[Federal Register Volume 75, Number 242 (Friday, December 17, 2010)]
[Rules and Regulations]
[Pages 79092-79171]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 2010-30286]



[[Page 79091]]

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Part II





Environmental Protection Agency





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40 CFR Part 98



Mandatory Reporting of Greenhouse Gases; Final Rule

  Federal Register / Vol. 75, No. 242 / Friday, December 17, 2010 / 
Rules and Regulations  

[[Page 79092]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 98

[EPA-HQ-OAR-2008-0508; FRL-9234-7]
RIN 2060-AQ33


Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is amending specific provisions in the greenhouse gas 
reporting rule to clarify certain provisions, to correct technical and 
editorial errors, and to address certain questions and issues that have 
arisen since promulgation. These final changes include generally 
providing additional information and clarity on existing requirements, 
allowing greater flexibility or simplified calculation methods for 
certain sources, amending data reporting requirements to provide 
additional clarity on when different types of greenhouse gas emissions 
need to be calculated and reported, clarifying terms and definitions in 
certain equations and other technical corrections and amendments.

DATES: The final rule is effective on December 31, 2010. The 
incorporation by reference of certain publications listed in the final 
rule amendments are approved by the director of the Federal Register as 
of December 31, 2010.

ADDRESSES: EPA has established a docket under Docket ID No. EPA-HQ-OAR-
2008-0508 for this action. All documents in the docket are listed in 
the http://www.regulations.gov index. Although listed in the index, 
some information is not publicly available, e.g., confidential business 
information (CBI) or other information whose disclosure is restricted 
by statute. Certain other material, such as copyrighted material, is 
not placed on the Internet and will be publicly available only in hard 
copy form. Publicly available docket materials are available either 
electronically through http://www.regulations.gov or in hard copy at 
EPA's Docket Center, Public Reading Room, EPA West Building, Room 3334, 
1301 Constitution Ave., NW., Washington, DC. This Docket Facility is 
open from 8:30 a.m. to 4:30 p.m., Monday through Friday, excluding 
legal holidays. The telephone number for the Public Reading Room is 
(202) 566-1744, and the telephone number for the Air Docket is (202) 
566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
[email protected]. For technical information and implementation 
materials, please go to the Greenhouse Gas Reporting Program Web site 
http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. To 
submit a question, select Rule Help Center, followed by Contact Us.

SUPPLEMENTARY INFORMATION: Regulated Entities. The Administrator 
determined that this action is subject to the provisions of Clean Air 
Act (CAA) section 307(d). See CAA section 307(d)(1)(V) (the provisions 
of section 307(d) apply to ``such other actions as the Administrator 
may determine''). These are final amendments to existing regulations. 
These amended regulations affect owners or operators of certain 
suppliers and direct emitters of greenhouse gases (GHGs). Regulated 
categories and entities include those listed in Table 1 of this 
preamble:

           Table 1--Examples of Affected Entities by Category
------------------------------------------------------------------------
                                                   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.

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                                         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

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comment (but within the time specified for judicial review) and if such 
objection is of central relevance to the outcome of the rule.'' Any 
person seeking to make such a demonstration to us should submit a 
Petition for Reconsideration to the Office of the Administrator, 
Environmental Protection Agency, Room 3000, Ariel Rios Building, 1200 
Pennsylvania Ave., NW., Washington, DC 20460, with a copy to the person 
listed in the preceding FOR FURTHER INFORMATION CONTACT section, and 
the Associate General Counsel for the Air and Radiation Law Office, 
Office of General Counsel (Mail Code 2344A), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20004. Note, under 
CAA section 307(b)(2), the requirements established by this final rule 
may not be challenged separately in any civil or criminal proceedings 
brought by EPA to enforce these requirements.
    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

API American Petroleum Institute
ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BAMM best available monitoring method
CAA Clean Air Act
cc cubic centimeters
CE calibration error
CEMS continuous emission monitoring system
CFR Code of Federal Regulations
CGA Cylinder gas audit
CH4 methane
CO carbon monoxide
CO2 carbon dioxide
CO2e CO2-equivalent
CWPB center worked prebake
FR Federal Register
FTIR Fourier transform infrared
GC gas chromatography
GHG greenhouse gas
GHGRP Greenhouse Gas Reporting Program
GPA Gas Processors Association
GWP global warming potential
HFCs hydrofluorocarbons
HHV high heat value
HSS horizontal stud S[oslash]derberg
IPCC Intergovernmental Panel on Climate Change
IR infrared
LDCs local natural gas distribution companies
mmBtu/hr million British thermal units per hour
mscf thousand standard cubic feet
MSW municipal solid waste
mtCO2e metric tons of CO2 equivalents
MVC molar volume conversion factor
NESHAP National Emission Standards for Hazardous Air Pollutants
NIST National Institute of Standards and Technology
NMR nuclear magnetic resonance
NSPS New Source Performance Standards
N2O nitrous oxide
NAICS North American Industry Classification System
NGLs natural gas liquids
O2 oxygen
OMB Office of Management and Budget
PFC perfluorocarbon
psia pounds per square inch absolute
QA quality assurance
QA/QC quality assurance/quality control
RATA relative accuracy test audit
RFA Regulatory Flexibility Act
scf standard cubic feet
scfm standard cubic feet per minute
SF6 sulfur hexafluoride
SO2 sulfur dioxide
SWPB side worked prebake
U.S. United States
VSS vertical stud S[oslash]derberg

Table of Contents

I. Background
    A. How is this preamble organized?
    B. Background on This Action
    C. Legal Authority
    D. How will these amendments apply to 2011 reports?
II. Final Amendments and Responses to Public Comments
    A. Subpart A--General Provisions: Best Available Monitoring 
Methods
    B. Subpart A--General Provisions: Calibration Requirements
    C. Subpart A--General Provisions: Reporting of Biogenic 
Emissions
    D. Subpart A--General Provisions: Requirements for Correction 
and Resubmission of Annual Reports
    E. Subpart A--General Provisions: Information to Record for 
Missing Data Events
    F. Subpart A--General Provisions: Other Technical Corrections 
and Amendments
    G. Subpart C--General Stationary Fuel Combustion
    H. Subpart D--Electricity Generation
    I. Subpart F--Aluminum Production
    J. Subpart G--Ammonia Manufacturing
    K. Subpart P--Hydrogen Production
    L. Subpart V--Nitric Acid Production
    M. Subpart X--Petrochemical Production
    N. Subpart Y--Petroleum Refineries
    O. Subpart AA--Pulp and Paper Manufacturing
    P. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
    Q. Subpart OO--Suppliers of Industrial Greenhouse Gases
    R. Subpart PP--Suppliers of Carbon Dioxide
III. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination with 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children from 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions that Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions to Address 
Environmental Justice in Minority Populations and Low-Income 
Populations
    K. Congressional Review Act

I. Background

A. How is this preamble organized?

    The first section of this preamble contains the basic background 
information about the origin of these rule amendments. This section 
also discusses EPA's use of our legal authority under the CAA to 
collect data on GHGs.
    The second section of this preamble describes in detail the rule 
changes that are being promulgated to, among other things, correct 
technical errors, provide clarification, and address implementation 
issues identified by EPA and others. This section also presents a 
summary and EPA's response to the major public comments submitted on 
the proposed rule amendments, and significant changes, if any, made 
since proposal in response to those comments.
    Finally, the last (third) section discusses the various statutory 
and executive order requirements applicable to this rulemaking.

B. Background on This Action

    The final Mandatory Reporting of Greenhouse Gases Rule was signed 
by EPA Administrator Lisa Jackson on September 22, 2009 and published 
in the Federal Register on October 30, 2009 (74 FR 56260-56519). This 
rule, which added Part 98 to chapter 40 of the Code of Federal 
Regulations (CFR) as well as amending other parts of 40 CFR, became 
effective on December 29, 2009, and included reporting of GHG 
information from facilities and suppliers, consistent with the 2008 
Consolidated Appropriations Act.\1\ These source categories capture 
approximately 85 percent of U.S. GHG emissions through reporting by 
direct emitters as well as certain suppliers (e.g., fossil fuel, 
petroleum products, industrial gases and CO2) and 
manufacturers of mobile sources.
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    \1\ Consolidated Appropriations Act, 2008, Pub. L. 110-161, 121 
Stat. 1844, 2128.
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    EPA published a notice proposing these amendments to Part 98 to, 
among other things, correct certain technical and editorial errors that 
have been identified since promulgation and clarify or propose 
amendments to certain provisions that have been the subject of 
questions from reporting entities. The proposal was published on

[[Page 79095]]

August 11, 2010 (75 FR 48744). The public comment period for the 
proposed rule amendments ended on September 27, 2010. EPA did not 
receive any requests to hold a public hearing.
    This is the second time that EPA has published a notice 
promulgating amendments to Part 98 to, among other things, correct 
certain technical and editorial errors identified since Part 98 was 
originally promulgated and to clarify and amend certain provisions that 
have been the subject of questions from reporting entities. The first 
final rule amendments were published on October 28, 2010 (75 FR 66434). 
This final rule complements the final rule published on October 28, 
2010 and is not intended to duplicate or replace those amendments.

C. Legal Authority

    EPA is promulgating these rule amendments under its existing CAA 
authority, specifically authorities provided in CAA section 114.
    As stated in the preamble to the 2009 final rule (74 FR 56260, 
October 30, 2009), CAA section 114 provides EPA broad authority to 
require the information mandated by Part 98 because such data would 
inform and are relevant to EPA's obligation to carry out a wide variety 
of CAA provisions. As discussed in the preamble to the initial proposal 
(74 FR 16448, April 10, 2009), CAA section 114(a)(1) authorizes the 
Administrator to require emissions sources, persons subject to the CAA, 
manufacturers of process or control equipment, and persons whom the 
Administrator believes may have necessary information to monitor and 
report emissions and provide such other information the Administrator 
requests for the purposes of carrying out any provision of the CAA. For 
further information about EPA's legal authority, see the preambles to 
the proposed and final rule, and Response to Comments Documents.\2\
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    \2\ 74 FR 16448 (April 10, 2009) and 74 FR 56260 (October 30, 
2009). Response to Comments Documents can be found at http://www.epa.gov/climatechange/emissions/responses.html
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D. How will these amendments apply to 2011 reports?

    We have determined that it is feasible for sources to implement 
these changes for the 2010 reporting year because the revisions 
primarily provide additional clarifications regarding the existing 
regulatory requirements, generally do not affect the type of 
information that must be collected and do not substantially affect how 
emissions are calculated. Our rationale for this determination is 
explained in the preamble to the proposed rule amendments.\3\ In 
response to general comments submitted on the proposed rulemaking, we 
have again reviewed the final amendments and determined that, with one 
limited exception, they can be implemented, as finalized, for the 2010 
reporting year.
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    \3\ 75 FR 48747 (August 11, 2010).
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    The one new requirement, regarding reporting of biogenic 
CO2 emissions from units subject to 40 CFR Part 75, is being 
phased in, so that it remains optional for reporting year 2010, but 
becomes mandatory for each subsequent year. Therefore this revision, as 
finalized, already accommodates implementation for the 2010 reporting 
year.
    In summary, except for the exception discussed above regarding 
biogenic CO2 emissions, these amendments do not require any 
additional monitoring or data collection above what was already 
included in Part 98. Therefore, we have determined that reporters can 
use the same information that they have been collecting under Part 98 
for each subpart to calculate and report GHG emissions for 2010 and 
submit reports in 2011 under the amended subparts.
    Following is a brief summary of major comments and responses. 
Several comments were received on this topic. Responses to additional 
significant comments received can be found in the document, ``Response 
to Comments: Revision to Certain Provisions of the Mandatory Reporting 
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Several commenters requested that we make use of the 
amendments optional for the 2010 reporting year and mandatory beginning 
with the 2011 reporting year. The commenters expressed concern that in 
2010, sources may not have been collecting the required data to 
implement certain amendments.
    Response: We sought comment on the feasibility of incorporating the 
proposed revisions for the 2010 reporting year. In the proposal, we 
explained that we felt implementation for the 2010 reporting year would 
be feasible because the proposed revisions, to a great extent, would 
simply clarify existing regulatory requirements or add flexibility to 
the rule. Further, the proposed amendments would not substantially 
affect the type of information that must be collected or how emissions 
are calculated. We sought comment on this conclusion and whether this 
timeline is feasible or appropriate, considering the nature of the 
proposed changes and the way in which data have been collected thus far 
in 2010. We requested that commenters provide specific reasons why they 
believe that the proposed implementation schedule would or would not be 
feasible. We received some comments about making optional the use of 
the amendments in 2010, as well as comments proposing to extend 
submission of the first reports until June 1, 2011. We received a few 
industry-specific examples providing a rationale for extending the 
deadline for reporting, or making use of the amendments optional for 
the 2010 reporting year. For example, some commenters expressed concern 
that the proposed clarification of the definition of natural gas, as 
well as the introduction of fuel gas into Table C-1, could affect 
applicability under the rule and the use of the tiers under subpart C. 
We have addressed the underlying concerns expressed by these 
commenters, as EPA did not intend to change applicability or force 
facilities to use higher tiered calculation methodologies. Therefore, 
because we addressed the underlying concerns, we are finalizing 
requirements to incorporate the amendments into 2010 reporting year 
data.

II. Final Amendments and Responses to Public Comments

    We are amending various subparts in Part 98 to correct errors in 
the regulatory language that were identified as a result of working 
with reporters to implement the various subparts of Part 98. We are 
also amending certain rule provisions to provide greater clarity. The 
amendments to Part 98 include the following types of changes:
     Additional information to understand better or more fully 
compliance obligations in a specific provision, such as the reference 
to a standardized method that must be followed.
     Amendments to certain equations to better reflect actual 
operating conditions.
     Corrections to terms and definitions in certain equations.
     Corrections to data reporting requirements so that they 
more closely conform to the information used to perform emission 
calculations.
     Amendments, in limited cases, to allow for the use of 
simplified emissions calculation methods.
     Changes to correct cross references within and between 
subparts.
     Other amendments related to certain issues identified as a 
result of working with reporters during rule implementation and 
outreach.
     Applying a threshold for reporting for local distribution 
companies of equal to or greater than 460,000 thousand

[[Page 79096]]

standard cubic feet (mscf) of natural gas delivered per year.
     Requiring separate reporting of biogenic CO2 
emissions for units that are also subject to 40 CFR part 75, beginning 
with the 2011 reporting year.
    The final amendments promulgated by this action reflect EPA's 
consideration of the comments received on the proposal. The major 
public comments and EPA's responses for each subpart are provided in 
this preamble. Our responses to additional significant public comments 
on the proposal are presented in a comment response document available 
in Docket ID No. EPA-HQ-OAR-2008-0508.

A. Subpart A--General Provisions: Best Available Monitoring Methods

1. Summary of Final Amendments and Major Changes Since Proposal
    EPA is finalizing the petition process established in 40 CFR 
98.3(j) that allows use of Best Available Monitoring Methods (BAMM) 
past December 31, 2010 for owners and operators required to report 
under subpart P (Hydrogen Production), subpart X (Petrochemical 
Production), or subpart Y (Petroleum Refineries), under limited 
circumstances. Owners or operators subject to these subparts can 
petition EPA to extend use of BAMM past December 31, 2010, if 
compliance with a specific provision in the regulation requires 
measurement device installation, and installation would necessitate an 
unscheduled process equipment or unit shutdown, or could be installed 
only through a ``hot tap.'' If the application is approved, the owner 
or operator can postpone installation of the measurement device until 
the next scheduled maintenance outage, but initially no later than 
December 31, 2013. If, in 2013, owners or operators still determine and 
certify that a scheduled shutdown will not occur by December 31, 2013, 
they may re-apply to use best available monitoring methods for an 
additional two years.
    Process for requesting an extension of best available monitoring 
methods. We are adding a similar petition process to that recently 
concluded for the use of BAMM for 2010 in 40 CFR 98.3(j). The process 
is for quantifying emissions from any source category at facilities 
subject to subparts P, X and/or Y, and solely for the installation of 
measurement devices that cannot be installed safely except during full 
process equipment or unit shutdown or through installation via a hot 
tap. BAMM is allowable initially no later than December 31, 2013. 
Subpart P, X, and/or Y owners or operators requesting to use BAMM 
beyond 2010 are required to electronically notify EPA by January 1, 
2011 that they intend to apply for BAMM for installation of measurement 
devices and certify that such installation will require a hot tap or 
unscheduled shutdown.
    Owners or operators must submit the full extension request for BAMM 
by February 15, 2011. The full extension request must include a 
description of the measurement devices that could not be installed in 
2010 without a process equipment or unit shutdown, or through a hot 
tap, a clear explanation of why that activity could not be accomplished 
in 2010 with supporting material, an estimated date for the next 
planned maintenance outage, and a discussion of how emissions will be 
calculated in the interim. More specifically, the full extension 
request must identify the specific monitoring instrumentation for which 
the request is being made, indicate the locations where each piece of 
monitoring instrumentation will be installed, and note the specific 
rule requirements (by rule subpart, section, and paragraph numbers) for 
which the instrumentation is needed. The extension requests must also 
include supporting documentation demonstrating that it is not 
practicable to isolate the equipment and install the monitoring 
instrument without a full process equipment or unit shutdown, or 
through a hot tap, as well as providing the dates of the three most 
recent process equipment or unit shutdowns, the typical frequency of 
shutdowns for the respective equipment or unit, and the date of the 
next planned shutdown.
    Once subpart P, X, and/or Y owners or operators have notified EPA 
of their plan to apply for BAMM for measurement device installation, by 
January 1, 2011, and subsequently submitted a full extension request, 
by February 15, 2011, they can automatically use BAMM consistent with 
their request through June 30, 2011. This automatic extension is 
necessary because the current BAMM requests submitted by these 
facilities will end no later than December 31, 2010. The BAMM must be 
extended automatically to provide EPA the time to review thoroughly the 
BAMM requests submitted for post-2010, while ensuring that the 
petitioning facilities are not out of compliance with the rule during 
that review process. All measurement devices must be installed by July 
1, 2011 unless EPA approves the BAMM extension request before that 
date.
    Approval of extension requests. In any approval of an extension 
request, EPA will approve the extension itself, establish a date by 
which all measurement devices must be installed, and indicate the 
approved alternate method for calculating GHG emissions in the interim.
    If EPA approves an extension request, the owner/operator has until 
the date approved by EPA to install the relevant remaining meters or 
other measurement devices, however initial approvals will not grant 
extensions beyond December 31, 2013. An owner/operator that already 
received approval from EPA to use BAMM during part or all of 2010 is 
required to submit a new request for use of BAMM beyond 2010. Unless 
EPA has approved an extension request, all owners or operators that 
submit a timely request under this new process for BAMM will be 
required to install all measurement devices by July 1, 2011.
    We recognize that occasionally a facility may plan a scheduled 
process equipment or unit shutdown and the installation of required 
monitoring equipment, but the date of the scheduled shutdown is 
changed. We are adding a process by which owners or operators who 
receive an extension will have the opportunity to extend the use of 
BAMM beyond the date approved by EPA if they can demonstrate to the 
Administrator's satisfaction that they are making a good faith effort 
to install the required equipment. At a minimum, facilities that 
determine that the date of a scheduled shutdown will be postponed are 
required to notify EPA within 4 weeks of such a determination, but no 
later than 4 weeks before the date for which the planned shutdown was 
scheduled.
    One-time request to extend best available monitoring methods past 
December 31, 2013. If subpart P, X, and/or Y owners or operators 
determine that a scheduled shutdown will not occur by December 31, 2013 
and thus they want to continue to use BAMM, they are required to re-
apply to use BAMM for one additional time period, not to extend beyond 
December 31, 2015. To obtain an extension for the use of BAMM past 
December 13, 2013, owners or operators are required to submit a new 
extension request by June 1, 2013 that contains the information 
required in 40 CFR 98.3(j)(4). All owners or operators that submit a 
request under this paragraph to extend the use of best available 
monitoring methods for measurement device installation are required to 
install all measurement devices by December 31, 2013, unless the 
additional extension request under this paragraph is approved by EPA.

[[Page 79097]]

2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this topic. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: EPA received several comments, both in support of and in 
opposition to, the proposed extension of BAMM for facilities subject to 
subparts P, X and Y. Some commenters that supported the new BAMM 
process also recommended that EPA extend the process beyond hydrogen 
producers, petrochemical facilities and petroleum refineries. They 
suggested that the same logic should apply to all facilities, that 
installation of monitoring equipment should not require process 
equipment or unit shutdown.
    Other commenters were concerned that the new BAMM process conflicts 
with the need for consistent data. The commenters urged that if EPA 
nevertheless decides to finalize the requirements, there should be only 
a one-time application process with BAMM ending no later than December 
2013. Further, they asserted that EPA should require facilities to make 
use of unplanned shutdowns as an opportunity to install equipment.
    Response: EPA carefully considered the issues raised by commenters 
and decided to retain the BAMM extension process, as proposed, only for 
facilities subject to subparts P, X and Y. The proposal preamble sought 
comment on this very issue and requested that commenters provide 
information on additional subparts, if any, that would need this 
flexibility, and include information on why installation could not be 
done in the absence of such a shutdown or why such shutdowns did not or 
could not occur in 2010 without unreasonable burden on the facility. 
Commenters did not provide the requested information to support their 
position that the provision should be extended to other industries. In 
summary, the commenters argued only that EPA should provide this 
flexibility, but did not provide a rationale as to why additional 
industries needed the flexibility.
    Regarding concerns that the new BAMM process would lead to 
inconsistent data, EPA has determined that this limited opportunity for 
a BAMM extension will provide sufficiently consistent data for these 
industries without causing the unnecessary burden or potential safety 
concerns that would be associated with installation of monitoring 
devices during unplanned shutdowns or hot taps. EPA notes that the BAMM 
process will still require facilities to follow the calculation methods 
in the rule, but will allow owners or operators to use alternative 
methods to provide the inputs to those calculations. Further, unlike 
the BAMM process that was established by promulgation of the October 
30, 2009 reporting rule (74 FR 56379-56380), any request for BAMM after 
2010 will require EPA approval of a facility's proposed approach to be 
implemented in lieu of the requirements in the rule. This further 
ensures that EPA will continue to receive data of the appropriate 
quality.
    EPA decided not to limit BAMM to a one-time extension through 2013, 
because we determined that the reasons supporting extension through 
2013 were still valid post 2013. Specifically, facilities in these 
particularly complex industries should not have to shut down 
unnecessarily in order to install equipment. Data provided by these 
industries show that some units, for example crude distillation units, 
are shut down only every 4 to 7 years. Other units such as vacuum 
distillation units, fluid catalytic cracking units, distillate 
hydrotreating units, catalytic feed hydrotreaters, hydrocrackers, 
coking units, sulfur recovery units and cogeneration units can be shut 
down as infrequently as every 5 years (see final Background Technical 
Support document to the Revision of Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule). Thus, providing a potential end 
date for BAMM of December 31, 2015, is appropriate based on information 
presented for these industries on the typical frequency of shutdown for 
these facilities.
    We also are not requiring a facility to order the measurement 
equipment early and have it on hand in the event of an unplanned 
shutdown before the scheduled shutdown. First, it would be hard to 
enforce a requirement to install equipment during an unplanned shutdown 
``if feasible'' because it would be hard to objectively determine 
whether a facility should have installed equipment during an unplanned 
shutdown. Moreover, during an unplanned shutdown, the priority is often 
to get the equipment up and running as quickly and safely as possible; 
therefore, there is not necessarily time to install the measurement 
equipment.
    Comment: In a related comment, one commenter raised concerns about 
Tier 3 monitoring requirements for a stream at its facility that is 
dangerous to monitor due to the presence of hydrogen cyanide. They 
indicated that they used BAMM to implement an approach other than 
direct sampling of the inputs to the equations for the 2010 reporting 
year, and now are considering implementing the Tier 4 method for future 
years. However, they argued the rule should provide a mechanism to 
address these dangerous streams.
    Response: No rule change has been made as a result of the comment. 
For the 2010 reporting year, the BAMM provisions were designed for use 
where it was not possible to acquire, install and operate a required 
piece of equipment during the early months of the GHG Reporting 
Program. Safety concerns were a valid reason for approving these early 
BAMM applications.
    Although the commenter notes concerns with conducting the Tier 3 
method for quantifying emissions from stationary combustion at the 
facility due to the presence of a hydrogen cyanide stream, EPA notes 
that the rule does not limit them to use of a Tier 3 approach. As 
acknowledged by the commenter, they also have the opportunity to use 
Tier 4 to meet the requirements of the rule and, by taking advantage of 
BAMM for 2010, had one year to install the Tier 4 equipment. The 
commenter merely wants additional time beyond that already provided in 
the rule to comply with the Tier 4 requirements. The commenter does not 
justify the requested extension by pointing to issues like unplanned 
shutdowns or hot taps, as discussed in the proposal. EPA has determined 
the unique situation raised by the commenter does not warrant expanding 
the BAMM process generally beyond industries subject to subparts P, X 
and Y.

B. Subpart A--General Provisions: Calibration Requirements

1. Summary of Final Amendments and Major Changes Since Proposal
    EPA has finalized amendments to 40 CFR 98.3(i)(1) to specify that 
the calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) 
are required only for flow meters that measure liquid and gaseous fuel 
feed rates, feedstock flow rates, or process stream flow rates that are 
used in the GHG emissions calculations, and only when the calibration 
accuracy requirement is specified in an applicable subpart of Part 98. 
For instance, the QA/QC requirements in 40 CFR 98.34(b)(1) of

[[Page 79098]]

subpart C require all flow meters that measure liquid and gaseous fuel 
flow rates for the Tier 3 CO2 calculation methodology to be 
calibrated according to 40 CFR 98.3(i); therefore, the accuracy 
standards in 40 CFR 98.3(i)(2) and (i)(3) will continue to apply to 
these meters.
    We are also amending 40 CFR 98.3(i) to clarify that the calibration 
accuracy specifications of 40 CFR 98.3(i)(2) and (i)(3) do not apply 
where the use of company records or the use of best available 
information is specified to quantify fuel usage or other parameters, 
nor do they apply to sources that use Part 75 methodologies to 
calculate CO2 mass emissions because the Part 75 quality-
assurance is sufficient. Although calibration accuracy requirements are 
not applicable for these data sources, per the requirements of 
98.3(g)(5), reporters are still required to explain in their monitoring 
plan the processes and methods used to collect the necessary data for 
the GHG calculations.
    We are also amending 40 CFR 98.3(i)(1) to clarify that the 
calibration accuracy specifications in 40 CFR 98.3(i)(2) and (i)(3) do 
not apply to other measurement devices (e.g., weighing devices) that 
provide data for the GHG emissions calculations. Rather, these devices 
must be calibrated to meet the accuracy requirements of the relevant 
subpart(s), or, in the absence of such requirements, meet appropriate, 
technology-based error-limits, such as industry consensus standards or 
manufacturer's accuracy specifications. Consistent with 40 CFR 
98.3(g)(5)(i)(C), the procedures and methods used to quality-assure the 
data from the measurement devices must be documented in the written 
monitoring plan.
    We are adding a new paragraph 40 CFR 98.3(i)(1)(ii) to clarify that 
flow meters and other measurement devices need to be installed and 
calibrated by the date on which data collection needs to begin, if a 
facility or supplier becomes subject to Part 98 after April 1, 2010.
    We are adding new paragraph 40 CFR 98.3(i)(1)(iii) to specify the 
frequency at which subsequent recalibrations of flow meters and other 
measurement devices must be performed. Recalibration must be at the 
frequency specified in each applicable subpart, or at the frequency 
recommended by the manufacturer or by an industry consensus standard 
practice, if no recalibration frequency was specified in an applicable 
subpart.
    We are adding new paragraph 40 CFR 98.3(i)(7) to specify the 
consequences of a failed flow meter calibration. Data become invalid 
prospectively, beginning at the hour of the failed calibration and 
continuing until a successful calibration is completed. Appropriate 
substitute data values must be used during the period of data 
invalidation.
    In 40 CFR 98.3(i)(2) and (3), we are adding absolute value signs to 
the numerators of Equations A-2 and A-3. These were inadvertently 
omitted in the October 30, 2009 Part 98.
    We are also amending 40 CFR 98.3(i)(3) to increase the alternative 
accuracy specification for orifice, nozzle, and venturi flow meters 
(i.e., the arithmetic sum of the three transmitter calibration errors 
(CE) at each calibration level) from 5.0 percent to 6.0 percent, since 
each transmitter is individually allowed an accuracy of 2.0 percent. We 
are also amending 40 CFR 98.3(i)(3) for orifice, nozzle, and venturi 
flow meters to account for cases where not all three transmitters for 
total pressure, differential pressure, and temperature are located in 
the vicinity of a flow meter's primary element. Instead of being 
required to install additional transmitters, reporters are, as 
described below, conditionally allowed to use assumed values for 
temperature and/or total pressure based on measurements of these 
parameters at remote locations. If only two of the three transmitters 
are installed and an assumed value is used for temperature or total 
pressure, the maximum allowable calibration error is 4.0 percent. If 
two assumed values are used and only the differential pressure 
transmitter is calibrated, the maximum allowable calibration error is 
2.0 percent.
    We are also amending 40 CFR 98.3(i)(3) to add five conditions that 
must be met in order for a source to use assumed values for temperature 
and/or total pressure at the flow meter location, based on measurements 
of these parameters at a remote location (or locations).
     The owner or operator must demonstrate that the remote 
readings, when corrected, are truly representative of the actual 
temperature and/or total pressure at the flow meter location, under all 
expected ambient conditions. Pressure and temperature surveys can be 
performed to determine the difference between the readings obtained 
with the remote transmitters and the actual conditions at the flow 
meter location.
     All temperature and/or total pressure measurements in the 
demonstration must be made with calibrated gauges, sensors, 
transmitters, or other appropriate measurement devices.
     The methods used for the demonstration, along with the 
data from the demonstration, supporting engineering calculations (if 
any), and the mathematical relationship(s) between the remote readings 
and the actual flow meter conditions derived from the demonstration 
data must be documented in the monitoring plan for the unit and 
maintained in a format suitable for auditing and inspection.
     The temperature and/or total pressure at the flow meter 
must be calculated on a daily basis from the remotely measured values, 
and the measured flow rates must then be corrected to standard 
conditions.
     The mathematical correlation(s) between the remote 
readings and actual flow meter conditions must be checked at least once 
a year, and any necessary adjustments must be made to the 
correlation(s) going forward.
    We are amending 40 CFR 98.3(i)(4) to include an additional 
exemption from the calibration requirements of 40 CFR 98.3(i) for flow 
meters that are used exclusively to measure the flow rates of fuels 
used for unit startup. For instance, a meter that is used only to 
measure the flow rate of startup fuel (e.g., natural gas) to a coal-
fired unit is exempted.
    Section 98.3(i)(4) is being further amended to clarify that gas 
billing meters are exempted from the monitoring plan and recordkeeping 
provisions of 40 CFR 98.3(g)(5)(i)(c), (g)(6) and (g)(7), which 
require, respectively, that a description of the methods used to 
quality-assure data from instruments used to provide data for the GHG 
emissions calculations be included in the written monitoring plan, that 
the results of all required certification and QA tests be kept, and 
that maintenance records be kept for those instruments.
    We are amending 40 CFR 98.3(i)(5) to clarify that flow meters that 
were already calibrated according to 40 CFR 98.3(i)(1) following a 
manufacturer's recommended calibration schedule or an industry 
consensus calibration schedule do not need to be recalibrated by the 
date specified in 40 CFR 98.3(i)(1) as long as the flow meter is still 
within the recommended calibration interval. This paragraph is also 
being amended to clarify that the deadline for successive calibrations 
will be according to the manufacturer's recommended calibration 
schedule or an industry consensus calibration schedule.
    We are amending 40 CFR 98.3(i)(6) to account for units and 
processes that operate continuously with infrequent outages and cannot 
meet the flow meter calibration deadline without disrupting

[[Page 79099]]

normal process operation. Part 98 allowed the owner or operator to 
postpone the initial calibration until the next scheduled maintenance 
outage. Although the rule allowed postponement of calibration, it did 
not specify how to report fuel consumption for the entire time period 
extending from January 1, 2010 until the next maintenance outage. We 
are amending 40 CFR 98.3(i)(6) to permit sources to use the best 
available data from company records to quantify fuel usage until the 
next scheduled maintenance outage. This revision addresses situations 
where the next scheduled outage is in 2011, or later.
    The major change since proposal is identified in the following 
list. The rationale for this and any other significant changes can be 
found in this preamble or the document, ``Response to Comments: 
Revision to Certain Provisions of the Mandatory Reporting of Greenhouse 
Gases Rule'' (see EPA-HQ-OAR-2008-0508).
     Removed the words ``ignition'' and ``ignition fuel'' from 
40 CFR 98.3(i)(4), so that only fuel flow meters that are used 
exclusively for startup are exempted from the calibration requirements 
of 40 CFR 98.3(i).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this topic. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: We received several comments relating to the proposed 
changes to the calibration accuracy requirements set in 40 CFR 98.3(i). 
Commenters expressed concern that removing the rule-wide 5 percent 
calibration accuracy requirement would compromise the rule's data 
quality. The commenters noted that a global calibration accuracy 
requirement is necessary to provide data that are accurate and 
comparable within and across industries. By dropping this requirement, 
the commenters believed small calibration errors will systematically 
produce major errors in reported data. For measuring devices other than 
flow meters they argued that it is not clear what an ``appropriate'' 
error range is, or what calibration standards a reporter would deem 
``applicable,'' and suggest that by stating calibration standards are 
``not limited to industry standards * * *, '' EPA is waiving 
calibration requirements for other measuring devices altogether. They 
acknowledge that there is a requirement to document the calibration 
procedure used in the monitoring plan, but they believe it is not 
enforceable and severely reduces transparency. The commenters contend 
that the use of different calibration methods and varying levels of 
accuracy would make it difficult to correctly interpret and compare the 
emissions data, and would render future policy development very 
difficult.
    In summary, commenters that were concerned about our removal of the 
blanket 5 percent calibration accuracy requirements asserted that EPA 
has a mandate to implement the rule and cannot promulgate any 
subsequent rule that would compromise the quality of the data reported. 
They further argue that it is arbitrary and capricious, in light of 
EPA's reporting mandate, to waive the calibration accuracy requirements 
for any flow meters. All such meters, they contend, should be required 
to meet these minimum accuracy requirements, with no exceptions.
    Response: We acknowledge the concerns of the commenters and agree 
that a high level of data quality is a valuable component of any 
environmental program. However, we believe the changes to the 
calibration accuracy requirements of 40 CFR 98.3(i) do not jeopardize 
the integrity of the reporting program nor compromise EPA's ability to 
use the data in the future to support climate policy development.
    As originally promulgated, 40 CFR 98.3(i) required that ``all 
measurement devices shall be calibrated to an accuracy of 5 percent.'' 
However, as promulgated, 40 CFR 98.3(i)(2) and (i)(3) only provided 
calibration procedures for flow meters. No specific procedures were 
provided for other measurement devices. As a result, measurement 
devices other than flow meters would necessarily be calibrated 
according to procedures specified in other subparts, industry consensus 
methods, or manufacturer specifications.
    In the ``Technical Support Document for Revision of Certain 
Provisions: Proposed Rule for Mandatory Reporting of Greenhouse 
Gases,'' dated July 8, 2010 (the TSD), vendor information on various 
types of measuring devices shows accuracy ranges of significantly less 
than 5 percent. Requiring the calibrations to be performed according to 
the accuracy specified by the device manufacturer, rather than 5 
percent, would likely actually increase the data accuracy of the rule. 
In addition, we recognize that other programs to which reporters may be 
subject impose calibration standards that will affect many of the 
instruments used for reporting under Part 98. For example, the tested 
accuracy of fuel flow meters and transmitter transducers used in the 
Acid Rain Program from 2005 through 2009 was well below 1 percent.
    As a result of the wide range of industries and measuring devices 
used within each industry, we have determined it is not practical to 
set a global calibration standard or method that would apply 
generically to every measurement device. Replacing the 5 percent 
requirement from the 2009 fine rule with manufacturer's specifications 
or industry specific standards will provide a higher level of data 
certainty across the rule while accommodating the wide variety of 
industries and equipment covered by the rule. We think it is highly 
unlikely that companies will choose to use arbitrary standards, as the 
procedures and methods used to quality-assure the measurement data must 
be listed in the facility or supplier's monitoring plan.
    The commenters correctly note that the calibration accuracy 
requirements of 40 CFR 98.3(i) have been removed where company records 
or best available information are used. Since promulgation, we have 
consistently affirmed that meters used to generate company records are 
not required to be calibrated according to 40 CFR 98.3(i). The purpose 
behind allowing the use of company records and best available 
information was to permit companies to use fuel billing receipts or 
other quality assured information they currently maintain. EPA 
authorized the use of company records to alleviate burden and did not 
intend for such data to be subject to additional calibration 
requirements, which would defeat the purpose of this flexibility.
    To be clear, we disagree with the commenter's assertions that we 
are ``waiving'' any calibration accuracy requirements or that certain 
types of flow meters would not have to be calibrated. All measurement 
technologies, except for the limited exceptions in 40 CFR 98.3(i) must 
meet calibration accuracy requirements. Further, most major emission 
sources should be covered by either the requirements of 40 CFR 98.38(i) 
or another program that provides a similarly, if not significantly 
more, stringent accuracy requirement. We have concluded that the 
amendments to the calibration accuracy requirements do not compromise 
our ability to implement successfully this reporting rule.

[[Page 79100]]

    Comment: One commenter pointed out an inconsistency in the proposed 
rule regarding the term ``ignition fuel.'' EPA proposed to amend 40 CFR 
98.3(i)(4) to exempt fuel flow meters that are used exclusively for 
startup and ignition fuel from the calibration requirements of 40 CFR 
98.3(i). However, EPA also proposed in 40 CFR 98.30(d) to exempt pilot 
lights from GHG emission reporting requirements. The commenter noted 
that pilot lights are essentially the same as ignitors, and the 
reference in 40 CFR 98.3(i)(4) to flow meters that measure ignition 
fuel appears to imply that GHG emissions from the combustion of 
ignition fuel must be reported.
    Response: The GHG emissions reporting exemption for pilot lights in 
40 CFR 98.30(d) refers to emissions from combustion of the fuel that 
supplies the pilot light. Therefore, in the final rule, we have removed 
the words ``ignition'' and ``ignition fuel'' from 40 CFR 98.3(i)(4). 
Paragraph (i)(4) now refers only to startup fuel, which is distinctly 
different from ignition fuel. For instance, at startup, a coal-fired 
boiler may burn natural gas for several hours at high heat input 
values, whereas a pilot light is a small flame that simply ignites or 
initiates combustion of the main fuel (e.g., fuel oil).

C. Subpart A--General Provisions: Reporting of Biogenic Emissions

1. Summary of Final Amendments and Major Changes Since Proposal
    Under the proposed amendments, EPA's goal was to reflect in 
regulatory language clarifications that have been issued stating that 
separate reporting of biogenic emissions for units subject to 40 CFR 
part 75 was optional. To clarify this optional reporting, we proposed 
to amend the data elements in subpart A (specifically 40 CFR 
98.3(c)(4)) and subpart C that currently require separate accounting 
and reporting of biogenic CO2 emissions so that it is 
optional for units that are subject to subpart D of this part or units 
that use the methods in part 75 to quantify CO2 mass 
emissions in accordance with 40 CFR 98.33(a)(5) (40 CFR part 75 units 
or ``part 75 units''). More specifically, to effect this clarification, 
we proposed to revise the reporting for all facilities such that all 
facilities would report combined non-biogenic and biogenic 
CO2, and all facilities, except those with ``part 75 
units,'' would still have been required to calculate and report 
biogenic CO2 emissions separately.
    We received numerous adverse comments on the proposed amendments 
that would re-structure 40 CFR 98.3(c)(4) and clarify that separate 
reporting of biogenic CO2 emissions was optional for ``part 
75 units''. Most commenters urged EPA to make separate reporting of 
biogenic emissions mandatory for all reporters. Many commenters also 
objected to the restructuring of 40 CFR 98.3(c)(4), which would have 
had all units reporting combined biogenic and non-biogenic 
CO2 emissions.
    Based on the comments received, we have decided to withdraw the 
proposed re-structuring of 40 CFR 98.3(c)(4). We have also reconsidered 
the optional reporting of biogenic CO2 emissions reporting 
for ``part 75 units''. In the final rule, a new paragraph, (c)(12), has 
been added to 40 CFR 98.3(c), which states that reporting biogenic 
CO2 is optional for ``part 75 units'' only for the first 
year of the program (i.e., for the 2010 reporting year). Thereafter, 
all ``part 75 units'' must separately report their biogenic 
CO2 emissions. We are allowing the optional biogenic 
CO2 emissions reporting for the 2010 reporting year in light 
of the 2009 final rule, as well as our previous statements and guidance 
on the issue. It is likely that at least some 40 CFR part 75 sources 
are following that policy guidance and have elected not to separately 
report biogenic CO2 emissions. It is equally likely that 
these sources have not been keeping the necessary records or performing 
the required emission testing to enable them to report these emissions 
for 2010.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Retaining the facility level reporting requirements from 
the 2009 final rule (74 FR 56373) in 40 CFR 98.3(c)(4) that requires 
reporting of CO2 emissions (excluding biogenic 
CO2) and separate reporting of biogenic emissions.
     Introducing new paragraph 40 CFR 98.3(c)(12) that allows 
facilities with 40 CFR part 75 units the option to include biogenic 
emissions in their facility totals for the 2010 reporting year only.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this topic. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: EPA received a large number of comments related to the 
proposed amendments to make separate reporting of biogenic 
CO2 emissions optional for units subject to 40 CFR part 75. 
The three main concerns, each raised by multiple commenters, were that 
(1) all reporters should be required to separately report biogenic 
CO2 emissions; (2) reporters should never be required to 
combine fossil CO2 and biogenic CO2; and, (3) if 
EPA nevertheless finalizes requirements allowing separate reporting of 
biogenic CO2 to be optional for units subject to 40 CFR part 
75, then EPA's implementation of the proposed revisions should be 
narrower in scope and not affect reporting requirements for all 
reporters.
    Regarding the first issue, some commenters argued that the 
requirements of the Acid Rain Program (ARP) should not constrain EPA in 
the GHG context and that all reporters under 40 CFR part 98 should be 
required to report biogenic CO2 emissions, regardless of the 
fact that such separate reporting is not a requirement in ARP. 
Commenters suggested that this is important for consistency across the 
GHG Reporting Program.
    Several commenters suggested that it is never appropriate to 
combine fossil CO2 and biogenic CO2 into a single 
reported value. Commenters noted that there is a distinction between 
fossil CO2 and biogenic CO2 and that in order to 
ensure transparency for future climate policy these two values should 
not be combined into a single reported emissions value. Further, they 
argued that EPA's proposed requirement for sources to combine fossil 
and biogenic emissions together in one total ignores the natural 
biomass carbon cycle and is counter to the principle of ``carbon 
neutrality,'' thereby overstating net CO2 entering the 
atmosphere.
    The commenters suggested that requiring separate reporting of 
biogenic CO2 is consistent with the Intergovernmental Panel 
on Climate Change and national, regional, and corporate GHG protocols 
and that EPA should not depart from this established accounting 
convention. These commenters also pointed out that EPA uses this same 
rationale for requiring separate reporting of biogenic CO2 
emissions in its own response to comments to the GHG Reporting Rule (74 
FR 56351). Further, the commenters articulated that separate reporting 
of biogenic emissions is necessary to

[[Page 79101]]

provide the public and policymakers with information on the extent of 
biomass combustion and the sectors of the economy where biomass fuels 
are used, which is information important for developing future climate 
policy. Several organizations also commented that an accurate, economy-
wide inventory of biogenic CO2 emissions is important 
because the evidence to date demonstrates that biomass is not 
inherently carbon neutral.
    Finally, commenters noted that if EPA nevertheless decides to 
finalize the rule allowing optional reporting of biogenic 
CO2 emissions for 40 CFR part 75 units, EPA should modify 
the proposed rule so the amendments affect only facilities with part 75 
units, and do not change the reporting requirements for all other 
reporters. Commenters were concerned that EPA's proposed change 
required all reporters to report total CO2 (including 
biogenic CO2 emissions), but only required facilities with 
non-part 75 units to report their biogenic emissions separately. 
Facilities with part 75 units would have the option to report 
separately biogenic CO2 from those units. The commenters 
suggested that if EPA chooses to finalize optional separate reporting 
for part 75 units, then EPA should revert to the reporting requirements 
in subpart A that were in the 2009 final rule (i.e., report 
CO2 excluding biogenic CO2) (74 FR 56379) for all 
other reporters and add a new paragraph specifically for facilities 
with part 75 units.
    Response: We appreciate the significant feedback generated by the 
proposed amendments designed to clarify that separate reporting of 
biogenic emissions was optional for units subject to 40 CFR part 75. We 
also recognize that many industry and environmental groups have 
significant interest in the treatment of biomass in GHG reports, and 
specifically in the accounting of biogenic CO2 emissions. 
Based on the significant feedback received, including comments received 
from facilities with 40 CFR part 75 units, as well as the fact that one 
of the fundamental goals of the Greenhouse Gas Reporting Program 
(GHGRP) is to collect data to support a range of potential future 
climate policies, we have reconsidered our position and decided to make 
the separate reporting of biogenic emissions mandatory for part 75 
units beginning in the 2011 reporting year. Separate reporting of 
biogenic CO2 emissions is optional for these units in the 
2010 reporting year.
    Per the requirements in the new paragraph 40 CFR 98.3(c)(12), 
facilities with one or more part 75 units must elect in the 2010 
reporting year whether to report biogenic CO2 emissions from 
40 CFR part 75 units separately, or report only total CO2 
emissions (including biogenic CO2) for the 40 CFR part 75 
units at their facility. Beginning in the 2011 reporting year, these 
facilities must separately report biogenic CO2 emissions for 
the entire facility per the requirements in 40 CFR 98.3(c)(4), like all 
other facilities.
    In addition, the final rule does not adopt the proposed 
restructuring of 40 CFR 98.3(c)(4) and leaves in place the facility-
level reporting requirements in 40 CFR 98.3(c)(4) for any facility in 
2010 or for future years. All other facilities, except those with part 
75 units, must, as finalized in the 2009 final rule, report 
CO2 (excluding biogenic CO2) and then report 
separately biogenic CO2 emissions. We would note that 
neither the original proposed amendments, nor the amendments finalized 
today, affect the fact that biogenic CO2 emissions are 
excluded from the applicability determination under 40 CFR 98.2.
    Commenters provided many reasons for supporting mandatory separate 
reporting of biogenic CO2 emissions from all facilities, 
including the increased transparency that such reporting brings. Some 
commenters supported the assumption of the carbon neutrality of biomass 
while others dispelled it, but both sides were united in their comments 
that it is important to understand the GHG emissions associated with 
biomass consumption. Our decision to also require separate reporting of 
biogenic emissions for units that use the methods in 40 CFR part 75 is 
founded solely on the principle that having data available at a more 
disaggregated level for a reporting program like this one improves 
transparency and better enables us and other stakeholders to use the 
data to evaluate future potential policy options, without prejudging 
what those policies might be. This decision is not based on any 
conclusions about ``carbon neutrality'' or the appropriateness of 
combining fossil CO2 and biogenic CO2 into a 
single value.\4\ Rather, EPA's approach preserves the flexibility for 
the Agency and for stakeholders to understand reported CO2 
emissions in multiple ways. Despite the benefits of having separate 
data with which to distinguish biogenic CO2 emissions, which 
we do not dispute, the 2009 final rule did not require this reporting 
for units subject to 40 CFR part 75. This is consistent with the 
Response to Comments document for subpart D of the final rule \5\ where 
it states ``It is EPA's intent that Acid Rain Program units will be 
able to continue to measure and report CO2 emissions as they 
do under the Acid Rain Program'' which did not require separate 
reporting of biogenic CO2. However, when we opened the 
relevant paragraphs to notice and comment, we received overwhelming 
support for making the separate reporting of biogenic CO2 
emissions mandatory, including from facilities with part 75 units. This 
support, in combination with the value of having the data for policy 
analysis, led us to reconsider our position and require separate 
reporting of biogenic CO2 emissions beginning in the 2011 
reporting year for the 40 CFR part 75 units. We decided to retain 
optional reporting for the 2010 reporting year due to the fact that we 
have provided guidance indicating that separate reporting was optional 
for these part 75 units, and therefore, some facilities may not have 
incorporated procedures into their monitoring plans or developed 
internal systems for collecting the necessary information to facilitate 
the biogenic CO2 emissions calculations.
---------------------------------------------------------------------------

    \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

[[Page 79102]]

substantive error exists. A substantive error is defined as one that 
impacts the quantity of GHG emissions reported or otherwise prevents 
the reported data from being validated or verified. This clarification 
is important because some errors are not significant (e.g., an error in 
the zip code) and do not impact emissions. Such non-significant errors 
will not obligate the owner or operator to resubmit the annual report.
    The owner or operator is required to resubmit the report within 45 
days of identifying the substantive error, or of being notified by the 
Administrator of a substantive error, unless the owner or operator 
provides information demonstrating that the previously submitted report 
does not contain the identified substantive error or that the 
identified error is not a substantive error. This amendment provides 
owners and operators the opportunity to demonstrate whether an error 
the Administrator has deemed to be a substantive error is not, in fact, 
a substantive error.
    Finally, we are also allowing owners and operators to request an 
extension of the 45-day resubmission deadline to address facility-
specific circumstances that arise in either correcting an error or 
determining whether or not an identified error is, in fact, a 
substantive error. Owners and operators are required to notify EPA by 
e-mail at least two business days prior to the end of the 45-day 
resubmission deadline if they seek an extension. An automatic 30-day 
extension will be granted if EPA does not respond to the extension 
request by the end of the 45-day period.
    We are including the opportunity to extend the period for 
resubmission in recognition that the data system is still under 
development and we do not yet fully know the full range of errors that 
will be identified and, therefore, the time required to address such 
errors. Verification and quality assurance and quality control checks 
are currently under development in the data system. Some flags that the 
data system might generate will not necessarily reflect substantive 
errors, but rather will be flags to alert the owner or operator to 
review the submission carefully to make sure the information provided 
is correct. On the other hand, some flags could identify substantive 
errors that affect the overall GHG emissions reported to EPA. Although 
we have concluded that it is important to provide facilities and 
suppliers the opportunity to extend this deadline, we believe that the 
45-day time period is a sufficient time period for the vast majority of 
facilities and suppliers.
    There have been no major changes from proposal regarding 
requirements for correction and resubmission of annual reports.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional comments received can be found in the document, ``Response 
to Comments: Revision to Certain Provisions of the Mandatory Reporting 
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter, representing several organizations, was 
concerned that the amended process for submitting revised annual GHG 
reports upon identification or notification by EPA of an error was too 
complex and would substantially slow down correction of reported 
errors. Generally, they asserted that the 45-day process that was in 
the final Part 98 (74 FR 56381) should be appropriate for most 
reporters, and to the extent there were any outliers, then EPA could 
use enforcement discretion for those specific reporters as opposed to 
changing the rule for all reporters. The commenter was further 
concerned that EPA proposed to allow reporters to extend their 
resubmission deadline in the event of a disagreement between EPA and 
the reporter, by at least 30 days. The commenters suggested that the 
process does not give EPA a clear method to dispute these points with 
operators, does not specify that EPA's view trumps the operator's 
opinion, and does not allow members of the public to argue that an 
error is, in fact, substantive, and must be corrected. They contended 
that the overall process could take months or years to correct errors, 
and the operators may still refuse to correct some of them. They argued 
this is a departure from the existing rule, and serves only to hinder 
what was a straightforward and effective process.
    Response: The process in these final rule amendments for submission 
of revised annual GHG reports to correct any substantive errors in 
these reports is reasonable and consistent with the purpose of the GHG 
Reporting Program. The purpose of these reporting requirements is to 
provide EPA with accurate and timely information on greenhouse gases in 
order to gain a better understanding of the relative emissions of 
specific industries and facilities, the factors that influence emission 
rates, and the actions that facilities could in the future, or already 
take, to reduce emissions. In light of this purpose, it is reasonable 
to focus an ongoing requirement to correct errors in an annual report 
on ``substantive errors,'' i.e., errors that affect emissions data 
quality, validation, or verification. Further, because this is a new 
program covering a wide variety of industries and processes, some of 
whom may not be familiar with GHG accounting and reporting, we have 
determined that under these circumstances it is reasonable to establish 
a procedure engaging owners and operators on whether the annual report 
actually contains identified ``substantive errors.''
    The commenters' claims that this procedure provides no ``clear 
method'' of determining what are substantive errors, may take ``months, 
perhaps years,'' may result in owners refusing to correct errors, and 
is unnecessary are unsupported and speculative. First, EPA has 
concluded that the definition of ``substantive error''--an error that 
impacts emissions data quality or otherwise prevents the data from 
being validated or verified--is reasonably clear and is consistent with 
the purposes of GHG emissions reporting. The commenter fails to show 
what is unclear about this definition, nor why it is unreasonable to 
focus corrections on substantive errors, versus insignificant ones that 
do not impact the accuracy of submitted information.
    Second, these final rule amendments set time limits for correction 
of substantive errors, i.e., correction through submission of a revised 
annual GHG report within 45 days of discovery (or notification by EPA 
of the errors) plus any ``reasonable extensions'' of time (including 
one automatic 30 day extension). The commenter fails to provide any 
basis for conflating these limited time frames into periods of many 
months or years. Further, because refusal by an owner or operator to 
correct substantive errors within the appropriate time frame would be a 
violation of the CAA and subject to significant civil penalties, the 
commenter has no basis for assuming that owners and operators would 
simply refuse to make the corrections.
    Third, the error correction process provides a standard process 
that is applicable to all owners and operators and that owners and 
operators and EPA can use to attempt to resolve issues concerning error 
correction. EPA has determined that this process will likely result in 
more efficient error correction and resolution of error correction 
issues by setting a limited time for contesting EPA's identification of 
substantive errors. In addition, EPA's provision of a standard process 
provides more certainty for owners and operators of an

[[Page 79103]]

opportunity to resolve issues than if EPA were simply to rely on 
enforcement discretion, as recommended by a commenter.
    The commenters also claimed the public will have no opportunity to 
argue that errors are substantive and should be corrected. However, 
this does not represent a change from the error correction process 
under the 2009 final rule. The amendments for resubmission of annual 
reports did not change public involvement in the resubmission process.
    The process in today's rule better focuses the resources of EPA, 
regulated industries and the public on those errors that are most 
relevant to generating accurate data.
    Comment: Several commenters requested that EPA provide a numerical 
determination of what is a ``substantive error.'' One commenter 
proposed a +/- 10 percent change in the reported GHG emissions value as 
a result of the identified error. Another commenter requested that EPA 
clarify that substantive errors are only those that exceed 1 percent to 
5 percent of the total annual CO2 equivalent emissions.
    One commenter requested that, in the final preamble, EPA clarify 
that any error not be considered substantive unless it exceeds 1 
percent to 5 percent of the total annual CO2 equivalent 
(``CO2e'') emission amount reported by an individual 
reporting facility. The commenter also requested that EPA modify the 
``contains one or more substantive errors'' language to allow the 
agency flexibility to investigate potential as well as documented 
errors.
    Response: The final rule defines substantive error as an error that 
impacts the quantity of GHG emissions reported or otherwise prevents 
the reported data from being validated or verified. EPA has determined 
that it is not appropriate to establish a threshold below which errors 
do not have to be corrected and resubmitted. EPA has determined that if 
an error in the GHG emissions estimate occurs, then that emissions 
error should be corrected and the annual GHG emissions report 
resubmitted. If a facility were to go through the process of 
identifying the estimate in GHG emissions, calculating what the GHG 
emissions total should have been, and then determining the percent 
difference between the original reported estimate and the revised 
estimate, then the reporter has all of the information necessary to 
report that revised estimate.

E. Subpart A--General Provisions: Information To Record for Missing 
Data Events

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.3(g)(4) by removing requirements to 
maintain records on the duration of a missing data event and actions 
taken to minimize future occurrences, while retaining the requirement 
that records be kept of the cause of each missing data event and the 
corrective actions taken. We are also clarifying that the records 
retained pursuant to 40 CFR 75.57(h) may be used to meet the 
recordkeeping requirements under Part 98 for the same missing data 
events.
    There have been no major changes from proposal regarding 
recordkeeping requirements for missing data events.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Some commenters stated that although EPA has justified 
this proposal by noting that 40 CFR part 75 does not require separate 
accounting of ``the duration of missing data events or * * * actions 
taken to minimize occurrence in the future,'' that alone is not 
sufficient justification for not including these requirements under the 
reporting program. The commenters asserted that part 75's requirements 
do not constrain EPA's obligations in the GHG context. The commenters 
wrote that reporting the duration of a missing data event cannot be 
considered overly burdensome because reporters that accurately use 
missing data procedures must know the duration of missing data events 
and so must be collecting this information regardless. Also, the 
commenters indicated that most facilities covered by the rule do not 
use CEMS, and thus, EPA should not change the ``minimize occurrence'' 
requirement for all reporters (CEMS users and non-CEMS users) because 
missing data events associated with the use of CEMS often have no clear 
measures to avoid similar occurrences in the future.
    Response: With respect to removal of the requirement to record the 
duration of a missing data event, EPA determined that the requirement 
in 40 CFR 98.3(c)(8) to report the total number of hours in the year 
that missing data are used for each data element provides sufficient 
information for purposes of the GHG Reporting Program. Although the 
``total number of hours'' will not provide information on the duration 
of each missing data event, EPA will know the total fraction of the 
year for which missing data are used for a particular data element. We 
have determined that this information provides EPA sufficient 
information on the extent of use of the missing data provisions for any 
given reporter.
    EPA also decided to remove recordkeeping requirements related to 
``actions taken to prevent or minimize occurrence in the future'' after 
considering the value of the potential loss of data as compared to the 
burden of compliance with the rule as written. As described below, we 
determined that sufficient information is available regarding missing 
data without requiring this additional information.
    First, reporters must report annual hours for each missing data 
element. Through this reported data, EPA can identify whether missing 
data is particularly prevalent for a given data element at a given 
facility. Second, records must be retained on the cause of the event 
and actions taken to restore malfunctioning equipment. If EPA elects to 
review these records, this information, along with reported information 
on the total hours of missing data for each data element, will suggest 
whether the source is taking action to prevent or minimize occurrence 
in the future. Therefore, we have determined that it is not necessary 
to collect information specifically on actions taken to prevent or 
minimize occurrence of missing data in the future.
    EPA acknowledges the point made by the commenters that most 
facilities subject to the rule do not use CEMS, and therefore, this 
fact can not be used as a justification for removing requirements 
related to minimizing future occurrence. Further, EPA agrees that 
information on duration would likely be collected when following the 
applicable missing data procedures. Nevertheless, based on the 
preceding discussion, EPA has concluded that sufficient data will be 
available on missing data through the required reporting of total 
number of hours in the year that missing data are used for each data 
element (per 40 CFR 98.3(c)(8)), and the recordkeeping requirements on 
cause of the event and actions taken to restore malfunctioning 
equipment. EPA has determined that requiring collection and retention 
of additional data on duration and actions taken to prevent or minimize 
occurrence

[[Page 79104]]

in the future is not necessary under the reporting program at this 
time.

F. Subpart A--General Provisions: Other Technical Corrections and 
Amendments

1. Summary of Final Amendments and Major Changes Since Proposal
    We are making several additional amendments to subpart A, as 
follows.
    We are making technical corrections to 40 CFR 98.3(c)(4)(i) through 
(c)(4)(iii) and (c)(4)(vi) to clarify that facilities must report GHG 
emissions from all applicable source categories, which includes general 
stationary fuel combustion, miscellaneous carbonates and any other 
source category covered by Part 98. This is consistent with the 
language in the 2009 final rule which required facilities to report 
emissions from all applicable source categories in subparts C through 
JJ. In a recent final rule (July 12, 2010, 75 FR 39736) we updated 40 
CFR 98.2 to remove the lists of source categories covered by the rule 
and replace the list with Tables, specifically Table A-3 and Table A-4 
of this chapter. This change was merely a reorganization and did not 
change applicability under the rule. The reformatting from lists to 
tables would enable EPA to add source categories in the future, and 
therefore add new subparts to the rule, without having to update all 
language referring to ``subparts C through JJ.'' In finalizing that 
rule, we made the appropriate changes to 40 CFR 98.2 indicating 
facilities must report GHG emissions from stationary fuel combustion 
sources, miscellaneous use of carbonates and all applicable source 
categories in Table A-3 and Table A-4. However, only the references to 
Table A-3 and Table A-4 were carried over to 40 CFR 98.3(c), which 
might suggest that facilities did not have to report emissions from 
general stationary combustion, because combustion is not in Table A-3 
or Table A-4. We are therefore amending 40 CFR 98.3(c) to clarify that 
facilities must also report emissions from general stationary 
combustion and miscellaneous use of carbonates.
    We are amending 40 CFR 98.3(c)(5)(i) to clarify that for the 
purposes of meeting the requirements of this paragraph, suppliers of 
industrial fluorinated GHGs only need to calculate and report GHG 
emissions in mtCO2e for those fluorinated GHGs that are 
listed in Table A-1. Suppliers of industrial fluorinated GHGs do not 
need to calculate and report GHG emissions in metric tons 
CO2 equivalents (mtCO2e) for fluorinated GHGs not 
listed in Table A-1. However, it is important to note that suppliers 
are still required to report these gases under 40 CFR 98.3(c)(5)(ii) 
(in metric tons of GHG).
    We are amending 40 CFR 98.3(d)(3) to correct the year in which 
reporters that submit an abbreviated report for 2010 must submit a full 
report, from 2011 to 2012. The full report submitted in 2012 will be 
for the 2011 reporting year.
    We are amending 40 CFR 98.3(f) to correct the cross-reference from 
``Sec.  98.3(c)(8)'' to ``Sec.  98.3(c)(9).'' We are amending 40 CFR 
98.3(g)(5)(iii) to correct a spelling error.
    We are amending the elements required with a certificate of 
representation under 40 CFR 98.4(i)(2) to include organization name 
(company affiliation-employer). We are also adding the same element to 
the delegation by designated representative and alternate designated 
representative under 40 CFR 98.4(m)(2). Part 98 and the amendments do 
not require the designated representative, alternate designated 
representative, or agent to be an employee of the reporting entity. If 
a designated representative further delegates their authority to an 
agent the agent gains access to all data for that facility or supplier. 
To underline the importance of granting access to the correct person, 
EPA requires the designated representative (or alternate) to confirm 
each agent delegation. Adding organization name to the certificate of 
representation and notice of delegation adds a level of assurance to 
the confirmation process.
    Finally, we are amending 40 CFR 98.6 (Definitions) and 40 CFR 98.7 
(What standardized methods are incorporated by reference into this 
part?). We are adding or changing several definitions to subpart A, 
which are needed to clarify terms used in other subparts of Part 98.
    We are amending the definitions of several terms in 40 CFR 98.6:
     Bulk natural gas liquid
     Distillate fuel oil
     Fossil fuel
     Fuel gas
     Municipal solid waste or MSW
     Natural gas
     Natural gas liquids, and
     Standard conditions
    Bulk natural gas liquid. We are amending the definitions of ``bulk 
natural gas liquid or NGL'' and ``natural gas liquids (NGL)'' by 
removing the phrase ``lease separators and field facilities'' for 
enhanced clarity. We have retained the words ``or other methods'' in 
both definitions because the list of separation processes in the 
definitions (absorption, condensation, adsorption) is not exhaustive, 
and other separation/extraction processes may be employed at some 
facilities. We do not wish to exclude the reporting of emissions 
associated with products separated/extracted by means not explicitly 
stated in the rule.
    Distillate fuel oil. We are expanding the definition of 
``Distillate fuel oil'' to include kerosene-type jet fuel.
    Fossil fuel. We are amending the definition of fossil fuel, as 
proposed, to read, ``Fossil fuel means natural gas, petroleum, coal, or 
any form of solid, liquid, or gaseous fuel derived from such material 
for purpose of creating useful heat.'' This amendment finalizes the 
same definition of fossil fuel that was originally proposed in April 
2009 (74 FR 16621), but was subsequently amended in the final Part 98 
(74 FR 56387). The change is not intended to have any impact on 
coverage of greenhouse gases under the GHG Reporting Program.
    Fuel gas. We are amending the definition of fuel gas to clarify 
that it includes only gas generated at refineries or petrochemical 
processes subject to subpart X and to remove the phrase ``or similar 
industrial process unit.'' For a fuel explanation of this final change, 
please see the Comments and Response discussion under Section II.G of 
this preamble.
    Municipal solid waste. We are amending the definition of municipal 
solid waste to be similar to, but not exactly the same as, the 
definition of ``municipal solid waste'' in subpart Ea of the NSPS 
regulations (40 CFR 60.51a). The amended definition explains what is 
meant by ``household waste,'' ``commercial/retail waste,'' and 
``institutional waste.'' Household, commercial/retail, and 
institutional wastes include yard waste, refuse-derived fuel, and motor 
vehicle maintenance materials. Insofar as there is separate collection, 
processing and disposal of industrial source waste streams consisting 
of used oil, wood pallets, construction, renovation, and demolition 
wastes (which includes, but is not limited to, railroad ties and 
telephone poles), paper, clean wood, plastics, industrial process or 
manufacturing wastes, medical waste, motor vehicle parts or vehicle 
fluff, or used tires that do not contain hazardous waste identified or 
listed under 42 U.S.C. 6921, such wastes are not municipal solid waste. 
However, such wastes qualify as municipal solid waste where they are 
collected with other municipal solid waste or are otherwise combined 
with other municipal solid waste for processing and/or disposal.
    Natural gas. We are finalizing the definition of natural gas to 
remove any specifications regarding Btu value or methane content. The 
final definition

[[Page 79105]]

reads, ``Natural gas means a naturally occurring mixture of hydrocarbon 
and non-hydrocarbon gases found in geologic formations beneath the 
earth's surface, of which the principal constituent is methane. Natural 
gas may be field quality or pipeline quality.'' For a full explanation 
of this final change, please see the Comments and Response discussion 
under this section of the preamble.
    Standard conditions. For consistency across the rule, and to 
reflect typical operating procedures at various types of industries 
covered by 40 CFR part 98, we are amending the definition of standard 
conditions to mean either 60 or 68 degrees Fahrenheit and 14.7 pounds 
per square inch absolute.
    We are adding definitions of the following terms to 40 CFR 98.6 to 
address the large number of questions received requesting clarification 
on the meaning of these terms:
     Agricultural by-products,
     Primary fuel,
     Solid by-products,
     Used oil, and
     Wood residuals.
    We received no comments on the definitions of ``Agricultural by-
products,'' ``Primary fuel,'' and ``Solid by-products.'' Therefore, 
these definitions have been finalized, as proposed. For the purposes of 
Part 98, ``Agricultural by-products'' includes the parts of crops that 
are not ordinarily used for food (e.g., corn straw, peanut shells, 
pomace, etc.). ``Primary fuel'' is defined as the fuel that contributes 
the greatest percentage of the annual heat input to a combustion unit. 
``Solid by-products'' includes plant matter such as vegetable waste, 
animal materials/wastes, and other solid biomass, except for wood, wood 
waste and sulphite lyes (black liquor).
    We proposed to add the term ``waste oil'' to Table C-1 but we 
received comment use of the term ``waste oil'' could result in used oil 
being classified as hazardous waste. We have therefore changed the term 
to ``used oil.'' Used oil has been added to Table C-1 as a new fuel 
type, and is defined as a petroleum-derived or synthetically-derived 
oil whose physical properties have changed as a result of handling or 
use, such that the oil cannot be used for its original purpose. Used 
oil consists primarily of automotive oils (e.g., used motor oil, 
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial 
oils (e.g., industrial engine oils, metalworking oils, process oils, 
industrial grease, etc). For a full explanation of this final change, 
please see the Comments and Response discussion under this section of 
the preamble.
    The definition of ``wood residuals'' has been finalized similar to 
the proposal, but EPA has also specifically included trim, sander dust, 
and sawdust from wood products manufacturing (including resinated wood 
product residuals) in the final definition.
    We are amending 40 CFR 98.7 (Incorporation by reference) to 
accommodate changes in the standard methods that are allowed by other 
subparts of Part 98. The rationale for any additions or deletions of 
methods in a particular subpart is discussed in the relevant subpart.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Not adopting the proposed amendments to 40 CFR 98.3(c)(1) 
to report a facility or supplier ID number.
     Clarifying the definition of municipal solid waste. 
Clarifying that separate collection, processing and disposal of 
industrial source waste streams consisting of used oil, wood pallets, 
construction, renovation, and demolition wastes, clean wood, industrial 
process or manufacturing wastes, medical waste, motor vehicle parts or 
vehicle fluff, or used tires that do not contain hazardous waste 
identified or listed under 42 U.S.C. 6921, are not municipal solid 
waste. However, such wastes qualify as municipal solid waste where they 
are collected with other municipal solid waste or are otherwise 
combined with other municipal solid waste for processing and/or 
disposal.
     Finalizing the definition of natural gas to remove any 
specifications regarding Btu value or methane content.
     Amending the definition of standard conditions to provide 
two alternatives.
     Replacing the term ``waste oil'' with ``used oil.''
     Amending the definition of ``wood residuals'' to include 
trim, sander dust and sawdust from wood products manufacturing, 
including resinated wood product residuals.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional comments received can be found in the document, ``Response 
to Comments: Revision to Certain Provisions of the Mandatory Reporting 
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Several commenters objected to the proposed definition of 
municipal solid waste or MSW. One commenter in particular pointed to 
the regulatory history of the definition in 40 CFR 60, subpart Ea, 
indicating that some of the materials excluded by the proposed 
definition under 40 CFR part 98 are often included in MSW. According to 
the commenter, some of the exclusions in subpart Ea were added to the 
definition to provide an exemption to certain sources that combust 
materials such as used oil or wood pellets separately. By excluding 
materials often considered to be part of MSW, the commenter expressed 
concern that the proposed definition of MSW in 40 CFR part 98 might 
force some municipal waste combustors who considered themselves to be 
combusting MSW and would therefore otherwise be allowed to use Tier 2, 
to not meet the definition of MSW under 40 CFR part 98 and therefore 
have to install CEMS and use the Tier 4 methodology to quantify 
CO2 emissions.
    Response: EPA proposed to amend the definition of MSW to provide 
greater clarity on what is included as MSW. Several questions were 
raised during implementation of the GHGRP because the definition of MSW 
in the final Part 98 rule was too generic and did not define terms such 
as ``house, commercial/retail, and institutional waste.'' To clarify 
the definition, EPA sought to use another EPA definition of the term, 
and did not intend to push some municipal waste combustors into a 
higher tier. Based on supplementary information provided by the 
commenter (please refer to EPA-HQ-OAR-2008-0508), the final definition 
of MSW includes materials that should not have been excluded, and 
clarifies that when these materials are extracted from MSW and 
combusted separately, they are not classified as MSW.
    Comment: Two commenters on the definition of ``Natural gas'' 
pointed out that not all natural gas (particularly field gas) can 
consistently meet the proposed specifications. The commenters were 
concerned that EPA's proposal to include specifications that natural 
gas must be composed of at least 70 percent methane by volume or have a 
high heat value between 910 and 1,150 Btu per standard cubic foot would 
be problematic for subpart W, when finalized, because these ranges 
could exclude field gas.
    Response: The definition of natural gas in the final rule caused 
significant confusion because it included not only

[[Page 79106]]

naturally occurring mixtures of hydrocarbons, but also fuels such as 
field gas, process gas and fuel gas. We proposed to change the 
definition of ``natural gas'' to include specifications on the methane 
content and a range of Btu values that must be achieved before the gas 
can be referred to as ``natural gas.'' Clarifying the definition of 
natural gas is important, particularly given that it is a fuel in Table 
C-1 and if an owner or operator burns a fuel outside the range of the 
specifications, then they could be pushed into Tier 3 if any unit has a 
maximum rated heat input capacity greater than 250 million British 
thermal units per hour (mmBtu/hr).
    Based on the comments received we have decided to finalize the 
definition of natural gas without any specifications regarding minimum 
or maximum Btu values or a minimum methane content. Although the 
commenters were concerned specifically about the implications of the 
definition of natural gas for the oil and gas industry, where the fuels 
combusted can often fall outside the listed specifications thereby 
potentially forcing them into Tier 3, these concerns did not weigh 
heavily into our determination to remove the specifications. Rather, we 
considered that most facilities subject to subpart C only typically 
burn natural gas within the proposed specifications. For these 
facilities, it was not necessary to list specifications, because most 
would already fall into the specifications we had proposed. Further, we 
were concerned that by introducing specifications to the definition of 
natural gas we could inadvertently push a small number of owners or 
operators into Tier 3, if they have been combusting a fuel outside that 
range.
    It is true that facilities in the oil and gas industry are more 
likely to combust gas outside the listed specifications (e.g., field 
gas). However, facilities in the oil and gas industry will be subject 
to the reporting requirements under subpart W beginning with the 2011 
reporting year. The concerns raised by the commenters with respect to 
calculating combustion-related emissions from natural gas were 
explicitly considered within the context of subpart W.
    Comment: One commenter brought to our attention that the term 
``used oil'' is more appropriate than ``waste oil.'' According to the 
commenter, the term ``waste oil'' could result in used oil being 
classified as hazardous waste rather than traditional fuel, and might 
bring the Resource Conservation and Recovery Act program into view.
    Response: Without indicating whether we agree with the commenter's 
concern or not, we have decided to avoid potential complication or 
confusion and have replaced the term ``waste oil'' with ``used oil'' in 
the final rule.
    Comment: We received two comments on the definition of ``wood 
residuals.'' Both commenters requested that the definition explicitly 
include trim, sander dust and sawdust from wood products manufacturing, 
including resinated wood product residuals because they were concerned 
that the proposed definition was too broad and it was not clear if 
these products were included.
    Response: We agree with the commenter. We did not intend to exclude 
these types of products from the definition of wood residuals and agree 
that these terms should be included in the definition in order to 
provide clarity.
    Comment: Several commenters expressed concern about EPA's proposal 
to add a reporting requirement for facility ID. Two commenters 
suggested that EPA provide a separate public comment period for 
including a facility ID reporting requirement, and in that proposal, 
include a specific mechanism for assigning the ID numbers.
    Response: Although we maintain that assigning a unique ID number to 
each facility or supplier, for administrative purposes, is important to 
facilitate program implementation, we have decided it is not necessary 
to finalize this reporting requirement at this time, given the concerns 
raised by the commenters. We will consider this issue further for 
future rulemakings. Note that we are still finalizing the technical 
clarification in 40 CFR 98.3(c)(1) that it is the physical street 
address of the facility or supplier that must be reported.

G. Subpart C--General Stationary Fuel Combustion

1. Summary of Final Amendments and Major Changes Since Proposal
    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart C for general stationary fuel 
combustion. The issues being addressed by the final amendments include 
the following:
     Definition of the source category.
     GHGs to report.
     Calculating GHG emissions.
     Natural gas consumption expressed in therms.
     Use of Equation C-2b.
     Categories of gaseous fuels.
     Use of mass-based gas flow meters.
     Site-specific stack gas moisture content values.
     Determining emissions from an exhaust stream diverted from 
a CEMS monitored stack.
     Biomass combustion in Part 75 units using the 
CO2 calculation methodologies in 40 CFR 98.33(a)(5).
     Use of Tier 3.
     Tier 4 monitoring threshold for units that combust MSW.
     Applicability of Tier 4 to common stack configurations.
     Starting dates for the use of Tier 4.
     Methane (CH4) and nitrous oxide 
(N2O) calculations.
     CO2 emissions from sorbent.
     Biogenic CO2 emissions from biomass combustion.
     Fuel sampling for coal and fuel oil.
     Tier 3 sampling frequency for gaseous fuels.
     GHG emissions from blended fuel combustion.
     Use of consensus standard methods.
     CO2 monitor span values.
     CEMS data validation.
     Use of American Society of Testing and Materials (ASTM) 
Methods D7459-08 and D6866-08.
     Electronic data reporting and recordkeeping.
     Common stack reporting option.
     Common fuel supply pipe reporting option.
     Table C-1 default HHV and CO2 emission factors.
     Table C-2 default CH4 and N2O 
emission factors.
    Definition of the source category. We are adding new paragraph 40 
CFR 98.30(d), clarifying that the GHG emissions from a pilot light need 
not be included in the emissions totals for the facility. A pilot light 
is a small auxiliary flame that simply ignites the burner of a 
combustion process in a boiler, turbine, or other fuel combustion 
device, and is not used to produce electricity or steam, or provide 
useful energy to an industrial process, or reduce waste by removing 
combustible matter.
    GHGs to report. We are amending 40 CFR 98.32 to clarify that 
CO2, CH4, and N2O mass emissions from 
a stationary fuel combustion unit do not need to be reported under 
subpart C if such an exclusion is indicated elsewhere in subpart C.
    Calculating GHG emissions. We are amending the introductory text of 
40 CFR 98.33(a) to provide additional detail and clarify who may (or 
must) use the calculation methods in the subsequent paragraphs to 
calculate and report GHG emissions. Specifically, we are amending this 
text to point out that certain sources may use the methods in 40 CFR 
part 75 to calculate CO2 emissions, if they are already 
using part

[[Page 79107]]

75 to report heat input data year-round under another CAA program. The 
introductory text of 40 CFR 98.33(a) is also being amended to clarify 
the reporting of CO2 emissions from biomass combustion when 
a unit combusts both biomass and fossil fuels.
    Natural gas consumption expressed in therms. We are amending 40 CFR 
98.33(a)(1) by adding two new equations to Tier 1. When natural gas 
consumption is expressed in therms, Equation C-1a enables sources to 
calculate CO2 mass emissions directly from the information 
on the billing records, without having to request or obtain additional 
data from the fuel suppliers. We are also allowing Equation C-1a to be 
used for units of any size when the fuel usage information on natural 
gas billing records is expressed in units of therms. A new paragraph, 
(b)(1)(v), has been added to 40 CFR 98.33 to reflect this. Section 
98.36(e)(2)(i) is also amended to allow gaseous fuel consumption to be 
reported in units of therms.
    Equation C-1b has been added to Tier 1 to accommodate situations in 
which the fuel usage information on gas billing records is expressed in 
mmBtu. We are also adding two new equations to 40 CFR 98.33(c), i.e., 
Equations C-8a and C-8b, for calculating CH4 and 
N2O emissions when the fuel usage information on natural gas 
billing records is in units of therms or mmBtu.
    Use of Equation C-2b. We are amending 40 CFR 98.33(a)(2)(ii), to 
require calculation of a weighted HHV, using Equation C-2b, only for 
individual Tier 2 units with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr, and for groups of units that 
contain at least one unit of that size. For Tier 2 units smaller than 
100 mmBtu/hr and for aggregated groups of Tier 2 units under 40 CFR 
98.36(c)(1) in which all units in the group are smaller than 100 mmBtu/
hr, we are allowing reporters to use either an annual arithmetic 
average HHV or an annual fuel-weighted average HHV in Equation C-2a.
    Categories of gaseous fuels. We have revised 40 CFR 
98.34(a)(2)(iii) by replacing the term ``fossil fuel-derived gaseous 
fuels'' with a more inclusive term, i.e., ``gaseous fuels other than 
natural gas.'' Corresponding changes to Table C-1 were also made for 
consistency, placing blast furnace gas, coke oven gas, fuel gas, and 
propane in a new category, ``Other fuels (gaseous).''
    Use of mass-based gas flow meters. The Tier 3 CO2 
emissions calculation methodology in 40 CFR 98.33(a)(3) allows 
reporters to use flow meters that measure mass flow rates of liquid 
fuels to quantify fuel consumption, provided that they (the reporters) 
determine the density of the fuel and convert the measured mass of fuel 
to units of volume (i.e., gallons), for use in Equation C-4. In 
response to a number of requests, we are amending 40 CFR 
98.33(a)(3)(iv), to conditionally allow reporters to use flow meters 
that measure mass flow rates of gaseous fuels for Tier 3 applications, 
as well as for liquid fuels. A reporter wanting to use this option will 
have to measure the density of the gaseous fuel, either with a 
calibrated density meter or by using a consensus standard method or 
standard industry practice, in order to convert the measured mass of 
fuel to units of standard cubic feet, for use in Equation C-5.
    Site-specific stack gas moisture content values. We are amending 40 
CFR 98.33(a)(4)(iii) to allow the use of site-specific moisture 
constants under the Tier 4 methodology. The site-specific moisture 
default value(s) must represent the fuel(s) or fuel blends that are 
combusted in the unit during normal, stable operation, and must account 
for any distinct difference(s) in stack gas moisture content associated 
with different process operating conditions. Generally, for each site-
specific default moisture percentage, at least nine runs are required 
using EPA Method 4--Determination of Moisture Content In Stack Gases 
(40 CFR part 60, appendix A-3). Each site-specific default moisture 
value would be calculated by taking the arithmetic average of the 
Method 4 runs. Moisture data from the relative accuracy test audit 
(RATA) of a CEMS could be used for this purpose. The final rule does 
allow the site-specific moisture default values to be based on fewer 
than nine Method 4 runs in cases where moisture data from the RATA of a 
CEMS are used to derive the default value and the applicable regulation 
allows a single moisture run to represent two or more RATA runs.
    Each site-specific moisture default value must be updated at least 
annually and whenever the reporter determines the current value is non-
representative due to changes in unit or process operation. The updated 
moisture value must be used in the subsequent CO2 emissions 
calculations.
    Determining emissions from an exhaust stream diverted from a CEMS 
monitored stack. We are finalizing amendments to 40 CFR 98.33(a)(4) by 
adding a new paragraph, (a)(4)(viii), to address the determination of 
CO2 mass emissions from a unit subject to the Tier 4 
calculation methodology when a portion of the flue gases generated by 
the unit exhaust through a stack that is not equipped with a CEMS to 
measure CO2 emissions (herein referred to as an 
``unmonitored stack''). The final amendments require annual emission 
testing of a diverted gas stream to be performed at a set point that 
best represents normal operation, using EPA Methods 2 and 3A and (if 
moisture correction is necessary) Method 4. A CO2 mass 
emission rate is calculated from the test results. If, over time, flow 
rate of the diverted stream varies little from the tested flow rate, 
then the annual CO2 mass emissions for the diverted stream 
(which must be added to the CO2 mass emissions measured at 
the main stack) are determined simply by multiplying the CO2 
mass emission rate from the emission testing by the number of operating 
hours in which a portion of the flue gas was diverted from the main 
flue gas exhaust system. However, if the flow rate of the diverted 
stream varies significantly over the reporting year, the owner or 
operator must either perform additional stack testing or use the best 
available information (e.g., fan settings and damper positions) and 
engineering judgment to estimate the CO2 mass emission rate 
at a minimum of two additional set points, to represent the variation 
across the normal operating range. Then, the most appropriate 
CO2 mass emission rate must be applied to each hour in which 
a portion of flue gas is diverted from the main exhaust system. The 
procedures used to determine the annual CO2 mass emissions 
for the diverted stream must be documented in the GHG monitoring plan.
    Biomass combustion in Part 75 units using the CO2 
calculation methodologies in 40 CFR 98.33(a)(5). We are amending 40 CFR 
98.33(a)(5)(iii)(D) to redesignate it as 40 CFR 98.33(a)(5)(iv). This 
is to correct a paragraph numbering error in subpart C, because this 
paragraph applies to all of 40 CFR 98.33(a)(5) and not just to 40 CFR 
98.33(a)(5)(iii).
    We had proposed to amend 40 CFR 98.3(c) in subpart A and 40 CFR 
98.33(a)(5) to clarify that the separate reporting of biogenic 
CO2 is optional for units that are not subject to the Acid 
Rain Program, but are using 40 CFR part 75 methodologies to calculate 
CO2 mass emissions, as described in 40 CFR 98.33(a)(5)(i) 
through (a)(5)(iii). After considering the comments received on this 
proposal and other information (see EPA-HQ-OAR-2008-0508), however, we 
are finalizing language which makes it clear that reporting of biogenic 
CO2 emissions from these units is optional for reporting 
year 2010, and mandatory

[[Page 79108]]

thereafter. Please see the discussion in Section II.C of this preamble 
regarding separate reporting of biogenic emissions for units subject to 
40 CFR part 75.
    Use of Tier 3. We are amending 40 CFR 98.33(b)(3)(iii) to clarify 
that the paragraph applies also to common pipe configurations where at 
least one unit served by the common pipe has a heat input capacity 
greater than 250 mmBtu/hr.
    We are also adding a new paragraph, (b)(3)(iv), to 40 CFR 98.33, 
requiring Tier 3 to be used when specified in another subpart of Part 
98, regardless of unit size. For example, subpart Y requires certain 
units that combust fuel gas to use Equation C-5 in subpart C (which is 
the Tier 3 equation for gaseous fuel combustion) to calculate 
CO2 mass emissions, without regard to unit size.
    Tier 4 monitoring threshold for units that combust MSW. We are 
amending 40 CFR 98.33(b)(4)(ii)(A) to change the Tier 4 monitoring 
threshold from 250 tons MSW per day to 600 tons MSW per day, based on 
analysis that this value is approximately equivalent to the 250 mmBtu/
hr Tier 4 heat input threshold for other large stationary combustion 
units. Units less than 600 tons MSW per day that do not meet the 
requirements in 40 CFR 98.33(b)(4)(iii) are allowed to use Tier 2 to 
calculate CO2 mass emissions (specifically, Equation C-2c).
    Applicability of Tier 4 to common stack configurations. We are 
amending 40 CFR 98.33(b)(4) by adding provisions to clarify how the 
Tier 4 criteria apply to common stack configurations. Paragraph 
(b)(4)(i) is expanded to include monitored common stack configurations 
that consist of stationary combustion units, process units, or both 
types of units. A new paragraph, (b)(4)(iv) is also added describing 
the following three distinct common stack configurations to which Tier 
4 might apply.
    The first, most basic configuration is one in which the combined 
effluent gas streams from two or more stationary fuel combustion units 
are vented through a monitored common stack (or duct). In this case, 
Tier 4 applies if the following conditions are met:
     There is at least one large unit in the configuration that 
has a maximum rated heat input capacity greater than 250 mmBtu/hr or an 
input capacity greater than 600 tons/day of MSW (as applicable).
     At least one large combustion unit in the configuration 
meets the conditions of 40 CFR 98.33(b)(4)(ii)(A) through 
(b)(4)(ii)(C).
     The CEMS installed at the common stack (or duct) meets all 
of the requirements of 40 CFR 98.33 (b)(4)(ii)(D) through 
(b)(4)(ii)(F).
    Tier 4 also applies when all of the combustion units in the 
configuration are small (not greater than 250 mmBtu/hr or 600 tons/day 
of MSW), if at least one of the units meets the conditions of 40 CFR 
98.33(b)(4)(iii).
    The second configuration is one in which the combined effluent gas 
streams from a stationary combustion unit and a process or 
manufacturing unit are vented through a common stack or duct. Many 
subparts of Part 98 describe this situation (see subparts F, G, K, Q, 
Z, BB, EE, and GG). In this case, the use of Tier 4 is required if the 
stationary combustion unit and the monitors installed at the common 
stack or duct meet the applicability criteria of 40 CFR 98.33(b)(4)(ii) 
or 98.33(b)(4)(iii). If multiple stationary combustion units and a 
process unit (or units) are vented through a common stack or duct, Tier 
4 is required if at least one of the combustion units and the monitors 
installed at the common stack or duct meet the conditions of 40 CFR 
98.33(b)(4)(ii) or 98.33(b)(4)(iii).
    The third configuration is one in which the combined effluent 
streams from two or more process or manufacturing units are vented 
through a common stack or duct. In this case, if any of these units is 
required to use Tier 4 under an applicable subpart of Part 98, the 
owner or operator can either monitor the CO2 mass emissions 
at the Tier 4 unit(s) before the effluent streams are combined 
together, or monitor the combined CO2 mass emissions from 
all units at the common stack or duct. However, if it is not feasible 
to monitor the individual units, the combined CO2 mass 
emissions will have to be monitored at the common stack or duct, using 
Tier 4.
    Starting dates for the use of Tier 4. In the October 30, 2009 final 
rule, 40 CFR 98.33(b)(5) of subpart C states that units that are 
required to use the Tier 4 methodology must begin using it on January 
1, 2010 if all required CEMS are in place. Otherwise, use of Tier 4 
begins on January 1, 2011, and Tier 2 or Tier 3 may be used to report 
CO2 mass emissions in 2010. We are amending 40 CFR 
98.33(b)(5) to clarify that sources can begin monitoring CO2 
emissions data prior to January 1, 2011 from CEMS that successfully 
complete certification testing in 2010. Note that changes in 
methodology during a reporting year are allowed by Part 98, and must be 
documented in the annual GHG emissions report (see 40 CFR 98.3(c)(6)).
    This revision will allow sources to discontinue using Tier 2 or 3 
and begin reporting their 2010 emissions under Tier 4 as of the date on 
which all required certification tests are passed. Data recorded during 
the certification test period for a CEMS can also be used for Part 98 
reporting, provided that: All required certification tests are passed 
in sequence, with no test failures; and no unscheduled maintenance or 
repair of the CEMS is required during the test period.
    We are also amending 40 CFR 98.33(b)(5) by adding a new paragraph, 
(b)(5)(iii), to address situations where the owner or operator of an 
affected unit that has been using Tier 1, 2, or 3 to calculate 
CO2 mass emissions makes a change that triggers Tier 4 
applicability by changing: The primary fuel, the manner of unit 
operation, or the installed continuous monitoring equipment. In such 
cases, the owner or operator will be required to begin using Tier 4 no 
later than 180 days from the date on which the change is implemented. 
This allows adequate time for the owner or operator to obtain and/or 
certify any of the required Tier 4 continuous monitors.
    Methane and nitrous oxide calculations. Today's amendments remove 
the term ``normal operation'' from 40 CFR 98.33(c)(4)(i) and 
(c)(4)(ii). Therefore, calculation of CH4 and N2O 
emissions is simply required for each Table C-2 fuel combusted in the 
unit during the reporting year.
    We are also further amending 40 CFR 98.33(c)(4)(ii), to allow 
additional reporting flexibility for certain units that combust more 
than one type of fuel; specifically, for units that report heat input 
data to EPA year-round using part 75 CEMS. Under the final amendments 
to 40 CFR 98.33(c)(4)(ii), 40 CFR part 75 units that use the worst-case 
F-factor reporting option can attribute 100 percent of the unit's 
annual heat input to the fuel with the highest F-factor, as though it 
were the only fuel combusted during the report year.
    For Tier 4 units, the requirement to use the best available 
information to determine the annual heat input from each type of fuel 
is being retained in 40 CFR 98.33(c)(4)(i), but we are also now 
allowing it under 40 CFR 98.33(c)(4)(ii)(D) as an alternative for part 
75 units, in cases where fuel-specific heat input values cannot be 
determined solely from the part 75 electronic data reports.
    Carbon dioxide emissions from sorbent. We are amending 40 CFR 
98.33(d) to make it more generally applicable to different types of 
CO2-producing sorbents. The term ``R'' is redefined as the 
number of moles of CO2 released upon capture of one mole of 
acid gas. When the sorbent is CaCO3, the

[[Page 79109]]

value of R is 1.00. For other CO2-producing sorbents, a 
specific value of R is determined by the reporting facility from the 
chemical formula of the sorbent and the chemical reaction with the acid 
gas species that is being removed.
    Biogenic CO2 emissions from biomass combustion.
    The title and introductory text of 40 CFR 98.33(e) are being 
amended to more precisely define the requirements for reporting 
biogenic CO2 emissions. In general, biogenic CO2 
emissions reporting is required only for the combustion of the biomass 
fuels listed in Table C-1 and for municipal solid waste (which consists 
partly of biomass and partly of fossil fuel derivatives).
    We are also amending 40 CFR 98.33(e) to describe three cases in 
which reporters may not need to report biogenic CO2 
emissions separate from total CO2 emissions, for units that 
combust biomass:
    1. If a biomass fuel is not listed in Table C-1 and is combusted in 
a unit that is not required to use Tier 4, a reporter is not required 
to separately report the biogenic CO2 emissions from 
combustion of that fuel unless:

--The fuel is combusted in a large unit (greater than 250 mmBtu/hr heat 
input capacity).
--The biomass fuel accounts for 10 percent or more of the annual heat 
input to the unit.

    In that case, according to 40 CFR 98.33(b)(3)(iii), Tier 3 must be 
used to determine the carbon content of the biomass fuel and to 
calculate the biogenic CO2 emissions.
    2. If a unit is subject to subpart C or D and uses the 
CO2 mass emissions calculation methodologies in 40 CFR part 
75 to satisfy the Part 98 reporting requirements, the reporter has the 
option to report biogenic CO2 emissions for the 2010 
reporting year, but is required to report them thereafter.
    3. For the combustion of tires, which are also partly biogenic 
(typically about 20 percent biomass, for car and truck tires), the 
reporter has the option, but not the requirement, to separately report 
the biogenic CO2 emissions, by following the applicable 
provisions in 40 CFR 98.33(e).
    No comments were received on the proposal to make biogenic 
CO2 emissions reporting optional for the combustion of 
tires, and the proposal has been finalized without modification. 
However, tire-derived fuel has a biomass component, and perhaps it 
should be treated in the same manner as MSW, which is also partly 
biogenic. A number of units that are subject to Part 98 combust tires 
as the primary fuel or as a secondary fuel. Therefore, we are 
considering whether these units should be required to account for their 
biogenic CO2 emissions. However, before making this 
mandatory we intend to open it to notice and comment in a future 
rulemaking.
    We are amending 40 CFR 98.33(e)(1) by removing the restriction 
against using Tier 1 to calculate biogenic CO2 emissions on 
units that use CEMS to measure the total CO2 mass emissions. 
However, the use of Tier 1 is not allowed for calculating biogenic 
CO2 emissions for combustion of MSW, as originally specified 
in 40 CFR 98.33(e)(1) of subpart C, and is also not allowed for the 
combustion of tires, if biogenic CO2 emissions are 
calculated for tires.
    We are amending the methodology in 40 CFR 98.33(e)(2), which is 
specifically for units using a CEMS to measure CO2 mass 
emissions, by limiting it to cases where the CO2 emissions 
measured by the CEMS are solely from combustion, i.e., the stack gas 
contains no additional process CO2 or CO2 from 
sorbent; and prohibiting its use if the unit combusts MSW or tires.
    For sources that combust MSW, we are amending 40 CFR 98.33(e)(3) to 
require, except as provided below, the quarterly use of ASTM methods 
D7459-08 and D6866-08, as described in 40 CFR 98.34(d), when any MSW is 
combusted either as the primary fuel or as the only fuel with a 
biogenic component. We are also amending 40 CFR 98.33(e)(3) to allow 
the ASTM methods to be used, as described in 40 CFR 98.34(e), for any 
unit in which biogenic (or partly biogenic) fuels, and non-biogenic 
fuels are combusted, in any proportions.
    In response to comments, we have added an alternative calculation 
methodology for biogenic CO2 emissions from the combustion 
of MSW and/or tires, which may be used when the total contribution of 
these fuels to the unit's heat input is 10 percent or less. If a unit 
combusts both MSW and tires and the reporter exercises the option not 
to separately report biogenic CO2 emissions from the tires, 
the alternative calculation methodology may still be used for the MSW, 
provided that the contribution of MSW to the unit's total heat input 
does not exceed 10 percent. The methodology may also be used for small, 
batch incinerators that burn no more than 1,000 tons of MSW per year.
    Units that qualify for and elect to use the alternative methodology 
will use Tier 1 to calculate the total annual CO2 emissions 
from the combustion of the MSW or tires, and multiply the result by an 
appropriate default factor that represents the biomass fraction of the 
fuel, to obtain an estimate of the annual biogenic CO2 
emissions. Based on additional background research conducted, we have 
concluded that reasonable default factors are 0.20 for tires and 0.60 
for MSW (please refer to the Background Technical Support Document--
Revision of Certain Provisions).
    We are also amending 40 CFR 98.33(e) to delete and reserve 40 CFR 
98.33(e)(4) and the related subparagraphs. Although 40 CFR 98.33(e)(4) 
allowed the ASTM methods to be used to determine biogenic 
CO2 emissions for various combinations of biogenic and 
fossil fuels, we are deleting and reserving that paragraph because the 
paragraph also included an unnecessary restriction, i.e., it only 
applied to units that use CEMS to measure total CO2 mass 
emissions. The amendments to 40 CFR 98.33(e)(3) described above will 
achieve the same intended purpose as paragraph (e)(4), without imposing 
this restriction, so paragraph (e)(4) is no longer needed.
    We are amending 40 CFR 98.33(e)(5) so that it also applies to units 
that are using Tier 2 (Equation C-2a), as well as Tier 1 (Equation C-
1), for calculating biogenic CO2 mass emissions. The 
approach in 40 CFR 98.33(e)(5) for estimating solid biomass fuel 
consumption is equally applicable to units using those two equations to 
calculate biogenic CO2 emissions. Equation C-2a applies when 
HHV data for a biomass fuel are available at the minimum frequency 
specified in 40 CFR 98.34(a)(2).
    Finally, one commenter asked EPA to allow Part 75 units to 
calculate biogenic CO2 emissions using the same general 
approach that is used in 40 CFR 98.33(c)(4)(ii) for the CH4 
and N2O emissions calculations. This requires a heat input-
based equation similar to Equation C-10 to be added to the rule. We 
find this request to be reasonable and have added a new paragraph, 
(e)(6), to 40 CFR 98.33(e). Paragraph (e)(6) provides the required 
equation, i.e., Equation C-15a. In cases where (HI)A, the 
fraction of unit heat input from combustion of the biomass fuel, cannot 
be determined from the information in Part 75 electronic data reports 
(e.g., for units that measure the total CO2 emissions with 
CEMS, if the ``worst-case'' F-factor option is used, or if biomass and 
fossil fuels with identical F-factors are combusted), facilities must 
use the ``best available information'' (as described in 40 CFR 
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.

[[Page 79110]]

    Fuel sampling for coal and fuel oil. We are amending 40 CFR 
98.34(a)(2), to clarify the frequency at which the HHV needs to be 
determined for different types of fuels.
    First, we are amending 40 CFR 98.34(a)(2)(ii) to expand the list of 
fuels for which sampling of each fuel lot is sufficient to include 
other solid or liquid fuels that are delivered in lots.
    Second, we are amending the definition of the term ``fuel lot'' in 
40 CFR 98.34(a)(2)(ii), as it pertains to facilities that receive 
multiple deliveries of a particular type of fuel from the same supply 
source each month, either by truck, rail, or pipeline. The amendment 
clarifies that a fuel lot consists of all of the deliveries of that 
fuel for a given calendar month. Thus, for these facilities, the 
required HHV sampling has to be no more frequent than once per month. 
We did receive requests to clarify the meaning of the terms ``type of 
fuel'' and ``supply source,'' pertaining to the proposal to require 
only one monthly sample to represent multiple fuel deliveries. The 
final rule clarifies that for coal, the type of fuel refers to the coal 
rank (i.e., anthracite, bituminous, sub-bituminous, or lignite). For 
fuel oil, the type of fuel refers to the grade number or classification 
of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel, etc.). The term 
``supply source'' is not so easily defined. For the reasons set forth 
in the Response to Comments (Section II.G.2 of this preamble), we have 
chosen not to include a definition of ``supply source'' in the final 
rule.
    Third, we are adding parallel language to 40 CFR 98.34(b)(3)(ii), 
the Tier 3 fuel sampling provisions for coal and fuel oil, for 
consistency with the revisions to 40 CFR 98.34(a)(2)(ii).
    Finally, we are amending 40 CFR 98.34(a)(2)(ii) and 40 CFR 
98.34(b)(3)(ii) to allow manual oil samples to be taken after each 
addition of oil to the storage tank. Daily manual sampling, flow-
proportional sampling, and continuous drip sampling are also allowed. 
The final rule requires at least one sample to be obtained from each 
storage tank that is currently in service, and whenever oil is added, 
for as long as the tank remains in service. If multiple additions 
(e.g., from multiple deliveries) are made on a given day, taking one 
sample after the final addition is sufficient. No sampling is required 
for addition of fuel to a tank that is out of service. Rather, a sample 
must be taken when the tank is brought into service and whenever oil is 
added to the tank, for as long as the tank remains in service. If the 
daily manual sampling option is implemented, sampling from a particular 
tank is required only on those days when oil from that tank is 
combusted in the unit(s).
    Tier 3 sampling frequency for gaseous fuels.
    We are amending 40 CFR 98.34(b)(3)(ii)(E) to clarify that daily 
sampling of gaseous fuels other than natural gas and biogas for carbon 
content and molecular weight is only required where continuous, on-line 
equipment is in place; weekly sampling is required in all other cases.
    GHG emissions from blended fuel combustion. One of the most 
frequently asked questions by the regulated community since publication 
of the October 30, 2009 final Part 98 is, ``How does one calculate 
CO2 mass emissions from the combustion of blended fuels?'' 
Subpart C provided only limited guidance on this issue. We are now 
finalizing amendments to 40 CFR 98.34(a)(3), (b)(1)(vi), and (b)(3)(v) 
to clarify reporting requirements for calculating emissions from 
blended fuels. The amendments make a clear distinction between cases 
where the mass or volume of each fuel in the blend is accurately 
measured prior to mixing (e.g., using individual flow meters for each 
component) and cases where the exact composition of the blend is not 
known. In the former case, the fact that the fuels are blended is of no 
consequence; because the exact quantity of each fuel in the blend is 
known, the CO2 emissions from combustion of each component 
must be calculated separately. In the latter case, the blend is 
considered to be a distinct ``fuel type,'' and the reporter must 
measure its mass or volume and essential properties (e.g., HHV, carbon 
content, etc.) at a prescribed frequency.
    When the mass or volume of each individual component of a blend is 
not precisely known prior to mixing, the appropriate method used to 
calculate the CO2 mass emissions from combustion of the 
blend is as follows. For smaller combustion units (heat input capacity 
not more than 250 mmBtu/hr), Tier 2 (or possibly Tier 1) can be used 
when all components of the blend are listed in Table C-1 of subpart C. 
In order to perform these CO2 emissions calculations for the 
blend, a reasonable estimate of the percentage composition of the blend 
would be required, using the best available information (e.g., from the 
typical or expected range of values of each component). A heat-weighted 
CO2 emission factor must be calculated, using new Equation 
C-16. For Tier 1 applications, a heat-weighted default HHV must be 
determined, using new Equation C-17.
    In cases where a fuel blend consists of a mixture of fuel(s) listed 
in Table C-1 and fuel(s) not listed in Table C-1, calculation of 
CO2 and other GHG emissions from combustion of the blend is 
required only for the Table C-1 fuel(s), using the best available 
estimate of the mass or volume percentage(s) of the Table C-1 fuel(s) 
in the blend. In these cases, the use of Tier 1 is required, with 
modifications to certain terms in Equations C-17 and C-1, to account 
for the fact that the blend is not composed entirely of Table C-1 
fuels. An example calculation is provided in 40 CFR 98.34(a)(3)(iv).
    For larger combustion units (heat input capacity greater than 250 
mmBtu/hr) that do not qualify to use Tier 1 or 2, the owner or operator 
must use Tier 3 to calculate the CO2 mass emissions from 
combustion of a blended fuel. The mathematics for Tier 3 are simpler 
than for Tiers 1 and 2, since no default values are used in the 
calculations, and an estimate of the percentage composition of the 
blend is not required. To apply Tier 3, the only requirements are to 
accurately measure the annual consumption of the blended fuel and to 
determine its carbon content and (if necessary) molecular weight, at a 
prescribed frequency. By considering the blended fuel to be a distinct 
``fuel type,'' in cases where that fuel is not listed in Table C-1, GHG 
emissions reporting is required in accordance with 40 CFR 
98.33(b)(3)(iii), if the blended fuel (as opposed to each individual 
component of the blend) provides at least 10 percent of the annual heat 
input to a unit or group of units, and if the use of Tier 4 is not 
required.
    To address the calculation of CH4 and N2O 
mass emissions from the combustion of blended fuels, we are adding a 
new paragraph, (c)(6), to 40 CFR 98.33. Calculation of CH4 
and N2O emissions is required only for components of a blend 
that are listed in Table C-2 of subpart C.
    If the mass or volume of each component of a blend is measured 
before the fuels are mixed and combusted, the existing CH4 
and N2O mass emissions calculation procedures in 40 CFR 
98.33(c)(1) through (5) must be followed for each component separately. 
The fact that the fuels are mixed prior to combustion is of no 
consequence in this case.
    If the mass or volume of each individual component is not measured 
prior to mixing, a reasonable estimate of the percentage composition of 
the blend is required, based on the best available information, and the 
procedures in 40 CFR 98.33(c)(6)(ii) will be followed. First, the 
annual consumption of each

[[Page 79111]]

component fuel in the blend is calculated by multiplying the total 
quantity of the blend combusted during the reporting year by the 
estimated mass or volume percentage of that component. Next, the annual 
heat input from the combustion of each component is calculated by 
multiplying its annual consumption by the appropriate HHV (either the 
default HHV from Table C-1 or, if available, the measured annual 
average value). The annual CH4 and N2O mass 
emissions for each component must then be calculated using the 
applicable equation in 40 CFR 98.33(c), i.e., Equation C-8, C-9a, or C-
10. Finally, the calculated CH4 and N2O emissions 
are summed across all components, and these sums are reported as the 
annual CH4 and N2O mass emissions for the blend.
    Use of consensus standard methods. We are amending 40 CFR 
98.33(a)(3)(iv) and (a)(3)(v) to remove reference to specific standard 
methods and allow the use of standards from consensus-based 
organizations or industry standard practice. We are amending 40 CFR 
98.34 to remove the specific ASTM and GPA method list for fuel sampling 
and analysis in 40 CFR 98.34(a)(6), to remove the list of American Gas 
Association (AGA) and American Society of Mechanical Engineers (ASME) 
methods for fuel meter calibration in 40 CFR 98.34(b)(4), and to delete 
the list of ASTM methods to determine carbon content and molecular 
weight in 40 CFR 98.34(b)(5). We are also redesignating 40 CFR 
98.34(b)(5) as 40 CFR 98.34(b)(4), and amending newly designated 40 CFR 
98.34(b)(4). Finally, we are amending 40 CFR 98.34(b)(1)(A) to remove 
the cross-reference to the fuel flow meter test methods listed in 40 
CFR 98.34(b)(4). These amendments allow the owner or operator to use 
manufacturers' procedures, appropriate methods published by consensus-
based standards organizations such as ASTM, ASME, American Petroleum 
Institute (API), AGA, ISO, etc.; or use industry-accepted practice. The 
methods used must be documented in the monitoring plan under 40 CFR 
98.3(g)(5).
    CO2 monitor span values. The Tier 4 calculation method 
in 40 CFR 98.33(a)(4) requires a CO2 concentration monitor 
and a stack gas flow rate monitor to measure CO2 mass 
emissions. The CO2 monitor must be certified and quality-
assured according to one of the following: 40 CFR part 60, 40 CFR part 
75, or an applicable State CEM program. When the part 60 option is 
selected, one of the required quality assurance (QA) tests of the 
CO2 monitor is a cylinder gas audit (CGA). The CGA checks 
the response of the CO2 analyzer at two calibration gas 
concentrations, i.e., one between 5 and 8 percent CO2 and 
one between 10 and 14 percent CO2. These CO2 
concentration levels are appropriate for most stationary combustion 
applications. However, when CO2 emissions from an industrial 
process (e.g., cement manufacturing) are combined with combustion 
CO2 emissions, the resultant CO2 concentration in 
the stack gas can be substantially higher than for the combustion 
emissions alone. In such cases, a span value of 30 percent 
CO2 (or higher) may be required.
    When the CO2 span exceeds 20 percent CO2, the 
CGA concentrations specified in Part 60 only evaluate the lower portion 
of the measurement scale and are no longer representative. Therefore, 
we are amending 40 CFR 98.34(c) by adding a new paragraph (c)(6), which 
allows the CGA of a CO2 monitor to be performed using 
calibration gas concentrations of 40 to 60 percent of span and 80 to 
100 percent of span, when the CO2 span value is set higher 
than 20 percent CO2.
    CEMS data validation. In subpart C, 40 CFR 98.34(c) provides the 
monitoring and QA requirements for Tier 4. However, no criteria for 
hourly CEMS data validation were specified in the final rule. We are 
adding a new paragraph, (c)(7), to 40 CFR 98.34, which requires hourly 
CEMS data validation to be consistent with the sections of 40 CFR part 
60 or part 75 cited in the preceding paragraph of this preamble. 
Alternatively, the hourly data validation procedures in an applicable 
State CEM program can be followed.
    Use of ASTM Methods D7459-08 and D6866-08. Sections 98.34(d) and 
(e) of subpart C, respectively, outline procedures for quantifying 
biogenic CO2 emissions for units that combust MSW and other 
units that combust combinations of fossil fuels and biomass. Flue gas 
samples are taken quarterly using ASTM Method D7459-08 and analyzed 
using ASTM Method D6866-08. We are amending 40 CFR 98.34(d) and (e), as 
discussed in the following paragraphs.
    The amendments to 40 CFR 98.34(d) require the ASTM methods to be 
used when MSW is combusted in a unit, either as the primary fuel, or as 
the only fuel with a biogenic component, unless the unit qualifies for 
the alternative Tier 1 calculation methodology described above, under 
``Biogenic CO2 emissions from biomass combustion.'' 
Quarterly sampling with ASTM Method D7459-08 is required for a minimum 
of 24 cumulative hours of sampling per quarter, except as provided 
below.
    We are amending 40 CFR 98.34(e) to remove the restriction limiting 
the use of ASTM Methods D7459-08 and D6866-08 to units with CEMS. 
Rather, any unit that combusts combinations of fossil and biogenic 
fuels (or partly biogenic fuels, such as tires), in any proportions, is 
allowed to determine biogenic CO2 emissions using the ASTM 
methods on a quarterly basis. At least 24 cumulative hours of sampling 
per quarter are required, except as provided immediately below.
    We are adding an option to 40 CFR 98.34(d) and (e), allowing 
sources to demonstrate that 8 hours of sampling per quarter is 
sufficient. The demonstration requires a minimum of two 8-hour tests 
and one 24-hour test, performed under normal, stable operating 
conditions. The demonstration tests must be distinct, i.e., no 
overlapping of the 8-hour and 24-hour test periods is permitted. If the 
average biogenic fraction obtained from the 8-hour tests is within 
5 percent of the results from the 24-hour test, then, in 
subsequent quarters, the Method D7459-08 sampling time may be reduced 
to 8 hours. The results of the demonstration must be documented in the 
monitoring plan.
    We are also amending 40 CFR 98.34(d) by adding an alternative to 
allow the owner or operator to collect an integrated sample by 
extracting a small amount of flue gas (1 to 5 cubic centimeters (cc)) 
during every unit operating hour in the quarter, in order to obtain a 
more representative sample for analysis.
    Procedures for estimating missing data. We are amending 40 CFR 
98.35(a) to clarify that the missing data procedures in 40 CFR part 75 
are only to be followed by units that are in the Acid Rain Program and 
those that monitor and report emissions and heat input data year round. 
Units that only monitor and report during the ozone season must follow 
the missing data procedures in 40 CFR 98.35(b).
    Electronic data reporting and recordkeeping. We are amending the 
data element lists in 40 CFR 98.36 by adding a number of essential data 
elements and eliminating or modifying others. The most significant 
revisions to the data element lists are summarized in the following 
paragraphs. We are also adding an alternative reporting option to 40 
CFR 98.36(c) to reduce the reporting burden for certain facilities.
    We are adding the reporting of methodology start and end dates in 
several places throughout 40 CFR 98.36(b), (c), and (d).
    We are amending the data element lists in 40 CFR 98.36 to be 
consistent

[[Page 79112]]

with respect to reporting of emissions by fuel type and reporting of 
biogenic CO2 emissions. Specifically, for clarity and 
consistency with the changes to 40 CFR 98.3(c), we have modified the 
amendments to 40 CFR 98.36(d)(1)(ii), (d)(1)(ix), (d)(2)(ii)(I), and 
(d)(2)(iii)(I) from the proposal. These sections state that for units 
subject to 40 CFR part 75, reporting of biogenic CO2 
emissions is optional only for the 2010 reporting year. Reporting of 
these emissions becomes mandatory starting with the 2011 reporting 
year.
    We are removing 40 CFR 98.36(b)(10) to remove the requirement to 
report the customer meter number for units that combust natural gas.
    We are finalizing requirements in 40 CFR 98.36(c)(1)(ii) that only 
the maximum rated heat input capacity of the largest unit in a group 
must be reported. We are also finalizing requirements for 98.36(c)(3) 
in a similar manner, for groups of units served by a common pipe.
    We are amending 40 CFR 98.36 to remove the requirement to report 
the combined annual GHG emissions from fossil fuel combustion in metric 
tons of CO2e (i.e., the sum of the CO2, 
CH4, and N2O emissions) by removing 40 CFR 
98.36(b)(9), (c)(1)(ix), (c)(2)(viii), and (c)(3)(viii). These data 
elements were duplicative of requirements in subpart A.
    We are amending 40 CFR 98.36(b), (c), and (d) to require reporting 
the fuel-specific annual heat input estimates, for the purpose of 
verifying the reported CH4 and N2O emissions. 
Also, we are amending 40 CFR 98.36(e)(2)(iv) to require reporting of 
the annual average HHV when measured HHV data are used to calculate 
CH4 and N2O emissions for a Tier 3 unit, in lieu 
of using a default HHV from Table C-1.
    We are amending 40 CFR 98.36(b) and (d) to make the data elements 
reported under Tiers 1 through 4 consistent for the reporting of 
biogenic CO2 emissions and CO2 from fossil fuel 
combustion. Also, as previously noted in Section II.C of this preamble, 
the amendments to 40 CFR 98.36(d) state that reporting of biogenic 
CO2 emissions is optional only for the 2010 reporting year 
for units using the CO2 mass emissions calculation methods 
in 40 CFR part 75.
    For units that use the Tier 4 methodology to calculate 
CO2 mass emissions, we are amending 40 CFR 98.36(b)(7)(i) 
and (b)(7)(ii) (redesignated as 40 CFR 98.36(b)(9)(i) and (b)(9)(ii), 
respectively) and 40 CFR 98.36(c)(2)(vi) (redesignated as 40 CFR 98.36 
(c)(2)(viii)). The amendments to these sections require the annual 
``non-biogenic'' CO2 mass emissions to be reported instead 
of reporting the annual CO2 mass emissions from fossil fuel 
combustion.
    We are adding a new alternative reporting option, under 40 CFR 
98.36(c)(4). This new option applies to specific situations where a 
common liquid or gaseous fuel supply is shared between large combustion 
units such as boilers or combustion turbines (including Acid Rain 
Program units and other combustion units that use the methods in 40 CFR 
part 75 to calculate CO2 mass emissions), and small 
combustion sources such as space heaters, hot water heaters, etc. In 
such cases, a source can simplify reporting by attributing all of the 
GHG emissions from combustion of the shared fuel to the large 
combustion unit(s), provided that:
     The total quantity of the shared fuel supply that is 
combusted during the report year is measured, either at the ``gate'' to 
the facility or at a point inside the facility, using a fuel flow 
meter, a billing meter or tank drop measurements; and
     On an annual basis, at least 95 percent of the shared fuel 
supply (by mass or volume) is burned in the large combustion unit(s) 
and the remainder of the fuel is fed to the small combustion sources.
    Company records can be used to determine the percentage 
distribution of the shared fuel to the large and small units. 
Facilities using this reporting option are required to document in 
their monitoring plan which units share the common fuel supply and the 
method used to determine that the reporting option applies. For the 
small combustion sources, a description of the type(s) and approximate 
number of units involved is sufficient.
    Finally, we are amending 40 CFR 98.36(e)(2)(iii) to simplify the 
recordkeeping requirements in cases where the results of fuel analyses 
for HHV are provided by the fuel supplier. Parallel language is added 
in a new paragraph, 40 CFR 98.36(e)(2)(v)(E), for the results of carbon 
content and molecular weight analyses received from the fuel supplier. 
In both cases, the owner or operator is required to keep records of 
only the dates on which the fuel sampling results are received, rather 
than keeping records of the dates on which the supplier's fuel samples 
were taken (which may not be readily available).
    Common stack reporting option. Section 98.36(c)(2) of subpart C 
allows subpart C stationary fuel combustion units that share a common 
stack or duct to use the Tier 4 Calculation Methodology to monitor and 
report the combined CO2 mass emissions at the common stack 
or duct, in lieu of monitoring each unit individually. However, 40 CFR 
98.36(c)(2) does not address circumstances where at least one of the 
units sharing the common stack is not a subpart C stationary fuel 
combustion unit, but is subject to another subpart of 40 CFR part 98. 
In view of this, we are amending 40 CFR 98.36(c)(2) by extending the 
applicability of the common stack monitoring and reporting option to 
situations where off-gases from multiple process units or mixtures of 
combustion products and process off-gases are combined together and 
vented through a common stack or duct.
    The amendments to 40 CFR 98.36(c)(2) apply not only to ordinary 
common stack or duct situations where the gas streams from multiple 
units are combined together, but also apply when combustion and/or 
process off-gas streams from a single unit (e.g., from a kiln, furnace, 
petrochemical process unit, or smelter) are routed to a stack. To 
accommodate this variation on the concept of a common stack, 40 CFR 
98.36(c)(2)(ii) is amended to require sources to report ``1'' as the 
``Number of units sharing the common stack or duct'' where combustion 
and/or process emissions from a single unit are vented through the same 
stack or duct.
    Finally, since the concept of maximum rated heat input capacity may 
not be applicable to certain types of process or manufacturing units, 
we are amending 40 CFR 98.36(c)(2)(iii), to require that the ``combined 
maximum rated heat input capacity of the units sharing the common stack 
or duct'' only be reported when all of the units sharing the common 
stack or duct are stationary fuel combustion units.
    Common fuel supply pipe reporting option. Section 98.36(c)(3) of 
subpart C allows units that are served by a common fuel supply pipe to 
report the combined CO2 emissions from all of the units in 
lieu of reporting CO2 emissions separately from each unit. 
To use this reporting option, the total amount of fuel combusted in the 
units must be accurately measured with a flow meter calibrated 
according to the requirements in 40 CFR 98.34. Section 98.36(c)(3) also 
states that the applicable tier to use for this reporting option is 
based on the maximum rated heat input of the largest unit in the group.
    We are amending 40 CFR 98.36(c)(3) as follows. First, the erroneous 
citation of ``Sec.  98.34(a)'' is corrected to read ``Sec.  98.34(b).'' 
Second, we are amending the requirement in 40 CFR 98.36(c)(3) to 
calibrate the fuel flow meter to the accuracy required by 40 CFR 
98.34(b)

[[Page 79113]]

(which cross-references the accuracy specifications in 40 CFR 98.3(i)), 
so that this calibration requirement applies only when Tier 3 is the 
required tier for calculating CO2 mass emissions. This is 
consistent with the final amendments to 40 CFR 98.3(i), where we 
clarify that the equipment used to generate company records under Tier 
1 and 2 is not required to meet the calibration accuracy specifications 
of 40 CFR 98.3(i).
    The applicable measurement tier for the common pipe option, 
according to subpart C, is based on the rated heat input capacity of 
the largest unit in the group. On the surface, this appears to mean 
that the use of Tiers 1 and 2 is restricted to common pipe 
configurations where the highest rated heat input capacity of any unit 
is 250 mmBtu/hr or less, and that Tier 3 is required if any unit has a 
maximum rated heat input capacity greater than 250 mmBtu/hr. In 
general, this is true. However, there is one exception in the current 
rule and we are amending the rule to add a second one. Section 
98.33(b)(2)(ii) of the current rule allows the use of Tier 2 instead of 
Tier 3 for the combustion of natural gas and/or distillate oil in a 
unit with a rated heat input capacity greater than 250 mmBtu/hr. 
Today's rule adds a new paragraph, (b)(1)(v), to 40 CFR 98.33, allowing 
Tier 1 to be used when natural gas consumption is determined from 
billing records, and fuel usage on those records is expressed in units 
of therms or mmBtu. Therefore, we are also amending 40 CFR 98.36(c)(3) 
to reflect these two exceptions for common pipe configurations that 
include a unit with a maximum rated heat input capacity greater than 
250 mmBtu/hr.
    Finally, we are amending the provision in 40 CFR 98.36(c)(3) 
regarding the partial diversion of a fuel stream such as natural gas 
that is measured ``at the gate'' to a facility (e.g., using a 
calibrated flow meter or a gas billing meter). Subpart C specifies that 
when part of a fuel stream is diverted to a chemical or industrial 
process where it is used but not combusted, and the remainder of the 
fuel is sent to a group of combustion units, you may subtract the 
diverted portion of the fuel stream from the total quantity of the fuel 
measured at the gate before applying the common pipe methodology to the 
combustion units. We are amending the rule to expand this provision to 
include cases where the diverted portion of the fuel stream is sent 
either to a flare or to another stationary combustion unit (or units) 
on site, including units that use 40 CFR part 75 methodologies to 
calculate annual CO2 mass emissions (e.g., Acid Rain Program 
units). Provided that the GHG emissions from the flare and/or other 
combustion unit(s) are properly accounted for according to the 
applicable subpart(s) of Part 98, you are allowed to subtract the 
diverted portion of the fuel stream from the total quantity of the fuel 
measured at the gate, and then apply the common pipe reporting option 
to the group of combustion units served by the common pipe, using the 
Tier 1, Tier 2, or Tier 3 calculation methodology (as applicable).
    Table C-1. Table C-1 of subpart C provides default HHV values and 
default CO2 emission factors for various types of fuel. We 
are finalizing several amendments to Table C-1; specifically, we have:
     Replaced the categories ``fossil fuel-derived fuels 
(solid)'' and ``fossil fuel-derived fuels (gaseous)'' with more 
inclusive terms, i.e., ``other fuels (solid)'' and ``other fuels 
(gaseous).'' The ``other fuels (solid)'' category includes four fuels: 
plastics, municipal solid waste, tires, and petroleum coke. The ``other 
fuels (gaseous)'' category includes blast furnace gas, coke oven gas, 
propane gas, and fuel gas.
     Removed the word ``pipeline'' from the description of 
natural gas.
     Retained the following fuels: ``wood residuals,'' 
``agricultural by-products,'' and ``solid by-products'', and added 
definitions of these terms to 40 CFR 98.6 (see section II.F of this 
preamble for further discussion).
     Added ``Used oil'' to the list of petroleum products, and 
added a definition to 40 CFR 98.6 (see section II.F of this preamble 
for further discussion).
     Removed ``still gas'' from the list of petroleum products 
and added ``fuel gas.''
     Corrected a typographic error in the HHV for ethane; 
changing it to 0.069 mmBtu/gal, rather than 0.096 mmBtu/gal.
     Revised footnote 1 regarding municipal waste combustor 
(MWC) units to make it clear that only MWC units that produce steam are 
prohibited from using the default HHV for MSW in Table C-1; MWC units 
that produce steam can still use the default CO2 emission 
factor for MSW.
     Modified footnote 1 to Table C-1, to reflect the new 
biogenic CO2 emissions calculation options for certain units 
that combust MSW and/or tires.
     Revised footnote 2 to clarify that if the conditions in 40 
CFR 98.243(d)(2)(i) and (d)(2)(ii) and 40 CFR 98.252(a)(1) and (a)(2) 
do not apply, reporters subject to 40 CFR 98.243(d) of subpart X or 
subpart Y shall use either Tier 3 or Tier 4.
     Remove the qualifier of 100 percent for ethanol and 
biodiesel.
     Added a default CO2 emission factor and a 
default high heat value for petroleum-derived ethanol. These are the 
same as the default values for biomass-derived ethanol.
    Table C-2. We are finalizing the proposed amendments to remove the 
first iteration of Table C-2 and make minor corrections to the second 
one. The amendments consist of correcting the exponents (powers-of-ten) 
of several emission factors.
    Standard conditions. A number of commenters requested that, for 
consistency with the rest of Part 98, we allow sources to use 60 [deg]F 
as standard temperature instead of 68 [deg]F, when Equation C-5 is used 
to calculate CO2 mass emissions from the combustion of 
gaseous fuel. We proposed to allow this alternative for subparts X and 
Y, because the refining and petrochemical industries use 60 [deg]F as 
standard temperature. We have concluded that the commenters' request to 
modify Equation C-5 accordingly is reasonable, and we are revising the 
definition of the term ``MVC (molar volume conversion)'' in the 
nomenclature of Equation C-5 (see revised 40 CFR 98.33(a)(3)(iii)). The 
revised definition of MVC allows sources to use a MVC value of either 
849.5 standard cubic feet per kilogram mole (scf/kg mole) for a 
standard temperature of 68 [deg]F, or 836.6 scf/kg mole for a standard 
temperature of 60 [deg]F. A corresponding change has been made to the 
definition of ``Standard conditions'' in 40 CFR 98.6. For verification 
purposes, a data element has been added at 40 CFR 98.36(e)(2)(iv)(G), 
requiring sources using Equation C-5 to report which MVC value was used 
in the emissions calculations.
    Miscellaneous revisions. We are amending 40 CFR 98.34(c) by adding 
the citations from 40 CFR part 75 that pertain to the initial 
certification of Tier 4 moisture monitoring systems. These amendments 
also correct an inadvertent omission in the verification section of 
subpart C, specifically, in 40 CFR 98.36(e)(2)(v)(C). That section 
requires units using the Tier 3 methodology to keep records of the 
method(s) used for carbon content determination. However, no mention is 
made of keeping records of the method(s) used to determine the 
molecular weight, which is a requirement for gaseous fuels. To correct 
this inadvertent oversight, we have amended 40 CFR 98.36(e)(2)(v)(C) to 
require records to be kept of the method(s) used for both carbon 
content and (if applicable) molecular weight determination. Finally, we 
have

[[Page 79114]]

corrected typographical errors in the definition of ``CC'' in the 
nomenclature of Equation C-5. This equation applies to gaseous fuels, 
not liquid fuels, and the units of measure for CC must be kg C per kg 
of fuel, rather than kg C per gallon.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     A new equation has been added to Tier 1 to accommodate 
situations in which the fuel usage information on gas billing records 
is expressed in mmBtu. We have also added two new equations to 40 CFR 
98.33(c) for calculating CH4 and N2O emissions 
when the fuel usage information on natural gas billing records is in 
units of therms or mmBtu.
     For units using the Tier 2 methodology that receive HHV 
data less frequently than monthly, or, for small units (< 100 mmBtu/hr) 
regardless of the HHV sampling frequency, we are allowing Equation C-2b 
to be used to calculate a fuel-weighted annual average HHV, instead of 
calculating the arithmetic average annual HHV.
     For consistency with other subparts, we have revised the 
nomenclature of Equation C-5, to allow reporters to use a molar volume 
conversion (MVC) constant referenced to a standard temperature of 
either 60 [deg]F or 68 [deg]F.
     For Tier 4 applications, we are allowing site-specific 
moisture default values to be based on fewer than nine Method 4 runs in 
cases where moisture data from the RATA of a CEMS are used to derive 
the default value and the applicable regulation allows a single 
moisture run to represent two or more RATA runs.
     We have modified the approach for calculating 
CO2 mass emissions from an exhaust stream diverted from a 
CEMS monitored stack.
     For consistency with Subpart A, we have added language in 
several places stating that for Part 75 units, separate reporting of 
biogenic CO2 emissions is optional in reporting year 2010 
and mandatory thereafter.
     We have added a new paragraph, (e)(6), to 40 CFR 98.33, 
allowing Part 75 units to calculate biogenic CO2 emissions 
using the same general approach that is used in 40 CFR 98.33(c)(4)(ii) 
for the CH4 and N2O emissions calculations.
     We have added an alternative calculation methodology, for 
biogenic CO2 emissions from the combustion of MSW and tires 
that may be used when the total contribution of these fuels to the 
unit's heat input is 10 percent or less. The methodology, which uses 
the Tier 1 equation together with default biogenic percentages, may 
also be used for small, batch incinerators that burn no more than 1,000 
tons of MSW per year.
     We have removed the term ``consecutive'' between the words 
``24'' and ``hours'', in reference to the minimum required sampling 
time for determining the percentage of biogenic CO2 in flue 
gas when ASTM Method D7459-08 is used, thereby allowing samples to be 
collected for 24 total hours in a quarter, rather than 24 consecutive 
hours. We have also added a provision allowing sources to perform 
additional testing to demonstrate that sampling for 8 hours is 
sufficient.
     We have added language to 40 CFR 98.34(a)(2)(ii) and 
(b)(3)(ii)(B) explaining how to implement certain fuel oil sampling 
options, specifically, daily manual sampling and sampling after each 
addition of oil to the tank.
     To minimize unnecessary burden related to collecting 
information on small units aggregated in a group and for the common 
pipe configuration, we are removing and reserving 40 CFR 98.36 
(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii). We are no longer requiring 
sources to report the number of units in, or the cumulative heat input 
capacity of, an aggregated group of units or a group of units served by 
a common pipe. Only the maximum rated heat input capacity of the 
largest unit in the group must be reported.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional comments received can be found in the document, ``Response 
to Comments: Revision to Certain Provisions of the Mandatory Reporting 
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Natural gas consumption expressed in therms.
    Comment: Commenters were generally supportive of EPA's proposal to 
provide equations for cases where natural gas consumption is expressed 
in therms in billing records. One commenter noted that the proposed 
rule failed to take into account that on some natural gas billing 
records, the fuel usage is expressed in units of mmBtu. The commenter 
also brought to our attention that the proposed rule did not provide 
corresponding equations for calculating CH4 and 
N2O emissions when the fuel usage information on gas billing 
records is expressed in therms.
    Response: We agree with these comments and have made the following 
adjustments to the final rule text. First, a new equation, Equation C-
1b, has been added to Tier 1 to accommodate situations in which the 
fuel usage information on gas billing records is expressed in mmBtu. 
Second, we have added two new equations to 40 CFR 98.33(c), i.e., 
Equations C-8a and C-8b, for calculating CH4 and 
N2O emissions when the fuel usage information on natural gas 
billing records is in units of therms or mmBtu.
    Site-specific stack gas moisture content values.
    Comment: Commenters were generally supportive of the proposed rule 
changes related to determining the site-specific moisture default 
values. Two commenters requested that we allow the site-specific 
moisture default values to be based on fewer than nine Method 4 runs, 
in cases where moisture data from the RATA of a CEMS are used to derive 
the default value and the applicable regulation allows a single 
moisture run to represent two or more RATA runs.
    Response: We believe that this is a reasonable request and have 
incorporated it into the final rule.
    Determining emissions from an exhaust stream diverted from a CEMS 
monitored stack.
    Comment: Commenters were supportive of the intent of the proposed 
amendments, but indicated that the proposed methodology for estimating 
the CO2 mass emissions from the diverted gas stream would 
not be implementable at every affected facility. Specifically, 
commenters took issue with EPA's assumption that the CO2 
concentration in the diverted stream will be the same as the 
concentration in the main stack. According to the commenters, this is 
not the case, because dilution air introduced via auxiliary fans and 
other equipment will lower the CO2 concentration of the side 
stream.
    Response: We agree with the commenters' assessment and have 
modified the proposed approach for quantifying emissions in the 
diverted stream. The final rule requires annual emission testing of the 
diverted gas stream to be performed at a set point that best represents 
normal operation, using EPA Methods 2 and 3A and (if moisture 
correction is necessary) Method 4. A CO2 mass emission rate 
is calculated from the test results. If, over time, flow rate of the 
diverted stream

[[Page 79115]]

varies little from the tested flow rate, then the annual CO2 
mass emissions for the diverted stream (which must be added to the 
CO2 mass emissions measured at the main stack) will be 
determined simply by multiplying the CO2 mass emission rate 
from the emission testing by the number of operating hours in which a 
portion of the flue gas was diverted from the main flue gas exhaust 
system. However, if the flow rate of the diverted stream varies 
significantly over the reporting year, the owner or operator must 
either perform additional stack testing or use the best available 
information (e.g., fan settings and damper positions) and engineering 
judgment to estimate the CO2 mass emission rate at a minimum 
of two additional set points, to represent the variation across the 
normal operating range. Then, the most appropriate CO2 mass 
emission rate must be applied to each hour in which a portion of flue 
gas is diverted from the main exhaust system. The procedures used to 
determine the annual CO2 mass emissions for the diverted 
stream must be documented in the monitoring plan.
    Fuel sampling for coal and fuel oil.
    Comment: Commenters were generally supportive of the proposed 
amendments to 40 CFR 98.34(a)(2)(ii) and 40 CFR 98.34(b)(3)(ii) 
regarding the definition of ``fuel lot.'' However, we did receive 
requests to clarify the meaning of the terms ``type of fuel'' and 
``supply source,'' pertaining to the proposal to require only one 
monthly sample to represent multiple fuel deliveries.
    Response: The final rule clarifies that for coal, the type of fuel 
refers to the coal rank (i.e., anthracite, bituminous, sub-bituminous, 
or lignite). For fuel oil, the type of fuel refers to the grade number 
or classification of the oil (e.g., No. 2 oil, No. 6 oil, jet-A fuel, 
etc.). The term ``supply source'' is not so easily defined, however, 
and we have chosen not to include a definition to the final rule. 
Instead, you may use the following general guidelines. The term 
``supply source'' can certainly refer to the coal mine, bulk terminal, 
or refinery from which the fuel is obtained. However, it also can apply 
to a fuel vendor who receives a particular type of fuel from different 
locations and distributes the fuel to his customers, provided the 
important properties of the fuel, such as its heating value, sulfur 
content, carbon content, etc., are guaranteed to be within specified 
ranges.
    Comment: With respect to the HHV sampling requirements for each 
fuel lot, commenters expressed concern that the option to sample fuel 
oil after each addition of fuel to the storage tank might not represent 
the fuel actually being combusted. For instance, fuel may be added to 
an empty or a partly full tank that is out of service. Also, for a tank 
that is currently in service, due to infrequent combustion of fuel oil, 
it may have been months, or even years, since oil was last added to the 
tank, and it may be months or years before oil is added again.
    Response: To address these concerns, the final rule requires at 
least one sample to be obtained from each storage tank that is 
currently in service, and an additional sample whenever fuel is added 
to the tank while it remains in service. If multiple additions are made 
to an in-service tank on a given day (e.g., from multiple deliveries) 
one sample taken after the final addition is sufficient. No sampling is 
required for addition of fuel to a tank that is out of service. Rather, 
a sample must be taken when the tank is brought into service and 
whenever oil is added to the tank, for as long as the tank remains in 
service.
    Tier 4 monitoring threshold for units that combust MSW.
    Comment: Commenters were generally supportive of the proposed 
amendment to increase the Tier 4 monitoring threshold for combustion of 
municipal solid waste from 250 to 600 tons per day. One concern was 
that the amendment might not be finalized before the end of 2010; 
therefore, they asked for the final rule to provide a six month 
extension of the January 1, 2011 regulatory deadline for installing and 
certifying CEMS. Some commenters were concerned that this proposed 
change would affect the quantity of emissions reported under the 
program and were, therefore, concerned about finalizing this proposed 
amendment.
    Response: There is no need for the requested extension because 
units at or above the 600 ton per day threshold have been on notice 
since the 2009 final rule that they are required to use CEMS. The 
proposed revision to the Tier 4 monitoring threshold should not have 
caused them to think otherwise. For units in-between the original 
threshold of 250 tons per day and the revised threshold of 600 tons per 
day, an extension is unnecessary because these units can use Tier 2 for 
the 2010 reporting year. We disagree with concerns that the final 
amendments will impact the quantity of data reported to the program, 
because the final amendments still require the same units to report GHG 
emissions. The only difference is that they may be using the Tier 2 
methodology instead of Tier 4.
    Biogenic CO2 emissions from biomass combustion.
    Comment: Regarding the proposed revisions to the optional biogenic 
CO2 emissions calculation methodology for units with CEMS 
described in 40 CFR 98.33(e)(2), one commenter recommended that we make 
the methodology more flexible by modifying Equation C-13. The change to 
this equation proposed by the commenter would allow the volume of 
CO2 from combustion of the biomass fuel (rather than the 
fossil fuel) to be calculated directly and then used in Equation C-14 
to calculate the biogenic percentage of the annual CO2 mass 
emissions.
    Response: EPA has not incorporated the commenter's proposed 
changes. Although the proposed modification to the methodology could 
work for fuels such as wood residue and bark (which have F-factors 
listed in Table 1 in section 3.3.5 of 40 CFR part 75, appendix F), the 
commenter appears to be unaware that we proposed to remove from 40 CFR 
98.33(e)(1) the restriction prohibiting units with CEMS from using the 
Tier 1 methodology to calculate biogenic CO2 emissions. As 
stated above, we are finalizing that amendment as proposed. Therefore, 
since both Tier 1 and the commenter's suggested methodology require 
sources to quantify the amount of biomass fuel combusted, and since the 
Tier 1 methodology is significantly simpler than the commenter's 
proposal, there is no need to revise the calculation procedures in 40 
CFR 98.33(e)(2).
    Comment: Many units and industrial processes burn relatively small 
amounts of partly biogenic fuels such as tires and MSW, as 
supplementary fuels. Quarterly sampling and analysis of the flue gas 
using ASTM Methods D7459-08 and D6866-08 is the only available 
methodology in Part 98 for quantifying biogenic CO2 
emissions from these fuels. Some commenters requested relief from 
reporting biogenic CO2 emissions from such fuels when they 
account for less than 10 percent of a unit's heat input. Another 
commenter asked EPA to either make reporting of biogenic CO2 
optional or reduce the amount of required testing with the ASTM methods 
to once every five years, for small batch incinerators that combust 
MSW. The commenter provided data for a typical batch incinerator, 
showing that in 2009, less than 400 metric tons of biogenic 
CO2 were emitted from the unit.
    Response: We do not intend to grant a reporting exemption for MSW 
combustion, and, for tires, although the reporting is optional at 
present, we intend to revisit this issue in the future. However, we are 
persuaded that the cost

[[Page 79116]]

of performing the ASTM methods (roughly $5,000 to $10,000 each quarter) 
is unreasonably high for sources that burn very small amounts of MSW 
and/or tires and emit comparatively little biogenic CO2. 
Also, for sources that combust tires and wish to report biogenic 
CO2, the ASTM methods are their only option. In view of 
these considerations, we have added an alternative calculation 
methodology for biogenic CO2 emissions from the combustion 
of tires and/or MSW. The methodology is found at 40 CFR 
98.33(e)(3)(iv), and may be used when the total contribution of these 
fuels to the unit's heat input is 10 percent or less. We are also 
allowing this methodology to be used for small batch incinerators that 
burn no more than 1,000 tons of MSW per year. Supplementary information 
provided by the commenter who requested reduced testing of these 
incinerators indicates that the rated capacities of the units can be as 
high as 1,300 lb/hr of MSW, but that in practice, since the units 
operate in batch mode, a more realistic estimate of the actual, 
annualized capacity of the units is somewhere between 100 and 200 lb/hr 
(see EPA-HQ-OAR-2008-0508). If one of these incinerators were to 
combust as much as 200 lb/hr of MSW on an annualized basis, this would 
equate to approximately 875 tons of MSW per year. The total annual 
CO2 emissions from the combustion of 875 tons of MSW is 
estimated to be about 800 metric tons, based on the default emission 
factors in Table C-1. Assuming a biogenic fraction of 0.60 for MSW, the 
biogenic portion of the total annual CO2 emissions would be 
480 metric tons, which is less than 2 percent of the 25,000 metric ton 
applicability threshold in 40 CFR 98.2 for Part 98 facilities. Based on 
the above analysis, we have concluded that it is appropriate to allow 
Tier 1 to be used together with a default biogenic percentage of 0.60 
to estimate the biogenic CO2 emissions from MSW combustion 
in small batch incinerators, in lieu of using ASTM Methods D7459-08 and 
D6866-08. To allow for some possible variation in the annualized 
capacity of these units, the final rule extends the use of the 
alternative calculation methodology to batch incinerators that combust 
no more than 1,000 tons of MSW per year (which corresponds to about 540 
tons of biogenic CO2 per year).
    Comment: With regard to the use of ASTM Methods D7459-08 and D6866-
08, two commenters from facilities that combust refuse-derived fuel 
(RDF) asked us to consider shortening the sampling time to 8 hours, in 
cases where the fuel is relatively homogeneous. Both commenters 
submitted data comparing the results of 8-hour samples against the 
results of 24-hour samples. For one source, the 8-hour sample results 
were within 3.3 percent of the 24-hour results, and for the other 
source the results were within 1.7 percent.
    Response: EPA agrees that under certain circumstances, it may be 
appropriate to shorten the sampling time. Therefore, we are adding an 
option to 40 CFR 98.34(d) and (e), allowing sources to demonstrate that 
8 hours of sampling per quarter is sufficient. The demonstration 
requires a minimum of two 8-hour tests and one 24-hour test, performed 
under normal, stable operating conditions. The demonstration tests must 
be distinct, i.e., no overlapping of the 8-hour and 24-hour test 
periods is permitted. If the average biogenic fraction obtained from 
the 8-hour tests is within  5 percent of the results from 
the 24-hour test, then, in subsequent quarters, the Method D7459-08 
sampling time may be reduced to 8 hours. The results of the 
demonstration must be documented in the monitoring plan. Note that 
although the data provided by the commenters showed that the 8-hour and 
24-hour sample results differed by no more that 3.3 percent, we believe 
that  5 percent is a more reasonable acceptance criterion. 
This is because the methodology will likely be used for the combustion 
of tires as well as MSW. Tire-derived fuel (TDF) has a much lower 
biogenic fraction than MSW (typically about 0.20, compared to 0.60 for 
MSW). An acceptance criterion lower than 5 percent for TDF combustion 
would require the difference between the 8-hour and 24-hour sample 
results to be less than 0.01, and would be overly stringent.
    Use of consensus standard methods.
    Comment: We received both supportive and adverse comments on the 
proposed amendments to remove reference to specific consensus 
standards. Commenters that objected to the proposal stated that 
elimination of the lists of acceptable methods and allowing the use of 
``industry standard practice'' weakens the rule. According to these 
commenters, there is no way to evaluate the technical merits of an 
``industry standard practice,'' and the quality of the reported GHG 
emissions data could suffer as a result.
    Response: We do not agree with the objections raised by these 
commenters. Subpart C covers a large range of industries, perhaps 
including some that we are not even aware of yet that are significant 
emitters of GHG emissions and therefore covered by the rule. In these 
early years of the program, we want to ensure that the methods required 
by the rule are appropriate for all facilities subject to subpart C of 
the rule. Although we attempted to assemble a comprehensive list of 
methods and provide appropriate alternatives in the 2009 final rule, 
based on questions received we determined that it was likely that other 
valid methods from these organizations and practices were overlooked. 
For instance, under the 2009 final rule, even updates to the IBR 
methods to reflect the latest practices would not have been acceptable 
without a rulemaking. The commenters did not sufficiently justify why 
opening up to industry consensus standards would compromise data 
quality. In fact, the opposite could be said where more updated 
versions of previously incorporated standards are now allowable.
    Further, subpart C already includes a mechanism by which we can 
evaluate the methods being used by industry. Sections 98.36(e)(2)(iii) 
and 98.36(e)(2)(v) require that records be kept of the methods that are 
used for flow meter calibration and for HHV and carbon content 
determinations, and 40 CFR 98.36(e)(4) requires sources to provide this 
information to EPA within 30 days of receiving a request for it.
    We note that we have not opened all subparts more broadly to 
industry consensus standards. Please see the responses to comments in 
Section II.K (Hydrogen Production) and Section II.M (Petrochemical 
Production) of this preamble for our response to similar comments under 
these subparts.
    Electronic data reporting and recordkeeping.
    Comment: Two commenters asked us to either remove or modify the 
proposed requirement to report the number of units in an aggregated 
group of units. One commenter suggested that reporting would be 
simplified if very small sources such as water heaters, space heaters, 
lab burners, etc., were lumped together and counted as one unit. The 
other commenter stated that it is burdensome to keep an accurate count 
of these small domestic units at large, complex industrial facilities. 
That same commenter also suggested that only units with heat input 
ratings of 10 mmBtu or greater should be included in the count. A third 
commenter noted that it is also difficult to report the cumulative 
maximum heat input rating of a group of units, as required under 40 CFR 
98.36(c)(1)(iii), when numerous small domestic units, some of which may 
not have a heat input rating, are included in an aggregated group.

[[Page 79117]]

    Response: We believe these comments have merit. After careful 
consideration, we have concluded that for verification purposes, we do 
not need to know either the exact number of units in an aggregated 
group or the combined maximum rated heat input of the group. The only 
critical data element is the maximum rated heat input capacity of the 
largest unit in the group. This information is needed to confirm that 
none of the units exceeds 250 mmBtu/hr, which is the condition that 
must be met to use the unit aggregation option in 40 CFR 98.36(c)(1). 
Therefore, in the final rule, we are withdrawing the proposed 
requirement to report the number of units in an aggregated group of 
units, and are removing the requirement to report the combined maximum 
rated heat input of the group. We also are withdrawing the proposed 
requirement under 40 CFR 98.36(c)(3)(ii) to report the number of units 
served by a common fuel pipe. The issue is the same for the common pipe 
configuration as for the aggregated group of units, i.e., hundreds of 
small, domestic units may be served by the common pipe. To effect these 
rule changes, 40 CFR 98.36(c)(1)(ii), (c)(1)(iii), and (c)(3)(ii) have 
been removed and reserved.
    Table C-1.
    Comment: Two commenters questioned the appropriateness of listing 
MSW with plastics and petroleum coke. Further, they noted that 
petroleum coke is listed twice in the table, first under petroleum 
products and then again under ``other fuels (solid).'' According to the 
commenters, petroleum coke is a petroleum derivative, and is more 
appropriately listed with the other ``petroleum products.''
    Response: The category ``other fuels (solid)'' in Table C-1 is not 
intended to make any policy statement about the nature of the fuels 
included in the category. The fuels included in ``other fuels (solid)'' 
are miscellaneous fuels that do not fit into any other existing 
category for the purposes of this rule. Petroleum coke was included as 
a petroleum product in the 2009 final rule (74 FR 56409). However, the 
HHV units of measure for petroleum products listed in Table C-1 are in 
mmBtu per gallon and some reporters were confused about how to 
appropriately calculate CO2 emissions from petroleum coke, 
since it is actually a solid fuel, and is nominally measured in units 
of short tons. By listing petroleum coke as a solid fuel with a heating 
value in units of mmBtu/short ton, EPA intends to alleviate confusion 
about how emissions are to be calculated for petroleum coke. However, 
we also understand that some facilities report petroleum coke usage to 
the Energy Information Administration (EIA) in units of equivalent 
barrels of petroleum, and may prefer to report petroleum coke 
consumption in units of gallons under this rule. As such, EPA is not 
proposing to remove petroleum coke from the list of petroleum products 
in Table C-1. The two HHVs for petroleum coke differ only in units of 
measure. They will give equivalent results when CO2 mass 
emissions are calculated.
    Comment: Two commenters asserted that plastics are a small 
component of MSW and there is no reason why plastics should be listed 
as a separate fuel in Table C-1. These commenters stated that to the 
best of their knowledge, plastics are not combusted as a separate fuel 
stream, and they recommended that EPA delete plastics from Table C-1.
    Two other commenters, however, stated that plastics are, in fact, 
sometimes separated out from MSW as a separate stream. These commenters 
provided a suggested definition of ``plastics'' and requested that we 
add it to 40 CFR 98.6. The commenters also asked us to modify the 
definition of MSW, to specifically exclude plastics that are recovered 
from MSW, processed separately, and disposed.
    Response: As mentioned in the preamble to the August 11, 2010 
proposed rule (75 FR 48764), facilities have questioned EPA as to why 
plastics and waste oil, two fuels that appeared in Table C-2 of the 
April 10, 2009 proposed rule, were left out of the October 30, 2009 
final rule. Responding to these concerns, on August 11, 2010 we 
proposed to add both fuels to Table C-1. Today's rule retains these 
entries, except that waste oil has been redesignated as ``used oil.'' 
In view of the input received from the commenters who brought to our 
attention that plastics (including such things as ``* * * bottles, 
containers, bags, CD cases, sheeting, packaging, broken consumer goods, 
etc. * * *'') are sometimes recovered from MSW and processed 
separately, we decided not to incorporate the recommendation of the 
other commenters who asked us to delete plastics from the table.
    We see no need to add a definition of plastics to 40 CFR 98.6, 
since plastic materials are readily identifiable. However, to address 
the commenters' chief concern, we have modified the definition of MSW 
to clearly state that insofar as plastics (along with certain other 
materials) are separated out from MSW, processed and disposed of, they 
are not considered to be ``municipal solid waste.''
    Comment: Two commenters argued against the inclusion of default 
factors for ``fuel gas'' in Table C-1. They argued that this would have 
a negative impact on chemical plant fuel gas streams that were 
previously exempt from Tier 3 requirements when the streams provide 
less than 10 percent of the annual heat input to a unit rated greater 
than 250 mmBtu/hr) because Table C-1 previously had no factors for fuel 
gas. According to the commenters, the proposed inclusion of default 
factors for ``fuel gas'' in Table C-1 requires monitoring and reporting 
of GHG emissions from these gas streams. Both commenters suggested that 
Table C-1 should include default factors for ``refinery fuel gas'' 
rather than ``fuel gas.'' One commenter also suggested revising the 
definition of ``fuel'' and Footnote 2 associated with the default 
values for fuel gas in Table C-1 to clarify that fuel gas is specific 
to refineries and petrochemical plants, but excludes process off-gases 
from chemical production plants.
    Response: Default values for fuel gas in Table C-1 are necessary to 
allow refineries and petrochemical plants to use Tier 1 or Tier 2 
methods for certain small fuel gas streams that were proposed to be 
excluded from the requirement to use Tier 3 for fuel gas in subparts X 
and Y. In providing these factors, we did not intend to require 
chemical plants to monitor and report GHG emissions generated by the 
combustion of ``fuel gas'' that were excluded from reporting 
requirements in the October 30, 2009, final Part 98. Therefore, we 
agree that some additional clarification of terms is needed to prevent 
the fuel gas factor from requiring measurement and reporting of GHG 
from the chemical plant vent gases.
    While changing the term used in Table C-1 to ``refinery fuel gas'' 
may have helped to clarify the intent, we do not believe, given the 
definition of ``fuel gas'' in the final rule, that this would 
adequately address the issue. ``Fuel gas'' as defined in the October 
30, 2009, final Part 98 means ``gas generated at a petroleum refinery, 
petrochemical plant, or similar industrial process unit, and that is 
combusted separately or in any combination with any type of gas.'' The 
inclusion of the phrase ``or similar industrial process unit'' within 
the definition of fuel gas expanded the meaning of fuel gas beyond 
refineries and petrochemical plants. Without specifically defining the 
term ``refinery fuel gas'' we expect that the rule language would have 
remained ambiguous, especially since refinery

[[Page 79118]]

fuel gas was still intended to apply to some petrochemical processes.
    To clarify our original intent of the proposed inclusion of default 
factors for fuel gas in Table C-1, we are revising the definition of 
``fuel gas'' to delete reference to other similar industrial process 
units. In Part 98, the term ``fuel gas'' is intended to apply to 
petroleum refineries and petrochemical plants, so this revision does 
not affect other Part 98 requirements; it simply clarifies that ``fuel 
gas'' and the fuel gas factors are specific to petroleum refineries and 
petrochemical plants.
    The commenter suggested revising the definition of fuel to mean 
``solid, liquid or gaseous combustible material, but excludes process 
waste off gases from chemical production plants that are not petroleum 
refineries or petrochemical plants.'' We have determined that this 
change is not necessary because we have addressed the commenter's 
concerns through the change in the definition of fuel gas. We are 
amending Footnote 2 of Table C-1, as requested, to clarify further that 
only reporters subject to 40 CFR 98.243(d) of subpart X or subpart Y 
are required to use Tier 3 or Tier 4 methodologies when the specific 
conditions outlined in the footnote do not exist.

H. Subpart D--Electricity Generation

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.40(a) by adding the word ``mass'' between 
the words ``CO2'' and ``emissions'' to make it clear that 
subpart D applies only to units in two categories: ARP units and non-
ARP electricity generating units (EGUs) that are required to report 
CO2 mass emissions data to EPA year-round.
    Optional reporting of biogenic CO2. For consistency with the 
amendments to subpart C, we have revised 40 CFR 98.43 to clarify that 
for subpart D units, reporting of biogenic CO2 emissions is 
optional only for the 2010 reporting year, and mandatory thereafter. We 
are also adding a new paragraph 40 CFR 98.43(b) indicating that 
biogenic CO2 emissions must be calculated and reported by 
following the applicable methods specified in 40 CFR 98.33(e). Fossil 
CO2 emissions are calculated by subtracting the biogenic 
CO2 mass emissions calculated according to 40 CFR 98.33(e) 
from the cumulative annual CO2 mass emissions from paragraph 
(a)(1) of this section.
    Data reporting requirements. Section 98.46 of subpart D specified 
that the owner or operator of a subpart D unit must comply with the 
data reporting requirements of 40 CFR 98.36(b) and, if applicable, 40 
CFR 98.36(c)(2) or (c)(3). These section citations were incorrect. 
Subpart D units all use the CO2 mass emissions calculation 
methodologies in 40 CFR part 75. Therefore, the applicable data 
reporting section for these units is 40 CFR 98.36(d), not 40 CFR 
98.36(b), 40 CFR 98.36(c)(2), or 40 CFR 98.36(c)(3). We are amending 40 
CFR 98.46 to correct this error.
    Recordkeeping. We are amending 40 CFR 98.47 to state that the 
records kept under 40 CFR 75.57(h) for missing data events satisfy the 
recordkeeping requirements of 40 CFR 98.3(g)(4) for those same events. 
We have concluded that, as a practical matter, the missing data records 
required to be kept under 40 CFR 75.57(h) are substantially equivalent 
to the records required under 40 CFR 98.3(g)(4).
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Making separate reporting of biogenic emissions optional 
for part 75 units in the 2010 reporting year and mandatory every year 
thereafter. See sections II.C and II.G of this preamble.
     Adding a provision to subpart D to clarify how to 
calculate and report biogenic CO2 emissions, referencing the 
applicable methods in 40 CFR 98.33(e) and the reporting requirements in 
40 CFR 98.3(c)(4) and (c)(12).
2. Summary of Comments and Responses
    No significant comments were received on the specific technical 
amendments to subpart D. Comments related to the proposed separate 
reporting of biogenic emissions for units subject to 40 CFR part 75 can 
be found in Sections II.C and II.G of this preamble.

I. Subpart F--Aluminum Production

1. Summary of Final Amendments and Major Changes Since Proposal
    Throughout subpart F we are making corrections as needed for 
typographical errors and alphanumeric sequencing. We are amending 40 
CFR 98.63 to clarify that each perfluorocarbon (PFC) compound 
(perfluoromethane, CF4, also called tetrafluoromethane, and 
perfluoroethane, C2F6, also called 
hexafluoroethane) must be quantified and reported and to clarify in 40 
CFR 98.63(c) that reporters must use CEMS if the process CO2 
emissions from anode consumption during electrolysis or anode baking of 
prebake cells are vented through the same stack as a combustion unit 
required to use CEMS. This requirement existed in the final rule, 
however, the cross-reference was omitted from the introductory language 
of 40 CFR 98.63(c).
    We are amending 40 CFR 98.64 to clarify the type of parameters that 
must be measured in accordance with the recommendations of the EPA/IAI 
Protocol for Measurement of Tetrafluoromethane (CF4) and 
Hexafluoroethane (C2F6) Emissions from Primary 
Aluminum Production (2008), and the frequency of monitoring for those 
parameters that are not measured annually, but are instead measured on 
a more or less frequent basis. We are also inserting dates into this 
paragraph. In inserting these dates, we have decided to use dates in 
reference to the effective date of the 2009 final rule, as opposed to 
the publication date as was written in the final rule. It was 
determined to be more appropriate to use the effective date of the rule 
as the basis for the timing of the requirements. Therefore, we are 
amending the paragraph to read ``December 31, 2010'' in place of ``one 
year after publication of the rule'' and are inserting ``December 31, 
2012'' in place of ``three years after publication of the rule.''
    We are amending Table F-2 to clarify that default CO2 
emissions from pitch volatiles combustion are relevant only for center 
work pre-bake (CWPB) and side work pre-bake (SWPB) technologies.
    We are also amending Table F-1 to spell out the acronyms for the 
technologies covered by that table; i.e., CWPB, SWPB, vertical stud 
S[oslash]derberg (VSS), and horizontal stud S[oslash]derberg (HSS).
    The comments received supported the proposed amendments, so the 
amendments to subpart F are finalized as proposed.
2. Summary of Comments and Responses
    One comment letter was received on this subpart, and it supported 
the proposed amendments. The summary and response to this comment 
letter can be found in the document, ``Response to Comments: Revision 
to Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).

J. Subpart G--Ammonia Manufacturing

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending subpart G to remove reporting of the waste recycle 
stream or

[[Page 79119]]

purge, and to make subpart G conform to the amendments to the 
calibration requirements in subpart A. With respect to the waste 
recycle stream, we are eliminating the calculation, monitoring and 
reporting of the emissions associated with the waste recycle stream or 
purge currently required by Equation G-6 from 40 CFR 98.73, 98.74, 
98.75, and 98.76. Carbon dioxide emissions from waste recycle stream or 
purge gas used as fuel will still be accounted for accurately using 
Equation G-5 in subpart G. Because total process emissions, calculated 
using Equation G-5, will also account for emissions associated with use 
of the purge gas as a fuel, we are amending 40 CFR 98.72(b) so that 
subpart C does not apply to CO2 emissions resulting from the 
use of purge gas as a fuel.
    We are clarifying in 40 CFR 98.72(a) and in the definition of 
CO2 in Equation G-5 that CO2 process emissions 
reported under this subpart may include CO2 that is later 
consumed on site for urea production and therefore is not released to 
the ambient air from the ammonia manufacturing process unit. We have 
included this clarification because although the equations accurately 
reflect total CO2 that is generated from the ammonia 
manufacturing process, not all of that CO2 is released on 
site. Rather, some of the CO2 may be used for urea 
production and not be actually released to the atmosphere until use of 
the urea at an off-site location.
    We are amending 40 CFR 98.74(d) to limit the flow meter calibration 
accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) to only meters 
that are used to measure liquid and gaseous feedstock volumes. In 
accordance with 40 CFR 98.3(i)(1), each measurement device that is not 
used to measure liquid and gaseous feedstock volumes, but is used to 
provide data for the GHG emissions calculations, will have to be 
calibrated to an accuracy within the appropriate error range for the 
specific measurement technology, based on an applicable operating 
standard, such as the manufacturer's specifications.
    We are amending the definition of CO2 emissions in 
Equation G-5 to indicate that the CO2 emissions estimates 
under subpart G may include CO2 that is later consumed on 
site for urea production and therefore not released to the atmosphere 
from the ammonia manufacturing process unit. This change does not 
affect the total CO2 emissions that are quantified and 
reported to EPA under the calculation equations in 40 CFR 98.73. 
Likewise, we are amending 40 CFR 98.76(b) to require reporting of the 
CO2 from the ammonia manufacturing process unit that is then 
used to produce urea and the method used to determine that quantity of 
CO2 consumed.
    In addition, we are amending subpart G to correct several 
typographical errors and an incorrect cross-reference to another 
subpart in 40 CFR part 98. We are correcting the terms and definitions 
for annual CO2 emissions arising from gaseous, liquid, and 
solid fuel feedstock consumption in Equations G-1, G-2, and G-3, 
respectively, in 40 CFR 98.73. We are correcting 40 CFR 98.76(a) by 
changing the cross-reference from ``Sec.  98.37(e)(2)(vi)'' to ``Sec.  
98.37.''
    We are amending the data reporting requirements in 40 CFR 
98.76(b)(6) and (15) for consistency with the calculation procedures in 
40 CFR 98.73(b)(6). We are amending 40 CFR 98.76(b)(6) to change 
``petroleum coke'' to ``feedstock'' because petroleum coke is the 
incorrect term, and amending 40 CFR 98.76(b)(15) to specify that the 
carbon content analysis method being reported is for each month. We are 
also removing 40 CFR 98.76(b)(17) for the reporting of urea produced, 
if known, as well as reporting requirements in 40 CFR 98.76(c) for 
total pounds of synthetic fertilizer produced and total nitrogen 
contained in that fertilizer.
    No major changes have been made to the amendatory language since 
proposal.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter was supportive of all proposed amendments to 
subpart G. However, we received adverse comments on the proposed 
amendment to remove requirements to report the total quantity of 
synthetic fertilizer produced and the nitrogen content of fertilizer. 
The commenter asserted that EPA does not offer a reason for the 
deletion of fertilizer reporting requirements, and noted that synthetic 
fertilizer application drives a large fraction of N2O 
emissions from agricultural soils. They asserted that the reporting 
requirements should be retained for several reasons, including that 
collecting information for N2O emissions, even if it is from 
less than one-half of the total fertilizer produced, is valuable. 
Further, the commenter contended that justifying removal of the 
reporting requirement because of the availability of other data through 
the Association of American Plant Food Control Officials is not 
appropriate because those other data may not be available reliably into 
the future and do not map emissions back to specific facilities. They 
argued that reporting of synthetic fertilizer production is a good 
first step in estimating N2O emissions from agricultural 
soils.
    Another commenter countered many of the points raised above, 
asserting that data on domestic synthetic fertilizer production is not 
a good indicator of N2O emissions from farming because the 
rule did not capture all fertilizer production and not all fertilizer 
is applied to fields.
    Response: EPA has finalized, as proposed, the amendment to remove 
reporting requirements of the total amount of synthetic fertilizer 
produced and nitrogen contained in that fertilizer. EPA has concluded 
that the burden placed on fertilizer production facilities to report on 
total pounds of synthetic fertilizer and total nitrogen contained in 
that fertilizer would not be commensurate with the value of the data we 
would receive in terms of improving our ability to estimate 
N2O emissions from soils. Specifically, facility specific 
data from producers on the nitrogen content of synthetic fertilizer is 
of minimal value in estimating soil N2O emissions by itself. 
As explained in the proposal preamble (75 FR 48767), there are a 
variety of inputs that would be valuable to consider to estimate 
N2O emissions from agricultural soils, including fertilizer 
application rates, timing of application, and the use of slow release 
fertilizers and nitrification/release inhibitors, none of which would 
be provided through the provision removed from the rule. Given that the 
information required from the final rule would not provide sufficient 
information to estimate N2O emissions from fertilizer 
application to soils, we are removing the reporting requirement at this 
time. While there is concern over the potential future loss of the 
Association of American Plant Food Control Officials data, EPA has 
determined that it is preferable to remove the incomplete reporting 
requirement at this time and, if appropriate in the future, reconsider 
in a comprehensive manner reporting of information on fertilizer 
production, import and use practices.

[[Page 79120]]

K. Subpart P--Hydrogen Production

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending the definition of the terms for the average carbon 
content (CCn) and molecular weight (MWn) in 
Equation P-1 of 40 CFR 98.163 to clarify that, where measurements are 
taken more frequently than monthly, CCn and MWn 
should be calculated using the arithmetic average of measurement values 
within the month.
    We are amending 40 CFR 98.164(b)(1) so it is consistent with 
today's amendments to 40 CFR 98.3(i). First, we are limiting the flow 
meter calibration accuracy requirements of 40 CFR 98.3(i)(2) and (i)(3) 
to meters that are used to measure liquid and gaseous feedstock 
volumes. In accordance with 40 CFR 98.3(i)(1), all other measurement 
devices that are used to provide data for the GHG emissions 
calculations have to be calibrated only to an accuracy within the 
appropriate error range for the specific measurement technology, based 
on an applicable operating standard, such as the manufacturer's 
specifications. Second, we are removing the requirements for solids 
weighing equipment and oil tank drop measurements to be calibrated 
according to 40 CFR 98.3(i), because the provisions of 40 CFR 98.3(i) 
apply only to gas and liquid flow meters. For oil tank drop 
measurements, the QA requirements of 40 CFR 98.34(b)(2) apply.
    As a harmonizing amendment with the amendment allowing the use of a 
gas chromatograph (described in 40 CFR 98.164(b)(5)), we are adding the 
phrase ``no less frequent'' to 40 CFR 98.164(b)(2). This change 
indicates that when determining the carbon content and the molecular 
weight of ``other gaseous fuels and feedstocks'' (e.g., biogas, 
refinery gas, or process gas), you must undertake sampling and analysis 
no less frequently than weekly. Replacing a ``weekly'' requirement with 
``no less frequent than weekly'' allows for the use of continuous, on-
line equipment gas chromatographs.
    We are amending 40 CFR 98.164(b)(5) to allow the use of 
chromatographic analysis of the fuel, provided that the gas 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Modification of Equation P-1 to account for measurements 
taken more frequently than monthly to determine the molecular weight of 
the gaseous fuel and feedstock.
     Inclusion of the option to use a gas chromatograph (both 
continuous and non-continuous) for determining the carbon content and 
molecular weight of gaseous fuels.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter noted that the fuels and feedstocks to a 
hydrogen plant subject to subpart P requirements are often the same 
fuels that are burned in combustion units subject to subpart C 
requirements. The commenter further noted that both subparts had 
different monitoring and QA/QC requirements which would pose a problem 
for a facility trying to determine which method to use.
    Response: No change has been made as a result of this comment. We 
did not receive sufficient information from the commenter as to why 
they would not be able to comply using the methods already prescribed 
in subpart P for determining carbon content and molecular weight. As 
noted by the commenter, facilities only subject to subpart C must use a 
method published by a consensus standards organization if such a method 
exists, or an industry consensus standard practice. Therefore, the 
methods in the 2009 final rule for subpart P could be used to meet the 
requirements in subpart C. We determined that it was appropriate to 
open the methods to industry consensus standards or industry standard 
practices for facilities subject to subpart C only, because the 
industries covered by subpart C could be wide ranging and the specific 
methods listed may not be appropriate for certain industry types. 
Because the commenter does not provide specific concerns as to why the 
methods listed in subpart P are not appropriate, we have decided not to 
remove the applicable methods listed in subpart P and replace them with 
the option to use consensus based standards or industry consensus 
standards.
    Comment: One commenter requested that EPA allow the use of gas 
chromatographs as an alternative method for determining the carbon 
content in gaseous fuels and feedstocks.
    Response: EPA acknowledges the commenter's recommendation to 
include the option to use gas chromatographs for measuring the carbon 
content and molecular weight of fuels and feedstocks in subpart P. As a 
result, EPA has revised the monitoring and QA/QC requirements to allow 
the use of gas chromatographs, both continuous and non-continuous, to 
determine the carbon content and molecular weight of fuels and 
feedstocks provided that the gas chromatograph is operated, maintained, 
and calibrated according to the manufacturer's instructions.

L. Subpart V--Nitric Acid Production

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.226 to remove the synthetic fertilizer 
and total nitrogen reporting requirement in 40 CFR 98.226(o). The 
detailed rationale for this amendment is provided in Section II.J of 
this preamble.
2. Summary of Comments and Responses
    Several comments were received on the proposal to remove the 
synthetic fertilizer and total nitrogen reporting requirement in 40 CFR 
98.226(o). Please see section II.J (Ammonia Production) of this 
preamble for the comments and responses related to reporting of 
fertilizer production data.

M. Subpart X--Petrochemical Production

1. Summary of Final Amendments and Major Changes Since Proposal
    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart X for petrochemical production 
facilities. The issues being addressed by the amendments include the 
following:
     Distillation and recycling of waste solvent.
     Process vent emissions monitored by CEMS.
     Process off-gas combustion in flares.
     CH4 and N2O emissions from 
combustion of process off-gas.
     Molar volume conversion (MVC) factors.
     Methodology for small ethylene off-gas streams.
     Monitoring and QA/QC requirements.
     Reporting requirements under the CEMS compliance option.

[[Page 79121]]

     Reporting requirements for the ethylene-specific option.
     Reporting measurement device calibrations.
     For the mass balance option, sampling frequency when 
receiving multiple deliveries from same supply source.
    Distillation and recycling of waste solvent. We are adding a new 
paragraph, as proposed, to 40 CFR 98.240(g) to specify that a process 
that distills or recycles waste solvent that contains a petrochemical 
is not part of the petrochemical production source category.
    Process vent emissions monitored by CEMS. We are adding a sentence, 
as proposed, to 40 CFR 98.242(a)(1) that specifies CO2 
emissions from process vents routed to stacks that are not associated 
with stationary combustion units must be reported under subpart X when 
you comply with the CEMS option in 40 CFR 98.243(b).
    Process off-gas combustion in flares. We are amending 40 CFR 
98.242(b), as proposed, by removing the reference to flares.
    CH4 and N2O emissions from combustion of 
process off-gas. We are amending 40 CFR 98.243(b), as proposed, to 
clarify that either the default HHV for fuel gas or a site-specific 
calculated HHV may be used when using Tier 3 procedures to calculate 
CH4 and N2O emissions from combustion units that 
burn petrochemical process off-gas and are monitored with a 
CO2 CEMS.
    Sampling frequency for mass balance method. We are amending 40 CFR 
98.243(c)(3) to clarify that when multiple deliveries of a particular 
liquid or solid feedstock are received from the same supply source in a 
month, one representative sample is sufficient for the month. The 
amendment is being made in response to a comment received. As explained 
in section II.M.2 of this preamble, we are amending 40 CFR 98.243(c)(3) 
to make the language in subpart X consistent with a similar amendment 
for fuel sampling in 40 CFR 98.34(b)(3)(ii)(B). The new language does 
not change the requirements in 40 CFR 98.243(c).
    Molar volume conversion (MVC) factors. We are amending Equation X-
1, as proposed, to provide two alternative values of MVC that 
correspond to the two most common standard conditions output by the 
flow monitors. Additionally, the reporting requirements related to this 
equation are being amended, as proposed, to include reporting of the 
standard temperature at which the gaseous feedstock and product volumes 
were determined (either 60 [deg]F or 68 [deg]F) and to afford 
verification of the reported emissions.
    Methodology for small ethylene off-gas streams. We are finalizing 
amendments to 40 CFR 98.243(d), as proposed, to allow the use of Tier 1 
or Tier 2 methods for small flows (in cases where a flow meter is not 
already installed). Specifically, Tier 1 or Tier 2 methods may be used 
for ethylene process off-gas streams that meet either of the following 
conditions:
     The annual average flow rate of fuel gas (that contains 
ethylene process off-gas) in the fuel gas line to the combustion unit, 
prior to any split to individual burners or ports, does not exceed 345 
standard cubic feet per minute (scfm) at 60 [deg]F and 14.7 pounds per 
square inch absolute (psia) and a flow meter is not installed at any 
point in the line supplying fuel gas or at an upstream common pipe.
     The combustion unit has a maximum rated heat input 
capacity of less than 30 mm Btu/hr, and a flow meter is not installed 
at any point in the line supplying fuel gas (that contains ethylene 
process off-gas) or an upstream common pipe.
    As in the proposal, this amendment also specifies how to calculate 
the annual average flow rate under the first condition. Specifically, 
the total flow obtained from company records is to be evenly 
distributed over 525,600 minutes per year. In response to comments we 
are making an editorial change to the introductory paragraph of 40 CFR 
98.243(d) to clarify that the common pipe reporting alternative may be 
used when applicable; the intent of the requirements in this section 
are not changed by this editorial change. We are also making a number 
of other editorial changes to 40 CFR 98.243(d), as proposed, to 
integrate the amended option with the existing requirements. Finally, 
we are amending 40 CFR 98.246(d)(2) and 98.247(c), as proposed, to add 
reporting and recordkeeping requirements that are related to the 
amendments in 40 CFR 98.243(d)(2).
    Monitoring methods for determining carbon content and composition. 
We are finalizing the proposed addition of ASTM D2593-93 (Reapproved 
2009), Standard Test Method for Butadiene Purity and Hydrocarbon 
Impurities by Gas Chromatography, to 40 CFR 98.244(b)(4). We are 
further amending 40 CFR 98.244(b)(4), as proposed, by adding a new 
paragraph that will allow the use of industry standard practice to 
determine the carbon content or composition of carbon black feedstock 
oils and carbon black products.
    We also added two more published methods to the list in 40 CFR 
98.244(b)(4) of the final rule: ASTM D7633, Standard Test Method for 
Carbon Black--Carbon Content, and EPA Method 9060A in EPA publication 
SW-846, Test Methods for Evaluating Solid Waste, Physical/Chemical 
Methods. We also added an option, already proposed in subparts C and Y, 
to use results of chromatographic analysis of feedstocks and products, 
provided that the gas chromatograph is operated, maintained, and 
calibrated according to the manufacturer's instructions. Finally, we 
added an option to use results of a mass spectrometer analysis of a 
feedstock or product, provided that the mass spectrometer is operated, 
maintained, and calibrated according to the manufacturer's 
instructions.
    We are also amending 40 CFR 98.244(b)(4), as proposed, to provide 
facilities the option to determine carbon content or composition of 
feedstocks or products using modified versions of the analytical 
methods listed in 40 CFR 98.244(b)(4) if the listed methods are not 
appropriate for reasons noted below. The proposed amendments in this 
section would have allowed the use of ``other analytical methods'' if 
methods listed in 40 CFR 98.244(b)(4) are not appropriate for any of 
the same reasons. However, in response to comments, we revised this 
provision to allow the use of ``other methods'' rather than ``other 
analytical methods'' so that non-analytical methods also can be used. 
The conditions under which the listed methods may be considered 
inappropriate are the same as at proposal. Specifically, a listed 
method may be considered inappropriate if the relevant compounds cannot 
be detected, the quality control requirements are not technically 
feasible, or use of the method will be unsafe.
    We are amending the reporting requirements in 40 CFR 98.246(a)(11), 
as proposed, so that if an alternative method is used, facilities must 
include in the annual report the name or title of the method used and, 
the first time it is used, a copy of the method and an explanation of 
why the use of the alternative method is necessary. Also as proposed, 
the amendments to 40 CFR 98.244(b)(4) may be used for the 2010 
reporting year.
    QA/QC requirements. To maintain consistency with the amendments to 
40 CFR 98.3(i), we are amending, as proposed, the QA/QC provisions for 
weighing devices, flow meters, and tank level measurement devices in 40 
CFR 98.244 (b)(1), (b)(2), and (b)(3).
    Reporting requirements under the CEMS compliance option. As 
proposed, we are making a number of changes in

[[Page 79122]]

40 CFR 98.246(b)(1) through (b)(5) to clarify the reporting 
requirements under the CEMS compliance option.
    First, we are moving the requirement for reporting of the 
petrochemical process ID from 40 CFR 98.246(b)(3) to 40 CFR 
98.246(b)(1) to be consistent with the structure in other reporting 
sections, and we are renumbering the existing paragraphs (b)(1) and 
(b)(2).
    Second, we are adding a statement in the renumbered paragraph 40 
CFR 98.246(b)(2) to specify that the reporting requirements in 40 CFR 
98.36(b)(9)(iii) (as numbered in today's action) for CH4 and 
N2O do not apply under subpart X because applicable 
reporting requirements are specified in 40 CFR 98.246(b)(5).
    Third, in the renumbered 40 CFR 98.246(b)(3), we are deleting the 
requirement to report information required under 40 CFR 
98.36(e)(2)(vii) because the referenced section specifies recordkeeping 
requirements, not reporting requirements. Note that one must still keep 
the applicable records because 40 CFR 98.247(a) references 40 CFR 
98.37, which in turn requires you to keep all of the applicable records 
in 40 CFR 98.36(e). We are also amending the reference to 40 CFR 
98.36(e)(2)(vii) to a more general reference of 40 CFR 98.36. This 
makes the reporting requirements consistent with the methodology for 
calculating emissions in 40 CFR 98.243(b).
    Fourth, we are amending 40 CFR 98.246(b)(4) to clarify our intent. 
The first sentence in 40 CFR 98.246(b)(4) requires reporting of the 
total CO2 emissions from each stack that is monitored with 
CO2 CEMS; this requirement will be unchanged. We are 
amending the second sentence in 40 CFR 98.246(b)(4) to clarify that for 
each CEMS that monitors a combustion unit stack, you must estimate the 
fraction of the total CO2 emissions that is from combustion 
of the petrochemical process off-gas in the fuel gas. This estimate 
will give an indication of the total petrochemical process emissions, 
whereas the CEMS data alone will also include emissions from combustion 
of supplemental fuel (if any).
    Finally, as proposed, we are finalizing several amendments to 40 
CFR 98.246(b)(5). In general, as noted above, the requirements in this 
paragraph are consistent with the requirements in 40 CFR 
98.36(b)(9)(iii) (as numbered in this action). Most of the amendments 
to 40 CFR 98.246(b)(5) restate requirements from 40 CFR 
98.36(b)(9)(iii); for example, the amendments clarify that emissions 
are to be reported in metric tons of each gas and in metric tons of 
CO2e. However, because 40 CFR 98.36(b)(9)(iii) allows you to 
consider petrochemical process off-gas as a part of ``fuel gas'' rather 
than as a separate fuel, under 40 CFR 98.246(b)(5) you must also 
estimate the fraction of total CH4 and N2O 
emissions in the exhaust from each stack that is from combustion of the 
petrochemical process off-gas. In addition, because 40 CFR 98.243(b) 
requires you to determine CH4 and N20 emissions 
using Equation C-8 in subpart C (rather than Equation C-10), the 
amendments to 40 CFR 98.246(b)(5) require reporting of the HHV that you 
use in Equation C-8. We are also deleting the erroneous reference to 
Equation C-10 that was included in 40 CFR 98.246(b)(5).
    Reporting requirements for the ethylene-specific option. As 
proposed, we are finalizing several amendments to clarify the reporting 
requirements in 40 CFR 98.246(c) for the combustion-based methodology 
that is available to the ethylene-specific option. First, we are adding 
a requirement to report each ethylene process ID to allow 
identification of the applicable process units at facilities with more 
than one ethylene process unit. Second, we are making editorial changes 
to clarify that you must estimate the fraction of total combustion 
emissions that is due to combustion of ethylene process off-gas, 
consistent with the requirements described above for combustion units 
that are monitored with CEMS. Third, we are replacing the requirement 
to report the ``annual quantity of each type of petrochemical produced 
from each process unit'' with a requirement to report the ``annual 
quantity of ethylene produced from each process unit.''
    Reporting measurement device calibrations. As proposed in 40 CFR 
98.246(a)(7) we are deleting the requirement for reporting of the dates 
and summarized results of calibrations of each measurement device under 
the mass balance option, and we are also adding 40 CFR 98.247(b)(4) to 
require retention of these records.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Additional methods for determining carbon content or 
composition of feedstocks and products were added to 40 CFR 
98.244(b)(4).
     For the optional combustion method for ethylene processes, 
the introductory paragraph in 40 CFR 98.243(d) was edited to require 
calculation of GHG emissions from ``combustion units'' rather than from 
``each combustion unit.'' This change makes it clear that the common 
pipe reporting alternative specified in 40 CFR 98.36(c)(3) of subpart C 
may be used when applicable, and it makes 40 CFR 98.243(d) consistent 
with the reporting requirements for the ethylene process option as 
specified in 40 CFR 98.246(c).
     For the mass balance option, 40 CFR 98.243(c)(3) was 
revised to specify that multiple deliveries of a particular liquid or 
solid feedstock in a month from the same supply source may be 
considered a single feedstock lot, requiring only one representative 
sample for carbon content analysis. This change makes the analysis 
requirements for feedstocks consistent with the amended requirements 
for fuels in 40 CFR 98.34(b)(3)(ii)(B).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Several commenters requested either the addition of 
specific carbon content or composition measurement methods in 40 CFR 
98.244(b)(4) or other changes that would increase measurement 
flexibility. One commenter requested that EPA Method 9060 of SW-846 be 
added to the list of methods, and that the list of methods be modified 
to allow for the use of a company-specific method for measuring 
acetonitrile as an alternative to using EPA Method 8015 in SW-846. One 
commenter requested that ASTM D7633, Standard Test Method for Carbon 
Black--Carbon Content, be added to the list of methods because it has 
recently been accepted and approved by ASTM. This commenter also noted 
that ASTM is currently reviewing a method for carbon content in carbon 
black feedstock oils and requested addition of a statement indicating 
that once this method is approved and assigned an official number by 
ASTM that it is effective as of January 1, 2010. One commenter 
requested that EPA remove the reference to ``analytical'' in the phrase 
``other analytical methods'' in proposed 40 CFR 98.244(b)(4)(xiii) 
(renumbered as paragraph (xv)(A) in the final amendments) so that the 
carbon content of ethylene oxide and water solutions

[[Page 79123]]

could be measured using a densitometer. One commenter stated that 40 
CFR 98.244(b)(4) should be expanded to allow the use of an on-line mass 
spectrometer to determine the carbon content and molecular weights. One 
commenter stated that requirements for gas chromatography should be 
consistent across all subparts and that EPA should extend the 
requirements for the use of gas chromatographs under subpart C to 
subpart X. Specifically, the commenter requested that the use of gas 
chromatographs be allowed, ``provided that the gas chromatograph is 
operated, maintained, and calibrated according to the manufacturer's 
instructions.'' One commenter noted that the proposed amendments to 
subpart C added flexibility to the carbon content analysis requirements 
for fuels by eliminating the list of specific methods and instead 
allowing a broader array of methods (i.e., industry consensus standard 
practice, method published by a consensus-based standards organization, 
or results of gas chromatographic analysis). This commenter stated that 
the same flexibility should be allowed for feedstock and product 
analysis under subpart X.
    Response: In the preamble to the proposed amendments we indicated 
that we would consider adding carbon content methods for carbon black 
and carbon black feedstock oil if they were approved by ASTM before 
publication of the final amendments. Because it has been approved by 
ASTM, we have added Method D7633, Standard Test Method for Carbon 
Black--Carbon Content, to 40 CFR 98.244(b)(4). We have not added the 
requested statement regarding the method for determining carbon content 
in carbon black feedstock oil because we cannot cite a specific method 
without being able to incorporate it by reference, and incorporation by 
reference is possible only if a copy of the method is available. 
However, if this method is a current industry standard practice, its 
use since January 1, 2010, is allowed by 40 CFR 98.244(b)(4)(xv) of the 
final amendments.
    We have also decided to make four of the other changes suggested by 
commenters. First, we have added EPA Method 9060A in SW-846 because a 
commenter indicated that it is much more effective at detecting organic 
compounds in a liquid waste stream than any of the listed methods. 
Because none of the currently listed methods effectively detect these 
compounds in the waste stream, an alternative method such as EPA Method 
9060A in SW-846 would already be allowed under 40 CFR 
98.244(b)(4)(xv)(A) of the final amendments. However, specifically 
listing the method will make demonstrating compliance more 
straightforward.
    Second, we have deleted the word ``analytical'' from the phrase 
``other analytical methods'' in 40 CFR 98.244(b)(4)(xv)(A) of the final 
amendments so that non-analytical methods can be used. We agree with 
the commenter that this change is needed so that a densitometer can be 
used to determine the carbon content in an ethylene oxide and water 
solution. We also agree that a non-analytical alternative must be 
available in cases where the carbon content of the solution cannot 
safely be determined using any of the listed analytical methods or 
modifications of them.
    Third, we have added the option from subpart C to use results from 
a gas chromatograph, provided the instrument is operated, maintained, 
and calibrated according to the manufacturer's instructions. This 
change means there is a common option in both subparts C and X, which 
we have determined is important because some materials may be a fuel in 
some applications and a petrochemical feedstock in others (e.g., 
ethylene feedstocks). With this change, a facility would not have to 
use two methods to determine the carbon content of the same material.
    Fourth, we have added an option to use a mass spectrometer to 
determine the carbon content of a feedstock or product. Although a mass 
spectrometer would more commonly be used as one type of detector to 
determine the concentration of individual compounds separated in a gas 
chromatograph, using a mass spectrometer alone to determine the overall 
carbon content is also acceptable.
    Finally, we have decided not to delete the list of specified 
methods and replace them with a general statement allowing the use of 
any industry consensus standard practice or method published by a 
consensus-based standards organization. We have received considerable 
input from the industry on methods that are actually being used. We 
conclude that the existing flexibility in the final amendments is 
sufficient, and that there is no need to allow the use of other 
unspecified methods. We recognize that this is not consistent with the 
methodologies allowed for determining carbon content in subpart C; 
however, we have concluded that this is justified given the wide 
variety of industries subject to subpart C versus the more narrowly-
focused sources subject to subpart X.
    We are not specifically allowing the use of a company-specific 
method for the determination of carbon content in acetonitrile because 
we are not convinced that it is necessary. The commenter indicated that 
they can use EPA Method 8015 of SW-846, and they have not indicated any 
problems with using this method. It is also possible that their 
company-specific method would qualify as a modification to a listed 
method that would be allowed if any of the criteria in 40 CFR 
98.244(b)(4)(xv)(A) of the final amendments are met. Therefore, we have 
not made the requested change.
    Comment: One commenter requested a modification to 40 CFR 
98.243(c)(3) for carbon black production processes that specifies all 
deliveries of a fuel or feedstock oil in a month from the same supply 
source are considered to be a fuel lot, and carbon content must be 
determined for only one representative sample from the lot.
    Response: Although we did not propose amendments to the sampling 
and analysis requirements in 40 CFR 98.243(c)(3), we did propose a 
change similar to that suggested by the commenter in 40 CFR 
98.34(b)(3)(ii)(B) of subpart C for fuels. Subpart X currently requires 
you to determine the carbon content for at least one sample of each 
feedstock and product per month. In addition, if you make more than one 
valid carbon content measurement during the month (from separate 
samples), then you must average the results arithmetically. (Note that 
this language does not require sampling and analysis for each delivery 
of a feedstock. Furthermore, each delivery of the same material, even 
from different suppliers, is not considered to be a separate 
feedstock.) However, we agree with the commenter that if multiple 
deliveries of the same feedstock are received from the same supply 
source, one representative sample is sufficient for the month. 
Therefore, we have amended 40 CFR 98.243(c)(3) in the interest of 
improving the operating flexibility of the rule. We have also broadened 
the statement so that it applies for any liquid or solid feedstock. 
Please see the amended rule language to 40 CFR 98.243(c)(3).
    Comment: One commenter stated that the proposed term ``each 
combustion unit'' in the introductory paragraph of 40 CFR 98.243(d) 
appears to preclude the use of the common pipe reporting alternative in 
40 CFR 98.36(c)(3). According to the commenter, the common pipe option 
is appropriate for ethylene processes, and precluding it will not 
improve the quality of GHG emission estimates. Therefore, the

[[Page 79124]]

commenter requests that ``each combustion unit'' be changed to 
``combustion units.''
    Response: We have made the suggested change in the final amendments 
because we agree with the commenter's assessment of the proposed 
language. We did not intend to preclude the use of the common pipe 
option, as evidenced by the fact that 40 CFR 98.243(d)(2)(i) and (ii) 
both specify that the determination of when Tier 1 and Tier 2 
procedures may be used is to be based on whether there is an existing 
flow meter either in the line to the combustion device or an upstream 
common pipe. Moreover, the reporting requirements in 40 CFR 
98.246(c)(2) require reporting for each stationary combustion unit, or 
group of stationary sources with a common pipe.

N. Subpart Y--Petroleum Refineries

1. Summary of Final Amendments and Major Changes Since Proposal
    Numerous issues have been raised by owners and operators in 
relation to the requirements in subpart Y for petroleum refineries. The 
issues being addressed by the amendments include the following:
     GHG emissions from flares.
     GHG emissions to report from combustion of fuel gas.
     GHG emissions to report from non-merchant hydrogen 
production process units.
     Calculating GHG emissions from fuel gas combustion.
     Calculating combustion GHG emissions from flares and 
asphalt blowing operations controlled by thermal oxidizer or flare.
     Molar volume conversion factors.
     Combined stacks monitored by CEMS.
     Nitrogen concentration monitoring to determine exhaust gas 
flow rate.
     Calculating CO2 emissions from catalytic 
reforming units.
     Calculating GHG emissions from sulfur recovery plants.
     Calculating CO2 emissions from coke calcining 
units.
     Calculating CO2 emissions from process vents.
     Monitoring and QA/QC requirements.
     Reporting requirements.
    GHG emissions from flares. We are finalizing corrections to 40 CFR 
98.252(a) (GHGs to report) as proposed to clarify the required 
emissions methods for flares. We are proposing to amend the second 
sentence in 40 CFR 98.252(a) to correctly require reporters to 
``Calculate and report the emissions from stationary combustion units 
under subpart C * * *'' and we are proposing to add an additional 
sentence at the end of this section to clarify that reporters must 
``Calculate and report the emissions from flares under this subpart.''
    GHG emissions to report from combustion of fuel gas. We are 
finalizing amendments to 40 CFR 98.252(a) as proposed to clarify that 
reporting of CH4 and N2O emissions is required 
for the stationary combustion units fired with fuel gas. As described 
in Section II.G of this preamble, we are also amending the definition 
of fuel gas.
    GHG emissions to report from non-merchant hydrogen production 
process units. As proposed, we are amending 40 CFR 98.252(i) to clarify 
that reporting of only CO2 emissions is required for non-
merchant hydrogen production process units.
    Calculating GHG emissions from fuel gas combustion. We are 
finalizing amendments to 40 CFR 98.252(a), as proposed, so that 
petroleum refineries subject to subpart Y can use the Tier 1 or 2 
methodologies in subpart C for combustion of fuel gas when either of 
the following conditions exists:
 The annual average fuel gas flow rate in the fuel gas line to 
the combustion unit, prior to any split to individual burners or ports, 
does not exceed 345 scfm at 60 [deg]F and 14.7 psia, and either of the 
following conditions exists:
    --A flow meter is not installed at any point in the line supplying 
fuel gas or an upstream common pipe; or
    --The fuel gas line contains only vapors from loading or unloading, 
waste or wastewater handling, and remediation activities that are 
combusted in a thermal oxidizer or thermal incinerator.
 The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr, and either of the following conditions exists:
    --A flow meter is not installed at any point in the line supplying 
fuel gas or an upstream common pipe; or
    --The fuel gas line contains only vapors from loading or unloading, 
waste or wastewater handling, and remediation activities that are 
combusted in a thermal oxidizer or thermal incinerator.

    Calculating combustion GHG emissions from flares and asphalt 
blowing operations controlled by thermal oxidizer or flare. As 
proposed, we are finalizing amendments to 40 CFR 98.253 to renumber 
existing Equations Y-1 and Y-16 as Equations Y-1a and Y-16a, and adding 
the more detailed Equations Y-1b and Y-16b that provide more detailed 
alternative methods for calculating emissions. We are also finalizing 
corresponding amendments in 40 CFR 98.256 as proposed to require 
reporting of which equation was used and, if the new equations are 
used, reporting of the additional equation parameters.
    Molar volume conversion factors. We are finalizing amendments to 
Equations Y-1, Y-3, Y-6, Y-12, Y-18, Y-19, Y-20, and Y-23 in subpart Y 
as proposed to provide two alternative values of MVC depending on the 
standard conditions output by the flow monitors. For reasons outlined 
in the ``Response to Comments: Revision to Certain Provisions of the 
Mandatory Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-
0508), we are also finalizing a similar amendment to Equation Y-2, as a 
logical outgrowth of the proposal and comments received to provide two 
alternative values of MVC in this equation (if mass flow monitors are 
used) depending on the standard conditions at which the higher heating 
value is determined. Additionally, the reporting requirements related 
to each of these equations are being amended to include reporting of 
the value of MVC used to support the calculations and to allow 
verification of the reported emissions.
    Combined stacks monitored by CEMS. As proposed, we are amending the 
language in 40 CFR 98.253(c)(1)(ii) and also the reporting requirements 
in 40 CFR 98.256(f)(6) to generalize the language to include other 
CO2 emission sources, not just a CO boiler.
    Nitrogen concentration monitoring to determine exhaust gas flow 
rate. As proposed, we are amending 40 CFR 98.253(c)(2)(ii) to renumber 
Equation Y-7 as Equation Y-7a and to add an Equation Y-7b to provide an 
alternative N2 concentration monitoring approach for 
determining the exhaust gas flow rate. We are also finalizing reporting 
requirements in 40 CFR 98.256(f)(9) to report the input parameters for 
Equation Y-7b if it is used.
    Calculating CO2 emissions from catalytic reforming units. We are 
finalizing amendments to the definition of the coke burn-off quantity, 
CBQ, and the term ``n'' in Equation Y-11 in 40 CFR 
98.253(e)(3) as proposed to clarify the application of Equation Y-11 to 
continuously regenerated catalytic reforming units.
    Calculating GHG emissions from sulfur recovery plants. We are 
amending 40 CFR 98.253(f) as proposed to add ``and for sour gas sent 
off site for sulfur recovery'' to clarify that this calculation 
methodology applies ``For on-site sulfur recovery plants and for sour 
gas sent off site for sulfur recovery, * * *'' and to

[[Page 79125]]

allow non-Claus sulfur recovery plants to alternatively follow the 
requirements in 40 CFR 98.253(j) for process vents. We also are 
finalizing amendments to the reporting requirements in 40 CFR 98.256(h) 
as proposed to include the type of sulfur recovery plant, an indication 
of the method used to calculate CO2 emissions, and reporting 
requirements for non-Claus sulfur recovery plants that elect to follow 
the requirements in 40 CFR 98.253(j) for process vents.
    Calculating CO2 emissions from coke calcining units. We are 
amending the definition of Mdust (the mass of dust collected 
in the dust collection system) in Equation Y-13 in 40 CFR 98.253(g) as 
proposed to clarify that dust recycled back to the coke calciner is not 
included in the mass of dust collected in the dust collection system 
(Mdust). We also are finalizing amendments to 40 CFR 
98.256(i)(5), as proposed, to require facilities that use Equation Y-13 
to indicate whether or not the collected dust is recycled to the coke 
calciner.
    Calculating CO2 emissions from process vents. We are finalizing 
amendments to the process vent requirements in 40 CFR 98.253(j) as 
proposed to account for the additional sources that may elect to use 
Equation Y-19, specifically non-Claus sulfur recovery units (as 
previously described) and uncontrolled blowdown vents (inadvertently 
not referenced). We are also amending the reporting requirements for 
process vents in 40 CFR 98.256(l) as proposed to clarify that the 
requirements apply to each process vent, and 40 CFR 98.256(l)(5) to 
require an indication of the measurement or estimation method for the 
volumetric flow rate and the mole fraction of the GHG in the vent.
    Finally, we are finalizing amendments to 40 CFR 98.253(n) as 
proposed to delete the words ``equilibrium'' and ``product-specific'' 
to clarify that the true vapor phase of the loading operation system 
should be used when determining whether the vapor-phase concentration 
of methane is 0.5 volume percent or more.
    Monitoring and QA/QC requirements. We are finalizing amendments to 
the monitoring and QA/QC requirements in subpart Y, 40 CFR 98.254 as 
proposed, except as provided below. We proposed amendments to require 
all gas flow meters on process vents subject to reporting under 40 CFR 
98.253(j) to comply with the monitoring requirements in 40 CFR 
98.254(f). However, for the reasons set forth in the Response to 
Comments (Section N.2. of this preamble), we are finalizing amendments 
for gas flow meters on process vents subject to reporting under 40 CFR 
98.253(j) to comply with the monitoring requirements in 40 CFR 
98.254(c).
    A summary of the amendments to the monitoring and QA/QC 
requirements that we are finalizing as proposed is below. Paragraph (a) 
of 40 CFR 98.254 is amended to include also the phrase ``sources that 
use a CEMS to measure CO2 emissions according to subpart C 
of this part * * *'' to separate further these sources from those that 
are covered by 40 CFR 98.254(b). We also are re-wording the phrase 
``follow the monitoring and QA/QC requirements in Sec.  98.34'' with 
``meet the applicable monitoring and QA/QC requirements in Sec.  
98.34'' to clarify that the monitors must meet the requirements for the 
specific tier for which monitoring was required (Tier 3 sources will 
comply with the Tier 3 requirements; Tier 4 sources will comply with 
the Tier 4 requirements; etc.).
    Because the QA/QC requirements for CO2 CEMS that were 
formerly included in 40 CFR 98.254(l) will be included in the amended 
paragraph 40 CFR 98.254(a), we are removing 40 CFR 98.254(l).
    Paragraph (b) of 40 CFR 98.254 is amended to clarify that these 
requirements apply to gas flow meters, gas composition monitors, and 
heating value monitors other than those subject to 40 CFR 98.254(a). We 
are correcting the reference to ``paragraphs (c) through (e)'' to 
correctly reference ``paragraphs (c) through (g)'' as gas monitoring 
system requirements are specified in 40 CFR 98.254(c) through (g). We 
are also clarifying that the calibration requirements in 40 CFR 98.3(i) 
only apply to gas flow meters and allowing recalibration of gas flow 
meters biennially (every two years), at the minimum frequency specified 
by the manufacturer, or at the interval specified by the industry 
consensus standard practice used. Paragraph (b) of 40 CFR 98.254 is 
also amended to clarify that gas composition and heating value monitors 
must be recalibrated either annually, at the minimum frequency 
specified by the manufacturer, or at the interval specified by the 
industry consensus standard practice used.
    Paragraph (c) of 40 CFR 98.254 is amended to clarify that the flare 
or sour gas flow meters must be calibrated (in addition to operated and 
maintained) using either a method published by a consensus-based 
standards organization (e.g., ASTM, API, etc.) or the procedures 
specified by the flow meter manufacturer. The 5 percent 
accuracy specification is being removed from 40 CFR 98.254(c). We are 
also amending 40 CFR 98.254(c) by removing the list of methods as this 
is redundant to the existing phrase, ``a method published by a 
consensus-based standards organization.''
    Paragraphs (d) and (e) of 40 CFR 98.254 are amended to allow the 
use of any chromatographic analysis to determine flare gas composition 
and high heat value, as an alternative to the methods listed in 40 CFR 
98.254(d) and (e), provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer's 
instructions. The methods used for operation, maintenance, and 
calibration of the gas chromatograph must be documented in the written 
monitoring plan for the unit under 40 CFR 98.3(g)(5). Paragraph (d) in 
40 CFR 98.254 is also amended to apply to all gas composition monitors, 
other than those included in 40 CFR 98.254(g), and not just flare gas 
composition monitors.
    We are also amending 40 CFR 98.254(d) to specify that the methods 
in this paragraph are also to be used for determining average molecular 
weight of the gas, which is needed in Equations Y-1a and Y-3. We are 
also adding an additional method (ASTM D2503-92) to this section for 
determining average molecular weight.
    We are making a number of amendments to 40 CFR 98.254(f). The term 
``exhaust gas flow meter'' is replaced with the term ``gas flow 
meter,'' as proposed.
    We are retaining 40 CFR 98.254(f)(3) and portions of 40 CFR 
98.254(f)(1) but only as general, supplementary guidelines for flow 
monitor installation and operation. Thus, we are amending 40 CFR 98.254 
to require that reporters must do all of the following:
     Install, operate, calibrate, and maintain each stack gas 
flow meter according to the requirements in 40 CFR 63.1572(c);
     Locate the flow monitor at a site that provides 
representative flow rates (avoiding locations where there is swirling 
flow or abnormal velocity distributions); and
     Use a monitoring system capable of correcting for the 
temperature, pressure, and moisture content to output flow in dry 
standard cubic feet (standard conditions as defined in 40 CFR 98.6).
    We are making a technical correction to 40 CFR 98.254(g) to correct 
the cross-reference from 40 CFR 63.1572(a) to 40 CFR 63.1572(c).
    We are amending 40 CFR 98.254(h) to require calibration of mass 
measurement equipment according to the procedures specified by National 
Institute of Standards and Technology (NIST)

[[Page 79126]]

Handbook 44 or the procedures specified by the manufacturer, and 
removing reference to the calibration requirements in 40 CFR 98.3(i).
    Reporting requirements. This section covers reporting requirements 
that have not been described in previous sections of this preamble.
    We are amending the reporting requirements in 40 CFR 98.256(e)(6) 
and (8) for Equations Y-1 (renumbered to Y-1a) and Y-2, respectively, 
to require reporting of whether daily or weekly measurement periods are 
used, for verification purposes.
    In 40 CFR 98.256(f)(6), 40 CFR 98.256(h)(6), and 40 CFR 
98.256(i)(6), we are amending the references to 40 CFR 98.36(e)(2)(vi) 
to reference 40 CFR 98.36 more generally. This will make the references 
consistent with the associated requirements in 40 CFR 98.253.
    We are amending 40 CFR 98.256(f) to require reporting of the unit-
specific emission factor for CH4 and N2O, if 
used, in the newly designated 40 CFR 98.256(f)(11) and (12), 
respectively.
    We are amending 40 CFR 98.256(i)(8) to make it consistent with the 
information collected in 40 CFR 98.245(i)(7).
    We are also amending 40 CFR 98.256(j)(2) to clarify that the 
reporting requirements for asphalt blowing apply at the unit level.
    We are also amending 40 CFR 98.256(o) to re-organize the reporting 
requirements to separate and clarify the reporting requirement for 
storage tanks used for processing unstabilized crude oil from those 
reporting requirements for other types of storage tanks.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     Amending Equation Y-2 in subpart Y to provide two 
alternative values of MVC in this equation (if mass flow monitors are 
used) depending on the standard conditions at which the higher heating 
value is determined.
     Amending requirements for gas flow meters on process vents 
subject to reporting under 40 CFR 98.253(j) to comply with the 
monitoring requirements in 40 CFR 98.254(c) rather than 40 CFR 
98.254(f).
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional comments received can be found in the document, ``Response 
to Comments: Revision to Certain Provisions of the Mandatory Reporting 
of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter stated that they have identified gas streams 
that would otherwise fit the requirements for the use of the Tier 1 or 
Tier 2 methodologies, as proposed in 40 CFR 98.252(a)(1) and (2), if it 
were not for the fact that they are equipped with flow meters. 
According to the commenter, these streams are not what industry would 
define as ``refinery fuel gas'' but would fall under the realm of 
``fuel gas'' as originally defined in 40 CFR 98.6 in the October 30, 
2009, final Part 98, and in the amended definition. These can include 
streams that are process off-gas or vent gases with properties much 
different from traditional ``refinery fuel gas'' streams and are not 
part of the refinery's fuel gas system. According to the commenter, 
these off-gas streams may not be sampled currently. The commenter 
asserted that many of these streams are difficult to sample (for 
example, because of low pressure) or may present hazardous sampling 
conditions. According to the commenter, the added rigor associated with 
Tier 3 requirements is not justified for the increased safety risk, 
considering the very small contribution of emissions (on the order of 
0.1 percent of a refinery's total greenhouse gas emissions as estimated 
by the commenter).
    Response: The proposed amendments provided limited exclusions to 
the Tier 3 requirement for very small fuel gas lines or combustion 
units that are not equipped with a flow meter. As noted in the preamble 
of the August 11, 2010, proposed amendments, the exclusion was 
specifically targeted to prevent the need to install flow meters for 
these small fuel gas lines. EPA noted that ``[i]f flow meters are in 
place at the process heater or at a common pipe location, we consider 
that the Tier 3 monitoring requirements are reasonable and justified.'' 
(See 75 FR 48772.) The commenter indicated that these gas streams could 
have a significantly different composition than typical refinery fuel 
gas, which suggests the default fuel gas factor would have considerable 
uncertainty for these gas streams, further indicating that Tier 3 
sampling is necessary. While we recognize that there are inherent 
safety issues with sampling any fuel gas streams, the commenter has not 
provided any supporting information for the assertion that sampling 
these ``process off-gas or vent gases'' is more hazardous than other 
fuel gas streams at the refinery. Therefore, we are not expanding the 
proposed exclusion to the Tier 3 methodology for fuel gas lines that 
have a flow meter already installed in the line or upstream common 
pipe. We also note that today's final amendments are not imposing new 
requirements to sample these fuel gas streams; the October 30, 2009, 
final Part 98 already required these fuel gas streams to be sampled for 
carbon content no less than once per calendar week.
    Comment: One commenter objected to the proposed revision of 40 CFR 
98.254(f) to also require exhaust gas flow meters associated with 
process vents (i.e., subject to 40 CFR 98.253(j) requirements) to be 
installed, operated, calibrated and maintained according the Petroleum 
Refineries NESHAP (40 CFR part 63, subpart UUU) requirements in 40 CFR 
63.1572(c). According to the commenter, the Petroleum Refineries NESHAP 
requirements in 40 CFR 63.1572(c) contain provisions that are more 
stringent than the monitoring and QA/QC requirements throughout Part 
98. For example, 40 CFR 63.1572(c) requires each monitoring system to 
have valid hourly average data from at least 75 percent of the hours 
during which the process operated and to complete a minimum of one 
cycle of operation for each successive 15-minute period with a minimum 
of four successive cycles of operation to have a valid hour of data (or 
at least two if a calibration check is performed during that hour or if 
the continuous parameter monitoring system is out-of-control). The 
commenter stated that, since the flow monitoring requirements for the 
Petroleum Refineries NESHAP in 40 CFR 63.1572(c) were established to 
demonstrate compliance with emission limits, they should not be used as 
a template for requirements of flow metering for GHG reporting. The 
commenter recommended that the process vent exhaust flow meter 
requirements should be consistent with the requirements in 40 CFR 
98.254(c) for flare and sour gas flow meters.
    Response: We proposed to include the requirements for flow meters 
used to comply with the 40 CFR 98.253(j) for process vents within the 
monitoring provisions of 40 CFR 98.254(f) because these meters are 
exhaust gas flow meters rather than fuel gas flow meters. However, we 
agree with the commenter that the inclusion of flow meters used to 
comply with the 40 CFR 98.253(j) within the monitoring provisions of 40 
CFR 98.254(f) added new requirements

[[Page 79127]]

to these flow meters. While we believe that the flow meter requirements 
in 40 CFR 63.1572(c) of the Petroleum Refineries NESHAP are reasonable 
requirements for exhaust gas flow meters in general (40 CFR 63.1572(c) 
are requirements for parameter monitoring systems, not continuous 
emission monitoring systems), we agree with the commenter that it is 
inappropriate to add these requirements to process vent flow meters at 
this juncture. Furthermore, the provisions in 40 CFR 98.253(j) allow 
use of process knowledge or engineering calculations as an alternative 
to direct flow measurement. As such, it is incongruous to subject 
facilities that have flow meters on these process vents to additional 
requirements when facilities that do not have flow meters on these 
process vents may use process knowledge or engineering calculations. 
Therefore, we are finalizing requirements for flow meters used to 
comply with 40 CFR 98.253(j) for process vents to meet the monitoring 
provisions of 40 CFR 98.254(c) rather than 40 CFR 98.254(f) as was 
required per the October 30, 2009 final Part 98.

O. Subpart AA--Pulp and Paper Manufacturing

1. Summary of Final Amendments and Major Changes Since Proposal
    We are amending 40 CFR 98.273(a)(1), (b)(1) and (c)(1) to clarify 
that owners and operators may choose to use a tier other than Tier 1 
from 40 CFR 98.33 to calculate fossil-fuel based CO2 
emissions.
    We have removed the CO2 emission factors from Table AA-2 
and revised 40 CFR 98.273(c)(1) to direct owners and operators to use 
the CO2 emission factors from Table C-1 of subpart C to 
calculate CO2 emissions from lime kilns.
    With respect to calculating CH4 and N2O 
emissions from fossil fuel combustion at lime kilns, and consistent 
with the amendments to allow use of higher tiers than Tier 1 for units 
subject to subpart AA, we are amending 40 CFR 98.273(a)(2), (b)(2), and 
(c)(2) to allow reporters to also use site-specific high heating 
values, as opposed to default values, when calculating CH4 
and N2O emissions. We are making harmonizing amendments to 
the definition of EF under Equation AA-1 to clarify that default or 
site-specific emission factors may be used. Similarly, we are amending 
40 CFR 98.276(e) to reflect the option to use default or site-specific 
values.
    We are clarifying through this final rule that emissions from the 
combustion of wastewater treatment sludge are calculated using the 
emission factors included in Table C-1. We have determined that this 
sludge falls within the definition of ``Wood and Wood Residuals'' 
included in Table C-1. Therefore, per 40 CFR 98.33(b)(1)(iii), 
emissions from the combustion of this type of sludge may be determined 
using Tier 1 in subpart C. In order to further clarify this, we are 
adding the definition of ``Wood and Wood Residuals'' to 40 CFR 98.6 and 
including wastewater process sludge from paper mills in this 
definition, as further described in Section II.F of this preamble.
    We are adding solid petroleum coke to both Table C-1 and Table AA-
2. We have concluded that it is not necessary to have emission factors 
for petroleum coke specific to kraft calciners in Table AA-2 because we 
do not believe that any kraft calciners are combusting this fuel, nor 
were any comments received suggesting this was not the case.
    There were no comments received specifically on subpart AA, 
therefore the amendments are being finalized as proposed.

P. Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids

1. Summary of Final Amendments and Major Changes Since Proposal
    Threshold for natural gas local distribution companies. We are 
amending 40 CFR Table A-5 of subpart A of 40 CFR part 98 to establish 
an applicability threshold so that only local distribution companies 
(LDCs) that deliver 460,000 thousand standard cubic feet (mscf) or more 
of natural gas per year are subject to the reporting rule. No major 
changes have been made since proposal.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Two commenters requested that EPA apply the 460,000 
thousand standard cubic feet (mscf) applicability threshold throughout 
40 CFR part 98 wherever a threshold is expressed in mtCO2e. 
Specifically, they contended that 40 CFR 98.2(i)(1) and (2) should be 
changed to allow LDCs to stop reporting if they deliver less than 460 
million cubic feet (mmcf) for 5 consecutive years or less than 276 mmcf 
for 3 consecutive years (25,000 mtCO2e is approximately 
equivalent to the CO2 emissions from the combustion of 460 
mmcf of natural gas and 15,000 mtCO2e is approximately 
equivalent to 276 mmcf of natural gas). The commenters urged EPA to 
clarify that the threshold for natural gas distributors (460,000 mscf) 
is equivalent to the threshold of 25,000 mtCO2e wherever 
that metric ton threshold appears in the rule.
    Response: EPA has finalized an applicability threshold for LDCs of 
460,000 mscf or more of natural gas delivered per year. As noted by the 
commenters, we decided that it would be easier for LDCs to determine 
whether or not they were above a reporting threshold expressed in mscf 
than if that threshold were expressed in metric tons of carbon dioxide 
equivalent for the first year of this reporting program.
    However, we have not changed the conditions for ceasing reporting. 
In the 2009 final rule, 40 CFR 98.2(i) states, ``Except as provided in 
this paragraph, once a facility or supplier is subject to the 
requirements of this part, the owner or operator must continue for each 
year thereafter to comply with all requirements of this part, including 
the requirement to submit annual GHG reports, even if the facility or 
supplier does not meet the applicability requirements in paragraph (a) 
of this section in a future year.'' As noted by the commenter, 
facilities and suppliers can cease reporting when reported emissions 
are below 25,000 mtCO2e for five consecutive years or below 
15,000 mtCO2e for three consecutive years, as specified in 
40 CFR 98.2(i)(1) and (i)(2), respectively. It is clear in the final 
rule that other than these two exceptions, a facility or supplier must 
continue to report even if the facility or supplier no longer meets the 
threshold for reporting
    EPA has concluded that applying a consistent threshold, expressed 
in mtCO2e, in 98.2(i)(1) and 98.2(i)(2) for all reporters 
levels the playing field for all reporters and is most logical. EPA 
does not intend to provide equivalent thresholds under 40 CFR 98.2(i) 
for various categories because it becomes too cumbersome. LDCs are 
required to report, under 40 CFR 98.406(b)(8), the total annual 
CO2 mass emissions that would result from complete 
combustion of the natural gas delivered to end-users. By performing 
this required calculation, LDCs have the necessary data to determine 
whether they may cease reporting.

[[Page 79128]]

Q. Subpart OO--Suppliers of Industrial Greenhouse Gases

1. Summary of Final Amendments and Major Changes Since Proposal
    We are making several changes to subpart OO to respond to concerns 
raised by producers of fluorinated GHGs regarding the scope of the 
monitoring and reporting requirements, and clarify the scope and due 
dates for certain reporting and recordkeeping requirements.
    Producers of fluorinated GHGs requested that EPA clarify that 
subpart OO does not apply to fluorinated GHGs that are either emitted 
or destroyed at the facility before the fluorinated GHG product is 
packaged for sale or for shipment to another facility for destruction; 
are produced and transformed at the same facility; or occur as low-
concentration constituents (e.g., impurities) in fluorinated GHG 
products. The producers also requested that EPA amend the rule to 
account for the fact that some fluorinated GHGs do not have global 
warming potential values (GWPs) listed in Table A-1 of subpart A. For 
fluorinated GHGs without GWPs in Table A-1, facilities cannot calculate 
CO2-equivalent production as required by subpart A, and 
importers and exporters cannot take advantage of the reporting 
exemptions for small shipments under 40 CFR 98.416(c) and (d), which 
are expressed in CO2-equivalents.
    In response to the concern regarding fluorinated GHGs that are 
emitted or destroyed before the product is packaged for sale, we are 
amending the definition of ``produce a fluorinated GHG'' at 40 CFR 
98.410(b) to explicitly exclude the ``creation of fluorinated GHGs that 
are released or destroyed at the production facility before the 
production measurement at Sec.  98.414(a).'' We are also removing the 
requirements at 40 CFR 98.414(j) and 98.416(a)(4) to monitor and report 
the destruction of fluorinated GHGs ``that are not included in the 
calculation of the mass produced in Sec.  98.413(a) because they are 
removed from the production process as by-products or wastes.'' 
Finally, we are modifying the requirements at 40 CFR 98.414(h), 
98.416(a)(3), and 98.416(a)(11) to limit them to the mass of each 
fluorinated GHG that is fed into the destruction device (or 
``destroyed'' in the case of 40 CFR 98.416(a)(3)) and that was 
previously produced as defined at 40 CFR 98.410(b).
    These amendments will clarify that the scope of subpart OO is that 
which EPA has always intended, and they will modify the destruction 
monitoring and reporting requirements to be fully consistent with that 
scope. As noted in the preamble to the final Part 98 (74 FR 56259), and 
in the response to comments document, the intent of subpart OO is to 
track the quantities of fluorinated GHGs entering and leaving the U.S. 
supply of fluorinated GHGs. Specifically, subpart OO is intended to 
address production of fluorinated GHGs, not emissions or destruction of 
fluorinated GHGs that occur during the production process.
    As noted in the proposed Part 98 (74 FR 16580), the production 
measurement at 40 CFR 98.414(a) could occur wherever it traditionally 
occurs, e.g., at the inlet to the day tank or at the shipping dock, as 
long as the subpart OO monitoring requirements were met (e.g., one-
percent precision and accuracy for the mass produced and for container 
heels, if applicable). Emissions upstream of the production measurement 
will be subject to the recently promulgated subpart L, which was signed 
by EPA Administrator Lisa Jackson on November 8, 2010 and are not part 
of the subpart OO source category.
    We are also amending 40 CFR 98.416(a)(3) and (a)(11) to limit the 
monitoring and reporting of destroyed fluorinated GHGs to those 
destroyed fluorinated GHGs that were previously ``produced'' under 
today's revised definition.\6\ Such fluorinated GHGs include but are 
not limited to quantities that are shipped to the facility by another 
facility for destruction, and quantities that are returned to the 
facility for reclamation but are found to be irretrievably 
contaminated. While monitoring of some destroyed streams appears to 
pose significant technical challenges,\7\ monitoring of quantities of 
fluorinated GHGs that were previously produced does not. These 
quantities can be weighed and analyzed by the facility upon receipt or 
upon the facility's conclusion that they cannot be brought back to the 
specifications for new or reusable product.
---------------------------------------------------------------------------

    \6\ In Part 98, EPA required the monitoring of all streams being 
destroyed because it was our understanding, based on conversations 
with fluorinated GHG producers, that the mass flow of destroyed 
fluorinated GHG streams was routinely monitored. To arrive at the 
quantities being removed from the supply, EPA required facilities to 
estimate the share of the total quantity of fluorinated GHGs 
destroyed that consisted of fluorinated GHGs that were not included 
in the calculation of the mass produced. This share could then be 
subtracted from the total to arrive at the amounts destroyed that 
were removed from the supply. In other words, monitoring and 
reporting of the destruction of fluorinated GHGs that were not 
included in the mass produced was required in order to estimate the 
destruction of fluorinated GHGs that had been produced.
    \7\ These include (1) low-pressure conditions that make it 
challenging to achieve good accuracies and precisions and under 
which the installation of a flowmeter may lead to low- or no-flow 
conditions, interfering with operations upstream of the meter, (2) 
corrosive conditions that require the use of Tefzel-lined flow 
meters, which are currently available in a limited range of sizes 
and precisions, and (3) variations in stream flow rates and 
compositions that are associated with purging of vessels and columns 
and that make it difficult to select a meter that will measure the 
full range of flows to the required accuracy and precision.
---------------------------------------------------------------------------

    In response to the concern regarding fluorinated GHGs that are 
produced and transformed at the same facility, we are amending the 
definition of ``produce a fluorinated GHG'' to exclude ``the creation 
of intermediates that are created and transformed in a single process 
with no storage of the intermediates.'' We are also amending the 
definition of ``produce a fluorinated GHG'' in 40 CFR 98.410(b) to 
explicitly include ``the manufacture of a fluorinated GHG as an 
isolated intermediate for use in a process that will result in its 
transformation either at or outside of the production facility.'' We 
are also adding a definition of ``isolated intermediate'' to 40 CFR 
98.418. Finally, we are adding provisions to 40 CFR 98.414, 98.416, and 
98.417 to clarify that isolated intermediates that are produced and 
transformed at the same facility are exempt from subpart OO monitoring, 
reporting, and recordkeeping requirements respectively.
    As noted by the producers, fluorinated GHGs that are produced and 
transformed at the same facility never enter the U.S. supply of 
industrial greenhouse gases; thus, they do not need to be reported 
under subpart OO. This is true both of isolated intermediates and of 
intermediates that are created and transformed in a single process with 
no storage of the intermediate. However, while we are excluding the 
latter from the definition of ``produce a fluorinated GHG,'' we are 
including the former in that definition. This is because the 
manufacture of isolated intermediates, which can lead to emissions of 
those intermediates, will be of interest under the recently promulgated 
subpart L and it is desirable to use the same definition of ``produce a 
fluorinated GHG'' for subpart L as for subpart OO for consistency and 
clarity. Thus, instead of excluding the manufacture of isolated 
intermediates that are transformed at the same facility from the 
definition of ``produce a fluorinated GHG,'' we are adding provisions 
to exclude it from the subpart OO monitoring, reporting, and 
recordkeeping requirements. We are also adding a definition of 
``isolated

[[Page 79129]]

intermediate'' that is the same as that for the recently promulgated 
subpart L.
    In response to the concern regarding fluorinated GHGs that occur as 
low-concentration constituents of fluorinated GHG products, we are 
defining and excluding low-concentration constituents from the 
monitoring, reporting, and recordkeeping requirements for fluorinated 
GHG production, exports, and imports. For purposes of production and 
export, we are defining a low-concentration constituent in 40 CFR 
98.418 as a fluorinated GHG constituent of a fluorinated GHG product 
that occurs in the product in concentrations below 0.1 percent by mass. 
This concentration is the same as that used in the definition of 
``trace concentration'' used elsewhere in subpart OO. It is also 
consistent with industry purity standards for HFC refrigerants (Air-
Conditioning, Heating, and Refrigeration Institute (AHRI) 700), for 
SF6 used as an insulator in electrical equipment 
(International Electrotechnical Commission (IEC) 60376), and for 
perfluorocarbons and other fluorinated GHGs used in electronics 
manufacturing (Semiconductor Equipment and Materials International 
(SEMI) C3 series). To meet these standards, which set limits that range 
from less than 0.1 percent to 0.5 percent for all fluorinated GHG 
impurities combined, fluorinated GHG producers are likely to have 
identified and quantified the concentrations of impurities at 
concentrations at or above 0.1 percent for the products subject to the 
standards. Finally, below concentrations of 0.1 percent, fluorinated 
GHG impurities are not likely to have a significant impact on the GWP 
of the product. For example, if a low-concentration constituent occurs 
in concentrations of just less than 0.1 percent and has a GWP that is 
ten times as large as the GWP of the main constituent of the product, 
it will increase the weighted GWP of the product by just less than one 
percent.
    To ensure that fluorinated GHG production facilities rely on data 
of known and acceptable quality when determining whether or not to 
report a minor fluorinated GHG constituent of a product, we are adding 
product sampling and analytical requirements at 40 CFR 98.414(n), 
corresponding calibration requirements at 40 CFR 98.414(o), and a 
corresponding reporting requirement at 40 CFR 98.416(f). We are also 
clarifying in 40 CFR 98.414(a) how to calculate production of each 
fluorinated GHG constituent of a product.
    For purposes of fluorinated GHG imports, we are defining a ``low-
concentration constituent'' in 40 CFR 98.418 as a fluorinated GHG 
constituent of a fluorinated GHG product that occurs in the product in 
concentrations below 0.5 percent by mass. We are defining a higher 
concentration for fluorinated GHG imports than for fluorinated GHG 
production and exports because importers are less likely than producers 
to have detailed information on the identities and concentrations of 
minor fluorinated GHG constituents in their products.
    In response to the concerns regarding fluorinated GHGs that do not 
have GWPs listed in Table A-1, we are amending subpart A to exempt such 
compounds from the general subpart A requirement to report supply flows 
in terms of CO2 equivalents and revising the reporting 
exemptions for import and export of small shipments to be in terms of 
kilograms of fluorinated GHGs or N2O, rather than tons of 
CO2-equivalents. The amendment to subpart A is discussed in 
more detail in Section II.F of this preamble. The exemptions for import 
and export will be applied to shipments of less than 25 kilograms of 
fluorinated GHGs or N2O rather than to shipments of less 
than 250 metric tons of CO2e. This will enable small 
shipments of fluorinated GHGs to be exempt from reporting regardless of 
whether or not the fluorinated GHG has a GWP listed in Table A-1.
    Other corrections. We are also amending the reporting and 
recordkeeping provisions in subpart OO to clarify those requirements 
and to correct internal inconsistencies in the subpart.
    We are amending the reporting requirements in 40 CFR 98.416(a)(15) 
and (c)(10) to remove N2O from the list of GHGs that must be 
reported when they are transferred off site for destruction, because 
N2O transferred off site for destruction is not required to 
be monitored.
    We are amending 40 CFR 98.416(b) and (e) to clarify the due dates 
of the one-time reports required by those paragraphs. The due date for 
the one-time reports is March 31, 2011, or within 60 days of commencing 
fluorinated GHG destruction or production (as applicable). The due date 
in 40 CFR 98.416(e) in subpart OO was originally April 1, 2011, and 
there was no provision for fluorinated GHG destruction or production 
commenced after that date.
    We are amending the recordkeeping requirements in 40 CFR 
98.417(a)(2) to correct and update an internal reference. The correct 
reference is to ``Sec.  98.414(m) and (o),'' instead of ``Sec.  
98.417(j) and (k).'' We are amending 40 CFR 98.417(b) to remove the 
reference to the ``annual destruction device outlet reports'' in 40 CFR 
98.416(e) since no such reporting requirement exists.
    Finally, we are amending 40 CFR 98.417(d)(2) to correct a 
typographical error; that paragraph should refer to ``the invoice for 
the export,'' rather than for the ``import.''
    EPA is making one clarifying editorial change in the final rule 
amendments that was not in the proposed amendments. As discussed above 
and in the preamble to the proposed amendments, 40 CFR 98.414(h) 
requires facilities to measure the mass of each fluorinated GHG that is 
fed into the destruction device and that was previously produced. If 
the mass being fed into the destruction device includes more than trace 
concentrations of materials other than the fluorinated GHG being 
destroyed, facilities must estimate the concentrations of the 
fluorinated GHGs being destroyed. They must then multiply these 
concentrations by the mass measurement to obtain the mass of the 
fluorinated GHGs fed into the destruction device. In the proposed 
paragraph (h), the final sentence read, ``You must multiply this 
concentration (mass fraction) by the mass measurement to obtain the 
mass of the fluorinated GHG destroyed.'' To be consistent with the 
beginning of the paragraph and to be mathematically correct, this 
sentence has been corrected in the final rule to read, ``You must 
multiply this concentration (mass fraction) by the mass measurement to 
obtain the mass of the fluorinated GHG fed into the destruction 
device.'' As specified in Equation OO-4 of 40 CFR 98.413(d), the mass 
of the fluorinated GHG destroyed is obtained by multiplying the mass of 
the fluorinated GHG fed into the destruction device by the destruction 
efficiency of the destruction device.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: Two commenters expressed concerns that exempting low-
concentration constituents of products from monitoring and reporting 
would exempt a significant amount of

[[Page 79130]]

emissions from reporting. These commenters requested additional 
information on the GWPs of these low-concentration constituents and on 
the emissions affected by the exemption.
    Response: We analyzed the potential impact of low-concentration 
constituents on the total calculated flows of fluorinated GHGs into the 
U.S. economy, considering both the possible masses of the low-
concentration constituents and their CO2-equivalents. We 
concluded that at a level of 0.1 percent of production and 0.5 percent 
of imports, identification of such constituents would have a negligible 
impact on the total calculated flows of fluorinated GHGs into the U.S. 
supply. It is important to note that, under the exemption for low-
concentration constituents, the masses and CO2e of low-
concentration constituents are not equated to zero. Instead, the mass 
of the low-concentration constituent is assigned to the main 
constituent of the product, and the GWP is assumed to be that of the 
main constituent of the product. Only if the GWP or atmospheric 
lifetime of the low-concentration constituent is significantly higher 
than that of the main constituent is there a potential concern 
associated with these assumptions.
    As noted in the preamble to the proposed rule, low-concentration 
constituents are generally by-products of the reaction used to produce 
the fluorinated GHG product. Although we do not have information on 
every product and by-product combination, we believe, based on the 
examples of which we are aware, that by-products rarely have GWPs that 
are more than ten times as large as that of the product. We analyzed 
the potential impact of a by-product that had ten times the GWP of the 
product on the weighted GWP of the combination of the two. At a 
concentration of 0.1 percent, the by-product would raise the weighted 
GWP (and CO2e) above that of the product by just under one 
percent. Given that the impacts of most low-concentration constituents 
are likely to fall below this level, we do not consider them 
significant.
    We also performed an analysis in which we conservatively assumed 
that every HFC, PFC, and SF6 product had a PFC by-product 
that was shipped along with it at a concentration of 0.1 percent. This 
was intended to address the possibility that low-concentration 
constituents had very long atmospheric lifetimes. Based on this worst-
case assumption, the quantity of PFCs flowing into the U.S. fluorinated 
GHG supply was increased by less than 10 percent. It is extremely 
unlikely that every HFC, PFC, and SF6 product has a PFC by-
product; in fact, the highest-volume products, the HFCs, are unlikely 
to have PFC by-products. Therefore, in consideration of this analysis 
and the GWP analysis, we have concluded that the exemption for low-
concentration constituents is very unlikely to lead to significant 
errors in our understanding of potential emissions of fluorinated GHGs 
from the U.S. supply.
    Comment: Two commenters expressed concerns regarding the proposal 
to exclude from subpart OO fluorinated GHGs that are emitted or 
destroyed before the fluorinated product is packaged for sale. They 
requested that EPA ensure that these emissions were fully captured 
under the reporting rule (e.g., subpart L) and requested that EPA 
document the magnitude of these emissions and the identities and GWPs 
of the compounds emitted.
    Response: As proposed, we are excluding from the definition of 
``produce a fluorinated GHG'' the creation of fluorinated GHGs that are 
released or destroyed at the production facility before the production 
measurement. As discussed in the preamble to the proposed amendments, 
such fluorinated GHGs never enter the U.S. supply of fluorinated GHGs, 
and the goal of subpart OO is to monitor fluorinated GHG flows into and 
out of this supply. However, the recently promulgated subpart L 
requires monitoring and reporting of emissions that occur before the 
production measurement. We have worked to ensure that no fluorinated 
GHG emissions from fluorinated GHG production are ``missed'' under the 
combined oversight of these two subparts. The magnitudes, identities, 
and GWPs of the emissions that will be reported under subpart L of 40 
CFR part 98 are discussed in the preamble to the proposed rule 
including subpart L (75 FR 18652, April 12, 2010) and in the Technical 
Support Document for subpart L.

R. Subpart PP--Suppliers of Carbon Dioxide

1. Summary of Final Amendments and Major Changes Since Proposal
    We are removing the words ``each'' from 40 CFR 98.422(a) and (b). 
This change will align this section with the requirements of the rest 
of subpart PP, which allow for monitoring of an aggregated flow of 
CO2, versus monitoring at each production well or process 
unit, if the monitoring is done at a gathering point downstream of 
individual production wells or production process units.
    We are allowing suppliers to calculate the annual mass of 
CO2 supplied in containers by using weigh bills, scales, 
load cells, or loaded container volume readings as an alternative to 
flow meters. We are making multiple amendments to the regulatory text 
to accommodate this provision. First, we are redesignating 40 CFR 
98.423(b) as 40 CFR 98.423(c) and adding a new 40 CFR 98.423(b) with 
calculation procedures for CO2 supplied in containers. 
Second, we are amending the first sentence of 40 CFR 98.423(a) to allow 
use of the alternative procedures in 40 CFR 98.423(b). Third, we are 
adding new QA/QC procedures for suppliers of CO2 in 
containers to 40 CFR 98.424(a)(2). Fourth, we are adding missing data 
procedures for suppliers of CO2 in containers to 40 CFR 
98.425(d) and specifying that the missing data procedures in 40 CFR 
98.425(a) are for suppliers using flow meters. Finally, we are making 
multiple amendments to regulatory text in 40 CFR 98.426 so that all 
data collected with weigh bills, scales, load cells, or loaded 
container volume readings must be reported just as for all data 
collected with flow meters.
    We are removing the requirement that CO2 measurement 
must be made prior to subsequent purification, processing, or 
compression at 40 CFR 98.423(a)(1), (a)(2), and (b) (which we are 
redesignating as 40 CFR 98.423(c)). Because the purpose of subpart PP 
is to collect accurate data on CO2 supplied to the economy, 
we have concluded that measurements made after purification, 
compression, or processing will continue to meet the level of data 
quality and accuracy needed with respect to subpart PP, while 
minimizing the burden on industry and providing greater flexibility in 
measuring CO2 streams.
    To ensure that all reporters account for the appropriate quantity 
of CO2 in situations where a CO2 stream is 
segregated such that only a portion is captured for commercial 
application or for injection and where a flow meter is used, we are 
making a number of amendments. First, we are adding language at 40 CFR 
98.424(a) regarding flow meter location. Reporters who have a flow 
meter(s) on the main, captured CO2 stream(s) only must 
locate the flow meter(s) after the point(s) of segregation. Reporters 
who have a flow meter(s) on the main, captured CO2 stream 
and a subsequent flow meter(s) on the CO2 stream(s) diverted 
for on-site use and who choose to use the subsequent flow meter(s) to 
calculate CO2 supply (i.e. the

[[Page 79131]]

two meter method) must locate the main flow meter(s) prior to the 
point(s) of segregation and the subsequent flow meter(s) on the 
CO2 stream(s) for on-site use after the point(s) of 
segregation. We are also amending existing language in 40 CFR 98.424(a) 
to reference this new requirement. Second, we are amending 40 CFR 
98.423(a)(3) to provide reporters using the two meter approach a new 
equation (Equation PP-3b) to calculate total CO2 supplied. 
As a harmonizing change, we are redesignating Equation PP-3 as Equation 
PP-3a. Third, we are amending 40 CFR 98.426(c) so that reporters using 
the new Equation PP-3b are required to report the equation inputs and 
output and the location of flow meters with respect to the point of 
segregation.
    Because the amendments will allow flow meters to be located after 
purification, compression, or processing, we are adding data reporting 
requirements in 40 CFR 98.426 to collect additional information on flow 
meter location. Specifically, we are adding that facilities will report 
information on the placement of each flow meter used in relation to the 
points of CO2 stream capture, dehydration, compression, and 
other processing. Knowing where in the production process the flow 
meter is located will enable EPA to effectively compare data across 
reporters and learn about the efficacy of various CO2 stream 
capture processes.
    We are specifying standard conditions under subpart PP as a 
temperature and an absolute pressure of 60 [deg]F and 1 atmosphere. It 
is our understanding that 60[deg] F and 1 atmosphere (which is 
equivalent to 14.7 psia) are more commonly used by the industries 
covered by subpart PP.
    We are making several amendments to allow the reporter to determine 
the mass of a CO2 stream by converting the volumetric flow 
of the CO2 stream from operating conditions to standard 
conditions and then applying the density value for CO2 at 
standard conditions and the measured concentration of CO2 in 
the flow as a volume percent. First, we are specifying that, at the 
revised standard conditions, the density of CO2 is 0.001868 
metric tons per standard cubic meter. This is slightly different than 
the density value proposed (0.018704) as the result of additional 
research we have conducted. We are specifying that a reporter who 
applies the density value for CO2 at standard conditions 
must use this specified value.
    Second, we are revising the definitions of two of the input 
variables to Equation PP-2 in paragraph (a)(2). Since it was finalized 
(74 FR 56260, October 30, 2009), Equation PP-2 allows a reporter to 
calculate annual mass of CO2 with an input for 
CO2 concentration in weight percent and an input for density 
of the CO2 stream. So that reporters can avail themselves of 
the density value for CO2 being finalized in this action, 
however, Equation PP-2 can now also be used to calculate annual mass of 
CO2 with an input for CO2 concentration in volume 
percent and an input for density of CO2. We note that when 
we proposed this action, we did not propose to revise the definitions 
of the input variables because we erroneously overlooked the mismatch 
between the density value we were providing (CO2) and the 
density value required by Equation PP-2 (the CO2 stream). In 
order to provide all reporters with lower burden calculation 
procedures, as intended by proposing a density value for 
CO2, we are correcting this omission and harmonizing 
Equation PP-2 with the finalized density value. We note that the 
revision to the two input variables is being applied for both reporters 
using flow meters and reporters using containers.
    Third, we are amending 40 CFR 98.426(b)(3) and (b)(4) to require 
that for volumetric flow meters, the reporter must report quarterly 
concentration either in volume or weight percent and a density value 
for either CO2 or the CO2 stream, depending on 
which of the two equation input descriptions provided the reporter 
uses.
    Fourth, we are amending language in 40 CFR 98.424(a)(5), (a)(5)(i) 
and (a)(5)(ii) to allow reporters to choose either a method published 
by a consensus-based standards organization or an industry standard 
practice to determine the density of the CO2 stream. We are 
also replacing the word ``measure'' with the word ``determine.'' 
Previously, subpart PP required a reporter to use an appropriate method 
published by a consensus-based standards organization to measure 
density for CO2 at standard conditions, if such a method 
existed. Only where no such method existed could an industry standard 
practice be used. However, we have been unable to identify any method 
published by a consensus-based standards organization for measuring the 
density of the CO2 stream. Therefore, we are providing 
reporters with more flexibility on this requirement so that they can 
use an industry standard practice to calculate the density of the 
CO2 stream rather than directly measure density with an 
instrument, if preferred.
    Finally, we are amending the reference to the U.S. Food and Drug 
Administration food-grade specifications for CO2 in 40 CFR 
98.424(b)(2) to correct a typographical error. The correct reference is 
21 CFR 184.1240, not 21 CFR 184.1250.
    Major changes since proposal are identified in the following list. 
The rationale for these and any other significant changes can be found 
in this preamble or the document, ``Response to Comments: Revision to 
Certain Provisions of the Mandatory Reporting of Greenhouse Gases 
Rule'' (see EPA-HQ-OAR-2008-0508).
     We are adding a second aggregation equation (Equation PP-
3b) with appropriate flow meter location requirements so that a 
reporter can select either the one-meter or two-meter approach for 
calculating total annual mass of CO2.
     We are revising the definitions of two of the input 
variables to Equation PP-2 in paragraphs 40 CFR 98.423(a)(2) and (b)(2) 
so that the equation can be used to calculate annual mass of 
CO2 with an input for CO2 concentration in either 
volume percent and an input for density of CO2, or weight 
percent CO2 and the density of the whole stream.
2. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments were received on this subpart. Responses to 
additional significant comments received can be found in the document, 
``Response to Comments: Revision to Certain Provisions of the Mandatory 
Reporting of Greenhouse Gases Rule'' (see EPA-HQ-OAR-2008-0508).
    Comment: One commenter asserted that one of their facilities has 
already installed a CO2 meter prior to purification, 
processing, or compression--as was required by 40 CFR 98.424 when Part 
98 was finalized (74 FR 56260, October 30, 2009)--and because this 
facility has segregation, this results in a flow meter location prior 
to segregation. The commenter suggested that this facility and others 
like it should be allowed to keep their flow meters in place rather 
than be required to move them to a location after segregation, as was 
proposed in the amendments of August 11, 2010. The commenter suggested 
a two-meter approach, whereby a facility locates a main flow meter 
prior to segregation on the main, captured CO2 stream and a 
subsequent flow meter after segregation on the diverted CO2 
stream and then calculates the CO2 for off-site commercial 
use as the difference between the two. The commenter stated that this 
two-meter approach should be

[[Page 79132]]

equally acceptable to the approach proposed.
    Response: EPA agrees that a reporter can calculate CO2 
supplied for commercial transaction or injection with sufficient 
accuracy with the two-meter approach suggested by the commenter, as 
long as the CO2 stream diverted for on site use is the only 
CO2 stream diversion after the location of the main flow 
meter. If any of the main CO2 stream remaining after on-site 
diversion is further diverted (to a vent for emission, for example) 
then the difference between the captured CO2 stream and the 
CO2 stream diverted for on-site use will not be an accurate 
reflection of the CO2 supplied for commercial transaction or 
injection. Therefore, EPA is finalizing two approaches for calculating 
CO2 supplied, including aggregation equations with flow 
meter location requirements, so that a reporter can select either the 
one-meter or two-meter approach. However, we are specifying in the 
monitoring and QA/QC requirements (40 CFR 98.424) that a reporter may 
only follow the two-meter approach if the CO2 stream(s) for 
on-site use is/are the only diversion(s) from the main, captured 
CO2 stream after the main flow meter(s) location.

III. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    This action is not a ``significant regulatory action'' under the 
terms of Executive Order 12866 (58 FR 51735, October 4, 1993) and is 
therefore not subject to review under the executive order.

B. Paperwork Reduction Act

    This action does not impose any new information collection burden. 
These amendments do not make substantive changes to the reporting 
requirements in any of the amended subparts. In many cases, the 
amendments to the reporting requirements reduce the reporting burden by 
making the reporting requirements conform more closely to current 
industry practices. While the final rule results in a net decrease in 
collection burden, there is a new reporting requirement for facilities 
with part 75 units. Previously, facilities with these units had the 
option of reporting biogenic CO2 emissions separately. This 
final rule requires separate reporting of biogenic CO2 
emissions beginning in 2011; however facilities may use simplified 
methods based on available information. The Office of Management and 
Budget (OMB) has previously approved the information collection 
requirements contained in the regulations promulgated on October 30, 
2009, under 40 CFR part 98 under the provisions of the Paperwork 
Reduction Act, 44 U.S.C. 3501 et seq. and has assigned OMB control 
number 2060-0629. Burden is defined at 5 CFR 1320.3(b). An agency may 
not conduct or sponsor, and a person is not required to respond to, a 
collection of information unless it displays a currently valid OMB 
control number. The OMB control numbers for EPA's regulations in 40 CFR 
are listed in 40 CFR part 9.
    Further information on EPA's assessment on the impact on burden can 
be found in the Revisions Cost Memo (EPA-HQ-OAR-2008-0508).

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of these amendments on small 
entities, small entity is defined as: (1) A small business as defined 
by the Small Business Administration's regulations at 13 CFR 121.201; 
(2) a small governmental jurisdiction that is a government of a city, 
county, town, school district or special district with a population of 
less than 50,000; and (3) a small organization that is any not-for-
profit enterprise which is independently owned and operated and is not 
dominant in its field.
    After considering the economic impacts of these rule amendments on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities.
    The rule amendments will not impose any new significant 
requirements on small entities that are not currently required by the 
rules promulgated on October 30, 2009 (i.e., calculating and reporting 
annual GHG emissions).
    Broadly, in developing the 2009 final rule EPA took several steps 
to reduce the impact on small entities. For example, EPA determined 
appropriate thresholds that reduced the number of small businesses 
reporting. In addition, EPA did not require facilities to install CEMS 
if they did not already have them. Facilities without CEMS can 
calculate emissions using readily available data or data that are less 
expensive to collect such as process data or material consumption data. 
For some source categories, EPA developed tiered methods that are 
simpler and less burdensome. Also, EPA required annual instead of more 
frequent reporting. Finally, EPA continues to conduct significant 
outreach on the mandatory GHG reporting rule and maintains an ``open 
door'' policy for stakeholders to help inform EPA's understanding of 
key issues for the industries.

D. Unfunded Mandates Reform Act (UMRA)

    This action contains no Federal mandates under the provisions of 
Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 U.S.C. 
1531-1538 for State, local, or tribal governments or the private 
sector. The action imposes no enforceable duty on any State, local or 
tribal governments or the private sector. In addition, EPA determined 
that the rule amendments contain no regulatory requirements that might 
significantly or uniquely affect small governments because the 
amendments will not impose any new requirements that are not currently 
required by the rule promulgated on October 30, 2009 (i.e., calculating 
and reporting annual GHG emissions), and the rule amendments will not 
unfairly apply to small governments. Therefore, this action is not 
subject to the requirements of section 203 of the UMRA.

E. Executive Order 13132: Federalism

    This action does not have federalism implications. It will not have 
substantial direct effects on the States, on the relationship between 
the national government and the States, or on the distribution of power 
and responsibilities among the various levels of government, as 
specified in Executive Order 13132. However, for a more detailed 
discussion about how these rule amendments will relate to existing 
State programs, please see Section II of the preamble for the proposed 
GHG reporting rule (74 FR 16457 to 16461, April 10, 2009).
    These amendments apply directly to facilities that supply fuel that 
when used emit greenhouse gases or facilities that directly emit 
greenhouses gases. They do not apply to governmental entities unless 
the government entity owns a facility that directly emits greenhouse 
gases above threshold levels (such as a landfill or stationary 
combustion source), so relatively few government facilities will be 
affected. This regulation also does not limit the

[[Page 79133]]

power of States or localities to collect GHG data and/or regulate GHG 
emissions. Thus, Executive Order 13132 does not apply to this action.
    Although section 6 of Executive Order 13132 does not apply to this 
action, EPA did consult with State and local officials or 
representatives of State and local governments in developing the 2009 
final rule. A summary of EPA's consultations with State and local 
governments is provided in Section VIII.E of the preamble to the 2009 
final rule (74 FR 56260, October 30, 2009).

F. Executive Order 13175: Consultation and Coordination With Indian 
Tribal Governments

    This action does not have tribal implications, as specified in 
Executive Order 13175 (65 FR 67249, November 9, 2000). The rule 
amendments will not result in any changes to the requirements of Part 
98. Thus, Executive Order 13175 does not apply to this action.
    Although Executive Order 13175 does not apply to this action, EPA 
sought opportunities to provide information to Tribal governments and 
representatives during the development of the rules promulgated on 
October 30, 2009. A summary of the EPA's consultations with Tribal 
officials is provided Sections VIII.E and VIII.F of the preamble to the 
final GHG Reporting Rule (74 FR 56260, October 30, 2009).

G. Executive Order 13045: Protection of Children From Environmental 
Health Risks and Safety Risks

    EPA interprets Executive Order 13045 (62 FR 19885, April 23, 1997) 
as applying only to those regulatory actions that concern health or 
safety risks, such that the analysis required under section 5-501 of 
the Executive Order has the potential to influence the regulation. This 
action is not subject to Executive Order 13045 because it does not 
establish an environmental standard intended to mitigate health or 
safety risks.

H. Executive Order 13211: Actions That Significantly Affect Energy 
Supply, Distribution, or Use

    This action is not subject to Executive Order 13211 (66 FR 28355 
(May 22, 2001)), because it is not a significant regulatory action 
under Executive Order 12866.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by voluntary 
consensus standards bodies. NTTAA directs EPA to provide Congress, 
through OMB, explanations when the Agency decides not to use available 
and applicable voluntary consensus standards.
    This rulemaking involves the use of two new voluntary consensus 
standards from ASTM International. Specifically, EPA will allow 
facilities in the petroleum refining and petrochemical production 
industries to use ASTM D2593-93(2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, and 
ASTM D7633-10 Standard Test Method for Carbon Black--Carbon Content, in 
addition to the methods incorporated by reference in Part 98. These 
additional voluntary consensus standards will provide alternative 
method that owners or operators in these industries can use to monitor 
GHG emissions.
    This rulemaking also involves the use of several standard methods 
that are in EPA publications. These include the following:
     Protocol for Measurement of Tetrafluoromethane 
(CF4) and Hexafluoroethane (C2F6) 
Emissions from Primary Aluminum Production (April 2008); IBR approved 
for 40 CFR 98.64(a).
     AP 42, Section 5.2, Transportation and Marketing of 
Petroleum Liquids, July 2008 (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, 
of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, 
Volume I; IBR approved for 40 CFR 98.253(n).
     AP 42, Section 7.1, Organic Liquid Storage Tanks, November 
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42, 
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume 1; 
IBR approved for 40 CFR 98.243(m)(1) and 40 CFR 98.256(o)(2)(i).
     Method 8015C, Nonhalogenated Organics By Gas 
Chromatography, Revision 3, February 2007 (Method 8015C), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA 
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste, 
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR 
98.244(b)(4)(viii).
     Method 8021B, Aromatic And Halogenated Volatiles By Gas 
Chromatography Using Photoionization And/Or Electrolytic Conductivity 
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA 
Publication No. SW-846, ``Test Methods for Evaluating Solid Waste, 
Physical/Chemical Methods,'' Third Edition; IBR approved for 40 CFR 
98.244(b)(4)(viii).
     Method 8031, Acrylonitrile By Gas Chromatography, Revision 
0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test 
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third 
Edition; IBR approved for 40 CFR 98.244(b)(4)(viii).
     Method 9060A, Total Organic Carbon, Revision 1, November 
2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for 
Evaluating Solid Waste, Physical/Chemical Methods,'' Third Edition; IBR 
approved for 40 CFR 98.244(b)(4)(viii).
    These methods are being added by the final rule amendments as a 
result of working with affected industries to identify existing methods 
that can be used to provide the data needed to calculate GHG emissions, 
proposing the addition of the methods, and considering the public 
comments on the addition of the methods in the final rule making.
    No new test methods were developed for this action.

J. Executive Order 12898: Federal Actions To Address Environmental 
Justice in Minority Populations and Low-Income Populations

    Executive Order 12898 (59 FR 7629, February 16, 1994) establishes 
federal executive policy on environmental justice. Its main provision 
directs Federal agencies, to the greatest extent practicable and 
permitted by law, to make environmental justice part of their mission 
by identifying and addressing, as appropriate, disproportionately high 
and adverse human health or environmental effects of their programs, 
policies, and activities on minority populations and low-income 
populations in the United States.
    EPA has determined that Part 98 does not have disproportionately 
high and adverse human health or environmental effects on minority or 
low-income populations because it does not affect the level of 
protection provided to human health or the environment because it is a 
rule addressing

[[Page 79134]]

information collection and reporting procedures.

K. Congressional Review Act

    The Congressional Review Act, 5 U.S.C. 801 et seq., as added by the 
Small Business Regulatory Enforcement Fairness Act of 1996 (SBREFA), 
generally provides that before a rule may take effect, the agency 
promulgating the rule must submit a rule report, which includes a copy 
of the rule, to each House of the Congress and to the Comptroller 
General of the United States. EPA will submit a report containing this 
rule and other required information to the U.S. Senate, the U.S. House 
of Representatives, and the Comptroller General of the U.S. prior to 
publication of the rule in the Federal Register. A major rule cannot 
take effect until 60 days after it is published in the Federal 
Register. This action is not a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective on December 31, 2010.

List of Subjects in 40 CFR Part 98

    Environmental protection, Administrative practice and procedure, 
Greenhouse gases, Incorporation by reference, Suppliers, Reporting and 
recordkeeping requirements.

    Dated: November 24, 2010.
Lisa P. Jackson,
Administrator.

0
For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is amended as follows:

PART 98--[AMENDED]

0
1. The authority citation for part 98 continues to read as follows:

    Authority:  42 U.S.C. 7401-7671q.

Subpart A--[Amended]

0
2. Section 98.3 is amended by:
0
a. Revising paragraphs (c)(1), (c)(4) introductory text, (c)(4)(i), 
(c)(4)(ii), and (c)(4)(iii) introductory text.
0
b. Adding paragraph (c)(4)(vi).
0
c. Adding a new sentence to the end of paragraph (c)(5)(i).
0
d. Adding paragraph (c)(12).
0
e. Revising the third sentence of paragraph (d)(3) introductory text.
0
f. Revising the first sentence of paragraph (f).
0
g. Revising paragraphs (g)(4) and (g)(5)(iii).
0
h. Revising paragraph (h).
0
i. Revising paragraph (i).
0
j. Adding paragraph (j).


Sec.  98.3  What are the general monitoring, reporting, recordkeeping 
and verification requirements of this part?

* * * * *
    (c) * * *
    (1) Facility name or supplier name (as appropriate), and physical 
street address of the facility or supplier, including the city, State, 
and zip code.
* * * * *
    (4) For facilities, except as otherwise provided in paragraph 
(c)(12) of this section, report annual emissions of CO2, 
CH4, N2O, and each fluorinated GHG (as defined in 
Sec.  98.6) as follows.
    (i) Annual emissions (excluding biogenic CO2) aggregated 
for all GHG from all applicable source categories, expressed in metric 
tons of CO2e calculated using Equation A-1 of this subpart.
    (ii) Annual emissions of biogenic CO2 aggregated for all 
applicable source categories, expressed in metric tons.
    (iii) Annual emissions from each applicable source category, 
expressed in metric tons of each applicable GHG listed in paragraphs 
(c)(4)(iii)(A) through (c)(4)(iii)(E) of this section.
* * * * *
    (vi) Applicable source categories means stationary fuel combustion 
sources (subpart C of this part), miscellaneous use of carbonates 
(subpart U of this part), and all of the source categories listed in 
Table A-3 and Table A-4 of this subpart present at the facility.
    (5) * * *
    (i) * * * For fluorinated GHGs, calculate and report 
CO2e for only those fluorinated GHGs listed in Table A-1 of 
this subpart.
* * * * *
    (12) For the 2010 reporting year only, facilities that have ``part 
75 units'' (i.e. units that are subject to subpart D of this part or 
units that use the methods in part 75 of this chapter to quantify 
CO2 mass emissions in accordance with Sec.  98.33(a)(5)) 
must report annual GHG emissions either in full accordance with 
paragraphs (c)(4)(i) through (c)(4)(iii) of this section or in full 
accordance with paragraphs (c)(12)(i) through (c)(12)(iii) of this 
section. If the latter reporting option is chosen, you must report:
    (i) Annual emissions aggregated for all GHG from all applicable 
source categories, expressed in metric tons of CO2e 
calculated using Equation A-1 of this subpart. You must include 
biogenic CO2 emissions from part 75 units in these annual 
emissions, but exclude biogenic CO2 emissions from any non-
part 75 units and other source categories.
    (ii) Annual emissions of biogenic CO2, expressed in 
metric tons (excluding biogenic CO2 emissions from part 75 
units), aggregated for all applicable source categories.
    (iii) Annual emissions from each applicable source category, 
expressed in metric tons of each applicable GHG listed in paragraphs 
(c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
    (A) Biogenic CO2 (excluding biogenic CO2 
emissions from part 75 units).
    (B) CO2. You must include biogenic CO2 
emissions from part 75 units in these totals and exclude biogenic 
CO2 emissions from other non-part 75 units and other source 
categories.
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (including those not listed in Table A-1 
of this subpart).
    (d) * * *
    (3) * * * An owner or operator that submits an abbreviated report 
must submit a full GHG report according to the requirements of 
paragraph (c) of this section beginning in calendar year 2012. * * *
* * * * *
    (f) Verification. To verify the completeness and accuracy of 
reported GHG emissions, the Administrator may review the certification 
statements described in paragraphs (c)(9) and (d)(3)(vi) of this 
section and any other credible evidence, in conjunction with a 
comprehensive review of the GHG reports and periodic audits of selected 
reporting facilities. * * *
    (g) * * *
    (4) Missing data computations. For each missing data event, also 
retain a record of the cause of the event and the corrective actions 
taken to restore malfunctioning monitoring equipment.
    (5) * * *
    (iii) The owner or operator shall revise the GHG Monitoring Plan as 
needed to reflect changes in production processes, monitoring 
instrumentation, and quality assurance procedures; or to improve 
procedures for the maintenance and repair of monitoring systems to 
reduce the frequency of monitoring equipment downtime.
* * * * *
    (h) Annual GHG report revisions. (1) The owner or operator shall 
submit a revised annual GHG report within 45 days of discovering that 
an annual GHG report that the owner or operator previously submitted 
contains one or more substantive errors. The revised report must 
correct all substantive errors.
    (2) The Administrator may notify the owner or operator in writing 
that an annual GHG report previously submitted by the owner or operator 
contains one or more substantive errors. Such notification will 
identify each such substantive error. The owner or

[[Page 79135]]

operator shall, within 45 days of receipt of the notification, either 
resubmit the report that, for each identified substantive error, 
corrects the identified substantive error (in accordance with the 
applicable requirements of this part) or provide information 
demonstrating that the previously submitted report does not contain the 
identified substantive error or that the identified error is not a 
substantive error.
    (3) A substantive error is an error that impacts the quantity of 
GHG emissions reported or otherwise prevents the reported data from 
being validated or verified.
    (4) Notwithstanding paragraphs (h)(1) and (h)(2) of this section, 
upon request by the owner or operator, the Administrator may provide 
reasonable extensions of the 45-day period for submission of the 
revised report or information under paragraphs (h)(1) and (h)(2) of 
this section. If the Administrator receives a request for extension of 
the 45-day period, by e-mail to an address prescribed by the 
Administrator, at least two business days prior to the expiration of 
the 45-day period, and the Administrator does not respond to the 
request by the end of such period, the extension request is deemed to 
be automatically granted for 30 more days. During the automatic 30-day 
extension, the Administrator will determine what extension, if any, 
beyond the automatic extension is reasonable and will provide any such 
additional extension.
    (5) The owner or operator shall retain documentation for 3 years to 
support any revision made to an annual GHG report.
    (i) Calibration accuracy requirements. The owner or operator of a 
facility or supplier that is subject to the requirements of this part 
must meet the applicable flow meter calibration and accuracy 
requirements of this paragraph (i). The accuracy specifications in this 
paragraph (i) do not apply where either the use of company records (as 
defined in Sec.  98.6) or the use of ``best available information'' is 
specified in an applicable subpart of this part to quantify fuel usage 
and/or other parameters. Further, the provisions of this paragraph (i) 
do not apply to stationary fuel combustion units that use the 
methodologies in part 75 of this chapter to calculate CO2 
mass emissions.
    (1) Except as otherwise provided in paragraphs (i)(4) through 
(i)(6) of this section, flow meters that measure liquid and gaseous 
fuel feed rates, process stream flow rates, or feedstock flow rates and 
provide data for the GHG emissions calculations shall be calibrated 
prior to April 1, 2010 using the procedures specified in this paragraph 
(i) when such calibration is specified in a relevant subpart of this 
part. Each of these flow meters shall meet the applicable accuracy 
specification in paragraph (i)(2) or (i)(3) of this section. All other 
measurement devices (e.g., weighing devices) that are required by a 
relevant subpart of this part, and that are used to provide data for 
the GHG emissions calculations, shall also be calibrated prior to April 
1, 2010; however, the accuracy specifications in paragraphs (i)(2) and 
(i)(3) of this section do not apply to these devices. Rather, each of 
these measurement devices shall be calibrated to meet the accuracy 
requirement specified for the device in the applicable subpart of this 
part, or, in the absence of such accuracy requirement, the device must 
be calibrated to an accuracy within the appropriate error range for the 
specific measurement technology, based on an applicable operating 
standard, including but not limited to manufacturer's specifications 
and industry standards. The procedures and methods used to quality-
assure the data from each measurement device shall be documented in the 
written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this 
section.
    (i) All flow meters and other measurement devices that are subject 
to the provisions of this paragraph (i) must be calibrated according to 
one of the following: You may use the manufacturer's recommended 
procedures; an appropriate industry consensus standard method; or a 
method specified in a relevant subpart of this part. The calibration 
method(s) used shall be documented in the monitoring plan required 
under paragraph (g) of this section.
    (ii) For facilities and suppliers that become subject to this part 
after April 1, 2010, all flow meters and other measurement devices (if 
any) that are required by the relevant subpart(s) of this part to 
provide data for the GHG emissions calculations shall be installed no 
later than the date on which data collection is required to begin using 
the measurement device, and the initial calibration(s) required by this 
paragraph (i) (if any) shall be performed no later than that date.
    (iii) Except as otherwise provided in paragraphs (i)(4) through 
(i)(6) of this section, subsequent recalibrations of the flow meters 
and other measurement devices subject to the requirements of this 
paragraph (i) shall be performed at one of the following frequencies:
    (A) You may use the frequency specified in each applicable subpart 
of this part.
    (B) You may use the frequency recommended by the manufacturer or by 
an industry consensus standard practice, if no recalibration frequency 
is specified in an applicable subpart.
    (2) Perform all flow meter calibration at measurement points that 
are representative of the normal operating range of the meter. Except 
for the orifice, nozzle, and venturi flow meters described in paragraph 
(i)(3) of this section, calculate the calibration error at each 
measurement point using Equation A-2 of this section. The terms ``R'' 
and ``A'' in Equation A-2 must be expressed in consistent units of 
measure (e.g., gallons/minute, ft\3\/min). The calibration error at 
each measurement point shall not exceed 5.0 percent of the reference 
value.
[GRAPHIC] [TIFF OMITTED] TR17DE10.000

Where:

CE = Calibration error (%).
R = Reference value.
A = Flow meter response to the reference value.

    (3) For orifice, nozzle, and venturi flow meters, the initial 
quality assurance consists of in-situ calibration of the differential 
pressure (delta-P), total pressure, and temperature transmitters.
    (i) Calibrate each transmitter at a zero point and at least one 
upscale point. Fixed reference points, such as the freezing point of 
water, may be used for temperature transmitter calibrations. Calculate 
the calibration error of each transmitter at each measurement point, 
using Equation A-3 of this subpart. The terms ``R,'' ``A,'' and ``FS'' 
in Equation A-3 of this subpart must be in consistent units of measure 
(e.g., milliamperes, inches of water, psi, degrees). For each 
transmitter, the CE value at each

[[Page 79136]]

measurement point shall not exceed 2.0 percent of full-scale. 
Alternatively, the results are acceptable if the sum of the calculated 
CE values for the three transmitters at each calibration level (i.e., 
at the zero level and at each upscale level) does not exceed 6.0 
percent.
[GRAPHIC] [TIFF OMITTED] TR17DE10.001

Where:
CE = Calibration error (%).
R = Reference value.
A = Transmitter response to the reference value.
FS = Full-scale value of the transmitter.

    (ii) In cases where there are only two transmitters (i.e., 
differential pressure and either temperature or total pressure) in the 
immediate vicinity of the flow meter's primary element (e.g., the 
orifice plate), or when there is only a differential pressure 
transmitter in close proximity to the primary element, calibration of 
these existing transmitters to a CE of 2.0 percent or less at each 
measurement point is still required, in accordance with paragraph 
(i)(3)(i) of this section; alternatively, when two transmitters are 
calibrated, the results are acceptable if the sum of the CE values for 
the two transmitters at each calibration level does not exceed 4.0 
percent. However, note that installation and calibration of an 
additional transmitter (or transmitters) at the flow monitor location 
to measure temperature or total pressure or both is not required in 
these cases. Instead, you may use assumed values for temperature and/or 
total pressure, based on measurements of these parameters at a remote 
location (or locations), provided that the following conditions are 
met:
    (A) You must demonstrate that measurements at the remote 
location(s) can, when appropriate correction factors are applied, 
reliably and accurately represent the actual temperature or total 
pressure at the flow meter under all expected ambient conditions.
    (B) You must make all temperature and/or total pressure 
measurements in the demonstration described in paragraph (i)(3)(ii)(A) 
of this section with calibrated gauges, sensors, transmitters, or other 
appropriate measurement devices. At a minimum, calibrate each of these 
devices to an accuracy within the appropriate error range for the 
specific measurement technology, according to one of the following. You 
may calibrate using a manufacturer's specification or an industry 
consensus standard.
    (C) You must document the methods used for the demonstration 
described in paragraph (i)(3)(ii)(A) of this section in the written GHG 
Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must 
also include the data from the demonstration, the mathematical 
correlation(s) between the remote readings and actual flow meter 
conditions derived from the data, and any supporting engineering 
calculations in the GHG Monitoring Plan. You must maintain all of this 
information in a format suitable for auditing and inspection.
    (D) You must use the mathematical correlation(s) derived from the 
demonstration described in paragraph (i)(3)(ii)(A) of this section to 
convert the remote temperature or the total pressure readings, or both, 
to the actual temperature or total pressure at the flow meter, or both, 
on a daily basis. You shall then use the actual temperature and total 
pressure values to correct the measured flow rates to standard 
conditions.
    (E) You shall periodically check the correlation(s) between the 
remote and actual readings (at least once a year), and make any 
necessary adjustments to the mathematical relationship(s).
    (4) Fuel billing meters are exempted from the calibration 
requirements of this section and from the GHG Monitoring Plan and 
recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) 
of this section, provided that the fuel supplier and any unit 
combusting the fuel do not have any common owners and are not owned by 
subsidiaries or affiliates of the same company. Meters used exclusively 
to measure the flow rates of fuels that are used for unit startup are 
also exempted from the calibration requirements of this section.
    (5) For a flow meter that has been previously calibrated in 
accordance with paragraph (i)(1) of this section, an additional 
calibration is not required by the date specified in paragraph (i)(1) 
of this section if, as of that date, the previous calibration is still 
active (i.e., the device is not yet due for recalibration because the 
time interval between successive calibrations has not elapsed). In this 
case, the deadline for the successive calibrations of the flow meter 
shall be set according to one of the following. You may use either the 
manufacturer's recommended calibration schedule or you may use the 
industry consensus calibration schedule.
    (6) For units and processes that operate continuously with 
infrequent outages, it may not be possible to meet the April 1, 2010 
deadline for the initial calibration of a flow meter or other 
measurement device without disrupting normal process operation. In such 
cases, the owner or operator may postpone the initial calibration until 
the next scheduled maintenance outage. The best available information 
from company records may be used in the interim. The subsequent 
required recalibrations of the flow meters may be similarly postponed. 
Such postponements shall be documented in the monitoring plan that is 
required under paragraph (g)(5) of this section.
    (7) If the results of an initial calibration or a recalibration 
fail to meet the required accuracy specification, data from the flow 
meter shall be considered invalid, beginning with the hour of the 
failed calibration and continuing until a successful calibration is 
completed. You shall follow the missing data provisions provided in the 
relevant missing data sections during the period of data invalidation.
    (j) Measurement device installation--(1) General. If an owner or 
operator required to report under subpart P, subpart X or subpart Y of 
this part has process equipment or units that operate continuously and 
it is not possible to install a required flow meter or other 
measurement device by April 1, 2010, (or by any later date in 2010 
approved by the Administrator as part of an extension of best available 
monitoring methods per paragraph (d) of this section) without process 
equipment or unit shutdown, or through a hot tap, the owner or operator 
may request an extension from the Administrator to delay installing the 
measurement device until the next scheduled process equipment or unit 
shutdown. If approval for such an extension is granted by the 
Administrator, the owner or operator must use best available monitoring 
methods during the extension period.
    (2) Requests for extension of the use of best available monitoring 
methods for measurement device installation. The owner or operator must 
first provide the

[[Page 79137]]

Administrator an initial notification of the intent to submit an 
extension request for use of best available monitoring methods beyond 
December 31, 2010 (or an earlier date approved by EPA) in cases where 
measurement device installation would require a process equipment or 
unit shutdown, or could only be done through a hot tap. The owner or 
operator must follow-up this initial notification with the complete 
extension request containing the information specified in paragraph 
(j)(4) of this section.
    (3) Timing of request. (i) The initial notice of intent must be 
submitted no later than January 1, 2011, or by the end of the approved 
use of best available monitoring methods extension in 2010, whichever 
is earlier. The completed extension request must be submitted to the 
Administrator no later than February 15, 2011.
    (ii) Any subsequent extensions to the original request must be 
submitted to the Administrator within 4 weeks of the owner or operator 
identifying the need to extend the request, but in any event no later 
than 4 weeks before the date for the planned process equipment or unit 
shutdown that was provided in the original request.
    (4) Content of the request. Requests must contain the following 
information:
    (i) Specific measurement device for which the request is being made 
and the location where each measurement device will be installed.
    (ii) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) requiring the measurement 
device.
    (iii) A description of the reasons why the needed equipment could 
not be installed before April 1, 2010, or by the expiration date for 
the use of best available monitoring methods, in cases where an 
extension has been granted under Sec.  98.3(d).
    (iv) Supporting documentation showing that it is not practicable to 
isolate the process equipment or unit and install the measurement 
device without a full shutdown or a hot tap, and that there was no 
opportunity during 2010 to install the device. Include the date of the 
three most recent shutdowns for each relevant process equipment or 
unit, the frequency of shutdowns for each relevant process equipment or 
unit, and the date of the next planned process equipment or unit 
shutdown.
    (v) Include a description of the proposed best available monitoring 
method for estimating GHG emissions during the time prior to 
installation of the meter.
    (5) Approval criteria. The owner or operator must demonstrate to 
the Administrator's satisfaction that it is not reasonably feasible to 
install the measurement device before April 1, 2010 (or by the 
expiration date for the use of best available monitoring methods, in 
cases where an extension has been granted under paragraph (d) of this 
section) without a process equipment or unit shutdown, or through a hot 
tap, and that the proposed method for estimating GHG emissions during 
the time before which the measurement device will be installed is 
appropriate. The Administrator will not initially approve the use of 
the proposed best available monitoring method past December 31, 2013.
    (6) Measurement device installation deadline. Any owner or operator 
that submits both a timely initial notice of intent and a timely 
completed extension request under paragraph (j)(3) of this section to 
extend use of best available monitoring methods for measurement device 
installation must install all such devices by July 1, 2011 unless the 
extension request under this paragraph (j) is approved by the 
Administrator before July 1, 2011.
    (7) One time extension past December 31, 2013. If an owner or 
operator determines that a scheduled process equipment or unit shutdown 
will not occur by December 31, 2013, the owner or operator may re-apply 
to use best available monitoring methods for one additional time 
period, not to extend beyond December 31, 2015. To extend use of best 
available monitoring methods past December 31, 2013, the owner or 
operator must submit a new extension request by June 1, 2013 that 
contains the information required in paragraph (j)(4) of this section. 
The owner or operator must demonstrate to the Administrator's 
satisfaction that it continues to not be reasonably feasible to install 
the measurement device before December 31, 2013 without a process 
equipment or unit shutdown, or that installation of the measurement 
device could only be done through a hot tap, and that the proposed 
method for estimating GHG emissions during the time before which the 
measurement device will be installed is appropriate. An owner or 
operator that submits a request under this paragraph to extend use of 
best available monitoring methods for measurement device installation 
must install all such devices by December 31, 2013, unless the 
extension request under this paragraph is approved by the 
Administrator.

0
3. Section 98.4 is amended by revising paragraphs (i)(2) and (m)(2)(i) 
to read as follows:


Sec.  98.4  Authorization and responsibilities of the designated 
representative.

* * * * *
    (i) * * *
    (2) The name, organization name (company affiliation-employer), 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of the designated representative and any 
alternate designated representative.
* * * * *
    (m) * * *
    (2) * * *
    (i) The name, organization name (company affiliation-employer) 
address, e-mail address (if any), telephone number, and facsimile 
transmission number (if any) of such designated representative or 
alternate designated representative.
* * * * *
0
4. Section 98.6 is amended by:

0
a. Adding in alphabetical order definitions for ``Agricultural by-
products,'' ``Primary fuel,'' ``Solid by-products,'' ``Used oil,'' and 
``Wood residuals.''
0
b. Revising the definitions for ``Bulk natural gas liquid or NGL,'' 
``Distillate Fuel Oil,'' ``Fossil fuel,'' ``Fuel gas,'' ``Municipal 
solid waste or MSW,'' ``Natural gas,'' ``Natural gas liquids (NGLs) and 
``Standard conditions or standard temperature and pressure (STP).''
0
c. Removing the definition for ``Fossil fuel-fired.''


Sec.  98.6  Definitions.

* * * * *
    Agricultural by-products means those parts of arable crops that are 
not used for the primary purpose of producing food. Agricultural by-
products include, but are not limited to, oat, corn and wheat straws, 
bagasse, peanut shells, rice and coconut husks, soybean hulls, palm 
kernel cake, cottonseed and sunflower seed cake, and pomace.
* * * * *
    Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons 
that have been separated from natural gas as liquids through the 
process of absorption, condensation, adsorption, or other methods. 
Generally, such liquids consist of ethane, propane, butanes, and 
pentanes plus. Bulk NGL is sold to fractionators or to refineries and 
petrochemical plants where the fractionation takes place.
* * * * *
    Distillate fuel oil means a classification for one of the petroleum

[[Page 79138]]

fractions produced in conventional distillation operations and from 
crackers and hydrotreating process units. The generic term distillate 
fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels 
(Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, 
No. 2, and No. 4).
* * * * *
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material, for purpose 
of creating useful heat.
* * * * *
    Fuel gas means gas generated at a petroleum refinery or 
petrochemical plant and that is combusted separately or in any 
combination with any type of gas.
* * * * *
    Municipal solid waste or MSW means solid phase household, 
commercial/retail, and/or institutional waste. Household waste includes 
material discarded by single and multiple residential dwellings, 
hotels, motels, and other similar permanent or temporary housing 
establishments or facilities. Commercial/retail waste includes material 
discarded by stores, offices, restaurants, warehouses, non-
manufacturing activities at industrial facilities, and other similar 
establishments or facilities. Institutional waste includes material 
discarded by schools, nonmedical waste discarded by hospitals, material 
discarded by non-manufacturing activities at prisons and government 
facilities, and material discarded by other similar establishments or 
facilities. Household, commercial/retail, and institutional wastes 
include yard waste, refuse-derived fuel, and motor vehicle maintenance 
materials. Insofar as there is separate collection, processing and 
disposal of industrial source waste streams consisting of used oil, 
wood pallets, construction, renovation, and demolition wastes (which 
includes, but is not limited to, railroad ties and telephone poles), 
paper, clean wood, plastics, industrial process or manufacturing 
wastes, medical waste, motor vehicle parts or vehicle fluff, or used 
tires that do not contain hazardous waste identified or listed under 42 
U.S.C. Sec.  6921, such wastes are not municipal solid waste. However, 
such wastes qualify as municipal solid waste where they are collected 
with other municipal solid waste or are otherwise combined with other 
municipal solid waste for processing and/or disposal.
* * * * *
    Natural gas means a naturally occurring mixture of hydrocarbon and 
non-hydrocarbon gases found in geologic formations beneath the earth's 
surface, of which the principal constituent is methane. Natural gas may 
be field quality or pipeline quality.
    Natural gas liquids (NGLs) means those hydrocarbons in natural gas 
that are separated from the gas as liquids through the process of 
absorption, condensation, adsorption, or other methods. Generally, such 
liquids consist of ethane, propane, butanes, and pentanes plus. Bulk 
NGLs refers to mixtures of NGLs that are sold or delivered as 
undifferentiated product from natural gas processing plants.
* * * * *
    Primary fuel means the fuel that provides the greatest percentage 
of the annual heat input to a stationary fuel combustion unit.
* * * * *
    Solid by-products means plant matter such as vegetable waste, 
animal materials/wastes, and other solid biomass, except for wood, wood 
waste, and sulphite lyes (black liquor).
* * * * *
    Standard conditions or standard temperature and pressure (STP), for 
the purposes of this part, means either 60 or 68 degrees Fahrenheit and 
14.7 pounds per square inch absolute.
* * * * *
    Used oil means a petroleum-derived or synthetically-derived oil 
whose physical properties have changed as a result of handling or use, 
such that the oil cannot be used for its original purpose. Used oil 
consists primarily of automotive oils (e.g., used motor oil, 
transmission oil, hydraulic fluids, brake fluid, etc.) and industrial 
oils (e.g., industrial engine oils, metalworking oils, process oils, 
industrial grease, etc).
* * * * *
    Wood residuals means materials recovered from three principal 
sources: Municipal solid waste (MSW); construction and demolition 
debris; and primary timber processing. Wood residuals recovered from 
MSW include wooden furniture, cabinets, pallets and containers, scrap 
lumber (from sources other than construction and demolition 
activities), and urban tree and landscape residues. Wood residuals from 
construction and demolition debris originate from the construction, 
repair, remodeling and demolition of houses and non-residential 
structures. Wood residuals from primary timber processing include bark, 
sawmill slabs and edgings, sawdust, and peeler log cores. Other sources 
of wood residuals include, but are not limited to, railroad ties, 
telephone and utility poles, pier and dock timbers, wastewater process 
sludge from paper mills, trim, sander dust, and sawdust from wood 
products manufacturing (including resinated wood product residuals), 
and logging residues.
* * * * *

0
5. Section 98.7 is amended by:
0
a. Removing and reserving paragraph (b).
0
b. Revising paragraphs (d)(1) through (d)(10).
0
c. Removing paragraph (d)(11).
0
d. Revising paragraph (e)(4).
0
e. Removing and reserving paragraph (e)(7).
0
f. Revising paragraphs (e)(8), (e)(10), (e)(11), (e)(14) and (e)(15).
0
g. Revising paragraphs (e)(19) and (e)(20).
0
h. Revising paragraphs (e)(24) through (e)(27).
0
i. Removing and reserving paragraph (e)(28).
0
j. Revising paragraph (e)(30).
0
k. Revising paragraph (e)(33).
0
l. Revising paragraph (e)(36).
0
m. Removing and reserving paragraph (e)(39).
0
n. Adding paragraphs (e)(48) and (e)(49).
0
o. Removing and reserving paragraph (f)(1).
0
p. Revising paragraph (f)(2).
0
q. Removing and reserving paragraph (g)(3).
0
r. Revising paragraph (m)(3).
0
s. Adding paragraphs (m)(8) through (m)(14).


Sec.  98.7  What standardized methods are incorporated by reference 
into this part?

* * * * *
    (d) * * *
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved 
for Sec.  98.124(m)(1), Sec.  98.324(e), Sec.  98.354(d), Sec.  
98.354(h), Sec.  98.344(c) and Sec.  98.364(e).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters, IBR approved for Sec.  98.124(m)(2), Sec.  98.324(e), 
Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR 
approved for Sec.  98.124(m)(3) and Sec.  98.354(d).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters, IBR approved for Sec.  98.124(m)(4), Sec.  
98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.  
98.124(m)(5),

[[Page 79139]]

Sec.  98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow 
in Closed Conduits by Weighing Method, IBR approved for Sec.  
98.124(m)(6).
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters, IBR approved for Sec.  98.124(m)(7), Sec.  
98.324(e), Sec.  98.344(c), and Sec.  98.354(h).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters, IBR approved for Sec.  98.124(m)(8), Sec.  
98.324(e), Sec.  98.344(c), Sec.  98.354(h), and Sec.  98.364(e).
    (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flow Meters, IBR approved for Sec.  98.354(d).
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable 
Area Meters, IBR approved for Sec.  98.324(e), Sec.  98.344(c), Sec.  
98.354(h), and Sec.  98.364(e).
    (e) * * *
    (4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR 
approved for Sec.  98.254(e).
* * * * *
    (8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter, IBR approved for Sec.  98.254(e).
* * * * *
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, IBR approved for Sec.  98.74(c), Sec.  
98.164(b), Sec.  98.244(b), Sec.  98.254(d), Sec.  98.324(d), Sec.  
98.354(g), and Sec.  98.344(b).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography, IBR approved for Sec.  98.74(c), 
Sec.  98.164(b), Sec.  98.254(d), Sec.  98.324(d), Sec.  98.344(b), 
Sec.  98.354(g), and Sec.  98.364(c).
* * * * *
    (14) ASTM D2502-04 Standard Test Method for Estimation of Mean 
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, 
IBR approved for Sec.  98.74(c).
    (15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure, IBR approved for Sec.  
98.74(c) and Sec.  98.254(d)(6).
* * * * *
    (19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for 
Calculation of Carbon Distribution and Structural Group Analysis of 
Petroleum Oils by the n-d-M Method, IBR approved for Sec.  98.74(c) and 
Sec.  98.164(b).
    (20) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels, IBR approved for Sec.  98.254(e).
* * * * *
    (24) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR 
approved for Sec.  98.254(e).
    (25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion, IBR approved for Sec.  98.254(e) and Sec.  98.324(d).
    (26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, IBR approved for Sec.  98.74(c), 
Sec.  98.164(b), Sec.  98.244(b), and Sec.  98.254(i).
    (27) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal, IBR approved for Sec.  98.74(c), Sec.  98.114(b), Sec.  
98.164(b), Sec.  98.174(b), Sec.  98.184(b), Sec.  98.244(b), Sec.  
98.254(i), Sec.  98.274(b), Sec.  98.284(c), Sec.  98.284(d), Sec.  
98.314(c), Sec.  98.314(d), Sec.  98.314(f), and Sec.  98.334(b).
* * * * *
    (30) ASTM D6348-03 Standard Test Method for Determination of 
Gaseous Compounds by Extractive Direct Interface Fourier Transform 
Infrared (FTIR) Spectroscopy, IBR approved for Sec.  98.54(b), Sec.  
98.124(e)(2), Sec.  98.224(b), and Sec.  98.414(n).
* * * * *
    (33) ASTM D6866-08 Standard Test Methods for Determining the 
Biobased Content of Solid, Liquid, and Gaseous Samples Using 
Radiocarbon Analysis, IBR approved for Sec.  98.34(d), Sec.  98.34(e), 
and Sec.  98.36(e).
* * * * *
    (36) ASTM D7459-08 Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved 
for Sec.  98.34(d), Sec.  98.34(e), and Sec.  98.36(e).
* * * * *
    (48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, 
approved July 1, 2009, IBR approved for Sec.  98.244(b)(4)(xi).
    (49) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon 
Content, approved May 15, 2010, IBR approved for Sec.  
98.244(b)(4)(xii).
* * * * *
    (f) * * *
    (1) [Reserved]
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, IBR approved for Sec.  98.164(b), Sec.  
98.254(d), Sec.  98.344(b), and Sec.  98.354(g).
* * * * *
    (m) * * *
    (3) Protocol for Measuring Destruction or Removal Efficiency (DRE) 
of Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-
003), http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf, 
IBR approved for Sec.  98.94(f)(4)(i), Sec.  98.94(g)(3), Sec.  
98.97(d)(4), Sec.  98.98, Sec.  98.124(e)(2), and Sec.  98.414(n)(1).
* * * * *
    (8) Protocol for Measurement of Tetrafluoromethane (CF4) 
and Hexafluoroethane (C2F6) Emissions from 
Primary Aluminum Production (2008), http://www.epa.gov/highgwp/aluminum-pfc/documents/measureprotocol.pdf, IBR approved for Sec.  
98.64(a).
    (9) AP 42, Section 5.2, Transportation and Marketing of Petroleum 
Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42, 
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, 
IBR approved for Sec.  98.253(n).
    (10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 
(Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, ``Test Methods for Evaluating 
Solid Waste, Physical/Chemical Methods,'' Third Edition, IBR approved 
for Sec.  98.244(b)(4)(viii).
    (11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, 
September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, ``Test 
Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' Third 
Edition, IBR approved for Sec.  98.244(b)(4)(viii).
    (12) Method 8021B, Aromatic and Halogenated Volatiles By Gas 
Chromatography Using Photoionization and/or Electrolytic Conductivity 
Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA 
Publication No. SW-846, ``Test Methods for Evaluating Solid

[[Page 79140]]

Waste, Physical/Chemical Methods,'' Third Edition, IBR approved for 
Sec.  98.244(b)(4)(viii).
    (13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, 
Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW-846, 
``Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,'' 
Third Edition, IBR approved for Sec.  98.244(b)(4)(viii).
    (14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 
2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42, 
Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, 
IBR approved for Sec.  98.253(m)(1) and Sec.  98.256(o)(2)(i).

0
6. Table A-5 to subpart A of part 98 is amended by revising the entry 
for paragraph (B) under the heading ``Natural gas and natural gas 
liquids suppliers (subpart NN)'' to read as follows:

   Table A-5 to Subpart A of Part 98--Supplier Category List for Sec.
                               98.2(a)(4)
------------------------------------------------------------------------
 
-------------------------------------------------------------------------
       Supplier Categories \a\ Applicable in 2010 and Future Years
------------------------------------------------------------------------
 
                                * * * * *
Natural gas and natural gas liquids suppliers (subpart NN)
 
                                * * * * *
(B) Local natural gas distribution companies that deliver 460,000
 thousand standard cubic feet or more of natural gas per year.
 
                                * * * * *
------------------------------------------------------------------------
\a\ Suppliers are defined in each applicable subpart.

---------------------------------------------------------------------------
Subpart C--[Amended]

0
7. Section 98.30 is amended by:
0
a. Revising paragraph (b)(4).
0
b. Revising paragraph (c) introductory text.
0
c. Adding paragraph (d).


Sec.  98.30  Definition of the source category.

* * * * *
    (b) * * *
    (4) Flares, unless otherwise required by provisions of another 
subpart of this part to use methodologies in this subpart.
* * * * *
    (c) For a unit that combusts hazardous waste (as defined in Sec.  
261.3 of this chapter), reporting of GHG emissions is not required 
unless either of the following conditions apply:
* * * * *
    (d) You are not required to report GHG emissions from pilot lights. 
A pilot light is a small auxiliary flame that ignites the burner of a 
combustion device when the control valve opens.

0
8. Section 98.32 is revised to read as follows:


Sec.  98.32  GHGs to report.

    You must report CO2, CH4, and N2O 
mass emissions from each stationary fuel combustion unit, except as 
otherwise indicated in this subpart.

0
9. Section 98.33 is amended by:
0
a. Revising paragraph (a) introductory text and paragraph (a)(1).
0
b. Revising the definition of ``HHV'' in Equation C-2a of paragraph 
(a)(2)(i).
0
c. Revising the first two sentences of paragraph (a)(2)(ii) 
introductory text.
0
d. In paragraph (a)(2)(ii)(A), revising the first sentence and the 
definitions of ``(HHV)i,'' ``(Fuel)i,'' and ``n'' 
in Equation C-2b.
0
e. Revising paragraph (a)(2)(ii)(B).
0
f. Revising the definitions of ``CC'', ``MW'', and ``MVC'' in Equation 
C-5 of paragraph (a)(3)(iii).
0
g. Revising paragraphs (a)(3)(iv), (a)(3)(v), (a)(4)(iii), and 
(a)(4)(iv).
0
h. Adding paragraph (a)(4)(viii).
0
i. Revising paragraphs (a)(5) introductory text, (a)(5)(i) introductory 
text, (a)(5)(i)(A), (a)(5)(i)(B), (a)(5)(ii) introductory text, 
(a)(5)(ii)(A), (a)(5)(iii) introductory text, (a)(5)(iii)(A), and 
(a)(5)(iii)(B).
0
j. Redesignating paragraph (a)(5)(iii)(D) as paragraph (a)(5)(iv), and 
revising newly designated paragraph (a)(5)(iv).
0
k. Revising paragraph (b)(1)(iv).
0
l. Adding paragraphs (b)(1)(v), (b)(1)(vi) and (b)(1)(vii).
0
m. Revising paragraphs (b)(2)(ii), (b)(3)(ii)(A), (b)(3)(iii) 
introductory text, and (b)(3)(iii)(B).
0
n. Adding paragraph (b)(3)(iv).
0
o. Adding a second sentence to paragraph (b)(4)(i).
0
p. Revising paragraphs (b)(4)(ii)(A), (b)(4)(ii)(B), (b)(4)(ii)(E), 
(b)(4)(ii)(F), and (b)(4)(iii) introductory text.
0
q. Adding paragraph (b)(4)(iv).
0
r. Revising paragraph (b)(5) and the third sentence of paragraph 
(b)(6).
0
s. Revising paragraph (c)(1) introductory text and the definition of 
``HHV'' in Equation C-8.
0
t. Adding paragraphs (c)(1)(i) and (c)(1)(ii).
0
u. Revising the second sentence of paragraph (c)(2).
0
v. In paragraph (c)(4) introductory text, revising the only sentence 
and revising the definition of ``(HI)A'' in Equation C-10.
0
w. Revising paragraphs (c)(4)(i) and (c)(4)(ii).
0
x. Revising paragraph (c)(5).
0
y. Adding paragraph (c)(6).
0
z. In paragraph (d)(1), revising the first sentence, adding a second 
sentence, and revising the definition of ``R'' in Equation C-11.
0
aa. Revising paragraphs (d)(2), paragraph (e) introductory text, 
paragraph (e)(1), and paragraph (e)(2) introductory text.
0
bb. Revising the definition of ``Fc'' in Equation C-13 of 
paragraph (e)(2)(iii).
0
cc. Revising paragraphs (e)(2)(iv), (e)(2)(vi)(C), and (e)(3).
0
dd. Removing paragraph (e)(4).
0
ee. Redesignating paragraph (e)(5) as (e)(4).
0
ff. Revising the first sentence of newly designated paragraph (e)(4).
0
gg. Adding paragraph (e)(5).


Sec.  98.33  Calculating GHG emissions.

* * * * *
    (a) CO2 emissions from fuel combustion. Calculate CO2 
mass emissions by using one of the four calculation methodologies in 
paragraphs (a)(1) through (a)(4) of this section, subject to the 
applicable conditions, requirements, and restrictions set forth in 
paragraph (b) of this section. Alternatively, for units that meet the 
conditions of paragraph (a)(5) of this section, you may use 
CO2 mass emissions calculation methods from part 75 of this 
chapter, as described in paragraph (a)(5) of this section. For units 
that combust both biomass and fossil fuels, you must calculate and 
report CO2 emissions from the combustion of biomass 
separately using the methods in paragraph (e) of this section, except 
as otherwise provided in paragraphs (a)(5)(iv) and (e) of this section 
and in Sec.  98.36(d).
    (1) Tier 1 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using Equation 
C-1, C-1a, or C-1b of this section (as applicable).
    (i) Use Equation C-1 except when natural gas billing records are 
used to quantify fuel usage and gas consumption is expressed in units 
of therms or million Btu. In that case, use Equation C-1a or C-1b, as 
applicable.

[[Page 79141]]

[GRAPHIC] [TIFF OMITTED] TR17DE10.015

Where:

CO2 = Annual CO2 mass emissions for the 
specific fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company 
records as defined in Sec.  98.6 (express mass in short tons for 
solid fuel, volume in standard cubic feet for gaseous fuel, and 
volume in gallons for liquid fuel).
HHV = Default high heat value of the fuel, from Table C-1 of this 
subpart (mmBtu per mass or mmBtu per volume, as applicable).
EF = Fuel-specific default CO2 emission factor, from 
Table C-1 of this subpart (kg CO2/mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (ii) If natural gas consumption is obtained from billing records 
and fuel usage is expressed in therms, use Equation C-1a.
[GRAPHIC] [TIFF OMITTED] TR17DE10.016

Where:

CO2 = Annual CO2 mass emissions from natural 
gas combustion (metric tons).
Gas = Annual natural gas usage, from billing records (therms).
EF = Fuel-specific default CO2 emission factor for 
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (iii) If natural gas consumption is obtained from billing records 
and fuel usage is expressed in mmBtu, use Equation C-1b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.017

Where:

CO2 = Annual CO2 mass emissions from natural 
gas combustion (metric tons).
Gas = Annual natural gas usage, from billing records (mmBtu).
EF = Fuel-specific default CO2 emission factor for 
natural gas, from Table C-1 of this subpart (kg CO2/
mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (2) * * *
    (i) * * *

HHV = Annual average high heat value of the fuel (mmBtu per mass or 
volume). The average HHV shall be calculated according to the 
requirements of paragraph (a)(2)(ii) of this section.
* * * * *
    (ii) The minimum required sampling frequency for determining the 
annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot) 
is specified in Sec.  98.34. The method for computing the annual 
average HHV is a function of unit size and how frequently you perform 
or receive from the fuel supplier the results of fuel sampling for HHV. 
* * *
    (A) If the results of fuel sampling are received monthly or more 
frequently, then for each unit with a maximum rated heat input capacity 
greater than or equal to 100 mmBtu/hr (or for a group of units that 
includes at least one unit of that size), the annual average HHV shall 
be calculated using Equation C-2b of this section. * * *
* * * * *
(HHV)I = Measured high heat value of the fuel, for month 
``i'' (which may be the arithmetic average of multiple 
determinations), or, if applicable, an appropriate substitute data 
value (mmBtu per mass or volume).
(Fuel)I = Mass or volume of the fuel combusted during 
month ``i,'' from company records (express mass in short tons for 
solid fuel, volume in standard cubic feet for gaseous fuel, and 
volume in gallons for liquid fuel).
n = Number of months in the year that the fuel is burned in the 
unit.

    (B) If the results of fuel sampling are received less frequently 
than monthly, or, for a unit with a maximum rated heat input capacity 
less than 100 mmBtu/hr (or a group of such units) regardless of the HHV 
sampling frequency, the annual average HHV shall either be computed 
according to paragraph (a)(2)(ii)(A) of this section or as the 
arithmetic average HHV for all values for the year (including valid 
samples and substitute data values under Sec.  98.35).
* * * * *
    (3) * * *
    (iii) * * *

CC = Annual average carbon content of the gaseous fuel (kg C per kg 
of fuel). The annual average carbon content shall be determined 
using the same procedures as specified for HHV in paragraph 
(a)(2)(ii) of this section.
MW = Annual average molecular weight of the gaseous fuel (kg/kg-
mole). The annual average molecular weight shall be determined using 
the same procedures as specified for HHV in paragraph (a)(2)(ii) of 
this section.
MVC = Molar volume conversion factor at standard conditions, as 
defined in Sec.  98.6. Use 849.5 scf per kg mole if you select 68 
[deg]F as standard temperature and 836.6 scf per kg mole if you 
select 60 [deg]F as standard temperature.
* * * * *
    (iv) Fuel flow meters that measure mass flow rates may be used for 
liquid or gaseous fuels, provided that the fuel density is used to 
convert the readings to volumetric flow rates. The density shall be 
measured at the same frequency as the carbon content. You must measure 
the density using one of the following appropriate methods. You may use 
a method published by a consensus-based standards organization, if such 
a method exists, or you may use industry standard practice. Consensus-
based standards organizations include, but are not limited to, the 
following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, 
West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA), 400 North Capitol 
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), 
and the North American Energy Standards Board (NAESB, 801 Travis 
Street, Suite 1675, Houston, TX 77002,

[[Page 79142]]

(713) 356-0060, http://www.api.org). The method(s) used shall be 
documented in the GHG Monitoring Plan required under Sec.  98.3(g)(5).
    (v) The following default density values may be used for fuel oil, 
in lieu of using the methods in paragraph (a)(3)(iv) of this section: 
6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 
6 oil.
* * * * *
    (4) * * *
    (iii) If the CO2 concentration is measured on a dry 
basis, a correction for the stack gas moisture content is required. You 
shall either continuously monitor the stack gas moisture content using 
a method described in Sec.  75.11(b)(2) of this chapter or use an 
appropriate default moisture percentage. For coal, wood, and natural 
gas combustion, you may use the default moisture values specified in 
Sec.  75.11(b)(1) of this chapter. Alternatively, for any type of fuel, 
you may determine an appropriate site-specific default moisture value 
(or values), using measurements made with EPA Method 4--Determination 
Of Moisture Content In Stack Gases, in appendix A-3 to part 60 of this 
chapter. Moisture data from the relative accuracy test audit (RATA) of 
a CEMS may be used for this purpose. If this option is selected, the 
site-specific moisture default value(s) must represent the fuel(s) or 
fuel blends that are combusted in the unit during normal, stable 
operation, and must account for any distinct difference(s) in the stack 
gas moisture content associated with different process operating 
conditions. For each site-specific default moisture percentage, at 
least nine Method 4 runs are required, except where the option to use 
moisture data from a RATA is selected, and the applicable regulation 
allows a single moisture determination to represent two or more RATA 
runs. In that case, you may base the site-specific moisture percentage 
on the number of moisture runs allowed by the RATA regulation. 
Calculate each site-specific default moisture value by taking the 
arithmetic average of the Method 4 runs. Each site-specific moisture 
default value shall be updated whenever the owner or operator believes 
the current value is non-representative, due to changes in unit or 
process operation, but in any event no less frequently than annually. 
Use the updated moisture value in the subsequent CO2 
emissions calculations. For each unit operating hour, a moisture 
correction must be applied to Equation C-6 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR17DE10.002

Where:

CO2* = Hourly CO2 mass emission rate, 
corrected for moisture (metric tons/hr).
CO2 = Hourly CO2 mass emission rate from 
Equation C-6 of this section, uncorrected (metric tons/hr).
%H2O = Hourly moisture percentage in the stack gas 
(measured or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in 
lieu of a CO2 concentration monitor to determine the hourly 
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the 
effluent gas stream monitored by the CEMS consists solely of combustion 
products (i.e., no process CO2 emissions or CO2 
emissions from sorbent are mixed with the combustion products) and if 
only fuels that are listed in Table 1 in section 3.3.5 of appendix F to 
part 75 of this chapter are combusted in the unit. If the O2 
monitoring option is selected, the F-factors used in Equations F-14a 
and F-14b shall be determined according to section 3.3.5 or section 
3.3.6 of appendix F to part 75 of this chapter, as applicable. If 
Equation F-14b is used, the hourly moisture percentage in the stack gas 
shall be determined in accordance with paragraph (a)(4)(iii) of this 
section.
* * * * *
    (viii) If a portion of the flue gases generated by a unit subject 
to Tier 4 (e.g., a slip stream) is continuously diverted from the main 
flue gas exhaust system for the purpose of heat recovery or some other 
similar process, and then exhausts through a stack that is not equipped 
with the continuous emission monitors to measure CO2 mass 
emissions, CO2 emissions shall be determined as follows:
    (A) At least once a year, use EPA Methods 2 and 3A, and (if 
necessary) Method 4 in appendices A-2 and A-3 to part 60 of this 
chapter to perform emissions testing at a set point that best 
represents normal, stable process operating conditions. A minimum of 
three one-hour Method 3A tests are required, to determine the 
CO2 concentration. A Method 2 test shall be performed during 
each Method 3A run, to determine the stack gas volumetric flow rate. If 
moisture correction is necessary, a Method 4 run shall also be 
performed during each Method 3A run. Important parametric information 
related to the stack gas flow rate (e.g., damper positions, fan 
settings, etc.) shall also be recorded during the test.
    (B) Calculate a CO2 mass emission rate (in metric tons/
hr) from the stack test data, using a version of Equation C-6 in 
paragraph (a)(4)(ii) of this section, modified as follows. In the 
Equation C-6 nomenclature, replace the words ``Hourly average'' in the 
definitions of ``CCO2'' and ``Q'' with the words ``3-run 
average''. Substitute the arithmetic average values of CO2 
concentration and stack gas flow rate from the emission testing into 
modified Equation C-6. If CO2 is measured on a dry basis, a 
moisture correction of the calculated CO2 mass emission rate 
is required. Use Equation C-7 in paragraph (a)(4)(ii) of this section 
to make this correction; replace the word ``Hourly'' with the words 
``3-run average'' in the equation nomenclature.
    (C) The results of each annual stack test shall be used in the GHG 
emissions calculations for the year of the test.
    (D) If, for the majority of the operating hours during the year, 
the diverted stream is withdrawn at a steady rate at or near the tested 
set point (as evidenced by fan and damper settings and/or other 
parameters), you may use the calculated CO2 mass emission 
rate from paragraph (a)(4)(viii)(B) of this section to estimate the 
CO2 mass emissions for all operating hours in which flue gas 
is diverted from the main exhaust system. Otherwise, you must account 
for the variation in the flow rate of the diverted stream, as described 
in paragraph (c)(4)(viii)(E) of this section.
    (E) If the flow rate of the diverted stream varies significantly 
throughout the year, except as provided below, repeat the stack test 
and emission rate calculation procedures described in paragraphs 
(c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two 
more set points across the range of typical operating conditions to 
develop a correlation between CO2 mass emission rate and the 
parametric data. If additional testing is not feasible, use the 
following approach to develop the necessary correlation. Assume that 
the average CO2 concentration obtained in the annual stack 
test is the same at all operating set points. Then, beginning

[[Page 79143]]

with the measured flow rate from the stack test and the associated 
parametric data, perform an engineering analysis to estimate the stack 
gas flow rate at two or more additional set points. Calculate the 
CO2 mass emission rate at each set point.
    (F) Calculate the annual CO2 mass emissions for the 
diverted stream as follows. For a steady-state process, multiply the 
number of hours in which flue gas was diverted from the main exhaust 
system by the CO2 mass emission rate from the stack test. 
Otherwise, using the best available information and engineering 
judgment, apply the most representative CO2 mass emission 
rate from the correlation in paragraph (c)(4)(viii)(E) of this section 
to determine the CO2 mass emissions for each hour in which 
flue gas was diverted, and sum the results. To simplify the 
calculations, you may count partial operating hours as full hours.
    (G) Finally, add the CO2 mass emissions from 
paragraph(c)(4)(viii)(F) of this section to the annual CO2 
mass emissions measured by the CEMS at the main stack. Report this sum 
as the total annual CO2 mass emissions for the unit.
    (H) The exact method and procedures used to estimate the 
CO2 mass emissions for the diverted portion of the flue gas 
exhaust stream shall be documented in the Monitoring Plan required 
under Sec.  98.3(g)(5).
    (5) Alternative methods for certain units subject to Part 75 of 
this chapter. Certain units that are not subject to subpart D of this 
part and that report data to EPA according to part 75 of this chapter 
may qualify to use the alternative methods in this paragraph (a)(5), in 
lieu of using any of the four calculation methodology tiers.
    (i) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to appendix D to part 75 of this chapter, but 
is not required by the applicable part 75 program to report 
CO2 mass emissions data, calculate the annual CO2 
mass emissions for the purposes of this part as follows:
    (A) Use the hourly heat input data from appendix D to part 75 of 
this chapter, together with Equation G-4 in appendix G to part 75 of 
this chapter to determine the hourly CO2 mass emission 
rates, in units of tons/hr;
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapter to calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons; and
* * * * *
    (ii) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to subpart D of this part, monitors and reports heat input 
data year-round according to Sec.  75.19 of this chapter but is not 
required by the applicable part 75 program to report CO2 
mass emissions data, calculate the annual CO2 mass emissions 
for the purposes of this part as follows:
    (A) Calculate the hourly CO2 mass emissions, in units of 
short tons, using Equation LM-11 in Sec.  75.19(c)(4)(iii) of this 
chapter.
* * * * *
    (iii) For a unit that is not subject to subpart D of this part, 
uses flow rate and CO2 (or O2) CEMS to report 
heat input data year-round according to part 75 of this chapter, but is 
not required by the applicable part 75 program to report CO2 
mass emissions data, calculate the annual CO2 mass emissions 
as follows:
    (A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 
75 of this chapter to calculate the hourly CO2 mass emission 
rates from the CEMS data. If an O2 monitor is used, convert 
the hourly average O2 readings to CO2 using 
Equation F-14a or F-14b in appendix F to part 75 of this chapter (as 
applicable), before applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to part 75 of this 
chapter to calculate the quarterly and cumulative annual CO2 
mass emissions, respectively, in units of short tons.
* * * * *
    (iv) For units that qualify to use the alternative CO2 
emissions calculation methods in paragraphs (a)(5)(i) through 
(a)(5)(iii) of this section, if both biomass and fossil fuel are 
combusted during the year, separate calculation and reporting of the 
biogenic CO2 mass emissions (as described in paragraph (e) 
of this section) is optional, only for the 2010 reporting year, as 
provided in Sec.  98.3(c)(12).
    (b) * * *
    (1) * * *
    (iv) May not be used if you routinely perform fuel sampling and 
analysis for the fuel high heat value (HHV) or routinely receive the 
results of HHV sampling and analysis from the fuel supplier at the 
minimum frequency specified in Sec.  98.34(a), or at a greater 
frequency. In such cases, Tier 2 shall be used. This restriction does 
not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and 
(b)(1)(vii) of this section.
    (v) May be used for natural gas combustion in a unit of any size, 
in cases where the annual natural gas consumption is obtained from fuel 
billing records in units of therms or mmBtu.
    (vi) May be used for MSW combustion in a small, batch incinerator 
that burns no more than 1,000 tons per year of MSW.
    (vii) May be used for the combustion of MSW and/or tires in a unit, 
provided that no more than 10 percent of the unit's annual heat input 
is derived from those fuels, combined. Notwithstanding this 
requirement, if a unit combusts both MSW and tires and the reporter 
elects not to separately calculate and report biogenic CO2 
emissions from the combustion of tires, Tier 1 may be used for the MSW 
combustion, provided that no more than 10 percent of the unit's annual 
heat input is derived from MSW.
    (2) * * *
    (ii) May be used in a unit with a maximum rated heat input capacity 
greater than 250 mmBtu/hr for the combustion of natural gas and/or 
distillate fuel oil.
* * * * *
    (3) * * *
    (ii) * * *
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs 
(b)(1)(iii), (b)(1)(v), and (b)(2)(ii) of this section.
* * * * *
    (iii) Shall be used for a fuel not listed in Table C-1 of this 
subpart if the fuel is combusted in a unit with a maximum rated heat 
input capacity greater than 250 mmBtu/hr (or, pursuant to Sec.  
98.36(c)(3), in a group of units served by a common supply pipe, having 
at least one unit with a maximum rated heat input capacity greater than 
250 mmBtu/hr), provided that both of the following conditions apply:
* * * * *
    (B) The fuel provides 10% or more of the annual heat input to the 
unit or, if Sec.  98.36(c)(3) applies, to the group of units served by 
a common supply pipe.
    (iv) Shall be used when specified in another applicable subpart of 
this part, regardless of unit size.
    (4) * * *
    (i) * * * Tier 4 may also be used for any group of stationary fuel 
combustion units, process units, or manufacturing units that share a 
common stack or duct.
    (ii) * * *
    (A) The unit has a maximum rated heat input capacity greater than 
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a 
maximum rated input capacity greater than 600 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW as the primary fuel.
* * * * *
    (E) The installed CEMS include a gas monitor of any kind or a stack 
gas volumetric flow rate monitor, or both and the monitors have been 
certified,

[[Page 79144]]

either in accordance with the requirements of part 75 of this chapter, 
part 60 of this chapter, or an applicable State continuous monitoring 
program.
    (F) The installed gas or stack gas volumetric flow rate monitors 
are required, either by an applicable Federal or State regulation or by 
the unit's operating permit, to undergo periodic quality assurance 
testing in accordance with either appendix B to part 75 of this 
chapter, appendix F to part 60 of this chapter, or an applicable State 
continuous monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input 
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal 
solid waste with a maximum rated input capacity of 600 tons of MSW per 
day or less, if the unit meets all of the following three conditions:
* * * * *
    (iv) May apply to common stack or duct configurations where:
    (A) The combined effluent gas streams from two or more stationary 
fuel combustion units are vented through a monitored common stack or 
duct. In this case, Tier 4 shall be used if all of the conditions in 
paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in 
paragraph (b)(4)(iv)(A)(2) of this section are met.
    (1) At least one of the units meets the requirements of paragraphs 
(b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS 
installed at the common stack (or duct) meet the requirements of 
paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
    (2) At least one of the units and the monitors installed at the 
common stack or duct meet the requirements of paragraph (b)(4)(iii) of 
this section.
    (B) The combined effluent gas streams from a process or 
manufacturing unit and a stationary fuel combustion unit are vented 
through a monitored common stack or duct. In this case, Tier 4 shall be 
used if the combustion unit and the monitors installed at the common 
stack or duct meet the applicability criteria specified in paragraph 
(b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
    (C) The combined effluent gas streams from two or more 
manufacturing or process units are vented through a common stack or 
duct. In this case, if any of the units is required by an applicable 
subpart of this part to use Tier 4, the CO2 mass emissions 
may be monitored at each individual unit, or the combined 
CO2 mass emissions may be monitored at the common stack or 
duct. However, if it is not feasible to monitor the individual units, 
the combined CO2 mass emissions shall be monitored at the 
common stack or duct.
    (5) The Tier 4 Calculation Methodology shall be used:
    (i) Starting on January 1, 2010, for a unit that is required to 
report CO2 mass emissions beginning on that date, if all of 
the monitors needed to measure CO2 mass emissions have been 
installed and certified by that date.
    (ii) No later than January 1, 2011, for a unit that is required to 
report CO2 mass emissions beginning on January 1, 2010, if 
all of the monitors needed to measure CO2 mass emissions 
have not been installed and certified by January 1, 2010. In this case, 
you may use Tier 2 or Tier 3 to report GHG emissions for 2010. However, 
if the required CEMS are certified some time in 2010, you need not wait 
until January 1, 2011 to begin using Tier 4. Rather, you may switch 
from Tier 2 or Tier 3 to Tier 4 as soon as CEMS certification testing 
is successfully completed. If this reporting option is chosen, you must 
document the change in CO2 calculation methodology in the 
Monitoring Plan required under Sec.  98.3(g)(5) and in the GHG 
emissions report under Sec.  98.3(c). Data recorded by the CEMS during 
a certification test period in 2010 may be used for reporting under 
this part, provided that the following two conditions are met:
    (A) The certification tests are passed in sequence, with no test 
failures.
    (B) No unscheduled maintenance or repair of the CEMS is performed 
during the certification test period.
    (iii) No later than 180 days following the date on which a change 
is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) 
or (b)(4)(iii) of this section (e.g., a change in the primary fuel, 
manner of unit operation, or installed continuous monitoring 
equipment).
    (6) * * * However, for units that use either the Tier 4 or the 
alternative calculation methodology specified in paragraph (a)(5)(iii) 
of this section, CO2 emissions from the combustion of all 
fuels shall be based solely on CEMS measurements.
    (c) * * *
    (1) Use Equation C-8 of this section to estimate CH4 and 
N2O emissions for any fuels for which you use the Tier 1 or 
Tier 3 calculation methodologies for CO2, except when 
natural gas usage in units of therms or mmBtu is obtained from gas 
billing records. In that case, use Equation C-8a in paragraph (c)(1)(i) 
of this section or Equation C-8b in paragraph (c)(1)(ii) of this 
section (as applicable). For Equation C-8, use the same values for fuel 
consumption that you use for the Tier 1 or Tier 3 calculation.
* * * * *
HHV = Default high heat value of the fuel from Table C-1 of this 
subpart; alternatively, for Tier 3, if actual HHV data are available 
for the reporting year, you may average these data using the 
procedures specified in paragraph (a)(2)(ii) of this section, and 
use the average value in Equation C-8 (mmBtu per mass or volume).
* * * * *
    (i) Use Equation C-8a to calculate CH4 and 
N2O emissions when natural gas usage is obtained from gas 
billing records in units of therms.
[GRAPHIC] [TIFF OMITTED] TR17DE10.018

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of natural gas (metric 
tons).
Fuel = Annual natural gas usage, from gas billing records (therms).
EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu).
0.1 = Conversion factor from therms to mmBtu
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (ii) Use Equation C-8b to calculate CH4 and 
N2O emissions when natural gas usage is obtained from gas 
billing records in units of mmBtu.
    CH4 or N2O = 1 x 10-\3\ * Fuel * 
EF (Eq. C-8b)

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of natural gas (metric 
tons).
Fuel = Annual natural gas usage, from gas billing records (mmBtu).
EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric 
tons.


[[Page 79145]]


    (2) * * * Use the same values for fuel consumption and HHV that you 
use for the Tier 2 calculation.
* * * * *
    (4) Use Equation C-10 of this section for: units subject to subpart 
D of this part; units that qualify for and elect to use the alternative 
CO2 mass emissions calculation methodologies described in 
paragraph (a)(5) of this section; and units that use the Tier 4 
Calculation Methodology.
* * * * *
(HI)A = Cumulative annual heat input from combustion of 
the fuel (mmBtu).
* * * * *
    (i) If only one type of fuel listed in Table C-2 of this subpart is 
combusted during the reporting year, substitute the cumulative annual 
heat input from combustion of the fuel into Equation C-10 of this 
section to calculate the annual CH4 or N2O 
emissions. For units in the Acid Rain Program and units that report 
heat input data to EPA year-round according to part 75 of this chapter, 
obtain the cumulative annual heat input directly from the electronic 
data reports required under Sec.  75.64 of this chapter. For Tier 4 
units, use the best available information, as described in paragraph 
(c)(4)(ii)(C) of this section, to estimate the cumulative annual heat 
input (HI)A.
    (ii) If more than one type of fuel listed in Table C-2 of this 
subpart is combusted during the reporting year, use Equation C-10 of 
this section separately for each type of fuel, except as provided in 
paragraph (c)(4)(ii)(B) of this section. Determine the appropriate 
values of (HI)A as follows:
    (A) For units in the Acid Rain Program and other units that report 
heat input data to EPA year-round according to part 75 of this chapter, 
obtain (HI)A for each type of fuel from the electronic data 
reports required under Sec.  75.64 of this chapter, except as otherwise 
provided in paragraphs (c)(4)(ii)(B) and (c)(4)(ii)(D) of this section.
    (B) For a unit that uses CEMS to monitor hourly heat input 
according to part 75 of this chapter, the value of (HI)A 
obtained from the electronic data reports under Sec.  75.64 of this 
chapter may be attributed exclusively to the fuel with the highest F-
factor, when the reporting option in 3.3.6.5 of appendix F to part 75 
of this chapter is selected and implemented.
    (C) For Tier 4 units, use the best available information (e.g., 
fuel feed rate measurements, fuel heating values, engineering analysis) 
to estimate the value of (HI)A for each type of fuel. 
Instrumentation used to make these estimates is not subject to the 
calibration requirements of Sec.  98.3(i) or to the QA requirements of 
Sec.  98.34.
    (D) Units in the Acid Rain Program and other units that report heat 
input data to EPA year-round according to part 75 of this chapter may 
use the best available information described in paragraph (c)(4)(ii)(C) 
of this section, to estimate (HI)A for each fuel type, 
whenever fuel-specific heat input values cannot be directly obtained 
from the electronic data reports under Sec.  75.64 of this chapter.
    (5) When multiple fuels are combusted during the reporting year, 
sum the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-
9b, or C-10 of this section (as applicable) to obtain the total annual 
CH4 and N2O emissions, in metric tons.
    (6) Calculate the annual CH4 and N2O mass 
emissions from the combustion of blended fuels as follows:
    (i) If the mass or volume of each component fuel in the blend is 
measured before the fuels are mixed and combusted, calculate and report 
CH4 and N2O emissions separately for each 
component fuel, using the applicable procedures in this paragraph (c).
    (ii) If the mass or volume of each component fuel in the blend is 
not measured before the fuels are mixed and combusted, a reasonable 
estimate of the percentage composition of the blend, based on best 
available information, is required. Perform the following calculations 
for each component fuel ``i'' that is listed in Table C-2:
    (A) Multiply (% Fuel)i, the estimated mass or volume 
percentage (decimal fraction) of component fuel ``i'', by the total 
annual mass or volume of the blended fuel combusted during the 
reporting year, to obtain an estimate of the annual consumption of 
component ``i'';
    (B) Multiply the result from paragraph (c)(6)(ii)(A) of this 
section by the HHV of the fuel (default value or, if available, the 
measured annual average value), to obtain an estimate of the annual 
heat input from component ``i'';
    (C) Calculate the annual CH4 and N2O 
emissions from component ``i'', using Equation C-8, C-8a, C-8b, C-9a, 
or C-10 of this section, as applicable;
    (D) Sum the annual CH4 emissions across all component 
fuels to obtain the annual CH4 emissions for the blend. 
Similarly sum the annual N2O emissions across all component 
fuels to obtain the annual N2O emissions for the blend. 
Report these annual emissions totals.
    (d) * * *
    (1) When a unit is a fluidized bed boiler, is equipped with a wet 
flue gas desulfurization system, or uses other acid gas emission 
controls with sorbent injection to remove acid gases, if the chemical 
reaction between the acid gas and the sorbent produces CO2 
emissions, use Equation C-11 of this section to calculate the 
CO2 emissions from the sorbent, except when those 
CO2 emissions are monitored by CEMS. When a sorbent other 
than CaCO3 is used, determine site-specific values of R and 
MWS.
* * * * *
R = The number of moles of CO2 released upon capture of 
one mole of the acid gas species being removed (R = 1.00 when the 
sorbent is CaCO3 and the targeted acid gas species is 
SO2).
* * * * *
    (2) The total annual CO2 mass emissions reported for the 
unit shall include the CO2 emissions from the combustion 
process and the CO2 emissions from the sorbent.
    (e) Biogenic CO2 emissions from combustion of biomass with other 
fuels. Use the applicable procedures of this paragraph (e) to estimate 
biogenic CO2 emissions from units that combust a combination 
of biomass and fossil fuels (i.e., either co-fired or blended fuels). 
Separate reporting of biogenic CO2 emissions from the 
combined combustion of biomass and fossil fuels is required for those 
biomass fuels listed in Table C-1 of this section and for municipal 
solid waste. In addition, when a biomass fuel that is not listed in 
Table C-1 is combusted in a unit that has a maximum rated heat input 
greater than 250 mmBtu/hr, if the biomass fuel accounts for 10% or more 
of the annual heat input to the unit, and if the unit does not use CEMS 
to quantify its annual CO2 mass emissions, then, pursuant to 
Sec.  98.33(b)(3)(iii), Tier 3 must be used to determine the carbon 
content of the biomass fuel and to calculate the biogenic 
CO2 emissions from combustion of the fuel. Notwithstanding 
these requirements, in accordance with Sec.  98.3(c)(12), separate 
reporting of biogenic CO2 emissions is optional for the 2010 
reporting year for units subject to subpart D of this part and for 
units that use the CO2 mass emissions calculation 
methodologies in part 75 of this chapter, pursuant to paragraph (a)(5) 
of this section. However, if the owner or operator opts to report 
biogenic CO2 emissions separately for these units, the 
appropriate method(s) in this paragraph (e) shall be used. Separate 
reporting of biogenic CO2 emissions from the combustion of 
tires is also optional, but may be reported by following the provisions 
of paragraph (e)(3) of this section.

[[Page 79146]]

    (1) You may use Equation C-1 of this subpart to calculate the 
annual CO2 mass emissions from the combustion of the biomass 
fuels listed in Table C-1 of this subpart (except MSW and tires), in a 
unit of any size, including units equipped with a CO2 CEMS, 
except when the use of Tier 2 is required as specified in paragraph 
(b)(1)(iv) of this section. Determine the quantity of biomass combusted 
using one of the following procedures in this paragraph (e)(1), as 
appropriate, and document the selected procedures in the Monitoring 
Plan under Sec.  98.3(g):
    (i) Company records.
    (ii) The procedures in paragraph (e)(5) of this section.
    (iii) The best available information for premixed fuels that 
contain biomass and fossil fuels (e.g., liquid fuel mixtures containing 
biodiesel).
    (2) You may use the procedures of this paragraph if the following 
three conditions are met: First, a CO2 CEMS (or a surrogate 
O2 monitor) and a stack gas flow rate monitor are used to 
determine the annual CO2 mass emissions (either according to 
part 75 of this chapter, the Tier 4 Calculation Methodology, or the 
alternative calculation methodology specified in paragraph (a)(5)(iii) 
of this section); second, neither MSW nor tires is combusted in the 
unit during the reporting year; and third, the CO2 emissions 
consist solely of combustion products (i.e., no process or sorbent 
emissions included).
* * * * *
    (iii) * * *

Fc = Fuel-specific carbon based F-factor, either a 
default value from Table 1 in section 3.3.5 of appendix F to part 75 
of this chapter, or a site-specific value determined under section 
3.3.6 of appendix F to part 75 (scf CO2/mmBtu).
* * * * *
    (iv) Subtract Vff from Vtotal to obtain 
Vbio, the annual volume of CO2 from the 
combustion of biomass.
* * * * *
    (vi) * * *
    (C) From the electronic data report required under Sec.  75.64 of 
this chapter, for units in the Acid Rain Program and other units using 
CEMS to monitor and report CO2 mass emissions according to 
part 75 of this chapter. However, before calculating the annual 
biogenic CO2 mass emissions, multiply the cumulative annual 
CO2 mass emissions by 0.91 to convert from short tons to 
metric tons.
    (3) You must use the procedures in paragraphs (e)(3)(i) through 
(e)(3)(iii) of this section to determine the annual biogenic 
CO2 emissions from the combustion of MSW, except as 
otherwise provided in paragraph (e)(3)(iv) of this section. These 
procedures also may be used for any unit that co-fires biomass and 
fossil fuels, including units equipped with a CO2 CEMS, and 
units for which optional separate reporting of biogenic CO2 
emissions from the combustion of tires is selected.
    (i) Use an applicable CO2 emissions calculation method 
in this section to quantify the total annual CO2 mass 
emissions from the unit.
    (ii) Determine the relative proportions of biogenic and non-
biogenic CO2 emissions in the flue gas on a quarterly basis 
using the method specified in Sec.  98.34(d) (for units that combust 
MSW as the primary fuel or as the only fuel with a biogenic component) 
or in Sec.  98.34(e) (for other units, including units that combust 
tires).
    (iii) Determine the annual biogenic CO2 mass emissions 
from the unit by multiplying the total annual CO2 mass 
emissions by the annual average biogenic decimal fraction obtained from 
Sec.  98.34(d) or Sec.  98.34(e), as applicable.
    (iv) If the combustion of MSW and/or tires provides no more than 10 
percent of the annual heat input to a unit, or if a small, batch 
incinerator combusts no more than 1,000 tons per year of MSW, you may 
estimate the annual biogenic CO2 emissions as follows, in 
lieu of following the procedures in paragraphs (e)(3)(i) through 
(e)(3)(iii) of this section:
    (A) Calculate the total annual CO2 emissions from 
combustion of MSW and/or tires in the unit, using the Tier 1 
calculation methodology in paragraph (a)(1) of this section.
    (B) Multiply the result from paragraph (e)(3)(iv)(A) of this 
section by the appropriate default factor to determine the annual 
biogenic CO2 emissions, in metric tons. For MSW, use a 
default factor of 0.60 and for tires, use a default factor of 0.20.
    (4) If Equation C-1 or Equation C-2a of this section is selected to 
calculate the annual biogenic mass emissions for wood, wood waste, or 
other solid biomass-derived fuel, Equation C-15 of this section may be 
used to quantify biogenic fuel consumption, provided that all of the 
required input parameters are accurately quantified. * * *
    (5) For units subject to subpart D of this part and for units that 
use the methods in part 75 of this chapter to quantify CO2 
mass emissions in accordance with paragraph (a)(5) of this section, you 
may calculate biogenic CO2 emissions from the combustion of 
biomass fuels listed in Table C-1 of this subpart using Equation C-15a. 
This equation may not be used to calculate biogenic CO2 
emissions from the combustion of tires or MSW; the methods described in 
paragraph (e)(3) of this section must be used for those fuels. Whenever 
(HI)A, the annual heat input from combustion of biomass fuel 
in Equation C-15a, cannot be determined solely from the information in 
the electronic emissions reports under Sec.  75.64 of this chapter 
(e.g., in cases where a unit uses CEMS in combination with multiple F-
factors, a worst-case F-factor, or a prorated F-factor to report heat 
input rather than reporting heat input based on fuel type), use the 
best available information (as described in Sec. Sec.  
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D)) to determine (HI)A.

    CO2 = 0.001 * (HI)A * EF (Eq. C-15a)

Where:

CO2 = Annual CO2 mass emissions from the 
combustion of a particular type of biomass fuel listed in Table C-1 
(metric tons)
(HI)A = Annual heat input from the biomass fuel, 
obtained, where feasible, from the electronic emissions reports 
required under Sec.  75.64 of this chapter. Where this is not 
feasible use best available information, as described in Sec. Sec.  
98.33(c)(4)(ii)(C) and (c)(4)(ii)(D) (mmBtu)
EF = CO2 emission factor for the biomass fuel, from Table 
C-1 (kg CO2/mmBtu)
0.001 = Conversion factor from kg to metric tons
* * * * *

0
10. Section 98.34 is amended by:
0
a. Revising paragraphs (a)(2), (a)(3), (a)(6), (b)(1) introductory 
text, (b)(1)(i), (b)(1)(ii), (b)(1)(iii), (b)(1)(vi), (b)(3)(ii), and 
(b)(3)(v).
0
b. Removing paragraph (b)(4).
0
c. Redesignating paragraph (b)(5) as (b)(4).
0
d. Revising newly designated paragraph (b)(4).
0
e. Revising paragraphs (c) introductory text, (c)(1)(i), (c)(1)(ii), 
(c)(2), (c)(3), and (c)(4).
0
f. Adding paragraphs (c)(6) and (c)(7).
0
g. Revising paragraphs (d), (e), (f) introductory text, (f)(1), (f)(3), 
(f)(5), and (f)(6).
0
h. Adding paragraphs (f)(7) and (f)(8).
0
i. Removing paragraph (g).


Sec.  98.34  Monitoring and QA/QC requirements.

* * * * *
    (a) * * *
    (2) The minimum required frequency of the HHV sampling and analysis 
for each type of fuel or fuel mixture (blend) is specified in this 
paragraph. When the specified frequency for a particular fuel or blend 
is based on a specified time period (e.g., week, month, quarter, or 
half-year), fuel sampling and analysis is

[[Page 79147]]

required only for those time periods in which the fuel or blend is 
combusted. The owner or operator may perform fuel sampling and analysis 
more often than the minimum required frequency, in order to obtain a 
more representative annual average HHV.
    (i) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at 
least four months apart).
    (ii) For coal and fuel oil, and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the unit's storage tank. Flow proportional sampling, continuous 
drip sampling, or daily manual oil sampling may also be used, in lieu 
of sampling each fuel lot. If the daily manual oil sampling option is 
selected, sampling from a particular tank is required only on days when 
oil from the tank is combusted by the unit (or units) served by the 
tank. If you elect to sample from the storage tank upon each addition 
of oil to the tank, you must take at least one sample from each tank 
that is currently in service and whenever oil is added to the tank, for 
as long as the tank remains in service. You need not take any samples 
from a storage tank while it is out of service. Rather, take a sample 
when the tank is brought into service and whenever oil is added to the 
tank, for as long as the tank remains in service. If multiple additions 
of oil are made to a particular in-service tank on a given day (e.g., 
from multiple deliveries), one sample taken after the final addition of 
oil is sufficient. For the purposes of this section, a fuel lot is 
defined as a shipment or delivery of a single type of fuel (e.g., ship 
load, barge load, group of trucks, group of railroad cars, oil delivery 
via pipeline from a tank farm, etc.). However, if multiple deliveries 
of a particular type of fuel are received from the same supply source 
in a given calendar month, the deliveries for that month may be 
considered, collectively, to comprise a fuel lot, requiring only one 
representative sample, subject to the following conditions:
    (A) For coal, the ``type'' of fuel means the rank of the coal 
(i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel 
oil, the ``type'' of fuel means the grade number or classification of 
the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
    (B) The owner or operator shall document in the monitoring plan 
under Sec.  98.3(g)(5) how the monthly sampling of each type of fuel is 
performed.
    (iii) For liquid fuels other than fuel oil, and for gaseous fuels 
other than natural gas (including biogas), sampling and analysis is 
required at least once per calendar quarter. To the extent practicable, 
consecutive quarterly samples shall be taken at least 30 days apart.
    (iv) For other solid fuels (except MSW), weekly sampling is 
required to obtain composite samples, which are then analyzed monthly.
    (v) For fuel blends that are received already mixed, or that are 
mixed on-site without measuring the exact amount of each component, as 
described in paragraph (a)(3)(ii) of this section, determine the HHV of 
the blend as follows. For blends of solid fuels (except MSW), weekly 
sampling is required to obtain composite samples, which are analyzed 
monthly. For blends of liquid or gaseous fuels, sampling and analysis 
is required at least once per calendar quarter. More frequent sampling 
is recommended if the composition of the blend varies significantly 
during the year.
    (3) Special considerations for blending of fuels. In situations 
where different types of fuel listed in Table C-1 of this subpart (for 
example, different ranks of coal or different grades of fuel oil) are 
in the same state of matter (i.e., solid, liquid, or gas), and are 
blended prior to combustion, use the following procedures to determine 
the appropriate CO2 emission factor and HHV for the blend.
    (i) If the fuels to be blended are received separately, and if the 
quantity (mass or volume) of each fuel is measured before the fuels are 
mixed and combusted, then, for each component of the blend, calculate 
the CO2 mass emissions separately. Substitute into Equation 
C-2a of this subpart the total measured mass or volume of the component 
fuel (from company records), together with the appropriate default 
CO2 emission factor from Table C-1, and the annual average 
HHV, calculated according to Sec.  98.33(a)(2)(ii). In this case, the 
fact that the fuels are blended prior to combustion is of no 
consequence.
    (ii) If the fuel is received as a blend (i.e., already mixed) or if 
the components are mixed on site without precisely measuring the mass 
or volume of each one individually, a reasonable estimate of the 
relative proportions of the components of the blend must be made, using 
the best available information (e.g., the approximate annual average 
mass or volume percentage of each fuel, based on the typical or 
expected range of values). Determine the appropriate CO2 
emission factor and HHV for use in Equation C-2a of this subpart, as 
follows:
    (A) Consider the blend to be the ``fuel type,'' measure its HHV at 
the frequency prescribed in paragraph (a)(2)(v) of this section, and 
determine the annual average HHV value for the blend according to Sec.  
98.33(a)(2)(ii).
    (B) Calculate a heat-weighted CO2 emission factor, 
(EF)B, for the blend, using Equation C-16 of this section. 
The heat-weighting in Equation C-16 is provided by the default HHVs 
(from Table C-1) and the estimated mass or volume percentages of the 
components of the blend.
    (C) Substitute into Equation C-2a of this subpart, the annual 
average HHV for the blend (from paragraph (a)(3)(ii)(A) of this 
section) and the calculated value of (EF)B, along with the 
total mass or volume of the blend combusted during the reporting year, 
to determine the annual CO2 mass emissions from combustion 
of the blend.
[GRAPHIC] [TIFF OMITTED] TR17DE10.003

Where:

(EF)B = Heat-weighted CO2 emission factor for 
the blend (kg CO2/mmBtu)
(HHV)i = Default high heat value for fuel ``i'' in the 
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)i = Estimated mass or volume percentage of fuel 
``i'' (mass % or volume %, as applicable, expressed as a decimal 
fraction; e.g., 25% = 0.25)
(EF)i = Default CO2 emission factor for fuel 
``i'' from Table C-1 (mmBtu per mass or volume)

[[Page 79148]]

(HHV)B = Annual average high heat value for the blend, 
calculated according to Sec.  98.33(a)(2)(ii) (mmBtu per mass or 
volume)

    (iii) Note that for the case described in paragraph (a)(3)(ii) of 
this section, if measured HHV values for the individual fuels in the 
blend or for the blend itself are not routinely received at the minimum 
frequency prescribed in paragraph (a)(2) of this section (or at a 
greater frequency), and if the unit qualifies to use Tier 1, calculate 
(HHV)B*, the heat-weighted default HHV for the blend, using 
Equation C-17 of this section. Then, use Equation C-16 of this section, 
replacing the term (HHV)B with (HHV)B* in the 
denominator, to determine the heat-weighted CO2 emission 
factor for the blend. Finally, substitute into Equation C-1 of this 
subpart, the calculated values of (HHV)B* and 
(EF)B, along with the total mass or volume of the blend 
combusted during the reporting year, to determine the annual 
CO2 mass emissions from combustion of the blend.
[GRAPHIC] [TIFF OMITTED] TR17DE10.004

Where:

(HHV)B* = Heat-weighted default high heat value for the 
blend (mmBtu per mass or Volume)
(HHV)i = Default high heat value for fuel ``i'' in the 
blend, from Table C-1 (mmBtu per mass or volume)
(%Fuel)i = Estimated mass or volume percentage of fuel 
``i'' in the blend (mass % or volume %, as applicable, expressed as 
a decimal fraction)

    (iv) If the fuel blend described in paragraph (a)(3)(ii) of this 
section consists of a mixture of fuel(s) listed in Table C-1 of this 
subpart and one or more fuels not listed in Table C-1, calculate 
CO2 and other GHG emissions only for the Table C-1 fuel(s), 
using the best available estimate of the mass or volume percentage(s) 
of the Table C-1 fuel(s) in the blend. In this case, Tier 1 shall be 
used, with the following modifications to Equations C-17 and C-1, to 
account for the fact that not all of the fuels in the blend are listed 
in Table C-1:
    (A) In Equation C-17, apply the term (Fuel)i only to the 
Table C-1 fuels. For each Table C-1 fuel, (Fuel)i will be 
the estimated mass or volume percentage of the fuel in the blend, 
divided by the sum of the mass or volume percentages of the Table C-1 
fuels. For example, suppose that a blend consists of two Table C-1 
fuels (``A'' and ``B'') and one fuel type (``C'') not listed in the 
Table, and that the volume percentages of fuels A, B, and C in the 
blend, expressed as decimal fractions, are, respectively, 0.50, 0.30, 
and 0.20. The term (Fuel)i in Equation C-17 for fuel A will 
be 0.50/(0.50 + 0.30) = 0.625, and for fuel B, (Fuel)i will 
be 0.30/(0.50 + 0.30) = 0.375.
    (B) In Equation C-1, the term ``Fuel'' will be equal to the total 
mass or volume of the blended fuel combusted during the year multiplied 
by the sum of the mass or volume percentages of the Table C-1 fuels in 
the blend. For the example in paragraph (a)(3)(iv)(A) of this section, 
``Fuel'' = (Annual volume of the blend combusted)(0.80).
* * * * *
    (6) You must use one of the following appropriate fuel sampling and 
analysis methods. The HHV may be calculated using chromatographic 
analysis together with standard heating values of the fuel 
constituents, provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer's 
instructions. Alternatively, you may use a method published by a 
consensus-based standards organization if such a method exists, or you 
may use industry standard practice to determine the high heat values. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box 
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, 
http://www.astm.org), the American National Standards Institute (ANSI, 
1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, 
http://www.ansi.org), the American Gas Association (AGA, 400 North 
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, 
http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the Monitoring 
Plan required under Sec.  98.3(g)(5).
    (b) * * *
    (1) You must calibrate each oil and gas flow meter according to 
Sec.  98.3(i) and the provisions of this paragraph (b)(1).
    (i) Perform calibrations using any of the test methods and 
procedures in this paragraph (b)(1)(i). The method(s) used shall be 
documented in the Monitoring Plan required under Sec.  98.3(g)(5).
    (A) You may use the calibration procedures specified by the flow 
meter manufacturer.
    (B) You may use an appropriate flow meter calibration method 
published by a consensus-based standards organization, if such a method 
exists. Consensus-based standards organizations include, but are not 
limited to, the following: ASTM International (100 Barr Harbor Drive, 
P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-
1373, http://www.astm.org), the American National Standards Institute 
(ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-
8020, http://www.ansi.org), the American Gas Association (AGA, 400 
North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-
7000, http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
    (C) You may use an industry-accepted practice.
    (ii) In addition to the initial calibration required by Sec.  
98.3(i), recalibrate each fuel flow meter (except as otherwise provided 
in paragraph (b)(1)(iii) of this section) according to one of the 
following. You may recalibrate annually, at the minimum frequency 
specified by the manufacturer, or at the interval specified by industry 
standard practice.
    (iii) Fuel billing meters are exempted from the initial and ongoing 
calibration requirements of this paragraph and from the Monitoring Plan 
and recordkeeping

[[Page 79149]]

requirements of Sec. Sec.  98.3(g)(5)(i)(C), (g)(6), and (g)(7), 
provided that the fuel supplier and the unit combusting the fuel do not 
have any common owners and are not owned by subsidiaries or affiliates 
of the same company. Meters used exclusively to measure the flow rates 
of fuels that are only used for unit startup are also exempted from the 
initial and ongoing calibration requirements of this paragraph.
* * * * *
    (vi) If a mixture of liquid or gaseous fuels is transported by a 
common pipe, you may either separately meter each of the fuels prior to 
mixing, using flow meters calibrated according to Sec.  98.3(i), or 
consider the fuel mixture to be the ``fuel type'' and meter the mixed 
fuel, using a flow meter calibrated according to Sec.  98.3(i).
* * * * *
    (3) * * *
    (ii) For each type of fuel, the minimum required frequency for 
collecting and analyzing samples for carbon content and (if applicable) 
molecular weight is specified in this paragraph. When the sampling 
frequency is based on a specified time period (e.g., week, month, 
quarter, or half-year), fuel sampling and analysis is required for only 
those time periods in which the fuel is combusted.
    (A) For natural gas, semiannual sampling and analysis is required 
(i.e., twice in a calendar year, with consecutive samples taken at 
least four months apart).
    (B) For coal and fuel oil and for any other solid or liquid fuel 
that is delivered in lots, analysis of at least one representative 
sample from each fuel lot is required. For fuel oil, as an alternative 
to sampling each fuel lot, a sample may be taken upon each addition of 
oil to the storage tank. Flow proportional sampling, continuous drip 
sampling, or daily manual oil sampling may also be used, in lieu of 
sampling each fuel lot. If the daily manual oil sampling option is 
selected, sampling from a particular tank is required only on days when 
oil from the tank is combusted by the unit (or units) served by the 
tank. If you elect to sample from the storage tank upon each addition 
of oil to the tank, you must take at least one sample from each tank 
that is currently in service and whenever oil is added to the tank, for 
as long as the tank remains in service. You need not take any samples 
from a storage tank while it is out of service. Rather, take a sample 
when the tank is brought into service and whenever oil is added to the 
tank, for as long as the tank remains in service. If multiple additions 
of oil are made to a particular in service tank on a given day (e.g., 
from multiple deliveries), one sample taken after the final addition of 
oil is sufficient. For the purposes of this section, a fuel lot is 
defined as a shipment or delivery of a single type of fuel (e.g., ship 
load, barge load, group of trucks, group of railroad cars, oil delivery 
via pipeline from a tank farm, etc.). However, if multiple deliveries 
of a particular type of fuel are received from the same supply source 
in a given calendar month, the deliveries for that month may be 
considered, collectively, to comprise a fuel lot, requiring only one 
representative sample, subject to the following conditions:
    (1) For coal, the ``type'' of fuel means the rank of the coal 
(i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel 
oil, the ``type'' of fuel means the grade number or classification of 
the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
    (2) The owner or operator shall document in the monitoring plan 
under Sec.  98.3(g)(5) how the monthly sampling of each type of fuel is 
performed.
    (C) For liquid fuels other than fuel oil and for biogas, sampling 
and analysis is required at least once per calendar quarter. To the 
extent practicable, consecutive quarterly samples shall be taken at 
least 30 days apart.
    (D) For other solid fuels (except MSW), weekly sampling is required 
to obtain composite samples, which are then analyzed monthly.
    (E) For gaseous fuels other than natural gas and biogas (e.g., 
process gas), daily sampling and analysis to determine the carbon 
content and molecular weight of the fuel is required if continuous, on-
line equipment, such as a gas chromatograph, is in place to make these 
measurements. Otherwise, weekly sampling and analysis shall be 
performed.
    (F) For mixtures (blends) of solid fuels, weekly sampling is 
required to obtain composite samples, which are analyzed monthly. For 
blends of liquid fuels, and for gas mixtures consisting only of natural 
gas and biogas, sampling and analysis is required at least once per 
calendar quarter. For gas mixtures that contain gases other than 
natural gas (including biogas), daily sampling and analysis to 
determine the carbon content and molecular weight of the fuel is 
required if continuous, on-line equipment is in place to make these 
measurements. Otherwise, weekly sampling and analysis shall be 
performed.
* * * * *
    (v) To calculate the CO2 mass emissions from combustion 
of a blend of fuels in the same state of matter (solid, liquid, or 
gas), you may either:
    (A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) 
to each component of the blend, if the mass or volume, the carbon 
content, and (if applicable), the molecular weight of each component 
are accurately measured prior to blending; or
    (B) Consider the blend to be the ``fuel type.'' Then, at the 
frequency specified in paragraph (b)(3)(ii)(F) of this section, measure 
the carbon content and, if applicable, the molecular weight of the 
blend and calculate the annual average value of each parameter in the 
manner described in Sec.  98.33(a)(2)(ii). Also measure the mass or 
volume of the blended fuel combusted during the reporting year. 
Substitute these measured values into Equation C-3, C-4, or C-5 of this 
subpart (as applicable).
    (4) You must use one of the following appropriate fuel sampling and 
analysis methods. The results of chromatographic analysis of the fuel 
may be used, provided that the gas chromatograph is operated, 
maintained, and calibrated according to the manufacturer's 
instructions. Alternatively, you may use a method published by a 
consensus-based standards organization if such a method exists, or you 
may use industry standard practice to determine the carbon content and 
molecular weight (for gaseous fuel) of the fuel. Consensus-based 
standards organizations include, but are not limited to, the following: 
ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West 
Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L 
Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol 
Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three 
Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, 
NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), 
and the North American Energy Standards Board (NAESB, 801 Travis 
Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the Monitoring 
Plan required under Sec.  98.3(g)(5).
    (c) For the Tier 4 Calculation Methodology, the CO2, 
flow rate, and (if applicable) moisture monitors must be

[[Page 79150]]

certified prior to the applicable deadline specified in Sec.  
98.33(b)(5).
    (1) * * *
    (i) Sec. Sec.  75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of 
this chapter and appendix A to part 75 of this chapter.
    (ii) The calibration drift test and relative accuracy test audit 
(RATA) procedures of Performance Specification 3 in appendix B to part 
60 of this chapter (for the CO2 concentration monitor) and 
Performance Specification 6 in appendix B to part 60 of this chapter 
(for the continuous emission rate monitoring system (CERMS)).
* * * * *
    (2) If an O2 concentration monitor is used to determine 
CO2 concentrations, the applicable provisions of part 75 of 
this chapter, part 60 of this chapter, or an applicable State 
continuous monitoring program shall be followed for initial 
certification and on-going quality assurance, and all required RATAs of 
the monitor shall be done on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures 
in either appendix B to part 75 of this chapter, appendix F to part 60 
of this chapter, or an applicable State continuous monitoring program. 
If appendix F to part 60 of this chapter is selected for on-going 
quality assurance, perform daily calibration drift assessments for both 
the CO2 monitor (or surrogate O2 monitor) and the 
flow rate monitor, conduct cylinder gas audits of the CO2 
concentration monitor in three of the four quarters of each year 
(except for non-operating quarters), and perform annual RATAs of the 
CO2 concentration monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow 
rate monitor RATAs required by appendix B to part 75 of this chapter 
and the annual RATAs of the CERMS required by appendix F to part 60 of 
this chapter need only be done at one operating level, representing 
normal load or normal process operating conditions, both for initial 
certification and for ongoing quality assurance.
* * * * *
    (6) For certain applications where combined process emissions and 
combustion emissions are measured, the CO2 concentrations in 
the flue gas may be considerably higher than for combustion emissions 
alone. In such cases, the span of the CO2 monitor may, if 
necessary, be set higher than the specified levels in the applicable 
regulations. If the CO2 span value is set higher than 20 
percent CO2, the cylinder gas audits of the CO2 
monitor under appendix F to part 60 of this chapter may be performed at 
40 to 60 percent and 80 to 100 percent of span, in lieu of the 
prescribed calibration levels of 5 to 8 percent CO2 and 10 
to 14 percent CO2.
    (7) Hourly average data from the CEMS shall be validated in a 
manner consistent with one of the following: Sec. Sec.  60.13(h)(2)(i) 
through (h)(2)(vi) of this chapter; Sec.  75.10(d)(1) of this chapter; 
or the hourly data validation requirements of an applicable State CEM 
regulation.
    (d) Except as otherwise provided in Sec.  98.33 (b)(1)(vi) and 
(b)(1)(vii), when municipal solid waste (MSW) is either the primary 
fuel combusted in a unit or the only fuel with a biogenic component 
combusted in the unit, determine the biogenic portion of the 
CO2 emissions using ASTM D6866-08 Standard Test Methods for 
Determining the Biobased Content of Solid, Liquid, and Gaseous Samples 
Using Radiocarbon Analysis (incorporated by reference, see Sec.  98.7) 
and ASTM D7459-08 Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources (incorporated 
by reference, see Sec.  98.7). Perform the ASTM D7459-08 sampling and 
the ASTM D6866-08 analysis at least once in every calendar quarter in 
which MSW is combusted in the unit. Collect each gas sample during 
normal unit operating conditions for at least 24 total (not necessarily 
consecutive) hours, or longer if the facility deems it necessary to 
obtain a representative sample. Notwithstanding this requirement, if 
the types of fuels combusted and their relative proportions are 
consistent throughout the year, the minimum required sampling time may 
be reduced to 8 hours if at least two 8-hour samples and one 24-hour 
sample are collected under normal operating conditions, and arithmetic 
average of the biogenic fraction of the flue gas from the 8-hour 
samples (expressed as a decimal) is within  5 percent of 
the biogenic fraction from the 24-hour test. There must be no 
overlapping of the 8-hour and 24-hour test periods. Document the 
results of the demonstration in the unit's monitoring plan. If the 
types of fuels and their relative proportions are not consistent 
throughout the year, an optional sampling approach that facilities may 
wish to consider to obtain a more representative sample is to collect 
an integrated sample by extracting a small amount of flue gas (e.g., 1 
to 5 cc) in each unit operating hour during the quarter. Separate the 
total annual CO2 emissions into the biogenic and non-
biogenic fractions using the average proportion of biogenic emissions 
of all samples analyzed during the reporting year. Express the results 
as a decimal fraction (e.g., 0.30, if 30 percent of the CO2 
is biogenic). When MSW is the primary fuel for multiple units at the 
facility, and the units are fed from a common fuel source, testing at 
only one of the units is sufficient.
    (e) For other units that combust combinations of biomass fuel(s) 
(or heterogeneous fuels that have a biomass component, e.g., tires) and 
fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-
08 (incorporated by reference, see Sec.  98.7) and ASTM D7459-08 
(incorporated by reference, see Sec.  98.7) may be used to determine 
the biogenic portion of the CO2 emissions in every calendar 
quarter in which biomass and non-biogenic fuels are co-fired in the 
unit. Follow the procedures in paragraph (d) of this section. If the 
primary fuel for multiple units at the facility consists of tires, and 
the units are fed from a common fuel source, testing at only one of the 
units is sufficient.
    (f) The records required under Sec.  98.3(g)(2)(i) shall include an 
explanation of how the following parameters are determined from company 
records (or, if applicable, from the best available information):
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation 
Methodologies are used, including cases where Sec.  98.36(c)(4) 
applies.
* * * * *
    (3) Fossil fuel consumption when Sec.  98.33(e)(2) applies to a 
unit that uses CEMS to quantify CO2 emissions and that 
combusts both fossil and biomass fuels.
* * * * *
    (5) Quantity of steam generated by a unit when Sec.  
98.33(a)(2)(iii) applies.
    (6) Biogenic fuel consumption and high heating value, as 
applicable, under Sec. Sec.  98.33(e)(5) and (e)(6).
    (7) Fuel usage for CH4 and N2O emissions 
calculations under Sec.  98.33(c)(4)(ii).
    (8) Mass of biomass combusted, for premixed fuels that contain 
biomass and fossil fuels under Sec.  98.33(e)(1)(iii).

0
11. Section 98.35 is amended by revising paragraph (a) to read as 
follows:


Sec.  98.35  Procedures for estimating missing data.

* * * * *
    (a) For all units subject to the requirements of the Acid Rain 
Program, and all other stationary combustion units subject to the 
requirements of this part that monitor and report emissions and heat 
input data year-round in

[[Page 79151]]

accordance with part 75 of this chapter, the missing data substitution 
procedures in part 75 of this chapter shall be followed for 
CO2 concentration, stack gas flow rate, fuel flow rate, high 
heating value, and fuel carbon content.
* * * * *

0
12. Section 98.36 is amended by:
0
a. Revising paragraph (b)(5).
0
b. Removing paragraphs (b)(9) and (b)(10).
0
c. Redesignating paragraphs (b)(6) through (b)(8) as paragraphs (b)(8) 
through (b)(10), respectively.
0
d. Revising newly designated paragraphs (b)(8) and (b)(9).
0
e. Adding new paragraphs (b)(6) and (b)(7).
0
f. Removing and reserving paragraphs (c)(1)(ii) and (c)(1)(iii).
0
g. Revising paragraphs (c)(1)(vi) and (c)(1)(vii).
0
h. Redesignating paragraph (c)(1)(viii) as paragraph (c)(1)(x), and 
revising newly designated paragraph (c)(1)(x).
0
i. Removing paragraph (c)(1)(ix).
0
j. Adding new paragraphs (c)(1)(viii) and (c)(1)(ix).
0
k. Revising paragraphs (c)(2) introductory text, (c)(2)(ii), 
(c)(2)(iii), and (c)(2)(v).
0
l. Removing paragraph (c)(2)(viii).
0
m. Redesignating paragraphs (c)(2)(vi) and (c)(2)(vii) as paragraphs 
(c)(2)(viii) and (c)(2)(ix), and revising newly designated paragraphs 
(c)(2)(viii) and (c)(2)(ix).
0
n. Adding new paragraphs (c)(2)(vi) and (c)(2)(vii).
0
o. Removing and reserving paragraph (c)(3)(ii).
0
p. Revising paragraphs (c)(3) introductory text, (c)(3)(iii), and 
(c)(3)(vii).
0
q. Removing paragraph (c)(3)(viii).
0
r. Adding new paragraphs (c)(3)(viii), (c)(3)(ix), and (c)(4).
0
s. Revising paragraph (d).
0
t. Revising paragraphs (e)(1)(iii), (e)(2)(i), (e)(2)(ii)(C), 
(e)(2)(ii)(D), (e)(2)(iii), (e)(2)(iv)(A), and (e)(2)(iv)(C).
0
u. Adding paragraphs (e)(2)(iv)(F) and (e)(2)(iv)(G).
0
v. Revising paragraph (e)(2)(v)(C).
0
w. Adding paragraph (e)(2)(v)(E).
0
x. Revising paragraphs (e)(2)(vii)(A), (e)(2)(ix) introductory text, 
and (e)(2)(x) introductory text.
0
y. Removing paragraphs (e)(2)(x)(B) and (e)(2)(x)(C).
0
z. Redesignating paragraph (e)(2)(x)(D) as (e)(2)(x)(B), and revising 
newly designated paragraph (e)(2)(x)(B).
0
aa. Revising paragraph (e)(2)(xi).


Sec.  98.36  Data reporting requirements.

* * * * *
    (b) * * *
    (5) The methodology (i.e., tier) used to calculate the 
CO2 emissions for each type of fuel combusted (i.e., Tier 1, 
2, 3, or 4).
    (6) The methodology start date, for each fuel type.
    (7) The methodology end date, for each fuel type.
    (8) For a unit that uses Tiers 1, 2, or 3:
    (i) The annual CO2 mass emissions (including biogenic 
CO2), and the annual CH4, and N2O mass 
emissions for each type of fuel combusted during the reporting year, 
expressed in metric tons of each gas and in metric tons of 
CO2e; and
    (ii) Metric tons of biogenic CO2 emissions (if 
applicable).
    (9) For a unit that uses Tier 4:
    (i) If the total annual CO2 mass emissions measured by 
the CEMS consists entirely of non-biogenic CO2 (i.e., 
CO2 from fossil fuel combustion plus, if applicable, 
CO2 from sorbent and/or process CO2), report the 
total annual CO2 mass emissions, expressed in metric tons. 
You are not required to report the combustion CO2 emissions 
by fuel type.
    (ii) Report the total annual CO2 mass emissions measured 
by the CEMS. If this total includes both biogenic and non-biogenic 
CO2, separately report the annual non-biogenic 
CO2 mass emissions and the annual CO2 mass 
emissions from biomass combustion, each expressed in metric tons. You 
are not required to report the combustion CO2 emissions by 
fuel type.
    (iii) An estimate of the heat input from each type of fuel listed 
in Table C-2 of this subpart that was combusted in the unit during the 
report year, and the annual CH4 and N2O emissions 
for each of these fuels, expressed in metric tons of each gas and in 
metric tons of CO2e.
* * * * *
    (c) * * *
    (1) * * *
    (ii) [Reserved]
    (iii) [Reserved]
* * * * *
    (vi) Annual CO2 mass emissions and annual 
CH4, and N2O mass emissions, aggregated for each 
type of fuel combusted in the group of units during the report year, 
expressed in metric tons of each gas and in metric tons of 
CO2e. If any of the units burn both fossil fuels and 
biomass, report also the annual CO2 emissions from 
combustion of all fossil fuels combined and annual CO2 
emissions from combustion of all biomass fuels combined, expressed in 
metric tons.
    (vii) The methodology (i.e., tier) used to calculate the 
CO2 mass emissions for each type of fuel combusted in the 
units (i.e., Tier 1, Tier 2, or Tier 3).
    (viii) The methodology start date, for each fuel type.
    (ix) The methodology end date, for each fuel type.
    (x) The calculated CO2 mass emissions (if any) from 
sorbent expressed in metric tons.
    (2) Monitored common stack or duct configurations. When the flue 
gases from two or more stationary fuel combustion units at a facility 
are combined together in a common stack or duct before exiting to the 
atmosphere and if CEMS are used to continuously monitor CO2 
mass emissions at the common stack or duct according to the Tier 4 
Calculation Methodology, you may report the combined emissions from the 
units sharing the common stack or duct, in lieu of separately reporting 
the GHG emissions from the individual units. This monitoring and 
reporting alternative may also be used when process off-gases or a 
mixture of combustion products and process gases are combined together 
in a common stack or duct before exiting to the atmosphere. Whenever 
the common stack or duct monitoring option is applied, the following 
information shall be reported instead of the information in paragraph 
(b) of this section:
* * * * *
    (ii) Number of units sharing the common stack or duct. Report ``1'' 
when the flue gas flowing through the common stack or duct includes 
combustion products and/or process off-gases, and all of the effluent 
comes from a single unit (e.g., a furnace, kiln, petrochemical 
production unit, or smelter).
    (iii) Combined maximum rated heat input capacity of the units 
sharing the common stack or duct (mmBtu/hr). This data element is 
required only when all of the units sharing the common stack are 
stationary fuel combustion units.
* * * * *
    (v) The methodology (tier) used to calculate the CO2 
mass emissions, i.e., Tier 4.
    (vi) The methodology start date.
    (vii) The methodology end date.
    (viii) Total annual CO2 mass emissions measured by the 
CEMS, expressed in metric tons. If any of the units burn both fossil 
fuels and biomass, separately report the annual non-biogenic 
CO2 mass emissions (i.e., CO2 from fossil fuel 
combustion plus, if applicable, CO2 from sorbent and/or 
process CO2) and the annual CO2 mass emissions 
from biomass combustion, each expressed in metric tons.
    (ix) An estimate of the heat input from each type of fuel listed in 
Table C-2 of

[[Page 79152]]

this subpart that was combusted during the report year in the units 
sharing the common stack or duct during the report year, and, for each 
of these fuels, the annual CH4 and N2O mass 
emissions from the units sharing the common stack or duct, expressed in 
metric tons of each gas and in metric tons of CO2e.
    (3) Common pipe configurations. When two or more stationary 
combustion units at a facility combust the same type of liquid or 
gaseous fuel and the fuel is fed to the individual units through a 
common supply line or pipe, you may report the combined emissions from 
the units served by the common supply line, in lieu of separately 
reporting the GHG emissions from the individual units, provided that 
the total amount of fuel combusted by the units is accurately measured 
at the common pipe or supply line using a fuel flow meter, or, for 
natural gas, the amount of fuel combusted may be obtained from gas 
billing records. For Tier 3 applications, the flow meter shall be 
calibrated in accordance with Sec.  98.34(b). If a portion of the fuel 
measured (or obtained from gas billing records) at the main supply line 
is diverted to either: A flare; or another stationary fuel combustion 
unit (or units), including units that use a CO2 mass 
emissions calculation method in part 75 of this chapter; or a chemical 
or industrial process (where it is used as a raw material but not 
combusted), and the remainder of the fuel is distributed to a group of 
combustion units for which you elect to use the common pipe reporting 
option, you may use company records to subtract out the diverted 
portion of the fuel from the fuel measured (or obtained from gas 
billing records) at the main supply line prior to performing the GHG 
emissions calculations for the group of units using the common pipe 
option. If the diverted portion of the fuel is combusted, the GHG 
emissions from the diverted portion shall be accounted for in 
accordance with the applicable provisions of this part. When the common 
pipe option is selected, the applicable tier shall be used based on the 
maximum rated heat input capacity of the largest unit served by the 
common pipe configuration, except where the applicable tier is based on 
criteria other than unit size. For example, if the maximum rated heat 
input capacity of the largest unit is greater than 250 mmBtu/hr, Tier 3 
will apply, unless the fuel transported through the common pipe is 
natural gas or distillate oil, in which case Tier 2 may be used, in 
accordance with Sec.  98.33(b)(2)(ii). As a second example, in 
accordance with Sec.  98.33(b)(1)(v), Tier 1 may be used regardless of 
unit size when natural gas is transported through the common pipe, if 
the annual fuel consumption is obtained from gas billing records in 
units of therms. When the common pipe reporting option is selected, the 
following information shall be reported instead of the information in 
paragraph (b) of this section:
* * * * *
    (iii) The highest maximum rated heat input capacity of any unit 
served by the common pipe (mmBtu/hr).
* * * * *
    (vii) Annual CO2 mass emissions and annual 
CH4 and N2O emissions from each fuel type for the 
units served by the common pipe, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (viii) Methodology start date
    (ix) Methodology end date
    (4) The following alternative reporting option applies to 
facilities at which a common liquid or gaseous fuel supply is shared 
between one or more large combustion units, such as boilers or 
combustion turbines (including units subject to subpart D of this part 
and other units subject to part 75 of this chapter) and small 
combustion sources, including, but not limited to, space heaters, hot 
water heaters, and lab burners. In this case, you may simplify 
reporting by attributing all of the GHG emissions from combustion of 
the shared fuel to the large combustion unit(s), provided that:
    (i) The total quantity of the fuel combusted during the report year 
in the units sharing the fuel supply is measured, either at the 
``gate'' to the facility or at a point inside the facility, using a 
fuel flow meter, billing meter, or tank drop measurements (as 
applicable);
    (ii) On an annual basis, at least 95 percent (by mass or volume) of 
the shared fuel is combusted in the large combustion unit(s), and the 
remainder is combusted in the small combustion sources. Company records 
may be used to determine the percentage distribution of the shared fuel 
to the large and small units; and
    (iii) The use of this reporting option is documented in the 
Monitoring Plan required under Sec.  98.3(g)(5). Indicate in the 
Monitoring Plan which units share the common fuel supply and the method 
used to demonstrate that this alternative reporting option applies. For 
the small combustion sources, a description of the types of units and 
the approximate number of units is sufficient.
    (d) Units subject to part 75 of this chapter.
    (1) For stationary combustion units that are subject to subpart D 
of this part, you shall report the following unit-level information:
    (i) Unit or stack identification numbers. Use exact same unit, 
common stack, common pipe, or multiple stack identification numbers 
that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, 
etc.) that are reported under Sec.  75.64 of this chapter.
    (ii) Annual CO2 emissions at each monitored location, 
expressed in both short tons and metric tons. Separate reporting of 
biogenic CO2 emissions under Sec.  98.3(c)(4)(ii) and Sec.  
98.3(c)(4)(iii)(A) is optional only for the 2010 reporting year, as 
provided in Sec.  98.3(c)(12).
    (iii) Annual CH4 and N2O emissions at each 
monitored location, for each fuel type listed in Table C-2 that was 
combusted during the year (except as otherwise provided in Sec.  
98.33(c)(4)(ii)(B)), expressed in metric tons of CO2e.
    (iv) The total heat input from each fuel listed in Table C-2 that 
was combusted during the year (except as otherwise provided in Sec.  
98.33(c)(4)(ii)(B)), expressed in mmBtu.
    (v) Identification of the Part 75 methodology used to determine the 
CO2 mass emissions.
    (vi) Methodology start date.
    (vii) Methodology end date.
    (viii) Acid Rain Program indicator.
    (ix) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons of CO2e, except where the 
reporting provisions of Sec. Sec.  98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (2) For units that use the alternative CO2 mass 
emissions calculation methods provided in Sec.  98.33(a)(5), you shall 
report the following unit-level information:
    (i) Unit, stack, or pipe ID numbers. Use exact same unit, common 
stack, common pipe, or multiple stack identification numbers that 
represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, 
etc.) that are reported under Sec.  75.64 of this chapter.
    (ii) For units that use the alternative methods specified in Sec.  
98.33(a)(5)(i) and (ii) to monitor and report heat input data year-
round according to appendix D to part 75 of this chapter or Sec.  75.19 
of this chapter:
    (A) Each type of fuel combusted in the unit during the reporting 
year.
    (B) The methodology used to calculate the CO2 mass 
emissions for each fuel type.
    (C) Methodology start date.
    (D) Methodology end date.

[[Page 79153]]

    (E) A code or flag to indicate whether heat input is calculated 
according to appendix D to part 75 of this chapter or Sec.  75.19 of 
this chapter.
    (F) Annual CO2 emissions at each monitored location, 
across all fuel types, expressed in metric tons of CO2e.
    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emissions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec.  98.33(c)(4)(ii)(D)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e, except where the 
reporting provisions of Sec. Sec.  98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (iii) For units with continuous monitoring systems that use the 
alternative method for units with continuous monitoring systems in 
Sec.  98.33(a)(5)(iii) to monitor heat input year-round according to 
part 75 of this chapter:
    (A) Each type of fuel combusted during the reporting year.
    (B) Methodology used to calculate the CO2 mass 
emissions.
    (C) Methodology start date.
    (D) Methodology end date.
    (E) A code or flag to indicate that the heat input data is derived 
from CEMS measurements.
    (F) The total annual CO2 emissions at each monitored 
location, expressed in metric tons of CO2e.
    (G) Annual heat input from each type of fuel listed in Table C-2 of 
this subpart that was combusted during the reporting year, expressed in 
mmBtu.
    (H) Annual CH4 and N2O emissions at each 
monitored location, from each fuel type listed in Table C-2 of this 
subpart that was combusted during the reporting year (except as 
otherwise provided in Sec.  98.33(c)(4)(ii)(B)), expressed in metric 
tons CO2e.
    (I) Annual CO2 mass emissions from the combustion of 
biomass, expressed in metric tons CO2e, except where the 
reporting provisions of Sec. Sec.  98.3(c)(12)(i) through (c)(12)(iii) 
are implemented for the 2010 reporting year.
    (e) * * *
    (1) * * *
    (iii) Are not in the Acid Rain Program, but are required to monitor 
and report CO2 mass emissions and heat input data year-
round, in accordance with part 75 of this chapter.
    (2) * * *
    (i) For the Tier 1 Calculation Methodology, report the total 
quantity of each type of fuel combusted in the unit or group of 
aggregated units (as applicable) during the reporting year, in short 
tons for solid fuels, gallons for liquid fuels and standard cubic feet 
for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
    (ii) * * *
    (C) The high heat values used in the CO2 emissions 
calculations for each type of fuel combusted during the reporting year, 
in mmBtu per short ton for solid fuels, mmBtu per gallon for liquid 
fuels, and mmBtu per scf for gaseous fuels. Report a HHV value for each 
calendar month in which HHV determination is required. If multiple 
values are obtained in a given month, report the arithmetic average 
value for the month. Indicate whether each reported HHV is a measured 
value or a substitute data value.
    (D) If Equation C-2c of this subpart is used to calculate 
CO2 mass emissions, report the total quantity (i.e., pounds) 
of steam produced from MSW or solid fuel combustion during each month 
of the reporting year, and the ratio of the maximum rate heat input 
capacity to the design rated steam output capacity of the unit, in 
mmBtu per lb of steam.
    (iii) For the Tier 2 Calculation Methodology, keep records of the 
methods used to determine the HHV for each type of fuel combusted and 
the date on which each fuel sample was taken, except where fuel 
sampling data are received from the fuel supplier. In that case, keep 
records of the dates on which the results of the fuel analyses for HHV 
are received.
    (iv) * * *
    (A) The quantity of each type of fuel combusted in the unit or 
group of units (as applicable) during each month of the reporting year, 
in short tons for solid fuels, gallons for liquid fuels, and scf for 
gaseous fuels.
* * * * *
    (C) The carbon content and, if applicable, gas molecular weight 
values used in the emission calculations (including both valid and 
substitute data values). For each calendar month of the reporting year 
in which carbon content and, if applicable, molecular weight 
determination is required, report a value of each parameter. If 
multiple values of a parameter are obtained in a given month, report 
the arithmetic average value for the month. Express carbon content as a 
decimal fraction for solid fuels, kg C per gallon for liquid fuels, and 
kg C per kg of fuel for gaseous fuels. Express the gas molecular 
weights in units of kg per kg-mole.
* * * * *
    (F) The annual average HHV, when measured HHV data, rather than a 
default HHV from Table C-1 of this subpart, are used to calculate 
CH4 and N2O emissions for a Tier 3 unit, in 
accordance with Sec.  98.33(c)(1).
    (G) The value of the molar volume constant (MVC) used in Equation 
C-5 (if applicable).
    (v) * * *
    (C) The methods used to determine the carbon content and (if 
applicable) the molecular weight of each type of fuel combusted.
* * * * *
    (E) The date on which each fuel sample was taken, except where fuel 
sampling data are received from the fuel supplier. In that case, keep 
records of the dates on which the results of the fuel analyses for 
carbon content and (if applicable) molecular weight are received.
* * * * *
    (vii) * * *
    (A) Whether the CEMS certification and quality assurance procedures 
of part 75 of this chapter, part 60 of this chapter, or an applicable 
State continuous monitoring program were used.
* * * * *
    (ix) For units that combust both fossil fuel and biomass, when 
biogenic CO2 is determined according to Sec.  98.33(e)(2), 
you shall report the following additional information, as applicable:
* * * * *
    (x) When ASTM methods D7459-08 (incorporated by reference, see 
Sec.  98.7) and D6866-08 (incorporated by reference, see Sec.  98.7) 
are used to determine the biogenic portion of the annual CO2 
emissions from MSW combustion, as described in Sec.  98.34(d), report:
* * * * *
    (B) The annual biogenic CO2 mass emissions from MSW 
combustion, in metric tons.
    (xi) When ASTM methods D7459-08 (incorporated by reference, see 
Sec.  98.7) and D6866-08 (incorporated by reference, see Sec.  98.7) 
are used in accordance with Sec.  98.34(e) to determine the biogenic 
portion of the annual CO2 emissions from a unit that co-
fires biogenic fuels (or partly-biogenic fuels, including tires if you 
are electing to report biogenic CO2 emissions from tire 
combustion) and non-biogenic fuels, you shall report the results of 
each quarterly sample analysis, expressed as a decimal fraction (e.g., 
if the biogenic fraction of the CO2 emissions is 30 percent, 
report 0.30).
* * * * *

0
13. Table C-1 to Subpart C is amended by:

[[Page 79154]]

0
a. Revising the heading.
0
b. Removing the entry for ``Pipeline (Weighted U.S. Average)'' and 
adding an entry for ``(Weighted U.S. Average)'' in its place.
0
c. Removing the entry for ``Still Gas.''
0
d. Adding an entry for ``Used Oil'', following the entry for ``Residual 
Fuel Oil No. 6.''
0
e. Revising the entry for ``Ethane''.
0
f. Adding an entry for ``Ethanol'', following the entry for ``Ethane.''
0
g. Revising the phrase ``Fossil fuel-derived fuels (solid)'' to read 
``Other fuels-solid.''
0
h. Revising the entry for ``Municipal Solid Waste.''
0
i. Adding entries for ``Plastics'' and ``Petroleum Coke'', following 
the entry for ``Tires.''
0
j. Revising the phrase ``Fossil fuel-derived fuels (gaseous)'' to read 
``Other fuels--gaseous.''
0
k. Adding entries for ``Propane Gas'' and ``Fuel Gas,'' following the 
entry for ``Coke Oven Gas.''
0
l. Amending the entry for ``Biomass fuels--liquid'' by centering 
``Biomass fuels--liquid.''
0
m. Revising the entries for ``Ethanol'' and ``Biodiesel'' that follow 
the entry for ``Biomass fuels--liquid.''
0
n. Revising footnote ``1.''
0
o. Adding footnote ``2.''

Table C-1 to Subpart C--Default CO[ihel2] Emission Factors and High Heat
                    Values for Various Types of Fuel
------------------------------------------------------------------------
                                Default high heat     Default CO[ihel2]
          Fuel type                   value            emission factor
------------------------------------------------------------------------
 
                              * * * * * * *
(Weighted U.S. Average).....  1.028 x 10-3          53.02
 
                              * * * * * * *
Used Oil....................  0.135                 74.00
 
                              * * * * * * *
Ethane......................  0.069                 62.64
Ethanol.....................  0.084                 68.44
 
                              * * * * * * *
Other fuels (solid).........  mmBtu/short ton       kg CO2/mmBtu
Municipal Solid Waste.......  9.95 \1\              90.7
 
                              * * * * * * *
Plastics....................  38.00                 75.00
Petroleum Coke..............  30.00                 102.41
Other fuels (gaseous).......  mmBtu/scf             kg CO2/mmBtu
 
                              * * * * * * *
Propane Gas.................  2.516 x 10-3          61.46
Fuel Gas \2\................  1.388 x 10-3          59.00
 
                              * * * * * * *
Ethanol.....................  0.084                 68.44
Biodiesel...................  0.128                 73.84
 
                              * * * * * * *
------------------------------------------------------------------------
\1\ Use of this default HHV is allowed only for: (a) Units that combust
  MSW, do not generate steam, and are allowed to use Tier 1; (b) units
  that derive no more than 10 percent of their annual heat input from
  MSW and/or tires; and (c) small batch incinerators that combust no
  more than 1,000 tons of MSW per year.
\2\ Reporters subject to subpart X of this part that are complying with
  Sec.   98.243(d) or subpart Y of this part may only use the default
  HHV and the default CO2 emission factor for fuel gas combustion under
  the conditions prescribed in Sec.   98.243(d)(2)(i) and (d)(2)(ii) and
  Sec.   98.252(a)(1) and (a)(2), respectively. Otherwise, reporters
  subject to subpart X or subpart Y shall use either Tier 3 (Equation C-
  5) or Tier 4.


0
14. The first Table C-2 to Subpart C is removed, and the second Table 
C-2 to Subpart C is revised to read as follows:

Table C-2 to Subpart C--Default CH[ihel4] and N[ihel2]O Emission Factors
                        for Various Types of Fuel
------------------------------------------------------------------------
                                Default CH[ihel4]     Default N[ihel2]O
          Fuel type            emission factor (kg   emission factor (kg
                                CH[ihel4]/mmBtu)      N[ihel2]O/mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-02           1.6 x 10-03
 types in Table C-1).
Natural Gas.................  1.0 x 10-03           1.0 x 10-04
Petroleum (All fuel types in  3.0 x 10-03           6.0 x 10-04
 Table C-1).
Municipal Solid Waste.......  3.2 x 10-02           4.2 x 10-03
Tires.......................  3.2 x 10-02           4.2 x 10-03
Blast Furnace Gas...........  2.2 x 10-05           1.0 x 10-04
Coke Oven Gas...............  4.8 x 10-04           1.0 x 10-04
Biomass Fuels--Solid (All     3.2 x 10-02           4.2 x 10-03
 fuel types in Table C-1).
Biogas......................  3.2 x 10-03           6.3 x 10-04

[[Page 79155]]

 
Biomass Fuels--Liquid (All    1.1 x 10-03           1.1 x 10-04
 fuel types in Table C-1).
------------------------------------------------------------------------
Note: Those employing this table are assumed to fall under the IPCC
  definitions of the ``Energy Industry'' or ``Manufacturing Industries
  and Construction''. In all fuels except for coal the values for these
  two categories are identical. For coal combustion, those who fall
  within the IPCC ``Energy Industry'' category may employ a value of 1g
  of CH[ihel4]/mmBtu.

Subpart D--[Amended]


0
15. Section 98.40 is amended by revising paragraph (a) to read as 
follows:


Sec.  98.40  Definition of the source category.

    (a) The electricity generation source category comprises 
electricity generating units that are subject to the requirements of 
the Acid Rain Program and any other electricity generating units that 
are required to monitor and report to EPA CO2 mass emissions 
year-round according to 40 CFR part 75.
* * * * *

0
16. Section 98.43 is revised to read as follows:


Sec.  98.43  Calculating GHG emissions.

    (a) Except as provided in paragraph (b) of this section, continue 
to monitor and report CO2 mass emissions as required under 
Sec.  75.13 or section 2.3 of appendix G to 40 CFR part 75, and Sec.  
75.64. Calculate CO2, CH4, and N2O 
emissions as follows:
    (1) Convert the cumulative annual CO2 mass emissions 
reported in the fourth quarter electronic data report required under 
Sec.  75.64 from units of short tons to metric tons. To convert tons to 
metric tons, divide by 1.1023.
    (2) Calculate and report annual CH4 and N2O 
mass emissions under this subpart by following the applicable method 
specified in Sec.  98.33(c).
    (b) Calculate and report biogenic CO2 emissions under 
this subpart by following the applicable methods specified in Sec.  
98.33(e). The CO2 emissions (excluding biogenic 
CO2) for units subject to this subpart that are reported 
under Sec. Sec.  98.3(c)(4)(i) and (c)(4)(iii)(B) shall be calculated 
by subtracting the biogenic CO2 mass emissions calculated 
according to Sec.  98.33(e) from the cumulative annual CO2 
mass emissions from paragraph (a)(1) of this section. Separate 
calculation and reporting of biogenic CO2 emissions is 
optional only for the 2010 reporting year pursuant to Sec.  98.3(c)(12) 
and required every year thereafter.


0
17. Section 98.46 is revised to read as follows:


Sec.  98.46  Data reporting requirements.

    The annual report shall comply with the data reporting requirements 
specified in Sec.  98.36(d)(1).


0
18. Section 98.47 is revised to read as follows:


Sec.  98.47  Records that must be retained.

    You shall comply with the recordkeeping requirements of Sec. Sec.  
98.3(g) and 98.37. Records retained under Sec.  75.57(h) of this 
chapter for missing data events satisfy the recordkeeping requirements 
of Sec.  98.3(g)(4) for those same events.

Subpart F--[Amended]

0
19. Section 98.62 is amended by revising paragraphs (a) and (b) to read 
as follows:


Sec.  98.62  GHGs to report.

* * * * *
    (a) Perfluoromethane (CF4), and perfluoroethane 
(C2F6) emissions from anode effects in all 
prebake and S[oslash]derberg electrolysis cells.
    (b) CO2 emissions from anode consumption during 
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
* * * * *

0
20. Section 98.63 is amended by:
0
a. In paragraph (a), revising the only sentence and the definitions of 
``EPFC,'' and ``Em'' in Equation F-1.
0
b. Revising the only sentence of paragraph (b).
0
c. Revising paragraph (c).


Sec.  98.63  Calculating GHG emissions.

    (a) The annual value of each PFC compound (CF4, 
C2F6) shall be estimated from the sum of monthly 
values using Equation F-1 of this section:
* * * * *
EPFC = Annual emissions of each PFC compound from 
aluminum production (metric tons PFC).
Em = Emissions of the individual PFC compound from 
aluminum production for the month ``m'' (metric tons PFC).

    (b) Use Equation F-2 of this section to estimate CF4 
emissions from anode effect duration or Equation F-3 of this section to 
estimate CF4 emissions from overvoltage, and use Equation F-
4 of this section to estimate C2F6 emissions from 
anode effects from each prebake and S[oslash]derberg electrolysis cell.
* * * * *
    (c) You must calculate and report the annual process CO2 
emissions from anode consumption during electrolysis and anode baking 
of prebake cells using either the procedures in paragraph (d) of this 
section, the procedures in paragraphs (e) and (f) of this section, or 
the procedures in paragraph (g) of this section.
* * * * *

0
21. Section 98.64 is amended by revising the first sentence of 
paragraph (a); and by revising paragraph (b) to read as follows:


Sec.  98.64  Monitoring and QA/QC requirements.

    (a) Effective December 31, 2010 for smelters with no prior 
measurement or effective December 31, 2012, for facilities with 
historic measurements, the smelter-specific slope coefficients, 
overvoltage emission factors, and weight fractions used in Equations F-
2, F-3, and F-4 of this subpart must be measured in accordance with the 
recommendations of the EPA/IAI Protocol for Measurement of 
Tetrafluoromethane (CF4) and Hexafluoroethane 
(C2F6) Emissions from Primary Aluminum Production 
(2008) (incorporated by reference, see Sec.  98.7), except the minimum 
frequency of measurement shall be every 10 years unless a change occurs 
in the control algorithm that affects the mix of types of anode effects 
or the nature of the anode effect termination routine. * * *
    (b) The minimum frequency of the measurement and analysis is 
annually except as follows:
    (1) Monthly for anode effect minutes per cell day (or anode effect 
overvoltage and current efficiency).
    (2) Monthly for aluminum production.
    (3) Smelter-specific slope coefficients, overvoltage emission 
factors, and weight fractions according to paragraph (a) of this 
section.
* * * * *

[[Page 79156]]


0
22. Section 98.65 is amended by revising the only sentence of paragraph 
(a) to read as follows:


Sec.  98.65  Procedures for estimating missing data.

* * * * *
    (a) Where anode or paste consumption data are missing, 
CO2 emissions can be estimated from aluminum production per 
Equation F-8 of this section.
* * * * *

0
23. Section 98.66 is amended by revising paragraph (c)(1) to read as 
follows:


Sec.  98.66  Data reporting requirements.

* * * * *
    (c) * * *
    (1) Perfluoromethane emissions and perfluoroethane emissions from 
anode effects in all prebake and all S[oslash]derberg electrolysis 
cells combined.
* * * * *

0
24. Table F-1 to Subpart F of Part 98 is revised to read as follows:

           Table F-1 to Subpart F of Part 98--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From Aluminum Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                         CF[ihel4] slope                                           Weight fraction
                                                                         coefficient [(kg         CF[ihel4] overvoltage      C[ihel2]F[ihel6]/CF[ihel4]
                             Technology                                CF[ihel4]/metric ton   coefficient  [(kg CF[ihel4]/    [(kg C[ihel2]F[ihel6]/kg
                                                                     Al)/(AE-Mins/cell-day)]      metric ton Al)/(mV)]               CF[ihel4])]
--------------------------------------------------------------------------------------------------------------------------------------------------------
Center Worked Prebake (CWPB).......................................                    0.143                          1.16                         0.121
Side Worked Prebake (SWPB).........................................                    0.272                          3.65                         0.252
Vertical Stud S[oslash]derberg (VSS)...............................                    0.092                            NA                         0.053
Horizontal Stud S[oslash]derberg (HSS).............................                    0.099                            NA                         0.085
--------------------------------------------------------------------------------------------------------------------------------------------------------



0
25. Table F-2 to Subpart F of Part 98 is amended by removing the entry 
for ``CO2 Emissions from Pitch Volatiles Combustion (VSS and 
HSS)'' and adding a new entry in its place to read as follows:

 Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters
                      Used for CO[ihel2] Emissions
------------------------------------------------------------------------
               Parameter                           Data source
------------------------------------------------------------------------
          CO[bdi2] Emissions From Prebake Cells (CWPB and SWPB)
 
                              * * * * * * *
      CO2 Emissions From Pitch Volatiles Combustion (CWPB and SWPB)
 
                              * * * * * * *
------------------------------------------------------------------------

Subpart G--[Amended]

0
26. Section 98.72 is amended by revising paragraphs (a) and (b) to read 
as follows:


Sec.  98.72  GHGs to report.

* * * * *
    (a) CO2 process emissions from steam reforming of a 
hydrocarbon or the gasification of solid and liquid raw material, 
reported for each ammonia manufacturing process unit following the 
requirements of this subpart (CO2 process emissions reported 
under this subpart may include CO2 that is later consumed on 
site for urea production, and therefore is not released to the ambient 
air from the ammonia manufacturing process unit).
    (b) CO2, CH4, and N2O emissions 
from each stationary fuel combustion unit. You must report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources), by following the requirements of subpart C, except 
that for ammonia manufacturing processes subpart C does not apply to 
any CO2 resulting from combustion of the waste recycle 
stream (commonly referred to as the purge gas stream).
* * * * *

0
27. Section 98.73 is amended by:
0
a. Revising paragraph (b) introductory text.
0
b. Revising the definition of ``CO2,G'' in Equation G-1 of 
paragraph (b)(1).
0
c. Revising the definition of ``CO2,L'' in Equation G-2 of 
paragraph (b)(2).
0
d. Revising the definition of ``CO2,S'' in Equation G-3 of 
paragraph (b)(3).
0
e. Revising the definition of ``CO2'' in Equation G-5 of 
paragraph (b)(5).
0
f. Removing paragraph (b)(6).


Sec.  98.73  Calculating GHG emissions.

* * * * *
    (b) Calculate and report under this subpart process CO2 
emissions using the procedures in paragraphs (b)(1) through (b)(5) of 
this section for gaseous feedstock, liquid feedstock, or solid 
feedstock, as applicable.
    (1) * * *

CO2,G,k = Annual CO2 emissions arising from 
gaseous feedstock consumption (metric tons).
* * * * *
    (2) * * *

CO2,L,k = Annual CO2 emissions arising from 
liquid feedstock consumption (metric tons).
* * * * *
    (3) * * *

CO2,S,k = Annual CO2 emissions arising from 
solid feedstock consumption (metric tons).
* * * * *
    (5) * * *

CO2 = Annual combined CO2 emissions from all 
ammonia processing units (metric tons) (CO2 process 
emissions reported under this subpart may include CO2 
that is later consumed on site for urea production, and therefore is 
not released to the ambient air from the ammonia manufacturing 
process unit(s)).
* * * * *

0
28. Section 98.74 is amended by revising paragraph (d) to read as set 
forth below and by removing and reserving paragraph (f):


Sec.  98.74  Monitoring and QA/QC requirements.

* * * * *
    (d) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes and flow rates (except for gas 
billing meters) according to the monitoring and QA/QC

[[Page 79157]]

requirements for the Tier 3 methodology in Sec.  98.34(b)(1). Perform 
oil tank drop measurements (if used to quantify feedstock volumes) 
according to Sec.  98.34(b)(2).
* * * * *

0
29. Section 98.75 is amended by revising the first sentence of 
paragraph (a); and by revising paragraph (b) to read as follows:


Sec.  98.75  Procedures for estimating missing data.

* * * * *
    (a) For missing data on monthly carbon contents of feedstock, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that carbon content in the month preceding and the 
month immediately following the missing data incident. * * *
    (b) For missing feedstock supply rates used to determine monthly 
feedstock consumption, you must determine the best available 
estimate(s) of the parameter(s), based on all available process data.

0
30. Section 98.76 is amended by:
0
a. Revising paragraphs (a) introductory text and (b)(6).
0
b. Removing paragraphs (b)(12) through (b)(15).
0
c. Redesignating paragraph (b)(16) as paragraph (b)(12).
0
d. Adding paragraph (b)(13).
0
e. Removing paragraphs (b)(17) and (c).


Sec.  98.76  Data reporting requirements.

* * * * *
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec.  98.36 for the 
Tier 4 Calculation Methodology and the following information in this 
paragraph (a):
* * * * *
    (b) * * *
    (6) Sampling analysis results of carbon content of feedstock as 
determined for QA/QC of supplier data under Sec.  98.74(e).
* * * * *
    (13) CO2 from the steam reforming of a hydrocarbon or 
the gasification of solid and liquid raw material at the ammonia 
manufacturing process unit used to produce urea and the method used to 
determine the CO2 consumed in urea production.

Subpart P--[Amended]

0
31. Section 98.163 is amended by revising the definitions of 
``CCn'' and ``MW'' in Equation P-1 of paragraph (b)(1) to 
read as follows:


Sec.  98.163  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) * * *

CCn = Average carbon content of the gaseous fuel and 
feedstock, from the results of one or more analyses for month n (kg 
carbon per kg of fuel and feedstock). If measurements are taken more 
frequently than monthly, use the arithmetic average of measurement 
values within the month to calculate a monthly average.
MWn = Average molecular weight of the gaseous fuel and 
feedstock from the results of one or more analyses for month n (kg/
kg-mole).
* * * * *

0
32. Section 98.164 is amended by revising paragraphs (b)(1), (b)(2), 
and (b)(5) introductory text to read as follows:


Sec.  98.164  Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (1) Calibrate all oil and gas flow meters that are used to measure 
liquid and gaseous feedstock volumes (except for gas billing meters) 
according to the monitoring and QA/QC requirements for the Tier 3 
methodology in Sec.  98.34(b)(1). Perform oil tank drop measurements 
(if used to quantify liquid fuel or feedstock consumption) according to 
Sec.  98.34(b)(2). Calibrate all solids weighing equipment according to 
the procedures in Sec.  98.3(i).
    (2) Determine the carbon content and the molecular weight annually 
of standard gaseous hydrocarbon fuels and feedstocks having consistent 
composition (e.g., natural gas). For other gaseous fuels and feedstocks 
(e.g., biogas, refinery gas, or process gas), sample and analyze no 
less frequently than weekly to determine the carbon content and 
molecular weight of the fuel and feedstock.
* * * * *
    (5) You must use the following applicable methods to determine the 
carbon content for all fuels and feedstocks, and molecular weight of 
gaseous fuels and feedstocks. Alternatively, you may use the results of 
continuous chromatographic analysis of the fuel and feedstock, provided 
that the gas chromatograph (GC) is operated, maintained, and calibrated 
according to the manufacturer's instructions; and the methods used for 
operation, maintenance, and calibration of the GC are documented in the 
written monitoring plan for the unit under Sec.  98.3(g)(5).
* * * * *

Subpart V--[Amended]

0
33. Section 98.226 is amended by removing and reserving paragraph (o).

Subpart X--[Amended]

0
34. Section 98.240 is amended by revising paragraph (a); and by adding 
paragraph (g) to read as follows:


Sec.  98.240  Definition of the source category.

    (a) The petrochemical production source category consists of all 
processes that produce acrylonitrile, carbon black, ethylene, ethylene 
dichloride, ethylene oxide, or methanol, except as specified in 
paragraphs (b) through (g) of this section. The source category 
includes processes that produce the petrochemical as an intermediate in 
the on-site production of other chemicals as well as processes that 
produce the petrochemical as an end product for sale or shipment off 
site.
* * * * *
    (g) A process that solely distills or recycles waste solvent that 
contains a petrochemical is not part of the petrochemical production 
source category.

0
35. Section 98.242 is amended by revising paragraph (a)(1) and 
paragraph (b) introductory text to read as follows:


Sec.  98.242  GHGs to report.

* * * * *
    (a) * * *
    (1) If you comply with Sec.  98.243(b) or (d), report under this 
subpart the calculated CO2, CH4, and 
N2O emissions for each stationary combustion source and 
flare that burns any amount of petrochemical process off-gas. If you 
comply with Sec.  98.243(b), also report under this subpart the 
measured CO2 emissions from process vents routed to stacks 
that are not associated with stationary combustion units.
* * * * *
    (b) CO2, CH4, and N2O combustion 
emissions from stationary combustion units.
* * * * *

0
36. Section 98.243 is amended by:
0
a. Revising the second sentence of paragraph (b).
0
b. Revising paragraph (c)(3).
0
c. Revising the definition of ``MVC'' in Equation X-1 in paragraph 
(c)(5)(i).
0
d. Revising paragraph (d).


Sec.  98.243  Calculating GHG emissions.

* * * * *
    (b) * * * For each stack (except flare stacks) that includes 
emissions from combustion of petrochemical process off-gas, calculate 
CH4 and N20 emissions in accordance with subpart 
C of this

[[Page 79158]]

part (use the Tier 3 methodology, emission factors for ``Petroleum'' in 
Table C-2 of subpart C of this part, and either the default high heat 
value for fuel gas in Table C-1 of subpart C of this part or a 
calculated HHV, as allowed in Equation C-8 of subpart C of this part). 
* * *
    (c) * * *
    (3) Collect a sample of each feedstock and product at least once 
per month and determine the carbon content of each sample according to 
the procedures of Sec.  98.244(b)(4). If multiple valid carbon content 
measurements are made during the monthly measurement period, average 
them arithmetically. However, if a particular liquid or solid feedstock 
is delivered in lots, and if multiple deliveries of the same feedstock 
are received from the same supply source in a given calendar month, 
only one representative sample is required. Alternatively, you may use 
the results of analyses conducted by a fuel or feedstock supplier, 
provided the sampling and analysis is conducted at least once per month 
using any of the procedures specified in Sec.  98.244(b)(4).
* * * * *
    (5) * * *
    (i) * * *

MVC = Molar volume conversion factor (849.5 scf per kg-mole at 68 
[deg]F and 14.7 pounds per square inch absolute or 836.6 scf/kg-mole 
at 60 [deg]F and 14.7 pounds per square inch absolute).
* * * * *
    (d) Optional combustion methodology for ethylene production 
processes. For each ethylene production process, calculate GHG 
emissions from combustion units that burn fuel that contains any off-
gas from the ethylene process as specified in paragraphs (d)(1) through 
(d)(5) of this section.
    (1) Except as specified in paragraphs (d)(2) and (d)(5) of this 
section, calculate CO2 emissions using the Tier 3 or Tier 4 
methodology in subpart C of this part.
    (2) You may use either Equation C-1 or Equation C-2a in subpart C 
of this part to calculate CO2 emissions from combustion of 
any ethylene process off-gas streams that meet either of the conditions 
in paragraphs (d)(2)(i) or (d)(2)(ii) of this section (for any default 
values in the calculation, use the defaults for fuel gas in Table C-1 
of subpart C of this part). Follow the otherwise applicable procedures 
in subpart C to calculate emissions from combustion of all other fuels 
in the combustion unit.
    (i) The annual average flow rate of fuel gas (that contains 
ethylene process off-gas) in the fuel gas line to the combustion unit, 
prior to any split to individual burners or ports, does not exceed 345 
standard cubic feet per minute at 60 [deg]F and 14.7 pounds per square 
inch absolute, and a flow meter is not installed at any point in the 
line supplying fuel gas or an upstream common pipe. Calculate the 
annual average flow rate using company records assuming total flow is 
evenly distributed over 525,600 minutes per year.
    (ii) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr, and a flow meter is not installed at any point 
in the line supplying fuel gas (that contains ethylene process off-gas) 
or an upstream common pipe.
    (3) Except as specified in paragraph (d)(5) of this section, 
calculate CH4 and N2O emissions using the 
applicable procedures in Sec.  98.33(c) for the same tier methodology 
that you used for calculating CO2 emissions.
    (i) For all gaseous fuels that contain ethylene process off-gas, 
use the emission factors for ``Petroleum'' in Table C-2 of subpart C of 
this part (General Stationary Fuel Combustion Sources).
    (ii) For Tier 3, use either the default high heat value for fuel 
gas in Table C-1 of subpart C of this part or a calculated HHV, as 
allowed in Equation C-8 of subpart C of this part.
    (4) You are not required to use the same Tier for each stationary 
combustion unit that burns ethylene process off-gas.
    (5) For each flare, calculate CO2, CH4, and 
N2O emissions using the methodology specified in Sec. Sec.  
98.253(b)(1) through (b)(3).

0
37. Section 98.244 is amended by revising paragraphs (b)(1) through 
(b)(3), (b)(4) introductory text, and (b)(4)(viii); and by adding 
paragraphs (b)(4)(xi) through (b)(4)(xv) to read as follows:


Sec.  98.244  Monitoring and QA/QC requirements.

* * * * *
    (b) * * *
    (1) Operate, maintain, and calibrate belt scales or other weighing 
devices as described in Specifications, Tolerances, and Other Technical 
Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) 
(incorporated by reference, see Sec.  98.7), or follow procedures 
specified by the measurement device manufacturer. You must recalibrate 
each weighing device according to one of the following frequencies. You 
may recalibrate either at the minimum frequency specified by the 
manufacturer or biennially (i.e., once every two years).
    (2) Operate and maintain all flow meters used for gas and liquid 
feedstocks and products according to the manufacturer's recommended 
procedures. You must calibrate each of these flow meters as specified 
in paragraphs (b)(2)(i) and (b)(2)(ii) of this section:
    (i) You may use either the calibration methods specified by the 
flow meter manufacturer or an industry consensus standard method. Each 
flow meter must meet the applicable accuracy specification in Sec.  
98.3(i), except as otherwise specified in Sec. Sec.  98.3(i)(4) through 
(i)(6).
    (ii) You must recalibrate each flow meter according to one of the 
following frequencies. You may recalibrate at the minimum frequency 
specified by the manufacturer, biennially (every two years), or at the 
interval specified by the industry consensus standard practice used.
    (3) You must perform tank level measurements (if used to determine 
feedstock or product flows) according to one of the following methods. 
You may use any standard method published by a consensus-based 
standards organization or you may use an industry standard practice. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box 
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, 
http://www.astm.org), the American National Standards Institute (ANSI, 
1819 L Street, NW., 6th Floor, Washington, DC 20036, (202) 293-8020, 
http://www.ansi.org), the American Gas Association (AGA, 400 North 
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, 
http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org,) and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
    (4) Beginning January 1, 2010, use any applicable methods specified 
in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section to 
determine the carbon content or composition of feedstocks and products 
and the average molecular weight of gaseous feedstocks and products. 
Calibrate instruments in accordance with paragraphs (b)(4)(i) through 
(b)(4)(xvi), as applicable. For coal used as a feedstock, the samples 
for carbon content determinations shall be

[[Page 79159]]

taken at a location that is representative of the coal feedstock used 
during the corresponding monthly period. For carbon black products, 
samples shall be taken of each grade or type of product produced during 
the monthly period. Samples of coal feedstock or carbon black product 
for carbon content determinations may be either grab samples collected 
and analyzed monthly or a composite of samples collected more 
frequently and analyzed monthly. Analyses conducted in accordance with 
methods specified in paragraphs (b)(4)(i) through (b)(4)(xv) of this 
section may be performed by the owner or operator, by an independent 
laboratory, or by the supplier of a feedstock.
* * * * *
    (viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A 
(all incorporated by reference, see Sec.  98.7).
* * * * *
    (xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for 
Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (xii) ASTM D7633-10 Standard Test Method for Carbon Black--Carbon 
Content (incorporated by reference, see Sec.  98.7).
    (xiii) The results of chromatographic analysis of a feedstock or 
product, provided that the gas chromatograph is operated, maintained, 
and calibrated according to the manufacturer's instructions.
    (xiv) The carbon content results of mass spectrometer analysis of a 
feedstock or product, provided that the mass spectrometer is operated, 
maintained, and calibrated according to the manufacturer's 
instructions.
    (xv) Beginning on January 1, 2010, the methods specified in 
paragraphs (b)(4)(xv)(A) and (B) of this section may be used as 
alternatives for the methods specified in paragraphs (b)(4)(i) through 
(b)(4)(xiv) of this section.
    (A) An industry standard practice for carbon black feedstock oils 
and carbon black products.
    (B) Modifications of existing analytical methods or other methods 
that are applicable to your process provided that the methods listed in 
paragraphs (b)(4)(i) through (b)(4)(xiv) of this section are not 
appropriate because the relevant compounds cannot be detected, the 
quality control requirements are not technically feasible, or use of 
the method would be unsafe.

0
38. Section 98.246 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(4).
0
b. Removing and reserving paragraph (a)(7).
0
c. Revising paragraph (a)(10).
0
d. Adding paragraph (a)(11).
0
e. Revising paragraphs (b) introductory text, and (b)(1) through 
(b)(5).
0
f. Revising paragraph (c).


Sec.  98.246  Data reporting requirements.

* * * * *
    (a) If you use the mass balance methodology in Sec.  98.243(c), you 
must report the information specified in paragraphs (a)(1) through 
(a)(11) of this section for each type of petrochemical produced, 
reported by process unit.
* * * * *
    (4) Each of the monthly volume, mass, and carbon content values 
used in Equations X-1 through X-3 of this subpart (i.e., the directly 
measured values, substitute values, or the calculated values based on 
other measured data such as tank levels or gas composition) and the 
molecular weights for gaseous feedstocks and products used in Equation 
X-1 of this subpart, and the temperature (in [deg]F) at which the 
gaseous feedstock and product volumes used in Equation X-1 of this 
subpart were determined. Indicate whether you used the alternative to 
sampling and analysis specified in Sec.  98.243(c)(4).
* * * * *
    (10) You may elect to report the flow and carbon content of 
wastewater, and you may elect to report the annual mass of carbon 
released in fugitive emissions and in process vents that are not 
controlled with a combustion device. These values may be estimated 
based on engineering analyses. These values are not to be used in the 
mass balance calculation.
    (11) If you determine carbon content or composition of a feedstock 
or product using a method under Sec.  98.244(b)(4)(xv)(B), report the 
information listed in paragraphs (a)(11)(i) through (a)(11)(iv) of this 
section. Include the information in paragraph (a)(11)(i) of this 
section in each annual report. Include the information in paragraphs 
(a)(11)(ii) and (a)(11)(iii) of this section only in the first 
applicable annual report, and provide any changes to this information 
in subsequent annual reports.
    (i) Name or title of the analytical method.
    (ii) A copy of the method. If the method is a modification of a 
method listed in Sec. Sec.  98.244(b)(4)(i) through (xiv), you may 
provide a copy of only the sections that differ from the listed method.
    (iii) An explanation of why an alternative to the methods listed in 
Sec. Sec.  98.244(b)(4)(i) through (xii) is needed.
    (b) If you measure emissions in accordance with Sec.  98.243(b), 
then you must report the information listed in paragraphs (b)(1) 
through (b)(8) of this section.
    (1) The petrochemical process unit ID or other appropriate 
descriptor, and the type of petrochemical produced.
    (2) For CEMS used on stacks for stationary combustion units, report 
the relevant information required under Sec.  98.36 for the Tier 4 
calculation methodology. Section 98.36(b)(9)(iii) does not apply for 
the purposes of this subpart.
    (3) For CEMS used on stacks that are not used for stationary 
combustion units, report the information required under Sec.  
98.36(e)(2)(vi).
    (4) The CO2 emissions from each stack and the combined 
CO2 emissions from all stacks (except flare stacks) that 
handle process vent emissions and emissions from stationary combustion 
units that burn process off-gas for the petrochemical process unit. For 
each stationary combustion unit (or group of combustion units monitored 
with a single CO2 CEMS) that burns petrochemical process 
off-gas, provide an estimate based on engineering judgment of the 
fraction of the total emissions that is attributable to combustion of 
off-gas from the petrochemical process unit.
    (5) For stationary combustion units that burn process off-gas from 
the petrochemical process unit, report the information related to 
CH4 and N2O emissions as specified in paragraphs 
(b)(5)(i) through (b)(5)(iv) of this section.
    (i) The CH4 and N2O emissions from each stack 
that is monitored with a CO2 CEMS, expressed in metric tons 
of each gas and in metric tons of CO2e. For each stack 
provide an estimate based on engineering judgment of the fraction of 
the total emissions that is attributable to combustion of off-gas from 
the petrochemical process unit.
    (ii) The combined CH4 and N2O emissions from 
all stationary combustion units, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (iii) The quantity of each type of fuel used in Equation C-8 in 
Sec.  98.33(c) for each stationary combustion unit or group of units 
(as applicable) during the reporting year, expressed in short tons for 
solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
    (iv) The HHV (either default or annual average from measured data) 
used in Equation C-8 in Sec.  98.33(c) for each

[[Page 79160]]

stationary combustion unit or group of combustion units (as 
applicable).
* * * * *
    (c) If you comply with the combustion methodology specified in 
Sec.  98.243(d), you must report under this subpart the information 
listed in paragraphs (c)(1) through (c)(5) of this section.
    (1) The ethylene process unit ID or other appropriate descriptor.
    (2) For each stationary combustion unit that burns ethylene process 
off-gas (or group of stationary sources with a common pipe), except 
flares, the relevant information listed in Sec.  98.36 for the 
applicable Tier methodology. For each stationary combustion unit or 
group of units (as applicable) that burns ethylene process off-gas, 
provide an estimate based on engineering judgment of the fraction of 
the total emissions that is attributable to combustion of off-gas from 
the ethylene process unit.
    (3) Information listed in Sec.  98.256(e) of subpart Y of this part 
for each flare that burns ethylene process off-gas.
    (4) Name and annual quantity of each feedstock.
    (5) Annual quantity of ethylene produced from each process unit 
(metric tons).

0
39. Section 98.247 is amended by:
0
a. Revising paragraph (a).
0
b. Adding paragraph (b)(4).
0
c. Revising paragraph (c).


Sec.  98.247  Records that must be retained.

* * * * *
    (a) If you comply with the CEMS measurement methodology in Sec.  
98.243(b), then you must retain under this subpart the records required 
for the Tier 4 Calculation Methodology in Sec.  98.37, records of the 
procedures used to develop estimates of the fraction of total emissions 
attributable to combustion of petrochemical process off-gas as required 
in Sec.  98.246(b), and records of any annual average HHV calculations.
    (b) * * *
    (4) The dates and results (e.g., percent calibration error) of the 
calibrations of each measurement device.
    (c) If you comply with the combustion methodology in Sec.  
98.243(d), then you must retain under this subpart the records required 
for the applicable Tier Calculation Methodologies in Sec.  98.37. If 
you comply with Sec.  98.243(d)(2), you must also keep records of the 
annual average flow calculations.

Subpart Y--[Amended]

0
40. Section 98.252 is amended by revising paragraph (a) and the first 
sentence of paragraph (i) to read as follows:


Sec.  98.252  GHGs to report.

* * * * *
    (a) CO2, CH4, and N2O combustion 
emissions from stationary combustion units and from each flare. 
Calculate and report the emissions from stationary combustion units 
under subpart C of this part (General Stationary Fuel Combustion 
Sources) by following the requirements of subpart C, except for 
emissions from combustion of fuel gas. For CO2 emissions 
from combustion of fuel gas, use either Equation C-5 in subpart C of 
this part or the Tier 4 methodology in subpart C of this part, unless 
either of the conditions in paragraphs (a)(1) or (2) of this section 
are met, in which case use either Equations C-1 or C-2a in subpart C of 
this part. For CH4 and N2O emissions from 
combustion of fuel gas, use the applicable procedures in Sec.  98.33(c) 
for the same tier methodology that was used for calculating 
CO2 emissions. (Use the default CH4 and 
N2O emission factors for ``Petroleum (All fuel types in 
Table C-1)'' in Table C-2 of this part. For Tier 3, use either the 
default high heat value for fuel gas in Table C-1 of subpart C of this 
part or a calculated HHV, as allowed in Equation C-8 of subpart C of 
this part.) You may aggregate units, monitor common stacks, or monitor 
common (fuel) pipes as provided in Sec.  98.36(c) when calculating and 
reporting emissions from stationary combustion units. Calculate and 
report the emissions from flares under this subpart.
    (1) The annual average fuel gas flow rate in the fuel gas line to 
the combustion unit, prior to any split to individual burners or ports, 
does not exceed 345 standard cubic feet per minute at 60 [deg]F and 
14.7 pounds per square inch absolute and either of the conditions in 
paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual 
average flow rate using company records assuming total flow is evenly 
distributed over 525,600 minutes per year.
    (i) A flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe.
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
    (2) The combustion unit has a maximum rated heat input capacity of 
less than 30 mmBtu/hr and either of the following conditions exist:
    (i) A flow meter is not installed at any point in the line 
supplying fuel gas or an upstream common pipe; or
    (ii) The fuel gas line contains only vapors from loading or 
unloading, waste or wastewater handling, and remediation activities 
that are combusted in a thermal oxidizer or thermal incinerator.
* * * * *
    (i) CO2 emissions from non-merchant hydrogen production 
process units (not including hydrogen produced from catalytic reforming 
units) under this subpart. * * *

0
41. Section 98.253 is amended by:
0
a. Revising paragraph (b)(1)(ii)(A).
0
b. Revising the definition of ``(Flare)p'' in Equation Y-2 
in paragraph (b)(1)(ii)(B).
0
c. Revising the definition of ``MVC'' in Equation Y-3 in paragraph 
(b)(1)(iii)(C).
0
d. Revising paragraph (c)(1)(ii).
0
e. Revising the definition of ``MVC'' in Equation Y-6 in paragraph 
(c)(2)(i).
0
f. Revising paragraph (c)(2)(ii).
0
g. Revising the definitions of ``CBQ'' and ``n'' in Equation 
Y-11 in paragraph (e)(3).
0
h. Revising the first sentence of paragraph (f) introductory text and 
the last sentence of paragraph (f)(1).
0
i. Revising the definition of ``MVC'' in Equation Y-12 in paragraph 
(f)(4).
0
j. Revising the definition of ``Mdust'' in Equation Y-13 in 
paragraph (g)(2).
0
k. Revising paragraphs (h) introductory text and (h)(2).
0
l. In paragraph (i)(1), revising the first two sentences and the 
definition of ``MVC'' in Equation Y-18.
0
m. In paragraph (j), revising the first two sentences; and revising the 
definitions of ``(VR)p,'' ``(MFx)p,'' 
and ``MVC'' in Equation Y-19.
0
n. In paragraph (k), revising the first sentence and the definition of 
``MVC'' in Equation Y-20.
0
o. Revising paragraph (m) introductory text.
0
p. Revising the only sentence of paragraph (m)(1).
0
p. Revising the definitions of ``MFCH4'' and ``MVC'' in 
Equation Y-23 in paragraph (m)(2).
0
q. Revising paragraph (n).


Sec.  98.253  Calculating GHG emissions.

* * * * *
    (b) * * *
    (1) * * *
    (ii) * * *
    (A) If you monitor gas composition, calculate the CO2 
emissions from the flare using either Equation Y-1a or Equation Y-1b of 
this section. If daily or more frequent measurement data are available, 
you must use daily values when using Equation Y-1a or Equation Y-1b of 
this section; otherwise, use weekly values.

[[Page 79161]]

[GRAPHIC] [TIFF OMITTED] TR17DE10.005

Where:

CO2 = Annual CO2 emissions for a specific fuel 
type (metric tons/year).
0.98 = Assumed combustion efficiency of a flare.
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of measurement periods. The minimum value for n is 52 
(for weekly measurements); the maximum value for n is 366 (for daily 
measurements during a leap year).
p = Measurement period index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(Flare)p = Volume of flare gas combusted during 
measurement period (standard cubic feet per period, scf/period). If 
a mass flow meter is used, measure flare gas flow rate in kg/period 
and replace the term ``(MW)p/MVC'' with ``1''.
(MW)p = Average molecular weight of the flare gas 
combusted during measurement period (kg/kg-mole). If measurements 
are taken more frequently than daily, use the arithmetic average of 
measurement values within the day to calculate a daily average.
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 pounds per square inch absolute (psia) or 836.6 scf/kg-mole 
at 60 [deg]F and 14.7 psia).
(CC)p = Average carbon content of the flare gas combusted 
during measurement period (kg C per kg flare gas). If measurements 
are taken more frequently than daily, use the arithmetic average of 
measurement values within the day to calculate a daily average.
[GRAPHIC] [TIFF OMITTED] TR17DE10.006

Where:

CO2 = Annual CO2 emissions for a specific fuel 
type (metric tons/year).
n = Number of measurement periods. The minimum value for n is 52 
(for weekly measurements); the maximum value for n is 366 (for daily 
measurements during a leap year).
p = Measurement period index.
(Flare)p = Volume of flare gas combusted during 
measurement period (standard cubic feet per period, scf/period). If 
a mass flow meter is used, you must determine the average molecular 
weight of the flare gas during the measurement period and convert 
the mass flow to a volumetric flow.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
(%CO2)p = Mole percent CO2 
concentration in the flare gas stream during the measurement period 
(mole percent = percent by volume).
y = Number of carbon-containing compounds other than CO2 
in the flare gas stream.
x = Index for carbon-containing compounds other than CO2.
0.98 = Assumed combustion efficiency of a flare (mole CO2 
per mole carbon).
(%Cx)p = Mole percent concentration of 
compound ``x'' in the flare gas stream during the measurement period 
(mole percent = percent by volume)
CMNx = Carbon mole number of compound ``x'' in the flare 
gas stream (mole carbon atoms per mole compound). E.g., CMN for 
ethane (C2H6) is 2; CMN for propane 
(C3H8) is 3.

    (B) * * *

(Flare)p = Volume of flare gas combusted during 
measurement period (million (MM) scf/period). If a mass flow meter 
is used, you must also measure molecular weight and convert the mass 
flow to a volumetric flow as follows: Flare[MMscf] = 0.000001 x 
Flare[kg] x MVC/(MW)p, where MVC is the molar volume 
conversion factor [849.5 scf/kg-mole at 68 [deg]F and 14.7 psia or 
836.6 scf/kg-mole at 60 [deg]F and 14.7 psia depending on the 
standard conditions used when determining (HHV)p] and 
(MW)p is the average molecular weight of the flare gas 
combusted during measurement period (kg/kg-mole).
* * * * *
    (iii) * * *
    (C) * * *

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (c) * * *
    (1) * * *
    (ii) For catalytic cracking units whose process emissions are 
discharged through a combined stack with other CO2 emissions 
(e.g., co-mingled with emissions from a CO boiler) you must also 
calculate the other CO2 emissions using the applicable 
methods for the applicable subpart (e.g., subpart C of this part in the 
case of a CO boiler). Calculate the process emissions from the 
catalytic cracking unit or fluid coking unit as the difference in the 
CO2 CEMS emissions and the calculated emissions associated 
with the additional units discharging through the combined stack.
    (2) * * *
    (i) * * *

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
    (ii) Either continuously monitor the volumetric flow rate of 
exhaust gas from the fluid catalytic cracking unit regenerator or fluid 
coking unit burner prior to the combustion of other fossil fuels or 
calculate the volumetric flow rate of this exhaust gas stream using 
either Equation Y-7a or Equation Y-7b of this section.
[GRAPHIC] [TIFF OMITTED] TR17DE10.007

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner

[[Page 79162]]

prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
cracking unit regenerator or fluid coking unit burner, as determined 
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
fluid catalytic cracking unit regenerator or fluid coking unit 
burner as determined from control room instrumentation (dscfh).
%O2 = Hourly average percent oxygen concentration in 
exhaust gas stream from the fluid catalytic cracking unit 
regenerator or fluid coking unit burner (percent by volume--dry 
basis).
%Ooxy = O2 concentration in oxygen enriched 
gas stream inlet to the fluid catalytic cracking unit regenerator or 
fluid coking unit burner based on oxygen purity specifications of 
the oxygen supply used for enrichment (percent by volume--dry 
basis).
%CO2 = Hourly average percent CO2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas 
stream from the fluid catalytic cracking unit regenerator or fluid 
coking unit burner (percent by volume--dry basis). When no auxiliary 
fuel is burned and a continuous CO monitor is not required under 40 
CFR part 63 subpart UUU, assume %CO to be zero.
[GRAPHIC] [TIFF OMITTED] TR17DE10.008

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner 
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
cracking unit regenerator or fluid coking unit burner, as determined 
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
fluid catalytic cracking unit regenerator or fluid coking unit 
burner as determined from control room instrumentation (dscfh).
%N2,oxy = N2 concentration in oxygen enriched 
gas stream inlet to the fluid catalytic cracking unit regenerator or 
fluid coking unit burner based on measured value or maximum 
N2 impurity specifications of the oxygen supply used for 
enrichment (percent by volume--dry basis).

%N2,exhaust = Hourly average percent N2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
* * * * *
    (e) * * *
    (3) * * *

CBQ = Coke burn-off quantity per regeneration cycle or 
measurement period from engineering estimates (kg coke/cycle or kg 
coke/measurement period).
n = Number of regeneration cycles or measurement periods in the 
calendar year.

* * * * *
    (f) For on-site sulfur recovery plants and for sour gas sent off 
site for sulfur recovery, calculate and report CO2 process 
emissions from sulfur recovery plants according to the requirements in 
paragraphs (f)(1) through (f)(5) of this section, or, for non-Claus 
sulfur recovery plants, according to the requirements in paragraph (j) 
of this section regardless of the concentration of CO2 in 
the vented gas stream. * * *
    (1) * * * Other sulfur recovery plants must either install a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C, or 
follow the requirements of paragraphs (f)(2) through (f)(5) of this 
section, or (for non-Claus sulfur recovery plants only) follow the 
requirements in paragraph (j) of this section to determine 
CO2 emissions for the sulfur recovery plant.
* * * * *
    (4) * * *

MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).

* * * * *
    (g) * * *
    (2) * * *

Mdust = Annual mass of petroleum coke dust removed from 
the process through the dust collection system of the coke calcining 
unit from facility records (metric ton petroleum coke dust/year). 
For coke calcining units that recycle the collected dust, the mass 
of coke dust removed from the process is the mass of coke dust 
collected less the mass of coke dust recycled to the process.

* * * * *
    (h) For asphalt blowing operations, calculate CO2 and 
CH4 emissions according to the requirements in paragraph (j) 
of this section regardless of the CO2 and CH4 
concentrations or according to the applicable provisions in paragraphs 
(h)(1) and (h)(2) of this section.
* * * * *
    (2) For asphalt blowing operations controlled by thermal oxidizer 
or flare, calculate CO2 using either Equation Y-16a or 
Equation Y-16b of this section and calculate CH4 emissions 
using Equation Y-17 of this section, provided these emissions are not 
already included in the flare emissions calculated in paragraph (b) of 
this section or in the stationary combustion unit emissions required 
under subpart C of this part (General Stationary Fuel Combustion 
Sources).
[GRAPHIC] [TIFF OMITTED] TR17DE10.009

Where:

CO2 = Annual CO2 emissions from controlled 
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from 
facility-specific test data (metric tons C/MMbbl asphalt blown); 
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).

[[Page 79163]]

[GRAPHIC] [TIFF OMITTED] TR17DE10.010

Where:

CO2 = Annual CO2 emissions from controlled 
asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (MMbbl/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
EFAB,CO2 = Emission factor for CO2 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CO2/MMbbl asphalt blown); default = 1,100.
CEFAB = Carbon emission factor from asphalt blowing from 
facility-specific test data (metric tons C/MMbbl asphalt blown); 
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TR17DE10.011

Where:

CH4 = Annual methane emissions from controlled asphalt 
blowing (metric tons CH4/year).
0.02 = Fraction of methane uncombusted in thermal oxidizer or flare 
based on assumed 98% combustion efficiency.
QAB = Quantity of asphalt blown (million barrels per 
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CH4/MMbbl asphalt blown); default = 580.

    (i) * * *
    (1) Use the process vent method in paragraph (j) of this section to 
calculate the CH4 emissions from the depressurization of the 
coke drum or vessel regardless of the CH4 concentration and 
also calculate the CH4 emissions from the subsequent opening 
of the vessel for coke cutting operations using Equation Y-18 of this 
section. If you have coke drums or vessels of different dimensions, use 
the process vent method in paragraph (j) of this section and Equation 
Y-18 for each set of coke drums or vessels of the same size and sum the 
resultant emissions across each set of coke drums or vessels to 
calculate the CH4 emissions for all delayed coking units.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (j) For each process vent not covered in paragraphs (a) through (i) 
of this section that can reasonably be expected to contain greater than 
2 percent by volume CO2 or greater than 0.5 percent by 
volume of CH4 or greater than 0.01 percent by volume (100 
parts per million) of N2O, calculate GHG emissions using the 
Equation Y-19 of this section. You must use Equation Y-19 of this 
section to calculate CH4 emissions for catalytic reforming 
unit depressurization and purge vents when methane is used as the purge 
gas or if you elected this method as an alternative to the methods in 
paragraphs (f), (h), or (k) of this section.
* * * * *
(VR)p = Average volumetric flow rate of process gas 
during the event (scf per hour) from measurement data, process 
knowledge, or engineering estimates.
(MFx)p = Mole fraction of GHG x in process 
vent during the event (kg-mol of GHG x/kg-mol vent gas) from 
measurement data, process knowledge, or engineering estimates.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (k) For uncontrolled blowdown systems, you must calculate CH4 
emissions either using the methods for process vents in paragraph (j) 
of this section regardless of the CH4 concentration or using 
Equation Y20 of this section. * * *
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (m) For storage tanks, except as provided in paragraph (m)(4) of 
this section, calculate CH4 emissions using the applicable 
methods in paragraphs (m)(1) through (m)(3) of this section.
    (1) For storage tanks other than those processing unstabilized 
crude oil, you must either calculate CH4 emissions from 
storage tanks that have a vapor-phase methane concentration of 0.5 
volume percent or more using tank-specific methane composition data 
(from measurement data or product knowledge) and the emission 
estimation methods provided in AP 42, Section 7.1 (incorporated by 
reference, see Sec.  98.7) or estimate CH4 emissions from 
storage tanks using Equation Y-22 of this section.
* * * * *
    (2) * * *
MFCH4 = Average mole fraction of CH4 in vent 
gas from the unstabilized crude oil storage tanks from facility 
measurements (kg-mole CH4/kg-mole gas); use 0.27 as a 
default if measurement data are not available.
* * * * *
MVC = Molar volume conversion factor (849.5 scf/kg-mole at 68 [deg]F 
and 14.7 psia or 836.6 scf/kg-mole at 60 [deg]F and 14.7 psia).
* * * * *
    (n) For crude oil, intermediate, or product loading operations for 
which the vapor-phase concentration of methane is 0.5 volume percent or 
more, calculate CH4 emissions from loading operations using 
vapor-phase methane composition data (from measurement data or process 
knowledge) and the emission estimation procedures provided in AP 42, 
Section 5.2 (incorporated by reference, see Sec.  98.7). For loading 
operations in which the vapor-phase concentration of methane is less 
than 0.5 volume percent, you may assume zero methane emissions.

0
42. Section 98.254 is amended by:
0
a. Revising paragraph (a).
0
b. Revising paragraph (b).
0
c. Revising paragraph (c).
0
d. Revising paragraph (d) introductory text.
0
e. Adding paragraph (d)(6).
0
f. Revising paragraph (e) introductory text.
0
g. Revising paragraph (f) introductory text and (f)(1).
0
h. Removing and reserving paragraph (f)(2).
0
i. Removing paragraph (f)(4).
0
j. Revising paragraph (g).
0
k. Revising the second sentence of paragraph (h).
0
l. Removing paragraph (l).


Sec.  98.254  Monitoring and QA/QC requirements.

    (a) Fuel flow meters, gas composition monitors, and heating value 
monitors that are associated with sources that use a CEMS to measure 
CO2 emissions

[[Page 79164]]

according to subpart C of this part or that are associated with 
stationary combustion sources must meet the applicable monitoring and 
QA/QC requirements in Sec.  98.34.
    (b) All gas flow meters, gas composition monitors, and heating 
value monitors that are used to provide data for the GHG emissions 
calculations in this subpart for sources other than those subject to 
the requirements in paragraph (a) of this section shall be calibrated 
according to the procedures specified by the manufacturer, or according 
to the procedures in the applicable methods specified in paragraphs (c) 
through (g) of this section. In the case of gas flow meters, all gas 
flow meters must meet the calibration accuracy requirements in Sec.  
98.3(i). All gas flow meters, gas composition monitors, and heating 
value monitors must be recalibrated at the applicable frequency 
specified in paragraph (b)(1) or (b)(2) of this section.
    (1) You must recalibrate each gas flow meter according to one of 
the following frequencies. You may recalibrate at the minimum frequency 
specified by the manufacturer, biennially (every two years), or at the 
interval specified by the industry consensus standard practice used.
    (2) You must recalibrate each gas composition monitor and heating 
value monitor according to one of the following frequencies. You may 
recalibrate at the minimum frequency specified by the manufacturer, 
annually, or at the interval specified by the industry standard 
practice used.
    (c) For flare or sour gas flow meters and gas flow meters used to 
comply with the requirements in Sec.  98.253(j), operate, calibrate, 
and maintain the flow meter according to one of the following. You may 
use the procedures specified by the flow meter manufacturer, or a 
method published by a consensus-based standards organization. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box 
CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, 
http://www.astm.org), the American National Standards Institute (ANSI, 
1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, 
http://www.ansi.org), the American Gas Association (AGA, 400 North 
Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, 
http://www.aga.org), the American Society of Mechanical Engineers 
(ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, 
http://www.asme.org), the American Petroleum Institute (API, 1220 L 
Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 
Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
    (d) Except as provided in paragraph (g) of this section, determine 
gas composition and, if required, average molecular weight of the gas 
using any of the following methods. Alternatively, the results of 
chromatographic analysis of the fuel may be used, provided that the gas 
chromatograph is operated, maintained, and calibrated according to the 
manufacturer's instructions; and the methods used for operation, 
maintenance, and calibration of the gas chromatograph are documented in 
the written Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *
    (6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure (incorporated by 
reference, see Sec.  98.7).
    (e) Determine flare gas higher heating value using any of the 
following methods. Alternatively, the results of chromatographic 
analysis of the fuel may be used, provided that the gas chromatograph 
is operated, maintained, and calibrated according to the manufacturer's 
instructions; and the methods used for operation, maintenance, and 
calibration of the gas chromatograph are documented in the written 
Monitoring Plan for the unit under Sec.  98.3(g)(5).
* * * * *
    (f) For gas flow meters used to comply with the requirements in 
Sec.  98.253(c)(2)(ii), install, operate, calibrate, and maintain each 
gas flow meter according to the requirements in 40 CFR 63.1572(c) and 
the following requirements.
    (1) Locate the flow monitor at a site that provides representative 
flow rates. Avoid locations where there is swirling flow or abnormal 
velocity distributions due to upstream and downstream disturbances.
* * * * *
    (g) For exhaust gas CO2/CO/O2 composition 
monitors used to comply with the requirements in Sec.  98.253(c)(2), 
install, operate, calibrate, and maintain exhaust gas composition 
monitors according to the requirements in 40 CFR 60.105a(b)(2) or 40 
CFR 63.1572(c) or according to the manufacturer's specifications and 
requirements.
    (h) * * * Calibrate the measurement device according to the 
procedures specified by NIST handbook 44 (incorporated by reference, 
see Sec.  98.7) or the procedures specified by the manufacturer. * * *
* * * * *

0
43. Section 98.256 is amended by:
0
a. Revising paragraph (e)(6).
0
b. Redesignating paragraphs (e)(7) through (e)(9) as (e)(8) through 
(e)(10), respectively.
0
c. Adding paragraph (e)(7).
0
d. Revising newly designated paragraphs (e)(8) and (e)(9).
0
e. Revising paragraphs (f)(6) through (f)(8).
0
f. Redesignating paragraphs (f)(9) through (f)(12) as (f)(10) through 
(f)(13), respectively.
0
g. Adding paragraph (f)(9).
0
h. Revising newly designated paragraphs (f)(11) through (f)(13).
0
i. Revising paragraphs (g)(5), (h)(2), and (h)(4), and the first 
sentence of paragraph (h)(6).
0
j. Adding paragraph (h)(7).
0
k. Revising paragraphs (i)(5), (i)(6), (i)(8), and (j)(2).
0
l. Redesignating paragraph (j)(8) as (j)(9).
0
m. Adding paragraph (j)(8).
0
n. Revising paragraphs (k)(1), (k)(3), (l) introductory text, (l)(5), 
and (m).
0
o. Revising paragraphs (o)(1) through (o)(4).


Sec.  98.256  Data reporting requirements.

* * * * *
    (e) * * *
    (6) If you use Equation Y-1a of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year) and the annual average molecular 
weight (in kg/kg-mole), the molar volume conversion factor (in scf/kg-
mole), and annual average carbon content of the flare gas (in kg carbon 
per kg flare gas).
    (7) If you use Equation Y-1b of this subpart, an indication of 
whether daily or weekly measurement periods are used, the annual volume 
of flare gas combusted (in scf/year), the molar volume conversion 
factor (in scf/kg-mole), the annual average CO2 
concentration (volume or mole percent), the number of carbon containing 
compounds other than CO2 in the flare gas stream, and for 
each of the carbon containing compounds other than CO2 in 
the flare gas stream:
    (i) The annual average concentration of the compound (volume or 
mole percent).
    (ii) The carbon mole number of the compound (moles carbon per mole 
compound).
    (8) If you use Equation Y-2 of this subpart, an indication of 
whether daily

[[Page 79165]]

or weekly measurement periods are used, the annual volume of flare gas 
combusted (in million (MM) scf/year), the annual average higher heating 
value of the flare gas (in mmBtu/mmscf), and an indication of whether 
the annual volume of flare gas combusted and the annual average higher 
heating value of the flare gas were determined using standard 
conditions of 68 [deg]F and 14.7 psia or 60 [deg]F and 14.7 psia.
    (9) If you use Equation Y-3 of this subpart, the annual volume of 
flare gas combusted (in MMscf/year) during normal operations, the 
annual average higher heating value of the flare gas (in mmBtu/mmscf), 
the number of SSM events exceeding 500,000 scf/day, the volume of gas 
flared (in scf/event), the average molecular weight (in kg/kg-mole), 
the molar volume conversion factor (in scf/kg-mole), and carbon content 
of the flare gas (in kg carbon per kg flare) for each SSM event over 
500,000 scf/day.
* * * * *
    (f) * * *
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS (unadjusted to remove 
CO2 combustion emissions associated with additional units, 
if present) and the process CO2 emissions as calculated 
according to Sec.  98.253(c)(1)(ii). Report the CO2 annual 
emissions associated with sources other than those from the coke burn-
off in the applicable subpart (e.g., subpart C of this part in the case 
of a CO boiler).
    (7) If you use Equation Y-6 of this subpart, the annual average 
exhaust gas flow rate, %CO2, %CO, and the molar volume 
conversion factor (in scf/kg-mole).
    (8) If you use Equation Y-7a of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %O2, 
%Ooxy, %CO2, and %CO.
    (9) If you use Equation Y-7b of this subpart, the annual average 
flow rate of inlet air and oxygen-enriched air, %N2,oxy, and 
%N2,exhaust.
* * * * *
    (11) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for CH4 
emissions. If you use a unit-specific emission factor for 
CH4, report the unit-specific emission factor for 
CH4, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor.
    (12) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the unit-specific emission factor for 
N2O, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor.
    (13) If you use Equation Y-11 of this subpart, the number of 
regeneration cycles or measurement periods during the reporting year, 
the average coke burn-off quantity per cycle or measurement period, and 
the average carbon content of the coke.
    (g) * * *
    (5) If the GHG emissions for the low heat value gas are calculated 
at the flexicoking unit, also report the calculated annual 
CO2, CH4, and N2O emissions for each 
unit, expressed in metric tons of each pollutant emitted, and the 
applicable equation input parameters specified in paragraphs (f)(7) 
through (f)(13) of this section.
    (h) * * *
    (2) Maximum rated throughput of each independent sulfur recovery 
plant, in metric tons sulfur produced/stream day, a description of the 
type of sulfur recovery plant, and an indication of the method used to 
calculate CO2 annual emissions for the sulfur recovery plant 
(e.g., CO2 CEMS, Equation Y-12, or process vent method in 
Sec.  98.253(j)).
* * * * *
    (4) If you use Equation Y-12 of this subpart, the annual volumetric 
flow to the sulfur recovery plant (in scf/year), the molar volume 
conversion factor (in scf/kg-mole), and the annual average mole 
fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
* * * * *
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS and the annual process 
CO2 emissions calculated according to Sec.  98.253(f)(1). * 
* *
    (7) If you use the process vent method in Sec.  98.253(j) for a 
non-Claus sulfur recovery plant, the relevant information required 
under paragraph (l)(5) of this section.
    (i) * * *
    (5) If you use Equation Y-13 of this subpart, annual mass and 
carbon content of green coke fed to the unit, the annual mass and 
carbon content of marketable coke produced, the annual mass of coke 
dust removed from the process through dust collection systems, and an 
indication of whether coke dust is recycled to the unit (e.g., all dust 
is recycled, a portion of the dust is recycled, or none of the dust is 
recycled).
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36 for the Tier 4 Calculation Methodology, the CO2 
annual emissions as measured by the CEMS and the annual process 
CO2 emissions calculated according to Sec.  98.253(g)(1). * 
* *
* * * * *
    (8) Indicate whether you use a measured value, a unit-specific 
emission factor, or a default emission factor for N2O 
emissions. If you use a unit-specific emission factor for 
N2O, report the unit-specific emission factor for 
N2O, the units of measure for the unit-specific factor, the 
activity data for calculating emissions (e.g., if the emission factor 
is based on coke burn-off rate, the annual quantity of coke burned), 
and the basis for the factor.
    (j) * * *
    (2) The quantity of asphalt blown (in million bbl) at the unit in 
the reporting year.
* * * * *
    (8) If you use Equation Y-16b of this subpart, the CO2 
emission factor used and the basis for its value and the carbon 
emission factor used and the basis for its value.
* * * * *
    (k) * * *
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all delayed coking units at the facility.
* * * * *
    (3) The total number of delayed coking units at the facility, the 
total number of delayed coking drums at the facility, and for each coke 
drum or vessel: The dimensions, the typical gauge pressure of the 
coking drum when first vented to the atmosphere, typical void fraction, 
the typical drum outage (i.e. the unfilled distance from the top of the 
drum, in feet), the molar volume conversion factor (in scf/kg-mole), 
and annual number of coke-cutting cycles.
* * * * *
    (l) For each process vent subject to Sec.  98.253(j), the owner or 
operator shall report:
* * * * *
    (5) The annual volumetric flow discharged to the atmosphere (in 
scf), and an indication of the measurement or estimation method, annual 
average mole fraction of each GHG above the concentration threshold or 
otherwise required to be reported and an indication of the measurement 
or estimation method, the molar volume conversion factor (in scf/kg-
mole), and for intermittent vents, the number of

[[Page 79166]]

venting events and the cumulative venting time.
    (m) For uncontrolled blowdown systems, the owner or operator shall 
report:
    (1) An indication of whether the uncontrolled blowdown emission are 
reported under Sec.  98.253(k) or Sec.  98.253(j) or a statement that 
the facility does not have any uncontrolled blowdown systems.
    (2) The cumulative annual CH4 emissions (in metric tons 
of CH4) for uncontrolled blowdown systems.
    (3) For uncontrolled blowdown systems reporting under Sec.  
98.253(k), the total quantity (in million bbl) of crude oil plus the 
quantity of intermediate products received from off site that are 
processed at the facility in the reporting year, the methane emission 
factor used for uncontrolled blowdown systems, the basis for the value, 
and the molar volume conversion factor (in scf/kg-mole).
    (4) For uncontrolled blowdown systems reporting under Sec.  
98.253(j), the relevant information required under paragraph (l)(5) of 
this section.
* * * * *
    (o) * * *
    (1) The cumulative annual CH4 emissions (in metric tons 
of CH4) for all storage tanks, except for those used to 
process unstabilized crude oil.
    (2) For storage tanks other than those processing unstabilized 
crude oil:
    (i) The method used to calculate the reported storage tank 
emissions for storage tanks other than those processing unstabilized 
crude (i.e., either AP 42, Section 7.1 (incorporated by reference, see 
Sec.  98.7), or Equation Y-22 of this section).
    (ii) The total quantity (in MMbbl) of crude oil plus the quantity 
of intermediate products received from off site that are processed at 
the facility in the reporting year.
    (3) The cumulative CH4 emissions (in metric tons of 
CH4) for storage tanks used to process unstabilized crude 
oil or a statement that the facility did not receive any unstabilized 
crude oil during the reporting year.
    (4) For storage tanks that process unstabilized crude oil:
    (i) The method used to calculate the reported unstabilized crude 
oil storage tank emissions.
    (ii) The quantity of unstabilized crude oil received during the 
calendar year (in MMbbl).
    (iii) The average pressure differential (in psi).
    (iv) The molar volume conversion factor (in scf/kg-mole).
    (v) The average mole fraction of CH4 in vent gas from 
unstabilized crude oil storage tanks and the basis for the mole 
fraction.
    (vi) If you did not use Equation Y-23, the tank-specific methane 
composition data and the gas generation rate data used to estimate the 
cumulative CH4 emissions for storage tanks used to process 
unstabilized crude oil.
* * * * *

0
44. Section 98.257 is revised to read as follows:


Sec.  98.257  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records of all parameters monitored under Sec.  98.255. If 
you comply with the combustion methodology in Sec.  98.252(a), then you 
must retain under this subpart the records required for the Tier 3 and/
or Tier 4 Calculation Methodologies in Sec.  98.37 and you must keep 
records of the annual average flow calculations.

Subpart AA--[Amended]

0
45. Section 98.273 is amended by:
0
a. Revising paragraphs (a)(1) and (a)(2).
0
b. Revising the definition of ``EF'' in Equation AA-1 of paragraph 
(a)(3).
0
c. Revising paragraphs (b)(1) and (b)(2).
0
d. Revising paragraphs (c)(1) and (c)(2).


Sec.  98.273  Calculating GHG emissions.

    (a) * * *
    (1) Calculate fossil fuel-based CO2 emissions from 
direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 methodology for stationary combustion 
sources in Sec.  98.33(a)(1). A higher tier from Sec.  98.33(a) may be 
used to calculate fossil fuel-based CO2 emissions if the 
respective monitoring and QA/QC requirements described in Sec.  98.34 
are met.
    (2) Calculate fossil fuel-based CH4 and N2O 
emissions from direct measurement of fossil fuels consumed, default or 
site-specific HHV, and default emissions factors and convert to metric 
tons of CO2 equivalent according to the methodology for 
stationary combustion sources in Sec.  98.33(c).
    (3) * * *

(EF) = Default or site-specific emission factor for CO2, 
CH4, or N2O, from Table AA-1 of this subpart 
(kg CO2, CH4, or N2O per mmBtu).
* * * * *
    (b) * * *
    (1) Calculate fossil CO2 emissions from fossil fuels 
from direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 Calculation Methodology for stationary 
combustion sources in Sec.  98.33(a)(1). A higher tier from Sec.  
98.33(a) may be used to calculate fossil fuel-based CO2 
emissions if the respective monitoring and QA/QC requirements described 
in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuels from direct measurement of fossil fuels consumed, default 
or site-specific HHV, and default emissions factors and convert to 
metric tons of CO2 equivalent according to the methodology 
for stationary combustion sources in Sec.  98.33(c).
* * * * *
    (c) * * *
    (1) Calculate CO2 emissions from fossil fuel from direct 
measurement of fossil fuels consumed and default HHV and default 
emissions factors, according to the Tier 1 Calculation Methodology for 
stationary combustion sources in Sec.  98.33(a)(1). A higher tier from 
Sec.  98.33(a) may be used to calculate fossil fuel-based 
CO2 emissions if the respective monitoring and QA/QC 
requirements described in Sec.  98.34 are met.
    (2) Calculate CH4 and N2O emissions from 
fossil fuel from direct measurement of fossil fuels consumed, default 
or site-specific HHV, and default emissions factors and convert to 
metric tons of CO2 equivalent according to the methodology 
for stationary combustion sources in Sec.  98.33(c); use the default 
HHV listed in Table C-1 of subpart C and the default CH4 and 
N2O emissions factors listed in Table AA-2 of this subpart.
* * * * *

0
46. Section 98.276 is amended by revising the introductory text and 
revising paragraph (e) to read as follows:


Sec.  98.276  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c) and the 
applicable information required by Sec.  98.36, each annual report must 
contain the information in paragraphs (a) through (k) of this section 
as applicable:
* * * * *
    (e) The default or site-specific emission factor for 
CO2, CH4, or N2O, used in Equation AA-
1 of this subpart (kg CO2, CH4, or N2O 
per mmBtu).
* * * * *

0
47. Table AA-2 to Subpart AA is revised to read as follows:

[[Page 79167]]



  Table AA-2 to Subpart AA--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CH[ihel4] and
                                                    N[ihel2]O
----------------------------------------------------------------------------------------------------------------
                                                    Fossil fuel-based emissions factors (kg/mmBtu HHV)
                                         -----------------------------------------------------------------------
                  Fuel                             Kraft lime kilns                     Kraft calciners
                                         -----------------------------------------------------------------------
                                              CH[ihel4]         N[ihel2]O         CH[ihel4]         N[ihel2]O
----------------------------------------------------------------------------------------------------------------
Residual Oil............................  ................  ................  ................            0.0003
Distillate Oil..........................  ................  ................            0.0027            0.0004
Natural Gas.............................            0.0027                    ................            0.0001
Biogas..................................  ................  ................  ................            0.0001
Petroleum coke..........................  ................  ................                NA            \a\ NA
----------------------------------------------------------------------------------------------------------------
\a\ Emission factors for kraft calciners are not available.

Subpart OO--[Amended]

0
48. Section 98.410 is amended by revising paragraph (b) to read as 
follows:


Sec.  98.410  Definition of the source category.

* * * * *
    (b) To produce a fluorinated GHG means to manufacture a fluorinated 
GHG from any raw material or feedstock chemical. Producing a 
fluorinated GHG includes the manufacture of a fluorinated GHG as an 
isolated intermediate for use in a process that will result in its 
transformation either at or outside of the production facility. 
Producing a fluorinated GHG also includes the creation of a fluorinated 
GHG (with the exception of HFC-23) that is captured and shipped off 
site for any reason, including destruction. Producing a fluorinated GHG 
does not include the reuse or recycling of a fluorinated GHG, the 
creation of HFC-23 during the production of HCFC-22, the creation of 
intermediates that are created and transformed in a single process with 
no storage of the intermediates, or the creation of fluorinated GHGs 
that are released or destroyed at the production facility before the 
production measurement at Sec.  98.414(a).
* * * * *

0
49. Section 98.414 is amended by:
0
a. Adding second and third sentences to paragraph (a).
0
b. Revising paragraph (h).
0
c. Removing and reserving paragraph (j).
0
d. Adding new paragraphs (n) through (q).


Sec.  98.414  Monitoring and QA/QC requirements.

    (a) * * * If the measured mass includes more than one fluorinated 
GHG, the concentrations of each of the fluorinated GHGs, other than 
low-concentration constituents, shall be measured as set forth in 
paragraph (n) of this section. For each fluorinated GHG, the mean of 
the concentrations of that fluorinated GHG (mass fraction) measured 
under paragraph (n) of this section shall be multiplied by the mass 
measurement to obtain the mass of that fluorinated GHG coming out of 
the production process.
* * * * *
    (h) You must measure the mass of each fluorinated GHG that is fed 
into the destruction device and that was previously produced as defined 
at Sec.  98.410(b). Such fluorinated GHGs include but are not limited 
to quantities that are shipped to the facility by another facility for 
destruction and quantities that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore destroyed. You must use flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of one percent of full scale or better. If the measured mass 
includes more than trace concentrations of materials other than the 
fluorinated GHG being destroyed, you must estimate the concentrations 
of the fluorinated GHG being destroyed considering current or previous 
representative concentration measurements and other relevant process 
information. You must multiply this concentration (mass fraction) by 
the mass measurement to obtain the mass of the fluorinated GHG fed into 
the destruction device.
* * * * *
    (n) If the mass coming out of the production process includes more 
than one fluorinated GHG, you shall measure the concentrations of all 
of the fluorinated GHGs, other than low-concentration constituents, as 
follows:
    (1) Analytical Methods. Use a quality-assured analytical 
measurement technology capable of detecting the analyte of interest at 
the concentration of interest and use a procedure validated with the 
analyte of interest at the concentration of interest. Where standards 
for the analyte are not available, a chemically similar surrogate may 
be used. Acceptable analytical measurement technologies include but are 
not limited to gas chromatography (GC) with an appropriate detector, 
infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic 
resonance (NMR). Acceptable methods include EPA Method 18 in Appendix 
A-1 of 40 CFR part 60; EPA Method 320 in Appendix A of 40 CFR part 63; 
the Protocol for Measuring Destruction or Removal Efficiency (DRE) of 
Fluorinated Greenhouse Gas Abatement Equipment in Electronics 
Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated 
by reference, see Sec.  98.7); ASTM D6348-03 Standard Test Method for 
Determination of Gaseous Compounds by Extractive Direct Interface 
Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by 
reference, see Sec.  98.7); or other analytical methods validated using 
EPA Method 301 in Appendix A of 40 CFR part 63 or some other 
scientifically sound validation protocol. The validation protocol may 
include analytical technology manufacturer specifications or 
recommendations.
    (2) Documentation in GHG Monitoring Plan. Describe the analytical 
method(s) used under paragraph (n)(1) of this section in the site GHG 
Monitoring Plan as required under Sec.  98.3(g)(5). At a minimum, 
include in the description of the method a description of the 
analytical measurement equipment and procedures, quantitative estimates 
of the method's accuracy and precision for the analytes of interest at 
the concentrations of interest, as well as a description of how these 
accuracies and precisions were estimated, including the validation 
protocol used.
    (3) Frequency of measurement. Perform the measurements at least 
once by February 15, 2011 if the fluorinated GHG product is being 
produced on December 17, 2010. Perform the measurements within 60 days 
of commencing production of any fluorinated GHG product that was not

[[Page 79168]]

being produced on December 17, 2010. Repeat the measurements if an 
operational or process change occurs that could change the identities 
or significantly change the concentrations of the fluorinated GHG 
constituents of the fluorinated GHG product. Complete the repeat 
measurements within 60 days of the operational or process change.
    (4) Measure all product grades. Where a fluorinated GHG is produced 
at more than one purity level (e.g., pharmaceutical grade and 
refrigerant grade), perform the measurements for each purity level.
    (5) Number of samples. Analyze a minimum of three samples of the 
fluorinated GHG product that have been drawn under conditions that are 
representative of the process producing the fluorinated GHG product. If 
the relative standard deviation of the measured concentrations of any 
of the fluorinated GHG constituents (other than low-concentration 
constituents) is greater than or equal to 15 percent, draw and analyze 
enough additional samples to achieve a total of at least six samples of 
the fluorinated GHG product.
    (o) All analytical equipment used to determine the concentration of 
fluorinated GHGs, including but not limited to gas chromatographs and 
associated detectors, IR, FTIR and NMR devices, shall be calibrated at 
a frequency needed to support the type of analysis specified in the 
site GHG Monitoring Plan as required under Sec.  98.414(n) and Sec.  
98.3(g)(5) of this part. Quality assurance samples at the 
concentrations of concern shall be used for the calibration. Such 
quality assurance samples shall consist of or be prepared from 
certified standards of the analytes of concern where available; if not 
available, calibration shall be performed by a method specified in the 
GHG Monitoring Plan.
    (p) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the monitoring requirements of this 
section.
    (q) Low-concentration constituents are exempt from the monitoring 
and QA/QC requirements of this section.

0
50. Section 98.416 is amended by:
0
a. Revising paragraph (a)(3).
0
b. Removing and reserving paragraph (a)(4).
0
c. Revising paragraphs (a)(11) and (a)(15).
0
d. Revising paragraphs (b) introductory text and (b)(1).
0
e. Revising paragraphs (c) introductory text, (c)(1), and (c)(10).
0
f. Revising paragraph (d) introductory text.
0
g. Revising paragraph (e) introductory text.
0
h. Adding paragraphs (f) through (h).


Sec.  98.416  Data reporting requirements.

* * * * *
    (a) * * *
    (3) Mass in metric tons of each fluorinated GHG that is destroyed 
at that facility and that was previously produced as defined at Sec.  
98.410(b). Quantities to be reported under this paragraph (a)(3) of 
this section include but are not limited to quantities that are shipped 
to the facility by another facility for destruction and quantities that 
are returned to the facility for reclamation but are found to be 
irretrievably contaminated and are therefore destroyed.
* * * * *
    (11) Mass in metric tons of each fluorinated GHG that is fed into 
the destruction device and that was previously produced as defined at 
Sec.  98.410(b). Quantities to be reported under this paragraph (a)(11) 
of this section include but are not limited to quantities that are 
shipped to the facility by another facility for destruction and 
quantities that are returned to the facility for reclamation but are 
found to be irretrievably contaminated and are therefore destroyed.
* * * * *
    (15) Names and addresses of facilities to which any fluorinated 
GHGs were sent for destruction, and the quantities (metric tons) of 
each fluorinated GHG that were sent to each for destruction.
* * * * *
    (b) By March 31, 2011 or within 60 days of commencing fluorinated 
GHG destruction, whichever is later, a fluorinated GHG production 
facility or importer that destroys fluorinated GHGs shall submit a one-
time report containing the following information for each destruction 
process:
    (1) Destruction efficiency (DE).
* * * * *
    (c) Each bulk importer of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its imports at the corporate 
level, except for shipments including less than twenty-five kilograms 
of fluorinated GHGs or nitrous oxide, transshipments, and heels that 
meet the conditions set forth at Sec.  98.417(e). The report shall 
contain the following information for each import:
    (1) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG imported in bulk, including each fluorinated GHG constituent of the 
fluorinated GHG product that makes up between 0.5 percent and 100 
percent of the product by mass.
* * * * *
    (10) If applicable, the names and addresses of the persons and 
facilities to which the fluorinated GHGs were sold or transferred for 
destruction, and the quantities (metric tons) of each fluorinated GHG 
that were sold or transferred to each facility for destruction.
    (d) Each bulk exporter of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes its exports at the corporate 
level, except for shipments including less than twenty-five kilograms 
of fluorinated GHGs or nitrous oxide, transshipments, and heels. The 
report shall contain the following information for each export:
* * * * *
    (e) By March 31, 2011, or within 60 days of commencing fluorinated 
GHG production, whichever is later, a fluorinated GHG production 
facility shall submit a one-time report describing the following 
information:
* * * * *
    (f) By March 31, 2011, all fluorinated GHG production facilities 
shall submit a one-time report that includes the concentration of each 
fluorinated GHG constituent in each fluorinated GHG product as measured 
under Sec.  98.414(n). If the facility commences production of a 
fluorinated GHG product that was not included in the initial report or 
performs a repeat measurement under Sec.  98.414(n) that shows that the 
identities or concentrations of the fluorinated GHG constituents of a 
fluorinated GHG product have changed, then the new or changed 
concentrations, as well as the date of the change, must be reflected in 
a revision to the report. The revised report must be submitted to EPA 
by the March 31st that immediately follows the measurement under Sec.  
98.414(n).
    (g) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the reporting requirements of this 
section.
    (h) Low-concentration constituents are exempt from the reporting 
requirements of this section.

0
51. Section 98.417 is amended by revising paragraphs (a)(2), (b), and 
(d)(2); and by adding paragraphs (f) and (g) to read as follows:


Sec.  98.417  Records that must be retained.

    (a) * * *
    (2) Records documenting the initial and periodic calibration of the 
analytical equipment (including but not limited to GC, IR, FTIR, or 
NMR), weigh scales, flowmeters, and volumetric and density measures 
used to measure the quantities reported under this subpart, including 
the manufacturer directions or industry standards used for

[[Page 79169]]

calibration pursuant to Sec.  98.414(m) and (o).
    (b) In addition to the data required by paragraph (a) of this 
section, any fluorinated GHG production facility that destroys 
fluorinated GHGs shall keep records of test reports and other 
information documenting the facility's one-time destruction efficiency 
report in Sec.  98.416(b).
* * * * *
    (d) * * *
    (2) The invoice for the export.
* * * * *
    (f) Isolated intermediates that are produced and transformed at the 
same facility are exempt from the recordkeeping requirements of this 
section.
    (g) Low-concentration constituents are exempt from the 
recordkeeping requirements of this section.

0
52. Section 98.418 is revised to read as follows:


Sec.  98.418  Definitions.

    Except as provided below, all of the terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part. If a conflict exists between a definition provided in this 
subpart and a definition provided in subpart A, the definition in this 
subpart shall take precedence for the reporting requirements in this 
subpart.
    Isolated intermediate means a product of a process that is stored 
before subsequent processing. An isolated intermediate is usually a 
product of chemical synthesis. Storage of an isolated intermediate 
marks the end of a process. Storage occurs at any time the intermediate 
is placed in equipment used solely for storage.
    Low-concentration constituent means, for purposes of fluorinated 
GHG production and export, a fluorinated GHG constituent of a 
fluorinated GHG product that occurs in the product in concentrations 
below 0.1 percent by mass. For purposes of fluorinated GHG import, low-
concentration constituent means a fluorinated GHG constituent of a 
fluorinated GHG product that occurs in the product in concentrations 
below 0.5 percent by mass. Low-concentration constituents do not 
include fluorinated GHGs that are deliberately combined with the 
product (e.g., to affect the performance characteristics of the 
product).

Subpart PP--[Amended]

0
53. Section 98.422 is amended by revising paragraphs (a) and (b) to 
read as follows:


Sec.  98.422  GHGs to report.

    (a) Mass of CO2 captured from production process units.
    (b) Mass of CO2 extracted from CO2 production 
wells.
* * * * *

0
54. Section 98.423 is amended by:
0
a. Revising the first sentence of paragraph (a) introductory text.
0
b. Revising the first sentences of paragraphs (a)(1) and (a)(2).
0
c. Revising the definitions of ``CCO2,p'' and 
``Dp'' in Equation PP-2 in paragraph (a)(2).
0
d. Revising paragraph (a)(3).
0
e. Redesignating paragraph (b) as paragraph (c) and revising newly 
designated paragraph (c).
0
f. Adding paragraph (b).


Sec.  98.423  Calculating CO2 Supply.

    (a) Except as allowed in paragraph (b) of this section, calculate 
the annual mass of CO2 captured, extracted, imported, or 
exported through each flow meter in accordance with the procedures 
specified in either paragraph (a)(1) or (a)(2) of this section. * * *
    (1) For each mass flow meter, you shall calculate quarterly the 
mass of CO2 in a CO2 stream in metric tons by 
multiplying the mass flow by the composition data, according to 
Equation PP-1 of this section. * * *
* * * * *
    (2) For each volumetric flow meter, you shall calculate quarterly 
the mass of CO2 in a CO2 stream in metric tons by 
multiplying the volumetric flow by the concentration and density data, 
according to Equation PP-2 of this section. * * *
* * * * *
CCO2,p = Quarterly CO2 concentration 
measurement in flow for flow meter u in quarter p (measured as 
either volume % CO2 or weight % CO2).
* * * * *
Dp = Density of CO2 in quarter p (metric tons 
CO2 per standard cubic meter) for flow meter u if 
CCO2,p is measured as volume % CO2, or density 
of the whole CO2 stream for flow meter u (metric tons per 
standard cubic meter) if CCO2,p is measured as weight % 
CO2.
* * * * *
    (3) To aggregate data, use either Equation PP-3a or PP-3b in this 
paragraph, as appropriate.
    (i) For facilities with production process units that capture a 
CO2 stream and either measure it after segregation or do not 
segregate the flow, calculate the total CO2 supplied in 
accordance with Equation PP-3a.
[GRAPHIC] [TIFF OMITTED] TR17DE10.012

Where:

CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons) 
through flow meter u.
u = Flow meter.

    (ii) For facilities with production process units that capture a 
CO2 stream and measure it ahead of segregation, calculate 
the total CO2 supplied in accordance with Equation PP-3b.
[GRAPHIC] [TIFF OMITTED] TR17DE10.013

Where:

CO2 = Total annual mass of CO2 (metric tons).
CO2,u = Annual mass of CO2 (metric tons) 
through main flow meter u.
CO2,v = Annual mass of CO2 (metric tons) 
through subsequent flow meter v for use on site.
u = Main flow meter.
v = Subsequent flow meter.

    (b) As an alternative to paragraphs (a)(1) through (3) of this 
section for CO2 that is supplied in containers, calculate 
the annual mass of CO2 supplied in containers delivered by 
each CO2 stream

[[Page 79170]]

in accordance with the procedures specified in either paragraph (b)(1) 
or (b)(2) of this section. If multiple CO2 streams are used 
to deliver CO2 to containers, you shall calculate the annual 
mass of CO2 supplied in containers delivered by all 
CO2 streams according to the procedures specified in 
paragraph (b)(3) of this section.
    (1) For each CO2 stream that delivers CO2 to 
containers, for which mass is measured, you shall calculate 
CO2 supply in containers using Equation PP-1 of this 
section.

Where:

CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
CCO2,p,u = Quarterly CO2 concentration 
measurement of CO2 stream u that delivers CO2 
to containers in quarter p (wt. %CO2).
Qp,u = Quarterly mass of contents supplied in all 
containers delivered by CO2 stream u in quarter p (metric 
tons).
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (2) For each CO2 stream that delivers to containers, for 
which volume is measured, you shall calculate CO2 supply in 
containers using Equation PP-2 of this section.

Where:

CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
CCO2,p = Quarterly CO2 concentration 
measurement of CO2 stream u that delivers CO2 
to containers in quarter p (measured as either volume % 
CO2 or weight % CO2).
Qp = Quarterly volume of contents supplied in all 
containers delivered by CO2 stream u in quarter p 
(standard cubic meters).
Dp = Quarterly CO2 density determination for 
CO2 stream u in quarter p (metric tons per standard cubic 
meter) if CO2,p is measured as volume % 
CO2, or density of CO2 stream u (metric tons 
per standard cubic meter) if CO2,p is measured as weight 
% CO2.
p = Quarter of the year.
u = CO2 stream that delivers to containers.

    (3) To aggregate data, sum the mass of CO2 supplied in 
containers delivered by all CO2 streams in accordance with 
Equation PP-3a of this section.
Where:

CO2 = Annual mass of CO2 (metric tons) 
supplied in containers delivered by all CO2 streams.
CO2,u = Annual mass of CO2 (metric tons) 
supplied in containers delivered by CO2 stream u.
u = CO2 stream that delivers to containers.

    (c) Importers or exporters that import or export CO2 in 
containers shall calculate the total mass of CO2 imported or 
exported in metric tons based on summing the mass in each 
CO2 container using weigh bills, scales, or load cells 
according to Equation PP-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR17DE10.014

Where:

CO2 = Annual mass of CO2 (metric tons).
Q = Annual mass in all CO2 containers imported or 
exported during the reporting year (metric tons).

0
55. Section 98.424 is amended by:
0
a. Revising paragraphs (a)(1), (a)(2), and (a)(5).
0
b. Revising the second sentence of paragraph (b)(2).
0
c. Adding paragraph (c).


Sec.  98.424  Monitoring and QA/QC requirements.

    (a) * * *
    (1) Reporters following the procedures in Sec.  98.423(a) shall 
determine quantity using a flow meter or meters located in accordance 
with this paragraph.
    (i) If the CO2 stream is segregated such that only a 
portion is captured for commercial application or for injection, you 
must locate the flow meter according to the following:
    (A) For reporters following the procedures in Sec.  
98.423(a)(3)(i), you must locate the flow meter(s) after the point of 
segregation.
    (B) For reporters following the procedures in paragraph (a)(3)(ii) 
of Sec.  98.423, you must locate the main flow meter(s) on the captured 
CO2 stream(s) prior to the point of segregation and the 
subsequent flow meter(s) on the CO2 stream(s) for on-site 
use after the point of segregation. You may only follow the procedures 
in paragraph (a)(3)(ii) of Sec.  98.423 if the CO2 stream(s) 
for on-site use is/are the only diversion(s) from the main, captured 
CO2 stream(s) after the main flow meter location(s).
    (ii) Reporters that have a mass flow meter or volumetric flow meter 
installed to measure the flow of a CO2 stream that meets the 
requirements of paragraph (a)(1)(i) of this section shall base 
calculations in Sec.  98.423 of this subpart on the installed mass flow 
or volumetric flow meters.
    (iii) Reporters that do not have a mass flow meter or volumetric 
flow meter installed to measure the flow of the CO2 stream 
that meets the requirements of paragraph (a)(1)(i) of this section 
shall base calculations in Sec.  98.423 of this subpart on the flow of 
gas transferred off site using a mass flow meter or a volumetric flow 
meter located at the point of off-site transfer.
    (2) Reporters following the procedures in paragraph (b) of Sec.  
98.423 shall determine quantity in accordance with this paragraph.
    (i) Reporters that supply CO2 in containers using weigh 
bills, scales, or load cells shall measure the mass of contents of each 
CO2 container to which the CO2 stream is 
delivered, sum the mass of contents supplied in all containers to which 
the CO2 stream is delivered during each quarter, sample the 
CO2 stream delivering CO2 to containers on a 
quarterly basis to determine the composition of the CO2 
stream, and apply Equation PP-1.
    (ii) Reporters that supply CO2 in containers using 
loaded container volumes shall measure the volume of contents of each 
CO2 container to which the CO2 stream is 
delivered, sum the volume of contents supplied in all containers to 
which the CO2 stream is delivered during each quarter, 
sample the CO2 stream on a quarterly basis to determine the 
composition of the CO2 stream, determine the density 
quarterly, and apply Equation PP-2.
* * * * *
    (5) Reporters using Equation PP-2 of this subpart and measuring 
CO2 concentration as weight % CO2 shall determine 
the density of the CO2 stream on a quarterly basis in order 
to calculate the mass of the CO2 stream according to one of 
the following procedures:
    (i) You may use a method published by a consensus-based standards 
organization. Consensus-based standards organizations include, but are 
not limited to, the following: ASTM International (100 Barr Harbor 
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 
(800) 262-1373, http://www.astm.org), the American National Standards 
Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, 
(202) 293-8020, http://www.ansi.org), the American Gas Association 
(AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, 
(202) 824-7000, http://www.aga.org), the American Society of

[[Page 79171]]

Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, 
(800) 843-2763, http://www.asme.org), the American Petroleum Institute 
(API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, 
http://www.api.org), and the North American Energy Standards Board 
(NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-
0060, http://www.api.org). The method(s) used shall be documented in 
the Monitoring Plan required under Sec.  98.3(g)(5).
    (ii) You may follow an industry standard method.
    (b) * * *
    (2) * * * Acceptable methods include, but are not limited to, the 
U.S. Food and Drug Administration food-grade specifications for 
CO2 (see 21 CFR 184.1240) and ASTM standard E1747-95 
(Reapproved 2005) Standard Guide for Purity of Carbon Dioxide Used in 
Supercritical Fluid Applications (ASTM International, 100 Barr Harbor 
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 
(800) 262-1373, http://www.astm.org).
    (c) You shall convert the density of the CO2 stream(s) 
and all measured volumes of carbon dioxide to the following standard 
industry temperature and pressure conditions: Standard cubic meters at 
a temperature of 60 degrees Fahrenheit and at an absolute pressure of 1 
atmosphere. If you apply the density value for CO2 at 
standard conditions, you must use 0.001868 metric tons per standard 
cubic meter.

0
56. Section 98.425 is amended by revising paragraph (a) introductory 
text; and by adding paragraph (d) to read as follows:


Sec.  98.425  Procedures for estimating missing data.

    (a) Whenever the quality assurance procedures in Sec.  98.424(a)(1) 
of this subpart cannot be followed to measure quarterly mass flow or 
volumetric flow of CO2, the most appropriate of the 
following missing data procedures shall be followed:
* * * * *
    (d) Whenever the quality assurance procedures in Sec.  98.424(a)(2) 
of this subpart cannot be followed to measure quarterly quantity of 
CO2 in containers, the most appropriate of the following 
missing data procedures shall be followed:
    (1) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during 
another representative quarter of the current reporting year.
    (2) A quarterly quantity of CO2 in containers that is 
missing may be substituted with a quarterly value measured during the 
same quarter from the past reporting year.
    (3) The quarterly quantity of CO2 in containers recorded 
for purposes of product tracking and billing according to the 
reporter's established procedures may be substituted for any period 
during which measurement equipment is inoperable.

0
57. Section 98.426 is amended by:
0
a. Revising paragraphs (a) introductory text and (a)(2).
0
b. Adding paragraph (a)(5).
0
c. Revising paragraphs (b) introductory text, (b)(2), (b)(3), and 
(b)(4).
0
d. Adding paragraph (b)(7).
0
e. Revising paragraphs (c) and (e)(1).


Sec.  98.426  Data reporting requirements.

* * * * *
    (a) If you use Equation PP-1 of this subpart, report the following 
information for each mass flow meter or CO2 stream that 
delivers CO2 to containers:
* * * * *
    (2) Quarterly mass in metric tons of CO2.
* * * * *
    (5) The location of the flow meter in your process chain in 
relation to the points of CO2 stream capture, dehydration, 
compression, and other processing.
* * * * *
    (b) If you use Equation PP-2 of this subpart, report the following 
information for each volumetric flow meter or CO2 stream 
that delivers CO2 to containers:
* * * * *
    (2) Quarterly volume in standard cubic meters of CO2.
    (3) Quarterly concentration of the CO2 stream in volume 
or weight percent.
    (4) Report density as follows:
    (i) Quarterly density of CO2 in metric tons per standard 
cubic meter if you report the concentration of the CO2 
stream in paragraph (b)(3) of this section in weight percent.
    (ii) Quarterly density of the CO2 stream in metric tons 
per standard cubic meter if you report the concentration of the 
CO2 stream in paragraph (b)(3) of this section in volume 
percent.
* * * * *
    (7) The location of the flow meter in your process chain in 
relation to the points of CO2 stream capture, dehydration, 
compression, and other processing.
    (c) For the aggregated annual mass of CO2 emissions 
calculated using Equation PP-3a or PP-3b, report the following:
    (1) If you use Equation PP-3a of this subpart, report the annual 
CO2 mass in metric tons from all flow meters and 
CO2 streams that deliver CO2 to containers.
    (2) If you use Equation PP-3b of this subpart, report:
    (i) The total annual CO2 mass through main flow meter(s) 
in metric tons.
    (ii) The total annual CO2 mass through subsequent flow 
meter(s) in metric tons.
    (iii) The total annual CO2 mass supplied in metric tons.
    (iv) The location of each flow meter in relation to the point of 
segregation.
* * * * *
    (e) * * *
    (1) The type of equipment used to measure the total flow of the 
CO2 stream or the total mass or volume in CO2 
containers.
* * * * *
[FR Doc. 2010-30286 Filed 12-16-10; 8:45 am]
BILLING CODE 6560-50-P