraph (a)(7).
c. Revising paragraph (a)(10).
d. Adding paragraph (a)(11).
e. Revising paragraphs (b) introductory text, and (b)(1) through
(b)(5).
f. Revising paragraph (c).
Sec. 98.246 Data reporting requirements.
* * * * *
(a) If you use the mass balance methodology in Sec. 98.243(c), you
must report the information specified in paragraphs (a)(1) through
(a)(11) of this section for each type of petrochemical produced,
reported by process unit.
* * * * *
(4) Each of the monthly volume, mass, and carbon content values
used in Equations X-1 through X-3 of this subpart (i.e., the directly
measured values, substitute values, or the calculated values based on
other measured data such as tank levels or gas composition) and the
molecular weights for gaseous feedstocks and products used in Equation
X-1 of this subpart, and the temperture (in [deg]F) at which the
gaseous feedstock and product volumes used in Equation X-1 of this
subpart were determined. Indicate whether you used the alternative to
sampling and analysis specified in Sec. 98.243(c)(4).
* * * * *
(10) You may elect to report the flow and carbon content of
wastewater, and you may elect to report the annual mass of carbon
released in fugitive emissions and in process vents that are not
controlled with a combustion device. These values may be estimated
based on engineering analyses. These values are not to be used in the
mass balance calculation.
(11) If you determine carbon content or composition of a feedstock
or product using a method under Sec. 98.244(b)(4)(xiii), report the
information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of
this section. Include the information in paragraph (a)(11)(i) of this
section in each annual report. Include the information in paragraphs
(a)(11)(ii) and (a)(11)(iii) of this section only in the first
applicable annual report, and provide any changes to this information
in subsequent annual reports.
(i) Name or title of the analytical method.
(ii) A copy of the method. If the method is a modification of a
method listed in Sec. 98.244(b)(4)(i) through (xii), you may provide a
copy of only the sections that differ from the listed method.
(iii) An explanation of why an alternative to the methods listed in
Sec. 98.244(b)(4)(i) through (xii) is needed.
(b) If you measure emissions in accordance with Sec. 98.243(b),
then you must report the information listed in paragraphs (b)(1)
through (b)(8) of this section.
(1) The petrochemical process unit ID or other appropriate
descriptor, and the type of petrochemical produced.
(2) For CEMS used on stacks for stationary combustion units, report
the relevant information required under Sec. 98.36 for the Tier 4
calculation
[[Page 48804]]
methodology. Section 98.36(b)(9)(iii) does not apply for the purposes
of this subpart.
(3) For CEMS used on stacks that are not used for stationary
combustion units, report the information required under Sec.
98.36(e)(2)(vi).
(4) The CO2 emissions from each stack and the combined
CO2 emissions from all stacks (except flare stacks) that
handle process vent emissions and emissions from stationary combustion
units that burn process off-gas for the petrochemical process unit. For
each stationary combustion unit (or group of combustion units monitored
with a single CO2 CEMS) that burns petrochemical process
off-gas, provide an estimate based on engineering judgment of the
fraction of the total emissions that is attributable to combustion of
off-gas from the petrochemical process unit.
(5) For stationary combustion units that burn process off-gas from
the petrochemical process unit, report the information related to
CH4 and N2O emissions as specified in paragraphs
(b)(5)(i) through (b)(5)(iv) of this section.
(i) The CH4 and N2O emissions from each stack
that is monitored with a CO2 CEMS, expressed in metric tons
of each gas and in metric tons of CO2e. For each stack
provide an estimate based on engineering judgment of the fraction of
the total emissions that is attributable to combustion of off-gas from
the petrochemical process unit.
(ii) The combined CH4 and N2O emissions from
all stationary combustion units, expressed in metric tons of each gas
and in metric tons of CO2e.
(iii) The quantity of each type of fuel used in Equation C-8 in
Sec. 98.33(c) for each stationary combustion unit or group of units
(as applicable) during the reporting year, expressed in short tons for
solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(iv) The HHV (either default or annual average from measured data)
used in Equation C-8 in Sec. 98.33(c) for each stationary combustion
unit or group of combustion units (as applicable).
* * * * *
(c) If you comply with the combustion methodology specified in
Sec. 98.243(d), you must report under this subpart the information
listed in paragraphs (c)(1) through (c)(5) of this section.
(1) The ethylene process unit ID or other appropriate descriptor.
(2) For each stationary combustion unit that burns ethylene process
off-gas (or group of stationary sources with a common pipe), except
flares, the relevant information listed in Sec. 98.36 for the
applicable Tier methodology. For each stationary combustion unit or
group of units (as applicable) that burns ethylene process off-gas,
provide an estimate based on engineering judgment of the fraction of
the total emissions that is attributable to combustion of off-gas from
the ethylene process unit.
(3) Information listed in Sec. 98.256(e) of subpart Y of this part
for each flare that burns ethylene process off-gas.
(4) Name and annual quantity of each feedstock.
(5) Annual quantity of ethylene produced from each process unit
(metric tons).
37. Section 98.247 is amended by:
a. Revising paragraph (a).
b. Adding paragraph (b)(4).
c. Revising paragraph (c).
Sec. 98.247 Records that must be retained.
* * * * *
(a) If you comply with the CEMS measurement methodology in Sec.
98.243(b), then you must retain under this subpart the records required
for the Tier 4 Calculation Methodology in Sec. 98.37, records of the
procedures used to develop estimates of the fraction of total emissions
attributable to combustion of petrochemical process off-gas as required
in Sec. 98.246(b), and records of any annual average HHV calculations.
(b) * * *
(4) The dates and results (e.g., percent calibration error) of the
calibrations of each measurement device.
(c) If you comply with the combustion methodology in Sec.
98.243(d), then you must retain under this subpart the records required
for the applicable Tier Calculation Methodologies in Sec. 98.37. If
you comply with Sec. 98.243(d)(2), you must also keep records of the
annual average flow calculations.
Subpart Y--[Amended]
38. Section 98.252 is amended by revising paragraph (a) and the
first sentence of paragraph (i) to read as follows:
Sec. 98.252 GHGs to report.
* * * * *
(a) CO2, CH4, and N2O combustion
emissions from stationary combustion units and from each flare.
Calculate and report the emissions from stationary combustion units
under subpart C of this part (General Stationary Fuel Combustion
Sources) by following the requirements of subpart C, except for
emissions from combustion of fuel gas. For CO2 emissions
from combustion of fuel gas, use either Equation C-5 in subpart C of
this part or the Tier 4 methodology in subpart C of this part, unless
either of the conditions in paragraphs (a)(1) or (2) of this section
are met, in which case use either Equations C-1 or C-2a in subpart C of
this part. For CH4 and N2O emissions from
combustion of fuel gas, use the applicable procedures in Sec. 98.33(c)
for the same tier methodology that was used for calculating
CO2 emissions. (Use the default CH4 and
N2O emission factors for ``Petroleum (All fuel types in
Table C-1)'' in Table C-2 of this part. For Tier 3, use either the
default high heat value for fuel gas in Table C-1 of subpart C of this
part or a calculated HHV, as allowed in Equation C-8 of subpart C of
this part.) You may aggregate units, monitor common stacks, or monitor
common (fuel) pipes as provided in Sec. 98.36(c) when calculating and
reporting emissions from stationary combustion units. Calculate and
report the emissions from flares under this subpart.
(1) The annual average fuel gas flow rate in the fuel gas line to
the combustion unit, prior to any split to individual burners or ports,
does not exceed 345 standard cubic feet per minute at 60[deg]F and 14.7
pounds per square inch absolute and either of the conditions in
paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual
average flow rate using company records assuming total flow is evenly
distributed over 525,600 minutes per year.
(i) A flow meter is not installed at any point in the line
supplying fuel gas or an upstream common pipe.
(ii) The fuel gas line contains only vapors from loading or
unloading, waste or wastewater handling, and remediation activities
that are combusted in a thermal oxidizer or thermal incinerator.
(2) The combustion unit has a maximum rated heat input capacity of
less than 30 MMBtu/hr and either of the following conditions exist:
(i) A flow meter is not installed at any point in the line
supplying fuel gas or an upsteam common pipe; or
(ii) The fuel gas line contains only vapors from loading or
unloading, waste or wastewater handling, and remediation activities
that are combusted in a thermal oxidizer or thermal incinerator.
* * * * *
(i) CO2 emissions from non-merchant hydrogen production
process units (not including hydrogen produced from catalytic reforming
units) under this subpart. * * *
39. Section 98.253 is amended by:
a. Revising paragraph (b)(1)(ii)(A).
b. Revising the definition of ``MVC'' in Equation Y-3 in paragraph
(b)(1)(iii)(C).
[[Page 48805]]
c. Revising paragraph (c)(1)(ii).
d. Revising the definition of ``MVC'' in Equation Y-6 in paragraph
(c)(2)(i).
e. Revising paragraph (c)(2)(ii).
f. Revising the definition of ``CBQ'' and ``n'' in
Equation Y-11 in paragraph (e)(3).
g. Revising the first sentence of paragraph (f) introductory text
and the last sentence of paragraph (f)(1).
h. Revising the definition of ``MVC'' in Equation Y-12 in paragraph
(f)(4).
i. Revising the definition of ``Mdust'' in Equation Y-13
in paragraph (g)(2).
j. Revising paragraphs (h) introductory text and (h)(2).
k. In paragraph (i)(1), revising the first two sentences and the
definition of ``MVC'' in Equation Y-18.
l. In paragraph (j), revising both sentences; and revising the
definitions of ``(VR)p,'' ``(MFx)p,''
and ``MVC'' in Equation Y-19.
m. In paragraph (k), revising the first sentence and the definition
of ``MVC'' in Equation Y-20.
n. Revising paragraph (m) introductory text.
o. Revising the definitions of ``MFCH4'' and ``MVC'' in
Equation Y-23 in paragraph (m)(2).
p. Revising paragraph (n).
Sec. 98.253 Calculating GHG emissions.
* * * * *
(b) * * *
(1) * * *
(ii) * * *
(A) If you monitor gas composition, calculate the CO2
emissions from the flare using either Equation Y-1a or Equation Y-1b of
this section. If daily or more frequent measurement data are available,
you must use daily values when using Equation Y-1a or Equation Y-1b of
this section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TP11AU10.007
Where:
CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52
(for weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Flare)p = Volume of flare gas combusted during
measurement period (standard cubic feet per period, scf/period). If
a mass flow meter is used, measure flare gas flow rate in kg/period
and replace the term ``(MW)p/MVC'' with ``1''.
(MW)p = Average molecular weight of the flare gas
combusted during measurement period (kg/kg-mole). If measurements
are taken more frequently than daily, use the arithmetic average of
measurement values within the day to calculate a daily average.
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68
[ordm]F and 14.7 pounds per square inch absolute (psia) or 836.6
scf/kg-mole at 60 [ordm]F and 14.7 psia).
(CC)p = Average carbon content of the flare gas combusted
during measurement period (kg C per kg flare gas). If measurements
are taken more frequently than daily, use the arithmetic average of
measurement values within the day to calculate a daily average.
[GRAPHIC] [TIFF OMITTED] TP11AU10.008
Where:
CO2 = Annual CO2 emissions for a specific fuel
type (metric tons/year).
n = Number of measurement periods. The minimum value for n is 52
(for weekly measurements); the maximum value for n is 366 (for daily
measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during
measurement period (standard cubic feet per period, scf/period). If
a mass flow meter is used, you must determine the average molecular
weight of the flare gas during the measurement period and convert
the mass flow to a volumetric flow.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68[ordm]F
and 14.7 psia or 836.6 scf/kg-mole at 60[ordm]F and 14.7 psia).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
(%CO2)p = Mole percent CO2
concentration in the flare gas stream during the measurement period
(mole percent = percent by volume).
y = Number of carbon-containing compounds other than CO2
in the flare gas stream.
x = Index for carbon-containing compounds other than CO2.
0.98 = Assumed combustion efficiency of a flare (mole CO2
per mole carbon).
(%Cx)p = Mole percent concentration of
compound ``x'' in the flare gas stream during the measurement period
(mole percent = percent by volume)
CMNx = Carbon mole number of compound ``x'' in the flare
gas stream (mole carbon atoms per mole compound). E.g., CMN for
ethane (C2H6) is 2; CMN for propane
(C3H8) is 3.
* * * * *
(iii) * * *
(C)
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68
[ordm]F and 14.7 psia or 836.6 scf/kg-mole at 60 [ordm]F and 14.7
psia).
* * * * *
(c) * * *
(1) * * *
(ii) For catalytic cracking units whose process emissions are
discharged through a combined stack with other CO2 emissions
(e.g., co-mingled with emissions from a CO boiler) you must also
calculate the other CO2 emissions using the applicable
methods for the applicable subpart (e.g., subpart C of this part in the
case of a CO boiler). Calculate the process emissions from the
catalytic cracking unit or fluid coking unit as the difference in the
CO2 CEMS emissions and the calculated emissions associated
with the additional units discharging through the combined stack.
(2) * * *
(i)
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68
[ordm]F and 14.7 psia or 836.6 scf/kg-mole at 60 [ordm]F and 14.7
psia).
* * * * *
(ii) Either continuously monitor the volumetric flow rate of
exhaust gas from
[[Page 48806]]
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 either Equation
Y-7a or Equation Y-7b of this section.
[GRAPHIC] [TIFF OMITTED] TP11AU10.009
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 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 under 40
CFR part 63 subpart UUU, assume %CO to be zero.
[GRAPHIC] [TIFF OMITTED] TP11AU10.010
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).
%N2,oxy = N2 concentration in oxygen enriched
gas stream inlet to the fluid catalytic cracking unit regenerator or
fluid coking unit burner based on measured value or maximum
N2 impurity specifications of the oxygen supply used for
enrichment (percent by volume--dry basis).
%N2,exhaust = Hourly average percent N2
concentration in the exhaust gas stream from the fluid catalytic
cracking unit regenerator or fluid coking unit burner (percent by
volume--dry basis).
* * * * *
(e) * * *
(3) * * *
CBQ = Coke burn-off quantity per regeneration cycle or
measurement period from engineering estimates (kg coke/cycle or kg
coke/measurement period).
n = Number of regeneration cycles or measurement periods in the
calendar year.
* * * * *
(f) For on-site sulfur recovery plants and for sour gas sent off
site for sulfur recovery, calculate and report CO2 process
emissions from sulfur recovery plants according to the requirements in
paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus
sulfur recovery plants, according to the requirements in paragraph (j)
of this section regardless of the concentration of CO2 in
the vented gas stream. * * *
(1) * * * Other sulfur recovery plants must either install a CEMS
that complies with the Tier 4 Calculation Methodology in subpart C, or
follow the requirements of paragraphs (f)(2) through (f)(5) of this
section, or (for non-Claus sulfur recovery plants only) follow the
requirements in paragraph (j) of this section to determine
CO2 emissions for the sulfur recovery plant.
* * * * *
(4) * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
(g) * * *
(2) * * *
Mdust = Annual mass of petroleum coke dust removed from
the process through the dust collection system of the coke calcining
unit from facility records (metric ton petroleum coke dust/year).
For coke calcining units that recycle the collected dust, the mass
of coke dust removed from the process is the mass of coke dust
collected less the mass of coke dust recycled to the process.
* * * * *
(h) For asphalt blowing operations, calculate CO2 and
CH4 emissions according to the requirements in paragraph (j)
of this section regardless of the CO2 and CH4
concentrations or according to the applicable provisions in paragraphs
(h)(1) and (h)(2) of this section.
* * * * *
(2) For asphalt blowing operations controlled by thermal oxidizer
or flare, calculate CO2 using either Equation Y-16a or
Equation Y-16b of this section and calculate CH4 emissions
using Equation Y-17 of this section, provided these emissions are not
already included in the flare emissions calculated in paragraph (b) of
this section or in the stationary combustion unit emissions required
under subpart C of this part (General Stationary Fuel Combustion
Sources).
[[Page 48807]]
[GRAPHIC] [TIFF OMITTED] TP11AU10.011
Where:
CO2 = Annual CO2 emissions from controlled
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from
facility-specific test data (metric tons C/MMbbl asphalt blown);
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TP11AU10.012
Where:
CO2 = Annual CO2 emissions from controlled
asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (MMbbl/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
EFAB,CO2 = Emission factor for CO2 from
uncontrolled asphalt blowing from facility-specific test data
(metric tons CO2/MMbbl asphalt blown); default = 1,100.
CEFAB = Carbon emission factor from asphalt blowing from
facility-specific test data (metric tons C/MMbbl asphalt blown);
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TP11AU10.013
Where:
CH4 = Annual methane emissions from controlled asphalt
blowing (metric tons CH4/year).
0.02 = Fraction of methane uncombusted in thermal oxidizer or flare
based on assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million barrels per
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from
uncontrolled asphalt blowing from facility-specific test data
(metric tons CH4/MMbbl asphalt blown); default = 580.
(i) * * *
(1) Use the process vent method in paragraph (j) of this section to
calculate the CH4 emissions from the depressurization of the
coke drum or vessel regardless of the CH4 concentration and
also calculate the CH4 emissions from the subsequent opening
of the vessel for coke cutting operations using Equation Y-18 of this
section. If you have coke drums or vessels of different dimensions, use
the process vent method in paragraph (j) of this section and Equation
Y-18 for each set of coke drums or vessels of the same size and sum the
resultant emissions across each set of coke drums or vessels to
calculate the CH4 emissions for all delayed coking units.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
(j) For each process vent not covered in paragraphs (a) through (i)
of this section that can be reasonably expected to contain greater than
2 percent by volume CO2 or greater than 0.5 percent by
volume of CH4 or greater than 0.01 percent by volume (100
parts per million) of N2O, calculate GHG emissions using the
Equation Y-19 of this section. You must use Equation Y-19 of this
section to calculate CH4 emissions for catalytic reforming
unit depressurization and purge vents when methane is used as the purge
gas or if you elected this method as an alternative to the methods in
paragraphs (f), (h), or (k) of this section.
* * * * *
(VR)p = Average volumetric flow rate of process gas
during the event (scf per hour) from measurement data, process
knowledge, or engineering estimates.
(MFx)p = Mole fraction of GHG x in process
vent during the event (kg-mol of GHG x/kg-mol vent gas) from
measurement data, process knowledge, or engineering estimates.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
(k) For uncontrolled blowdown systems, you must calculate CH4
emissions either using the methods for process vents in paragraph (j)
of this section regardless of the CH4 concentration or using
Equation Y20 of this section. * * *
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
(m) For storage tanks, except as provided in paragraph (m)(4) of
this section, calculate CH4 emissions using the applicable
methods in paragraphs (m)(1) through (m)(3) of this section.
(2) * * *
MFCH4 = Average mole fraction of CH4 in vent
gas from the unstabilized crude oil storage tanks from facility
measurements (kg-mole CH4/kg-mole gas); use 0.27 as a
default if measurement data are not available.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
(n) For crude oil, intermediate, or product loading operations for
which the vapor-phase concentration of methane is 0.5 volume percent or
more, calculate CH4 emissions from loading operations using
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 vapor-phase concentration of methane is less than 0.5
volume percent, you may assume zero methane emissions.
40. Section 98.254 is amended by:
a. Revising paragraph (a).
[[Page 48808]]
b. Revising paragraph (b).
c. Revising paragraph (c).
d. Revising paragraphs (d) introductory text and (d)(6).
e. Adding a new paragraph (d)(6).
f. Revising paragraph (e) introductory text.
g. Revising paragraph (f) introductory text and (f)(1).
h. Removing and reserving paragraph (f)(2).
i. Removing paragraph (f)(4).
j. Revising paragraph (g).
k. Revising the second sentence of paragraph (h).
l. Removing paragraph (l).
Sec. 98.254 Monitoring and QA/QC requirements.
(a) Fuel flow meters, gas composition monitors, and heating value
monitors that are associated with sources that use a CEMS to measure
CO2 emissions according to subpart C of this part or that
are associated with stationary combustion sources must meet the
applicable monitoring and QA/QC requirements in Sec. 98.34.
(b) All gas flow meters, gas composition monitors, and heating
value monitors that are used to provide data for the GHG emissions
calculations in this subpart for sources other than those subject to
the requirements in paragraph (a) of this section shall be calibrated
according to the procedures in the applicable methods specified in
paragraphs (c) through (g) of this section or the procedures specified
by the manufacturer. In the case of gas flow meters, all gas flow
meters must meet the calibration accuracy requirements in Sec.
98.3(i). You must recalibrate each gas flow meter according to one of
the following frequencies. You may recalibrate either biennially (every
two years), at the minimum frequency specified by the manufacturer, or
at the interval specified by the industry consensus standard practice
used. You must recalibrate each gas composition monitor and heating
value monitor according to one of the following frequencies. You may
recalibrate either annually, at the minimum frequency specified by the
manufacturer, or at the interval specified by the industry consensus
standard practice used.
(c) For flare or sour gas flow meters, operate, calibrate, and
maintain the flow meter according to one of the following. You may use
a method published by a consensus-based standards organization or the
procedures specified by the flow meter manufacturer. Consensus-based
standards include, but are not limited to, the following: ASTM
International, the American Society of Mechanical Engineers (ASME), and
the American Gas Association (AGA).
(d) Except as provided in paragraph (g) of this section, determine
gas composition and, if required, average molecular weight of the gas
using any of the following methods. Alternatively, the results of
chromatographic analysis of the fuel may be used, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions; and the methods used for operation,
maintenance, and calibration of the gas chromatograph are documented in
the written Monitoring Plan for the unit under Sec. 98.3(g)(5).
* * * * *
(6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by
Thermoelectric Measurement of Vapor Pressure (incorporated by
reference, see Sec. 98.7).
(e) Determine flare gas higher heating value using any of the
following methods. Alternatively, the results of chromatographic
analysis of the fuel may be used, provided that the gas chromatograph
is operated, maintained, and calibrated according to the manufacturer's
instructions; and the methods used for operation, maintenance, and
calibration of the gas chromatograph are documented in the written
Monitoring Plan for the unit under Sec. 98.3(g)(5).
* * * * *
(f) For gas flow meters used to comply with the requirements in
Sec. 98.253(c)(2)(ii) or Sec. 98.253(j), install, operate, calibrate,
and maintain each gas flow meter according to the requirements in 40
CFR 63.1572(c) and the following requirements.
(1) Locate the flow monitor at a site that provides representative
flow rates. Avoid locations where there is swirling flow or abnormal
velocity distributions due to upstream and downstream disturbances.
* * * * *
(g) For exhaust gas CO2/CO/O2 composition
monitors used to comply with the requirements in Sec. 98.253(c)(2),
install, operate, calibrate, and maintain exhaust gas composition
monitors according to the the requirements in 40 CFR 60.105a(b)(2) or
40 CFR 63.1572(c) or according to the manufacturer's specifications and
requirements.
(h) * * * Calibrate the measurement device according to the
procedures specified by NIST handbook 44 or the procedures specified by
the manufacturer. * * *
* * * * *
41. Section 98.256 is amended by:
a. Revising paragraph (e)(6).
b. Redesignating paragraphs (e)(7) through (e)(9) as (e)(8) through
(e)(10), respectively.
c. Adding a new paragraph (e)(7).
d. Revising newly designated paragraphs (e)(8) and (e)(9).
e. Revising paragraphs (f)(6) through (f)(8).
f. Redesignating paragraphs (f)(9) through (f)(12) as (f)(10)
through (f)(13), respectively.
g. Adding a new paragraph (f)(9).
h. Revising newly designated paragraphs (f)(11) through (f)(13).
i. Revising paragraphs (g)(5), (h)(2), (h)(4), and (h)(6).
j. Adding paragraph (h)(7).
k. Revising paragraphs (i)(5), (i)(6), (i)(8), and (j)(2).
l. Redesignating paragraph (j)(8) as (j)(9).
m. Adding a new paragraph (j)(8).
n. Revising paragraphs (k)(1), (k)(3), (l) introductory text,
(l)(5), and (m).
o. Revising paragraph (o).
Sec. 98.256 Data reporting requirements.
* * * * *
(e) * * *
(6) If you use Equation Y-1a of this subpart, an indication of
whether daily or weekly measurement periods are used, the annual volume
of flare gas combusted (in scf/year) and the annual average molecular
weight (in kg/kg-mole), the molar volume conversion factor (in scf/kg-
mole), and annual average carbon content of the flare gas (in kg carbon
per kg flare gas).
(7) If you use Equation Y-1b of this subpart, an indication of
whether daily or weekly measurement periods are used, the annual volume
of flare gas combusted (in scf/year), the molar volume conversion
factor (in scf/kg-mole), the annual average CO2
concentration (volume or mole percent), the number of carbon containing
compounds other than CO2 in the flare gas stream, and for
each of the carbon containing compounds other than CO2 in
the flare gas stream:
(i) The annual average concentration of the compound (volume or
mole percent).
(ii) The carbon mole number of the compound (moles carbon per mole
compound).
(8) If you use Equation Y-2 of this subpart, an indication of
whether daily or weekly measurement periods are used, the annual volume
of flare gas combusted (in million (MM) scf/year) and the annual
average higher heating value of the flare gas (in MMBtu per MMscf).
(9) If you use Equation Y-3 of this subpart, the annual volume of
flare gas combusted (in MMscf/year) during
[[Page 48809]]
normal operations, the annual average higher heating value of the flare
gas (in MMBtu/MMscf), the number of SSM events exceeding 500,000 scf/
day, the volume of gas flared (in scf/event), the average molecular
weight (in kg/kg-mole), the molar volume conversion factor (in scf/kg-
mole), and carbon content of the flare gas (in kg carbon per kg flare)
for each SSM event over 500,000 scf/day.
* * * * *
(f) * * *
(6) If you use a CEMS, the relevant information required under
Sec. 98.36 for the Tier 4 Calculation Methodology, the CO2
annual emissions as measured by the CEMS (unadjusted to remove
CO2 combustion emissions associated with additional units,
if present) and the process CO2 emissions as calculated
according to Sec. 98.253(c)(1)(ii). Report the CO2 annual
emissions associated with sources other than those from the coke burn-
off in the applicable subpart (e.g., subpart C of this part in the case
of a CO boiler).
(7) If you use Equation Y-6 of this subpart, the annual average
exhaust gas flow rate, %CO2, %CO, and the molar volume
conversion factor (in scf/kg-mole).
(8) If you use Equation Y-7a of this subpart, the annual average
flow rate of inlet air and oxygen-enriched air, %O2,
%Ooxy, %CO2, and %CO.
(9) If you use Equation Y-7b of this subpart, the annual average
flow rate of inlet air and oxygen-enriched air, %N2,oxy, and
%N2,exhaust.
* * * * *
(11) Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for CH4
emissions. If you use a unit-specific emission factor for
CH4, report the unit-specific emission factor for
CH4, the units of measure for the unit-specific factor, the
activity data for calculating emissions (e.g., if the emission factor
is based on coke burn-off rate, the annual quantity of coke burned),
and the basis for the factor.
(12) Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for N2O
emissions. If you use a unit-specific emission factor for
N2O, report the unit-specific emission factor for
N2O, the units of measure for the unit-specific factor, the
activity data for calculating emissions (e.g., if the emission factor
is based on coke burn-off rate, the annual quantity of coke burned),
and the basis for the factor.
(13) If you use Equation Y-11 of this subpart, the number of
regeneration cycles or measurement periods during the reporting year,
the average coke burn-off quantity per cycle or measurement period, and
the average carbon content of the coke.
(g) * * *
(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, and the
applicable equation input parameters specified in paragraphs (f)(7)
through (f)(13) of this section.
(h) * * *
(2) Maximum rated throughput of each independent sulfur recovery
plant, in metric tons sulfur produced/stream day, a description of the
type of sulfur recovery plant, and an indication of the method used to
calculate CO2 annual emissions for the sulfur recovery plant
(e.g., CO2 CEMS, Equation Y-12, or process vent method in
Sec. 98.253(j)).
* * * * *
(4) If you use Equation Y-12 of this subpart, the annual volumetric
flow to the sulfur recovery plant (in scf/year), the molar volume
conversion factor (in scf/kg-mole), and the annual average mole
fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
* * * * *
(6) If you use a CEMS, the relevant information required under
Sec. 98.36 for the Tier 4 Calculation Methodology, the CO2
annual emissions as measured by the CEMS and the annual process
CO2 emissions calculated according to Sec. 98.253(f)(1). *
* *
(7) If you use the process vent method in Sec. 98.253(j) for a
non-Claus sulfur recovery plant, the relevant information required
under paragraph (l)(5) of this section.
(i) * * *
(5) If you use Equation Y-13 of this subpart, annual mass and
carbon content of green coke fed to the unit, the annual mass and
carbon content of marketable coke produced, the annual mass of coke
dust removed from the process through dust collection systems, and an
indication of whether coke dust is recycled to the unit (e.g., all dust
is recycled, a portion of the dust is recycled, or none of the dust is
recycled).
(6) If you use a CEMS, the relevant information required under
Sec. 98.36 for the Tier 4 Calculation Methodology, the CO2
annual emissions as measured by the CEMS and the annual process
CO2 emissions calculated according to Sec. 98.253(g)(1).
* * * * *
(8) Indicate whether you use a measured value, a unit-specific
emission factor, or a default emission factor for N2O
emissions. If you use a unit-specific emission factor for
N2O, report the unit-specific emission factor for
N2O, the units of measure for the unit-specific factor, the
activity data for calculating emissions (e.g., if the emission factor
is based on coke burn-off rate, the annual quantity of coke burned),
and the basis for the factor. (j) * * *
(2) The quantity of asphalt blown (in Million bbl) at the unit in
the reporting year.
* * * * *
(8) If you use Equation Y-16b of this subpart, the CO2
emission factor used and the basis for its value and the carbon
emission factor used and the basis for its value.
* * * * *
(k) * * *
(1) The cumulative annual CH4 emissions (in metric tons
of CH4) for all delayed coking units at the facility.
* * * * *
(3) The total number of delayed coking units at the facility, the
total number of delayed coking drums at the facility, and for each coke
drum or vessel: The dimensions, the typical gauge pressure of the
coking drum when first vented to the atmosphere, typical void fraction,
the typical drum outage (i.e., the unfilled distance from the top of
the drum, in feet), the molar volume conversion factor (in scf/kg-
mole), and annual number of coke-cutting cycles.
* * * * *
(l) For each process vent subject to Sec. 98.253(j), the owner or
operator shall report:
* * * * *
(5) The annual volumetric flow discharged to the atmosphere (in
scf), and an indication of the measurement or estimation method, annual
average mole fraction of each GHG above the concentration threshold or
otherwise required to be reported and an indication of the measurement
or estimation method, the molar volume conversion factor (in scf/kg-
mole), and for intermittent vents, the number of venting events and the
cumulative venting time.
(m) For uncontrolled blowdown systems, the owner or operator shall
report:
(1) An indication of whether the uncontrolled blowdown emission are
reported under Sec. 98.253(k) or Sec. 98.253(j) or a statement that
the facility does not have any uncontrolled blowdown systems.
(2) The cumulative annual CH4 emissions (in metric tons
of CH4) for uncontrolled blowdown systems.
[[Page 48810]]
(3) For uncontrolled blowdown systems reporting under Sec.
98.253(k), 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, the methane emission
factor used for uncontrolled blowdown systems, the basis for the value,
and the molar volume conversion factor (in scf/kg-mole).
(4) For uncontrolled blowdown systems reporting under Sec.
98.253(j), the relevant information required under paragraph (l)(5) of
this section.
* * * * *
(o) * * *
(1) The cumulative annual CH4 emissions (in metric tons
of CH4) for all storage tanks, except for those used to
process unstabilized crude oil.
(2) For storage tanks other than those processing unstabilized
crude oil:
(i) The method used to calculate the reported storage tank
emissions for storage tanks other than those processing unstabilized
crude (Section 7.1 of the AP-42: ``Compilation of Air Pollutant
Emission Factors, Volume 1: Stationary Point and Area Sources'',
including TANKS Model (Version 4.09D) or similar programs, or Equation
Y-22 of this section, other).
(ii) The total quantity (in MMbbl) of crude oil plus the quantity
of intermediate products received from off-site that are processed at
the facility in the reporting year.
(3) The cumulative CH4 emissions (in metric tons of
CH4) for storage tanks used to process unstabilized crude
oil or a statement that the facility did not receive any unstabilized
crude oil during the reporting year.
(4) For storage tanks that process unstabilized crude oil:
(i) The method used to calculate the reported unstabilized crude
oil storage tank emissions .
(ii) The quantity of unstabilized crude oil received during the
calendar year (in MMbbl).
(iii) The average pressure differential (in psi).
(iv) The molar volume conversion factor (in scf/kg-mole).
(v) The average mole fraction of CH4 in vent gas from
unstabilized crude oil storage tanks and the basis for the mole
fraction.
(vi) If you did not use Equation Y-23, the tank-specific methane
composition data and the gas generation rate data used to estimate the
cumulative CH4 emissions for storage tanks used to process
unstabilized crude oil.
* * * * *
42. Section 98.257 is revised to read as follows:
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. If
you comply with the combustion methodology in Sec. 98.252(a), then you
must retain under this subpart the records required for the Tier 3 and/
or Tier 4 Calculation Methodologies in Sec. 98.37 and you must keep
records of the annual average flow calculations.
Subpart AA--[Amended]
43. Section 98.273 is amended by:
a. Revising paragraphs (a)(1) and (a)(2).
b. Revising paragraphs (b)(1) and (b)(2).
c. Revising paragraphs (c)(1) and (c)(2).
Sec. 98.273 Calculating GHG emissions.
(a) * * *
(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). A higher tier from Sec. 98.33(a) may be
used to calculate fossil fuel-based CO2 emissions if the
respective monitoring and QA/QC requirements described in Sec. 98.34
are met.
(2) Calculate fossil fuel-based CH4 and N2O
emissions from direct measurement of fossil fuels consumed, default or
site-specific 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).
* * * * *
(b) * * *
(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). A higher tier from Sec.
98.33(a) may be used to calculate fossil fuel-based CO2
emissions if the respective monitoring and QA/QC requirements described
in Sec. 98.34 are met.
(2) Calculate CH4 and N2O emissions from
fossil fuels from direct measurement of fossil fuels consumed, default
or site-specific 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).
* * * * *
(c) * * *
(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). A higher tier from
Sec. 98.33(a) may be used to calculate fossil fuel-based
CO2 emissions if the respective monitoring and QA/QC
requirements described in Sec. 98.34 are met.
(2) Calculate CH4 and N2O emissions from
fossil fuel from direct measurement of fossil fuels consumed, default
or site-specific 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); use the default
HHV listed in Table C-1 of subpart C and the default CH4 and
N2O emissions factors listed in Table AA-2 of this subpart.
* * * * *
44. Section 98.276 is amended by revising the introductory text to
read as follows:
Sec. 98.276 Data reporting requirements.
In addition to the information required by Sec. 98.3(c) and the
applicable information required by Sec. 98.36, each annual report must
contain the information in paragraphs (a) through (k) of this section
as applicable:
* * * * *
45. In the Tables to Subpart AA of Part 98, Table AA-2 is revised
to read as follows:
[[Page 48811]]
Table AA-2 of Subpart AA--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CH4 and N2O
----------------------------------------------------------------------------------------------------------------
Fossil fuel-based emissions factors (kg/mmBtu HHV)
-----------------------------------------------------------------------
Fuel Kraft lime kilns Kraft calciners
-----------------------------------------------------------------------
CH4 N2O CH4 N2O
----------------------------------------------------------------------------------------------------------------
Residual Oil ................ ................ ................ 0.0003
Distillate Oil ................ ................ 0.0027 0.0004
Natural Gas 0.0027 0 ................ 0.0001
Biogas ................ ................ ................ 0.0001
Petroleum coke ................ ................ NA \a\NA
----------------------------------------------------------------------------------------------------------------
\a\ Emission factors for kraft calciners are not available.
Subpart OO--[Amended]
46. Section 98.410 is amended by revising paragraph (b) to read as
follows:
Sec. 98.410 Definition of the source category.
* * * * *
(b) To produce a fluorinated GHG means to manufacture a fluorinated
GHG from any raw material or feedstock chemical. Producing a
fluorinated GHG includes the manufacture of a fluorinated GHG as an
isolated intermediate for use in a process that will result in its
transformation either at or outside of the production facility.
Producing a fluorinated GHG also includes the creation of a fluorinated
GHG (with the exception of HFC-23) that is captured and shipped off
site for any reason, including destruction. Producing a fluorinated GHG
does not include the reuse or recycling of a fluorinated GHG, the
creation of HFC-23 during the production of HCFC-22, the creation of
intermediates that are created and transformed in a single process with
no storage of the intermediates, or the creation of fluorinated GHGs
that are released or destroyed at the production facility before the
production measurement at Sec. 98.414(a).
* * * * *
47. Section 98.414 is amended by:
a. Adding a second and third sentence to paragraph (a).
b. Revising paragraph (h).
c. Removing and reserving paragraph (j).
d. Adding new paragraphs (n) through (q).
Sec. 98.414 Monitoring and QA/QC requirements.
(a) * * * If the measured mass includes more than one fluorinated
GHG, the concentrations of each of the fluorinated GHGs, other than
low-concentration constituents, shall be measured as set forth in
paragraph (n) of this section. For each fluorinated GHG, the mean of
the concentrations of that fluorinated GHG (mass fraction) measured
under paragraph (n) of this section shall be multiplied by the mass
measurement to obtain the mass of that fluorinated GHG coming out of
the production process.
* * * * *
(h) You must measure the mass of each fluorinated GHG that is fed
into the destruction device and that was previously produced as defined
at Sec. 98.410(b). Such fluorinated GHGs include but are not limited
to quantities that are shipped to the facility by another facility for
destruction and quantities that are returned to the facility for
reclamation but are found to be irretrievably contaminated and are
therefore destroyed. You must use flowmeters, weigh scales, or a
combination of volumetric and density measurements with an accuracy and
precision of one percent of full scale or better. If the measured mass
includes more than trace concentrations of materials other than the
fluorinated GHG being destroyed, you must estimate the concentrations
of fluorinated GHG being destroyed considering current or previous
representative concentration measurements and other relevant process
information. You must multiply this concentration (mass fraction) by
the mass measurement to obtain the mass of the fluorinated GHG
destroyed.
* * * * *
(n) If the mass coming out of the production process includes more
than one fluorinated GHG, you shall measure the concentrations of all
of the fluorinated GHGs, other than low-concentration constituents, as
follows:
(1) Analytical Methods. Use a quality-assured analytical
measurement technology capable of detecting the analyte of interest at
the concentration of interest and use a procedure validated with the
analyte of interest at the concentration of interest. Where standards
for the analyte are not available, a chemically similar surrogate may
be used. Acceptable analytical measurement technologies include but are
not limited to gas chromatography (GC) with an appropriate detector,
infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic
resonance (NMR). Acceptable methods include EPA Method 18 in Appendix
A-1 of 40 CFR part 60; EPA Method 320 in Appendix A of 40 CFR part 63;
the Protocol for Measuring Destruction or Removal Efficiency (DRE) of
Fluorinated Greenhouse Gas Abatement Equipment in Electronics
Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated
by reference, see Sec. 98.7); ASTM D6348-03 Standard Test Method for
Determination of Gaseous Compounds by Extractive Direct Interface
Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by
reference, see Sec. 98.7); or other analytical methods validated using
EPA Method 301 in Appendix A of 40 CFR part 63 or some other
scientifically sound validation protocol. The validation protocol may
include analytical technology manufacturer specifications or
recommendations.
(2) Documentation in GHG Monitoring Plan. Describe the analytical
method(s) used under paragraph (n)(1) of this section in the site GHG
Monitoring Plan as required under Sec. 98.3(g)(5). At a minimum,
include in the description of the method a description of the
analytical measurement equipment and procedures, quantitative estimates
of the method's accuracy and precision for the analytes of interest at
the concentrations of interest, as well as a description of how these
accuracies and precisions were estimated, including the validation
protocol used.
(3) Frequency of measurement. Perform the measurements at least
once by October 12, 2010 if the fluorinated GHG product is being
produced on August 11, 2010. Perform the measurements within 60 days of
commencing production of any fluorinated GHG product that was not being
produced on August 11, 2010.
[[Page 48812]]
Repeat the measurements if an operational or process change occurs that
could change the identities or significantly change the concentrations
of the fluorinated GHG constituents of the fluorinated GHG product.
Complete the repeat measurements within 60 days of the operational or
process change.
(4) Measure all product grades. Where a fluorinated GHG is produced
at more than one purity level (e.g., pharmaceutical grade and
refrigerant grade), perform the measurements for each purity level.
(5) Number of samples. Analyze a minimum of three samples of the
fluorinated GHG product that have been drawn under conditions that are
representative of the process producing the fluorinated GHG product. If
the relative standard deviation of the measured concentrations of any
of the fluorinated GHG constituents (other than low-concentration
constituents) is greater than or equal to 15 percent, draw and analyze
enough additional samples to achieve a total of at least six samples of
the fluorinated GHG product.
(o) All analytical equipment used to determine the concentration of
fluorinated GHGs, including but not limited to gas chromatographs and
associated detectors, IR, FTIR and NMR devices, shall be calibrated at
a frequency needed to support the type of analysis specified in the
site GHG Monitoring Plan as required under Sec. 98.414(n) and Sec.
98.3(g)(5) of this part. Quality assurance samples at the
concentrations of concern shall be used for the calibration. Such
quality assurance samples shall consist of or be prepared from
certified standards of the analytes of concern where available; if not
available, calibration shall be performed by a method specified in the
GHG Monitoring Plan.
(p) Isolated intermediates that are produced and transformed at the
same facility are exempt from the monitoring requirements of this
section.
(q) Low-concentration constituents are exempt from the monitoring
and QA/QC requirements of this section.
48. Section 98.416 is amended by:
a. Revising paragraph (a)(3).
b. Removing and reserving paragraph (a)(4).
c. Revising paragraph (a)(11).
d. Revising paragraphs (c) introductory text and (c)(1).
e. Revising paragraph (d) introductory text.
f. Adding paragraphs (f) through (h).
Sec. 98.416 Data reporting requirements.
* * * * *
(a) * * *
(3) Mass in metric tons of each fluorinated GHG that is destroyed
at that facility and that was previously produced as defined at Sec.
98.410(b). Quantities to be reported under this paragraph (a)(3) of
this section include but are not limited to quantities that are shipped
to the facility by another facility for destruction and quantities that
are returned to the facility for reclamation but are found to be
irretrievably contaminated and are therefore destroyed.
* * * * *
(11) Mass in metric tons of each fluorinated GHG that is fed into
the destruction device and that was previously produced as defined at
Sec. 98.410(b). Quantities to be reported under this paragraph (a)(11)
of this section include but are not limited to quantities that are
shipped to the facility by another facility for destruction and
quantities that are returned to the facility for reclamation but are
found to be irretrievably contaminated and are therefore destroyed.
* * * * *
(c) Each bulk importer of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes its imports at the corporate
level, except for shipments including less than twenty-five kilograms
of fluorinated GHGs or nitrous oxide, transshipments, and heels that
meet the conditions set forth at Sec. 98.417(e). 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, including each fluorinated GHG constituent of the
fluorinated GHG product that makes up between 0.5 percent and 100
percent of the product by mass.
* * * * *
(d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall
submit an annual report that summarizes its exports at the corporate
level, except for shipments including less than twenty-five kilograms
of fluorinated GHGs or nitrous oxide, transshipments, and heels. The
report shall contain the following information for each export:
* * * * *
(f) By March 31, 2011, all fluorinated GHG production facilities
shall submit a one-time report that includes the concentration of each
fluorinated GHG constituent in each fluorinated GHG product as measured
under Sec. 98.414(n). If the facility commences production of a
fluorinated GHG product that was not included in the initial report or
performs a repeat measurement under Sec. 98.414(n) that shows that the
identities or concentrations of the fluorinated GHG constituents of a
fluorinated GHG product have changed, then the new or changed
concentrations, as well as the date of the change, must be reflected in
a revision to the report. The revised report must be submitted to EPA
by the March 31st that immediately follows the measurement under Sec.
98.414(n).
(g) Isolated intermediates that are produced and transformed at the
same facility are exempt from the reporting requirements of this
section.
(h) Low-concentration constituents are exempt from the reporting
requirements of this section.
49. Section 98.417 is amended by revising paragraph (a)(2); and by
adding paragraphs (f) and (g) to read as follows:
Sec. 98.417 Records that must be retained.
(a) * * *
(2) Records documenting the initial and periodic calibration of the
analytical equipment (including but not limited to GC, IR, FTIR, or
NMR), 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(m) and (o).
* * * * *
(f) Isolated intermediates that are produced and transformed at the
same facility are exempt from the recordkeeping requirements of this
section.
(g) Low-concentration constituents are exempt from the
recordkeeping requirements of this section.
50. Section 98.418 is revised to read as follows:
Sec. 98.418 Definitions.
Except as provided below, all of the terms used in this subpart
have the same meaning given in the Clean Air Act and subpart A of this
part. If a conflict exists between a definition provided in this
subpart and a definition provided in subpart A, the definition in this
subpart shall take precedence for the reporting requirements in this
subpart.
Isolated intermediate means a product of a process that is stored
before subsequent processing. An isolated intermediate is usually a
product of chemical synthesis. Storage of an isolated intermediate
marks the end of a process. Storage occurs at any time the intermediate
is placed in equipment used solely for storage.
Low-concentration constituent means, for purposes of fluorinated
GHG production and export, a fluorinated GHG constituent of a
fluorinated GHG product that occurs in the product in concentrations
below 0.1 percent by mass. For purposes of fluorinated GHG
[[Page 48813]]
import, low-concentration constituent means a fluorinated GHG
constituent of a fluorinated GHG product that occurs in the product in
concentrations below 0.5 percent by mass. Low-concentration
constituents do not include fluorinated GHGs that are deliberately
combined with the product (e.g., to affect the performance
characteristics of the product).
Subpart PP--[Amended]
51. Section 98.422 is amended by revising paragraphs (a) and (b) to
read as follows:
Sec. 98.422 GHGs to report.
(a) Mass of CO2 captured from production process units.
(b) Mass of CO2 extracted from CO2 production
wells.
* * * * *
52. Section 98.423 is amended by:
a. Revising the first sentence of paragraph (a) introductory text.
b. Revising the first sentence of paragraphs (a)(1) and (a)(2).
c. Redesignating paragraph (b) as paragraph (c) and revising the
only sentence in newly designated paragraph (c).
d. Adding a new paragraph (b).
Sec. 98.423 Calculating CO2 Supply.
(a) Except as allowed in paragraph (b) of this section, calculate
the annual mass of CO2 captured, extracted, imported, or
exported through each flow meter in accordance with the procedures
specified in either paragraph (a)(1) or (a)(2) of this section. * * *
(1) For each mass flow meter, you shall calculate quarterly the
mass of CO2 in a CO2 stream in metric tons by
multiplying the mass flow by the composition data, according to
Equation PP-1 of this section. * * *
* * * * *
(2) For each volumetric flow meter, you shall calculate quarterly
the mass of CO2 in a CO2 stream in metric tons by
multiplying the volumetric flow by the concentration and density data,
according to Equation PP-2 of this section. * * *
* * * * *
(b) As an alternative to paragraphs (a)(1) through (3) of this
section for CO2 that is supplied in containers, calculate
the annual mass of CO2 supplied in containers delivered by
each CO2 stream in accordance with the procedures specified
in either paragraph (b)(1) or (b)(2) of this section. If multiple
CO2 streams are used to deliver CO2 to
containers, you shall calculate the annual mass of CO2
supplied in containers delivered by all CO2 streams
according to the procedures specified in paragraph (b)(3) of this
section.
(1) For each CO2 stream that delivers CO2 to
containers, for which mass is measured, you shall calculate
CO2 supply in containers using Equation PP-1 of this
section.
Where:
CO2,u = Annual mass of CO2 (metric tons)
supplied in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration
measurement of CO2 stream u that delivers CO2
to containers in quarter p (wt. %CO2).
Qp,u = Quarterly mass of contents supplied in all
containers delivered by CO2 stream u in quarter p (metric
tons).
p = Quarter of the year.
u = CO2 stream that delivers to containers.
(2) For each CO2 stream that delivers to containers, for
which volume is measured, you shall calculate CO2 supply in
containers using Equation PP-2 of this section.
Where:
CO2,u = Annual mass of CO2 (metric tons)
supplied in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration
measurement of CO2 stream u that delivers CO2
to containers in quarter p (vol. %CO2).
Qp = Quarterly volume of contents supplied in all
containers delivered by CO2 stream u in quarter p (metric
tons) (standard cubic meters).
Dp = Quarterly CO2 stream density
determination for CO2 stream u in quarter p (metric tons
per standard cubic meter).
p = Quarter of the year.
u = CO2 stream that delivers to containers.
(3) To aggregate data, sum the mass of CO2 supplied in
containers delivered by all CO2 streams in accordance with
Equation PP-3 of this section.
Where:
CO2 = Annual mass of CO2 (metric tons)
supplied in containers delivered by all CO2 streams.
CO2,u = Annual mass of CO2 (metric tons)
supplied in containers delivered by CO2 stream u.
u = CO2 stream that delivers to containers.
(c) Importers or exporters that import or export CO2 in
containers shall calculate the total mass of CO2 imported or
exported in metric tons based on summing the mass in each
CO2 container using weigh bills, scales, or load cells
according to Equation PP-4 of this section.
* * * * *
53. Section 98.424 is amended by revising paragraphs (a)(1),
(a)(2), (a)(5)introductory text, (a)(5)(ii), the last sentence in
paragraph (b)(2); and by adding paragraph (c) to read as follows:
Sec. 98.424 Monitoring and QA/QC requirements.
(a) * * *
(1) Reporters following the procedures in paragraph (a) of Sec.
98.423 shall determine quantity using a flow meter or meters located in
accordance with this paragraph.
(i) If the CO2 stream is segregated such that only a
portion is captured for commercial application or for injection, you
must locate the flow meter after the point of segregation.
(ii) Reporters that have a mass flow meter or volumetric flow meter
installed to measure the flow of a CO2 stream that meets the
requirements of paragraph (a)(1)(i) of this section shall base
calculations in Sec. 98.423 of this subpart on the installed mass flow
or volumetric flow meters.
(iii) Reporters that do not have a mass flow meter or volumetric
flow meter installed to measure the flow of the CO2 stream
that meets the requirements of paragraph (a)(1)(i) of this section
shall base calculations in Sec. 98.423 of this subpart on the flow of
gas transferred off site using a mass flow meter or a volumetric flow
meter located at the point of off-site transfer.
(2) Reporters following the procedures in paragraph (b) of Sec.
98.423 shall determine quantity in accordance with this paragraph.
(i) Reporters that supply CO2 in containers using weigh
bills, scales, or load cells shall measure the mass of contents of each
CO2 container to which the CO2 stream delivered,
sum the mass of contents supplied in all containers to which the
CO2 stream delivered during each quarter, sample the
CO2 stream delivering CO2 to containers on a
quarterly basis to determine the composition of the CO2
stream, and apply Equation PP-1.
(ii) Reporters that supply CO2 in containers using
loaded container volumes shall measure the volume of contents of each
CO2 container to which the CO2 stream delivered,
sum the volume of contents supplied in all containers to which the
CO2 stream delivered during each quarter, sample the
CO2 stream on a quarterly basis to determine the composition
of the CO2 stream, determine the density quarterly, and
apply Equation PP-2.
* * * * *
(5) Reporters using Equation PP-2 of this subpart shall determine
the density of the CO2 stream on a quarterly basis in order
to calculate the mass of the CO2 stream according to one of
the following procedures:
* * * * *
(ii) You shall follow industry standard practices.
[[Page 48814]]
(b) * * *
(2) * * * Acceptable methods include U.S. Food and Drug
Administration food-grade specifications for CO2 (see 21 CFR
184.1240) and ASTM standard E1747-95(Reapproved 2005) Standard Guide
for Purity of Carbon Dioxide Used in Supercritical Fluid Applications
(incorporated by reference, see Sec. 98.7 of subpart A of this part).
(c) If you measure the flow of the CO2 stream with a
volumetric flow meter, you shall convert all measured volumes of carbon
dioxide to the following standard industry temperature and pressure
conditions: standard cubic meters at a temperature of 60 degrees
Fahrenheit and at an absolute pressure of 1 atmosphere. If you apply
the density value for CO2 at standard conditions, you must
use must use 0.0018704 metric tons per standard cubic meter.
54. Section 98.425 is amended by adding a new paragraph (d) to read
as follows:
Sec. 98.425 Procedures for estimating missing data.
* * * * *
(d) Whenever the quality assurance procedures in Sec. 98.424(a)(2)
of this subpart cannot be followed to measure quarterly quantity of
CO2 in containers, the most appropriate of the following
missing data procedures shall be followed:
(1) A quarterly quantity of CO2 in containers that is
missing may be substituted with a quarterly value measured during
another representative quarter of the current reporting year.
(2) A quarterly quantity of CO2 in containers that is
missing may be substituted with a quarterly value measured during the
same quarter from the past reporting year.
(3) The quarterly quantity of CO2 in containers recorded
for purposes of product tracking and billing according to the
reporter's established procedures may be substituted for any period
during which measurement equipment is inoperable.
55. Section 98.426 is amended by:
a. Revising paragraphs (a) introductory text and (a)(2).
b. Adding a new paragraph (a)(5).
c. Revising paragraphs (b) introductory text and (b)(2).
d. Adding a new paragraph (b)(7).
e. Revising paragraphs (c) and (e)(1).
Sec. 98.426 Data reporting requirements.
* * * * *
(a) If you use Equation PP-1 of this subpart, report the following
information for each mass flow meter or CO2 stream that
delivers CO2 to containers:
* * * * *
(2) Quarterly mass in metric tons of CO2.
* * * * *
(5) The location of the flow meter in your process chain in
relation to the points of CO2 stream capture, deyhdration,
compression, and other processing.
(b) If you use Equation PP-2 of this subpart, report the following
information for each volumetric flow meter or CO2 stream
that delivers CO2 to containers:
* * * * *
(2) Quarterly volume in standard cubic meters of CO2.
* * * * *
(7) The location of the flow meter in your process chain in
relation to the points of CO2 stream capture, deyhdration,
compression, and other processing.
(c) If you use Equation PP-3 of this subpart report the annual
CO2 mass in metric tons from all flow meters and
CO2 streams that delivers CO2 to containers.
* * * * *
(e) * * *
(1) The type of equipment used to measure the total flow of the
CO2 stream or the total mass or volume in CO2
containers.
* * * * *
[FR Doc. 2010-18354 Filed 8-10-10; 8:45 am]
BILLING CODE 6560-50-P