[Federal Register Volume 75, Number 242 (Friday, December 17, 2010)]
[Rules and Regulations]
[Pages 79092-79171]
[FR Doc No: 2010-30286]

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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

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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:<PHONE_NUMBER>; fax number:<PHONE_NUMBER>; e-mail address:
<EMAIL_ADDRESS>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
------------------------------------------------------------------------
                                                   Examples of affected
            Category                  NAICS             facilities
------------------------------------------------------------------------
General Stationary Fuel          ..............  Facilities operating
 Combustion Sources.                              boilers, process
                                                  heaters, incinerators,
                                                  turbines, and internal
                                                  combustion engines.
                                            211  Extractors of crude
                                                  petroleum and natural
                                                  gas.
                                            321  Manufacturers of lumber
                                                  and wood products.
                                            322  Pulp and paper mills.
                                            325  Chemical manufacturers.
                                            324  Petroleum refineries
                                                  and manufacturers of
                                                  coal products.
                                  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.

                                         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.
------------------------------------------------------------------------
\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

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

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

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.

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

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

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.

    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

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

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

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

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

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

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

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

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