[Federal Register Volume 75, Number 242 (Friday, December 17, 2010)]
[Rules and Regulations]
[Pages 79092-79171]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-30286]
[[Page 79091]]
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Part II
Environmental Protection Agency
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40 CFR Part 98
Mandatory Reporting of Greenhouse Gases; Final Rule
Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 /
Rules and Regulations
[[Page 79092]]
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ENVIRONMENTAL PROTECTION AGENCY
40 CFR Part 98
[EPA-HQ-OAR-2008-0508; FRL-9234-7]
RIN 2060-AQ33
Mandatory Reporting of Greenhouse Gases
AGENCY: Environmental Protection Agency (EPA).
ACTION: Final rule.
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SUMMARY: EPA is amending specific provisions in the greenhouse gas
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 final changes include generally
providing additional information and clarity on existing requirements,
allowing greater flexibility or simplified calculation methods for
certain sources, amending data reporting requirements to provide
additional clarity on when different types of greenhouse gas emissions
need to be calculated and reported, clarifying terms and definitions in
certain equations and other technical corrections and amendments.
DATES: The final rule is effective on December 31, 2010. The
incorporation by reference of certain publications listed in the final
rule amendments are approved by the director of the Federal Register as
of December 31, 2010.
ADDRESSES: EPA has established a docket under Docket ID No. EPA-HQ-OAR-
2008-0508 for this action. 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., confidential business
information (CBI) or other information whose disclosure is restricted
by statute. Certain other material, such as copyrighted material, is
not placed on the Internet and will be publicly available only in hard
copy form. Publicly available docket materials are available either
electronically through http://www.regulations.gov or in hard copy at
EPA's Docket Center, Public Reading Room, 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 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 and implementation
materials, please go to the Greenhouse Gas Reporting Program Web site
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To
submit a question, select Rule Help Center, followed by Contact Us.
SUPPLEMENTARY INFORMATION: 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 final amendments to existing regulations.
These amended regulations affect owners or operators of certain
suppliers and direct emitters of greenhouse gases (GHGs). Regulated
categories and entities include those listed in Table 1 of this
preamble:
Table 1--Examples of Affected Entities by Category
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Examples of affected
Category NAICS facilities
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General Stationary Fuel .............. Facilities operating
Combustion Sources. boilers, process
heaters, incinerators,
turbines, and internal
combustion engines.
211 Extractors of crude
petroleum and natural
gas.
321 Manufacturers of lumber
and wood products.
322 Pulp and paper mills.
325 Chemical manufacturers.
324 Petroleum refineries
and manufacturers of
coal products.
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 325120 Chlorodifluoromethane
Destruction. 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.
Nitric Acid Production......... 325311 Nitric acid production
facilities.
Petrochemical Production....... 32511 Ethylene dichloride
production facilities.
[[Page 79093]]
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 \a\.......... 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 221210 Natural gas
NGLs. distribution
facilities.
211112 Natural gas liquid
extraction facilities.
Suppliers of Industrial GHGs... 325120 Industrial gas
production facilities.
Suppliers of Carbon Dioxide 325120 Industrial gas
(CO2). production facilities.
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\a\ EPA will not be implementing subpart JJ of 40 CFR part 98 using
funds provided in its FY2010 appropriations or Continuing
Appropriations Act, 2011 (Pub. L. 111-242), due to a Congressional
restriction prohibiting the expenditure of funds for this purpose.
Table 1 of this preamble is not intended to be exhaustive, but
rather provides a guide for readers regarding facilities and suppliers
likely to be affected by this action. Table 1 of this preamble lists
the types of facilities and suppliers that EPA is now aware could be
potentially affected by the reporting requirements. Other types of
facilities and suppliers 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 subparts. If you have questions regarding the applicability of this
action to a particular facility or supplier, consult the person listed
in the preceding FOR FURTHER INFORMATION CONTACT section.
What is the effective date? The final rule is effective on December
31, 2010. Section 553(d) of the Administrative Procedure Act (APA), 5
U.S.C. Chapter 5, generally provides that rules may not take effect
earlier than 30 days after they are published in the Federal Register.
EPA is issuing this final rule under section 307(d)(1) of the Clean Air
Act, which states: ``The provisions of section 553 through 557 * * * of
Title 5 shall not, except as expressly provided in this section, apply
to actions to which this subsection applies.'' Thus, section 553(d) of
the APA does not apply to this rule. EPA is nevertheless acting
consistently with the purposes underlying APA section 553(d) in making
this rule effective on December 31, 2010. Section 5 U.S.C. 553(d)(3)
allows an effective date less than 30 days after publication ``as
otherwise provided by the agency for good cause found and published
with the rule.'' As explained below, EPA finds that there is good cause
for this rule to become effective on December 31, 2010, even though
this results in an effective date fewer than 30 days from date of
publication in the Federal Register.
While this action is being signed prior to December 1, 2010, there
is likely to be a significant delay in the publication of this rule as
it contains complex equations and tables and is relatively long in
length. As an example, EPA signed a shorter technical amendments
package related to the same underlying reporting rule on October 7,
2010, and it was not published until October 28, 2010 (75 FR 66434),
three weeks later.
The purpose of the 30-day waiting period prescribed in 5 U.S.C.
553(d) is to give affected parties a reasonable time to adjust their
behavior and prepare before the final rule takes effect. Where, as
here, the final rule will be signed and made available on the EPA Web
site more than 30 days before the effective date, but where the
publication is likely to be delayed due to the complexity and length of
the rule, that purpose is still met. Moreover, most of the revisions
being made in this package provide flexibilities to sources covered by
the reporting rule, or otherwise relieve a restriction. Thus, a shorter
effective date in such circumstances is consistent with the purposes of
APA section 553(d), which provides an exception for any action that
grants or recognizes an exemption or relieves a restriction.
Accordingly, we find good cause exists to make this rule effective on
December 31, 2010, consistent with the purposes of 5 U.S.C. 553(d)(3).
Judicial Review. Under section 307(b)(1) of the CAA, judicial
review of this final rule is available only by filing a petition for
review in the U.S. Court of Appeals for the District of Columbia
Circuit (the Court) by February 15, 2011. Under CAA section
307(d)(7)(B), only an objection to this final rule that was raised with
reasonable specificity during the period for public comment can be
raised during judicial review. CAA section 307(d)(7)(B) also provides a
mechanism for EPA to convene a proceeding for reconsideration, ``[i]f
the person raising an objection can demonstrate to EPA that it was
impracticable to raise such objection within [the period for public
comment] or if the grounds for such objection arose after the period
for public
[[Page 79094]]
comment (but within the time specified for judicial review) and if such
objection is of central relevance to the outcome of the rule.'' Any
person seeking to make such a demonstration to us should submit a
Petition for Reconsideration to the Office of the Administrator,
Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200
Pennsylvania Ave., NW., Washington, DC 20460, with a copy to the person
listed in the preceding FOR FURTHER INFORMATION CONTACT section, and
the Associate General Counsel for the Air and Radiation Law Office,
Office of General Counsel (Mail Code 2344A), Environmental Protection
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, under
CAA section 307(b)(2), the requirements established by this final rule
may not be challenged separately in any civil or criminal proceedings
brought by EPA to enforce these requirements.
Acronyms and Abbreviations. The following acronyms and
abbreviations are used in this document.
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
CAA Clean Air Act
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
FR Federal Register
FTIR Fourier transform infrared
GC gas chromatography
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GPA Gas Processors Association
GWP global warming potential
HFCs hydrofluorocarbons
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
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
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
scf standard cubic feet
scfm standard cubic feet per minute
SF6 sulfur hexafluoride
SO2 sulfur dioxide
SWPB side worked prebake
U.S. United States
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 will these amendments apply to 2011 reports?
II. Final Amendments and Responses to Public Comments
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
K. Congressional Review Act
I. Background
A. How is this preamble organized?
The first section of this preamble contains the basic background
information about the origin of these rule amendments. This section
also discusses EPA's use of our legal authority under the CAA to
collect data on GHGs.
The second section of this preamble describes in detail the rule
changes that are being promulgated to, among other things, correct
technical errors, provide clarification, and address implementation
issues identified by EPA and others. This section also presents a
summary and EPA's response to the major public comments submitted on
the proposed rule amendments, and significant changes, if any, made
since proposal in response to those comments.
Finally, the last (third) section discusses the various statutory
and executive order requirements applicable to this rulemaking.
B. Background on This Action
The final Mandatory Reporting of Greenhouse Gases Rule 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). This
rule, which added Part 98 to chapter 40 of the Code of Federal
Regulations (CFR) as well as amending other parts of 40 CFR, became
effective on December 29, 2009, and 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 certain suppliers (e.g., fossil fuel,
petroleum products, industrial gases and CO2) and
manufacturers of mobile sources.
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\1\ Consolidated Appropriations Act, 2008, Pub. L. 110-161, 121
Stat. 1844, 2128.
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EPA published a notice proposing these amendments to Part 98 to,
among other things, correct certain technical and editorial errors that
have been identified since promulgation and clarify or propose
amendments to certain provisions that have been the subject of
questions from reporting entities. The proposal was published on
[[Page 79095]]
August 11, 2010 (75 FR 48744). The public comment period for the
proposed rule amendments ended on September 27, 2010. EPA did not
receive any requests to hold a public hearing.
This is the second time that EPA has published a notice
promulgating amendments to Part 98 to, among other things, correct
certain technical and editorial errors identified since Part 98 was
originally promulgated and to clarify and amend certain provisions that
have been the subject of questions from reporting entities. The first
final rule amendments were published on October 28, 2010 (75 FR 66434).
This final rule complements the final rule published on October 28,
2010 and is not intended to duplicate or replace those amendments.
C. Legal Authority
EPA is promulgating these rule amendments under its existing CAA
authority, specifically authorities provided in CAA section 114.
As stated in the preamble to the 2009 final rule (74 FR 56260,
October 30, 2009), CAA section 114 provides EPA broad authority to
require the information mandated 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), CAA section 114(a)(1) authorizes the
Administrator to require emissions sources, persons subject to the CAA,
manufacturers of process or control equipment, and 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 will these amendments apply to 2011 reports?
We have determined that it is feasible for sources to implement
these changes for the 2010 reporting year because the revisions
primarily provide additional clarifications 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. Our rationale for this determination is
explained in the preamble to the proposed rule amendments.\3\ In
response to general comments submitted on the proposed rulemaking, we
have again reviewed the final amendments and determined that, with one
limited exception, they can be implemented, as finalized, for the 2010
reporting year.
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\3\ 75 FR 48747 (August 11, 2010).
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The one new requirement, regarding reporting of biogenic
CO2 emissions from units subject to 40 CFR Part 75, is being
phased in, so that it remains optional for reporting year 2010, but
becomes mandatory for each subsequent year. Therefore this revision, as
finalized, already accommodates implementation for the 2010 reporting
year.
In summary, except for the exception discussed above regarding
biogenic CO2 emissions, these amendments do not require any
additional monitoring or data collection above what was already
included in Part 98. Therefore, we have determined that reporters can
use the same information that they have been collecting under Part 98
for each subpart to calculate and report GHG emissions for 2010 and
submit reports in 2011 under the amended subparts.
Following is a brief summary of major comments and responses.
Several comments were received on this topic. Responses to additional
significant comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Several commenters requested that we make use of the
amendments optional for the 2010 reporting year and mandatory beginning
with the 2011 reporting year. The commenters expressed concern that in
2010, sources may not have been collecting the required data to
implement certain amendments.
Response: We sought comment on the feasibility of incorporating the
proposed revisions for the 2010 reporting year. In the proposal, we
explained that we felt implementation for the 2010 reporting year would
be feasible because the proposed revisions, to a great extent, would
simply clarify existing regulatory requirements or add flexibility to
the rule. Further, the proposed amendments would not substantially
affect the type of information that must be collected or how emissions
are calculated. We sought comment on this conclusion and 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 requested that commenters provide specific reasons why they
believe that the proposed implementation schedule would or would not be
feasible. We received some comments about making optional the use of
the amendments in 2010, as well as comments proposing to extend
submission of the first reports until June 1, 2011. We received a few
industry-specific examples providing a rationale for extending the
deadline for reporting, or making use of the amendments optional for
the 2010 reporting year. For example, some commenters expressed concern
that the proposed clarification of the definition of natural gas, as
well as the introduction of fuel gas into Table C-1, could affect
applicability under the rule and the use of the tiers under subpart C.
We have addressed the underlying concerns expressed by these
commenters, as EPA did not intend to change applicability or force
facilities to use higher tiered calculation methodologies. Therefore,
because we addressed the underlying concerns, we are finalizing
requirements to incorporate the amendments into 2010 reporting year
data.
II. Final Amendments and Responses to Public Comments
We are amending various subparts in Part 98 to correct errors in
the regulatory language that were identified as a result of working
with reporters to implement the various subparts of Part 98. We are
also amending certain rule provisions to provide greater clarity. The
amendments to Part 98 include the following types of changes:
Additional information to understand better or more fully
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.
Amendments, in limited cases, to allow for the use of
simplified emissions calculation methods.
Changes to correct cross references within and between
subparts.
Other amendments related to certain issues identified as a
result of working with reporters during rule implementation and
outreach.
Applying a threshold for reporting for local distribution
companies of equal to or greater than 460,000 thousand
[[Page 79096]]
standard cubic feet (mscf) of natural gas delivered per year.
Requiring separate reporting of biogenic CO2
emissions for units that are also subject to 40 CFR part 75, beginning
with the 2011 reporting year.
The final amendments promulgated by this action reflect EPA's
consideration of the comments received on the proposal. The major
public comments and EPA's responses for each subpart are provided in
this preamble. Our responses to additional significant public comments
on the proposal are presented in a comment response document available
in Docket ID No. EPA-HQ-OAR-2008-0508.
A. Subpart A--General Provisions: Best Available Monitoring Methods
1. Summary of Final Amendments and Major Changes Since Proposal
EPA is finalizing the petition process established in 40 CFR
98.3(j) that allows use of Best Available Monitoring Methods (BAMM)
past December 31, 2010 for owners and operators required to report
under subpart P (Hydrogen Production), subpart X (Petrochemical
Production), or subpart Y (Petroleum Refineries), under limited
circumstances. Owners or operators subject to these subparts can
petition EPA to extend use of BAMM past December 31, 2010, if
compliance with a specific provision in the regulation requires
measurement device installation, and installation would necessitate an
unscheduled process equipment or unit shutdown, or could be installed
only through a ``hot tap.'' If the application is approved, the owner
or operator can 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.
Process for requesting an extension of best available monitoring
methods. We are adding a similar petition process to that recently
concluded for the use of BAMM for 2010 in 40 CFR 98.3(j). The process
is for quantifying emissions from any source category at facilities
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 is allowable initially no later than December 31, 2013.
Subpart P, X, and/or Y owners or operators requesting to use BAMM
beyond 2010 are 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 will require a hot tap or
unscheduled shutdown.
Owners or operators must submit the full extension request for BAMM
by February 15, 2011. The full extension request must 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 could not be accomplished
in 2010 with supporting material, an estimated date for the next
planned maintenance outage, and a discussion of how emissions will be
calculated in the interim. More specifically, the full extension
request must 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 must also
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 can automatically use BAMM consistent with
their request through June 30, 2011. This automatic extension is
necessary because the current BAMM requests submitted by these
facilities will end no later than December 31, 2010. The BAMM must be
extended automatically to provide EPA the time to review thoroughly the
BAMM requests submitted for post-2010, while ensuring that the
petitioning facilities are not out of compliance with the rule during
that review process. All measurement devices must be installed by July
1, 2011 unless EPA approves the BAMM extension request before that
date.
Approval of extension requests. In any approval of an extension
request, EPA will 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 has until
the date approved by EPA to install the relevant remaining meters or
other measurement devices, however initial approvals will 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 is
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 process for BAMM will 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 adding a process by which owners or operators who
receive an extension will 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 postponed are
required to notify EPA within 4 weeks of such a determination, but no
later than 4 weeks before the date for 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
and thus they want to continue to use BAMM, they are required to re-
apply to use BAMM for one additional time period, not to extend beyond
December 31, 2015. To obtain an extension for the use of BAMM past
December 13, 2013, owners or operators are required to submit a new
extension request by June 1, 2013 that contains the information
required in 40 CFR 98.3(j)(4). All owners or operators that submit a
request under this paragraph to extend the use of best available
monitoring methods for measurement device installation are required to
install all measurement devices by December 31, 2013, unless the
additional extension request under this paragraph is approved by EPA.
[[Page 79097]]
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this topic. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: EPA received several comments, both in support of and in
opposition to, the proposed extension of BAMM for facilities subject to
subparts P, X and Y. Some commenters that supported the new BAMM
process also recommended that EPA extend the process beyond hydrogen
producers, petrochemical facilities and petroleum refineries. They
suggested that the same logic should apply to all facilities, that
installation of monitoring equipment should not require process
equipment or unit shutdown.
Other commenters were concerned that the new BAMM process conflicts
with the need for consistent data. The commenters urged that if EPA
nevertheless decides to finalize the requirements, there should be only
a one-time application process with BAMM ending no later than December
2013. Further, they asserted that EPA should require facilities to make
use of unplanned shutdowns as an opportunity to install equipment.
Response: EPA carefully considered the issues raised by commenters
and decided to retain the BAMM extension process, as proposed, only for
facilities subject to subparts P, X and Y. The proposal preamble sought
comment on this very issue and requested that commenters 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.
Commenters did not provide the requested information to support their
position that the provision should be extended to other industries. In
summary, the commenters argued only that EPA should provide this
flexibility, but did not provide a rationale as to why additional
industries needed the flexibility.
Regarding concerns that the new BAMM process would lead to
inconsistent data, EPA has determined that this limited opportunity for
a BAMM extension will provide sufficiently consistent data for these
industries without causing the unnecessary burden or potential safety
concerns that would be associated with installation of monitoring
devices during unplanned shutdowns or hot taps. EPA notes that the BAMM
process will still require facilities to follow the calculation methods
in the rule, but will allow owners or operators to use alternative
methods to provide the inputs to those calculations. Further, unlike
the BAMM process that was established by promulgation of the October
30, 2009 reporting rule (74 FR 56379-56380), any request for BAMM after
2010 will require EPA approval of a facility's proposed approach to be
implemented in lieu of the requirements in the rule. This further
ensures that EPA will continue to receive data of the appropriate
quality.
EPA decided not to limit BAMM to a one-time extension through 2013,
because we determined that the reasons supporting extension through
2013 were still valid post 2013. Specifically, facilities in these
particularly complex industries should not have to shut down
unnecessarily in order to install equipment. Data provided by these
industries show that some units, for example crude distillation units,
are shut down only every 4 to 7 years. Other units such as vacuum
distillation units, fluid catalytic cracking units, distillate
hydrotreating units, catalytic feed hydrotreaters, hydrocrackers,
coking units, sulfur recovery units and cogeneration units can be shut
down as infrequently as every 5 years (see final Background Technical
Support document to the Revision of Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule). Thus, providing a potential end
date for BAMM of December 31, 2015, is appropriate based on information
presented for these industries on the typical frequency of shutdown for
these facilities.
We also are not requiring a facility to order the measurement
equipment early and have it on hand in the event of an unplanned
shutdown before the scheduled shutdown. First, it would be hard to
enforce a requirement to install equipment during an unplanned shutdown
``if feasible'' because it would be hard to objectively determine
whether a facility should have installed equipment during an unplanned
shutdown. Moreover, during an unplanned shutdown, the priority is often
to get the equipment up and running as quickly and safely as possible;
therefore, there is not necessarily time to install the measurement
equipment.
Comment: In a related comment, one commenter raised concerns about
Tier 3 monitoring requirements for a stream at its facility that is
dangerous to monitor due to the presence of hydrogen cyanide. They
indicated that they used BAMM to implement an approach other than
direct sampling of the inputs to the equations for the 2010 reporting
year, and now are considering implementing the Tier 4 method for future
years. However, they argued the rule should provide a mechanism to
address these dangerous streams.
Response: No rule change has been made as a result of the comment.
For the 2010 reporting year, the BAMM provisions were designed for use
where it was not possible to acquire, install and operate a required
piece of equipment during the early months of the GHG Reporting
Program. Safety concerns were a valid reason for approving these early
BAMM applications.
Although the commenter notes concerns with conducting the Tier 3
method for quantifying emissions from stationary combustion at the
facility due to the presence of a hydrogen cyanide stream, EPA notes
that the rule does not limit them to use of a Tier 3 approach. As
acknowledged by the commenter, they also have the opportunity to use
Tier 4 to meet the requirements of the rule and, by taking advantage of
BAMM for 2010, had one year to install the Tier 4 equipment. The
commenter merely wants additional time beyond that already provided in
the rule to comply with the Tier 4 requirements. The commenter does not
justify the requested extension by pointing to issues like unplanned
shutdowns or hot taps, as discussed in the proposal. EPA has determined
the unique situation raised by the commenter does not warrant expanding
the BAMM process generally beyond industries subject to subparts P, X
and Y.
B. Subpart A--General Provisions: Calibration Requirements
1. Summary of Final Amendments and Major Changes Since Proposal
EPA has finalized amendments to 40 CFR 98.3(i)(1) to specify that
the calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3)
are 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
[[Page 79098]]
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) will continue to apply to
these meters.
We are also amending 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.
We are also amending 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
must be calibrated to meet the accuracy requirements of the relevant
subpart(s), or, in the absence of such requirements, 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 must be documented in the written
monitoring plan.
We are adding 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.
We are adding new paragraph 40 CFR 98.3(i)(1)(iii) to specify the
frequency at which subsequent recalibrations of flow meters and other
measurement devices must be performed. Recalibration must 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.
We are adding new paragraph 40 CFR 98.3(i)(7) to specify the
consequences of a failed flow meter calibration. Data become invalid
prospectively, beginning at the hour of the failed calibration and
continuing until a successful calibration is completed. Appropriate
substitute data values must be used during the period of data
invalidation.
In 40 CFR 98.3(i)(2) and (3), we are adding absolute value signs to
the numerators of Equations A-2 and A-3. These were inadvertently
omitted in the October 30, 2009 Part 98.
We are also amending 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 amending 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 are, as
described below, conditionally 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 is 4.0 percent. If
two assumed values are used and only the differential pressure
transmitter is calibrated, the maximum allowable calibration error is
2.0 percent.
We are also amending 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 must 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 can be
performed to determine the difference between the readings obtained
with the remote transmitters 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 must 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.
We are amending 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. 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 is exempted.
Section 98.3(i)(4) is being further amended to clarify that gas
billing meters are exempted from the monitoring plan and recordkeeping
provisions of 40 CFR 98.3(g)(5)(i)(c), (g)(6) 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, that
the results of all required certification and QA tests be kept, and
that maintenance records be kept for those instruments.
We are amending 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 is also
being amended to clarify that the deadline for successive calibrations
will be according to the manufacturer's recommended calibration
schedule or an industry consensus calibration schedule.
We are amending 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
[[Page 79099]]
normal process operation. Part 98 allowed the owner or operator to
postpone the initial calibration until the next scheduled maintenance
outage. Although the rule allowed postponement of calibration, it did
not specify how to report fuel consumption for the entire time period
extending from January 1, 2010 until the next maintenance outage. We
are amending 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 revision addresses situations
where the next scheduled outage is in 2011, or later.
The major change since proposal is identified in the following
list. The rationale for this and any other significant changes can be
found in this preamble or the document, ``Response to Comments:
Revision to Certain Provisions of the Mandatory Reporting of Greenhouse
Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Removed the words ``ignition'' and ``ignition fuel'' from
40 CFR 98.3(i)(4), so that only fuel flow meters that are used
exclusively for startup are exempted from the calibration requirements
of 40 CFR 98.3(i).
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this topic. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: We received several comments relating to the proposed
changes to the calibration accuracy requirements set in 40 CFR 98.3(i).
Commenters expressed concern that removing the rule-wide 5 percent
calibration accuracy requirement would compromise the rule's data
quality. The commenters noted that a global calibration accuracy
requirement is necessary to provide data that are accurate and
comparable within and across industries. By dropping this requirement,
the commenters believed small calibration errors will systematically
produce major errors in reported data. For measuring devices other than
flow meters they argued that it is not clear what an ``appropriate''
error range is, or what calibration standards a reporter would deem
``applicable,'' and suggest that by stating calibration standards are
``not limited to industry standards * * *, '' EPA is waiving
calibration requirements for other measuring devices altogether. They
acknowledge that there is a requirement to document the calibration
procedure used in the monitoring plan, but they believe it is not
enforceable and severely reduces transparency. The commenters contend
that the use of different calibration methods and varying levels of
accuracy would make it difficult to correctly interpret and compare the
emissions data, and would render future policy development very
difficult.
In summary, commenters that were concerned about our removal of the
blanket 5 percent calibration accuracy requirements asserted that EPA
has a mandate to implement the rule and cannot promulgate any
subsequent rule that would compromise the quality of the data reported.
They further argue that it is arbitrary and capricious, in light of
EPA's reporting mandate, to waive the calibration accuracy requirements
for any flow meters. All such meters, they contend, should be required
to meet these minimum accuracy requirements, with no exceptions.
Response: We acknowledge the concerns of the commenters and agree
that a high level of data quality is a valuable component of any
environmental program. However, we believe the changes to the
calibration accuracy requirements of 40 CFR 98.3(i) do not jeopardize
the integrity of the reporting program nor compromise EPA's ability to
use the data in the future to support climate policy development.
As originally promulgated, 40 CFR 98.3(i) required that ``all
measurement devices shall be calibrated to an accuracy of 5 percent.''
However, as promulgated, 40 CFR 98.3(i)(2) and (i)(3) only provided
calibration procedures for flow meters. No specific procedures were
provided for other measurement devices. As a result, measurement
devices other than flow meters would necessarily be calibrated
according to procedures specified in other subparts, industry consensus
methods, or manufacturer specifications.
In the ``Technical Support Document for Revision of Certain
Provisions: Proposed Rule for Mandatory Reporting of Greenhouse
Gases,'' dated July 8, 2010 (the TSD), vendor information on various
types of measuring devices shows accuracy ranges of significantly less
than 5 percent. Requiring the calibrations to be performed according to
the accuracy specified by the device manufacturer, rather than 5
percent, would likely actually increase the data accuracy of the rule.
In addition, we recognize that other programs to which reporters may be
subject impose calibration standards that will affect many of the
instruments used for reporting under Part 98. For example, the tested
accuracy of fuel flow meters and transmitter transducers used in the
Acid Rain Program from 2005 through 2009 was well below 1 percent.
As a result of the wide range of industries and measuring devices
used within each industry, we have determined it is not practical to
set a global calibration standard or method that would apply
generically to every measurement device. Replacing the 5 percent
requirement from the 2009 fine rule with manufacturer's specifications
or industry specific standards will provide a higher level of data
certainty across the rule while accommodating the wide variety of
industries and equipment covered by the rule. We think it is highly
unlikely that companies will choose to use arbitrary standards, as the
procedures and methods used to quality-assure the measurement data must
be listed in the facility or supplier's monitoring plan.
The commenters correctly note that the calibration accuracy
requirements of 40 CFR 98.3(i) have been removed where company records
or best available information are used. Since promulgation, we have
consistently affirmed that meters used to generate company records are
not required to be calibrated according to 40 CFR 98.3(i). The purpose
behind allowing the use of company records and best available
information was to permit companies to use fuel billing receipts or
other quality assured information they currently maintain. EPA
authorized the use of company records to alleviate burden and did not
intend for such data to be subject to additional calibration
requirements, which would defeat the purpose of this flexibility.
To be clear, we disagree with the commenter's assertions that we
are ``waiving'' any calibration accuracy requirements or that certain
types of flow meters would not have to be calibrated. All measurement
technologies, except for the limited exceptions in 40 CFR 98.3(i) must
meet calibration accuracy requirements. Further, most major emission
sources should be covered by either the requirements of 40 CFR 98.38(i)
or another program that provides a similarly, if not significantly
more, stringent accuracy requirement. We have concluded that the
amendments to the calibration accuracy requirements do not compromise
our ability to implement successfully this reporting rule.
[[Page 79100]]
Comment: One commenter pointed out an inconsistency in the proposed
rule regarding the term ``ignition fuel.'' EPA proposed to amend 40 CFR
98.3(i)(4) to exempt fuel flow meters that are used exclusively for
startup and ignition fuel from the calibration requirements of 40 CFR
98.3(i). However, EPA also proposed in 40 CFR 98.30(d) to exempt pilot
lights from GHG emission reporting requirements. The commenter noted
that pilot lights are essentially the same as ignitors, and the
reference in 40 CFR 98.3(i)(4) to flow meters that measure ignition
fuel appears to imply that GHG emissions from the combustion of
ignition fuel must be reported.
Response: The GHG emissions reporting exemption for pilot lights in
40 CFR 98.30(d) refers to emissions from combustion of the fuel that
supplies the pilot light. Therefore, in the final rule, we have removed
the words ``ignition'' and ``ignition fuel'' from 40 CFR 98.3(i)(4).
Paragraph (i)(4) now refers only to startup fuel, which is distinctly
different from ignition fuel. For instance, at startup, a coal-fired
boiler may burn natural gas for several hours at high heat input
values, whereas a pilot light is a small flame that simply ignites or
initiates combustion of the main fuel (e.g., fuel oil).
C. Subpart A--General Provisions: Reporting of Biogenic Emissions
1. Summary of Final Amendments and Major Changes Since Proposal
Under the proposed amendments, EPA's goal was to reflect in
regulatory language clarifications that have been issued stating that
separate reporting of biogenic emissions for units subject to 40 CFR
part 75 was optional. To clarify this optional reporting, we proposed
to amend the data elements in subpart A (specifically 40 CFR
98.3(c)(4)) and subpart C that currently require separate accounting
and reporting of biogenic CO2 emissions so that it is
optional for units that are subject to subpart D of this part or units
that use the methods in part 75 to quantify CO2 mass
emissions in accordance with 40 CFR 98.33(a)(5) (40 CFR part 75 units
or ``part 75 units''). More specifically, to effect this clarification,
we proposed to revise the reporting for all facilities such that all
facilities would report combined non-biogenic and biogenic
CO2, and all facilities, except those with ``part 75
units,'' would still have been required to calculate and report
biogenic CO2 emissions separately.
We received numerous adverse comments on the proposed amendments
that would re-structure 40 CFR 98.3(c)(4) and clarify that separate
reporting of biogenic CO2 emissions was optional for ``part
75 units''. Most commenters urged EPA to make separate reporting of
biogenic emissions mandatory for all reporters. Many commenters also
objected to the restructuring of 40 CFR 98.3(c)(4), which would have
had all units reporting combined biogenic and non-biogenic
CO2 emissions.
Based on the comments received, we have decided to withdraw the
proposed re-structuring of 40 CFR 98.3(c)(4). We have also reconsidered
the optional reporting of biogenic CO2 emissions reporting
for ``part 75 units''. In the final rule, a new paragraph, (c)(12), has
been added to 40 CFR 98.3(c), which states that reporting biogenic
CO2 is optional for ``part 75 units'' only for the first
year of the program (i.e., for the 2010 reporting year). Thereafter,
all ``part 75 units'' must separately report their biogenic
CO2 emissions. We are allowing the optional biogenic
CO2 emissions reporting for the 2010 reporting year in light
of the 2009 final rule, as well as our previous statements and guidance
on the issue. It is likely that at least some 40 CFR part 75 sources
are following that policy guidance and have elected not to separately
report biogenic CO2 emissions. It is equally likely that
these sources have not been keeping the necessary records or performing
the required emission testing to enable them to report these emissions
for 2010.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Retaining the facility level reporting requirements from
the 2009 final rule (74 FR 56373) in 40 CFR 98.3(c)(4) that requires
reporting of CO2 emissions (excluding biogenic
CO2) and separate reporting of biogenic emissions.
Introducing new paragraph 40 CFR 98.3(c)(12) that allows
facilities with 40 CFR part 75 units the option to include biogenic
emissions in their facility totals for the 2010 reporting year only.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this topic. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: EPA received a large number of comments related to the
proposed amendments to make separate reporting of biogenic
CO2 emissions optional for units subject to 40 CFR part 75.
The three main concerns, each raised by multiple commenters, were that
(1) all reporters should be required to separately report biogenic
CO2 emissions; (2) reporters should never be required to
combine fossil CO2 and biogenic CO2; and, (3) if
EPA nevertheless finalizes requirements allowing separate reporting of
biogenic CO2 to be optional for units subject to 40 CFR part
75, then EPA's implementation of the proposed revisions should be
narrower in scope and not affect reporting requirements for all
reporters.
Regarding the first issue, some commenters argued that the
requirements of the Acid Rain Program (ARP) should not constrain EPA in
the GHG context and that all reporters under 40 CFR part 98 should be
required to report biogenic CO2 emissions, regardless of the
fact that such separate reporting is not a requirement in ARP.
Commenters suggested that this is important for consistency across the
GHG Reporting Program.
Several commenters suggested that it is never appropriate to
combine fossil CO2 and biogenic CO2 into a single
reported value. Commenters noted that there is a distinction between
fossil CO2 and biogenic CO2 and that in order to
ensure transparency for future climate policy these two values should
not be combined into a single reported emissions value. Further, they
argued that EPA's proposed requirement for sources to combine fossil
and biogenic emissions together in one total ignores the natural
biomass carbon cycle and is counter to the principle of ``carbon
neutrality,'' thereby overstating net CO2 entering the
atmosphere.
The commenters suggested that requiring separate reporting of
biogenic CO2 is consistent with the Intergovernmental Panel
on Climate Change and national, regional, and corporate GHG protocols
and that EPA should not depart from this established accounting
convention. These commenters also pointed out that EPA uses this same
rationale for requiring separate reporting of biogenic CO2
emissions in its own response to comments to the GHG Reporting Rule (74
FR 56351). Further, the commenters articulated that separate reporting
of biogenic emissions is necessary to
[[Page 79101]]
provide the public and policymakers with information on the extent of
biomass combustion and the sectors of the economy where biomass fuels
are used, which is information important for developing future climate
policy. Several organizations also commented that an accurate, economy-
wide inventory of biogenic CO2 emissions is important
because the evidence to date demonstrates that biomass is not
inherently carbon neutral.
Finally, commenters noted that if EPA nevertheless decides to
finalize the rule allowing optional reporting of biogenic
CO2 emissions for 40 CFR part 75 units, EPA should modify
the proposed rule so the amendments affect only facilities with part 75
units, and do not change the reporting requirements for all other
reporters. Commenters were concerned that EPA's proposed change
required all reporters to report total CO2 (including
biogenic CO2 emissions), but only required facilities with
non-part 75 units to report their biogenic emissions separately.
Facilities with part 75 units would have the option to report
separately biogenic CO2 from those units. The commenters
suggested that if EPA chooses to finalize optional separate reporting
for part 75 units, then EPA should revert to the reporting requirements
in subpart A that were in the 2009 final rule (i.e., report
CO2 excluding biogenic CO2) (74 FR 56379) for all
other reporters and add a new paragraph specifically for facilities
with part 75 units.
Response: We appreciate the significant feedback generated by the
proposed amendments designed to clarify that separate reporting of
biogenic emissions was optional for units subject to 40 CFR part 75. We
also recognize that many industry and environmental groups have
significant interest in the treatment of biomass in GHG reports, and
specifically in the accounting of biogenic CO2 emissions.
Based on the significant feedback received, including comments received
from facilities with 40 CFR part 75 units, as well as the fact that one
of the fundamental goals of the Greenhouse Gas Reporting Program
(GHGRP) is to collect data to support a range of potential future
climate policies, we have reconsidered our position and decided to make
the separate reporting of biogenic emissions mandatory for part 75
units beginning in the 2011 reporting year. Separate reporting of
biogenic CO2 emissions is optional for these units in the
2010 reporting year.
Per the requirements in the new paragraph 40 CFR 98.3(c)(12),
facilities with one or more part 75 units must elect in the 2010
reporting year whether to report biogenic CO2 emissions from
40 CFR part 75 units separately, or report only total CO2
emissions (including biogenic CO2) for the 40 CFR part 75
units at their facility. Beginning in the 2011 reporting year, these
facilities must separately report biogenic CO2 emissions for
the entire facility per the requirements in 40 CFR 98.3(c)(4), like all
other facilities.
In addition, the final rule does not adopt the proposed
restructuring of 40 CFR 98.3(c)(4) and leaves in place the facility-
level reporting requirements in 40 CFR 98.3(c)(4) for any facility in
2010 or for future years. All other facilities, except those with part
75 units, must, as finalized in the 2009 final rule, report
CO2 (excluding biogenic CO2) and then report
separately biogenic CO2 emissions. We would note that
neither the original proposed amendments, nor the amendments finalized
today, affect the fact that biogenic CO2 emissions are
excluded from the applicability determination under 40 CFR 98.2.
Commenters provided many reasons for supporting mandatory separate
reporting of biogenic CO2 emissions from all facilities,
including the increased transparency that such reporting brings. Some
commenters supported the assumption of the carbon neutrality of biomass
while others dispelled it, but both sides were united in their comments
that it is important to understand the GHG emissions associated with
biomass consumption. Our decision to also require separate reporting of
biogenic emissions for units that use the methods in 40 CFR part 75 is
founded solely on the principle that having data available at a more
disaggregated level for a reporting program like this one improves
transparency and better enables us and other stakeholders to use the
data to evaluate future potential policy options, without prejudging
what those policies might be. This decision is not based on any
conclusions about ``carbon neutrality'' or the appropriateness of
combining fossil CO2 and biogenic CO2 into a
single value.\4\ Rather, EPA's approach preserves the flexibility for
the Agency and for stakeholders to understand reported CO2
emissions in multiple ways. Despite the benefits of having separate
data with which to distinguish biogenic CO2 emissions, which
we do not dispute, the 2009 final rule did not require this reporting
for units subject to 40 CFR part 75. This is consistent with the
Response to Comments document for subpart D of the final rule \5\ where
it states ``It is EPA's intent that Acid Rain Program units will be
able to continue to measure and report CO2 emissions as they
do under the Acid Rain Program'' which did not require separate
reporting of biogenic CO2. However, when we opened the
relevant paragraphs to notice and comment, we received overwhelming
support for making the separate reporting of biogenic CO2
emissions mandatory, including from facilities with part 75 units. This
support, in combination with the value of having the data for policy
analysis, led us to reconsider our position and require separate
reporting of biogenic CO2 emissions beginning in the 2011
reporting year for the 40 CFR part 75 units. We decided to retain
optional reporting for the 2010 reporting year due to the fact that we
have provided guidance indicating that separate reporting was optional
for these part 75 units, and therefore, some facilities may not have
incorporated procedures into their monitoring plans or developed
internal systems for collecting the necessary information to facilitate
the biogenic CO2 emissions calculations.
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\4\ EPA requested comment on approaches to accounting for GHG
emissions from bioenergy and other biogenic sources earlier this
year. The Call for Information (75 FR 41173 and 75 FR 45112),
supporting information and comments can be found in docket EPA-HQ-
OAR-2010-0560. Please refer to those documents for more information
about this issue.
\5\ Mandatory Greenhouse Gas Reporting Rule, EPA's Response to
Public Comments, Volume 16, Subpart D Electricity Generation. Found
at http://www.epa.gov/climatechange/emissions/downloads09/documents/SubpartD-CommentReponses.pdf.
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To implement the changes described above, we are adding new
paragraph 40 CFR 98.3(c)(12), as well as amending paragraphs 40 CFR
98.33(e) (to provide an additional option for part 75 units to
calculate the biogenic CO2 emissions), 40 CFR 98.34(f),
several paragraphs in 40 CFR 98.36(d), and 40 CFR 98.43.
D. Subpart A--General Provisions: Requirements for Correction and
Resubmission of Annual Reports
1. Summary of Final Amendments and Major Changes Since Proposal
Subpart A, as promulgated in October 2009, required 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. * * *'' We are amending 40
CFR 98.3(h) to clarify the types of errors that trigger a resubmission
and the process for resubmitting annual GHG reports.
First, reports only have to be resubmitted when the owner or
operator or the Administrator determines that a
[[Page 79102]]
substantive error exists. A substantive error is 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 non-significant errors
will not obligate the owner or operator to resubmit the annual report.
The owner or operator is required to resubmit the report within 45
days of identifying the substantive error, or of being notified by the
Administrator 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 amendment provides
owners and operators the opportunity to demonstrate whether an error
the Administrator has deemed to be a substantive error is not, in fact,
a substantive error.
Finally, we are also allowing owners and operators to request an
extension of 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 and operators are 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 will be granted if EPA does not respond to the extension
request by the end of the 45-day period.
We are including 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 will 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 and
suppliers 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 and suppliers.
There have been no major changes from proposal regarding
requirements for correction and resubmission of annual reports.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: One commenter, representing several organizations, was
concerned that the amended process for submitting revised annual GHG
reports upon identification or notification by EPA of an error was too
complex and would substantially slow down correction of reported
errors. Generally, they asserted that the 45-day process that was in
the final Part 98 (74 FR 56381) should be appropriate for most
reporters, and to the extent there were any outliers, then EPA could
use enforcement discretion for those specific reporters as opposed to
changing the rule for all reporters. The commenter was further
concerned that EPA proposed to allow reporters to extend their
resubmission deadline in the event of a disagreement between EPA and
the reporter, by at least 30 days. The commenters suggested that the
process does not give EPA a clear method to dispute these points with
operators, does not specify that EPA's view trumps the operator's
opinion, and does not allow members of the public to argue that an
error is, in fact, substantive, and must be corrected. They contended
that the overall process could take months or years to correct errors,
and the operators may still refuse to correct some of them. They argued
this is a departure from the existing rule, and serves only to hinder
what was a straightforward and effective process.
Response: The process in these final rule amendments for submission
of revised annual GHG reports to correct any substantive errors in
these reports is reasonable and consistent with the purpose of the GHG
Reporting Program. The purpose of these reporting requirements is to
provide EPA with accurate and timely information on greenhouse gases in
order to gain a better understanding of the relative emissions of
specific industries and facilities, the factors that influence emission
rates, and the actions that facilities could in the future, or already
take, to reduce emissions. In light of this purpose, it is reasonable
to focus an ongoing requirement to correct errors in an annual report
on ``substantive errors,'' i.e., errors that affect emissions data
quality, validation, or verification. Further, because this is a new
program covering a wide variety of industries and processes, some of
whom may not be familiar with GHG accounting and reporting, we have
determined that under these circumstances it is reasonable to establish
a procedure engaging owners and operators on whether the annual report
actually contains identified ``substantive errors.''
The commenters' claims that this procedure provides no ``clear
method'' of determining what are substantive errors, may take ``months,
perhaps years,'' may result in owners refusing to correct errors, and
is unnecessary are unsupported and speculative. First, EPA has
concluded that the definition of ``substantive error''--an error that
impacts emissions data quality or otherwise prevents the data from
being validated or verified--is reasonably clear and is consistent with
the purposes of GHG emissions reporting. The commenter fails to show
what is unclear about this definition, nor why it is unreasonable to
focus corrections on substantive errors, versus insignificant ones that
do not impact the accuracy of submitted information.
Second, these final rule amendments set time limits for correction
of substantive errors, i.e., correction through submission of a revised
annual GHG report within 45 days of discovery (or notification by EPA
of the errors) plus any ``reasonable extensions'' of time (including
one automatic 30 day extension). The commenter fails to provide any
basis for conflating these limited time frames into periods of many
months or years. Further, because refusal by an owner or operator to
correct substantive errors within the appropriate time frame would be a
violation of the CAA and subject to significant civil penalties, the
commenter has no basis for assuming that owners and operators would
simply refuse to make the corrections.
Third, the error correction process provides a standard process
that is applicable to all owners and operators and that owners and
operators and EPA can use to attempt to resolve issues concerning error
correction. EPA has determined that this process will likely result in
more efficient error correction and resolution of error correction
issues by setting a limited time for contesting EPA's identification of
substantive errors. In addition, EPA's provision of a standard process
provides more certainty for owners and operators of an
[[Page 79103]]
opportunity to resolve issues than if EPA were simply to rely on
enforcement discretion, as recommended by a commenter.
The commenters also claimed the public will have no opportunity to
argue that errors are substantive and should be corrected. However,
this does not represent a change from the error correction process
under the 2009 final rule. The amendments for resubmission of annual
reports did not change public involvement in the resubmission process.
The process in today's rule better focuses the resources of EPA,
regulated industries and the public on those errors that are most
relevant to generating accurate data.
Comment: Several commenters requested that EPA provide a numerical
determination of what is a ``substantive error.'' One commenter
proposed a +/- 10 percent change in the reported GHG emissions value as
a result of the identified error. Another commenter requested that EPA
clarify that substantive errors are only those that exceed 1 percent to
5 percent of the total annual CO2 equivalent emissions.
One commenter requested that, in the final preamble, EPA clarify
that any error not be considered substantive unless it exceeds 1
percent to 5 percent of the total annual CO2 equivalent
(``CO2e'') emission amount reported by an individual
reporting facility. The commenter also requested that EPA modify the
``contains one or more substantive errors'' language to allow the
agency flexibility to investigate potential as well as documented
errors.
Response: The final rule defines substantive error as an error that
impacts the quantity of GHG emissions reported or otherwise prevents
the reported data from being validated or verified. EPA has determined
that it is not appropriate to establish a threshold below which errors
do not have to be corrected and resubmitted. EPA has determined that if
an error in the GHG emissions estimate occurs, then that emissions
error should be corrected and the annual GHG emissions report
resubmitted. If a facility were to go through the process of
identifying the estimate in GHG emissions, calculating what the GHG
emissions total should have been, and then determining the percent
difference between the original reported estimate and the revised
estimate, then the reporter has all of the information necessary to
report that revised estimate.
E. Subpart A--General Provisions: Information To Record for Missing
Data Events
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.3(g)(4) by removing requirements to
maintain records on the duration of a missing data event and actions
taken to minimize future occurrences, while retaining the requirement
that records be kept of the cause of each missing data event and the
corrective actions taken. We are also clarifying 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.
There have been no major changes from proposal regarding
recordkeeping requirements for missing data events.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Some commenters stated that although EPA has justified
this proposal by noting that 40 CFR part 75 does not require separate
accounting of ``the duration of missing data events or * * * actions
taken to minimize occurrence in the future,'' that alone is not
sufficient justification for not including these requirements under the
reporting program. The commenters asserted that part 75's requirements
do not constrain EPA's obligations in the GHG context. The commenters
wrote that reporting the duration of a missing data event cannot be
considered overly burdensome because reporters that accurately use
missing data procedures must know the duration of missing data events
and so must be collecting this information regardless. Also, the
commenters indicated that most facilities covered by the rule do not
use CEMS, and thus, EPA should not change the ``minimize occurrence''
requirement for all reporters (CEMS users and non-CEMS users) because
missing data events associated with the use of CEMS often have no clear
measures to avoid similar occurrences in the future.
Response: With respect to removal of the requirement to record the
duration of a missing data event, EPA determined that the requirement
in 40 CFR 98.3(c)(8) to report the total number of hours in the year
that missing data are used for each data element provides sufficient
information for purposes of the GHG Reporting Program. Although the
``total number of hours'' will not provide information on the duration
of each missing data event, EPA will know the total fraction of the
year for which missing data are used for a particular data element. We
have determined that this information provides EPA sufficient
information on the extent of use of the missing data provisions for any
given reporter.
EPA also decided to remove recordkeeping requirements related to
``actions taken to prevent or minimize occurrence in the future'' after
considering the value of the potential loss of data as compared to the
burden of compliance with the rule as written. As described below, we
determined that sufficient information is available regarding missing
data without requiring this additional information.
First, reporters must report annual hours for each missing data
element. Through this reported data, EPA can identify whether missing
data is particularly prevalent for a given data element at a given
facility. Second, records must be retained on the cause of the event
and actions taken to restore malfunctioning equipment. If EPA elects to
review these records, this information, along with reported information
on the total hours of missing data for each data element, will suggest
whether the source is taking action to prevent or minimize occurrence
in the future. Therefore, we have determined that it is not necessary
to collect information specifically on actions taken to prevent or
minimize occurrence of missing data in the future.
EPA acknowledges the point made by the commenters that most
facilities subject to the rule do not use CEMS, and therefore, this
fact can not be used as a justification for removing requirements
related to minimizing future occurrence. Further, EPA agrees that
information on duration would likely be collected when following the
applicable missing data procedures. Nevertheless, based on the
preceding discussion, EPA has concluded that sufficient data will be
available on missing data through the required reporting of total
number of hours in the year that missing data are used for each data
element (per 40 CFR 98.3(c)(8)), and the recordkeeping requirements on
cause of the event and actions taken to restore malfunctioning
equipment. EPA has determined that requiring collection and retention
of additional data on duration and actions taken to prevent or minimize
occurrence
[[Page 79104]]
in the future is not necessary under the reporting program at this
time.
F. Subpart A--General Provisions: Other Technical Corrections and
Amendments
1. Summary of Final Amendments and Major Changes Since Proposal
We are making several additional amendments to subpart A, as
follows.
We are making technical corrections to 40 CFR 98.3(c)(4)(i) through
(c)(4)(iii) and (c)(4)(vi) to clarify that facilities must report GHG
emissions from all applicable source categories, which includes general
stationary fuel combustion, miscellaneous carbonates and any other
source category covered by Part 98. This is consistent with the
language in the 2009 final rule which required facilities to report
emissions from all applicable source categories in subparts C through
JJ. In a recent final rule (July 12, 2010, 75 FR 39736) we updated 40
CFR 98.2 to remove the lists of source categories covered by the rule
and replace the list with Tables, specifically Table A-3 and Table A-4
of this chapter. This change was merely a reorganization and did not
change applicability under the rule. The reformatting from lists to
tables would enable EPA to add source categories in the future, and
therefore add new subparts to the rule, without having to update all
language referring to ``subparts C through JJ.'' In finalizing that
rule, we made the appropriate changes to 40 CFR 98.2 indicating
facilities must report GHG emissions from stationary fuel combustion
sources, miscellaneous use of carbonates and all applicable source
categories in Table A-3 and Table A-4. However, only the references to
Table A-3 and Table A-4 were carried over to 40 CFR 98.3(c), which
might suggest that facilities did not have to report emissions from
general stationary combustion, because combustion is not in Table A-3
or Table A-4. We are therefore amending 40 CFR 98.3(c) to clarify that
facilities must also report emissions from general stationary
combustion and miscellaneous use of carbonates.
We are amending 40 CFR 98.3(c)(5)(i) to clarify that for the
purposes of meeting the requirements of this paragraph, suppliers of
industrial fluorinated GHGs only need to calculate and report GHG
emissions in mtCO2e for those fluorinated GHGs that are
listed in Table A-1. Suppliers of industrial fluorinated GHGs do not
need to calculate and report GHG emissions in metric tons
CO2 equivalents (mtCO2e) for fluorinated GHGs not
listed in Table A-1. However, it is important to note that suppliers
are still required to report these gases under 40 CFR 98.3(c)(5)(ii)
(in metric tons of GHG).
We are amending 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 amending 40 CFR 98.3(f) to correct the cross-reference from
``Sec. 98.3(c)(8)'' to ``Sec. 98.3(c)(9).'' We are amending 40 CFR
98.3(g)(5)(iii) to correct a spelling error.
We are amending 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 adding the same element to
the delegation by designated representative and alternate designated
representative under 40 CFR 98.4(m)(2). Part 98 and the amendments do
not require the designated representative, alternate designated
representative, or agent to be an employee of the reporting entity. If
a designated representative further delegates their authority to an
agent the agent gains access to all data for that facility or supplier.
To underline the importance of granting access to the correct person,
EPA requires the designated representative (or alternate) to confirm
each agent delegation. Adding organization name to the certificate of
representation and notice of delegation adds a level of assurance to
the confirmation process.
Finally, we are amending 40 CFR 98.6 (Definitions) and 40 CFR 98.7
(What standardized methods are incorporated by reference into this
part?). We are adding or changing several definitions to subpart A,
which are needed to clarify terms used in other subparts of Part 98.
We are amending the definitions of several terms in 40 CFR 98.6:
Bulk natural gas liquid
Distillate fuel oil
Fossil fuel
Fuel gas
Municipal solid waste or MSW
Natural gas
Natural gas liquids, and
Standard conditions
Bulk natural gas liquid. We are amending the definitions of ``bulk
natural gas liquid or NGL'' and ``natural gas liquids (NGL)'' by
removing the phrase ``lease separators and field facilities'' for
enhanced clarity. We have retained the words ``or other methods'' in
both definitions because the list of separation processes in the
definitions (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
associated with products separated/extracted by means not explicitly
stated in the rule.
Distillate fuel oil. We are expanding the definition of
``Distillate fuel oil'' to include kerosene-type jet fuel.
Fossil fuel. We are amending the definition of fossil fuel, as
proposed, to read, ``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.'' This amendment finalizes the
same definition of fossil fuel that was originally proposed in April
2009 (74 FR 16621), but was subsequently amended in the final Part 98
(74 FR 56387). The change is not intended to have any impact on
coverage of greenhouse gases under the GHG Reporting Program.
Fuel gas. We are amending the definition of fuel gas to clarify
that it includes only gas generated at refineries or petrochemical
processes subject to subpart X and to remove the phrase ``or similar
industrial process unit.'' For a fuel explanation of this final change,
please see the Comments and Response discussion under Section II.G of
this preamble.
Municipal solid waste. We are amending the definition of municipal
solid waste to be similar to, but not exactly the same as, the
definition of ``municipal solid waste'' in subpart Ea of the NSPS
regulations (40 CFR 60.51a). The amended definition explains what is
meant by ``household waste,'' ``commercial/retail waste,'' and
``institutional waste.'' Household, commercial/retail, and
institutional wastes include yard waste, refuse-derived fuel, and motor
vehicle maintenance materials. Insofar as there is separate collection,
processing and disposal of industrial source waste streams consisting
of used oil, wood pallets, construction, renovation, and demolition
wastes (which includes, but is not limited to, railroad ties and
telephone poles), paper, clean wood, plastics, industrial process or
manufacturing wastes, medical waste, motor vehicle parts or vehicle
fluff, or used tires that do not contain hazardous waste identified or
listed under 42 U.S.C. 6921, such wastes are not municipal solid waste.
However, such wastes qualify as municipal solid waste where they are
collected with other municipal solid waste or are otherwise combined
with other municipal solid waste for processing and/or disposal.
Natural gas. We are finalizing the definition of natural gas to
remove any specifications regarding Btu value or methane content. The
final definition
[[Page 79105]]
reads, ``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.'' For a full explanation
of this final change, please see the Comments and Response discussion
under this section of the preamble.
Standard conditions. For consistency across the rule, and to
reflect typical operating procedures at various types of industries
covered by 40 CFR part 98, we are amending the definition of standard
conditions to mean either 60 or 68 degrees Fahrenheit and 14.7 pounds
per square inch absolute.
We are adding definitions of the following terms to 40 CFR 98.6 to
address the large number of questions received requesting clarification
on the meaning of these terms:
Agricultural by-products,
Primary fuel,
Solid by-products,
Used oil, and
Wood residuals.
We received no comments on the definitions of ``Agricultural by-
products,'' ``Primary fuel,'' and ``Solid by-products.'' Therefore,
these definitions have been finalized, as proposed. For the purposes of
Part 98, ``Agricultural by-products'' includes the parts of crops that
are not ordinarily used for food (e.g., corn straw, peanut shells,
pomace, etc.). ``Primary fuel'' is defined as the fuel that contributes
the greatest percentage of the annual heat input to a combustion unit.
``Solid by-products'' includes plant matter such as vegetable waste,
animal materials/wastes, and other solid biomass, except for wood, wood
waste and sulphite lyes (black liquor).
We proposed to add the term ``waste oil'' to Table C-1 but we
received comment use of the term ``waste oil'' could result in used oil
being classified as hazardous waste. We have therefore changed the term
to ``used oil.'' Used oil has been added to Table C-1 as a new fuel
type, and is defined as a petroleum-derived or synthetically-derived
oil whose physical properties have changed as a result of handling or
use, such that the oil cannot be used for its original purpose. Used
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). For a full explanation of this final change,
please see the Comments and Response discussion under this section of
the preamble.
The definition of ``wood residuals'' has been finalized similar to
the proposal, but EPA has also specifically included trim, sander dust,
and sawdust from wood products manufacturing (including resinated wood
product residuals) in the final definition.
We are amending 40 CFR 98.7 (Incorporation by reference) to
accommodate changes in the standard methods that are allowed by other
subparts of Part 98. The rationale for any additions or deletions of
methods in a particular subpart is discussed in the relevant subpart.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Not adopting the proposed amendments to 40 CFR 98.3(c)(1)
to report a facility or supplier ID number.
Clarifying the definition of municipal solid waste.
Clarifying that separate collection, processing and disposal of
industrial source waste streams consisting of used oil, wood pallets,
construction, renovation, and demolition wastes, clean wood, industrial
process or manufacturing wastes, medical waste, motor vehicle parts or
vehicle fluff, or used tires that do not contain hazardous waste
identified or listed under 42 U.S.C. 6921, are not municipal solid
waste. However, such wastes qualify as municipal solid waste where they
are collected with other municipal solid waste or are otherwise
combined with other municipal solid waste for processing and/or
disposal.
Finalizing the definition of natural gas to remove any
specifications regarding Btu value or methane content.
Amending the definition of standard conditions to provide
two alternatives.
Replacing the term ``waste oil'' with ``used oil.''
Amending the definition of ``wood residuals'' to include
trim, sander dust and sawdust from wood products manufacturing,
including resinated wood product residuals.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Several commenters objected to the proposed definition of
municipal solid waste or MSW. One commenter in particular pointed to
the regulatory history of the definition in 40 CFR 60, subpart Ea,
indicating that some of the materials excluded by the proposed
definition under 40 CFR part 98 are often included in MSW. According to
the commenter, some of the exclusions in subpart Ea were added to the
definition to provide an exemption to certain sources that combust
materials such as used oil or wood pellets separately. By excluding
materials often considered to be part of MSW, the commenter expressed
concern that the proposed definition of MSW in 40 CFR part 98 might
force some municipal waste combustors who considered themselves to be
combusting MSW and would therefore otherwise be allowed to use Tier 2,
to not meet the definition of MSW under 40 CFR part 98 and therefore
have to install CEMS and use the Tier 4 methodology to quantify
CO2 emissions.
Response: EPA proposed to amend the definition of MSW to provide
greater clarity on what is included as MSW. Several questions were
raised during implementation of the GHGRP because the definition of MSW
in the final Part 98 rule was too generic and did not define terms such
as ``house, commercial/retail, and institutional waste.'' To clarify
the definition, EPA sought to use another EPA definition of the term,
and did not intend to push some municipal waste combustors into a
higher tier. Based on supplementary information provided by the
commenter (please refer to EPA-HQ-OAR-2008-0508), the final definition
of MSW includes materials that should not have been excluded, and
clarifies that when these materials are extracted from MSW and
combusted separately, they are not classified as MSW.
Comment: Two commenters on the definition of ``Natural gas''
pointed out that not all natural gas (particularly field gas) can
consistently meet the proposed specifications. The commenters were
concerned that EPA's proposal to include specifications that natural
gas must be composed of at least 70 percent methane by volume or have a
high heat value between 910 and 1,150 Btu per standard cubic foot would
be problematic for subpart W, when finalized, because these ranges
could exclude field gas.
Response: The definition of natural gas in the final rule caused
significant confusion because it included not only
[[Page 79106]]
naturally occurring mixtures of hydrocarbons, but also fuels such as
field gas, process gas and fuel gas. We proposed to change the
definition of ``natural gas'' to include specifications on the methane
content and a range of Btu values that must be achieved before the gas
can be referred to as ``natural gas.'' Clarifying the definition of
natural gas is important, particularly given that it is a fuel in Table
C-1 and if an owner or operator burns a fuel outside the range of the
specifications, then they could be pushed into Tier 3 if any unit has a
maximum rated heat input capacity greater than 250 million British
thermal units per hour (mmBtu/hr).
Based on the comments received we have decided to finalize the
definition of natural gas without any specifications regarding minimum
or maximum Btu values or a minimum methane content. Although the
commenters were concerned specifically about the implications of the
definition of natural gas for the oil and gas industry, where the fuels
combusted can often fall outside the listed specifications thereby
potentially forcing them into Tier 3, these concerns did not weigh
heavily into our determination to remove the specifications. Rather, we
considered that most facilities subject to subpart C only typically
burn natural gas within the proposed specifications. For these
facilities, it was not necessary to list specifications, because most
would already fall into the specifications we had proposed. Further, we
were concerned that by introducing specifications to the definition of
natural gas we could inadvertently push a small number of owners or
operators into Tier 3, if they have been combusting a fuel outside that
range.
It is true that facilities in the oil and gas industry are more
likely to combust gas outside the listed specifications (e.g., field
gas). However, facilities in the oil and gas industry will be subject
to the reporting requirements under subpart W beginning with the 2011
reporting year. The concerns raised by the commenters with respect to
calculating combustion-related emissions from natural gas were
explicitly considered within the context of subpart W.
Comment: One commenter brought to our attention that the term
``used oil'' is more appropriate than ``waste oil.'' According to the
commenter, the term ``waste oil'' could result in used oil being
classified as hazardous waste rather than traditional fuel, and might
bring the Resource Conservation and Recovery Act program into view.
Response: Without indicating whether we agree with the commenter's
concern or not, we have decided to avoid potential complication or
confusion and have replaced the term ``waste oil'' with ``used oil'' in
the final rule.
Comment: We received two comments on the definition of ``wood
residuals.'' Both commenters requested that the definition explicitly
include trim, sander dust and sawdust from wood products manufacturing,
including resinated wood product residuals because they were concerned
that the proposed definition was too broad and it was not clear if
these products were included.
Response: We agree with the commenter. We did not intend to exclude
these types of products from the definition of wood residuals and agree
that these terms should be included in the definition in order to
provide clarity.
Comment: Several commenters expressed concern about EPA's proposal
to add a reporting requirement for facility ID. Two commenters
suggested that EPA provide a separate public comment period for
including a facility ID reporting requirement, and in that proposal,
include a specific mechanism for assigning the ID numbers.
Response: Although we maintain that assigning a unique ID number to
each facility or supplier, for administrative purposes, is important to
facilitate program implementation, we have decided it is not necessary
to finalize this reporting requirement at this time, given the concerns
raised by the commenters. We will consider this issue further for
future rulemakings. Note that we are still finalizing the technical
clarification in 40 CFR 98.3(c)(1) that it is the physical street
address of the facility or supplier that must be reported.
G. Subpart C--General Stationary Fuel Combustion
1. Summary of Final Amendments and Major Changes Since Proposal
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 final 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.
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 Part 75 units using the
CO2 calculation methodologies in 40 CFR 98.33(a)(5).
Use of Tier 3.
Tier 4 monitoring threshold for units that combust MSW.
Applicability of Tier 4 to common stack configurations.
Starting dates for the use of Tier 4.
Methane (CH4) and nitrous oxide
(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.
GHG emissions from blended fuel combustion.
Use of consensus standard methods.
CO2 monitor span values.
CEMS data validation.
Use of American Society of Testing and Materials (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 adding 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. A pilot light
is a small 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 provide
useful energy to an industrial process, or reduce waste by removing
combustible matter.
GHGs to report. We are amending 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 amending the introductory text of
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 amending this
text 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
[[Page 79107]]
75 to report heat input data year-round under another CAA program. The
introductory text of 40 CFR 98.33(a) is also being 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. We are amending 40 CFR
98.33(a)(1) by adding two new equations to Tier 1. When natural gas
consumption is expressed in therms, Equation C-1a enables 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 also allowing 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), has been added to 40 CFR 98.33 to reflect this. Section
98.36(e)(2)(i) is also amended to allow gaseous fuel consumption to be
reported in units of therms.
Equation C-1b has been added to Tier 1 to accommodate situations in
which the fuel usage information on gas billing records is expressed in
mmBtu. We are also adding two new equations to 40 CFR 98.33(c), i.e.,
Equations C-8a and C-8b, for calculating CH4 and
N2O emissions when the fuel usage information on natural gas
billing records is in units of therms or mmBtu.
Use of Equation C-2b. We are amending 40 CFR 98.33(a)(2)(ii), to
require calculation of a weighted HHV, using Equation C-2b, 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 40 CFR
98.36(c)(1) in which all units in the group are smaller than 100 mmBtu/
hr, we are allowing reporters to use either an annual arithmetic
average HHV or an annual fuel-weighted average HHV in Equation C-2a.
Categories of gaseous fuels. We have revised 40 CFR
98.34(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 to Table C-1 were also made 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) allows
reporters to use flow meters that measure mass flow rates of liquid
fuels to quantify fuel consumption, provided that they (the reporters)
determine the density of the fuel and convert the measured mass of fuel
to units of volume (i.e., gallons), for use in Equation C-4. In
response to a number of requests, we are amending 40 CFR
98.33(a)(3)(iv), to conditionally allow reporters to use flow meters
that measure mass flow rates of gaseous fuels for Tier 3 applications,
as well as for liquid fuels. A reporter wanting to use this option will
have to measure the density of the gaseous fuel, 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. We are amending 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) 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 stack gas moisture content associated
with different process operating conditions. Generally, for each site-
specific default moisture percentage, at least nine runs are required
using EPA Method 4--Determination of Moisture Content In Stack Gases
(40 CFR part 60, appendix A-3). Each site-specific default moisture
value would be calculated by taking the arithmetic average of the
Method 4 runs. Moisture data from the relative accuracy test audit
(RATA) of a CEMS could be used for this purpose. The final rule does
allow the site-specific moisture default values to be based on fewer
than nine Method 4 runs in cases where moisture data from the RATA of a
CEMS are used to derive the default value and the applicable regulation
allows a single moisture run to represent two or more RATA runs.
Each site-specific moisture default value must be updated at least
annually and whenever the reporter determines the current value is non-
representative due to changes in unit or process operation. The updated
moisture value must be used in the subsequent CO2 emissions
calculations.
Determining emissions from an exhaust stream diverted from a CEMS
monitored stack. We are finalizing amendments to 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 final amendments require annual emission
testing of a diverted gas stream to be performed at a set point that
best represents normal operation, using EPA Methods 2 and 3A and (if
moisture correction is necessary) Method 4. A CO2 mass
emission rate is calculated from the test results. If, over time, flow
rate of the diverted stream varies little from the tested flow rate,
then the annual CO2 mass emissions for the diverted stream
(which must be added to the CO2 mass emissions measured at
the main stack) are determined simply by multiplying the CO2
mass emission rate from the emission testing by the number of operating
hours in which a portion of the flue gas was diverted from the main
flue gas exhaust system. However, if the flow rate of the diverted
stream varies significantly over the reporting year, the owner or
operator must either perform additional stack testing or use the best
available information (e.g., fan settings and damper positions) and
engineering judgment to estimate the CO2 mass emission rate
at a minimum of two additional set points, to represent the variation
across the normal operating range. Then, the most appropriate
CO2 mass emission rate must be applied to each hour in which
a portion of flue gas is diverted from the main exhaust system. The
procedures used to determine the annual CO2 mass emissions
for the diverted stream must be documented in the GHG monitoring plan.
Biomass combustion in Part 75 units using the CO2
calculation methodologies in 40 CFR 98.33(a)(5). We are amending 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).
We had proposed to amend 40 CFR 98.3(c) in subpart A and 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 40 CFR part 75 methodologies to calculate
CO2 mass emissions, as described in 40 CFR 98.33(a)(5)(i)
through (a)(5)(iii). After considering the comments received on this
proposal and other information (see EPA-HQ-OAR-2008-0508), however, we
are finalizing language which makes it clear that reporting of biogenic
CO2 emissions from these units is optional for reporting
year 2010, and mandatory
[[Page 79108]]
thereafter. Please see the discussion in Section II.C of this preamble
regarding separate reporting of biogenic emissions for units subject to
40 CFR part 75.
Use of Tier 3. We are amending 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.
We are also adding 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 unit size. For example, subpart Y requires certain
units that combust fuel gas 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 monitoring threshold for units that combust MSW. We are
amending 40 CFR 98.33(b)(4)(ii)(A) to change the Tier 4 monitoring
threshold from 250 tons MSW per day to 600 tons MSW per day, based on
analysis that this value is approximately equivalent to the 250 mmBtu/
hr Tier 4 heat input threshold for other large stationary combustion
units. Units less than 600 tons MSW per day that do not meet the
requirements in 40 CFR 98.33(b)(4)(iii) are allowed to use Tier 2 to
calculate CO2 mass emissions (specifically, Equation C-2c).
Applicability of Tier 4 to common stack configurations. We are
amending 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) is 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) is also 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 applies if the following conditions are met:
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).
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 also applies when all of the combustion units in the
configuration are small (not greater than 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 is 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 and a
process unit (or units) are vented through a common stack or duct, Tier
4 is 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 can 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 will have to be monitored at the common stack or duct, using
Tier 4.
Starting dates for the use of Tier 4. In the October 30, 2009 final
rule, 40 CFR 98.33(b)(5) of subpart C 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. We are amending 40 CFR
98.33(b)(5) to clarify that sources can begin monitoring CO2
emissions data prior to January 1, 2011 from CEMS that successfully
complete certification testing in 2010. 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)).
This revision will 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. Data recorded during
the certification test period for a CEMS can also be used for Part 98
reporting, provided that: All required certification tests are passed
in sequence, with no test failures; and no unscheduled maintenance or
repair of the CEMS is required during the test period.
We are also amending 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: The primary fuel, the manner of unit
operation, or the installed continuous monitoring equipment. In such
cases, the owner or operator will be required to begin using Tier 4 no
later than 180 days from the date on which the change is implemented.
This allows 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. Today's amendments remove
the term ``normal operation'' from 40 CFR 98.33(c)(4)(i) and
(c)(4)(ii). Therefore, calculation of CH4 and N2O
emissions is simply required for each Table C-2 fuel combusted in the
unit during the reporting year.
We are also further amending 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. Under the final amendments
to 40 CFR 98.33(c)(4)(ii), 40 CFR part 75 units that use the worst-case
F-factor reporting option can 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 CFR 98.33(c)(4)(i), but we are also now
allowing 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 solely from the part 75 electronic data reports.
Carbon dioxide emissions from sorbent. We are amending 40 CFR
98.33(d) to make it more generally applicable to different types of
CO2-producing sorbents. The term ``R'' is redefined as the
number of moles of CO2 released upon capture of one mole of
acid gas. When the sorbent is CaCO3, the
[[Page 79109]]
value of R is 1.00. For other CO2-producing sorbents, a
specific value of R is 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.
The title and introductory text of 40 CFR 98.33(e) are being
amended to more precisely define the requirements for reporting
biogenic CO2 emissions. In general, biogenic CO2
emissions reporting is 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 amending 40 CFR 98.33(e) to describe three cases in
which reporters may not need to report biogenic CO2
emissions separate from total CO2 emissions, for units that
combust biomass:
1. If a biomass fuel is not listed in Table C-1 and is combusted in
a unit that is not required to use Tier 4, a reporter is not required
to separately report the biogenic CO2 emissions from
combustion of that fuel unless:
--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.
In that case, according to 40 CFR 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.
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 reporter has the
option to report biogenic CO2 emissions for the 2010
reporting year, but is required to report them thereafter.
3. For the combustion of tires, which are also partly biogenic
(typically about 20 percent biomass, for car and truck tires), the
reporter has the option, but not the requirement, to separately report
the biogenic CO2 emissions, by following the applicable
provisions in 40 CFR 98.33(e).
No comments were received on the proposal to make biogenic
CO2 emissions reporting optional for the combustion of
tires, and the proposal has been finalized without modification.
However, tire-derived fuel has a biomass component, and perhaps it
should be treated in the same manner as MSW, which is also partly
biogenic. A number of units that are subject to Part 98 combust tires
as the primary fuel or as a secondary fuel. Therefore, we are
considering whether these units should be required to account for their
biogenic CO2 emissions. However, before making this
mandatory we intend to open it to notice and comment in a future
rulemaking.
We are amending 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.
However, the use of Tier 1 is not allowed for calculating biogenic
CO2 emissions for combustion of MSW, as originally specified
in 40 CFR 98.33(e)(1) of subpart C, and is also not allowed for the
combustion of tires, if biogenic CO2 emissions are
calculated for tires.
We are amending the methodology in 40 CFR 98.33(e)(2), which is
specifically for units using a CEMS to measure CO2 mass
emissions, by 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 prohibiting its use if the unit combusts MSW or tires.
For sources that combust MSW, we are amending 40 CFR 98.33(e)(3) to
require, except as provided below, the quarterly use of ASTM methods
D7459-08 and D6866-08, 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 also amending 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.
In response to comments, we have added an alternative calculation
methodology for biogenic CO2 emissions from the combustion
of MSW and/or tires, which may be used when the total contribution of
these fuels to the unit's heat input is 10 percent or less. If a unit
combusts both MSW and tires and the reporter exercises the option not
to separately report biogenic CO2 emissions from the tires,
the alternative calculation methodology may still be used for the MSW,
provided that the contribution of MSW to the unit's total heat input
does not exceed 10 percent. The methodology may also be used for small,
batch incinerators that burn no more than 1,000 tons of MSW per year.
Units that qualify for and elect to use the alternative methodology
will use Tier 1 to calculate the total annual CO2 emissions
from the combustion of the MSW or tires, and multiply the result by an
appropriate default factor that represents the biomass fraction of the
fuel, to obtain an estimate of the annual biogenic CO2
emissions. Based on additional background research conducted, we have
concluded that reasonable default factors are 0.20 for tires and 0.60
for MSW (please refer to the Background Technical Support Document--
Revision of Certain Provisions).
We are also amending 40 CFR 98.33(e) to delete and reserve 40 CFR
98.33(e)(4) and the related subparagraphs. Although 40 CFR 98.33(e)(4)
allowed the ASTM methods to be used to determine biogenic
CO2 emissions for various combinations of biogenic and
fossil fuels, we are deleting and reserving that paragraph because the
paragraph also included an unnecessary restriction, i.e., it only
applied to units that use CEMS to measure total CO2 mass
emissions. The amendments to 40 CFR 98.33(e)(3) described above will
achieve the same intended purpose as paragraph (e)(4), without imposing
this restriction, so paragraph (e)(4) is no longer needed.
We are amending 40 CFR 98.33(e)(5) so that it also applies 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 applies when
HHV data for a biomass fuel are available at the minimum frequency
specified in 40 CFR 98.34(a)(2).
Finally, one commenter asked EPA to allow Part 75 units to
calculate biogenic CO2 emissions using the same general
approach that is used in 40 CFR 98.33(c)(4)(ii) for the CH4
and N2O emissions calculations. This requires a heat input-
based equation similar to Equation C-10 to be added to the rule. We
find this request to be reasonable and have added a new paragraph,
(e)(6), to 40 CFR 98.33(e). Paragraph (e)(6) provides the required
equation, i.e., Equation C-15a. In cases where (HI)A, the
fraction of unit heat input from combustion of the biomass fuel, cannot
be determined from the information in Part 75 electronic data reports
(e.g., for units that measure the total CO2 emissions with
CEMS, if the ``worst-case'' F-factor option is used, or if biomass and
fossil fuels with identical F-factors are combusted), facilities must
use the ``best available information'' (as described in 40 CFR
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.
[[Page 79110]]
Fuel sampling for coal and fuel oil. We are amending 40 CFR
98.34(a)(2), to clarify the frequency at which the HHV needs to be
determined for different types of fuels.
First, we are amending 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 amending the definition of the term ``fuel lot'' in
40 CFR 98.34(a)(2)(ii), as it pertains to facilities that receive
multiple deliveries of a particular type of fuel from the same supply
source each month, either by truck, rail, or pipeline. The amendment
clarifies that a fuel lot consists of all of the deliveries of that
fuel for a given calendar month. Thus, for these facilities, the
required HHV sampling has to be no more frequent than once per month.
We did receive requests to clarify the meaning of the terms ``type of
fuel'' and ``supply source,'' pertaining to the proposal to require
only one monthly sample to represent multiple fuel deliveries. The
final rule clarifies that for coal, the type of fuel refers to the coal
rank (i.e., anthracite, bituminous, sub-bituminous, or lignite). For
fuel oil, the type of fuel refers to the grade number or classification
of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel, etc.). The term
``supply source'' is not so easily defined. For the reasons set forth
in the Response to Comments (Section II.G.2 of this preamble), we have
chosen not to include a definition of ``supply source'' in the final
rule.
Third, we are adding 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 revisions to 40 CFR 98.34(a)(2)(ii).
Finally, we are amending 40 CFR 98.34(a)(2)(ii) and 40 CFR
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 are also allowed.
The final rule requires at least one sample to be obtained from each
storage tank that is currently in service, and whenever oil is added,
for as long as the tank remains in service. If multiple additions
(e.g., from multiple deliveries) are made on a given day, taking one
sample after the final addition is sufficient. No sampling is required
for addition of fuel to a tank that is out of service. Rather, a sample
must be taken when the tank is brought into service and whenever oil is
added to the tank, for as long as the tank remains in service. If the
daily manual sampling option is implemented, sampling from a particular
tank is required only on those days when oil from that tank is
combusted in the unit(s).
Tier 3 sampling frequency for gaseous fuels.
We are amending 40 CFR 98.34(b)(3)(ii)(E) to clarify that daily
sampling of gaseous fuels other than natural gas and biogas for carbon
content and molecular weight is only required where continuous, on-line
equipment is in place; weekly sampling is required in all other cases.
GHG emissions from blended fuel combustion. One of the most
frequently asked questions by the regulated community since publication
of the October 30, 2009 final 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. We are now
finalizing amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v)
to clarify reporting requirements for calculating emissions from
blended fuels. The amendments 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
must be calculated separately. In the latter case, the blend is
considered to be a distinct ``fuel type,'' and the reporter must
measure its mass or volume and essential properties (e.g., HHV, carbon
content, etc.) 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 is as follows. For smaller combustion units (heat input capacity
not more than 250 mmBtu/hr), Tier 2 (or possibly Tier 1) can 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 must be calculated, using new Equation
C-16. For Tier 1 applications, a heat-weighted default HHV must be
determined, using new 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 is
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 is required, with
modifications to certain terms in Equations C-17 and 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 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, the owner or operator
must use Tier 3 to calculate the CO2 mass emissions from
combustion of a blended fuel. The mathematics for Tier 3 are 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 are 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 is 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 adding a
new paragraph, (c)(6), to 40 CFR 98.33. Calculation of CH4
and N2O emissions is 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) must 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 is required, based on the best available information, and the
procedures in 40 CFR 98.33(c)(6)(ii) will be followed. First, the
annual consumption of each
[[Page 79111]]
component fuel in the blend is 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 is 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 must 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
are summed across all components, and these sums are reported as the
annual CH4 and N2O mass emissions for the blend.
Use of consensus standard methods. We are amending 40 CFR
98.33(a)(3)(iv) and (a)(3)(v) to remove reference to specific standard
methods and allow the use of standards from consensus-based
organizations or industry standard practice. We are amending 40 CFR
98.34 to remove the specific ASTM and GPA method list for fuel sampling
and analysis in 40 CFR 98.34(a)(6), to remove the list of American Gas
Association (AGA) and American Society of Mechanical Engineers (ASME)
methods for fuel meter calibration in 40 CFR 98.34(b)(4), and to delete
the list of ASTM methods to determine carbon content and molecular
weight in 40 CFR 98.34(b)(5). We are also redesignating 40 CFR
98.34(b)(5) as 40 CFR 98.34(b)(4), and amending newly designated 40 CFR
98.34(b)(4). Finally, we are amending 40 CFR 98.34(b)(1)(A) to remove
the cross-reference to the fuel flow meter test methods listed in 40
CFR 98.34(b)(4). These amendments allow the owner or operator to use
manufacturers' procedures, appropriate methods published by consensus-
based standards organizations such as ASTM, ASME, American Petroleum
Institute (API), AGA, ISO, etc.; or use industry-accepted practice. The
methods used must 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. 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 amending 40 CFR 98.34(c) by adding a new paragraph (c)(6), which
allows the CGA 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. 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 were specified in the final rule. We are
adding a new paragraph, (c)(7), to 40 CFR 98.34, which requires hourly
CEMS data validation to be consistent with the sections of 40 CFR part
60 or part 75 cited in the preceding paragraph of this preamble.
Alternatively, the hourly data validation procedures in an applicable
State CEM program can 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 MSW and other
units that combust combinations of fossil fuels and biomass. Flue gas
samples are taken quarterly using ASTM Method D7459-08 and analyzed
using ASTM Method D6866-08. We are amending 40 CFR 98.34(d) and (e), as
discussed in the following paragraphs.
The amendments to 40 CFR 98.34(d) 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, unless the unit qualifies for
the alternative Tier 1 calculation methodology described above, under
``Biogenic CO2 emissions from biomass combustion.''
Quarterly sampling with ASTM Method D7459-08 is required for a minimum
of 24 cumulative hours of sampling per quarter, except as provided
below.
We are amending 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, is
allowed to determine biogenic CO2 emissions using the ASTM
methods on a quarterly basis. At least 24 cumulative hours of sampling
per quarter are required, except as provided immediately below.
We are adding an option to 40 CFR 98.34(d) and (e), allowing
sources to demonstrate that 8 hours of sampling per quarter is
sufficient. The demonstration requires a minimum of two 8-hour tests
and one 24-hour test, performed under normal, stable operating
conditions. The demonstration tests must be distinct, i.e., no
overlapping of the 8-hour and 24-hour test periods is permitted. If the
average biogenic fraction obtained from the 8-hour tests is within
5 percent of the results from the 24-hour test, then, in
subsequent quarters, the Method D7459-08 sampling time may be reduced
to 8 hours. The results of the demonstration must be documented in the
monitoring plan.
We are also amending 40 CFR 98.34(d) by adding 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.
Procedures for estimating missing data. We are amending 40 CFR
98.35(a) to clarify that the missing data procedures in 40 CFR part 75
are only to be followed by units that are in the Acid Rain Program and
those that monitor and report emissions and heat input data year round.
Units that only monitor and report during the ozone season must follow
the missing data procedures in 40 CFR 98.35(b).
Electronic data reporting and recordkeeping. We are amending 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 summarized in the following
paragraphs. We are also adding an alternative reporting option to 40
CFR 98.36(c) to reduce the reporting burden for certain facilities.
We are adding the reporting of methodology start and end dates in
several places throughout 40 CFR 98.36(b), (c), and (d).
We are amending the data element lists in 40 CFR 98.36 to be
consistent
[[Page 79112]]
with respect to reporting of emissions by fuel type and reporting of
biogenic CO2 emissions. Specifically, for clarity and
consistency with the changes to 40 CFR 98.3(c), we have modified the
amendments to 40 CFR 98.36(d)(1)(ii), (d)(1)(ix), (d)(2)(ii)(I), and
(d)(2)(iii)(I) from the proposal. These sections state that for units
subject to 40 CFR part 75, reporting of biogenic CO2
emissions is optional only for the 2010 reporting year. Reporting of
these emissions becomes mandatory starting with the 2011 reporting
year.
We are removing 40 CFR 98.36(b)(10) to remove the requirement to
report the customer meter number for units that combust natural gas.
We are finalizing requirements in 40 CFR 98.36(c)(1)(ii) that only
the maximum rated heat input capacity of the largest unit in a group
must be reported. We are also finalizing requirements for 98.36(c)(3)
in a similar manner, for groups of units served by a common pipe.
We are amending 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) by removing 40 CFR
98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data
elements were duplicative of requirements in subpart A.
We are amending 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 amending 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.
We are amending 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 II.C of this preamble,
the amendments to 40 CFR 98.36(d) state that reporting of biogenic
CO2 emissions is optional only for the 2010 reporting year
for units using the CO2 mass emissions calculation methods
in 40 CFR part 75.
For units that use the Tier 4 methodology to calculate
CO2 mass emissions, we are amending 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 amendments to these sections require the annual
``non-biogenic'' CO2 mass emissions to be reported instead
of reporting the annual CO2 mass emissions from fossil fuel
combustion.
We are adding a new alternative reporting option, under 40 CFR
98.36(c)(4). This new option applies 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, a source can 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.
Company records can be used to determine the percentage
distribution of the shared fuel to the large and small units.
Facilities using this reporting option are 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 is sufficient.
Finally, we are amending 40 CFR 98.36(e)(2)(iii) to simplify the
recordkeeping requirements in cases where the results of fuel analyses
for HHV are provided by the fuel supplier. Parallel language is added
in a new paragraph, 40 CFR 98.36(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 is 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 may not be readily available).
Common stack reporting option. Section 98.36(c)(2) of subpart C
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 40 CFR part 98.
In view of this, we are amending 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 amendments to 40 CFR 98.36(c)(2) apply not only to ordinary
common stack or duct situations where the gas streams from multiple
units are combined together, but also apply when combustion and/or
process off-gas streams from a single unit (e.g., from a kiln, furnace,
petrochemical process unit, or smelter) are routed to a stack. To
accommodate this variation on the concept of a common stack, 40 CFR
98.36(c)(2)(ii) is amended to require sources to report ``1'' as the
``Number of units sharing the common stack or duct'' where combustion
and/or process emissions from a single unit are 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 amending 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 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 amending 40 CFR 98.36(c)(3) as follows. First, the erroneous
citation of ``Sec. 98.34(a)'' is corrected to read ``Sec. 98.34(b).''
Second, we are amending 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)
[[Page 79113]]
(which cross-references the accuracy specifications in 40 CFR 98.3(i)),
so that this calibration requirement applies only when Tier 3 is the
required tier for calculating CO2 mass emissions. This is
consistent with the final amendments to 40 CFR 98.3(i), where we
clarify that 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).
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 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 amending the rule to add a second one. Section
98.33(b)(2)(ii) of the current rule 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.
Today's rule adds a new paragraph, (b)(1)(v), to 40 CFR 98.33, allowing
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 or mmBtu. Therefore, we are also amending 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 amending 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 amending the rule 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 40 CFR 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 are 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. We
are finalizing several amendments to Table C-1; specifically, we have:
Replaced the categories ``fossil fuel-derived fuels
(solid)'' and ``fossil fuel-derived fuels (gaseous)'' with more
inclusive terms, i.e., ``other fuels (solid)'' and ``other fuels
(gaseous).'' The ``other fuels (solid)'' category includes four fuels:
plastics, municipal solid waste, tires, and petroleum coke. The ``other
fuels (gaseous)'' category includes blast furnace gas, coke oven gas,
propane gas, and fuel gas.
Removed the word ``pipeline'' from the description of
natural gas.
Retained the following fuels: ``wood residuals,''
``agricultural by-products,'' and ``solid by-products'', and added
definitions of these terms to 40 CFR 98.6 (see section II.F of this
preamble for further discussion).
Added ``Used oil'' to the list of petroleum products, and
added a definition to 40 CFR 98.6 (see section II.F of this preamble
for further discussion).
Removed ``still gas'' from the list of petroleum products
and added ``fuel gas.''
Corrected a typographic error in the HHV for ethane;
changing it to 0.069 mmBtu/gal, rather than 0.096 mmBtu/gal.
Revised footnote 1 regarding municipal waste combustor
(MWC) units to make it clear that only MWC units that produce steam are
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.
Modified footnote 1 to Table C-1, to reflect the new
biogenic CO2 emissions calculation options for certain units
that combust MSW and/or tires.
Revised footnote 2 to clarify that if the conditions in 40
CFR 98.243(d)(2)(i) and (d)(2)(ii) and 40 CFR 98.252(a)(1) and (a)(2)
do not apply, reporters subject to 40 CFR 98.243(d) of subpart X or
subpart Y shall use either Tier 3 or Tier 4.
Remove the qualifier of 100 percent for ethanol and
biodiesel.
Added a default CO2 emission factor and a
default high heat value for petroleum-derived ethanol. These are the
same as the default values for biomass-derived ethanol.
Table C-2. We are finalizing the proposed amendments to remove the
first iteration of Table C-2 and make minor corrections to the second
one. The amendments consist of correcting the exponents (powers-of-ten)
of several emission factors.
Standard conditions. A number of commenters requested that, for
consistency with the rest of Part 98, we allow sources to use 60 [deg]F
as standard temperature instead of 68 [deg]F, when Equation C-5 is used
to calculate CO2 mass emissions from the combustion of
gaseous fuel. We proposed to allow this alternative for subparts X and
Y, because the refining and petrochemical industries use 60 [deg]F as
standard temperature. We have concluded that the commenters' request to
modify Equation C-5 accordingly is reasonable, and we are revising the
definition of the term ``MVC (molar volume conversion)'' in the
nomenclature of Equation C-5 (see revised 40 CFR 98.33(a)(3)(iii)). The
revised definition of MVC allows sources to use a MVC value of either
849.5 standard cubic feet per kilogram mole (scf/kg mole) for a
standard temperature of 68 [deg]F, or 836.6 scf/kg mole for a standard
temperature of 60 [deg]F. A corresponding change has been made to the
definition of ``Standard conditions'' in 40 CFR 98.6. For verification
purposes, a data element has been added at 40 CFR 98.36(e)(2)(iv)(G),
requiring sources using Equation C-5 to report which MVC value was used
in the emissions calculations.
Miscellaneous revisions. We are amending 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. These amendments
also correct an inadvertent omission in the verification section of
subpart C, specifically, in 40 CFR 98.36(e)(2)(v)(C). That section
requires units using the Tier 3 methodology to keep records of the
method(s) used for carbon content determination. However, no mention is
made of keeping records of the method(s) used to determine the
molecular weight, which is a requirement for gaseous fuels. To correct
this inadvertent oversight, we have amended 40 CFR 98.36(e)(2)(v)(C) to
require records to be kept of the method(s) used for both carbon
content and (if applicable) molecular weight determination. Finally, we
have
[[Page 79114]]
corrected typographical errors in the definition of ``CC'' in the
nomenclature of Equation C-5. This equation applies to gaseous fuels,
not liquid fuels, and the units of measure for CC must be kg C per kg
of fuel, rather than kg C per gallon.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
A new equation has been added to Tier 1 to accommodate
situations in which the fuel usage information on gas billing records
is expressed in mmBtu. We have also added two new equations to 40 CFR
98.33(c) for calculating CH4 and N2O emissions
when the fuel usage information on natural gas billing records is in
units of therms or mmBtu.
For units using the Tier 2 methodology that receive HHV
data less frequently than monthly, or, for small units (< 100 mmBtu/hr)
regardless of the HHV sampling frequency, we are allowing Equation C-2b
to be used to calculate a fuel-weighted annual average HHV, instead of
calculating the arithmetic average annual HHV.
For consistency with other subparts, we have revised the
nomenclature of Equation C-5, to allow reporters to use a molar volume
conversion (MVC) constant referenced to a standard temperature of
either 60 [deg]F or 68 [deg]F.
For Tier 4 applications, we are allowing site-specific
moisture default values to be based on fewer than nine Method 4 runs in
cases where moisture data from the RATA of a CEMS are used to derive
the default value and the applicable regulation allows a single
moisture run to represent two or more RATA runs.
We have modified the approach for calculating
CO2 mass emissions from an exhaust stream diverted from a
CEMS monitored stack.
For consistency with Subpart A, we have added language in
several places stating that for Part 75 units, separate reporting of
biogenic CO2 emissions is optional in reporting year 2010
and mandatory thereafter.
We have added a new paragraph, (e)(6), to 40 CFR 98.33,
allowing Part 75 units to calculate biogenic CO2 emissions
using the same general approach that is used in 40 CFR 98.33(c)(4)(ii)
for the CH4 and N2O emissions calculations.
We have added an alternative calculation methodology, for
biogenic CO2 emissions from the combustion of MSW and tires
that may be used when the total contribution of these fuels to the
unit's heat input is 10 percent or less. The methodology, which uses
the Tier 1 equation together with default biogenic percentages, may
also be used for small, batch incinerators that burn no more than 1,000
tons of MSW per year.
We have removed the term ``consecutive'' between the words
``24'' and ``hours'', in reference to the minimum required sampling
time for determining the percentage of biogenic CO2 in flue
gas when ASTM Method D7459-08 is used, thereby allowing samples to be
collected for 24 total hours in a quarter, rather than 24 consecutive
hours. We have also added a provision allowing sources to perform
additional testing to demonstrate that sampling for 8 hours is
sufficient.
We have added language to 40 CFR 98.34(a)(2)(ii) and
(b)(3)(ii)(B) explaining how to implement certain fuel oil sampling
options, specifically, daily manual sampling and sampling after each
addition of oil to the tank.
To minimize unnecessary burden related to collecting
information on small units aggregated in a group and for the common
pipe configuration, we are removing and reserving 40 CFR 98.36
(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii). We are no longer requiring
sources to report the number of units in, or the cumulative heat input
capacity of, an aggregated group of units or a group of units served by
a common pipe. Only the maximum rated heat input capacity of the
largest unit in the group must be reported.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Natural gas consumption expressed in therms.
Comment: Commenters were generally supportive of EPA's proposal to
provide equations for cases where natural gas consumption is expressed
in therms in billing records. One commenter noted that the proposed
rule failed to take into account that on some natural gas billing
records, the fuel usage is expressed in units of mmBtu. The commenter
also brought to our attention that the proposed rule did not provide
corresponding equations for calculating CH4 and
N2O emissions when the fuel usage information on gas billing
records is expressed in therms.
Response: We agree with these comments and have made the following
adjustments to the final rule text. First, a new equation, Equation C-
1b, has been added to Tier 1 to accommodate situations in which the
fuel usage information on gas billing records is expressed in mmBtu.
Second, we have added two new equations to 40 CFR 98.33(c), i.e.,
Equations C-8a and C-8b, for calculating CH4 and
N2O emissions when the fuel usage information on natural gas
billing records is in units of therms or mmBtu.
Site-specific stack gas moisture content values.
Comment: Commenters were generally supportive of the proposed rule
changes related to determining the site-specific moisture default
values. Two commenters requested that we allow the site-specific
moisture default values to be based on fewer than nine Method 4 runs,
in cases where moisture data from the RATA of a CEMS are used to derive
the default value and the applicable regulation allows a single
moisture run to represent two or more RATA runs.
Response: We believe that this is a reasonable request and have
incorporated it into the final rule.
Determining emissions from an exhaust stream diverted from a CEMS
monitored stack.
Comment: Commenters were supportive of the intent of the proposed
amendments, but indicated that the proposed methodology for estimating
the CO2 mass emissions from the diverted gas stream would
not be implementable at every affected facility. Specifically,
commenters took issue with EPA's assumption that the CO2
concentration in the diverted stream will be the same as the
concentration in the main stack. According to the commenters, this is
not the case, because dilution air introduced via auxiliary fans and
other equipment will lower the CO2 concentration of the side
stream.
Response: We agree with the commenters' assessment and have
modified the proposed approach for quantifying emissions in the
diverted stream. The final rule requires annual emission testing of the
diverted gas stream to be performed at a set point that best represents
normal operation, using EPA Methods 2 and 3A and (if moisture
correction is necessary) Method 4. A CO2 mass emission rate
is calculated from the test results. If, over time, flow rate of the
diverted stream
[[Page 79115]]
varies little from the tested flow rate, then the annual CO2
mass emissions for the diverted stream (which must be added to the
CO2 mass emissions measured at the main stack) will be
determined simply by multiplying the CO2 mass emission rate
from the emission testing by the number of operating hours in which a
portion of the flue gas was diverted from the main flue gas exhaust
system. However, if the flow rate of the diverted stream varies
significantly over the reporting year, the owner or operator must
either perform additional stack testing or use the best available
information (e.g., fan settings and damper positions) and engineering
judgment to estimate the CO2 mass emission rate at a minimum
of two additional set points, to represent the variation across the
normal operating range. Then, the most appropriate CO2 mass
emission rate must be applied to each hour in which a portion of flue
gas is diverted from the main exhaust system. The procedures used to
determine the annual CO2 mass emissions for the diverted
stream must be documented in the monitoring plan.
Fuel sampling for coal and fuel oil.
Comment: Commenters were generally supportive of the proposed
amendments to 40 CFR 98.34(a)(2)(ii) and 40 CFR 98.34(b)(3)(ii)
regarding the definition of ``fuel lot.'' However, we did receive
requests to clarify the meaning of the terms ``type of fuel'' and
``supply source,'' pertaining to the proposal to require only one
monthly sample to represent multiple fuel deliveries.
Response: The final rule clarifies that for coal, the type of fuel
refers to the coal rank (i.e., anthracite, bituminous, sub-bituminous,
or lignite). For fuel oil, the type of fuel refers to the grade number
or classification of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel,
etc.). The term ``supply source'' is not so easily defined, however,
and we have chosen not to include a definition to the final rule.
Instead, you may use the following general guidelines. The term
``supply source'' can certainly refer to the coal mine, bulk terminal,
or refinery from which the fuel is obtained. However, it also can apply
to a fuel vendor who receives a particular type of fuel from different
locations and distributes the fuel to his customers, provided the
important properties of the fuel, such as its heating value, sulfur
content, carbon content, etc., are guaranteed to be within specified
ranges.
Comment: With respect to the HHV sampling requirements for each
fuel lot, commenters expressed concern that the option to sample fuel
oil after each addition of fuel to the storage tank might not represent
the fuel actually being combusted. For instance, fuel may be added to
an empty or a partly full tank that is out of service. Also, for a tank
that is currently in service, due to infrequent combustion of fuel oil,
it may have been months, or even years, since oil was last added to the
tank, and it may be months or years before oil is added again.
Response: To address these concerns, the final rule requires at
least one sample to be obtained from each storage tank that is
currently in service, and an additional sample whenever fuel is added
to the tank while it remains in service. If multiple additions are made
to an in-service tank on a given day (e.g., from multiple deliveries)
one sample taken after the final addition is sufficient. No sampling is
required for addition of fuel to a tank that is out of service. Rather,
a sample must be taken when the tank is brought into service and
whenever oil is added to the tank, for as long as the tank remains in
service.
Tier 4 monitoring threshold for units that combust MSW.
Comment: Commenters were generally supportive of the proposed
amendment to increase the Tier 4 monitoring threshold for combustion of
municipal solid waste from 250 to 600 tons per day. One concern was
that the amendment might not be finalized before the end of 2010;
therefore, they asked for the final rule to provide a six month
extension of the January 1, 2011 regulatory deadline for installing and
certifying CEMS. Some commenters were concerned that this proposed
change would affect the quantity of emissions reported under the
program and were, therefore, concerned about finalizing this proposed
amendment.
Response: There is no need for the requested extension because
units at or above the 600 ton per day threshold have been on notice
since the 2009 final rule that they are required to use CEMS. The
proposed revision to the Tier 4 monitoring threshold should not have
caused them to think otherwise. For units in-between the original
threshold of 250 tons per day and the revised threshold of 600 tons per
day, an extension is unnecessary because these units can use Tier 2 for
the 2010 reporting year. We disagree with concerns that the final
amendments will impact the quantity of data reported to the program,
because the final amendments still require the same units to report GHG
emissions. The only difference is that they may be using the Tier 2
methodology instead of Tier 4.
Biogenic CO2 emissions from biomass combustion.
Comment: Regarding the proposed revisions to the optional biogenic
CO2 emissions calculation methodology for units with CEMS
described in 40 CFR 98.33(e)(2), one commenter recommended that we make
the methodology more flexible by modifying Equation C-13. The change to
this equation proposed by the commenter would allow the volume of
CO2 from combustion of the biomass fuel (rather than the
fossil fuel) to be calculated directly and then used in Equation C-14
to calculate the biogenic percentage of the annual CO2 mass
emissions.
Response: EPA has not incorporated the commenter's proposed
changes. Although the proposed modification to the methodology could
work for fuels such as wood residue and bark (which have F-factors
listed in Table 1 in section 3.3.5 of 40 CFR part 75, appendix F), the
commenter appears to be unaware that we proposed to remove from 40 CFR
98.33(e)(1) the restriction prohibiting units with CEMS from using the
Tier 1 methodology to calculate biogenic CO2 emissions. As
stated above, we are finalizing that amendment as proposed. Therefore,
since both Tier 1 and the commenter's suggested methodology require
sources to quantify the amount of biomass fuel combusted, and since the
Tier 1 methodology is significantly simpler than the commenter's
proposal, there is no need to revise the calculation procedures in 40
CFR 98.33(e)(2).
Comment: Many units and industrial processes burn relatively small
amounts of partly biogenic fuels such as tires and MSW, as
supplementary fuels. Quarterly sampling and analysis of the flue gas
using ASTM Methods D7459-08 and D6866-08 is the only available
methodology in Part 98 for quantifying biogenic CO2
emissions from these fuels. Some commenters requested relief from
reporting biogenic CO2 emissions from such fuels when they
account for less than 10 percent of a unit's heat input. Another
commenter asked EPA to either make reporting of biogenic CO2
optional or reduce the amount of required testing with the ASTM methods
to once every five years, for small batch incinerators that combust
MSW. The commenter provided data for a typical batch incinerator,
showing that in 2009, less than 400 metric tons of biogenic
CO2 were emitted from the unit.
Response: We do not intend to grant a reporting exemption for MSW
combustion, and, for tires, although the reporting is optional at
present, we intend to revisit this issue in the future. However, we are
persuaded that the cost
[[Page 79116]]
of performing the ASTM methods (roughly $5,000 to $10,000 each quarter)
is unreasonably high for sources that burn very small amounts of MSW
and/or tires and emit comparatively little biogenic CO2.
Also, for sources that combust tires and wish to report biogenic
CO2, the ASTM methods are their only option. In view of
these considerations, we have added an alternative calculation
methodology for biogenic CO2 emissions from the combustion
of tires and/or MSW. The methodology is found at 40 CFR
98.33(e)(3)(iv), and may be used when the total contribution of these
fuels to the unit's heat input is 10 percent or less. We are also
allowing this methodology to be used for small batch incinerators that
burn no more than 1,000 tons of MSW per year. Supplementary information
provided by the commenter who requested reduced testing of these
incinerators indicates that the rated capacities of the units can be as
high as 1,300 lb/hr of MSW, but that in practice, since the units
operate in batch mode, a more realistic estimate of the actual,
annualized capacity of the units is somewhere between 100 and 200 lb/hr
(see EPA-HQ-OAR-2008-0508). If one of these incinerators were to
combust as much as 200 lb/hr of MSW on an annualized basis, this would
equate to approximately 875 tons of MSW per year. The total annual
CO2 emissions from the combustion of 875 tons of MSW is
estimated to be about 800 metric tons, based on the default emission
factors in Table C-1. Assuming a biogenic fraction of 0.60 for MSW, the
biogenic portion of the total annual CO2 emissions would be
480 metric tons, which is less than 2 percent of the 25,000 metric ton
applicability threshold in 40 CFR 98.2 for Part 98 facilities. Based on
the above analysis, we have concluded that it is appropriate to allow
Tier 1 to be used together with a default biogenic percentage of 0.60
to estimate the biogenic CO2 emissions from MSW combustion
in small batch incinerators, in lieu of using ASTM Methods D7459-08 and
D6866-08. To allow for some possible variation in the annualized
capacity of these units, the final rule extends the use of the
alternative calculation methodology to batch incinerators that combust
no more than 1,000 tons of MSW per year (which corresponds to about 540
tons of biogenic CO2 per year).
Comment: With regard to the use of ASTM Methods D7459-08 and D6866-
08, two commenters from facilities that combust refuse-derived fuel
(RDF) asked us to consider shortening the sampling time to 8 hours, in
cases where the fuel is relatively homogeneous. Both commenters
submitted data comparing the results of 8-hour samples against the
results of 24-hour samples. For one source, the 8-hour sample results
were within 3.3 percent of the 24-hour results, and for the other
source the results were within 1.7 percent.
Response: EPA agrees that under certain circumstances, it may be
appropriate to shorten the sampling time. Therefore, we are adding an
option to 40 CFR 98.34(d) and (e), allowing sources to demonstrate that
8 hours of sampling per quarter is sufficient. The demonstration
requires a minimum of two 8-hour tests and one 24-hour test, performed
under normal, stable operating conditions. The demonstration tests must
be distinct, i.e., no overlapping of the 8-hour and 24-hour test
periods is permitted. If the average biogenic fraction obtained from
the 8-hour tests is within 5 percent of the results from
the 24-hour test, then, in subsequent quarters, the Method D7459-08
sampling time may be reduced to 8 hours. The results of the
demonstration must be documented in the monitoring plan. Note that
although the data provided by the commenters showed that the 8-hour and
24-hour sample results differed by no more that 3.3 percent, we believe
that 5 percent is a more reasonable acceptance criterion.
This is because the methodology will likely be used for the combustion
of tires as well as MSW. Tire-derived fuel (TDF) has a much lower
biogenic fraction than MSW (typically about 0.20, compared to 0.60 for
MSW). An acceptance criterion lower than 5 percent for TDF combustion
would require the difference between the 8-hour and 24-hour sample
results to be less than 0.01, and would be overly stringent.
Use of consensus standard methods.
Comment: We received both supportive and adverse comments on the
proposed amendments to remove reference to specific consensus
standards. Commenters that objected to the proposal stated that
elimination of the lists of acceptable methods and allowing the use of
``industry standard practice'' weakens the rule. According to these
commenters, there is no way to evaluate the technical merits of an
``industry standard practice,'' and the quality of the reported GHG
emissions data could suffer as a result.
Response: We do not agree with the objections raised by these
commenters. Subpart C covers a large range of industries, perhaps
including some that we are not even aware of yet that are significant
emitters of GHG emissions and therefore covered by the rule. In these
early years of the program, we want to ensure that the methods required
by the rule are appropriate for all facilities subject to subpart C of
the rule. Although we attempted to assemble a comprehensive list of
methods and provide appropriate alternatives in the 2009 final rule,
based on questions received we determined that it was likely that other
valid methods from these organizations and practices were overlooked.
For instance, under the 2009 final rule, even updates to the IBR
methods to reflect the latest practices would not have been acceptable
without a rulemaking. The commenters did not sufficiently justify why
opening up to industry consensus standards would compromise data
quality. In fact, the opposite could be said where more updated
versions of previously incorporated standards are now allowable.
Further, subpart C already includes a mechanism by which we can
evaluate the methods being used by industry. Sections 98.36(e)(2)(iii)
and 98.36(e)(2)(v) require that records be kept of the methods that are
used for flow meter calibration and for HHV and carbon content
determinations, and 40 CFR 98.36(e)(4) requires sources to provide this
information to EPA within 30 days of receiving a request for it.
We note that we have not opened all subparts more broadly to
industry consensus standards. Please see the responses to comments in
Section II.K (Hydrogen Production) and Section II.M (Petrochemical
Production) of this preamble for our response to similar comments under
these subparts.
Electronic data reporting and recordkeeping.
Comment: Two commenters asked us to either remove or modify the
proposed requirement to report the number of units in an aggregated
group of units. One commenter suggested that reporting would be
simplified if very small sources such as water heaters, space heaters,
lab burners, etc., were lumped together and counted as one unit. The
other commenter stated that it is burdensome to keep an accurate count
of these small domestic units at large, complex industrial facilities.
That same commenter also suggested that only units with heat input
ratings of 10 mmBtu or greater should be included in the count. A third
commenter noted that it is also difficult to report the cumulative
maximum heat input rating of a group of units, as required under 40 CFR
98.36(c)(1)(iii), when numerous small domestic units, some of which may
not have a heat input rating, are included in an aggregated group.
[[Page 79117]]
Response: We believe these comments have merit. After careful
consideration, we have concluded that for verification purposes, we do
not need to know either the exact number of units in an aggregated
group or the combined maximum rated heat input of the group. The only
critical data element is the maximum rated heat input capacity of the
largest unit in the group. This information is needed to confirm that
none of the units exceeds 250 mmBtu/hr, which is the condition that
must be met to use the unit aggregation option in 40 CFR 98.36(c)(1).
Therefore, in the final rule, we are withdrawing the proposed
requirement to report the number of units in an aggregated group of
units, and are removing the requirement to report the combined maximum
rated heat input of the group. We also are withdrawing the proposed
requirement under 40 CFR 98.36(c)(3)(ii) to report the number of units
served by a common fuel pipe. The issue is the same for the common pipe
configuration as for the aggregated group of units, i.e., hundreds of
small, domestic units may be served by the common pipe. To effect these
rule changes, 40 CFR 98.36(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii) have
been removed and reserved.
Table C-1.
Comment: Two commenters questioned the appropriateness of listing
MSW with plastics and petroleum coke. Further, they noted that
petroleum coke is listed twice in the table, first under petroleum
products and then again under ``other fuels (solid).'' According to the
commenters, petroleum coke is a petroleum derivative, and is more
appropriately listed with the other ``petroleum products.''
Response: The category ``other fuels (solid)'' in Table C-1 is not
intended to make any policy statement about the nature of the fuels
included in the category. The fuels included in ``other fuels (solid)''
are miscellaneous fuels that do not fit into any other existing
category for the purposes of this rule. Petroleum coke was included as
a petroleum product in the 2009 final rule (74 FR 56409). However, the
HHV units of measure for petroleum products listed in Table C-1 are in
mmBtu per gallon and some reporters were confused about how to
appropriately calculate CO2 emissions from petroleum coke,
since it is actually a solid fuel, and is nominally measured in units
of short tons. By listing petroleum coke as a solid fuel with a heating
value in units of mmBtu/short ton, EPA intends to alleviate confusion
about how emissions are to be calculated for petroleum coke. However,
we also understand that some facilities report petroleum coke usage to
the Energy Information Administration (EIA) in units of equivalent
barrels of petroleum, and may prefer to report petroleum coke
consumption in units of gallons under this rule. As such, EPA is not
proposing to remove petroleum coke from the list of petroleum products
in Table C-1. The two HHVs for petroleum coke differ only in units of
measure. They will give equivalent results when CO2 mass
emissions are calculated.
Comment: Two commenters asserted that plastics are a small
component of MSW and there is no reason why plastics should be listed
as a separate fuel in Table C-1. These commenters stated that to the
best of their knowledge, plastics are not combusted as a separate fuel
stream, and they recommended that EPA delete plastics from Table C-1.
Two other commenters, however, stated that plastics are, in fact,
sometimes separated out from MSW as a separate stream. These commenters
provided a suggested definition of ``plastics'' and requested that we
add it to 40 CFR 98.6. The commenters also asked us to modify the
definition of MSW, to specifically exclude plastics that are recovered
from MSW, processed separately, and disposed.
Response: As mentioned in the preamble to the August 11, 2010
proposed rule (75 FR 48764), facilities have questioned EPA as to why
plastics and waste oil, two fuels that appeared in Table C-2 of the
April 10, 2009 proposed rule, were left out of the October 30, 2009
final rule. Responding to these concerns, on August 11, 2010 we
proposed to add both fuels to Table C-1. Today's rule retains these
entries, except that waste oil has been redesignated as ``used oil.''
In view of the input received from the commenters who brought to our
attention that plastics (including such things as ``* * * bottles,
containers, bags, CD cases, sheeting, packaging, broken consumer goods,
etc. * * *'') are sometimes recovered from MSW and processed
separately, we decided not to incorporate the recommendation of the
other commenters who asked us to delete plastics from the table.
We see no need to add a definition of plastics to 40 CFR 98.6,
since plastic materials are readily identifiable. However, to address
the commenters' chief concern, we have modified the definition of MSW
to clearly state that insofar as plastics (along with certain other
materials) are separated out from MSW, processed and disposed of, they
are not considered to be ``municipal solid waste.''
Comment: Two commenters argued against the inclusion of default
factors for ``fuel gas'' in Table C-1. They argued that this would have
a negative impact on chemical plant fuel gas streams that were
previously exempt from Tier 3 requirements when the streams provide
less than 10 percent of the annual heat input to a unit rated greater
than 250 mmBtu/hr) because Table C-1 previously had no factors for fuel
gas. According to the commenters, the proposed inclusion of default
factors for ``fuel gas'' in Table C-1 requires monitoring and reporting
of GHG emissions from these gas streams. Both commenters suggested that
Table C-1 should include default factors for ``refinery fuel gas''
rather than ``fuel gas.'' One commenter also suggested revising the
definition of ``fuel'' and Footnote 2 associated with the default
values for fuel gas in Table C-1 to clarify that fuel gas is specific
to refineries and petrochemical plants, but excludes process off-gases
from chemical production plants.
Response: Default values for fuel gas in Table C-1 are necessary to
allow refineries and petrochemical plants to use Tier 1 or Tier 2
methods for certain small fuel gas streams that were proposed to be
excluded from the requirement to use Tier 3 for fuel gas in subparts X
and Y. In providing these factors, we did not intend to require
chemical plants to monitor and report GHG emissions generated by the
combustion of ``fuel gas'' that were excluded from reporting
requirements in the October 30, 2009, final Part 98. Therefore, we
agree that some additional clarification of terms is needed to prevent
the fuel gas factor from requiring measurement and reporting of GHG
from the chemical plant vent gases.
While changing the term used in Table C-1 to ``refinery fuel gas''
may have helped to clarify the intent, we do not believe, given the
definition of ``fuel gas'' in the final rule, that this would
adequately address the issue. ``Fuel gas'' as defined in the October
30, 2009, final Part 98 means ``gas generated at a petroleum refinery,
petrochemical plant, or similar industrial process unit, and that is
combusted separately or in any combination with any type of gas.'' The
inclusion of the phrase ``or similar industrial process unit'' within
the definition of fuel gas expanded the meaning of fuel gas beyond
refineries and petrochemical plants. Without specifically defining the
term ``refinery fuel gas'' we expect that the rule language would have
remained ambiguous, especially since refinery
[[Page 79118]]
fuel gas was still intended to apply to some petrochemical processes.
To clarify our original intent of the proposed inclusion of default
factors for fuel gas in Table C-1, we are revising the definition of
``fuel gas'' to delete reference to other similar industrial process
units. In Part 98, the term ``fuel gas'' is intended to apply to
petroleum refineries and petrochemical plants, so this revision does
not affect other Part 98 requirements; it simply clarifies that ``fuel
gas'' and the fuel gas factors are specific to petroleum refineries and
petrochemical plants.
The commenter suggested revising the definition of fuel to mean
``solid, liquid or gaseous combustible material, but excludes process
waste off gases from chemical production plants that are not petroleum
refineries or petrochemical plants.'' We have determined that this
change is not necessary because we have addressed the commenter's
concerns through the change in the definition of fuel gas. We are
amending Footnote 2 of Table C-1, as requested, to clarify further that
only reporters subject to 40 CFR 98.243(d) of subpart X or subpart Y
are required to use Tier 3 or Tier 4 methodologies when the specific
conditions outlined in the footnote do not exist.
H. Subpart D--Electricity Generation
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 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: ARP units and non-
ARP electricity generating units (EGUs) that are required to report
CO2 mass emissions data to EPA year-round.
Optional reporting of biogenic CO2. For consistency with the
amendments to subpart C, we have revised 40 CFR 98.43 to clarify that
for subpart D units, reporting of biogenic CO2 emissions is
optional only for the 2010 reporting year, and mandatory thereafter. We
are also adding a new paragraph 40 CFR 98.43(b) indicating that
biogenic CO2 emissions must be calculated and reported by
following the applicable methods specified in 40 CFR 98.33(e). Fossil
CO2 emissions are calculated by subtracting the biogenic
CO2 mass emissions calculated according to 40 CFR 98.33(e)
from the cumulative annual CO2 mass emissions from paragraph
(a)(1) of this section.
Data reporting requirements. Section 98.46 of subpart D specified
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 were 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 amending 40
CFR 98.46 to correct this error.
Recordkeeping. We are amending 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 have concluded 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).
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Making separate reporting of biogenic emissions optional
for part 75 units in the 2010 reporting year and mandatory every year
thereafter. See sections II.C and II.G of this preamble.
Adding a provision to subpart D to clarify how to
calculate and report biogenic CO2 emissions, referencing the
applicable methods in 40 CFR 98.33(e) and the reporting requirements in
40 CFR 98.3(c)(4) and (c)(12).
2. Summary of Comments and Responses
No significant comments were received on the specific technical
amendments to subpart D. Comments related to the proposed separate
reporting of biogenic emissions for units subject to 40 CFR part 75 can
be found in Sections II.C and II.G of this preamble.
I. Subpart F--Aluminum Production
1. Summary of Final Amendments and Major Changes Since Proposal
Throughout subpart F we are making corrections as needed for
typographical errors and alphanumeric sequencing. We are amending 40
CFR 98.63 to clarify that each perfluorocarbon (PFC) compound
(perfluoromethane, CF4, also called tetrafluoromethane, and
perfluoroethane, C2F6, also called
hexafluoroethane) 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 amending 40 CFR 98.64 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 that are not measured annually, but are instead measured on
a more or less frequent basis. We are also inserting dates into this
paragraph. In inserting these dates, we have decided to use dates in
reference to the effective date of the 2009 final rule, as opposed to
the publication date as was written in the final rule. It was
determined to be more appropriate to use the effective date of the rule
as the basis for the timing of the requirements. Therefore, we are
amending the paragraph to read ``December 31, 2010'' in place of ``one
year after publication of the rule'' and are inserting ``December 31,
2012'' in place of ``three years after publication of the rule.''
We are amending 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 amending Table F-1 to spell out the acronyms for the
technologies covered by that table; i.e., CWPB, SWPB, vertical stud
S[oslash]derberg (VSS), and horizontal stud S[oslash]derberg (HSS).
The comments received supported the proposed amendments, so the
amendments to subpart F are finalized as proposed.
2. Summary of Comments and Responses
One comment letter was received on this subpart, and it supported
the proposed amendments. The summary and response to this comment
letter can be found in the document, ``Response to Comments: Revision
to Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
J. Subpart G--Ammonia Manufacturing
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending subpart G to remove reporting of the waste recycle
stream or
[[Page 79119]]
purge, and to make subpart G conform to the amendments to the
calibration requirements in subpart A. With respect to the waste
recycle stream, we are eliminating 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 amending 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.
We are clarifying in 40 CFR 98.72(a) and in the definition of
CO2 in Equation G-5 that 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. We have
included this clarification because although the equations accurately
reflect total CO2 that is generated from the ammonia
manufacturing process, not all of that CO2 is released on
site. Rather, some of the CO2 may be used for urea
production and not be actually released to the atmosphere until use of
the urea at an off-site location.
We are amending 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, will 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 amending the definition of CO2 emissions in
Equation G-5 to indicate that the CO2 emissions estimates
under subpart G 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 change does not
affect the total CO2 emissions that are quantified and
reported to EPA under the calculation equations in 40 CFR 98.73.
Likewise, we are amending 40 CFR 98.76(b) to require reporting 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 amending subpart G to correct several
typographical errors and an incorrect cross-reference to another
subpart in 40 CFR part 98. We are correcting 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 correcting 40 CFR 98.76(a) by
changing the cross-reference from ``Sec. 98.37(e)(2)(vi)'' to ``Sec.
98.37.''
We are amending 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 amending 40 CFR 98.76(b)(6) to change
``petroleum coke'' to ``feedstock'' because petroleum coke is the
incorrect term, and amending 40 CFR 98.76(b)(15) to specify that the
carbon content analysis method being reported is for each month. We are
also removing 40 CFR 98.76(b)(17) for the reporting of urea produced,
if known, as well as reporting requirements in 40 CFR 98.76(c) for
total pounds of synthetic fertilizer produced and total nitrogen
contained in that fertilizer.
No major changes have been made to the amendatory language since
proposal.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: One commenter was supportive of all proposed amendments to
subpart G. However, we received adverse comments on the proposed
amendment to remove requirements to report the total quantity of
synthetic fertilizer produced and the nitrogen content of fertilizer.
The commenter asserted that EPA does not offer a reason for the
deletion of fertilizer reporting requirements, and noted that synthetic
fertilizer application drives a large fraction of N2O
emissions from agricultural soils. They asserted that the reporting
requirements should be retained for several reasons, including that
collecting information for N2O emissions, even if it is from
less than one-half of the total fertilizer produced, is valuable.
Further, the commenter contended that justifying removal of the
reporting requirement because of the availability of other data through
the Association of American Plant Food Control Officials is not
appropriate because those other data may not be available reliably into
the future and do not map emissions back to specific facilities. They
argued that reporting of synthetic fertilizer production is a good
first step in estimating N2O emissions from agricultural
soils.
Another commenter countered many of the points raised above,
asserting that data on domestic synthetic fertilizer production is not
a good indicator of N2O emissions from farming because the
rule did not capture all fertilizer production and not all fertilizer
is applied to fields.
Response: EPA has finalized, as proposed, the amendment to remove
reporting requirements of the total amount of synthetic fertilizer
produced and nitrogen contained in that fertilizer. EPA has concluded
that the burden placed on fertilizer production facilities to report on
total pounds of synthetic fertilizer and total nitrogen contained in
that fertilizer would not be commensurate with the value of the data we
would receive in terms of improving our ability to estimate
N2O emissions from soils. Specifically, facility specific
data from producers on the nitrogen content of synthetic fertilizer is
of minimal value in estimating soil N2O emissions by itself.
As explained in the proposal preamble (75 FR 48767), there are a
variety of inputs that would be valuable to consider to estimate
N2O emissions from agricultural soils, including fertilizer
application rates, timing of application, and the use of slow release
fertilizers and nitrification/release inhibitors, none of which would
be provided through the provision removed from the rule. Given that the
information required from the final rule would not provide sufficient
information to estimate N2O emissions from fertilizer
application to soils, we are removing the reporting requirement at this
time. While there is concern over the potential future loss of the
Association of American Plant Food Control Officials data, EPA has
determined that it is preferable to remove the incomplete reporting
requirement at this time and, if appropriate in the future, reconsider
in a comprehensive manner reporting of information on fertilizer
production, import and use practices.
[[Page 79120]]
K. Subpart P--Hydrogen Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending the definition of the terms for the average carbon
content (CCn) and molecular weight (MWn) in
Equation P-1 of 40 CFR 98.163 to clarify that, where measurements are
taken more frequently than monthly, CCn and MWn
should be calculated using the arithmetic average of measurement values
within the month.
We are amending 40 CFR 98.164(b)(1) so it is consistent with
today's amendments to 40 CFR 98.3(i). First, we are limiting 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
devices that are used to provide data for the GHG emissions
calculations have to be calibrated only 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 are removing 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)
apply only to gas and liquid flow meters. For oil tank drop
measurements, the QA requirements of 40 CFR 98.34(b)(2) apply.
As a harmonizing amendment with the amendment allowing the use of a
gas chromatograph (described in 40 CFR 98.164(b)(5)), we are adding the
phrase ``no less frequent'' to 40 CFR 98.164(b)(2). This change
indicates that when determining the carbon content and the molecular
weight of ``other gaseous fuels and feedstocks'' (e.g., biogas,
refinery gas, or process gas), you must undertake sampling and analysis
no less frequently than weekly. Replacing a ``weekly'' requirement with
``no less frequent than weekly'' allows for the use of continuous, on-
line equipment gas chromatographs.
We are amending 40 CFR 98.164(b)(5) to allow the use of
chromatographic analysis of the fuel, provided that the gas
chromatograph is operated, maintained, and calibrated according to the
manufacturer's instructions.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Modification of Equation P-1 to account for measurements
taken more frequently than monthly to determine the molecular weight of
the gaseous fuel and feedstock.
Inclusion of the option to use a gas chromatograph (both
continuous and non-continuous) for determining the carbon content and
molecular weight of gaseous fuels.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: One commenter noted that the fuels and feedstocks to a
hydrogen plant subject to subpart P requirements are often the same
fuels that are burned in combustion units subject to subpart C
requirements. The commenter further noted that both subparts had
different monitoring and QA/QC requirements which would pose a problem
for a facility trying to determine which method to use.
Response: No change has been made as a result of this comment. We
did not receive sufficient information from the commenter as to why
they would not be able to comply using the methods already prescribed
in subpart P for determining carbon content and molecular weight. As
noted by the commenter, facilities only subject to subpart C must use a
method published by a consensus standards organization if such a method
exists, or an industry consensus standard practice. Therefore, the
methods in the 2009 final rule for subpart P could be used to meet the
requirements in subpart C. We determined that it was appropriate to
open the methods to industry consensus standards or industry standard
practices for facilities subject to subpart C only, because the
industries covered by subpart C could be wide ranging and the specific
methods listed may not be appropriate for certain industry types.
Because the commenter does not provide specific concerns as to why the
methods listed in subpart P are not appropriate, we have decided not to
remove the applicable methods listed in subpart P and replace them with
the option to use consensus based standards or industry consensus
standards.
Comment: One commenter requested that EPA allow the use of gas
chromatographs as an alternative method for determining the carbon
content in gaseous fuels and feedstocks.
Response: EPA acknowledges the commenter's recommendation to
include the option to use gas chromatographs for measuring the carbon
content and molecular weight of fuels and feedstocks in subpart P. As a
result, EPA has revised the monitoring and QA/QC requirements to allow
the use of gas chromatographs, both continuous and non-continuous, to
determine the carbon content and molecular weight of fuels and
feedstocks provided that the gas chromatograph is operated, maintained,
and calibrated according to the manufacturer's instructions.
L. Subpart V--Nitric Acid Production
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 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 amendment is provided in Section II.J of
this preamble.
2. Summary of Comments and Responses
Several comments were received on the proposal to remove the
synthetic fertilizer and total nitrogen reporting requirement in 40 CFR
98.226(o). Please see section II.J (Ammonia Production) of this
preamble for the comments and responses related to reporting of
fertilizer production data.
M. Subpart X--Petrochemical Production
1. Summary of Final Amendments and Major Changes Since Proposal
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 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.
[[Page 79121]]
Reporting requirements for the ethylene-specific option.
Reporting measurement device calibrations.
For the mass balance option, sampling frequency when
receiving multiple deliveries from same supply source.
Distillation and recycling of waste solvent. We are adding a new
paragraph, as proposed, to 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.
Process vent emissions monitored by CEMS. We are adding a sentence,
as proposed, 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).
Process off-gas combustion in flares. We are amending 40 CFR
98.242(b), as proposed, by removing the reference to flares.
CH4 and N2O emissions from combustion of
process off-gas. We are amending 40 CFR 98.243(b), as proposed, to
clarify that either the default HHV for fuel gas or a site-specific
calculated HHV may be used when using Tier 3 procedures to calculate
CH4 and N2O emissions from combustion units that
burn petrochemical process off-gas and are monitored with a
CO2 CEMS.
Sampling frequency for mass balance method. We are amending 40 CFR
98.243(c)(3) to clarify that when multiple deliveries of a particular
liquid or solid feedstock are received from the same supply source in a
month, one representative sample is sufficient for the month. The
amendment is being made in response to a comment received. As explained
in section II.M.2 of this preamble, we are amending 40 CFR 98.243(c)(3)
to make the language in subpart X consistent with a similar amendment
for fuel sampling in 40 CFR 98.34(b)(3)(ii)(B). The new language does
not change the requirements in 40 CFR 98.243(c).
Molar volume conversion (MVC) factors. We are amending Equation X-
1, as proposed, 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 are being amended, as proposed, 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.
Methodology for small ethylene off-gas streams. We are finalizing
amendments to 40 CFR 98.243(d), as proposed, 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, Tier 1 or Tier 2 methods may be used
for ethylene process off-gas streams that meet either of the following
conditions:
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 (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 at an upstream common pipe.
The combustion unit has a maximum rated heat input
capacity of less than 30 mm Btu/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.
As in the proposal, this amendment also specifies 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. In response to comments we
are making an editorial change to the introductory paragraph of 40 CFR
98.243(d) to clarify that the common pipe reporting alternative may be
used when applicable; the intent of the requirements in this section
are not changed by this editorial change. We are also making a number
of other editorial changes to 40 CFR 98.243(d), as proposed, to
integrate the amended option with the existing requirements. Finally,
we are amending 40 CFR 98.246(d)(2) and 98.247(c), as proposed, to add
reporting and recordkeeping requirements that are related to the
amendments in 40 CFR 98.243(d)(2).
Monitoring methods for determining carbon content and composition.
We are finalizing the proposed addition of ASTM D2593-93 (Reapproved
2009), Standard Test Method for Butadiene Purity and Hydrocarbon
Impurities by Gas Chromatography, to 40 CFR 98.244(b)(4). We are
further amending 40 CFR 98.244(b)(4), as proposed, by adding a new
paragraph that will allow the use of industry standard practice to
determine the carbon content or composition of carbon black feedstock
oils and carbon black products.
We also added two more published methods to the list in 40 CFR
98.244(b)(4) of the final rule: ASTM D7633, Standard Test Method for
Carbon Black--Carbon Content, and EPA Method 9060A in EPA publication
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical
Methods. We also added an option, already proposed in subparts C and Y,
to use results of chromatographic analysis of feedstocks and products,
provided that the gas chromatograph is operated, maintained, and
calibrated according to the manufacturer's instructions. Finally, we
added an option to use results of a mass spectrometer analysis of a
feedstock or product, provided that the mass spectrometer is operated,
maintained, and calibrated according to the manufacturer's
instructions.
We are also amending 40 CFR 98.244(b)(4), as proposed, to provide
facilities the option to determine carbon content or composition of
feedstocks or products using modified versions of the analytical
methods listed in 40 CFR 98.244(b)(4) if the listed methods are not
appropriate for reasons noted below. The proposed amendments in this
section would have allowed the use of ``other analytical methods'' if
methods listed in 40 CFR 98.244(b)(4) are not appropriate for any of
the same reasons. However, in response to comments, we revised this
provision to allow the use of ``other methods'' rather than ``other
analytical methods'' so that non-analytical methods also can be used.
The conditions under which the listed methods may be considered
inappropriate are the same as at proposal. Specifically, a listed
method may be considered inappropriate if the relevant compounds cannot
be detected, the quality control requirements are not technically
feasible, or use of the method will be unsafe.
We are amending the reporting requirements in 40 CFR 98.246(a)(11),
as proposed, so that if an alternative method is used, facilities must
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. Also as proposed,
the amendments to 40 CFR 98.244(b)(4) may be used for the 2010
reporting year.
QA/QC requirements. To maintain consistency with the amendments to
40 CFR 98.3(i), we are amending, as proposed, the QA/QC provisions for
weighing devices, flow meters, and tank level measurement devices in 40
CFR 98.244 (b)(1), (b)(2), and (b)(3).
Reporting requirements under the CEMS compliance option. As
proposed, we are making a number of changes in
[[Page 79122]]
40 CFR 98.246(b)(1) through (b)(5) to clarify the reporting
requirements under the CEMS compliance option.
First, we are moving 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 adding 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 action) for CH4 and
N2O do not apply under subpart X because applicable
reporting requirements are specified in 40 CFR 98.246(b)(5).
Third, in the renumbered 40 CFR 98.246(b)(3), we are deleting 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 one must still 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 amending 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 amending 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 is monitored with
CO2 CEMS; this requirement will be unchanged. We are
amending 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 will also include emissions from combustion
of supplemental fuel (if any).
Finally, as proposed, we are finalizing 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 action). Most of the amendments
to 40 CFR 98.246(b)(5) restate requirements from 40 CFR
98.36(b)(9)(iii); for example, the 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, under 40 CFR 98.246(b)(5) you must also
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 N20 emissions
using Equation C-8 in subpart C (rather than Equation C-10), the
amendments to 40 CFR 98.246(b)(5) require reporting of the HHV that you
use in Equation C-8. We are also deleting the erroneous reference to
Equation C-10 that was included in 40 CFR 98.246(b)(5).
Reporting requirements for the ethylene-specific option. As
proposed, we are finalizing several amendments to clarify the reporting
requirements in 40 CFR 98.246(c) for the combustion-based methodology
that is available to the ethylene-specific option. First, we are adding
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 making 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, we are replacing 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. As proposed in 40 CFR
98.246(a)(7) we are deleting the requirement for reporting of the dates
and summarized results of calibrations of each measurement device under
the mass balance option, and we are also adding 40 CFR 98.247(b)(4) to
require retention of these records.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Additional methods for determining carbon content or
composition of feedstocks and products were added to 40 CFR
98.244(b)(4).
For the optional combustion method for ethylene processes,
the introductory paragraph in 40 CFR 98.243(d) was edited to require
calculation of GHG emissions from ``combustion units'' rather than from
``each combustion unit.'' This change makes it clear that the common
pipe reporting alternative specified in 40 CFR 98.36(c)(3) of subpart C
may be used when applicable, and it makes 40 CFR 98.243(d) consistent
with the reporting requirements for the ethylene process option as
specified in 40 CFR 98.246(c).
For the mass balance option, 40 CFR 98.243(c)(3) was
revised to specify that multiple deliveries of a particular liquid or
solid feedstock in a month from the same supply source may be
considered a single feedstock lot, requiring only one representative
sample for carbon content analysis. This change makes the analysis
requirements for feedstocks consistent with the amended requirements
for fuels in 40 CFR 98.34(b)(3)(ii)(B).
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Several commenters requested either the addition of
specific carbon content or composition measurement methods in 40 CFR
98.244(b)(4) or other changes that would increase measurement
flexibility. One commenter requested that EPA Method 9060 of SW-846 be
added to the list of methods, and that the list of methods be modified
to allow for the use of a company-specific method for measuring
acetonitrile as an alternative to using EPA Method 8015 in SW-846. One
commenter requested that ASTM D7633, Standard Test Method for Carbon
Black--Carbon Content, be added to the list of methods because it has
recently been accepted and approved by ASTM. This commenter also noted
that ASTM is currently reviewing a method for carbon content in carbon
black feedstock oils and requested addition of a statement indicating
that once this method is approved and assigned an official number by
ASTM that it is effective as of January 1, 2010. One commenter
requested that EPA remove the reference to ``analytical'' in the phrase
``other analytical methods'' in proposed 40 CFR 98.244(b)(4)(xiii)
(renumbered as paragraph (xv)(A) in the final amendments) so that the
carbon content of ethylene oxide and water solutions
[[Page 79123]]
could be measured using a densitometer. One commenter stated that 40
CFR 98.244(b)(4) should be expanded to allow the use of an on-line mass
spectrometer to determine the carbon content and molecular weights. One
commenter stated that requirements for gas chromatography should be
consistent across all subparts and that EPA should extend the
requirements for the use of gas chromatographs under subpart C to
subpart X. Specifically, the commenter requested that the use of gas
chromatographs be allowed, ``provided that the gas chromatograph is
operated, maintained, and calibrated according to the manufacturer's
instructions.'' One commenter noted that the proposed amendments to
subpart C added flexibility to the carbon content analysis requirements
for fuels by eliminating the list of specific methods and instead
allowing a broader array of methods (i.e., industry consensus standard
practice, method published by a consensus-based standards organization,
or results of gas chromatographic analysis). This commenter stated that
the same flexibility should be allowed for feedstock and product
analysis under subpart X.
Response: In the preamble to the proposed amendments we indicated
that we would consider adding carbon content methods for carbon black
and carbon black feedstock oil if they were approved by ASTM before
publication of the final amendments. Because it has been approved by
ASTM, we have added Method D7633, Standard Test Method for Carbon
Black--Carbon Content, to 40 CFR 98.244(b)(4). We have not added the
requested statement regarding the method for determining carbon content
in carbon black feedstock oil because we cannot cite a specific method
without being able to incorporate it by reference, and incorporation by
reference is possible only if a copy of the method is available.
However, if this method is a current industry standard practice, its
use since January 1, 2010, is allowed by 40 CFR 98.244(b)(4)(xv) of the
final amendments.
We have also decided to make four of the other changes suggested by
commenters. First, we have added EPA Method 9060A in SW-846 because a
commenter indicated that it is much more effective at detecting organic
compounds in a liquid waste stream than any of the listed methods.
Because none of the currently listed methods effectively detect these
compounds in the waste stream, an alternative method such as EPA Method
9060A in SW-846 would already be allowed under 40 CFR
98.244(b)(4)(xv)(A) of the final amendments. However, specifically
listing the method will make demonstrating compliance more
straightforward.
Second, we have deleted the word ``analytical'' from the phrase
``other analytical methods'' in 40 CFR 98.244(b)(4)(xv)(A) of the final
amendments so that non-analytical methods can be used. We agree with
the commenter that this change is needed so that a densitometer can be
used to determine the carbon content in an ethylene oxide and water
solution. We also agree that a non-analytical alternative must be
available in cases where the carbon content of the solution cannot
safely be determined using any of the listed analytical methods or
modifications of them.
Third, we have added the option from subpart C to use results from
a gas chromatograph, provided the instrument is operated, maintained,
and calibrated according to the manufacturer's instructions. This
change means there is a common option in both subparts C and X, which
we have determined is important because some materials may be a fuel in
some applications and a petrochemical feedstock in others (e.g.,
ethylene feedstocks). With this change, a facility would not have to
use two methods to determine the carbon content of the same material.
Fourth, we have added an option to use a mass spectrometer to
determine the carbon content of a feedstock or product. Although a mass
spectrometer would more commonly be used as one type of detector to
determine the concentration of individual compounds separated in a gas
chromatograph, using a mass spectrometer alone to determine the overall
carbon content is also acceptable.
Finally, we have decided not to delete the list of specified
methods and replace them with a general statement allowing the use of
any industry consensus standard practice or method published by a
consensus-based standards organization. We have received considerable
input from the industry on methods that are actually being used. We
conclude that the existing flexibility in the final amendments is
sufficient, and that there is no need to allow the use of other
unspecified methods. We recognize that this is not consistent with the
methodologies allowed for determining carbon content in subpart C;
however, we have concluded that this is justified given the wide
variety of industries subject to subpart C versus the more narrowly-
focused sources subject to subpart X.
We are not specifically allowing the use of a company-specific
method for the determination of carbon content in acetonitrile because
we are not convinced that it is necessary. The commenter indicated that
they can use EPA Method 8015 of SW-846, and they have not indicated any
problems with using this method. It is also possible that their
company-specific method would qualify as a modification to a listed
method that would be allowed if any of the criteria in 40 CFR
98.244(b)(4)(xv)(A) of the final amendments are met. Therefore, we have
not made the requested change.
Comment: One commenter requested a modification to 40 CFR
98.243(c)(3) for carbon black production processes that specifies all
deliveries of a fuel or feedstock oil in a month from the same supply
source are considered to be a fuel lot, and carbon content must be
determined for only one representative sample from the lot.
Response: Although we did not propose amendments to the sampling
and analysis requirements in 40 CFR 98.243(c)(3), we did propose a
change similar to that suggested by the commenter in 40 CFR
98.34(b)(3)(ii)(B) of subpart C for fuels. Subpart X currently requires
you to determine the carbon content for at least one sample of each
feedstock and product per month. In addition, if you make more than one
valid carbon content measurement during the month (from separate
samples), then you must average the results arithmetically. (Note that
this language does not require sampling and analysis for each delivery
of a feedstock. Furthermore, each delivery of the same material, even
from different suppliers, is not considered to be a separate
feedstock.) However, we agree with the commenter that if multiple
deliveries of the same feedstock are received from the same supply
source, one representative sample is sufficient for the month.
Therefore, we have amended 40 CFR 98.243(c)(3) in the interest of
improving the operating flexibility of the rule. We have also broadened
the statement so that it applies for any liquid or solid feedstock.
Please see the amended rule language to 40 CFR 98.243(c)(3).
Comment: One commenter stated that the proposed term ``each
combustion unit'' in the introductory paragraph of 40 CFR 98.243(d)
appears to preclude the use of the common pipe reporting alternative in
40 CFR 98.36(c)(3). According to the commenter, the common pipe option
is appropriate for ethylene processes, and precluding it will not
improve the quality of GHG emission estimates. Therefore, the
[[Page 79124]]
commenter requests that ``each combustion unit'' be changed to
``combustion units.''
Response: We have made the suggested change in the final amendments
because we agree with the commenter's assessment of the proposed
language. We did not intend to preclude the use of the common pipe
option, as evidenced by the fact that 40 CFR 98.243(d)(2)(i) and (ii)
both specify that the determination of when Tier 1 and Tier 2
procedures may be used is to be based on whether there is an existing
flow meter either in the line to the combustion device or an upstream
common pipe. Moreover, the reporting requirements in 40 CFR
98.246(c)(2) require reporting for each stationary combustion unit, or
group of stationary sources with a common pipe.
N. Subpart Y--Petroleum Refineries
1. Summary of Final Amendments and Major Changes Since Proposal
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 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
asphalt blowing operations controlled by thermal oxidizer or flare.
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.
Monitoring and QA/QC requirements.
Reporting requirements.
GHG emissions from flares. We are finalizing corrections to 40 CFR
98.252(a) (GHGs to report) as proposed to clarify the required
emissions methods for flares. 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 reporters must
``Calculate and report the emissions from flares under this subpart.''
GHG emissions to report from combustion of fuel gas. We are
finalizing amendments to 40 CFR 98.252(a) as proposed to clarify that
reporting of CH4 and N2O emissions is required
for the stationary combustion units fired with fuel gas. As described
in Section II.G of this preamble, we are also amending the definition
of fuel gas.
GHG emissions to report from non-merchant hydrogen production
process units. As proposed, we are amending 40 CFR 98.252(i) to clarify
that reporting of only CO2 emissions is required for non-
merchant hydrogen production process units.
Calculating GHG emissions from fuel gas combustion. We are
finalizing amendments to 40 CFR 98.252(a), as proposed, so that
petroleum refineries subject to subpart Y can use the Tier 1 or 2
methodologies in subpart C for combustion of fuel gas when either of
the following conditions exists:
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 exists:
--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.
The combustion unit has a maximum rated heat input capacity of
less than 30 mmBtu/hr, and either of the following conditions exists:
--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.
Calculating combustion GHG emissions from flares and asphalt
blowing operations controlled by thermal oxidizer or flare. As
proposed, we are finalizing amendments to 40 CFR 98.253 to renumber
existing Equations Y-1 and Y-16 as Equations Y-1a and Y-16a, and adding
the more detailed Equations Y-1b and Y-16b that provide more detailed
alternative methods for calculating emissions. We are also finalizing
corresponding amendments in 40 CFR 98.256 as proposed to require
reporting of which equation was used and, if the new equations are
used, reporting of the additional equation parameters.
Molar volume conversion factors. We are finalizing amendments to
Equations Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y-20, and Y-23 in subpart Y
as proposed to provide two alternative values of MVC depending on the
standard conditions output by the flow monitors. For reasons outlined
in the ``Response to Comments: Revision to Certain Provisions of the
Mandatory Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-
0508), we are also finalizing a similar amendment to Equation Y-2, as a
logical outgrowth of the proposal and comments received to provide two
alternative values of MVC in this equation (if mass flow monitors are
used) depending on the standard conditions at which the higher heating
value is determined. Additionally, the reporting requirements related
to each of these equations are being amended to include reporting of
the value of MVC used to support the calculations and to allow
verification of the reported emissions.
Combined stacks monitored by CEMS. As proposed, we are amending 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.
Nitrogen concentration monitoring to determine exhaust gas flow
rate. As proposed, we are amending 40 CFR 98.253(c)(2)(ii) to renumber
Equation Y-7 as Equation Y-7a and to add an Equation Y-7b to provide an
alternative N2 concentration monitoring approach for
determining the exhaust gas flow rate. We are also finalizing reporting
requirements in 40 CFR 98.256(f)(9) to report the input parameters for
Equation Y-7b if it is used.
Calculating CO2 emissions from catalytic reforming units. We are
finalizing amendments to the definition of the coke burn-off quantity,
CBQ, and the term ``n'' in Equation Y-11 in 40 CFR
98.253(e)(3) as proposed to clarify the application of Equation Y-11 to
continuously regenerated catalytic reforming units.
Calculating GHG emissions from sulfur recovery plants. We are
amending 40 CFR 98.253(f) as proposed 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
[[Page 79125]]
allow non-Claus sulfur recovery plants to alternatively follow the
requirements in 40 CFR 98.253(j) for process vents. We also are
finalizing amendments to the reporting requirements in 40 CFR 98.256(h)
as proposed to include the type of sulfur recovery plant, an indication
of the method used to calculate CO2 emissions, and reporting
requirements for non-Claus sulfur recovery plants that elect to follow
the requirements in 40 CFR 98.253(j) for process vents.
Calculating CO2 emissions from coke calcining units. We are
amending the definition of Mdust (the mass of dust collected
in the dust collection system) in Equation Y-13 in 40 CFR 98.253(g) as
proposed to clarify that dust recycled back to the coke calciner is not
included in the mass of dust collected in the dust collection system
(Mdust). We also are finalizing amendments to 40 CFR
98.256(i)(5), as proposed, 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 finalizing
amendments to the process vent requirements in 40 CFR 98.253(j) as
proposed to account for 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). We are also amending the reporting requirements for
process vents in 40 CFR 98.256(l) as proposed to clarify that the
requirements apply to each process vent, and 40 CFR 98.256(l)(5) to
require an indication of the measurement or estimation method for the
volumetric flow rate and the mole fraction of the GHG in the vent.
Finally, we are finalizing amendments to 40 CFR 98.253(n) as
proposed 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.
Monitoring and QA/QC requirements. We are finalizing amendments to
the monitoring and QA/QC requirements in subpart Y, 40 CFR 98.254 as
proposed, except as provided below. We proposed amendments to require
all gas flow meters on process vents subject to reporting under 40 CFR
98.253(j) to comply with the monitoring requirements in 40 CFR
98.254(f). However, for the reasons set forth in the Response to
Comments (Section N.2. of this preamble), we are finalizing amendments
for gas flow meters on process vents subject to reporting under 40 CFR
98.253(j) to comply with the monitoring requirements in 40 CFR
98.254(c).
A summary of the amendments to the monitoring and QA/QC
requirements that we are finalizing as proposed is below. Paragraph (a)
of 40 CFR 98.254 is amended to include also the phrase ``sources that
use a CEMS to measure CO2 emissions according to subpart C
of this part * * *'' to separate further these sources from those that
are covered by 40 CFR 98.254(b). We also are re-wording the phrase
``follow the monitoring and QA/QC requirements in Sec. 98.34'' with
``meet the applicable monitoring and QA/QC requirements in Sec.
98.34'' to clarify that the monitors must meet the requirements for the
specific tier for which monitoring was required (Tier 3 sources will
comply with the Tier 3 requirements; Tier 4 sources will 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) will be included in the amended
paragraph 40 CFR 98.254(a), we are removing 40 CFR 98.254(l).
Paragraph (b) of 40 CFR 98.254 is 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
are correcting 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
are also clarifying that the calibration requirements in 40 CFR 98.3(i)
only apply to gas flow meters and allowing 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 is
also 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 is 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 is being removed from 40 CFR 98.254(c). We are
also amending 40 CFR 98.254(c) by removing the list of methods as this
is redundant to the existing phrase, ``a method published by a
consensus-based standards organization.''
Paragraphs (d) and (e) of 40 CFR 98.254 are 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 (e), provided that the gas chromatograph is operated,
maintained, and calibrated according to the manufacturer's
instructions. The methods used for operation, maintenance, and
calibration of the gas chromatograph must be documented in the written
monitoring plan for the unit under 40 CFR 98.3(g)(5). Paragraph (d) in
40 CFR 98.254 is also 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.
We are also amending 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 adding an additional method (ASTM D2503-92) to this section for
determining average molecular weight.
We are making a number of amendments to 40 CFR 98.254(f). The term
``exhaust gas flow meter'' is replaced with the term ``gas flow
meter,'' as proposed.
We are retaining 40 CFR 98.254(f)(3) and portions of 40 CFR
98.254(f)(1) but only as general, supplementary guidelines for flow
monitor installation and operation. Thus, we are amending 40 CFR 98.254
to require that reporters must do all of the following:
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 making a technical correction to 40 CFR 98.254(g) to correct
the cross-reference from 40 CFR 63.1572(a) to 40 CFR 63.1572(c).
We are amending 40 CFR 98.254(h) to require calibration of mass
measurement equipment according to the procedures specified by National
Institute of Standards and Technology (NIST)
[[Page 79126]]
Handbook 44 or the procedures specified by the manufacturer, and
removing reference to the calibration requirements in 40 CFR 98.3(i).
Reporting requirements. This section covers reporting requirements
that have not been described in previous sections of this preamble.
We are amending the reporting requirements in 40 CFR 98.256(e)(6)
and (8) for Equations Y-1 (renumbered to Y-1a) and Y-2, respectively,
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 amending the references to 40 CFR 98.36(e)(2)(vi)
to reference 40 CFR 98.36 more generally. This will make the references
consistent with the associated requirements in 40 CFR 98.253.
We are amending 40 CFR 98.256(f) to require 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 amending 40 CFR 98.256(i)(8) to make it consistent with the
information collected in 40 CFR 98.245(i)(7).
We are also amending 40 CFR 98.256(j)(2) to clarify that the
reporting requirements for asphalt blowing apply at the unit level.
We are also amending 40 CFR 98.256(o) to re-organize the reporting
requirements to separate and clarify the reporting requirement for
storage tanks used for processing unstabilized crude oil from those
reporting requirements for other types of storage tanks.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
Amending Equation Y-2 in subpart Y to provide two
alternative values of MVC in this equation (if mass flow monitors are
used) depending on the standard conditions at which the higher heating
value is determined.
Amending requirements for gas flow meters on process vents
subject to reporting under 40 CFR 98.253(j) to comply with the
monitoring requirements in 40 CFR 98.254(c) rather than 40 CFR
98.254(f).
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional comments received can be found in the document, ``Response
to Comments: Revision to Certain Provisions of the Mandatory Reporting
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: One commenter stated that they have identified gas streams
that would otherwise fit the requirements for the use of the Tier 1 or
Tier 2 methodologies, as proposed in 40 CFR 98.252(a)(1) and (2), if it
were not for the fact that they are equipped with flow meters.
According to the commenter, these streams are not what industry would
define as ``refinery fuel gas'' but would fall under the realm of
``fuel gas'' as originally defined in 40 CFR 98.6 in the October 30,
2009, final Part 98, and in the amended definition. These can include
streams that are process off-gas or vent gases with properties much
different from traditional ``refinery fuel gas'' streams and are not
part of the refinery's fuel gas system. According to the commenter,
these off-gas streams may not be sampled currently. The commenter
asserted that many of these streams are difficult to sample (for
example, because of low pressure) or may present hazardous sampling
conditions. According to the commenter, the added rigor associated with
Tier 3 requirements is not justified for the increased safety risk,
considering the very small contribution of emissions (on the order of
0.1 percent of a refinery's total greenhouse gas emissions as estimated
by the commenter).
Response: The proposed amendments provided limited exclusions to
the Tier 3 requirement for very small fuel gas lines or combustion
units that are not equipped with a flow meter. As noted in the preamble
of the August 11, 2010, proposed amendments, the exclusion was
specifically targeted to prevent the need to install flow meters for
these small fuel gas lines. EPA noted that ``[i]f 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.''
(See 75 FR 48772.) The commenter indicated that these gas streams could
have a significantly different composition than typical refinery fuel
gas, which suggests the default fuel gas factor would have considerable
uncertainty for these gas streams, further indicating that Tier 3
sampling is necessary. While we recognize that there are inherent
safety issues with sampling any fuel gas streams, the commenter has not
provided any supporting information for the assertion that sampling
these ``process off-gas or vent gases'' is more hazardous than other
fuel gas streams at the refinery. Therefore, we are not expanding the
proposed exclusion to the Tier 3 methodology for fuel gas lines that
have a flow meter already installed in the line or upstream common
pipe. We also note that today's final amendments are not imposing new
requirements to sample these fuel gas streams; the October 30, 2009,
final Part 98 already required these fuel gas streams to be sampled for
carbon content no less than once per calendar week.
Comment: One commenter objected to the proposed revision of 40 CFR
98.254(f) to also require exhaust gas flow meters associated with
process vents (i.e., subject to 40 CFR 98.253(j) requirements) to be
installed, operated, calibrated and maintained according the Petroleum
Refineries NESHAP (40 CFR part 63, subpart UUU) requirements in 40 CFR
63.1572(c). According to the commenter, the Petroleum Refineries NESHAP
requirements in 40 CFR 63.1572(c) contain provisions that are more
stringent than the monitoring and QA/QC requirements throughout Part
98. For example, 40 CFR 63.1572(c) requires each monitoring system to
have valid hourly average data from at least 75 percent of the hours
during which the process operated and to complete a minimum of one
cycle of operation for each successive 15-minute period with a minimum
of four successive cycles of operation to have a valid hour of data (or
at least two if a calibration check is performed during that hour or if
the continuous parameter monitoring system is out-of-control). The
commenter stated that, since the flow monitoring requirements for the
Petroleum Refineries NESHAP in 40 CFR 63.1572(c) were established to
demonstrate compliance with emission limits, they should not be used as
a template for requirements of flow metering for GHG reporting. The
commenter recommended that the process vent exhaust flow meter
requirements should be consistent with the requirements in 40 CFR
98.254(c) for flare and sour gas flow meters.
Response: We proposed to include the requirements for flow meters
used to comply with the 40 CFR 98.253(j) for process vents within the
monitoring provisions of 40 CFR 98.254(f) because these meters are
exhaust gas flow meters rather than fuel gas flow meters. However, we
agree with the commenter that the inclusion of flow meters used to
comply with the 40 CFR 98.253(j) within the monitoring provisions of 40
CFR 98.254(f) added new requirements
[[Page 79127]]
to these flow meters. While we believe that the flow meter requirements
in 40 CFR 63.1572(c) of the Petroleum Refineries NESHAP are reasonable
requirements for exhaust gas flow meters in general (40 CFR 63.1572(c)
are requirements for parameter monitoring systems, not continuous
emission monitoring systems), we agree with the commenter that it is
inappropriate to add these requirements to process vent flow meters at
this juncture. Furthermore, the provisions in 40 CFR 98.253(j) allow
use of process knowledge or engineering calculations as an alternative
to direct flow measurement. As such, it is incongruous to subject
facilities that have flow meters on these process vents to additional
requirements when facilities that do not have flow meters on these
process vents may use process knowledge or engineering calculations.
Therefore, we are finalizing requirements for flow meters used to
comply with 40 CFR 98.253(j) for process vents to meet the monitoring
provisions of 40 CFR 98.254(c) rather than 40 CFR 98.254(f) as was
required per the October 30, 2009 final Part 98.
O. Subpart AA--Pulp and Paper Manufacturing
1. Summary of Final Amendments and Major Changes Since Proposal
We are amending 40 CFR 98.273(a)(1), (b)(1) and (c)(1) to clarify
that owners and operators may choose to use a tier other than Tier 1
from 40 CFR 98.33 to calculate fossil-fuel based CO2
emissions.
We have removed the CO2 emission factors from Table AA-2
and revised 40 CFR 98.273(c)(1) to direct owners and operators to use
the CO2 emission factors from Table C-1 of subpart C to
calculate CO2 emissions from lime kilns.
With respect to calculating CH4 and N2O
emissions from fossil fuel combustion at lime kilns, and consistent
with the amendments to allow use of higher tiers than Tier 1 for units
subject to subpart AA, we are amending 40 CFR 98.273(a)(2), (b)(2), and
(c)(2) to allow reporters to also use site-specific high heating
values, as opposed to default values, when calculating CH4
and N2O emissions. We are making harmonizing amendments to
the definition of EF under Equation AA-1 to clarify that default or
site-specific emission factors may be used. Similarly, we are amending
40 CFR 98.276(e) to reflect the option to use default or site-specific
values.
We are clarifying through this final rule that emissions from the
combustion of wastewater treatment sludge are calculated using the
emission factors included in Table C-1. We have determined that 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
adding the definition of ``Wood and Wood Residuals'' to 40 CFR 98.6 and
including wastewater process sludge from paper mills in this
definition, as further described in Section II.F of this preamble.
We are adding solid petroleum coke to both Table C-1 and Table AA-
2. We have concluded that it is not necessary to have emission factors
for petroleum coke specific to kraft calciners in Table AA-2 because we
do not believe that any kraft calciners are combusting this fuel, nor
were any comments received suggesting this was not the case.
There were no comments received specifically on subpart AA,
therefore the amendments are being finalized as proposed.
P. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
1. Summary of Final Amendments and Major Changes Since Proposal
Threshold for natural gas local distribution companies. We are
amending 40 CFR Table A-5 of subpart A of 40 CFR part 98 to establish
an applicability threshold so that only local distribution companies
(LDCs) that deliver 460,000 thousand standard cubic feet (mscf) or more
of natural gas per year are subject to the reporting rule. No major
changes have been made since proposal.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Two commenters requested that EPA apply the 460,000
thousand standard cubic feet (mscf) applicability threshold throughout
40 CFR part 98 wherever a threshold is expressed in mtCO2e.
Specifically, they contended that 40 CFR 98.2(i)(1) and (2) should be
changed to allow LDCs to stop reporting if they deliver less than 460
million cubic feet (mmcf) for 5 consecutive years or less than 276 mmcf
for 3 consecutive years (25,000 mtCO2e is approximately
equivalent to the CO2 emissions from the combustion of 460
mmcf of natural gas and 15,000 mtCO2e is approximately
equivalent to 276 mmcf of natural gas). The commenters urged EPA to
clarify that the threshold for natural gas distributors (460,000 mscf)
is equivalent to the threshold of 25,000 mtCO2e wherever
that metric ton threshold appears in the rule.
Response: EPA has finalized an applicability threshold for LDCs of
460,000 mscf or more of natural gas delivered per year. As noted by the
commenters, we decided that it would be easier for LDCs to determine
whether or not they were above a reporting threshold expressed in mscf
than if that threshold were expressed in metric tons of carbon dioxide
equivalent for the first year of this reporting program.
However, we have not changed the conditions for ceasing reporting.
In the 2009 final rule, 40 CFR 98.2(i) states, ``Except as provided in
this paragraph, once a facility or supplier is subject to the
requirements of this part, the owner or operator must continue for each
year thereafter to comply with all requirements of this part, including
the requirement to submit annual GHG reports, even if the facility or
supplier does not meet the applicability requirements in paragraph (a)
of this section in a future year.'' As noted by the commenter,
facilities and suppliers can cease reporting when reported emissions
are below 25,000 mtCO2e for five consecutive years or below
15,000 mtCO2e for three consecutive years, as specified in
40 CFR 98.2(i)(1) and (i)(2), respectively. It is clear in the final
rule that other than these two exceptions, a facility or supplier must
continue to report even if the facility or supplier no longer meets the
threshold for reporting
EPA has concluded that applying a consistent threshold, expressed
in mtCO2e, in 98.2(i)(1) and 98.2(i)(2) for all reporters
levels the playing field for all reporters and is most logical. EPA
does not intend to provide equivalent thresholds under 40 CFR 98.2(i)
for various categories because it becomes too cumbersome. LDCs are
required to report, under 40 CFR 98.406(b)(8), the total annual
CO2 mass emissions that would result from complete
combustion of the natural gas delivered to end-users. By performing
this required calculation, LDCs have the necessary data to determine
whether they may cease reporting.
[[Page 79128]]
Q. Subpart OO--Suppliers of Industrial Greenhouse Gases
1. Summary of Final Amendments and Major Changes Since Proposal
We are making several changes to subpart OO to respond to concerns
raised by producers of fluorinated GHGs regarding the scope of the
monitoring and reporting requirements, and 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 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;
are produced and transformed at the same facility; or occur as low-
concentration constituents (e.g., 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.
In response to the concern regarding fluorinated GHGs that are
emitted or destroyed before the product is packaged for sale, we are
amending 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).'' We are also removing 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 Sec. 98.413(a) because they are
removed from the production process as by-products or wastes.''
Finally, we are modifying the requirements at 40 CFR 98.414(h),
98.416(a)(3), and 98.416(a)(11) to limit them to the mass of each
fluorinated GHG that is fed into the destruction device (or
``destroyed'' in the case of 40 CFR 98.416(a)(3)) and that was
previously produced as defined at 40 CFR 98.410(b).
These amendments will clarify that the scope of subpart OO is that
which EPA has always intended, and they will 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 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.
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). Emissions upstream of the production measurement
will be subject to the recently promulgated subpart L, which was signed
by EPA Administrator Lisa Jackson on November 8, 2010 and are not part
of the subpart OO source category.
We are also amending 40 CFR 98.416(a)(3) and (a)(11) to limit the
monitoring and reporting of destroyed fluorinated GHGs to those
destroyed fluorinated GHGs that were previously ``produced'' under
today's revised definition.\6\ 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,\7\ 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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\6\ 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.
\7\ 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 amending 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.'' We are also amending the
definition of ``produce a fluorinated GHG'' in 40 CFR 98.410(b) 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.'' We
are also adding a definition of ``isolated intermediate'' to 40 CFR
98.418. Finally, we are adding 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 excluding the
latter from the definition of ``produce a fluorinated GHG,'' we are
including the former in that definition. This is because the
manufacture of isolated intermediates, which can lead to emissions of
those intermediates, will be of interest under the recently promulgated
subpart L and it is desirable 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 adding provisions
to exclude it from the subpart OO monitoring, reporting, and
recordkeeping requirements. We are also adding a definition of
``isolated
[[Page 79129]]
intermediate'' that is the same as that for the recently promulgated
subpart L.
In response to the concern regarding fluorinated GHGs that occur as
low-concentration constituents of fluorinated GHG products, we are
defining and excluding 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 defining a low-concentration constituent in 40 CFR
98.418 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 (Air-
Conditioning, Heating, and Refrigeration Institute (AHRI) 700), for
SF6 used as an insulator in electrical equipment
(International Electrotechnical Commission (IEC) 60376), and for
perfluorocarbons and other fluorinated GHGs used in electronics
manufacturing (Semiconductor Equipment and Materials International
(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 less than 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 less than 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 adding
product sampling and analytical requirements at 40 CFR 98.414(n),
corresponding calibration requirements at 40 CFR 98.414(o), and a
corresponding reporting requirement at 40 CFR 98.416(f). We are also
clarifying in 40 CFR 98.414(a) how to calculate production of each
fluorinated GHG constituent of a product.
For purposes of fluorinated GHG imports, we are defining a ``low-
concentration constituent'' in 40 CFR 98.418 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 defining 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.
In response to the concerns regarding fluorinated GHGs that do not
have GWPs listed in Table A-1, we are amending subpart A to exempt such
compounds from the general subpart A requirement to report supply flows
in terms of CO2 equivalents and revising the reporting
exemptions for import and export of small shipments to be 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.F of this preamble. The exemptions for import
and export will 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 will enable small
shipments of fluorinated GHGs to be exempt from reporting regardless of
whether or not the fluorinated GHG has a GWP listed in Table A-1.
Other corrections. We are also amending the reporting and
recordkeeping provisions in subpart OO to clarify those requirements
and to correct internal inconsistencies in the subpart.
We are amending 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 amending 40 CFR 98.416(b) and (e) to clarify the due dates
of the one-time reports required by those paragraphs. The 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 originally April 1, 2011, and
there was no provision for fluorinated GHG destruction or production
commenced after that date.
We are amending 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 amending 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 amending 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.''
EPA is making one clarifying editorial change in the final rule
amendments that was not in the proposed amendments. As discussed above
and in the preamble to the proposed amendments, 40 CFR 98.414(h)
requires facilities to measure the mass of each fluorinated GHG that is
fed into the destruction device and that was previously produced. If
the mass being fed into the destruction device includes more than trace
concentrations of materials other than the fluorinated GHG being
destroyed, facilities must estimate the concentrations of the
fluorinated GHGs being destroyed. They must then multiply these
concentrations by the mass measurement to obtain the mass of the
fluorinated GHGs fed into the destruction device. In the proposed
paragraph (h), the final sentence read, ``You must multiply this
concentration (mass fraction) by the mass measurement to obtain the
mass of the fluorinated GHG destroyed.'' To be consistent with the
beginning of the paragraph and to be mathematically correct, this
sentence has been corrected in the final rule to read, ``You must
multiply this concentration (mass fraction) by the mass measurement to
obtain the mass of the fluorinated GHG fed into the destruction
device.'' As specified in Equation OO-4 of 40 CFR 98.413(d), the mass
of the fluorinated GHG destroyed is obtained by multiplying the mass of
the fluorinated GHG fed into the destruction device by the destruction
efficiency of the destruction device.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: Two commenters expressed concerns that exempting low-
concentration constituents of products from monitoring and reporting
would exempt a significant amount of
[[Page 79130]]
emissions from reporting. These commenters requested additional
information on the GWPs of these low-concentration constituents and on
the emissions affected by the exemption.
Response: We analyzed the potential impact of low-concentration
constituents on the total calculated flows of fluorinated GHGs into the
U.S. economy, considering both the possible masses of the low-
concentration constituents and their CO2-equivalents. We
concluded that at a level of 0.1 percent of production and 0.5 percent
of imports, identification of such constituents would have a negligible
impact on the total calculated flows of fluorinated GHGs into the U.S.
supply. It is important to note that, under the exemption for low-
concentration constituents, the masses and CO2e of low-
concentration constituents are not equated to zero. Instead, the mass
of the low-concentration constituent is assigned to the main
constituent of the product, and the GWP is assumed to be that of the
main constituent of the product. Only if the GWP or atmospheric
lifetime of the low-concentration constituent is significantly higher
than that of the main constituent is there a potential concern
associated with these assumptions.
As noted in the preamble to the proposed rule, low-concentration
constituents are generally by-products of the reaction used to produce
the fluorinated GHG product. Although we do not have information on
every product and by-product combination, we believe, based on the
examples of which we are aware, that by-products rarely have GWPs that
are more than ten times as large as that of the product. We analyzed
the potential impact of a by-product that had ten times the GWP of the
product on the weighted GWP of the combination of the two. At a
concentration of 0.1 percent, the by-product would raise the weighted
GWP (and CO2e) above that of the product by just under one
percent. Given that the impacts of most low-concentration constituents
are likely to fall below this level, we do not consider them
significant.
We also performed an analysis in which we conservatively assumed
that every HFC, PFC, and SF6 product had a PFC by-product
that was shipped along with it at a concentration of 0.1 percent. This
was intended to address the possibility that low-concentration
constituents had very long atmospheric lifetimes. Based on this worst-
case assumption, the quantity of PFCs flowing into the U.S. fluorinated
GHG supply was increased by less than 10 percent. It is extremely
unlikely that every HFC, PFC, and SF6 product has a PFC by-
product; in fact, the highest-volume products, the HFCs, are unlikely
to have PFC by-products. Therefore, in consideration of this analysis
and the GWP analysis, we have concluded that the exemption for low-
concentration constituents is very unlikely to lead to significant
errors in our understanding of potential emissions of fluorinated GHGs
from the U.S. supply.
Comment: Two commenters expressed concerns regarding the proposal
to exclude from subpart OO fluorinated GHGs that are emitted or
destroyed before the fluorinated product is packaged for sale. They
requested that EPA ensure that these emissions were fully captured
under the reporting rule (e.g., subpart L) and requested that EPA
document the magnitude of these emissions and the identities and GWPs
of the compounds emitted.
Response: As proposed, we are excluding from the definition of
``produce a fluorinated GHG'' the creation of fluorinated GHGs that are
released or destroyed at the production facility before the production
measurement. As discussed in the preamble to the proposed amendments,
such fluorinated GHGs never enter the U.S. supply of fluorinated GHGs,
and the goal of subpart OO is to monitor fluorinated GHG flows into and
out of this supply. However, the recently promulgated subpart L
requires monitoring and reporting of emissions that occur before the
production measurement. We have worked to ensure that no fluorinated
GHG emissions from fluorinated GHG production are ``missed'' under the
combined oversight of these two subparts. The magnitudes, identities,
and GWPs of the emissions that will be reported under subpart L of 40
CFR part 98 are discussed in the preamble to the proposed rule
including subpart L (75 FR 18652, April 12, 2010) and in the Technical
Support Document for subpart L.
R. Subpart PP--Suppliers of Carbon Dioxide
1. Summary of Final Amendments and Major Changes Since Proposal
We are removing the words ``each'' from 40 CFR 98.422(a) and (b).
This change will align this section with the requirements of the rest
of subpart PP, which allow for monitoring of an aggregated flow of
CO2, versus monitoring at each production well or process
unit, if the monitoring is done at a gathering point downstream of
individual production wells or production process units.
We are allowing suppliers 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. We are making multiple amendments to the regulatory text
to accommodate this provision. First, we are redesignating 40 CFR
98.423(b) as 40 CFR 98.423(c) and adding a new 40 CFR 98.423(b) with
calculation procedures for CO2 supplied in containers.
Second, we are amending the first sentence of 40 CFR 98.423(a) to allow
use of the alternative procedures in 40 CFR 98.423(b). Third, we are
adding new QA/QC procedures for suppliers of CO2 in
containers to 40 CFR 98.424(a)(2). Fourth, we are adding missing data
procedures for suppliers of CO2 in containers to 40 CFR
98.425(d) and specifying that the missing data procedures in 40 CFR
98.425(a) are for suppliers using flow meters. Finally, we are making
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 are removing 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
redesignating as 40 CFR 98.423(c)). Because 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 for injection and where a flow meter is used, we are
making a number of amendments. First, we are adding language at 40 CFR
98.424(a) regarding flow meter location. Reporters who have a flow
meter(s) on the main, captured CO2 stream(s) only must
locate the flow meter(s) after the point(s) of segregation. Reporters
who have a flow meter(s) on the main, captured CO2 stream
and a subsequent flow meter(s) on the CO2 stream(s) diverted
for on-site use and who choose to use the subsequent flow meter(s) to
calculate CO2 supply (i.e. the
[[Page 79131]]
two meter method) must locate the main flow meter(s) prior to the
point(s) of segregation and the subsequent flow meter(s) on the
CO2 stream(s) for on-site use after the point(s) of
segregation. We are also amending existing language in 40 CFR 98.424(a)
to reference this new requirement. Second, we are amending 40 CFR
98.423(a)(3) to provide reporters using the two meter approach a new
equation (Equation PP-3b) to calculate total CO2 supplied.
As a harmonizing change, we are redesignating Equation PP-3 as Equation
PP-3a. Third, we are amending 40 CFR 98.426(c) so that reporters using
the new Equation PP-3b are required to report the equation inputs and
output and the location of flow meters with respect to the point of
segregation.
Because the amendments will allow flow meters to be located after
purification, compression, or processing, we are adding data reporting
requirements in 40 CFR 98.426 to collect additional information on flow
meter location. Specifically, we are adding that facilities will report
information on the placement of each flow meter used in relation to the
points of CO2 stream capture, dehydration, compression, and
other processing. Knowing where in the production process the flow
meter is located will enable EPA to effectively compare data across
reporters and learn about the efficacy of various CO2 stream
capture processes.
We are specifying standard conditions under subpart PP as a
temperature and an absolute pressure of 60 [deg]F and 1 atmosphere. 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.
We are making several amendments to allow the reporter to determine
the mass of a CO2 stream by converting the volumetric flow
of the CO2 stream 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 as a volume percent. First, we are specifying that, at the
revised standard conditions, the density of CO2 is 0.001868
metric tons per standard cubic meter. This is slightly different than
the density value proposed (0.018704) as the result of additional
research we have conducted. We are specifying that a reporter who
applies the density value for CO2 at standard conditions
must use this specified value.
Second, we are revising the definitions of two of the input
variables to Equation PP-2 in paragraph (a)(2). Since it was finalized
(74 FR 56260, October 30, 2009), Equation PP-2 allows a reporter to
calculate annual mass of CO2 with an input for
CO2 concentration in weight percent and an input for density
of the CO2 stream. So that reporters can avail themselves of
the density value for CO2 being finalized in this action,
however, Equation PP-2 can now also be used to calculate annual mass of
CO2 with an input for CO2 concentration in volume
percent and an input for density of CO2. We note that when
we proposed this action, we did not propose to revise the definitions
of the input variables because we erroneously overlooked the mismatch
between the density value we were providing (CO2) and the
density value required by Equation PP-2 (the CO2 stream). In
order to provide all reporters with lower burden calculation
procedures, as intended by proposing a density value for
CO2, we are correcting this omission and harmonizing
Equation PP-2 with the finalized density value. We note that the
revision to the two input variables is being applied for both reporters
using flow meters and reporters using containers.
Third, we are amending 40 CFR 98.426(b)(3) and (b)(4) to require
that for volumetric flow meters, the reporter must report quarterly
concentration either in volume or weight percent and a density value
for either CO2 or the CO2 stream, depending on
which of the two equation input descriptions provided the reporter
uses.
Fourth, we are amending language in 40 CFR 98.424(a)(5), (a)(5)(i)
and (a)(5)(ii) to allow reporters to choose either a method published
by a consensus-based standards organization or an industry standard
practice to determine the density of the CO2 stream. We are
also replacing the word ``measure'' with the word ``determine.''
Previously, subpart PP required a reporter to use an appropriate method
published by a consensus-based standards organization to measure
density for CO2 at standard conditions, if such a method
existed. Only where no such method existed could an industry standard
practice be used. However, we have been unable to identify any method
published by a consensus-based standards organization for measuring the
density of the CO2 stream. Therefore, we are providing
reporters with more flexibility on this requirement so that they can
use an industry standard practice to calculate the density of the
CO2 stream rather than directly measure density with an
instrument, if preferred.
Finally, we are amending 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.
Major changes since proposal are identified in the following list.
The rationale for these and any other significant changes can be found
in this preamble or the document, ``Response to Comments: Revision to
Certain Provisions of the Mandatory Reporting of Greenhouse Gases
Rule'' (see EPA-HQ-OAR-2008-0508).
We are adding a second aggregation equation (Equation PP-
3b) with appropriate flow meter location requirements so that a
reporter can select either the one-meter or two-meter approach for
calculating total annual mass of CO2.
We are revising the definitions of two of the input
variables to Equation PP-2 in paragraphs 40 CFR 98.423(a)(2) and (b)(2)
so that the equation can be used to calculate annual mass of
CO2 with an input for CO2 concentration in either
volume percent and an input for density of CO2, or weight
percent CO2 and the density of the whole stream.
2. Summary of Comments and Responses
This section contains a brief summary of major comments and
responses. Several comments were received on this subpart. Responses to
additional significant comments received can be found in the document,
``Response to Comments: Revision to Certain Provisions of the Mandatory
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
Comment: One commenter asserted that one of their facilities has
already installed a CO2 meter prior to purification,
processing, or compression--as was required by 40 CFR 98.424 when Part
98 was finalized (74 FR 56260, October 30, 2009)--and because this
facility has segregation, this results in a flow meter location prior
to segregation. The commenter suggested that this facility and others
like it should be allowed to keep their flow meters in place rather
than be required to move them to a location after segregation, as was
proposed in the amendments of August 11, 2010. The commenter suggested
a two-meter approach, whereby a facility locates a main flow meter
prior to segregation on the main, captured CO2 stream and a
subsequent flow meter after segregation on the diverted CO2
stream and then calculates the CO2 for off-site commercial
use as the difference between the two. The commenter stated that this
two-meter approach should be
[[Page 79132]]
equally acceptable to the approach proposed.
Response: EPA agrees that a reporter can calculate CO2
supplied for commercial transaction or injection with sufficient
accuracy with the two-meter approach suggested by the commenter, as
long as the CO2 stream diverted for on site use is the only
CO2 stream diversion after the location of the main flow
meter. If any of the main CO2 stream remaining after on-site
diversion is further diverted (to a vent for emission, for example)
then the difference between the captured CO2 stream and the
CO2 stream diverted for on-site use will not be an accurate
reflection of the CO2 supplied for commercial transaction or
injection. Therefore, EPA is finalizing two approaches for calculating
CO2 supplied, including aggregation equations with flow
meter location requirements, so that a reporter can select either the
one-meter or two-meter approach. However, we are specifying in the
monitoring and QA/QC requirements (40 CFR 98.424) that a reporter may
only follow the two-meter approach if the CO2 stream(s) for
on-site use is/are the only diversion(s) from the main, captured
CO2 stream after the main flow meter(s) location.
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 12866 (58 FR 51735, October 4, 1993) and is
therefore not subject to review under the executive order.
B. Paperwork Reduction Act
This action does not impose any new information collection burden.
These amendments do not make substantive changes to the reporting
requirements in any of the amended subparts. In many cases, the
amendments to the reporting requirements reduce the reporting burden by
making the reporting requirements conform more closely to current
industry practices. While the final rule results in a net decrease in
collection burden, there is a new reporting requirement for facilities
with part 75 units. Previously, facilities with these units had the
option of reporting biogenic CO2 emissions separately. This
final rule requires separate reporting of biogenic CO2
emissions beginning in 2011; however facilities may use simplified
methods based on available information. 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. Burden is defined at 5 CFR 1320.3(b). An agency may
not conduct or sponsor, and a person is not required to respond to, a
collection of information unless it displays a currently valid OMB
control number. The OMB control numbers for EPA's regulations in 40 CFR
are listed in 40 CFR part 9.
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 these amendments 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 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 rule amendments will not impose any new significant
requirements on small entities that are not currently required by the
rules promulgated on October 30, 2009 (i.e., calculating and reporting
annual GHG emissions).
Broadly, in developing the 2009 final rule EPA took several steps
to reduce the impact 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.
D. Unfunded Mandates Reform Act (UMRA)
This action contains no Federal mandates under the provisions of
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C.
1531-1538 for State, local, or tribal governments or the private
sector. The action imposes no enforceable duty on any State, local or
tribal governments or the private sector. In addition, EPA determined
that the 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 rule promulgated on October 30, 2009 (i.e., calculating
and reporting annual GHG emissions), and the rule amendments will not
unfairly apply to small governments. Therefore, this action is not
subject to the requirements of section 203 of the UMRA.
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 rule amendments will relate to existing
State programs, please see Section II of the preamble for the proposed
GHG reporting rule (74 FR 16457 to 16461, April 10, 2009).
These amendments apply directly to facilities that supply fuel 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 stationary
combustion source), so relatively few government facilities will be
affected. This regulation also does not limit the
[[Page 79133]]
power of States or localities to collect GHG data and/or regulate GHG
emissions. Thus, Executive Order 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 the 2009
final rule. A summary of EPA's consultations with State and local
governments is provided in Section VIII.E of the preamble to the 2009
final rule (74 FR 56260, October 30, 2009).
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 rule
amendments will not result in any changes to the requirements of Part
98. 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 GHG Reporting Rule (74 FR 56260, October 30, 2009).
G. Executive Order 13045: Protection of Children From Environmental
Health Risks and Safety Risks
EPA interprets Executive Order 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 Executive Order has the potential to influence the regulation. This
action is not subject to Executive Order 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 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 rulemaking involves the use of two new voluntary consensus
standards from ASTM International. Specifically, EPA will allow
facilities in the petroleum refining and petrochemical production
industries to use ASTM D2593-93(2009) Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, and
ASTM D7633-10 Standard Test Method for Carbon Black--Carbon Content, in
addition to the methods incorporated by reference in Part 98. These
additional voluntary consensus standards will provide alternative
method that owners or operators in these industries can use to monitor
GHG emissions.
This rulemaking also involves the use of several standard methods
that are in EPA publications. These include the following:
Protocol for Measurement of Tetrafluoromethane
(CF4) and Hexafluoroethane (C2F6)
Emissions from Primary Aluminum Production (April 2008); IBR approved
for 40 CFR 98.64(a).
AP 42, Section 5.2, Transportation and Marketing of
Petroleum Liquids, July 2008 (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry,
of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition,
Volume I; IBR approved for 40 CFR 98.253(n).
AP 42, Section 7.1, Organic Liquid Storage Tanks, November
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume 1;
IBR approved for 40 CFR 98.243(m)(1) and 40 CFR 98.256(o)(2)(i).
Method 8015C, Nonhalogenated Organics By Gas
Chromatography, Revision 3, February 2007 (Method 8015C), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR
98.244(b)(4)(viii).
Method 8021B, Aromatic And Halogenated Volatiles By Gas
Chromatography Using Photoionization And/Or Electrolytic Conductivity
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste,
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR
98.244(b)(4)(viii).
Method 8031, Acrylonitrile By Gas Chromatography, Revision
0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third
Edition; IBR approved for 40 CFR 98.244(b)(4)(viii).
Method 9060A, Total Organic Carbon, Revision 1, November
2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for
Evaluating Solid Waste, Physical/Chemical Methods,'' Third Edition; IBR
approved for 40 CFR 98.244(b)(4)(viii).
These methods are being added by the final rule amendments as a
result of working with affected industries to identify existing methods
that can be used to provide the data needed to calculate GHG emissions,
proposing the addition of the methods, and considering the public
comments on the addition of the methods in the final rule making.
No new test methods were developed for this action.
J. Executive Order 12898: Federal Actions To Address Environmental
Justice in Minority Populations and Low-Income Populations
Executive Order 12898 (59 FR 7629, February 16, 1994) establishes
federal executive policy on environmental justice. Its main provision
directs Federal agencies, to the greatest extent practicable and
permitted by law, to make environmental justice part of their mission
by identifying and addressing, as appropriate, disproportionately high
and adverse human health or environmental effects of their programs,
policies, and activities on minority populations and low-income
populations in the United States.
EPA has determined that Part 98 does 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
[[Page 79134]]
information collection and reporting procedures.
K. Congressional Review Act
The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA),
generally provides that before a rule may take effect, the agency
promulgating the rule must submit a rule report, which includes a copy
of the rule, to each House of the Congress and to the Comptroller
General of the United States. EPA will submit a report containing this
rule and other required information to the U.S. Senate, the U.S. House
of Representatives, and the Comptroller General of the U.S. prior to
publication of the rule in the Federal Register. A major rule cannot
take effect until 60 days after it is published in the Federal
Register. This action is not a ``major rule'' as defined by 5 U.S.C.
804(2). This rule will be effective on December 31, 2010.
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: November 24, 2010.
Lisa P. Jackson,
Administrator.
0
For the reasons stated in the preamble, title 40, chapter I, of the
Code of Federal Regulations is amended as follows:
PART 98--[AMENDED]
0
1. The authority citation for part 98 continues to read as follows:
Authority: 42 U.S.C. 7401-7671q.
Subpart A--[Amended]
0
2. Section 98.3 is amended by:
0
a. Revising paragraphs (c)(1), (c)(4) introductory text, (c)(4)(i),
(c)(4)(ii), and (c)(4)(iii) introductory text.
0
b. Adding paragraph (c)(4)(vi).
0
c. Adding a new sentence to the end of paragraph (c)(5)(i).
0
d. Adding paragraph (c)(12).
0
e. Revising the third sentence of paragraph (d)(3) introductory text.
0
f. Revising the first sentence of paragraph (f).
0
g. Revising paragraphs (g)(4) and (g)(5)(iii).
0
h. Revising paragraph (h).
0
i. Revising paragraph (i).
0
j. 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), and physical
street address of the facility or supplier, including the city, State,
and zip code.
* * * * *
(4) For facilities, except as otherwise provided in paragraph
(c)(12) of this section, report annual emissions of CO2,
CH4, N2O, and each fluorinated GHG (as defined in
Sec. 98.6) as follows.
(i) Annual emissions (excluding biogenic CO2) aggregated
for all GHG from all applicable source categories, 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, expressed in metric tons.
(iii) Annual emissions from each applicable source category,
expressed in metric tons of each applicable GHG listed in paragraphs
(c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.
* * * * *
(vi) Applicable source categories means stationary fuel combustion
sources (subpart C of this part), miscellaneous use of carbonates
(subpart U of this part), and all of the source categories listed in
Table A-3 and Table A-4 of this subpart present at the facility.
(5) * * *
(i) * * * For fluorinated GHGs, calculate and report
CO2e for only those fluorinated GHGs listed in Table A-1 of
this subpart.
* * * * *
(12) For the 2010 reporting year only, facilities that have ``part
75 units'' (i.e. units that are subject to subpart D of this part or
units that use the methods in part 75 of this chapter to quantify
CO2 mass emissions in accordance with Sec. 98.33(a)(5))
must report annual GHG emissions either in full accordance with
paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full
accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this
section. If the latter reporting option is chosen, you must report:
(i) Annual emissions aggregated for all GHG from all applicable
source categories, expressed in metric tons of CO2e
calculated using Equation A-1 of this subpart. You must include
biogenic CO2 emissions from part 75 units in these annual
emissions, but exclude biogenic CO2 emissions from any non-
part 75 units and other source categories.
(ii) Annual emissions of biogenic CO2, expressed in
metric tons (excluding biogenic CO2 emissions from part 75
units), aggregated for all applicable source categories.
(iii) Annual emissions from each applicable source category,
expressed in metric tons of each applicable GHG listed in paragraphs
(c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
(A) Biogenic CO2 (excluding biogenic CO2
emissions from part 75 units).
(B) CO2. You must include biogenic CO2
emissions from part 75 units in these totals and exclude biogenic
CO2 emissions from other non-part 75 units and other source
categories.
(C) CH4.
(D) N2O.
(E) Each fluorinated GHG (including those not 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. Such notification will
identify each such substantive error. The owner or
[[Page 79135]]
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 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 manufacturer's specifications
and industry standards. 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] TR17DE10.000
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
[[Page 79136]]
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.
[GRAPHIC] [TIFF OMITTED] TR17DE10.001
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 a manufacturer's specification or an industry
consensus standard.
(C) You must document the methods used for the demonstration
described in paragraph (i)(3)(ii)(A) of this section in the written GHG
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 GHG 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 GHG Monitoring Plan and
recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), 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 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
relevant 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
[[Page 79137]]
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. (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 subsequent 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.
0
3. 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.
* * * * *
0
4. Section 98.6 is amended by:
0
a. Adding in alphabetical order definitions for ``Agricultural by-
products,'' ``Primary fuel,'' ``Solid by-products,'' ``Used oil,'' and
``Wood residuals.''
0
b. Revising the definitions for ``Bulk natural gas liquid or NGL,''
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Fuel gas,'' ``Municipal
solid waste or MSW,'' ``Natural gas,'' ``Natural gas liquids (NGLs) and
``Standard conditions or standard temperature and pressure (STP).''
0
c. Removing the definition for ``Fossil fuel-fired.''
Sec. 98.6 Definitions.
* * * * *
Agricultural by-products means those parts of arable crops that are
not used for the primary purpose of producing food. Agricultural by-
products 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
[[Page 79138]]
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.
* * * * *
Fuel gas means gas generated at a petroleum refinery or
petrochemical plant and that is combusted separately or in any
combination with any type of gas.
* * * * *
Municipal solid waste or MSW means solid phase household,
commercial/retail, and/or institutional waste. Household waste includes
material discarded by single and multiple 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 wastes
include yard waste, refuse-derived fuel, and motor vehicle maintenance
materials. Insofar as there is separate collection, processing and
disposal of industrial source waste streams consisting of used oil,
wood pallets, construction, renovation, and demolition wastes (which
includes, but is not limited to, railroad ties and telephone poles),
paper, clean wood, plastics, industrial process or manufacturing
wastes, medical waste, motor vehicle parts or vehicle fluff, or used
tires that do not contain hazardous waste identified or listed under 42
U.S.C. Sec. 6921, such wastes are not municipal solid waste. However,
such wastes qualify as municipal solid waste where they are collected
with other municipal solid waste or are otherwise combined with other
municipal solid waste for processing and/or disposal.
* * * * *
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 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 by-products means plant matter such as vegetable waste,
animal materials/wastes, and other solid biomass, except for wood, wood
waste, and sulphite lyes (black liquor).
* * * * *
Standard conditions or standard temperature and pressure (STP), for
the purposes of this part, means either 60 or 68 degrees Fahrenheit and
14.7 pounds per square inch absolute.
* * * * *
Used oil means a petroleum-derived or synthetically-derived oil
whose physical properties have changed as a result of handling or use,
such that the oil cannot be used for its original purpose. Used 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 materials 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, trim, sander dust, and sawdust from wood
products manufacturing (including resinated wood product residuals),
and logging residues.
* * * * *
0
5. Section 98.7 is amended by:
0
a. Removing and reserving paragraph (b).
0
b. Revising paragraphs (d)(1) through (d)(10).
0
c. Removing paragraph (d)(11).
0
d. Revising paragraph (e)(4).
0
e. Removing and reserving paragraph (e)(7).
0
f. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14) and (e)(15).
0
g. Revising paragraphs (e)(19) and (e)(20).
0
h. Revising paragraphs (e)(24) through (e)(27).
0
i. Removing and reserving paragraph (e)(28).
0
j. Revising paragraph (e)(30).
0
k. Revising paragraph (e)(33).
0
l. Revising paragraph (e)(36).
0
m. Removing and reserving paragraph (e)(39).
0
n. Adding paragraphs (e)(48) and (e)(49).
0
o. Removing and reserving paragraph (f)(1).
0
p. Revising paragraph (f)(2).
0
q. Removing and reserving paragraph (g)(3).
0
r. Revising paragraph (m)(3).
0
s. Adding paragraphs (m)(8) through (m)(14).
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. 98.124(m)(1), Sec. 98.324(e), Sec. 98.354(d), Sec.
98.354(h), 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. 98.124(m)(2), Sec. 98.324(e),
Sec. 98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow
in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR
approved for Sec. 98.124(m)(3) and Sec. 98.354(d).
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using
Vortex Flowmeters, IBR approved for Sec. 98.124(m)(4), Sec.
98.324(e), Sec. 98.344(c), Sec. 98.354(h), 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.
98.124(m)(5),
[[Page 79139]]
Sec. 98.324(e), Sec. 98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow
in Closed Conduits by Weighing Method, IBR approved for Sec.
98.124(m)(6).
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of
Coriolis Mass Flowmeters, IBR approved for Sec. 98.124(m)(7), Sec.
98.324(e), Sec. 98.344(c), and Sec. 98.354(h).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore
Precision Orifice Meters, IBR approved for Sec. 98.124(m)(8), Sec.
98.324(e), Sec. 98.344(c), Sec. 98.354(h), and Sec. 98.364(e).
(9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits
with Electromagnetic Flow Meters, IBR approved for Sec. 98.354(d).
(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable
Area Meters, IBR approved for Sec. 98.324(e), Sec. 98.344(c), Sec.
98.354(h), and Sec. 98.364(e).
(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).
* * * * *
(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), Sec. 98.324(d), Sec.
98.354(g), and Sec. 98.344(b).
(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis
of Reformed Gas by Gas Chromatography, IBR approved for Sec. 98.74(c),
Sec. 98.164(b), Sec. 98.254(d), Sec. 98.324(d), Sec. 98.344(b),
Sec. 98.354(g), 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) and Sec. 98.254(d)(6).
* * * * *
(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) and Sec. 98.324(d).
(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).
* * * * *
(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.
98.124(e)(2), 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).
* * * * *
(48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography,
approved July 1, 2009, IBR approved for Sec. 98.244(b)(4)(xi).
(49) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon
Content, approved May 15, 2010, IBR approved for Sec.
98.244(b)(4)(xii).
* * * * *
(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), Sec. 98.344(b), and Sec. 98.354(g).
* * * * *
(m) * * *
(3) 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 (EPA 430-R-10-
003), http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf,
IBR approved for Sec. 98.94(f)(4)(i), Sec. 98.94(g)(3), Sec.
98.97(d)(4), Sec. 98.98, Sec. 98.124(e)(2), and Sec. 98.414(n)(1).
* * * * *
(8) Protocol for Measurement of Tetrafluoromethane (CF4)
and Hexafluoroethane (C2F6) Emissions from
Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf, IBR approved for Sec.
98.64(a).
(9) AP 42, Section 5.2, Transportation and Marketing of Petroleum
Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I,
IBR approved for Sec. 98.253(n).
(10) Method 9060A, Total Organic Carbon, Revision 1, November 2004
(Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for Evaluating
Solid Waste, Physical/Chemical Methods,'' Third Edition, IBR approved
for Sec. 98.244(b)(4)(viii).
(11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0,
September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third
Edition, IBR approved for Sec. 98.244(b)(4)(viii).
(12) Method 8021B, Aromatic and Halogenated Volatiles By Gas
Chromatography Using Photoionization and/or Electrolytic Conductivity
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA
Publication No. SW-846, ``Test Methods for Evaluating Solid
[[Page 79140]]
Waste, Physical/Chemical Methods,'' Third Edition, IBR approved for
Sec. 98.244(b)(4)(viii).
(13) Method 8015C, Nonhalogenated Organics By Gas Chromatography,
Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW-846,
``Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,''
Third Edition, IBR approved for Sec. 98.244(b)(4)(viii).
(14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42,
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I,
IBR approved for Sec. 98.253(m)(1) and Sec. 98.256(o)(2)(i).
0
6. Table A-5 to subpart A of part 98 is amended by revising the entry
for paragraph (B) under the heading ``Natural gas and natural gas
liquids suppliers (subpart NN)'' to read as follows:
Table A-5 to Subpart A of Part 98--Supplier Category List for Sec.
98.2(a)(4)
------------------------------------------------------------------------
-------------------------------------------------------------------------
Supplier Categories \a\ Applicable in 2010 and Future Years
------------------------------------------------------------------------
* * * * *
Natural gas and natural gas liquids suppliers (subpart NN)
* * * * *
(B) Local natural gas distribution companies that deliver 460,000
thousand standard cubic feet or more of natural gas per year.
* * * * *
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.
---------------------------------------------------------------------------
Subpart C--[Amended]
0
7. Section 98.30 is amended by:
0
a. Revising paragraph (b)(4).
0
b. Revising paragraph (c) introductory text.
0
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 auxiliary flame that ignites the burner of a
combustion device when the control valve opens.
0
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.
0
9. Section 98.33 is amended by:
0
a. Revising paragraph (a) introductory text and paragraph (a)(1).
0
b. Revising the definition of ``HHV'' in Equation C-2a of paragraph
(a)(2)(i).
0
c. Revising the first two sentences of paragraph (a)(2)(ii)
introductory text.
0
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.
0
e. Revising paragraph (a)(2)(ii)(B).
0
f. Revising the definitions of ``CC'', ``MW'', and ``MVC'' in Equation
C-5 of paragraph (a)(3)(iii).
0
g. Revising paragraphs (a)(3)(iv), (a)(3)(v), (a)(4)(iii), and
(a)(4)(iv).
0
h. Adding paragraph (a)(4)(viii).
0
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), and
(a)(5)(iii)(B).
0
j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv), and
revising newly designated paragraph (a)(5)(iv).
0
k. Revising paragraph (b)(1)(iv).
0
l. Adding paragraphs (b)(1)(v), (b)(1)(vi) and (b)(1)(vii).
0
m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii)
introductory text, and (b)(3)(iii)(B).
0
n. Adding paragraph (b)(3)(iv).
0
o. Adding a second sentence to paragraph (b)(4)(i).
0
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.
0
q. Adding paragraph (b)(4)(iv).
0
r. Revising paragraph (b)(5) and the third sentence of paragraph
(b)(6).
0
s. Revising paragraph (c)(1) introductory text and the definition of
``HHV'' in Equation C-8.
0
t. Adding paragraphs (c)(1)(i) and (c)(1)(ii).
0
u. Revising the second sentence of paragraph (c)(2).
0
v. In paragraph (c)(4) introductory text, revising the only sentence
and revising the definition of ``(HI)A'' in Equation C-10.
0
w. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
0
x. Revising paragraph (c)(5).
0
y. Adding paragraph (c)(6).
0
z. In paragraph (d)(1), revising the first sentence, adding a second
sentence, and revising the definition of ``R'' in Equation C-11.
0
aa. Revising paragraphs (d)(2), paragraph (e) introductory text,
paragraph (e)(1), and paragraph (e)(2) introductory text.
0
bb. Revising the definition of ``Fc'' in Equation C-13 of
paragraph (e)(2)(iii).
0
cc. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
0
dd. Removing paragraph (e)(4).
0
ee. Redesignating paragraph (e)(5) as (e)(4).
0
ff. Revising the first sentence of newly designated paragraph (e)(4).
0
gg. Adding 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, C-1a, or C-1b 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 or million Btu. In that case, use Equation C-1a or C-1b, as
applicable.
[[Page 79141]]
[GRAPHIC] [TIFF OMITTED] TR17DE10.015
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] TR17DE10.016
Where:
CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas usage, 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.
(iii) If natural gas consumption is obtained from billing records
and fuel usage is expressed in mmBtu, use Equation C-1b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.017
Where:
CO2 = Annual CO2 mass emissions from natural
gas combustion (metric tons).
Gas = Annual natural gas usage, from billing records (mmBtu).
EF = Fuel-specific default CO2 emission factor for
natural gas, from Table C-1 of this subpart (kg CO2/
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'' (which may be the arithmetic average of multiple
determinations), 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 either be computed
according to paragraph (a)(2)(ii)(A) of this section or 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.
MVC = Molar volume conversion factor at standard conditions, as
defined in Sec. 98.6. Use 849.5 scf per kg mole if you select 68
[deg]F as standard temperature and 836.6 scf per kg mole if you
select 60 [deg]F as standard temperature.
* * * * *
(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. You must measure
the density using one of the following appropriate methods. You may use
a method published by a consensus-based 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 (100 Barr Harbor Drive, P.O. Box CB700,
West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA), 400 North Capitol
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street,
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org),
and the North American Energy Standards Board (NAESB, 801 Travis
Street, Suite 1675, Houston, TX 77002,
[[Page 79142]]
(713) 356-0060, http://www.api.org). The method(s) used shall be
documented in the GHG Monitoring Plan required under Sec. 98.3(g)(5).
(v) The following default density values may be used for fuel oil,
in lieu of using the methods in paragraph (a)(3)(iv) of this section:
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No.
6 oil.
* * * * *
(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 using
a method 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. Moisture data from the relative accuracy test audit (RATA) of
a CEMS may be used for this purpose. 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, except where the option to use
moisture data from a RATA is selected, and the applicable regulation
allows a single moisture determination to represent two or more RATA
runs. In that case, you may base the site-specific moisture percentage
on the number of moisture runs allowed by the RATA regulation.
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] TR17DE10.002
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, CO2 emissions shall be determined as follows:
(A) At least once a year, use EPA Methods 2 and 3A, and (if
necessary) Method 4 in appendices A-2 and A-3 to part 60 of this
chapter to perform emissions testing at a set point that best
represents normal, stable process operating conditions. A minimum of
three one-hour Method 3A tests are required, to determine the
CO2 concentration. A Method 2 test shall be performed during
each Method 3A run, to determine the stack gas volumetric flow rate. If
moisture correction is necessary, a Method 4 run shall also be
performed during each Method 3A run. Important parametric information
related to the stack gas flow rate (e.g., damper positions, fan
settings, etc.) shall also be recorded during the test.
(B) Calculate a CO2 mass emission rate (in metric tons/
hr) from the stack test data, using a version of Equation C-6 in
paragraph (a)(4)(ii) of this section, modified as follows. In the
Equation C-6 nomenclature, replace the words ``Hourly average'' in the
definitions of ``CCO2'' and ``Q'' with the words ``3-run
average''. Substitute the arithmetic average values of CO2
concentration and stack gas flow rate from the emission testing into
modified Equation C-6. If CO2 is measured on a dry basis, a
moisture correction of the calculated CO2 mass emission rate
is required. Use Equation C-7 in paragraph (a)(4)(ii) of this section
to make this correction; replace the word ``Hourly'' with the words
``3-run average'' in the equation nomenclature.
(C) The results of each annual stack test shall be used in the GHG
emissions calculations for the year of the test.
(D) If, for the majority of the operating hours during the year,
the diverted stream is withdrawn at a steady rate at or near the tested
set point (as evidenced by fan and damper settings and/or other
parameters), you may use the calculated CO2 mass emission
rate from paragraph (a)(4)(viii)(B) of this section to estimate the
CO2 mass emissions for all operating hours in which flue gas
is diverted from the main exhaust system. Otherwise, you must account
for the variation in the flow rate of the diverted stream, as described
in paragraph (c)(4)(viii)(E) of this section.
(E) If the flow rate of the diverted stream varies significantly
throughout the year, except as provided below, repeat the stack test
and emission rate calculation procedures described in paragraphs
(c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two
more set points across the range of typical operating conditions to
develop a correlation between CO2 mass emission rate and the
parametric data. If additional testing is not feasible, use the
following approach to develop the necessary correlation. Assume that
the average CO2 concentration obtained in the annual stack
test is the same at all operating set points. Then, beginning
[[Page 79143]]
with the measured flow rate from the stack test and the associated
parametric data, perform an engineering analysis to estimate the stack
gas flow rate at two or more additional set points. Calculate the
CO2 mass emission rate at each set point.
(F) Calculate the annual CO2 mass emissions for the
diverted stream as follows. For a steady-state process, multiply the
number of hours in which flue gas was diverted from the main exhaust
system by the CO2 mass emission rate from the stack test.
Otherwise, using the best available information and engineering
judgment, apply the most representative CO2 mass emission
rate from the correlation in paragraph (c)(4)(viii)(E) of this section
to determine the CO2 mass emissions for each hour in which
flue gas was diverted, and sum the results. To simplify the
calculations, you may count partial operating hours as full hours.
(G) Finally, add the CO2 mass emissions from
paragraph(c)(4)(viii)(F) of this section to the annual CO2
mass emissions measured by the CEMS at the main stack. Report this sum
as the total annual CO2 mass emissions for the unit.
(H) The exact method and procedures used to estimate the
CO2 mass emissions for 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
chapter to 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 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, only for the 2010 reporting year, as
provided in Sec. 98.3(c)(12).
(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), (b)(1)(v), (b)(1)(vi), and
(b)(1)(vii) 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 or mmBtu.
(vi) May be used for MSW combustion in a small, batch incinerator
that burns no more than 1,000 tons per year of MSW.
(vii) May be used for the combustion of MSW and/or tires in a unit,
provided that no more than 10 percent of the unit's annual heat input
is derived from those fuels, combined. Notwithstanding this
requirement, if a unit combusts both MSW and tires and the reporter
elects not to separately calculate and report biogenic CO2
emissions from the combustion of tires, Tier 1 may be used for the MSW
combustion, provided that no more than 10 percent of the unit's annual
heat input is derived from MSW.
(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,
[[Page 79144]]
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 if 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 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.
(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 Equation C-8 of this section to estimate CH4 and
N2O emissions for any fuels for which you use the Tier 1 or
Tier 3 calculation methodologies for CO2, except when
natural gas usage in units of therms or mmBtu is obtained from gas
billing records. In that case, use Equation C-8a in paragraph (c)(1)(i)
of this section or Equation C-8b in paragraph (c)(1)(ii) of this
section (as applicable). For Equation C-8, 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).
* * * * *
(i) Use Equation C-8a to calculate CH4 and
N2O emissions when natural gas usage is obtained from gas
billing records in units of therms.
[GRAPHIC] [TIFF OMITTED] TR17DE10.018
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of natural gas (metric
tons).
Fuel = Annual natural gas usage, from gas billing records (therms).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric
tons.
(ii) Use Equation C-8b to calculate CH4 and
N2O emissions when natural gas usage is obtained from gas
billing records in units of mmBtu.
CH4 or N2O = 1 x 10-\3\ * Fuel *
EF (Eq. C-8b)
Where:
CH4 or N2O = Annual CH4 or
N2O emissions from the combustion of natural gas (metric
tons).
Fuel = Annual natural gas usage, from gas billing records (mmBtu).
EF = Fuel-specific default emission factor for CH4 or
N2O, from Table C-2 of this subpart (kg CH4 or
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric
tons.
[[Page 79145]]
(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.
(5) When multiple fuels are combusted during the reporting year,
sum the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-
9b, or C-10 of this section (as applicable) to obtain the total annual
CH4 and N2O emissions, in metric tons.
(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-8a, C-8b, 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 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, in accordance with Sec. 98.3(c)(12), separate
reporting of biogenic CO2 emissions is optional for the 2010
reporting year 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 provisions
of paragraph (e)(3) of this section.
[[Page 79146]]
(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, except as
otherwise provided in paragraph (e)(3)(iv) of this section. 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.
(iv) If the combustion of MSW and/or tires provides no more than 10
percent of the annual heat input to a unit, or if a small, batch
incinerator combusts no more than 1,000 tons per year of MSW, you may
estimate the annual biogenic CO2 emissions as follows, in
lieu of following the procedures in paragraphs (e)(3)(i) through
(e)(3)(iii) of this section:
(A) Calculate the total annual CO2 emissions from
combustion of MSW and/or tires in the unit, using the Tier 1
calculation methodology in paragraph (a)(1) of this section.
(B) Multiply the result from paragraph (e)(3)(iv)(A) of this
section by the appropriate default factor to determine the annual
biogenic CO2 emissions, in metric tons. For MSW, use a
default factor of 0.60 and for tires, use a default factor of 0.20.
(4) 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. * * *
(5) For units subject to subpart D of this part and for units that
use the methods in part 75 of this chapter to quantify CO2
mass emissions in accordance with paragraph (a)(5) of this section, you
may calculate biogenic CO2 emissions from the combustion of
biomass fuels listed in Table C-1 of this subpart using Equation C-15a.
This equation may not be used to calculate biogenic CO2
emissions from the combustion of tires or MSW; the methods described in
paragraph (e)(3) of this section must be used for those fuels. Whenever
(HI)A, the annual heat input from combustion of biomass fuel
in Equation C-15a, cannot be determined solely from the information in
the electronic emissions reports under Sec. 75.64 of this chapter
(e.g., in cases where a unit uses CEMS in combination with multiple F-
factors, a worst-case F-factor, or a prorated F-factor to report heat
input rather than reporting heat input based on fuel type), use the
best available information (as described in Sec. Sec.
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.
CO2 = 0.001 * (HI)A * EF (Eq. C-15a)
Where:
CO2 = Annual CO2 mass emissions from the
combustion of a particular type of biomass fuel listed in Table C-1
(metric tons)
(HI)A = Annual heat input from the biomass fuel,
obtained, where feasible, from the electronic emissions reports
required under Sec. 75.64 of this chapter. Where this is not
feasible use best available information, as described in Sec. Sec.
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) (mmBtu)
EF = CO2 emission factor for the biomass fuel, from Table
C-1 (kg CO2/mmBtu)
0.001 = Conversion factor from kg to metric tons
* * * * *
0
10. Section 98.34 is amended by:
0
a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) introductory
text, (b)(1)(i), (b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), and
(b)(3)(v).
0
b. Removing paragraph (b)(4).
0
c. Redesignating paragraph (b)(5) as (b)(4).
0
d. Revising newly designated paragraph (b)(4).
0
e. Revising paragraphs (c) introductory text, (c)(1)(i), (c)(1)(ii),
(c)(2), (c)(3), and (c)(4).
0
f. Adding paragraphs (c)(6) and (c)(7).
0
g. Revising paragraphs (d), (e), (f) introductory text, (f)(1), (f)(3),
(f)(5), and (f)(6).
0
h. Adding paragraphs (f)(7) and (f)(8).
0
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
[[Page 79147]]
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. If the daily manual oil sampling option is
selected, sampling from a particular tank is required only on days when
oil from the tank is combusted by the unit (or units) served by the
tank. If you elect to sample from the storage tank upon each addition
of oil to the tank, you must take at least one sample from each tank
that is currently in service and whenever oil is added to the tank, for
as long as the tank remains in service. You need not take any samples
from a storage tank while it is out of service. Rather, take a sample
when the tank is brought into service and whenever oil is added to the
tank, for as long as the tank remains in service. If multiple additions
of oil are made to a particular in-service tank on a given day (e.g.,
from multiple deliveries), one sample taken after the final addition of
oil is sufficient. For the purposes of this section, a fuel lot is
defined as a shipment or delivery of a single type of fuel (e.g., ship
load, barge load, group of trucks, group of railroad cars, oil delivery
via pipeline from a tank farm, etc.). However, 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 may be
considered, collectively, to comprise a fuel lot, requiring only one
representative sample, subject to the following conditions:
(A) For coal, the ``type'' of fuel means the rank of the coal
(i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel
oil, the ``type'' of fuel means the grade number or classification of
the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
(B) The owner or operator shall document in the monitoring plan
under Sec. 98.3(g)(5) how the monthly sampling of each type of fuel is
performed.
(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 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, or that are
mixed on-site without measuring the exact amount of each component, 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) or if
the components are mixed on site without precisely measuring the mass
or volume of each one individually, 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] TR17DE10.003
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)
[[Page 79148]]
(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] TR17DE10.004
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, 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. 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. Alternatively, you may use a method published by a
consensus-based standards organization if such a method exists, or you
may use industry standard practice to determine the high heat values.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
http://www.astm.org), the American National Standards Institute (ANSI,
1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020,
http://www.ansi.org), the American Gas Association (AGA, 400 North
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000,
http://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
http://www.asme.org), the American Petroleum Institute (API, 1220 L
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). 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 the calibration procedures specified by the flow
meter manufacturer.
(B) You may use an appropriate flow meter calibration method
published by a consensus-based standards organization, if such a method
exists. Consensus-based standards organizations include, but are not
limited to, the following: ASTM International (100 Barr Harbor Drive,
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute
(ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400
North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, http://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
http://www.asme.org), the American Petroleum Institute (API, 1220 L
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(C) You may use an industry-accepted 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) according to one of the
following. You may recalibrate annually, at the minimum frequency
specified by the manufacturer, or at the interval specified by industry
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
[[Page 79149]]
requirements of Sec. Sec. 98.3(g)(5)(i)(C), (g)(6), 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 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. If the daily manual oil sampling option is
selected, sampling from a particular tank is required only on days when
oil from the tank is combusted by the unit (or units) served by the
tank. If you elect to sample from the storage tank upon each addition
of oil to the tank, you must take at least one sample from each tank
that is currently in service and whenever oil is added to the tank, for
as long as the tank remains in service. You need not take any samples
from a storage tank while it is out of service. Rather, take a sample
when the tank is brought into service and whenever oil is added to the
tank, for as long as the tank remains in service. If multiple additions
of oil are made to a particular in service tank on a given day (e.g.,
from multiple deliveries), one sample taken after the final addition of
oil is sufficient. For the purposes of this section, a fuel lot is
defined as a shipment or delivery of a single type of fuel (e.g., ship
load, barge load, group of trucks, group of railroad cars, oil delivery
via pipeline from a tank farm, etc.). However, 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 may be
considered, collectively, to comprise a fuel lot, requiring only one
representative sample, subject to the following conditions:
(1) For coal, the ``type'' of fuel means the rank of the coal
(i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel
oil, the ``type'' of fuel means the grade number or classification of
the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
(2) The owner or operator shall document in the monitoring plan
under Sec. 98.3(g)(5) how the monthly sampling of each type of fuel is
performed.
(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 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. 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. Alternatively, you may use a method published by a
consensus-based standards organization if such a method exists, or you
may use industry 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 (100 Barr Harbor Drive, P.O. Box CB700, West
Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street,
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org),
and the North American Energy Standards Board (NAESB, 801 Travis
Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). 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
[[Page 79150]]
certified prior to the applicable deadline specified in Sec.
98.33(b)(5).
(1) * * *
(i) Sec. Sec. 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) Except as otherwise provided in Sec. 98.33 (b)(1)(vi) and
(b)(1)(vii), 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 total (not necessarily
consecutive) hours, or longer if the facility deems it necessary to
obtain a representative sample. Notwithstanding this requirement, if
the types of fuels combusted and their relative proportions are
consistent throughout the year, the minimum required sampling time may
be reduced to 8 hours if at least two 8-hour samples and one 24-hour
sample are collected under normal operating conditions, and arithmetic
average of the biogenic fraction of the flue gas from the 8-hour
samples (expressed as a decimal) is within 5 percent of
the biogenic fraction from the 24-hour test. There must be no
overlapping of the 8-hour and 24-hour test periods. Document the
results of the demonstration in the unit's monitoring plan. If the
types of fuels and their relative proportions are not consistent
throughout the year, an optional sampling approach that facilities may
wish to consider to obtain a more representative sample is 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 (incorporated by reference, see Sec. 98.7) and ASTM D7459-08
(incorporated by reference, see Sec. 98.7) may be used to determine
the biogenic portion of the CO2 emissions in every calendar
quarter in which biomass and non-biogenic fuels are co-fired in the
unit. Follow the procedures in paragraph (d) of this section. 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 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.
(6) Biogenic fuel consumption and high heating value, as
applicable, under Sec. Sec. 98.33(e)(5) and (e)(6).
(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).
0
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 year-round in
[[Page 79151]]
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.
* * * * *
0
12. Section 98.36 is amended by:
0
a. Revising paragraph (b)(5).
0
b. Removing paragraphs (b)(9) and (b)(10).
0
c. Redesignating paragraphs (b)(6) through (b)(8) as paragraphs (b)(8)
through (b)(10), respectively.
0
d. Revising newly designated paragraphs (b)(8) and (b)(9).
0
e. Adding new paragraphs (b)(6) and (b)(7).
0
f. Removing and reserving paragraphs (c)(1)(ii) and (c)(1)(iii).
0
g. Revising paragraphs (c)(1)(vi) and (c)(1)(vii).
0
h. Redesignating paragraph (c)(1)(viii) as paragraph (c)(1)(x), and
revising newly designated paragraph (c)(1)(x).
0
i. Removing paragraph (c)(1)(ix).
0
j. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix).
0
k. Revising paragraphs (c)(2) introductory text, (c)(2)(ii),
(c)(2)(iii), and (c)(2)(v).
0
l. Removing paragraph (c)(2)(viii).
0
m. 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).
0
n. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii).
0
o. Removing and reserving paragraph (c)(3)(ii).
0
p. Revising paragraphs (c)(3) introductory text, (c)(3)(iii), and
(c)(3)(vii).
0
q. Removing paragraph (c)(3)(viii).
0
r. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), and (c)(4).
0
s. Revising paragraph (d).
0
t. Revising paragraphs (e)(1)(iii), (e)(2)(i), (e)(2)(ii)(C),
(e)(2)(ii)(D), (e)(2)(iii), (e)(2)(iv)(A), and (e)(2)(iv)(C).
0
u. Adding paragraphs (e)(2)(iv)(F) and (e)(2)(iv)(G).
0
v. Revising paragraph (e)(2)(v)(C).
0
w. Adding paragraph (e)(2)(v)(E).
0
x. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) introductory text,
and (e)(2)(x) introductory text.
0
y. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C).
0
z. Redesignating paragraph (e)(2)(x)(D) as (e)(2)(x)(B), and revising
newly designated paragraph (e)(2)(x)(B).
0
aa. 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) Report the total annual CO2 mass emissions measured
by the CEMS. If this total 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) [Reserved]
(iii) [Reserved]
* * * * *
(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
combustion products and/or process off-gases, and all of the effluent
comes from a single unit (e.g., a furnace, kiln, petrochemical
production unit, or smelter).
(iii) Combined maximum rated heat input capacity of the units
sharing the 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
[[Page 79152]]
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 stationary
combustion units at a facility combust the same type of liquid or
gaseous 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, or, for
natural gas, the amount of fuel combusted may be obtained from gas
billing records. For Tier 3 applications, the flow meter shall be
calibrated in accordance with Sec. 98.34(b). If a portion of the fuel
measured (or obtained from gas billing records) 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 (or obtained from gas
billing records) 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:
* * * * *
(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
facilities at which 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 other units subject to part 75 of this chapter) and small
combustion sources, including, but not limited to, space heaters, hot
water heaters, and lab burners. 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, 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. Separate reporting of
biogenic CO2 emissions under Sec. 98.3(c)(4)(ii) and Sec.
98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as
provided in Sec. 98.3(c)(12).
(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, except where the
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii)
are implemented for the 2010 reporting year.
(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, 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.
[[Page 79153]]
(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 emissions 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, except where the
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii)
are implemented for the 2010 reporting year.
(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 emissions 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, except where the
reporting provisions of Sec. Sec. 98.3(c)(12)(i) through (c)(12)(iii)
are implemented for the 2010 reporting year.
(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
for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
(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).
(G) The value of the molar volume constant (MVC) used in Equation
C-5 (if applicable).
(v) * * *
(C) The methods used to determine the carbon content and (if
applicable) the molecular weight of each type of fuel combusted.
* * * * *
(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 (incorporated by reference, see
Sec. 98.7) and D6866-08 (incorporated by reference, see Sec. 98.7)
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 (incorporated by reference, see
Sec. 98.7) and D6866-08 (incorporated by reference, see Sec. 98.7)
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).
* * * * *
0
13. Table C-1 to Subpart C is amended by:
[[Page 79154]]
0
a. Revising the heading.
0
b. Removing the entry for ``Pipeline (Weighted U.S. Average)'' and
adding an entry for ``(Weighted U.S. Average)'' in its place.
0
c. Removing the entry for ``Still Gas.''
0
d. Adding an entry for ``Used Oil'', following the entry for ``Residual
Fuel Oil No. 6.''
0
e. Revising the entry for ``Ethane''.
0
f. Adding an entry for ``Ethanol'', following the entry for ``Ethane.''
0
g. Revising the phrase ``Fossil fuel-derived fuels (solid)'' to read
``Other fuels-solid.''
0
h. Revising the entry for ``Municipal Solid Waste.''
0
i. Adding entries for ``Plastics'' and ``Petroleum Coke'', following
the entry for ``Tires.''
0
j. Revising the phrase ``Fossil fuel-derived fuels (gaseous)'' to read
``Other fuels--gaseous.''
0
k. Adding entries for ``Propane Gas'' and ``Fuel Gas,'' following the
entry for ``Coke Oven Gas.''
0
l. Amending the entry for ``Biomass fuels--liquid'' by centering
``Biomass fuels--liquid.''
0
m. Revising the entries for ``Ethanol'' and ``Biodiesel'' that follow
the entry for ``Biomass fuels--liquid.''
0
n. Revising footnote ``1.''
0
o. Adding footnote ``2.''
Table C-1 to Subpart C--Default CO[ihel2] Emission Factors and High Heat
Values for Various Types of Fuel
------------------------------------------------------------------------
Default high heat Default CO[ihel2]
Fuel type value emission factor
------------------------------------------------------------------------
* * * * * * *
(Weighted U.S. Average)..... 1.028 x 10-3 53.02
* * * * * * *
Used Oil.................... 0.135 74.00
* * * * * * *
Ethane...................... 0.069 62.64
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
* * * * * * *
Ethanol..................... 0.084 68.44
Biodiesel................... 0.128 73.84
* * * * * * *
------------------------------------------------------------------------
\1\ Use of this default HHV is allowed only for: (a) Units that combust
MSW, do not generate steam, and are allowed to use Tier 1; (b) units
that derive no more than 10 percent of their annual heat input from
MSW and/or tires; and (c) small batch incinerators that combust no
more than 1,000 tons of MSW per year.
\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, reporters
subject to subpart X or subpart Y shall use either Tier 3 (Equation C-
5) or Tier 4.
0
14. The first Table C-2 to Subpart C is removed, and the second Table
C-2 to Subpart C is revised to read as follows:
Table C-2 to Subpart C--Default CH[ihel4] and N[ihel2]O Emission Factors
for Various Types of Fuel
------------------------------------------------------------------------
Default CH[ihel4] Default N[ihel2]O
Fuel type emission factor (kg emission factor (kg
CH[ihel4]/mmBtu) N[ihel2]O/mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel 1.1 x 10-02 1.6 x 10-03
types in Table C-1).
Natural Gas................. 1.0 x 10-03 1.0 x 10-04
Petroleum (All fuel types in 3.0 x 10-03 6.0 x 10-04
Table C-1).
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 3.2 x 10-02 4.2 x 10-03
fuel types in Table C-1).
Biogas...................... 3.2 x 10-03 6.3 x 10-04
[[Page 79155]]
Biomass Fuels--Liquid (All 1.1 x 10-03 1.1 x 10-04
fuel types in Table C-1).
------------------------------------------------------------------------
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 1g
of CH[ihel4]/mmBtu.
Subpart D--[Amended]
0
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.
* * * * *
0
16. Section 98.43 is revised to read as follows:
Sec. 98.43 Calculating GHG emissions.
(a) Except as provided in paragraph (b) of this section, continue
to monitor and report CO2 mass emissions as required under
Sec. 75.13 or section 2.3 of appendix G to 40 CFR part 75, and Sec.
75.64. Calculate CO2, CH4, and N2O
emissions as follows:
(1) Convert the cumulative annual CO2 mass emissions
reported in the fourth quarter electronic data report required under
Sec. 75.64 from units of short tons to metric tons. To convert tons to
metric tons, divide by 1.1023.
(2) Calculate and report annual CH4 and N2O
mass emissions under this subpart by following the applicable method
specified in Sec. 98.33(c).
(b) Calculate and report biogenic CO2 emissions under
this subpart by following the applicable methods specified in Sec.
98.33(e). The CO2 emissions (excluding biogenic
CO2) for units subject to this subpart that are reported
under Sec. Sec. 98.3(c)(4)(i) and (c)(4)(iii)(B) shall be calculated
by subtracting the biogenic CO2 mass emissions calculated
according to Sec. 98.33(e) from the cumulative annual CO2
mass emissions from paragraph (a)(1) of this section. Separate
calculation and reporting of biogenic CO2 emissions is
optional only for the 2010 reporting year pursuant to Sec. 98.3(c)(12)
and required every year thereafter.
0
17. 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).
0
18. 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]
0
19. 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.
* * * * *
0
20. Section 98.63 is amended by:
0
a. In paragraph (a), revising the only sentence and the definitions of
``EPFC,'' and ``Em'' in Equation F-1.
0
b. Revising the only sentence of paragraph (b).
0
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.
* * * * *
0
21. 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 December 31, 2010 for smelters with no prior
measurement or effective December 31, 2012, 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) (incorporated by reference, see Sec. 98.7), 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.
* * * * *
[[Page 79156]]
0
22. 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.
* * * * *
0
23. 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.
* * * * *
0
24. Table F-1 to Subpart F of Part 98 is revised to read as follows:
Table F-1 to Subpart F of Part 98--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From Aluminum Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
CF[ihel4] slope Weight fraction
coefficient [(kg CF[ihel4] overvoltage C[ihel2]F[ihel6]/CF[ihel4]
Technology CF[ihel4]/metric ton coefficient [(kg CF[ihel4]/ [(kg C[ihel2]F[ihel6]/kg
Al)/(AE-Mins/cell-day)] metric ton Al)/(mV)] CF[ihel4])]
--------------------------------------------------------------------------------------------------------------------------------------------------------
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
--------------------------------------------------------------------------------------------------------------------------------------------------------
0
25. Table F-2 to Subpart F of Part 98 is amended by removing the entry
for ``CO2 Emissions from Pitch Volatiles Combustion (VSS and
HSS)'' and adding a new entry in its place to read as follows:
Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters
Used for CO[ihel2] Emissions
------------------------------------------------------------------------
Parameter Data source
------------------------------------------------------------------------
CO[bdi2] Emissions From Prebake Cells (CWPB and SWPB)
* * * * * * *
CO2 Emissions From Pitch Volatiles Combustion (CWPB and SWPB)
* * * * * * *
------------------------------------------------------------------------
Subpart G--[Amended]
0
26. 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).
* * * * *
0
27. Section 98.73 is amended by:
0
a. Revising paragraph (b) introductory text.
0
b. Revising the definition of ``CO2,G'' in Equation G-1 of
paragraph (b)(1).
0
c. Revising the definition of ``CO2,L'' in Equation G-2 of
paragraph (b)(2).
0
d. Revising the definition of ``CO2,S'' in Equation G-3 of
paragraph (b)(3).
0
e. Revising the definition of ``CO2'' in Equation G-5 of
paragraph (b)(5).
0
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)).
* * * * *
0
28. Section 98.74 is amended by revising paragraph (d) to read as set
forth below and by removing and reserving paragraph (f):
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
[[Page 79157]]
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).
* * * * *
0
29. 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. * * *
(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.
0
30. Section 98.76 is amended by:
0
a. Revising paragraphs (a) introductory text and (b)(6).
0
b. Removing paragraphs (b)(12) through (b)(15).
0
c. Redesignating paragraph (b)(16) as paragraph (b)(12).
0
d. Adding paragraph (b)(13).
0
e. 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).
* * * * *
(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]
0
31. Section 98.163 is amended by revising the definitions of
``CCn'' and ``MW'' in Equation P-1 of paragraph (b)(1) to
read as follows:
Sec. 98.163 Calculating GHG emissions.
* * * * *
(b) * * *
(1) * * *
CCn = Average carbon content of the gaseous fuel and
feedstock, from the results of one or more analyses for month n (kg
carbon per kg of fuel and feedstock). If measurements are taken more
frequently than monthly, use the arithmetic average of measurement
values within the month to calculate a monthly average.
MWn = Average molecular weight of the gaseous fuel and
feedstock from the results of one or more analyses for month n (kg/
kg-mole).
* * * * *
0
32. Section 98.164 is amended by revising paragraphs (b)(1), (b)(2),
and (b)(5) introductory text 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).
(2) Determine the carbon content and the molecular weight annually
of standard gaseous hydrocarbon fuels and feedstocks having consistent
composition (e.g., natural gas). For other gaseous fuels and feedstocks
(e.g., biogas, refinery gas, or process gas), sample and analyze no
less frequently than weekly to determine the carbon content and
molecular weight of the fuel and feedstock.
* * * * *
(5) You must use the following applicable methods to determine the
carbon content for all fuels and feedstocks, and molecular weight of
gaseous fuels and feedstocks. Alternatively, you may use the results of
continuous chromatographic analysis of the fuel and feedstock, provided
that the gas chromatograph (GC) 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 Sec. 98.3(g)(5).
* * * * *
Subpart V--[Amended]
0
33. Section 98.226 is amended by removing and reserving paragraph (o).
Subpart X--[Amended]
0
34. 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 on-site production of other chemicals as well as processes that
produce the petrochemical as an end product for sale or shipment off
site.
* * * * *
(g) A process that solely distills or recycles waste solvent that
contains a petrochemical is not part of the petrochemical production
source category.
0
35. 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.
* * * * *
0
36. Section 98.243 is amended by:
0
a. Revising the second sentence of paragraph (b).
0
b. Revising paragraph (c)(3).
0
c. Revising the definition of ``MVC'' in Equation X-1 in paragraph
(c)(5)(i).
0
d. 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 N20 emissions in accordance with subpart
C of this
[[Page 79158]]
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) * * *
(3) Collect a sample of each feedstock and product at least once
per month and determine the carbon content of each sample according to
the procedures of Sec. 98.244(b)(4). If multiple valid carbon content
measurements are made during the monthly measurement period, average
them arithmetically. However, if a particular liquid or solid feedstock
is delivered in lots, and if multiple deliveries of the same feedstock
are received from the same supply source in a given calendar month,
only one representative sample is required. Alternatively, you may use
the results of analyses conducted by a fuel or feedstock supplier,
provided the sampling and analysis is conducted at least once per month
using any of the procedures specified in Sec. 98.244(b)(4).
* * * * *
(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 combustion units that burn 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 (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. Sec.
98.253(b)(1) through (b)(3).
0
37. Section 98.244 is amended by revising paragraphs (b)(1) through
(b)(3), (b)(4) introductory text, and (b)(4)(viii); and by adding
paragraphs (b)(4)(xi) through (b)(4)(xv) 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 at the minimum frequency specified by the
manufacturer or biennially (i.e., once every two years).
(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 as specified
in paragraphs (b)(2)(i) and (b)(2)(ii) of this section:
(i) You may use either the calibration methods specified by the
flow meter manufacturer or an industry consensus standard method. Each
flow meter must meet the applicable accuracy specification in Sec.
98.3(i), except as otherwise specified in Sec. Sec. 98.3(i)(4) through
(i)(6).
(ii) You must recalibrate each flow meter according to one of the
following frequencies. You may recalibrate at the minimum frequency
specified by the manufacturer, biennially (every two years), 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 or you may use an industry standard practice.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
http://www.astm.org), the American National Standards Institute (ANSI,
1819 L Street, NW., 6th Floor, Washington, DC 20036, (202) 293-8020,
http://www.ansi.org), the American Gas Association (AGA, 400 North
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000,
http://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
http://www.asme.org), the American Petroleum Institute (API, 1220 L
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org,) and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(4) Beginning January 1, 2010, use any applicable methods specified
in paragraphs (b)(4)(i) through (b)(4)(xiv) 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)(xvi), as applicable. For coal used as a feedstock, the samples
for carbon content determinations shall be
[[Page 79159]]
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)(xv) of this
section may be performed by the owner or operator, by an independent
laboratory, or by the supplier of a feedstock.
* * * * *
(viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A
(all incorporated by reference, see Sec. 98.7).
* * * * *
(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).
(xii) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon
Content (incorporated by reference, see Sec. 98.7).
(xiii) The results of chromatographic analysis of a feedstock or
product, provided that the gas chromatograph is operated, maintained,
and calibrated according to the manufacturer's instructions.
(xiv) The carbon content results of mass spectrometer analysis of a
feedstock or product, provided that the mass spectrometer is operated,
maintained, and calibrated according to the manufacturer's
instructions.
(xv) Beginning on January 1, 2010, the methods specified in
paragraphs (b)(4)(xv)(A) and (B) of this section may be used as
alternatives for the methods specified in paragraphs (b)(4)(i) through
(b)(4)(xiv) of this section.
(A) An industry standard practice for carbon black feedstock oils
and carbon black products.
(B) Modifications of existing analytical methods or other methods
that are applicable to your process provided that the methods listed in
paragraphs (b)(4)(i) through (b)(4)(xiv) of this section 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.
0
38. Section 98.246 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(4).
0
b. Removing and reserving paragraph (a)(7).
0
c. Revising paragraph (a)(10).
0
d. Adding paragraph (a)(11).
0
e. Revising paragraphs (b) introductory text, and (b)(1) through
(b)(5).
0
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 temperature (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)(xv)(B), report the
information listed in paragraphs (a)(11)(i) through (a)(11)(iv) 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. Sec. 98.244(b)(4)(i) through (xiv), 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. 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 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
[[Page 79160]]
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).
0
39. Section 98.247 is amended by:
0
a. Revising paragraph (a).
0
b. Adding paragraph (b)(4).
0
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]
0
40. 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 upstream 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. * * *
0
41. Section 98.253 is amended by:
0
a. Revising paragraph (b)(1)(ii)(A).
0
b. Revising the definition of ``(Flare)p'' in Equation Y-2
in paragraph (b)(1)(ii)(B).
0
c. Revising the definition of ``MVC'' in Equation Y-3 in paragraph
(b)(1)(iii)(C).
0
d. Revising paragraph (c)(1)(ii).
0
e. Revising the definition of ``MVC'' in Equation Y-6 in paragraph
(c)(2)(i).
0
f. Revising paragraph (c)(2)(ii).
0
g. Revising the definitions of ``CBQ'' and ``n'' in Equation
Y-11 in paragraph (e)(3).
0
h. Revising the first sentence of paragraph (f) introductory text and
the last sentence of paragraph (f)(1).
0
i. Revising the definition of ``MVC'' in Equation Y-12 in paragraph
(f)(4).
0
j. Revising the definition of ``Mdust'' in Equation Y-13 in
paragraph (g)(2).
0
k. Revising paragraphs (h) introductory text and (h)(2).
0
l. In paragraph (i)(1), revising the first two sentences and the
definition of ``MVC'' in Equation Y-18.
0
m. In paragraph (j), revising the first two sentences; and revising the
definitions of ``(VR)p,'' ``(MFx)p,''
and ``MVC'' in Equation Y-19.
0
n. In paragraph (k), revising the first sentence and the definition of
``MVC'' in Equation Y-20.
0
o. Revising paragraph (m) introductory text.
0
p. Revising the only sentence of paragraph (m)(1).
0
p. Revising the definitions of ``MFCH4'' and ``MVC'' in
Equation Y-23 in paragraph (m)(2).
0
q. 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.
[[Page 79161]]
[GRAPHIC] [TIFF OMITTED] TR17DE10.005
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 [deg]F
and 14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-mole
at 60 [deg]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] TR17DE10.006
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 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]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.
(B) * * *
(Flare)p = Volume of flare gas combusted during
measurement period (million (MM) scf/period). If a mass flow meter
is used, you must also measure molecular weight and convert the mass
flow to a volumetric flow as follows: Flare[MMscf] = 0.000001 x
Flare[kg] x MVC/(MW)p, where MVC is the 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 depending on the
standard conditions used when determining (HHV)p] and
(MW)p is the average molecular weight of the flare gas
combusted during measurement period (kg/kg-mole).
* * * * *
(iii) * * *
(C) * * *
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).
* * * * *
(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 [deg]F
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
(ii) Either continuously monitor the volumetric flow rate of
exhaust gas from the fluid catalytic cracking unit regenerator or fluid
coking unit burner prior to the combustion of other fossil fuels or
calculate the volumetric flow rate of this exhaust gas stream using
either Equation Y-7a or Equation Y-7b of this section.
[GRAPHIC] [TIFF OMITTED] TR17DE10.007
Where:
Qr = Volumetric flow rate of exhaust gas from the fluid
catalytic cracking unit regenerator or fluid coking unit burner
[[Page 79162]]
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] TR17DE10.008
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).
[GRAPHIC] [TIFF OMITTED] TR17DE10.009
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).
[[Page 79163]]
[GRAPHIC] [TIFF OMITTED] TR17DE10.010
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] TR17DE10.011
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 reasonably be 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.
(1) For storage tanks other than those processing unstabilized
crude oil, you must either calculate CH4 emissions from
storage tanks that have a vapor-phase methane concentration of 0.5
volume percent or more using tank-specific methane composition data
(from measurement data or product knowledge) and the emission
estimation methods provided in AP 42, Section 7.1 (incorporated by
reference, see Sec. 98.7) or estimate CH4 emissions from
storage tanks using Equation Y-22 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 AP 42,
Section 5.2 (incorporated by reference, see Sec. 98.7). For loading
operations in which the vapor-phase concentration of methane is less
than 0.5 volume percent, you may assume zero methane emissions.
0
42. Section 98.254 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b).
0
c. Revising paragraph (c).
0
d. Revising paragraph (d) introductory text.
0
e. Adding paragraph (d)(6).
0
f. Revising paragraph (e) introductory text.
0
g. Revising paragraph (f) introductory text and (f)(1).
0
h. Removing and reserving paragraph (f)(2).
0
i. Removing paragraph (f)(4).
0
j. Revising paragraph (g).
0
k. Revising the second sentence of paragraph (h).
0
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
[[Page 79164]]
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 specified by the manufacturer, or according
to the procedures in the applicable methods specified in paragraphs (c)
through (g) of this section. In the case of gas flow meters, all gas
flow meters must meet the calibration accuracy requirements in Sec.
98.3(i). All gas flow meters, gas composition monitors, and heating
value monitors must be recalibrated at the applicable frequency
specified in paragraph (b)(1) or (b)(2) of this section.
(1) You must recalibrate each gas flow meter according to one of
the following frequencies. You may recalibrate at the minimum frequency
specified by the manufacturer, biennially (every two years), or at the
interval specified by the industry consensus standard practice used.
(2) You must recalibrate each gas composition monitor and heating
value monitor according to one of the following frequencies. You may
recalibrate at the minimum frequency specified by the manufacturer,
annually, or at the interval specified by the industry standard
practice used.
(c) For flare or sour gas flow meters and gas flow meters used to
comply with the requirements in Sec. 98.253(j), operate, calibrate,
and maintain the flow meter according to one of the following. You may
use the procedures specified by the flow meter manufacturer, or a
method published by a consensus-based standards organization.
Consensus-based standards organizations include, but are not limited
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373,
http://www.astm.org), the American National Standards Institute (ANSI,
1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020,
http://www.ansi.org), the American Gas Association (AGA, 400 North
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000,
http://www.aga.org), the American Society of Mechanical Engineers
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763,
http://www.asme.org), the American Petroleum Institute (API, 1220 L
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(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), 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 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 (incorporated by reference,
see Sec. 98.7) or the procedures specified by the manufacturer. * * *
* * * * *
0
43. Section 98.256 is amended by:
0
a. Revising paragraph (e)(6).
0
b. Redesignating paragraphs (e)(7) through (e)(9) as (e)(8) through
(e)(10), respectively.
0
c. Adding paragraph (e)(7).
0
d. Revising newly designated paragraphs (e)(8) and (e)(9).
0
e. Revising paragraphs (f)(6) through (f)(8).
0
f. Redesignating paragraphs (f)(9) through (f)(12) as (f)(10) through
(f)(13), respectively.
0
g. Adding paragraph (f)(9).
0
h. Revising newly designated paragraphs (f)(11) through (f)(13).
0
i. Revising paragraphs (g)(5), (h)(2), and (h)(4), and the first
sentence of paragraph (h)(6).
0
j. Adding paragraph (h)(7).
0
k. Revising paragraphs (i)(5), (i)(6), (i)(8), and (j)(2).
0
l. Redesignating paragraph (j)(8) as (j)(9).
0
m. Adding paragraph (j)(8).
0
n. Revising paragraphs (k)(1), (k)(3), (l) introductory text, (l)(5),
and (m).
0
o. Revising paragraphs (o)(1) through (o)(4).
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
[[Page 79165]]
or weekly measurement periods are used, the annual volume of flare gas
combusted (in million (MM) scf/year), the annual average higher heating
value of the flare gas (in mmBtu/mmscf), and an indication of whether
the annual volume of flare gas combusted and the annual average higher
heating value of the flare gas were determined using standard
conditions of 68 [deg]F and 14.7 psia or 60 [deg]F and 14.7 psia.
(9) If you use Equation Y-3 of this subpart, the annual volume of
flare gas combusted (in MMscf/year) during 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
[[Page 79166]]
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.
(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 (i.e., either AP 42, Section 7.1 (incorporated by reference, see
Sec. 98.7), or Equation Y-22 of this section).
(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.
* * * * *
0
44. 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]
0
45. Section 98.273 is amended by:
0
a. Revising paragraphs (a)(1) and (a)(2).
0
b. Revising the definition of ``EF'' in Equation AA-1 of paragraph
(a)(3).
0
c. Revising paragraphs (b)(1) and (b)(2).
0
d. 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).
(3) * * *
(EF) = Default or site-specific emission factor for CO2,
CH4, or N2O, from Table AA-1 of this subpart
(kg CO2, CH4, or N2O per mmBtu).
* * * * *
(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.
* * * * *
0
46. Section 98.276 is amended by revising the introductory text and
revising paragraph (e) 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:
* * * * *
(e) The default or site-specific emission factor for
CO2, CH4, or N2O, used in Equation AA-
1 of this subpart (kg CO2, CH4, or N2O
per mmBtu).
* * * * *
0
47. Table AA-2 to Subpart AA is revised to read as follows:
[[Page 79167]]
Table AA-2 to Subpart AA--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CH[ihel4] and
N[ihel2]O
----------------------------------------------------------------------------------------------------------------
Fossil fuel-based emissions factors (kg/mmBtu HHV)
-----------------------------------------------------------------------
Fuel Kraft lime kilns Kraft calciners
-----------------------------------------------------------------------
CH[ihel4] N[ihel2]O CH[ihel4] N[ihel2]O
----------------------------------------------------------------------------------------------------------------
Residual Oil............................ ................ ................ ................ 0.0003
Distillate Oil.......................... ................ ................ 0.0027 0.0004
Natural Gas............................. 0.0027 ................ 0.0001
Biogas.................................. ................ ................ ................ 0.0001
Petroleum coke.......................... ................ ................ NA \a\ NA
----------------------------------------------------------------------------------------------------------------
\a\ Emission factors for kraft calciners are not available.
Subpart OO--[Amended]
0
48. 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).
* * * * *
0
49. Section 98.414 is amended by:
0
a. Adding second and third sentences to paragraph (a).
0
b. Revising paragraph (h).
0
c. Removing and reserving paragraph (j).
0
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 the 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 fed into
the destruction device.
* * * * *
(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 February 15, 2011 if the fluorinated GHG product is being
produced on December 17, 2010. Perform the measurements within 60 days
of commencing production of any fluorinated GHG product that was not
[[Page 79168]]
being produced on December 17, 2010. 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.
0
50. Section 98.416 is amended by:
0
a. Revising paragraph (a)(3).
0
b. Removing and reserving paragraph (a)(4).
0
c. Revising paragraphs (a)(11) and (a)(15).
0
d. Revising paragraphs (b) introductory text and (b)(1).
0
e. Revising paragraphs (c) introductory text, (c)(1), and (c)(10).
0
f. Revising paragraph (d) introductory text.
0
g. Revising paragraph (e) introductory text.
0
h. 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.
* * * * *
(15) Names and addresses of facilities to which any fluorinated
GHGs were sent for destruction, and the quantities (metric tons) of
each fluorinated GHG that were sent to each for destruction.
* * * * *
(b) By March 31, 2011 or within 60 days of commencing fluorinated
GHG destruction, whichever is later, a fluorinated GHG production
facility or importer that destroys fluorinated GHGs shall submit a one-
time report containing the following information for each destruction
process:
(1) Destruction efficiency (DE).
* * * * *
(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.
* * * * *
(10) If applicable, the names and addresses of the persons and
facilities to which the fluorinated GHGs were sold or transferred for
destruction, and the quantities (metric tons) of each fluorinated GHG
that were sold or transferred to each facility for destruction.
(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:
* * * * *
(e) By March 31, 2011, or within 60 days of commencing fluorinated
GHG production, whichever is later, a fluorinated GHG production
facility shall submit a one-time report describing the following
information:
* * * * *
(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.
0
51. Section 98.417 is amended by revising paragraphs (a)(2), (b), and
(d)(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 manufacturer directions or industry standards used for
[[Page 79169]]
calibration pursuant to Sec. 98.414(m) and (o).
(b) In addition to the data required by paragraph (a) of this
section, any fluorinated GHG production facility that destroys
fluorinated GHGs shall keep records of test reports and other
information documenting the facility's one-time destruction efficiency
report in Sec. 98.416(b).
* * * * *
(d) * * *
(2) The invoice for the export.
* * * * *
(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.
0
52. 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 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]
0
53. 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.
* * * * *
0
54. Section 98.423 is amended by:
0
a. Revising the first sentence of paragraph (a) introductory text.
0
b. Revising the first sentences of paragraphs (a)(1) and (a)(2).
0
c. Revising the definitions of ``CCO2,p'' and
``Dp'' in Equation PP-2 in paragraph (a)(2).
0
d. Revising paragraph (a)(3).
0
e. Redesignating paragraph (b) as paragraph (c) and revising newly
designated paragraph (c).
0
f. Adding 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. * * *
* * * * *
CCO2,p = Quarterly CO2 concentration
measurement in flow for flow meter u in quarter p (measured as
either volume % CO2 or weight % CO2).
* * * * *
Dp = Density of CO2 in quarter p (metric tons
CO2 per standard cubic meter) for flow meter u if
CCO2,p is measured as volume % CO2, or density
of the whole CO2 stream for flow meter u (metric tons per
standard cubic meter) if CCO2,p is measured as weight %
CO2.
* * * * *
(3) To aggregate data, use either Equation PP-3a or PP-3b in this
paragraph, as appropriate.
(i) For facilities with production process units that capture a
CO2 stream and either measure it after segregation or do not
segregate the flow, calculate the total CO2 supplied in
accordance with Equation PP-3a.
[GRAPHIC] [TIFF OMITTED] TR17DE10.012
Where:
CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons)
through flow meter u.
u = Flow meter.
(ii) For facilities with production process units that capture a
CO2 stream and measure it ahead of segregation, calculate
the total CO2 supplied in accordance with Equation PP-3b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.013
Where:
CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons)
through main flow meter u.
CO2,v = Annual mass of CO2 (metric tons)
through subsequent flow meter v for use on site.
u = Main flow meter.
v = Subsequent flow meter.
(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
[[Page 79170]]
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 = Quarterly CO2 concentration
measurement of CO2 stream u that delivers CO2
to containers in quarter p (measured as either volume %
CO2 or weight % CO2).
Qp = Quarterly volume of contents supplied in all
containers delivered by CO2 stream u in quarter p
(standard cubic meters).
Dp = Quarterly CO2 density determination for
CO2 stream u in quarter p (metric tons per standard cubic
meter) if CO2,p is measured as volume %
CO2, or density of CO2 stream u (metric tons
per standard cubic meter) if CO2,p is measured as weight
% CO2.
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-3a 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.
[GRAPHIC] [TIFF OMITTED] TR17DE10.014
Where:
CO2 = Annual mass of CO2 (metric tons).
Q = Annual mass in all CO2 containers imported or
exported during the reporting year (metric tons).
0
55. Section 98.424 is amended by:
0
a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
0
b. Revising the second sentence of paragraph (b)(2).
0
c. Adding paragraph (c).
Sec. 98.424 Monitoring and QA/QC requirements.
(a) * * *
(1) Reporters following the procedures in Sec. 98.423(a) 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 according to the following:
(A) For reporters following the procedures in Sec.
98.423(a)(3)(i), you must locate the flow meter(s) after the point of
segregation.
(B) For reporters following the procedures in paragraph (a)(3)(ii)
of Sec. 98.423, you must locate the main flow meter(s) on the captured
CO2 stream(s) prior to the point of segregation and the
subsequent flow meter(s) on the CO2 stream(s) for on-site
use after the point of segregation. You may only follow the procedures
in paragraph (a)(3)(ii) of Sec. 98.423 if the CO2 stream(s)
for on-site use is/are the only diversion(s) from the main, captured
CO2 stream(s) after the main flow meter location(s).
(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 is
delivered, sum the mass of contents supplied in all containers to which
the CO2 stream is 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 is
delivered, sum the volume of contents supplied in all containers to
which the CO2 stream is 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 and measuring
CO2 concentration as weight % CO2 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:
(i) You may use a method published by a consensus-based standards
organization. Consensus-based standards organizations include, but are
not limited to, the following: ASTM International (100 Barr Harbor
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959,
(800) 262-1373, http://www.astm.org), the American National Standards
Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036,
(202) 293-8020, http://www.ansi.org), the American Gas Association
(AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001,
(202) 824-7000, http://www.aga.org), the American Society of
[[Page 79171]]
Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990,
(800) 843-2763, http://www.asme.org), the American Petroleum Institute
(API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000,
http://www.api.org), and the North American Energy Standards Board
(NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-
0060, http://www.api.org). The method(s) used shall be documented in
the Monitoring Plan required under Sec. 98.3(g)(5).
(ii) You may follow an industry standard method.
(b) * * *
(2) * * * Acceptable methods include, but are not limited to, the
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 (ASTM International, 100 Barr Harbor
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959,
(800) 262-1373, http://www.astm.org).
(c) You shall convert the density of the CO2 stream(s)
and 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 0.001868 metric tons per standard
cubic meter.
0
56. Section 98.425 is amended by revising paragraph (a) introductory
text; and by adding paragraph (d) to read as follows:
Sec. 98.425 Procedures for estimating missing data.
(a) Whenever the quality assurance procedures in Sec. 98.424(a)(1)
of this subpart cannot be followed to measure quarterly mass flow or
volumetric flow of CO2, the most appropriate of the
following missing data procedures shall be followed:
* * * * *
(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.
0
57. Section 98.426 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(2).
0
b. Adding paragraph (a)(5).
0
c. Revising paragraphs (b) introductory text, (b)(2), (b)(3), and
(b)(4).
0
d. Adding paragraph (b)(7).
0
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, dehydration,
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.
(3) Quarterly concentration of the CO2 stream in volume
or weight percent.
(4) Report density as follows:
(i) Quarterly density of CO2 in metric tons per standard
cubic meter if you report the concentration of the CO2
stream in paragraph (b)(3) of this section in weight percent.
(ii) Quarterly density of the CO2 stream in metric tons
per standard cubic meter if you report the concentration of the
CO2 stream in paragraph (b)(3) of this section in volume
percent.
* * * * *
(7) The location of the flow meter in your process chain in
relation to the points of CO2 stream capture, dehydration,
compression, and other processing.
(c) For the aggregated annual mass of CO2 emissions
calculated using Equation PP-3a or PP-3b, report the following:
(1) If you use Equation PP-3a of this subpart, report the annual
CO2 mass in metric tons from all flow meters and
CO2 streams that deliver CO2 to containers.
(2) If you use Equation PP-3b of this subpart, report:
(i) The total annual CO2 mass through main flow meter(s)
in metric tons.
(ii) The total annual CO2 mass through subsequent flow
meter(s) in metric tons.
(iii) The total annual CO2 mass supplied in metric tons.
(iv) The location of each flow meter in relation to the point of
segregation.
* * * * *
(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. 2010-30286 Filed 12-16-10; 8:45 am]
BILLING CODE 6560-50-P