[Federal Register Volume 74, Number 209 (Friday, October 30, 2009)]
[Rules and Regulations]
[Pages 56260-56519]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-23315]



[[Page 56259]]

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Part II





Environmental Protection Agency





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40 CFR Parts 86, 87, 89 et al.



 Mandatory Reporting of Greenhouse Gases; Final Rule

  Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / 
Rules and Regulations  

[[Page 56260]]


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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 86, 87, 89, 90, 94, 98, 1033, 1039, 1042, 1045, 1048, 
1051, 1054, 1065

[EPA-HQ-OAR-2008-0508; FRL-8963-5]
RIN 2060-A079


Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Final rule.

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SUMMARY: EPA is promulgating a regulation to require reporting of 
greenhouse gas emissions from all sectors of the economy. The final 
rule applies to fossil fuel suppliers and industrial gas suppliers, 
direct greenhouse gas emitters and manufacturers of heavy-duty and off-
road vehicles and engines. The rule does not require control of 
greenhouse gases, rather it requires only that sources above certain 
threshold levels monitor and report emissions.

DATES: The final rule is effective on December 29, 2009. The 
incorporation by reference of certain publications listed in the rule 
is approved by the Director of the Federal Register as of December 29, 
2009.

ADDRESSES: EPA has established a docket for this action under Docket ID 
No. EPA-HQ-OAR-2008-0508. All documents in the docket are listed on the 
www.regulations.gov Web site. 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 www.regulations.gov or in hard copy at EPA's 
Docket Center, Public Reading Room, EPA West Building, Room 3334, 1301 
Constitution Avenue, NW., Washington, DC 20004. 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 Web site www.epa.gov/climatechange/emissions/ghgrulemaking.html. You may also contact the Greenhouse Gas 
Reporting Rule Hotline at telephone number: (877) 444-1188; or e-mail: 
[email protected].

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.''). The final 
rule affects fuel and chemicals suppliers, direct emitters of 
greenhouse gases (GHGs) and manufacturers of mobile sources and 
engines. 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 manufacturing
                                                  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 manufacturing
                                                  facilities.
Iron and Steel Production......          331111  Integrated iron and
                                                  steel mills, steel
                                                  companies, sinter
                                                  plants, blast
                                                  furnaces, basic oxygen
                                                  process furnace shops.
Lead Production................          331419  Primary lead smelting
                                                  and refining
                                                  facilities.
                                         331492  Secondary lead smelting
                                                  and refining
                                                  facilities.
Lime Production................          327410  Calcium oxide, calcium
                                                  hydroxide, dolomitic
                                                  hydrates manufacturing
                                                  facilities.
Nitric Acid Production.........          325311  Nitric acid
                                                  manufacturing
                                                  facilities.
Petrochemical Production.......           32511  Ethylene dichloride
                                                  manufacturing
                                                  facilities.
                                         325199  Acrylonitrile, ethylene
                                                  oxide, methanol
                                                  manufacturing
                                                  facilities.
                                         325110  Ethylene manufacturing
                                                  facilities.

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                                         325182  Carbon black
                                                  manufacturing
                                                  facilities.
Petroleum Refineries...........          324110  Petroleum refineries.
Phosphoric Acid Production.....          325312  Phosphoric acid
                                                  manufacturing
                                                  facilities.
Pulp and Paper Manufacturing...          322110  Pulp mills.
                                         322121  Paper mills.
                                         322130  Paperboard mills.
Silicon Carbide Production.....          327910  Silicon carbide
                                                  abrasives
                                                  manufacturing
                                                  facilities.
Soda Ash Manufacturing.........          325181  Alkalies and chlorine
                                                  manufacturing
                                                  facilities.
                                         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..............          112111  Beef cattle feedlots.
                                         112120  Dairy cattle and milk
                                                  production facilities.
                                         112210  Hog and pig farms.
                                         112310  Chicken egg production
                                                  facilities.
                                         112330  Turkey Production.
                                         112320  Broilers and Other Meat
                                                  type Chicken
                                                  Production.
Suppliers of Coal Based Liquids          211111  Coal liquefaction at
 Fuels.                                           mine sites.
Suppliers of Petroleum Products          324110  Petroleum refineries.
Suppliers of Natural Gas and             221210  Natural gas
 NGLs.                                            distribution
                                                  facilities.
                                         211112  Natural gas liquid
                                                  extraction facilities.
Suppliers of Industrial GHGs...          325120  Industrial gas
                                                  manufacturing
                                                  facilities.
Suppliers of Carbon Dioxide              325120  Industrial gas
 (CO2).                                           manufacturing
                                                  facilities.
Mobile Sources.................          333618  Heavy-duty, non-road,
                                                  aircraft, locomotive,
                                                  and marine diesel
                                                  engine manufacturing.
                                         336120  Heavy-duty vehicle
                                                  manufacturing
                                                  facilities.
                                         336312  Small non-road, and
                                                  marine spark-ignition
                                                  engine manufacturing
                                                  facilities.
                                         336999  Personal watercraft
                                                  manufacturing
                                                  facilities.
                                         336991  Motorcycle
                                                  manufacturing
                                                  facilities.
------------------------------------------------------------------------

    Table 1 of this preamble is not intended to be exhaustive, but 
rather provides a guide for readers regarding facilities likely to be 
affected by this action. Table 1 of this preamble lists the types of 
facilities that EPA is now aware could be potentially affected by the 
reporting requirements. Other types of facilities and suppliers not 
listed in the table could also be subject to reporting requirements. To 
determine whether you are affected by this action, you should carefully 
examine the applicability criteria found in 40 CFR part 98, subpart A 
or the relevant criteria in the sections related to manufacturers of 
heavy-duty and off-road vehicles and engines. If you have questions 
regarding the applicability of this action to a particular facility, 
consult the person listed in the preceding FOR FURTHER INFORMATION 
CONTACT section.
    Many facilities that are affected by the final rule have GHG 
emissions from multiple source categories listed in Table 1 of this 
preamble. Table 2 of this preamble has been developed as a guide to 
help potential reporters subject to the mandatory reporting rule 
identify the source categories (by subpart) that they may need to (1) 
consider in their facility applicability determination, and (2) include 
in their reporting. For each source category, activity, or facility 
type (e.g., electricity generation, aluminum production), Table 2 of 
this preamble identifies the subparts that are likely to be relevant. 
The table should only be seen as a guide. Additional subparts may be 
relevant for a given reporter. Similarly, not all listed subparts are 
relevant for all reporters.

            Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
                                          Other subparts recommended for
  Source category (and main applicable         review to determine
                subpart)                          applicability
------------------------------------------------------------------------
General Stationary Fuel Combustion
 Sources.
Electricity Generation.................  General Stationary Fuel
                                          Combustion, Suppliers of CO2.
Adipic Acid Production.................  General Stationary Fuel
                                          Combustion.
Aluminum Production....................  General Stationary Fuel
                                          Combustion.
Ammonia Manufacturing..................  General Stationary Fuel
                                          Combustion, Hydrogen, Nitric
                                          Acid, Petroleum Refineries,
                                          Suppliers of CO2.
Cement Production......................  General Stationary Fuel
                                          Combustion, Suppliers of CO2.
Ferroalloy Production..................  General Stationary Fuel
                                          Combustion.
Glass Production.......................  General Stationary Fuel
                                          Combustion.
HCFC-22 Production and HFC-23            General Stationary Fuel
 Destruction.                             Combustion.
Hydrogen Production....................  General Stationary Fuel
                                          Combustion, Petrochemicals,
                                          Petroleum Refineries,
                                          Suppliers of Industrial GHGs,
                                          Suppliers of CO2.
Iron and Steel Production..............  General Stationary Fuel
                                          Combustion, Suppliers of CO2.

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Lead Production........................  General Stationary Fuel
                                          Combustion.
Lime Manufacturing.....................  General Stationary Fuel
                                          Combustion.
Nitric Acid Production.................  General Stationary Fuel
                                          Combustion, Adipic Acid.
Petrochemical Production...............  General Stationary Fuel
                                          Combustion, Ammonia, Petroleum
                                          Refineries.
Petroleum Refineries...................  General Stationary Fuel
                                          Combustion, Hydrogen,
                                          Suppliers of Petroleum
                                          Products.
Phosphoric Acid Production.............  General Stationary Fuel
                                          Combustion.
Pulp and Paper Manufacturing...........  General Stationary Fuel
                                          Combustion.
Silicon Carbide Production.............  General Stationary Fuel
                                          Combustion.
Soda Ash Manufacturing.................  General Stationary Fuel
                                          Combustion.
Titanium Dioxide Production............  General Stationary Fuel
                                          Combustion.
Zinc Production........................  General Stationary Fuel
                                          Combustion.
Municipal Solid Waste Landfills........  General Stationary Fuel
                                          Combustion.
Manure Management......................  General Stationary Fuel
                                          Combustion.
Suppliers of Coal-based Liquid Fuels...  Suppliers of Petroleum
                                          Products.
Suppliers of Petroleum Products........  General Stationary Fuel
                                          Combustion.
Suppliers of Natural Gas and NGLs......  General Stationary Fuel
                                          Combustion, Suppliers of CO2.
Suppliers of Industrial GHGs...........  General Stationary Fuel
                                          Combustion, Hydrogen
                                          Production, Suppliers of CO2.
Suppliers of Carbon Dioxide (CO2)......  General Stationary Fuel
                                          Combustion, Electricity
                                          Generation, Ammonia, Cement,
                                          Hydrogen, Iron and Steel,
                                          Suppliers of Industrial GHGs.
Mobile Sources.........................  General Stationary Fuel
                                          Combustion.
------------------------------------------------------------------------

    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 by December 29, 2009. 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. This section also provides a mechanism for us to 
convene a proceeding for reconsideration, ``[i]f the person raising an 
objection can demonstrate to EPA that it was impracticable to raise 
such objection within [the period for public comment] or if the grounds 
for such objection arose after the period for public comment (but 
within the time specified for judicial review) and if such objection is 
of central relevance to the outcome of this 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 20004, 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.

ARP Acid Rain Program
ASME American Society of Mechanical Engineers
ASTM American Society for Testing and Materials
BLS Bureau of Labor Statistics
CAA Clean Air Act
CAFE Corporate Average Fuel Economy
CAIR Clean Air Interstate Rule
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CCS carbon capture and sequestration
CEMS continuous emission monitoring system(s)
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
EAF electric arc furnace
ECOS Environmental Council of the States
EGUs electric generating units
EIA Energy Information Administration
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC-22 chlorodifluoromethane (or CHClF2)
HCFCs hydrochlorofluorocarbons
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
kg kilograms
LDCs local natural gas distribution companies
LMP lime manufacturing plants
mmBtu/hr millions British thermal units per hour
MSW municipal solid waste
MW megawatts
MY mileage year
N2O nitrous oxide
NACAA National Association of Clean Air Agencies
NAICS North American Industry Classification System
NEI National Emissions Inventory
NESHAP national emission standards for hazardous air pollutants
NF3 nitrogen trifluoride
NGLs natural gas liquids
NSPS new source performance standards
NSR New Source Review
NTTAA National Technology Transfer and Advancement Act of 1995
O3 ozone
ODS ozone-depleting substance(s)
OMB Office of Management and Budget
ORIS Office of Regulatory Information Systems
PFCs perfluorocarbons
PIN personal identification number
PSD Prevention of Significant Deterioration
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
R&D research and development
RFA Regulatory Flexibility Act
RGGI Regional Greenhouse Gas Initiative
RICE reciprocating internal combustion engine
RIA regulatory impact analysis
SBREFA Small Business Regulatory Enforcement Fairness Act

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scf standard cubic feet
SF6 sulfur hexafluoride
SIP State Implementation Plan
SOP standard operating procedure
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TRI Toxic Release Inventory
TSD technical support document
U.S. United States
UIC underground injection control
UMRA Unfunded Mandates Reform Act of 1995
UNFCCC United Nations Framework Convention on Climate Change
VMT vehicle miles traveled
VOC volatile organic compound(s)
WBCSD World Business Council for Sustainable Development
WCI Western Climate Initiative
WRI World Resources Institute
XML eXtensible Markup Language

Table of Contents

I. Background
    A. Organization of This Preamble
    B. Background on the Final Rule
    C. Legal Authority
    D. How does this rule relate to EPA and U.S. government climate 
change efforts?
    E. How does this rule relate to State and regional programs?
II. General Requirements of the Rule
    A. Summary of the General Requirements of the Final Rule
    B. Summary of the Major Changes Since Proposal
    C. Summary of Comments and Responses on GHGs To Report
    D. Summary of Comments and Responses on Source Categories To 
Report
    E. Summary of Comments and Responses on Thresholds
    F. Summary of Comments and Responses on Level of Reporting
    G. Summary of Comments and Responses on Initial Reporting Year 
and Best Available Monitoring Methods
    H. Summary of Comments and Responses on Frequency of Reporting 
and Provisions To Cease Reporting
    I. Summary of Comments and Responses on General Content of the 
Annual GHG Report
    J. Summary of Comments and Responses on Submittal Date and 
Making Corrections to Annual Reports
    K. Summary of Comments and Responses on De Minimis Reporting
    L. Summary of Comments and Responses on General Monitoring 
Requirements
    M. Summary of Comments and Responses on General Recordkeeping 
Requirements
    N. Summary of Comments and Responses on Emissions Verification 
Approach
    O. Summary of Comments and Responses on the Role of States and 
Relationship of This Rule to Other Programs
    P. Summary of Comments and Responses on Other General Rule 
Requirements
    Q. Summary of Comments and Responses on Statutory Authority
    R. Summary of Comments and Responses on CBI
    S. Summary of Comments and Responses on Other Legal Issues
III. Reporting and Recordkeeping Requirements for Specific Source 
Categories
    A. Overview
    B. Electricity Purchases
    C. General Stationary Fuel Combustion Sources
    D. Electricity Generation
    E. Adipic Acid Production
    F. Aluminum Production
    G. Ammonia Manufacturing
    H. Cement Production
    I. Electronics Manufacturing
    J. Ethanol Production
    K. Ferroalloy Production
    L. Fluorinated GHG Production
    M. Food Processing
    N. Glass Production
    O. HCFC-22 Production and HFC-23 Destruction
    P. Hydrogen Production
    Q. Iron and Steel Production
    R. Lead Production
    S. Lime Manufacturing
    T. Magnesium Production
    U. Miscellaneous Uses of Carbonates
    V. Nitric Acid Production
    W. Oil and Natural Gas Systems
    X. Petrochemical Production
    Y. Petroleum Refineries
    Z. Phosphoric Acid Production
    AA. Pulp and Paper Manufacturing
    BB. Silicon Carbide Production
    CC. Soda Ash Manufacturing
    DD. Sulfur Hexafluoride (SF6) from Electrical 
Equipment
    EE. Titanium Dioxide Production
    FF. Underground Coal Mines
    GG. Zinc Production
    HH. Municipal Solid Waste Landfills
    II. Wastewater Treatment
    JJ. Manure Management
    KK. Suppliers of Coal
    LL. Suppliers of Coal-Based Liquid Fuels
    MM. Suppliers of Petroleum Products
    NN. Suppliers of Natural Gas and Natural Gas Liquids
    OO. Suppliers of Industrial GHGs
    PP. Suppliers of Carbon Dioxide (CO2)
IV. Mobile Sources
    A. Summary of Requirements of the Final Rule
    B. Summary of Changes Since Proposal
    C. Summary of Comments and Responses
V. Collection, Management, and Dissemination of GHG Emissions Data
    A. Summary of Data Collection, Management and Dissemination for 
the Final Rule
    B. Summary of Comments and Responses on Collection, Management, 
and Dissemination of GHG Emissions Data
VI. Compliance and Enforcement
    A. Compliance and Enforcement Summary
    B. Summary of Public Comments and Responses on Compliance and 
Enforcement
VII. Economic Impacts of the Rule
    A. How were compliance costs estimated?
    B. What are the costs of the rule?
    C. What are the economic impacts of the rule?
    D. What are the impacts of the rule on small businesses?
    E. What are the benefits of the rule for society?
VIII. 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. Organization of This Preamble

    This preamble is broken into several large sections, as detailed 
above in the Table of Contents. The paragraphs below describe the 
layout of the preamble and provide a brief summary of each section.
    The first section of this preamble contains the basic background 
information about the origin of this rule, our legal authority, and how 
this proposal relates to other Federal, State, and regional efforts to 
address emissions of GHGs.
    The second section of this preamble summarizes the general 
provisions of the final GHG reporting rule and identifies the major 
changes since proposal. It also provides a brief summary of public 
comments and responses on key design elements such as: (i) Source 
categories included, (ii) the level of reporting, (iii) applicability 
thresholds, (iv) selection of reporting and monitoring methods, (v) 
emissions verification, (vi) frequency of reporting and (vii) duration 
of reporting. It also addresses some of the legal comments on the 
statutory authority for the rule and the relationship of this rule to 
other CAA programs.
    The third section of this preamble contains separate subsections 
addressing each individual source category of the proposed rule. Each 
source category section contains a summary of specific requirements of 
the rule for that source category, identifies major changes since 
proposal, and briefly discusses public comments and EPA responses 
specific to the source category. For example, comments on EPA's general 
approach for selecting monitoring methods are discussed in Section II 
of this preamble, whereas,

[[Page 56264]]

comments on specific monitoring methods for individual source 
categories are discussed in Section III of this preamble.
    The fourth section of this preamble summarizes rule requirements 
and addresses public comments pertaining to mobile sources.
    The fifth section of this preamble explains how EPA plans to 
collect, manage and disseminate the data, while the sixth section 
describes the approach to compliance and enforcement. In both sections 
key public comments are summarized and responses are presented.
    The seventh section provides the summary of the cost impacts, 
economic impacts, and benefits of the final rule and discusses comments 
on the regulatory impacts analyses. Finally, the last section discusses 
the various statutory and executive order requirements applicable to 
this rulemaking.

B. Background on the Final Rule

    The fiscal year 2008 (FY2008) Consolidated Appropriations Act, 
signed on December 26, 2007, authorized funding for EPA to ``develop 
and publish a draft rule not later than nine months after the date of 
enactment of [the] Act, and a final rule not later than 18 months after 
the date of enactment of [the] Act, to require mandatory reporting of 
greenhouse gas emissions above appropriate thresholds in all sectors of 
the economy of the United States.'' Consolidated Appropriations Act, 
2008, Public Law 110-161, 121 Stat. 1844, 2128 (2008).
    The accompanying joint explanatory statement directed EPA to ``use 
its existing authority under the Clean Air Act'' to develop a mandatory 
GHG reporting rule. ``The Agency is further directed to include in its 
rule reporting of emissions resulting from upstream production and 
downstream sources, to the extent that the Administrator deems it 
appropriate.'' EPA interpreted that language to confirm that it was 
appropriate for the Agency to exercise its CAA authority to develop 
this rulemaking. The joint explanatory statement further states that 
``[t]he Administrator shall determine appropriate thresholds of 
emissions above which reporting is required, and how frequently reports 
shall be submitted to EPA. The Administrator shall have discretion to 
use existing reporting requirements for electric generating units 
(EGUs)'' under section 821 of the 1990 CAA Amendments.
    On April 10, 2009 (74 FR 16448), EPA proposed the GHG reporting 
rule. EPA held two public hearings, and received approximately 16,800 
written public comments. The public comment period ended on June 9, 
2009.
    In addition to the public hearings, EPA had an open door policy, 
similar to the outreach conducted during the development of the 
proposal. As a result, EPA has met with over 4,000 people and 135 
groups since proposal signature (March 10, 2009). Details of these 
meetings are available in the docket (EPA-HQ-OAR-2008-0508).
    EPA developed this final rule and included reporting of GHGs from 
the facilities that we determined appropriately responded to the 
direction in the FY2008 Consolidated Appropriations Act \1\ (e.g., 
capturing approximately 85 percent of U.S. GHG emissions through 
reporting by direct emitters as well as suppliers of fossil fuels and 
industrial gases and manufacturers of heavy-duty and off-road vehicles 
and engines). There are, however, many additional types of data and 
reporting that the Agency deems important and necessary to address an 
issue as large and complex as climate change (e.g., indirect emissions, 
electricity use). In that sense, one could view this final rule as 
narrowly focused on certain sources of emissions and upstream 
suppliers. As described in Sections I.C and D of this preamble as well 
as in the comment response sections, there are several existing 
programs at the Federal, regional and State levels that also collect 
valuable information to inform and implement policies necessary to 
address climate change. Many of these programs are focused on cost-
effectively reducing GHG emissions through improvements in energy 
efficiency and by other means. These programs are an essential 
component of the Nation's climate policy, and the targeted nature of 
this rule should not be interpreted to mean that the data EPA collects 
through this program are the only data necessary to support the full 
range of climate policies and programs.
---------------------------------------------------------------------------

    \1\ Consolidated Appropriations Act, 2008, Public Law 110-161, 
121 Stat. 1844, 2128. Congress reaffirmed interest in a GHG 
reporting rule, and provided additional funding, in the 2009 
Appropriations Act (Consolidated Appropriations Act, 2009, Public 
Law 110-329, 122 Stat. 3574-3716).
---------------------------------------------------------------------------

    Today's rule requires the reporting of the GHG emissions that could 
result from the combustion or use of fossil fuel or industrial gas that 
is produced or imported from upstream sources such as fuel suppliers, 
as well as reporting of GHG emissions directly emitted from facilities 
(downstream sources) through their processes and/or from fuel 
combustion, as appropriate. Vehicle and engine manufacturers are also 
required to report emissions rate data on the heavy-duty and off-road 
engines they produce. The rule also establishes appropriate thresholds 
and frequency for reporting.
    The rule requires reporting of annual emissions of carbon dioxide 
(CO2), methane (CH4), nitrous oxide 
(N2O), sulfur hexafluoride (SF6), 
hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), and other 
fluorinated gases (e.g., nitrogen trifluoride (NF3) and 
hydrofluorinated ethers (HFEs)). It also includes provisions to ensure 
the accuracy of emissions data through monitoring, recordkeeping and 
verification requirements. The rule applies to certain downstream 
facilities that emit GHGs (primarily large facilities emitting 25,000 
metric tons or more of CO2 equivalent (CO2e) GHG 
emissions per year) and to most upstream suppliers of fossil fuels and 
industrial GHGs, as well as to manufacturers of vehicles and engines. 
Reporting is at the facility level, except certain suppliers and 
vehicle and engine manufacturers report at the corporate level.

C. Legal Authority

    As proposed, EPA is promulgating this rule under its existing CAA 
authority, specifically authorities provided in CAA sections 114 and 
208. As discussed further below and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues'', we 
are not citing the FY 2008 Consolidated Appropriations Act as the 
statutory basis for this action. While that law required that EPA spend 
no less than $3.5 million on a rule requiring the mandatory reporting 
of GHG emissions, it is the CAA, not the Appropriations Act, that EPA 
is citing as the authority to gather the information required by this 
rule.
    Sections 114 and 208 of the CAA provide EPA broad authority to 
require the information mandated by this rule because such data will 
inform and are relevant to EPA's carrying out a wide variety of CAA 
provisions. As discussed in the proposed rule, CAA section 114(a)(1) 
authorizes the Administrator to require emissions sources, persons 
subject to the CAA, or persons whom the Administrator believes may have 
necessary information to monitor and report emissions and provide such 
other information the Administrator requests for the purposes of 
carrying out any provision of the CAA (except for a provision of title 
II with respect to manufacturers of new motor vehicles or

[[Page 56265]]

new motor vehicle engines).\2\ Section 208 of the CAA provides EPA with 
similar broad authority regarding the manufacturers of new motor 
vehicles or new motor vehicle engines, and other persons subject to the 
requirements of parts A and C of title II. We note that while climate 
change legislation approved by the U.S. House of Representatives would 
provide EPA additional authority for a GHG registry similar to today's 
rule, and would do so for purposes of that pending legislation, this 
final rule is authorized by, and the information being gathered by the 
rule is relevant to implementing, the existing CAA. We expect, however, 
that the information collected by this final rule will also prove 
useful to legislative efforts to address GHG emissions.
---------------------------------------------------------------------------

    \2\ Although there are exclusions in CAA section 114(a)(1) 
regarding certain title II requirements applicable to manufacturers 
of new motor vehicle and motor vehicle engines, CAA section 208 
authorizes the gathering of information related to those areas.
---------------------------------------------------------------------------

    As discussed in the proposal, emissions from direct emitters should 
inform decisions about whether and how to use CAA section 111 to 
establish new source performance standards (NSPS) for various source 
categories emitting GHGs, including whether there are any additional 
categories of sources that should be listed under CAA section 111(b). 
Similarly, the information required of manufacturers of mobile sources 
should support decisions regarding treatment of those sources under CAA 
sections 202, 213 or 231. In addition, the information from fuel 
suppliers would be relevant in analyzing whether to proceed, and 
particular options for how to proceed, under CAA section 211(c) 
regarding fuels, or to inform action concerning downstream sources 
under a variety of Title I or Title II provisions. The data overall 
also would inform EPA's implementation of CAA section 103(g) regarding 
improvements in non-regulatory strategies and technologies for 
preventing or reducing air pollutants (e.g., EPA's voluntary GHG 
reduction programs such as the non-CO2 partnership programs 
and ENERGY STAR, described below in Section I.D of this preamble and 
Section II of the proposal preamble (74 FR 16448, April 10, 2009)).

D. How does this rule relate to EPA and U.S. government climate change 
efforts?

    This reporting rule is one specific action EPA has taken, 
consistent with the Congressional request contained in the FY2008 
Consolidated Appropriations Act, to collect GHG emissions data. EPA has 
recently announced a number of climate change related actions, 
including proposed findings that GHG emissions from new motor vehicles 
and engines contribute to air pollution which may reasonably be 
anticipated to endanger public health and welfare (74 FR 18886, April 
24, 2009, ``Proposed Endangerment and Cause or Contribute Findings for 
Greenhouse Gases Under Section 202(a) of the Clean Air Act''), and an 
intent to regulate light duty vehicles, jointly published with U.S. 
Department of Transportation (DOT) (74 FR 24007, May 22, 2009, ``Notice 
of Upcoming Joint Rulemaking To Establish Vehicle GHG Emissions and 
CAFE Standards''). The Administrator has also announced her 
reconsideration of the memo entitled ``EPA's Interpretation of 
Regulations that Determine Pollutants Covered By Federal Prevention of 
Significant Deterioration (PSD) Permit Program'' (73 FR 80300, December 
31, 2008), and granted California's request for a waiver for its GHG 
vehicle standard (74 FR 32744, July 8, 2009). These are all separate 
actions, some of which are related to EPA's response to the U.S. 
Supreme Court's decision in Massachusetts v. EPA. 127 S. Ct. 1438 
(2007). This rulemaking does not indicate EPA has made any final 
decisions on pending actions. In fact the mandatory GHG reporting 
program will provide EPA, other government agencies, and outside 
stakeholders with economy-wide data on facility-level (and in some 
cases corporate-level) GHG emissions, which should assist in future 
policy development.
    Accurate and timely information on GHG emissions is essential for 
informing many future climate change policy decisions. Although 
additional data collection (e.g., for other source categories or to 
support additional policy or program needs) will no doubt be required 
as the development of climate policies evolves, the data collected in 
this rule will provide useful information for a variety of polices. 
Through data collected under this rule, EPA, States and the public will 
gain a better understanding of the relative emissions of specific 
industries across the nation and the distribution of emissions from 
individual facilities within those industries. The facility-specific 
data will also improve our understanding of the factors that influence 
GHG emission rates and actions that facilities could in the future or 
already take to reduce emissions, including under traditional and more 
flexible programs.
    As discussed in more detail in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Legal Issues'' and elsewhere, 
EPA is promulgating this rule to gather GHG information to assist EPA 
in assessing how to address GHG emissions and climate change under the 
Clean Air Act. However, we expect that the information will prove 
useful for other purposes as well. For example, using the rich data set 
provided by this rulemaking, EPA, States and the public will be able to 
track emission trends from industries and facilities within industries 
over time, particularly in response to policies and potential 
regulations. The data collected by this rule will also improve the U.S. 
government's ability to formulate climate policies, and to assess which 
industries might be affected, and how these industries might be 
affected by potential policies. Finally, EPA's experience with other 
reporting programs is that such programs raise awareness of emissions 
among reporters and other stakeholders, and thus contribute to efforts 
to identify and implement emission reduction opportunities. These data 
can also be coupled with efforts at the local, State and Federal levels 
to assist corporations and facilities in determining their GHG 
footprints and identifying opportunities to reduce emissions (e.g., 
through energy audits or other forms of assistance).
    This GHG reporting program supplements and complements, rather than 
duplicates, existing U.S. government programs (e.g., climate policy and 
research programs). For example, EPA anticipates that facility-level 
GHG emissions data will lead to improvements in the quality of the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory), which 
EPA prepares annually, with input from several other agencies, and 
submits to the Secretariat of the United Nations Framework Convention 
on Climate Change (UNFCCC).
    A number of EPA voluntary partnership programs include a GHG 
emissions and/or reductions reporting component (e.g., Climate Leaders, 
the Natural Gas STAR program, Energy Star). This mandatory reporting 
program has broader coverage of U.S. GHG emissions than most voluntary 
programs, which typically focus on a specific industry and/or goal 
(e.g., reduction of CH4 emissions or development of 
corporate inventories). It will improve EPA's understanding of 
emissions from facilities not currently included in these programs and 
increase the coverage of these industries. That said, we expect ongoing 
and potential new voluntary programs to continue to

[[Page 56266]]

play an important role in achieving low-cost reductions in GHG 
emissions.
    In addition to EPA's programs mentioned above, U.S. Department of 
Energy (DOE) EIA implements a voluntary GHG registry under section 
1605(b) of the Energy Policy Act, which is further discussed in Section 
II of the proposal preamble (74 FR 16458, April 10, 2009). Under EIA's 
``1605(b) program,'' reporters can choose to prepare an entity-wide GHG 
inventory and identify specific GHG reductions made by the entity.\3\ 
EPA's mandatory GHG reporting rule covers a much broader set of 
reporters, primarily at the facility rather than entity-level, but this 
reporting rule is not designed with the specific intent of reporting of 
emission reductions, as is the 1605(b) program.
    For additional information about these programs, please see 
Sections I and II of the preamble to the proposed GHG reporting rule 
(74 FR 16454, April 10, 2009).
---------------------------------------------------------------------------

    \3\ Under the 1605(b) program an ``entity'' is defined as ``the 
whole or part of any business, institution, organization or 
household that is recognized as an entity under any U.S. Federal, 
State or local law that applies to it; is located, at least in part, 
in the U.S.; and whose operations affect U.S. greenhouse gas 
emissions.'' (http://www.pi.energy.gov/enhancingGHGregistry/)
---------------------------------------------------------------------------

E. How does this rule relate to other State and Regional Programs?

    There are several existing State and regional GHG reporting and/or 
reduction programs summarized in Section II of the proposal preamble 
(74 FR 16457, April 10, 2009). These are important programs that not 
only led the way in reporting of GHG emissions before the Federal 
government acted but also assist in quantifying the GHG reductions 
achieved by various policies. Many of these programs collect different 
or additional data as compared to this rule. For example, State 
programs may establish lower thresholds for reporting or request 
information on areas not addressed in EPA's reporting rule (e.g., 
electricity use or emission related to other indirect sources). States 
collecting additional information have determined that these data are 
necessary to implement their specific climate policies and programs. 
EPA agrees that State and regional programs are crucial to achieving 
emissions reductions, and this rule does not preempt any other 
programs.
    EPA's GHG reporting rule is a specific single action that was 
developed in response to the Appropriations Act, and therefore is 
targeted to accomplish the purpose of the language of the 
Appropriations Act and serve EPA's purposes under the CAA. As State 
experience has demonstrated, we recognize that in order to address the 
breadth of climate change issues there will likely be a need to collect 
additional data from sources subject to this rule as well as other 
sources. The timing and nature of these additional needs will be 
dependent on the types of programs and actions the Agency has underway 
or may develop and implement in response to future policy developments 
and/or new requests from Congress. Addressing climate change will 
require a suite of policies and programs and this reporting rule is 
just one effort to collect information to inform those policies.
    EPA is committed to working with State and regional programs to 
coordinate implementation of reporting programs, reduce burden on 
reporters, provide timely access to verified emissions data, establish 
mechanisms to efficiently share data, and harmonize data systems to the 
extent possible. See Section II.O of this preamble for a summary of 
public comments and responses on the role of States and the 
relationship of this GHG reporting rule to other programs. See Section 
VI.B of this preamble for a summary of comments and responses on State 
delegation of rule implementation and enforcement. As mentioned above, 
for additional information about existing State and regional programs 
please see Section II of the proposal preamble (74 FR 16457, April 10, 
2009) and the docket EPA-HQ-OAR-2008-0508.

II. General Requirements of the Rule

    The rule requires reporting of annual emissions of CO2, 
CH4, N2O, SF6, HFCs, PFCs, and other 
fluorinated gases (as defined in 40 CFR part 98, subpart A) in metric 
tons. The final 40 CFR part 98 applies to certain downstream facilities 
that emit GHGs, and to certain upstream suppliers of fossil fuels and 
industrial GHGs. For suppliers, the GHG emissions reported are the 
emissions that would result from combustion or use of the products 
supplied. The rule also includes provisions to ensure the accuracy of 
emissions data through monitoring, recordkeeping and verification 
requirements. Reporting is at the facility \4\ level, except that 
certain suppliers of fossil fuels and industrial gases would report at 
the corporate level.
---------------------------------------------------------------------------

    \4\ For the purposes of this rule, facility means any physical 
property, plant, building, structure, source, or stationary 
equipment located on one or more contiguous or adjacent properties 
in actual physical contact or separated solely by a public roadway 
or other public right-of-way and under common ownership or common 
control, that emits or may emit any greenhouse gas. Operators of 
military installations may classify such installations as more than 
a single facility based on distinct and independent functional 
groupings within contiguous military properties.
---------------------------------------------------------------------------

    In addition, GHG reporting by manufacturers of heavy-duty and off-
road vehicles and engines is required, by incorporating new 
requirements into the existing reporting requirements for motor 
vehicles and engine manufacturers in 40 CFR parts 86, 87, 89, 90, 94, 
1033, 1039, 1042, 1045, 1048, 1051, 1054, and 1065. A summary of the 
reporting requirements for manufacturers of motor vehicles and engines 
is contained in Section IV of this preamble. A discussion of public 
comments and responses that pertain to motor vehicles is also contained 
in Section IV of this preamble and in the ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Motor Vehicle and 
Engine Manufacturers.''
    The remainder of this section summarizes the general provisions of 
40 CFR part 98, identifies changes since the proposed rule, and 
summarizes key public comments and responses on the general 
requirements of the rule.

A. Summary of the General Requirements of the Final Rule

1. Applicability
    Reporters must submit annual GHG reports for the following 
facilities and supply operations.
     Any facility that contains any source category (as defined 
in 40 CFR part 98, subparts C through JJ) that is listed below in any 
calendar year starting in 2010.\5\ For these facilities, the annual GHG 
report covers all source categories and GHGs for which calculation 
methodologies are provided in 40 CFR part 98, subparts C through JJ.
---------------------------------------------------------------------------

    \5\ Unless otherwise noted, years and dates in this notice refer 
to calendar years and dates.

--Electricity generating facilities that are subject to the Acid Rain 
Program (ARP) or otherwise report CO2 mass emissions year-
round through 40 CFR part 75.
--Adipic acid production.
--Aluminum production.
--Ammonia manufacturing.
--Cement production.
--HCFC-22 production.
--HFC-23 destruction processes that are not co-located with a HCFC-22 
production facility and that destroy more than 2.14 metric tons of HFC-
23 per year.
--Lime manufacturing.
--Nitric acid production.
--Petrochemical production.
--Petroleum refineries.

[[Page 56267]]

--Phosphoric acid production.
--Silicon carbide production.
--Soda ash production.
--Titanium dioxide production.
--Municipal solid waste (MSW) landfills that generate CH4 in 
amounts equivalent to 25,000 metric tons CO2e or more per 
year, as determined according to 40 CFR part 98, subpart HH.
--Manure management systems that emit CH4 and N20 
(combined) in amounts equivalent to 25,000 metric tons CO2e 
or more per year, as determined according to 40 CFR part 98, subpart 
JJ.

     Any facility that contains any source category (as defined 
in 40 CFR part 98, subparts C through JJ) that is listed below and that 
emits 25,000 metric tons CO2e or more per year in combined 
emissions from stationary fuel combustion units, miscellaneous use of 
carbonates and all of the source categories listed in this paragraph in 
any calendar year starting in 2010. For these facilities, the annual 
GHG report must cover all source categories and GHGs for which 
calculation methodologies are provided in 40 CFR part 98, subparts C 
through JJ.

--Ferroalloy Production.
--Glass Production.
--Hydrogen Production.
--Iron and Steel Production.
--Lead Production.
--Pulp and Paper Manufacturing.
--Zinc Production.

     Any facility that in any calendar year starting in 2010 
meets all three of the conditions listed in this paragraph. For these 
facilities, the annual GHG report covers emissions from stationary fuel 
combustion sources only. For 2010 only, the facilities can submit an 
abbreviated GHG report according to 40 CFR 98.3(d).

--The facility does not meet the requirements described in the above 
two paragraphs;
--The aggregate maximum rated heat input capacity of the stationary 
fuel combustion units at the facility is 30 million British thermal 
units per hour (mmBtu/hr) or greater; and
--The facility emits 25,000 metric tons CO2e or more per 
year from all stationary fuel combustion sources.\6\
---------------------------------------------------------------------------

    \6\ This does not include portable equipment, emergency 
generators, or emergency equipment as defined in the rule.

     Any supplier (as defined in 40 CFR part 98, subparts LL 
through PP) of any of the products as listed below in any calendar year 
starting in 2010. For these suppliers, the annual GHG report covers all 
applicable products for which calculation methodologies are provided in 
---------------------------------------------------------------------------
40 CFR part 98, subparts KK through PP.

--Coal-based liquid fuels: All producers of coal-to-liquid fuels; 
importers and exporters of coal-to-liquid fuels with annual imports or 
annual exports that are equivalent to 25,000 metric tons 
CO2e or more per year.
--Petroleum products: All petroleum refiners that distill crude oil; 
importers and exporters of petroleum products with annual imports or 
annual exports that are equivalent to 25,000 metric tons 
CO2e or more per year.
--Natural gas and natural gas liquids (NGLs): All natural gas 
fractionators and all local natural gas distribution companies (LDCs).
--Industrial GHGs: All producers of industrial GHGs; importers and 
exporters of industrial GHGs with annual bulk imports or exports of 
N2O, fluorinated GHGs, and CO2 that in 
combination are equivalent to 25,000 metric tons CO2e or 
more per year.

--CO2: All producers of CO2; importers and exporters of 
CO2 with annual bulk imports or exports of N2O, 
fluorinated GHGs, and CO2 that in combination are equivalent 
to 25,000 metric tons CO2e or more per year.

     Research and development activities (as defined in 40 CFR 
98.6) are not considered to be part of any source category subject to 
the rule.
    It is important to note that the applicability criteria apply to a 
facility's annual emissions or a supplier's annual quantity of product 
supplied.\7\ For example, while a facility's emissions may be below 
25,000 metric tons CO2e in January, if the cumulative 
emissions for the calendar year are 25,000 metric tons CO2e 
or more at the end of December, the rule applies and the reporter must 
submit an annual GHG report for that facility. Therefore, it is in a 
facility's or supplier's interest to collect the GHG data required by 
the rule if they think they will meet or exceed the applicability 
criteria in 40 CFR 98.2 by the end of the year. EPA plans to have tools 
and guidance available to assist potential reporters in assessing 
whether the rule applies to their facilities or supply operations.
---------------------------------------------------------------------------

    \7\ Supplied means produced, imported, or exported.
---------------------------------------------------------------------------

2. Schedule for Reporting
    Reporters must begin collecting data on January 1, 2010. The first 
annual GHG report is due on March 31, 2011, for GHGs emitted or 
products supplied during 2010. For a portion of 2010, the rule allows 
reporters to use best available monitoring methods for parameters that 
cannot reasonably be measured according to the monitoring and quality 
assurance/quality control (QA/QC) requirements of the relevant subpart 
as described in Sections II.A.3 and II.G of this preamble.
    Reports are submitted annually. For EGUs that are subject to the 
ARP, reporters must continue to report CO2 mass emissions 
quarterly, as required by the ARP, in addition to providing annual GHG 
reports under this rule. Reporters must submit GHG data on an ongoing, 
annual basis. The snapshot of information provided by a one-time 
information collection request (ICR) would not provide the type of 
ongoing information which could inform the variety of potential CAA 
policy options being evaluated for addressing climate change.
    Once subject to this reporting rule, reporters must continue to 
submit GHG reports annually. A reporter can cease reporting if the 
required annual GHG reports demonstrate that reported GHG emissions are 
either (1) less than 25,000 metric tons of CO2e per year for 
five consecutive years or (2) less than 15,000 metric tons of 
CO2e per year for three consecutive years. The reporter must 
notify EPA that they intend to cease reporting and explain the reasons 
for the reduction in emissions. This provision applies to all 
facilities and suppliers subject to the rule, regardless of their 
applicability category (i.e., whether rule applicability was initially 
triggered by an ``all-in'' source category or a source category with a 
25,000 metric tons CO2e threshold). The reporter must keep 
records for all five consecutive years in which emissions were less 
than 25,000 metric tons per year, or all three consecutive years in 
which emissions were less than 15,000 metric tons per year, as 
appropriate. If GHG emissions (or quantities in products supplied) 
subsequently increase to 25,000 metric tons CO2e in any 
calendar year, the reporter must again begin annual reporting. The rule 
also contains a provision to allow facilities and suppliers to notify 
EPA and stop reporting if they close all GHG-emitting processes and 
operations covered by the rule.
    If reporters discover or are notified by EPA of errors in an annual 
GHG report, they must submit a revised GHG report within 45 days.
3. What has to be included in the annual GHG report?
    Reporters must include the following information in each annual GHG 
report:

[[Page 56268]]

     Facility name or supplier name (as appropriate) and 
physical street address including the city, State, and zip code.
     Year and months covered by the report, and date of report 
submittal.
     For facilities that directly emit GHG:

--Annual facility emissions (excluding biogenic CO2), 
expressed in metric tons of CO2e per year, aggregated for 
all GHG from all source categories in 40 CFR part 98, subparts C 
through JJ that are located at the facility.
--Annual emissions of biogenic CO2 (i.e., CO2 
from combustion of biomass) aggregated for all applicable source 
categories in subparts C through JJ located at the facility.
--Annual GHG emissions for each of the source categories located at the 
facility, by gas. Gases are: CO2 (excluding biogenic 
CO2), biogenic CO2, CH4, 
N2O, and each fluorinated GHG.
--Within each source category, emissions broken out at the level 
specified in the respective subpart (e.g., some source categories 
require reporting for each individual unit or each process line).
--Additional data specified in the applicable subparts for each source 
category. This includes activity data (e.g., fuel use, feedstock 
inputs) that were used to generate the emissions data and additional 
data to support QA/QC and emissions verification.
--Total pounds of synthetic fertilizer produced through nitric acid or 
ammonia production and total nitrogen contained in that fertilizer.

     For suppliers: \8\
---------------------------------------------------------------------------

    \8\ Suppliers include producers, importers, and exporters of 
fuels and industrial gases. The level of reporting for suppliers is 
specified in the rule. Most report at the facility level. Imports 
and exports are reported at the corporate level.

--Annual quantities of each GHG that would be emitted from combustion 
or use \9\ of the products supplied, imported, or exported during the 
year. Report this for each applicable supply category in 40 CFR part 98 
subparts KK through PP, by gas. Also report the total quantity, 
expressed in metric tons of CO2e, aggregated for all GHGs 
from all applicable supply categories.
---------------------------------------------------------------------------

    \9\ ``Use'' for purposes of industrial GHGs presumes that there 
will be 100 percent release of the GHG.
---------------------------------------------------------------------------

--Additional data specified in the applicable subparts for each supply 
category. This includes data used to calculate GHG quantities or needed 
to support QA/QC and verification.

     A written explanation if the reporter changes GHG 
calculation methodologies during the reporting period.
     If best available monitoring methods were used for part of 
calendar year 2010, a brief description of the methods used.
     Each data element for which a missing data procedure was 
used according to the procedures of an applicable subpart and the total 
number of hours in the year that a missing data procedure was used for 
each data element.
     A signed and dated certification statement provided by the 
Designated Representative of the owner or operator.
    Note that in some cases, the same facility is subject to the rule 
requirements for direct emitters as well as for suppliers. For example, 
petroleum refineries are suppliers of petroleum products (40 CFR part 
98, subpart NN) and also directly emit GHGs from petroleum refining (40 
CFR part 98, subpart Y), general stationary fuel combustion (40 CFR 
part 98, subpart C), and possibly other source categories located at a 
refinery. In such cases, reporters must report the information in both 
the facility and supplier bullets listed above.
    EPA will protect any information claimed as CBI in accordance with 
regulations in 40 CFR part 2, subpart B. However, note that in general, 
emission data collected under CAA sections 114 and 208 shall be 
available to the public and cannot be withheld as CBI.\10\
---------------------------------------------------------------------------

    \10\ Although CBI determinations are usually made on a case-by-
case basis, EPA has discussed in an earlier Federal Register notice 
what constitutes emissions data that cannot be withheld as CBI (956 
FR 7042-7043, February 21, 1991). In addition, as discussed in 
Section II.R of this preamble, EPA will be initiating a separate 
notice and comment process to make CBI and emissions data 
determinations for the categories of data collected under this 
rulemaking.
---------------------------------------------------------------------------

    Special Provisions for Reporting Year 2010. During January 1, 2010 
through March 31, 2010, reporters may use best available monitoring 
methods for any parameter (e.g., fuel use, daily carbon content of 
feedstock by process line) that cannot reasonably be measured according 
to the monitoring and QA/QC requirements of a relevant subpart. The 
reporter must still use the calculation methodologies and equations in 
the ``Calculating GHG Emissions'' sections of each relevant subpart, 
but may use the best available monitoring method for any parameter for 
which it is not reasonably feasible to acquire, install, and operate a 
required piece of monitoring equipment by January 1, 2010. Starting no 
later than April 1, 2010, the reporter must begin following all 
applicable monitoring and QA/QC requirements of this part, unless they 
submit a request to EPA showing that it is not reasonably feasible to 
acquire, install, and operate a required piece of monitoring equipment 
by April 1, 2010, and EPA approves the request. EPA will not approve 
use of best available methods beyond December 31, 2010. Best available 
monitoring methods include any of the following methods:
     Monitoring methods currently used by the facility that do 
not meet the specifications of a relevant subpart.
     Supplier data.
     Engineering calculations.
     Other company data.
    Abbreviated GHG Report for Facilities Containing Only General 
Stationary Fuel Combustion Sources. In lieu of a full annual GHG 
report, reporters may submit an abbreviated GHG report for 2010 
emissions from existing facilities that were in operation as of January 
1, 2010, and are required to report only their stationary combustion 
source emissions per 40 CFR 98.2(a)(3). The abbreviated report contains 
total facility GHG emissions aggregated for all stationary combustion 
units calculated according to any of the methods in 40 CFR 98.33(a) and 
expressed in metric tons of CO2, CH4, 
N2O, and CO2e. While the breakdown of emissions 
by individual combustion units and the activity data used to calculate 
the emissions do not need to be reported as part of the abbreviated GHG 
report, the calculation variables used in the selected method must be 
reported. For calendar year 2011, all reporters must submit the full 
annual GHG report containing all required information.
4. How is the report submitted?
    The reports must be submitted electronically, in a format to be 
specified by the Administrator after publication of the final rule.\11\ 
To the extent practicable, we plan to adapt existing EPA facility 
reporting programs to accept GHG emissions data. We are developing a 
new electronic data reporting system for source categories or suppliers 
for which it is not feasible to use existing EPA reporting mechanisms.
---------------------------------------------------------------------------

    \11\ For more information about the reporting format please see 
Section V of this preamble.
---------------------------------------------------------------------------

    Each report must contain a signed certification by a Designated 
Representative of the facility. On behalf of the owners and operators, 
the Designated Representative must certify under penalty of law that 
the report has been prepared in accordance with the requirements of 40 
CFR part 98 and that the information contained in the report is true 
and accurate.
5. What records must be retained?
    Each reporter must also retain and make available to EPA upon 
request the

[[Page 56269]]

following records for three years in an electronic or hard-copy format 
as appropriate:
     A list of all units, operations, processes and activities 
for which GHG emissions are calculated.
     The data used to calculate the GHG emissions for each 
unit, operation, process, and activity, categorized by fuel or material 
type. These data include, but are not limited to:

--The GHG emissions calculations and methods used.
--Analytical results for the development of site-specific emissions 
factors.
--The results of all required analyses for high heat value, carbon 
content, or other required fuel or feedstock parameters.
--Any facility operating data or process information used for the GHG 
emissions calculations.

     The annual GHG reports.
     Missing data computations. For each missing data event, 
also retain a record of the duration of the event, actions taken to 
restore malfunctioning monitoring equipment, the cause of the event, 
and the actions taken to prevent or minimize occurrence in the future.
     A written GHG monitoring plan containing the information 
specified in 40 CFR 98.3(g)(5).
     The results of all required certification and quality 
assurance (QA) tests of CEMS, fuel flow meters, and other 
instrumentation used to provide data for the GHGs reported.
     Maintenance records for all CEMS, flow meters, and other 
instrumentation used to provide data for the GHGs reported.
     Any other data specified in any applicable subpart of 40 
CFR part 98. Examples of such data could include the results of 
sampling and analysis procedures required by the subparts (e.g., fuel 
heat content, carbon content of raw materials, and flow rate) and other 
data used to calculate emissions.

B. Summary of the Major Changes Since Proposal

    EPA received approximately 16,800 public comments on the proposed 
rulemaking. As mentioned earlier in this preamble, we had two public 
hearings and conducted an unprecedented level of outreach between 
signature of the proposal and the close of the public comment period. 
Below are the major changes to the program since the proposal. The 
rationale for these and any other significant changes can be found in 
this preamble or in the ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments.''
     Reduced the number of source categories included in the 
final rule as we further consider comments and options on several 
categories.\12\
---------------------------------------------------------------------------

    \12\ See the following sections of this preamble for discussion 
of source categories not included in today's final rule: sections 
III.I (electronics manufacturing), III.J (ethanol production), III.L 
(fluorinated GHG production), III.M (food processing), III.T 
(magnesium production), III.W (oil and natural gas systems), III.DD 
(SF6 from electrical equipment), III.FF (underground coal 
mines), III.HH (industrial landfills are not included in today's 
rule, but MSW landfills are covered by the rule), III.II (wastewater 
treatment), and III.KK (suppliers of coal).
---------------------------------------------------------------------------

     Added a mechanism in 40 CFR 98.2 to allow facilities and 
suppliers that report less than 25,000 metric tons of CO2e 
for five consecutive years, or less than 15,000 metric tons for 3 
consecutive years, to cease annual reporting to EPA.
     Added a mechanism in 40 CFR 98.2 to allow facilities and 
suppliers that stop operating all GHG-emitting processes and operations 
covered by the rule to cease annual reporting to EPA.
     Added a provision in 40 CFR 98.3 for submittal of revised 
annual GHG reports to correct errors.
     Added provisions in 40 CFR 98.3 to allow use of best 
available monitoring methods for part of calendar year 2010.
     Added, in 40 CFR 98.3, calibration requirements for 
monitoring instruments including an accuracy specification of plus or 
minus five percent for flow meters.
     Excluded R&D activities from reporting under 40 CFR part 
98 by adding an exclusion in 40 CFR 98.2.
     Revised the requirements of the Designated Representative 
in 40 CFR 98.4 to align them with those in 40 CFR part 75 (ARP 
regulations).
     Changed record retention to three years instead of five 
years for most records (40 CFR 98.3).
     In the recordkeeping section (40 CFR 98.3), clarified the 
contents of the monitoring plan (called the quality assurance 
performance plan (QAPP) at proposal).
     Edited references to the stationary fuel combustion 
subpart to improve consistency and edited the CEMS language in several 
subparts for consistency and to clarify when CEMS are used and under 
what circumstances upgrades are needed.
     Revised several definitions in 40 CFR part 98, subpart A 
to address comments.
     In several subparts of 40 CFR part 98, moved some of the 
data elements listed in the recordkeeping section of the proposed rule 
to the reporting section. In general, these changes were made to 
provide sufficient data for EPA to verify the reported emissions using 
the verification approach described in Section II.N of this preamble. 
Specific changes and reasons for them are summarized in the relevant 
source category sections within Section III of this preamble.

C. Summary of Comments and Responses on GHGs To Report

    This section contains a brief summary of major comments and 
responses on the issue of which GHGs to report. A large number of 
comments were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Selection of 
Reporting Thresholds, Greenhouse Gases, and De Minimis Provisions.'' 
Reponses to comments on fluorinated gases can be found in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Suppliers of Industrial GHGs.''
    Comment: Many commenters supported reporting of the GHGs included 
in the proposed rule: CO2, CH4, N2O, 
HFCs, PFCs, SF6, and other fluorinated compounds. Many 
commenters noted that IPCC and national inventories focus on these 
gases, and that they are directly emitted by human activities, long-
lived in the atmosphere, and contribute to global climate change. A few 
of these also stated that collection of data on these gases is useful 
for future GHG policy development. While some commenters suggested 
collecting data on fewer gases or requiring reporting of additional 
gases, most agreed with the proposed list.
    Some commenters raised concerns that the proposed definition of 
fluorinated GHGs was broad and included compounds for which global 
warming potentials (GWPs) were not currently available.
    Response: The final rule requires reporting of the same gases as 
the proposed rule. These are the most abundantly emitted GHGs that 
result from human activity. They are not currently controlled by 
mandatory Federal programs and, with the exception of the 
CO2 emissions data reported by EGUs subject to the ARP, data 
on their emissions are also not reported under mandatory Federal 
programs. CO2 is the most abundant GHG directly emitted by 
human activities, and is a significant driver of climate change. The 
global anthropogenic combined heating effect of CH4, 
N2O, HFCs, PFCs, SF6, and the other fluorinated 
compounds are also

[[Page 56270]]

significant: About 40 percent as large as the CO2 heating 
effect according to the Fourth Assessment Report of the IPCC.
    The IPCC focuses on CO2, CH4, N2O, 
HFCs, PFCs, and SF6 for both scientific assessments and 
emissions inventory purposes because these are long-lived, well-mixed 
GHGs not controlled by the Montreal Protocol as Substances that Deplete 
the Ozone (O3) Layer. These GHGs are directly emitted by 
human activities, are reported annually in EPA's Inventory of U.S. 
Greenhouse Gas Emissions and Sinks, and are a major focus of the 
climate change research and policy communities. The IPCC also included 
methods for accounting for emissions from several specified fluorinated 
gases in the 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories.\13\ These gases include fluorinated ethers, which are used 
in electronics, in anesthetics, and as heat transfer fluids. These 
fluorinated compounds are long-lived in the atmosphere and have high 
GWPs, like the HFCs, PFCs, and SF6. In many cases these 
fluorinated gases are used in growing industries (e.g., electronics) or 
as substitutes for HFCs. As such, EPA is requiring reporting of these 
gases to ensure that the Agency has an accurate understanding of the 
emissions and uses of these gases, particularly as those uses expand.
---------------------------------------------------------------------------

    \13\ 2006 IPCC Guidelines for National Greenhouse Gas 
Inventories. The National Greenhouse Gas Inventories Programme, H.S. 
Eggleston, L. Buendia, K. Miwa, T. Ngara, and K. Tanabe (eds), 
hereafter referred to as the ``2006 IPCC Guidelines'' are found at: 
http://www.ipcc.ch/ipccreports/methodology-reports.htm. For 
additional information on these gases please see Table A-1 in 
proposed 40 CFR part 98, subpart A and the Suppliers of Industrial 
GHGs TSD (EPA-HQ-OAR-2008-0508-041).
---------------------------------------------------------------------------

    There are other GHGs and aerosols that have climatic warming 
effects that we are not including in this rule: water vapor, 
chlorofluorocarbons (CFCs), hydrochlorofluorocarbons (HCFCs), halons, 
tropospheric O3, and black carbon. The reasons why we are 
not requiring reporting of these gases and aerosols under this rule are 
contained in Section IV.A of the preamble to the proposed rule (74 FR 
16464, April 10, 2009) and in the ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Selection of Reporting 
Thresholds, Greenhouse Gases, and De Minimis Provisions.''
    In response to comments, the definition of fluorinated gases to 
report has been changed. See Section III.OO of this preamble (Suppliers 
of Industrial GHGs) for the response to comments on fluorinated gases 
to be reported.

D. Summary of Comments and Responses on Source Categories To Report

    This section contains a brief summary of major comments and 
responses on which source categories must report. A large number of 
comments were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Selection of 
Source Categories to Report and Level of Reporting.''
1. Reduction in Number of Source Categories Included in the Final Rule
    Comment: While many commenters agreed with the source categories 
selected for inclusion in the proposed rule, some commenters objected 
to the inclusion of specific source categories. Some also expressed 
concern that there might not be sufficient time for EPA to consider and 
address public comments and finalize the rules by fall 2009 for 
particular source categories.
    Response: In today's notice EPA is promulgating subparts that 
require reporting for most of the source categories included in the 
proposed rule. For these categories, EPA fully considered and addressed 
the public comments, and has determined that the source categories 
should be included in the rule for reasons stated in Section IV.B of 
the preamble for the proposed rule (74 FR 16465, April 10, 2009), the 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments: EPA's Response to Public Comments, Selection of Source 
Categories to Report and Level of Reporting'', and the relevant comment 
response volumes for each of the individual source categories. However, 
at this time EPA is not going final with the following subparts as we 
further evaluate public comments:

 Electronics manufacturing
 Ethanol production
 Fluorinated GHG production
 Food processing
 Magnesium production
 Oil and natural gas systems
 SF6 from electrical equipment
 Underground coal mines
 Industrial landfills
 Wastewater treatment
 Suppliers of coal

    We plan to further review public comments and other information 
before finalizing these subparts. Additional discussion of our reasons 
for not finalizing these particular source categories at this time can 
be found in the individual subsections in Section III of this preamble.
2. Scope of Source Categories Covered
    Comment: Several commenters suggested that the scope of reporting 
and the source categories covered should be broader. Some indicated 
that the rule should require reporting of net rather than gross 
emissions, including reporting of offset projects. In addition, some of 
the comments suggested requiring reporting of emissions and 
sequestration from forestry practices.
    Response: EPA selected the source categories required to report 
under the rule after considering the language of the Appropriations 
Act, the accompanying explanatory statement, the CAA, and EPA's 
experience in developing the U.S. GHG Inventory. The Appropriations Act 
referred to reporting ``in all sectors of the economy,'' and the 
explanatory statement directed EPA to include ``emissions from upstream 
production and downstream sources to the extent the Administrator deems 
it appropriate.'' EPA interpreted this to mean direct emissions from 
facilities over a certain threshold as well as the emissions associated 
with fuel or industrial gases when completely combusted or used, but 
not necessarily project-based reductions or sequestration.\14\ 
Calculation and reporting of net emissions (emissions at a facility 
less any sequestration occurring at the facility) was determined to be 
outside of the scope of this rule.
---------------------------------------------------------------------------

    \14\ For the discussion of the CAA authority to collect these 
data, see Section II.Q of this preamble. Also see the relevant 
source category sections within Section III of this preamble.
---------------------------------------------------------------------------

    In selecting source categories, EPA considered all anthropogenic 
sources of GHG emissions (those produced as a result of human 
activities) included in the U.S. GHG Inventory and reviewed the 2006 
IPCC Guidelines for National Greenhouse Gas Inventories and existing 
voluntary and regulatory GHG reporting programs for additional source 
categories that might be relevant. EPA systematically reviewed the list 
of source categories developed from the U.S. GHG Inventory and the IPCC 
guidance to ensure the inclusion of those that emit the most 
significant amounts of GHG emissions while minimizing the number of 
reporters. Some sources were deemed inappropriate for inclusion in this 
rule for a variety of reasons including the current ability to monitor 
and verify the emissions or products with sufficient accuracy and 
consistency. For further discussions of sources included and excluded 
please see Section IV.B of the preamble to the proposed rule (74 FR 
16465). In total, the rule is estimated to

[[Page 56271]]

cover approximately 85 percent of U.S. GHG emissions.
    With respect to emissions and sequestration from agricultural 
sources and other land uses, the rule does not require reporting of 
emissions or sequestration associated with deforestation, carbon 
storage in living biomass or harvested wood products. These categories 
were excluded because currently available, practical reporting methods 
to calculate facility-level emissions for these sources can be 
difficult to implement and can yield uncertain results. Currently, 
there are no direct GHG emission measurement methods available except 
for research methods that are very expensive and require sophisticated 
equipment. Limited modeling-based methods have been developed for 
voluntary GHG reporting protocols which use general emission factors, 
and large-scale models have been developed to produce comprehensive 
national-level emissions estimates, such as those reported in the U.S. 
GHG Inventory report. To calculate emissions or sequestration using 
emission factor or carbon stock exchange approaches, it would be 
necessary for landowners to report on management practices and a 
variety of data inputs. The activity data collection and emission 
factor development necessary for emissions calculations at the scale of 
individual reporters can be complex and costly. Due to the current lack 
of reasonably accurate facility-level emissions/stock change factors 
and the ability to accurately measure all facility-level calculation 
variables at a reasonable cost to reporters, the reporting of emissions 
and sequestration associated with deforestation and carbon 
sequestration from forestry practices was excluded as a source 
category.
    While this reporting rule does not require reporting by facilities 
or suppliers in every source category, the U.S. GHG Inventory does 
provide national estimates of emissions from all U.S. anthropogenic GHG 
sources. In the case of land-based emissions, this includes all 
emissions by sources and removals by sinks on lands that are managed. 
The Inventory is prepared annually by EPA, in collaboration with other 
Federal agencies, and is an impartial, policy-neutral report that 
tracks annual GHG emissions at the national level and presents 
historical emissions from 1990 to 2007. The Inventory also calculates 
carbon dioxide emissions that are removed from the atmosphere by 
``sinks,'' such as through the uptake of carbon by forests, vegetation, 
and soils.
    Offsets projects are of interest to many stakeholders because they 
could be an important component of a potential future cap and trade 
system. Some commenters requested EPA to include accounting methods for 
offsets in this reporting rule. We believe that this issue is beyond 
the scope of this rulemaking and the Congressional request that 
initiated it. However, EPA will continue to monitor policy needs and 
developments in the future and is prepared to initiate additional 
reporting efforts at the appropriate time.
3. Reporting by Both Upstream and Downstream Sources
    Comment: Some commenters were concerned that requiring reporting by 
both fuel and industrial GHG suppliers (upstream sources) and direct 
emitters (downstream sources) results in double counting of GHG 
emissions and could lead to overestimation of emissions. Some 
commenters thought reporting by both upstream and downstream sources 
was duplicative, confusing, unnecessary, or burdensome and recommended 
the rule be revised to eliminate double reporting. Other commenters 
agreed with EPA's proposed selection of source categories to report and 
that reporting by upstream sources and downstream sources is needed to 
inform development of GHG policies and programs.
    Response: This rule responds to a specific request from Congress to 
collect data on GHG emissions from both upstream production and 
downstream sources, as appropriate. The rule requires reporting by 
facilities that directly emit GHGs above the selected threshold as a 
result of combustion of fuel or industrial processes (downstream 
sources). The majority of these reporters are large facilities in the 
electricity generation and industrial sectors. The rule also requires 
upstream suppliers of fossil fuels and industrial GHGs to report the 
GHG emissions that could be emitted from combustion or use of the 
quantity of fuels or industrial gases supplied into the economy. In 
many cases, the fossil fuels and industrial GHGs supplied by producers 
and importers are used and ultimately emitted by a large number of 
small sources. To cover these direct emissions would require reporting 
by hundreds or thousands of small facilities. To avoid this impact, the 
rule does not include all of those emitters but instead requires 
reporting by the suppliers of industrial gases and suppliers of fossil 
fuels.
    The data collected under this rule are consistent with the 
appropriations language and provide valuable information to EPA and 
stakeholders in the development of climate change policy and programs. 
Potential policies such as low carbon fuel standards can only be 
applied upstream, whereas end-use emission standards can only be 
applied downstream. Data from upstream and downstream sources would be 
necessary to formulate and assess the impacts of such potential 
policies. Eliminating reporting by either upstream sources or 
downstream sources would not satisfy EPA's data needs and policy 
objectives of this rule.
    EPA acknowledges that there is inherent double reporting of 
emissions in a program that includes both upstream and downstream 
sources. However, as discussed in Sections I.D and IV.B of the preamble 
to the proposed rule (74 FR 16448, April 10, 2009) EPA does not intend 
to use emissions data collected by this rule as a replacement for the 
national emission estimates found in the annual Inventory of GHG 
emissions.

E. Summary of Comments and Responses on Thresholds

    This section contains a brief summary of major comments and 
responses on EPA's approach and rationale for selection of reporting 
thresholds. See sections III.C through PP of this preamble for 
summaries of comments and responses on specific threshold analyses for 
the individual source categories contained in 40 CFR part 98, subparts 
C through PP. A large number of comments were received covering 
numerous topics. Responses to significant comments received can be 
found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Selection of Reporting Thresholds, Greenhouse Gases, 
and De Minimis Provisions.''
    Comment: Many commenters supported the proposed threshold of 25,000 
metric tons of CO2e per calendar year. These commenters 
generally agreed that the 25,000 metric ton threshold level achieves a 
reasonable balance between the percentage of national emissions covered 
and the number of reporters, resulting in a sufficiently comprehensive 
dataset while minimizing the impact on small facilities. Some also 
commented that this threshold is consistent with other existing GHG 
programs or likely future programs. Some commenters supported a 100,000 
metric ton CO2e threshold because they believe this level 
covers an appropriate percentage of national GHG emissions while easing 
the reporting burden on industry. Some commenters supported an emission 
threshold of 10,000 metric tons CO2e to enable collection of 
emissions data for smaller

[[Page 56272]]

sources. Some of these commenters also noted that a 10,000 metric ton 
CO2e threshold is more appropriate in order to monitor 
leakage of emissions to smaller sources (since 25,000 metric tons of 
CO2e is a likely threshold for future emissions reductions 
mandates). Some commenters suggested quantitative evaluation of 
intermediate threshold options in addition to the four evaluated by EPA 
(1,000; 10,000; 25,000; and 100,000); several of these suggested EPA 
analyze a threshold of 50,000 metric tons CO2e to reduce the 
number of reporting facilities.
    Response: As described in the preamble to the proposed rule (74 FR 
16448, April 10, 2009), EPA considered four threshold levels, as well 
as capacity-based thresholds where appropriate, and we proposed a 
threshold of 25,000 metric tons of CO2e for many source 
categories, and capacity-based or ``all in'' thresholds for other 
categories. Based on comments received, we reexamined the threshold 
analyses both in general and for each industry, taking into account 
additional data provided, and we considered whether there were reasons 
to develop different thresholds in specific industry sectors. The 
specific elements of these analyses are discussed in the relevant 
source category discussions in this preamble and the accompanying 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments'' volumes for each source category. At the general level, we 
also considered non-quantitative factors, such as consistency with 
State and other programs (the majority have established thresholds for 
GHG reporting at 25,000 metric tons or lower, such as 10,000 or 5,000 
metric tons), and the need to select a threshold level that best 
satisfies the objective of the reporting rule to collect a national 
data set that is sufficiently comprehensive for use in analyzing a 
range of GHG policies and programs.
    From these analyses, we concluded that a 25,000 metric ton 
threshold suited the needs of the reporting program by providing 
comprehensive coverage of emissions with a reasonable number of 
reporters, thereby creating the robust data set necessary for the 
quantitative analyses of the range of likely GHG policies, programs and 
regulations. Moreover, the 25,000 metric ton threshold covers similarly 
sized sources as covered by many current CAA programs (e.g., NSPS 
applies PM emissions limits to oil-fired and coal-fired units larger 
than 30 mmBtu per hour).\15\ And, as mentioned previously, this level 
is consistent with (or higher than) the majority of other GHG reporting 
programs. Furthermore, having a uniform threshold \16\ was an equitable 
approach because like facilities could be compared across sectors and 
no one industry would be disproportionately affected or subjected to a 
lower or higher threshold. A uniform threshold is also essential for 
evaluating potential policies and programs that could have a single 
emissions threshold across source categories (e.g., PSD), and 
simplifies the applicability determination for facilities that emit 
GHGs from more than one source category under the rule.
---------------------------------------------------------------------------

    \15\ As explained in section II.A of this preamble, facilities 
that only have stationary combustion units as their only source of 
emissions and have units with an aggregate maximum heat input of 
less than 30 mmbtu are not included in this rule.
    \16\ Although the thresholds were expressed in different ways 
(e.g., ``all-in'', annual emissions) most corresponded to, or were 
consistent with, an annual facility-wide emission level of 25,000 
metric tons of CO2e.
---------------------------------------------------------------------------

    As discussed in Section IV.C of the preamble to the proposed rule 
(74 FR 16448, April 10, 2009), we considered four potential thresholds 
(the range of 1,000 to 100,000 metric tons of CO2e) and from 
our analysis and the comments we concluded we had enough information to 
select an appropriate threshold for the final rule and that detailed 
quantitative analyses of additional intermediate thresholds would not 
change EPA's decision. For example, in reviewing our threshold 
analyses, we determined that the intermediate options between 25,000 
and 100,000 metric tons would not provide an alternative threshold that 
substantially reduced the number of the reporters relative to other 
options considered or substantially improved the cost effectiveness. 
(See ``Review of Threshold Analyses'' memorandum in docket EPA-HQ-OAR-
2008-0508.) Based on our proposal analysis on the data available, we 
saw that the majority of the affected facilities or suppliers had 
emissions either considerably above or below 25,000 metric tons 
CO2e per year. (As previously explained, supplier GHG 
quantities represent the emissions that could be released when the 
products they supply are combusted or used.) The selected threshold 
took into account our finding that while a threshold other than 25,000 
metric tons of CO2e might appear to achieve an appropriate 
balance between the number of facilities and emissions covered for a 
limited number of source categories, there are several additional 
reasons for selecting the threshold of 25,000 metric tons of 
CO2e per year.
    The lower threshold alternatives that we considered were 1,000 
metric tons of CO2e per year, and 10,000 metric tons of 
CO2e per year. At proposal, we explained that we did not 
select either of these thresholds because although both broaden 
national emissions coverage, they do so by disproportionately 
increasing the number of affected facilities. With the data available 
at proposal and from the comment period, we remain convinced that the 
1,000 metric ton CO2e/year threshold would increase the 
number of reporters by an order of magnitude, thus changing the focus 
of the program from large to small emitters and imposing reporting 
costs on tens of thousands of small businesses that in total would 
amount to less than 10 percent of national GHG emissions. Our analysis 
indicates that a 10,000 metric ton CO2e/yr threshold would 
approximately double the number of reporters, but would only increase 
national emissions coverage by one percent. (See the Regulatory Impacts 
Analysis for the final rule for the estimated number of facilities and 
GHG emissions covered by the alternative thresholds examined.) While 
some proposals (e.g., WCI and H.R. 2454, American Clean Energy and 
Security Act) contain a 10,000 metric ton threshold for reporting, EPA 
concluded for policy evaluation purposes, the 25,000 metric ton 
threshold more effectively targets large industrial emitters and 
suppliers, covers approximately 85 percent of U.S. emissions, and 
minimizes the burden on smaller facilities.
    We also reviewed the 100,000 metric tons of CO2e per 
year as an alternative threshold but concluded that it fails to satisfy 
key objectives. It excludes a number of emitters in certain source 
categories such that the emissions data would not adequately cover key 
sectors of the economy. At 100,000 metric tons CO2e per 
year, reporting for some large industry sectors would be rather 
significantly fragmented, resulting in an incomplete understanding of 
direct emissions from that sector. We concluded that this threshold 
would not sufficiently cover the types of facilities that are typically 
regulated under the CAA and would be inadequate for the intended use of 
analyzing potential policies and developing future CAA programs.
    Based on our review, EPA has determined that the selected 25,000 
metric ton CO2e threshold will cover many of the types of 
facilities and suppliers typically regulated under the CAA, while 
appropriately balancing

[[Page 56273]]

emission coverage and burden. At this threshold, EPA will be able to 
evaluate the effects of a number of options and policies that could 
address GHG emissions without placing an undue burden on a large number 
of smaller facilities and sources. In addition, this threshold level is 
largely consistent with many of the existing GHG reporting programs and 
different legislative proposals in Congress. Furthermore, many industry 
stakeholders that EPA met with and the majority of public commenters, 
representing a wide variety of stakeholders, expressed support for a 
25,000 metric ton CO2e threshold, agreeing with the Agency's 
assessment of coverage.

F. Summary of Comments and Responses on Level of Reporting

    This section contains a brief summary of major comments and 
responses on the level of reporting. A large number of comments were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Selection of Source Categories to 
Report and Level of Reporting.''
    Comment: Many commenters supported facility-level reporting rather 
than corporate-level reporting. The reasons they gave included: 
Facility-level reporting is consistent with most air rules and 
permitting programs, environmental managers are used to facility-level 
reporting, facility-level data would be needed to implement likely 
future regulatory programs such as a cap and trade program, this 
approach is simpler to implement and minimizes administrative burden, a 
facility's corporate status can change during the year, and tying data 
to physical sources makes emissions easier to track and monitor over 
time. On the other hand, several commenters favored corporate-level 
reporting. The reasons they gave included: The effect of GHG emissions 
is global, therefore the location where the GHGs are emitted is not 
important; various other GHG programs require corporate-level reporting 
and have mechanisms for handling ownership changes; the overall carbon 
footprint of a corporation is important; a company's entire emissions 
should be reported, not just those facilities that are above a 
threshold; and facility-level data are more likely to be CBI.
    Response: In response to comments, EPA reviewed our initial views 
outlined in Sections IV.D and V of the proposal preamble (74 FR 16448, 
April 10, 2009) in light of our data needs under the CAA, our 
interpretation of the Congressional request, and the feedback received. 
Based on these considerations, we determined that the final rule will 
retain the same reporting level as the proposed rule. Facility-level 
reporting is required, with the exception of some supplier source 
categories (e.g., importers of fuels or industrial GHGs or 
manufacturers of motor vehicles and engines). If a facility is covered 
by the rule, the reporter must report the facility's GHG emissions from 
all source categories for which the rule contains GHG emission methods. 
The total emissions for the facility are reported, as well as emissions 
broken out by source category within the facility. Subparts for some 
source categories specify further breakout of emissions by process line 
or unit.
    We retained this approach because the purpose of this rule is to 
collect data from suppliers and from facilities with direct GHG 
emissions above selected thresholds for use in analyzing, developing, 
and implementing potential future CAA GHG policies and programs. 
Facility-level data are needed to support analyses of some types of 
potential GHG reduction programs, such as NSPS. The data collected from 
facility-level reporting under this rule will improve our ability to 
formulate a set of climate change policy options and to assess which 
facilities and industries would be affected by the options and how they 
would be affected. (Note, we expect that similarly, facility-level data 
will also be useful to States, the public, and other stakeholders to 
formulate State and regional programs and track emission trends over 
time.) Reporting by individual facilities is also consistent with most 
existing air regulatory such as ARP, NSPS and national emission 
standards for hazardous air pollutants (NESHAP), and permitting 
programs. Many facility environmental managers are already experienced 
with facility-level emissions reporting under such programs and can 
likewise submit reports under the mandatory GHG reporting rule.
    Corporate-level reporting was not selected because corporate 
reporting without facility-specific details would not provide 
sufficient data to assess many potential CAA GHG policies and programs. 
EPA understands that some corporate-level GHG reporting programs have 
mechanisms to establish reporting responsibilities under complex and 
changing ownership situations, but we find corporate-level reporting 
overly complex for this rulemaking given that facility level data are 
needed, and it is simpler to place reporting responsibility directly on 
individual facilities. We note that while EPA requires facility-level 
reporting, it is up to the facility owners and operators to select the 
designated representative who will submit the report for a facility, 
and reporters can also establish any internal corporate review 
processes they deem appropriate.
    While EPA agrees with the commenters who indicated that information 
on corporate carbon footprints is useful for various purposes, 
collection of such information is outside the scope of this rulemaking. 
With that said, we are exploring options for adding additional data 
elements to the reports, such as name of parent company and NAICS 
code(s), to allow easier aggregation of facility-level data to the 
corporate level under this program. EPA expects to subject any 
additional requests to notice and comment rulemaking. In any event, we 
expect that the facility-level data collected under this rule will be 
useful for programs that request or require corporate reporting. But, 
as explained in Sections I.D and I.E of this preamble, this reporting 
rule is one action to respond to a specific request from Congress. 
Various other Federal and State programs are collecting and will 
continue to collect corporate-level data on direct and indirect 
emissions, energy efficiency, and other data as part of a broad array 
of climate change initiatives.
    For the response to the commenters' concern about CBI, see Section 
II.R of this preamble.

G. Summary of Comments and Responses on Initial Reporting Year and Best 
Available Monitoring Methods

    This section contains a brief summary of major comments and 
responses on the initial reporting year. A large number of comments 
were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Initial Year of Reporting, 
Duration of the Reporting Program, and Provisions to Cease Reporting.''
    Comment: The proposed rule included reporting of calendar year 2010 
emissions in March 2011, which would require reporters to collect data 
starting on January 1, 2010. The preamble to the proposed rule also 
discussed options of allowing reporting of best available data for 
2010, or delaying reporting by one year (64 FR 16471, April 10, 2009). 
Many industries with source categories covered by the proposed rule 
commented that a data collection start date of January 1, 2010,

[[Page 56274]]

does not provide sufficient time to review the final rule, purchase and 
install required monitoring equipment, train staff, and develop 
internal electronic data management and recordkeeping systems needed to 
comply with the rule. Many indicated that they do not currently have 
all the meters and monitoring equipment required by the rule. Most of 
these commenters strongly stated that calendar year 2011 should be the 
first reporting year. Many of them also stated that if EPA decides data 
collection must begin in 2010, a best available data approach should be 
allowed for calculating and reporting 2010 emissions.
    Conversely, Congressional inquiries and a large number of public 
commenters including States, NGOs, and the general public, emphasized 
that data collection must start in 2010 because time is of the essence 
for developing and implementing GHG policies and programs. These 
commenters urged EPA to require reporting of calendar year 2010 GHG 
emissions and not to delay data collection until calendar year 2011.
    Some of the commenters made suggestions about the types of data and 
methods that could be allowed if EPA chose to use a best available data 
approach for 2010.
    Response: EPA carefully reviewed input from all commenters with the 
goal of balancing the urgent need for data against the legitimate 
concerns raised regarding timing. As a result, we have revised the 
approach for the final rule. The final rule requires data collection 
for calendar year 2010, but has been changed since proposal to allow 
use of best available monitoring methods for the first quarter of 2010.
    Schedule. EPA decided to require reporting of calendar year 2010 
emissions because the data are crucial to the timely development of 
future GHG policy and regulatory programs. In the Appropriation Act, 
Congress requested EPA to develop this reporting program on an 
expedited schedule, and Congressional inquiries along with public 
comments reinforce that data collection for calendar year 2010 is a 
priority. Delaying data collection until calendar year 2011 would mean 
the data would not be received until 2012, which would likely be too 
late for many ongoing GHG policy and program development needs.
    However, EPA understands that because the final rule is not being 
promulgated until fall of 2009, facilities that do not already have the 
monitoring systems required by the rule in place might not have time to 
install and begin operating them by January 1, 2010. Under the schedule 
in the Appropriations Act, the final rule would have been signed at the 
end of June 2009, which would have allowed approximately six months to 
prepare for data collection in January 2010. Given the delay in 
promulgating the rule, there is less time between signature of the rule 
and a January 1, 2010 start date. In light of this fact, and the 
industry comments indicating that facilities do not currently have all 
of the required monitoring systems, EPA has decided to provide 
flexibility by establishing a best available monitoring methods option 
for the first quarter of calendar year 2010. This approach will provide 
time comparable to what would have occurred had EPA met the schedule in 
the Congressional request. We will post the rule on EPA's Web site soon 
after signature, allowing reporters to see the final requirements and 
begin compliance planning even before the rule is published in the 
Federal Register.
    For the time period of January 1 through March 31, 2010, the rule 
allows use of best available monitoring methods for parameters that 
cannot reasonably be measured according to the monitoring and QA/QC 
requirements of the relevant subpart. Starting no later than April 1, 
2010, the reporter must begin following all applicable monitoring and 
QA/QC requirements of this part, unless they submit an extension 
request showing that it is not reasonably feasible to acquire, install, 
and operate a required piece of monitoring equipment by the specified 
date and EPA approves the request. EPA may approve such requests for a 
set time period, but will not approve the use of best available methods 
beyond December 31, 2010. See the paragraph heading ``Extension Request 
Process'' near the end of this response for further details.
    EPA has concluded that the time period allowed under this schedule 
(including the provision for facility-specific requests) will allow 
facilities that do not currently have the required monitoring systems 
sufficient time to begin implementing the monitoring methods required 
by the rule. In general, the required monitors, such as flow meters, 
are widely available and are not time consuming to install. By allowing 
the additional time, many facilities may also be able to install the 
equipment during other planned (or unplanned) process unit downtime, 
thus avoiding process interruptions.
    Definition of Best Available Monitoring Methods. In determining 
methods that would be allowed under a best available monitoring methods 
approach, EPA considered the goal of collecting consistent data to 
provide information of sufficient quality to inform policy and program 
development, while recognizing that not all facilities may be able to 
implement the full monitoring methods required by the rule by January 
2010. We reviewed the public comments as well as the California Air 
Resources Board (CARB) mandatory reporting rule, and we considered 
options falling between full flexibility to use any method and the full 
requirements of EPA's mandatory reporting rule.
    The least stringent approach would be to allow facilities to 
calculate GHG emissions using any data, methods, calculation 
procedures, or emission factors they choose during the best available 
monitoring period and submit minimal supporting data. This approach 
would provide maximum flexibility to industry, but EPA did not select 
this approach because the usefulness of the collected data would be 
questionable given that it would be obtained using inconsistent methods 
and it could not be verified with sufficient confidence. Instead, EPA 
developed a hybrid approach that falls between full flexibility and 
implementation of full monitoring requirements in January 2010. Under 
the final rule, during January 1, 2010, through March 31, 2010, 
reporters may use best available monitoring methods for any parameter 
(e.g., fuel use, daily carbon content of feedstock by process line) if 
that parameter cannot reasonably be measured following the monitoring 
and QA/QC requirements of a relevant subpart. The reporter must use the 
calculation procedures and equations in the ``Calculating GHG 
Emissions'' sections of each relevant subpart, but may use the best 
available monitoring method for any parameter for which it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by January 1, 2010. Best available monitoring 
methods include the following:
     Monitoring methods currently used by the facility that do 
not meet the specifications of a relevant subpart.
     Supplier data.
     Engineering calculations.
     Other company data.
    Reporters must submit an annual GHG report for 2010. This calendar 
year 2010 report (submitted March 31, 2011) includes the same 
information as in subsequent years, but also requires brief 
descriptions of each best available monitoring method used, the 
parameter measured using that method, and the

[[Page 56275]]

time period during which the method was used.
    EPA selected this approach because it is responsive to commenters' 
concerns that monitoring equipment cannot be installed by January 1, 
2010, while also ensuring timely submission of more consistent and 
verifiable data than the alternatives. We have concluded that the data 
will be more consistent because all reporters will use the same basic 
emissions calculation equations that are in the rule, with best 
available inputs, rather than the wide range of calculation methods 
that would likely be used under a full flexibility approach. 
Furthermore, the selected approach requires reporting of sufficient 
information for EPA to verify the emissions data. We have therefore 
determined that this approach for collection and reporting of the 
calendar year 2010 data will fulfill the objectives of this reporting 
rule.
    It should also be noted that, like the proposed rule, the final 
rule allows facilities that must report only emissions from general 
stationary fuel combustion equipment (and do not have other covered 
source categories) to determine calendar year 2010 emissions using any 
of the methods (tiers) in 40 CFR part 98, subpart C, and submit an 
abbreviated GHG report. Full reporting starts with calendar year 2011. 
This allows such facilities, which are less likely to have experience 
with emissions monitoring and reporting, an extra year to begin full 
reporting using all the procedures required by the rule.
    Extension Request Process. We expect that the vast majority of 
facilities will begin complying with the full monitoring requirements 
of the rule no later than April 1, 2010, and will not require or be 
granted an extension. However, EPA is providing facilities with 
specific circumstances an opportunity to request an extension in the 
use of best available monitoring methods. EPA will review extension 
requests to determine whether they should be approved. We envision that 
extensions will apply primarily to situations when needed monitoring 
instrumentation could not be obtained within the timeframe despite good 
faith efforts by the facility, or when installation of monitoring 
instrumentation would require a process unit shutdown that could not 
feasibly be scheduled prior to April 1, 2010.
    Timing. Reporters must submit extension requests to EPA no later 
than 30 days after the effective data of the GHG reporting rule. EPA 
intends to review each submitted request and may approve or disapprove 
the requests. EPA may approve the request for a specified time period, 
but will not approve the use of best available methods beyond December 
31, 2010. If EPA disapproves an extension request, then the reporter is 
required to implement the full monitoring methods required by the rule 
by April 1, 2010.
    Content of Request. Requests must contain the following 
information:
     A list of specific monitoring instrumentation for which 
the request is being made and the locations where each piece of 
monitoring instrumentation will be installed.
     Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) for which the instrumentation 
is needed.
     A detailed description of the reasons why the needed 
equipment could not be obtained and installed before April 1, 2010.
     If the reason for the extension is that the equipment 
cannot be purchased and delivered by April 1, 2010, include supporting 
documentation such as the date the monitoring equipment was ordered, 
investigation of alternative suppliers and the dates by which 
alternative vendors promised delivery, backorder notices or unexpected 
delays, descriptions of actions taken to expedite delivery, and the 
current expected date of delivery.
     If the reason for the extension is that the equipment 
cannot be installed without a process unit shutdown, include supporting 
documentation demonstrating that it is not possible to isolate the 
equipment, piping, or line and install the monitoring instrument 
without a full process unit shutdown. Also include the date of the most 
recent process unit shutdown, the frequency of shutdowns for this 
process unit, and the date of the next planned shutdown during which 
the monitoring equipment can be installed. If there has been a shutdown 
or if there is a planned process unit shutdown between promulgation of 
this rule and April 1, 2010, include a justification of why the 
equipment could not be obtained and installed during that shutdown.
     A description of the specific actions the facility will 
take to obtain and install the equipment as soon as reasonably feasible 
and the expected date by which the equipment will be installed and 
operating.
    Approval Criteria. EPA will approve a request if it contains all of 
the information required by the rule and if it demonstrates to the 
Administrator's satisfaction that it is not reasonably feasible to 
acquire, install, and operate a required piece of monitoring equipment 
by April 1, 2010.
    For example, EPA is likely to approve a request for an extension if 
the documentation provided by the reporter shows that they ordered 
monitoring equipment in a timely manner, attempted to find a supplier 
who could deliver it in time, and could not control the fact that the 
equipment was not received for installation prior to April 1, 2010.
    If a reporter requests an extension because equipment cannot be 
installed without a process unit shutdown, EPA is likely to approve 
such a request if the documentation clearly demonstrates why it is not 
feasible to install the equipment without a process unit shutdown, 
shows there is not a planned shutdown (and has not been a shutdown) 
prior to April 1, 2010, during which the monitoring instrument could be 
installed. There are many locations where monitors can be installed 
without a process unit shutdown, because there is often some redundancy 
in process or combustion equipment or in the piping that conveys fuels, 
raw materials and products. For example, many facilities have multiple 
combustion units and fuel feed lines such that when one combustion unit 
is not operating they can obtain the needed steam, heat, or emissions 
destruction by using other combustion devices. Some facilities have 
multiple process lines that can operate independently, so one line can 
be temporarily shut down to install monitors while the facility 
continues to make the same product in other process lines to maintain 
production goals. If a monitor needs to be installed in a section of 
piping or ductwork, it can be possible in some cases to isolate a line 
without shutting down the process unit (depending on the process 
configuration, mode of operation, storage capacity, etc.). If the line 
or equipment location where a monitor needs to be installed can be 
temporarily isolated and the monitor can be installed without a full 
process unit shutdown, it is less likely EPA will approve an extension 
request.
    While there might be other unique facility-specific situations for 
which an extension might be granted, EPA expects few of these. There 
have been several changes to the rule since proposal that would reduce 
the need for extensions. For example, fewer source categories are 
included in the final rule; changes have been made to the monitoring 
requirements of some rule subparts to allow more flexibility in 
monitoring methods; and provisions have been added to the general 
stationary fuel combustion, petroleum refineries, and petrochemical 
productions subparts allowing facilities

[[Page 56276]]

additional time to perform some monitor calibrations. These changes 
address many of the specific situations about which commenters raised 
concerns.
    It is highly unlikely we would approve extension requests for 
parameters that are measured by periodic sampling and analyses. 
Facilities should be able to make arrangements to collect periodic 
samples and send them off-site for analyses (if they don't have on-site 
analytical capabilities) without the need for an extension. Similarly, 
extensions for design of electronic recordkeeping systems seem 
unnecessary. Many facilities already have electronic recordkeeping 
systems that can be altered to keep the records needed for this rule. 
Furthermore, reporters can keep the specified records in any type of 
hard copy or electronic format they choose, as long as it is in a form 
suitable for expeditious inspection and review.

H. Summary of Comments and Responses on Frequency of Reporting and 
Provisions To Cease Reporting

    This section contains a brief summary of major comments and 
responses on the frequency of reporting and on whether reporters should 
be allowed to stop submitting annual reports if emissions are reduced 
below a threshold level. A large number of comments were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Initial Year of Reporting, Duration of the 
Reporting Program, and Provisions to Cease Reporting'' and ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart A: Applicability and Reporting Schedule.''
1. Provisions To Cease Reporting if Emissions Decrease
    Comment: The majority of public commenters favored annual reporting 
as opposed to more or less frequent reporting. Many commenters, 
especially industrial facilities required to report under the rule, 
objected to the ``once in always in'' reporting approach in the 
proposed rule and requested a mechanism to stop reporting if emissions 
fall below the 25,000 metric tons CO2e per year annual 
threshold. Others suggested a level different from 25,000 metric tons 
CO2e per year to cease reporting. Some commented that the 
lack of such a mechanism is a disincentive to reduce facility 
emissions. Conversely, other commenters supported the proposed once in 
always in approach in order to create a consistent, long term data set 
covering the same population of facilities over time that could be used 
to track trends and understand factors that influence emission levels.
    Response: After reviewing the comments, EPA has not changed the 
frequency of reporting since the proposed rule. Affected facilities and 
suppliers must submit annual GHG reports. Facilities with ARP units 
that report CO2 emissions data to EPA on a quarterly basis 
would continue to submit quarterly reports as required by 40 CFR part 
75, in addition to providing the annual GHG reports. We have determined 
that annual reporting is sufficient for policy and regulatory 
development. It is also consistent with other existing mandatory and 
voluntary GHG reporting programs at the State and Federal levels (e.g., 
The Climate Registry (TCR), several individual State mandatory GHG 
reporting rules, EPA voluntary partnership programs, the DOE voluntary 
GHG registry).
    In response to comments on ``once in, always in,'' however, EPA has 
added provisions to allow facilities and suppliers to stop submitting 
annual reports under certain conditions. These provisions apply to 
facilities and suppliers regardless of their applicability threshold as 
it is based on the annual report.
     Under the first provision, if any facility's annual GHG 
reports demonstrate emissions of less than 25,000 metric tons of 
CO2e per year for five consecutive years, they can cease 
submitting annual reports. Similarly, if any supplier's annual reports 
demonstrate that the products supplied equate to less than 25,000 
metric tons of CO2e per year for five consecutive years, 
they can cease submitting annual reports.
     Under the second provision, if any facility's or 
supplier's annual GHG reports demonstrate emissions of less than 15,000 
metric tons CO2e per year for three consecutive years, they 
can cease submitting annual reports.
    In either case, before they can stop reporting, the facility or 
supplier must submit a notification to EPA that announces the cessation 
of reporting and explains the reasons for the reduction in emissions so 
EPA can understand the reason for the decrease in emissions to help aid 
in evaluating emission reduction options across the industry.
    If emissions subsequently increase to 25,000 metric tons of 
CO2e or more in any calendar year, the facility or supplier 
must again begin annual reporting. Importantly, although a source may 
not know its emissions (or quantities supplied) exceeded the reporting 
threshold until later in the year, the requirements of the rule apply 
as of January 1, unless the increase is a result of a physical or 
operational change covered by 40 CFR 98.3(b). Thus sources close to the 
threshold should consider monitoring their emissions according to 
requirements of 40 CFR part 98 if they determine there is a chance they 
will meet or exceed the threshold. EPA is developing tools and guidance 
to assist facilities and suppliers in assessing whether the 
requirements of the rule apply to them.
    EPA concluded that adding the provisions to allow cessation of 
reporting balances the need for a complete dataset with the burden of 
continued annual reporting by facilities where there has been a change 
that has consistently reduced emissions (or supplier quantities) below 
25,000 metric tons CO2e. This approach rewards actions taken 
to reduce emissions and reduces the reporting burden. It is consistent 
with other reporting programs, such as the CARB mandatory reporting 
rule and the WCI program, both of which have mechanisms to allow 
facilities to cease reporting if their emissions are below a specified 
threshold for multiple consecutive years.
    For the first provision, EPA selected 25,000 metric tons 
CO2e per year because it is the same as the general 
applicability threshold for this rule.\17\ We selected a 5-year period, 
instead of a shorter time frame, because it allows reporters that 
consistently report less than 25,000 metric tons CO2e to 
stop reporting, but avoids the situation where a facility or supplier 
near this level would be constantly moving in and out of the reporting 
program due to small variations from one year to the next. Because this 
reporting rule is based on actual rather than potential emissions, such 
a situation would make tracking of facilities and analyses of trends 
difficult.
---------------------------------------------------------------------------

    \17\ Applicability thresholds for different source categories 
are expressed in different ways (e.g., actual emissions, production 
capacity, ``all-in''), but most correspond to a facility-wide 
emission level of 25,000 metric tons per year. The provision to 
cease reporting applies to reporters regardless of the specific 
applicability threshold that triggered reporting for their facility 
or supply operation.
---------------------------------------------------------------------------

    The second provision (cease reporting if emissions were below 
15,000 metric tons for three consecutive years) was added to reduce the 
duration of reporting for facilities and suppliers that reduce 
emissions to well below 25,000 metric tons. In such cases, a 5-year 
period is longer than necessary to

[[Page 56277]]

demonstrate that annual emissions will remain below 25,000 metric tons 
per year. If emissions are less than 15,000 metric tons for three 
consecutive years, it is unlikely that annual variation in emissions 
would cause the facility or supplier to exceed the threshold of 25,000 
metric tons per year. The shorter time period provides an incentive for 
facilities that significantly reduce their GHG emissions.
2. Provisions To Cease Reporting Due to Closures
    Comment: Several commenters suggested that EPA add a provision to 
allow closed facilities, or facilities or suppliers that stop operating 
their GHG-emitting processes, to cease annual reporting.
    Response: In response to comments, EPA has added a mechanism to 
allow facilities or suppliers that close all of their GHG-emitting 
processes or operations covered by the rule to cease annual reporting. 
The reporter must submit an annual report covering the calendar year 
during which the closure occurs. The reporter must also notify EPA that 
they intend to cease reporting and must certify that all GHG-emitting 
processes and operations for which there are methods in the rule have 
been closed. EPA agrees that it does not make sense for closed 
facilities or facilities that close all of their GHG-emitting processes 
to continue reporting indefinitely or for the 5-year period needed to 
demonstrate that emissions are less than 25,000 metric tons 
CO2e per year (or the 3-year period needed to demonstrate 
emissions are less than 15,000 metric tons CO2e per year). 
However, notification is required so that we can track facilities and 
understand why facilities stop reporting. If a facility or supplier 
that was once subject to the reporting rule and ceased reporting under 
this provision restarts any of the GHG-emitting processes or operations 
formerly reported, then they must resume annual reporting regardless of 
whether they exceed the thresholds in 40 CFR 98.2(a) when they restart. 
This provision is important so that EPA can consistently track 
emissions from facilities covered by the rule. If after the restart, 
annual reports show emissions of less than 25,000 metric tons 
CO2e per year for five consecutive calendar years or less 
than 15,000 metric tons CO2e per year for three consecutive 
years, then the facility could be exempt under the separate mechanism 
discussed in Section II.H.1 of this preamble.
    It is important to note that the provision to stop reporting is not 
intended to apply to seasonal or longer temporary cessation of 
operation. The mechanism is intended for long-term closure situations. 
It should also be noted that in order to use this provision to cease 
reporting, a facility or supplier must close all of their processes and 
operations that are required to report emissions. For example, consider 
a facility that is required to report process emissions from one or 
more source categories covered by 40 CFR part 98 and general stationary 
fuel combustion source emissions. If the facility closes some of the 
process units subject to the rule but continues to operate other 
process units covered by the rule or continues to operate stationary 
fuel combustion sources, then they must continue to submit annual 
reports until the required annual GHG reports demonstrate emissions of 
less than 25,000 metric tons of CO2e per year for five 
consecutive years (or less than 15,000 metric tons of CO2e 
per year for three consecutive years) and the facility qualifies for 
the separate provisions to stop reporting discussed in Section II.H.1 
of this preamble.

I. Summary of Comments and Responses on General Content of the Annual 
GHG Report

    This section contains a brief summary of major comments and 
responses on the emissions information to be reported under the general 
provisions (40 CFR part 98, subpart A). See sections III.C through PP 
of this preamble for summaries of comments and responses on specific 
reporting requirements for the individual source categories contained 
in 40 CFR part 98, subparts C through PP. A large number of comments on 
emission information to report under the general provisions were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart A: Content of the Annual 
Report, the Abbreviated Emission Report, Recordkeeping, and Monitoring 
Plan.''
    Comment: EPA received a variety of comments on the general content 
of the annual GHG reports. Some commenters objected to the level of 
detail required in the annual GHG reports. Some suggested reporting 
only facility-level emissions and keeping as records more detailed 
emissions breakouts (e.g., by source category, process line, or unit) 
and activity data used to calculate emissions. Other commenters 
supported the proposed general reporting requirements.
    Response: After reviewing the comments, we have not made any major 
changes in the general content of the annual GHG reports since 
proposal. The final rule requires facilities to report emissions from 
all source categories at the facility for which methods are defined in 
the rule. The General Provisions (40 CFR part 98, subpart A) require 
facilities to report total annual GHG emissions in metric tons 
CO2e and to separately present annual mass emissions of each 
individual GHG emitted from each source category at the facility. 
Reporting of CO2e allows a comparison of total GHG emissions 
across facilities in varying categories which emit different GHGs. 
Knowledge of both individual gases emitted and total CO2e 
emissions maintains transparency, is valuable for future policy and 
regulatory development, and will help EPA quantify the relative 
contribution of each gas to a source category's emissions and maintain 
transparency.
    Individual rule subparts for each source category, rather than the 
General Provisions, identify the specific data elements to be reported 
for that source category. Comments received on the need for specific 
data elements are described and responded to in Section III of this 
preamble and in relevant source category volumes of the ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments''. 
Where appropriate, the final rule has been modified based on those 
comments. In general, reporting of such data is required primarily to 
enable emissions verification and ensure the consistency and accuracy 
of data collected under this rule. The information is also needed to 
support analyses of GHG emissions for future CAA policy and program 
development. Besides total facility emissions, it benefits policy 
makers to understand: (1) The specific sources of emissions and the 
amounts emitted by each unit/process to effectively interpret the data, 
and (2) the effect of different processes, fuels, and feedstocks on 
emissions. Many of these data are already routinely monitored and 
recorded by facilities for business reasons. Further discussion of the 
selection of general reporting requirements is contained in Section 
IV.G of the proposal preamble (74 FR 16472, April 10, 2009). Other 
responses to comments on the reporting requirements in 40 CFR Part 98, 
Subpart A, and discussion of some clarifications made to the rule, are 
contained in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart A: Applicability and Reporting Schedule'', 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Subpart

[[Page 56278]]

A: Content of the Annual Report, the Abbreviated Emission Report, 
Recordkeeping, and Monitoring Plan'', and ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Subpart A: 
Definitions, Incorporation by Reference, and Other Subpart A 
Comments''.

J. Summary of Comments and Responses on Submittal Date and Making 
Corrections to Annual Reports

1. Submittal Date for Annual Report
    Comment: Several commenters requested that EPA change the annual 
submittal date for GHG reports from March 31 to a later date, such as 
April 30 or June 30. Several commenters stated that March 31 does not 
provide adequate time for data collection, aggregation and 
disaggregation, GHG calculations, QA, management review, and 
certification, and explained that this is a complex process for large 
industrial sites that have many individual GHG emission sources. Some 
of these commenters indicated that unexpected issues can arise during 
GHG emissions calculations and QA that take time to resolve. Some of 
these commenters suggested a date of June 30 to align this mandatory 
reporting rule with the submittal dates for other reporting programs 
such as California Climate Action Registry (CCAR), TCR, Climate 
Leaders, and Toxic Release Inventory (TRI). Some commented that the 
same personnel who will prepare the GHG reports are also involved in 
preparing other EPA mandated reports and that completing multiple 
reporting activities in the first quarter is a large workload. Other 
commenters favored the March 31 reporting date so that the data could 
be disseminated and available for use by policy makers, EPA, States, 
and the public in a timely fashion.
    Response: After reviewing and addressing both general comments and 
comments received on this issue for specific source categories, and 
considering the need to balance prompt reporting with the burden on 
reporters, EPA has determined that the reporting deadline of March 31 
allows a sufficient amount of time for compiling, reviewing, 
certifying, and submitting annual GHG reports. The March deadline will 
ensure timely collection of the data necessary to inform decisions 
regarding future GHG policy and program development. Since the data 
needed to calculate emissions and prepare the report must be collected 
on an ongoing basis throughout the year, reporters can begin to compile 
the data for the report and initiate QA activities during the year as 
the data are collected. Reporters would then only have to compile the 
most recently collected information, complete the final calculations, 
and review and certify the annual report after the reporting period has 
ended. Because the reports required by the rule rely on well-defined 
calculation methodologies, EPA determined that three months is a 
sufficient amount of time to complete the report. Moreover, as 
discussed in Section III of this preamble for the specific subparts, we 
have made several changes to reporting requirements that will ease 
burden and further facilitate reporting by March 31. In addition, EPA 
intends to provide outreach and training on rule requirements and an 
electronic reporting system that will help expedite report submission.
    The March 31 reporting deadline is also consistent with the 
reporting deadline implemented in 2005 for reporting GHG emissions 
under the EU Emissions Trading System and is longer than the deadlines 
allowed for reporting under many other CAA programs. For example, many 
NESHAPs and NSPSs, including those for large complex industrial 
facilities such as chemical plants and refineries, require reports of 
excess emissions and monitoring system performance to be submitted 
within 30 calendar days of the end of each compliance period. The ARP 
and Regional Greenhouse Gas Initiative (RGGI) programs, which are 
established emission cap and trade programs that rely on the same types 
of data many sources will have to submit under the GHG reporting rule, 
require facilities to submit their quarterly emissions reports within 
30 days of the end of each quarter.
2. Making Corrections to Annual Reports
    Comment: Several commenters representing multiple stakeholders 
suggested the rule should include provisions to submit revised annual 
reports. Many commented that even with good-faith efforts to follow all 
the monitoring and reporting requirements, there will likely be 
unintentional errors that are not discovered by the reporter or by EPA 
until after an annual report is submitted. Some commenters added that 
given the stringency of the self-certification provisions and potential 
penalties involved, reporters need a way to submit corrected data, and 
some provided examples of other reporting rules that include provisions 
to submit revised reports.
    Response: EPA has addressed this comment in the final rule. We have 
added a provision in 40 CFR 98.3 that requires the reporters to submit 
a revised GHG 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 agree that it is important for facilities to 
correct errors, regardless of whether they are discovered by the 
reporter or by EPA. In order to ensure accurate data for future GHG 
policies and programs, known errors should be corrected. Furthermore, 
adding a requirement to submit corrected reports is consistent with 
other EPA reporting programs, such as ARP and TRI, as well as State and 
other GHG programs. EPA intends to review the annual GHG reports 
submitted under this rule by performing electronic data QA checks and a 
range of other emission verification activities. When we find reporting 
errors (as we have in ARP and other reporting programs), we will notify 
reporters of errors and require them to submit revised reports. The 
time period of 45 days was selected to allow reporters time to retrieve 
any needed data, perform revised calculations, and resubmit the report. 
Because data for the calendar year covered by the report has already 
been collected and must be retained according to the rule, it should be 
readily available for any reanalyses needed to correct a reporting 
error. Given that facilities are allowed three months from the end of a 
reporting period to submit the annual report, revising a report to 
address a known error would logically require less time and EPA 
concluded that 45 days is sufficient.

K. Summary of Comments and Responses on De Minimis Reporting

    Comment: Some commenters suggested that de minimis cutoffs or 
simplified methods for de minimis sources should be provided to be 
consistent with other programs, such as the California mandatory GHG 
reporting rule. The commenters argued that it makes sense to focus 
effort on the significant emissions sources at a facility, rather than 
spending a lot of effort to precisely calculate emissions from sources 
that are a small percent of a facility's total emissions.
    Response: EPA considered public comments on de minimis reporting, 
both general comments and those received on individual source 
categories, in addition to the analyses of de minimis provisions we 
conducted at proposal of the rule. Based on these considerations, we 
concluded that de minimis provisions are not necessary for this rule.

[[Page 56279]]

    As discussed in the preamble to the proposal (74 FR 16448, April 
10, 2009), many existing reporting programs require corporate level 
reporting of all emissions, including emissions from numerous remote 
facilities and small onsite equipment (e.g., lawn mowers). Other 
reporting programs require reporting at the facility level but require 
reporting of emissions from all types of emission sources.\18\ These 
reporting programs recognize that it may not be possible or efficient 
to specify the reporting methods for every source that must be reported 
and include de minimis provisions to reduce the reporting burden. The 
de minimis provisions included in these programs either allow the 
reporter to exclude a portion of their emissions (e.g., the DOE 1605(b) 
voluntary reporting program allows up to three percent of facility-
level emissions to be excluded) or allow simplified calculation methods 
for small sources.
---------------------------------------------------------------------------

    \18\ For additional information about these programs please see 
overview of existing programs (EPA-HQ-OAR-2008-0508-0052) and the de 
minimis memo (EPA-HQ-OAR-2008-0508-0048).
---------------------------------------------------------------------------

    Since reporters must determine the de minimis emissions even when 
reporting is not required, the trend for both mandatory and voluntary 
reporting programs is to require reporting of all emissions but allow 
simplified calculation methods for small sources of emissions. Hence, 
the de minimis provisions included in many existing reporting programs 
are designed to avoid potentially unreasonable reporting burdens. For 
example, TCR allows reporters to use simplified calculation methods of 
their own design for calculating up to five percent of their emissions. 
Some programs recognize that a small percentage of emissions may still 
represent a large mass of emissions. For this reason, some existing 
reporting programs include a cap on the mass of de minimis emissions. 
For example, both the California mandatory reporting rule and EU 
Emissions Trading System cap de minimis emissions at 20,000 metric tons 
CO2e/year cap. For additional information on the treatment 
of de minimis in existing GHG reporting programs, please refer to the 
``Reporting Methods for Small Emission Points (De Minimis Reporting)'' 
(EPA-HQ-OAR-2008-0508-0048).
    In contrast to such existing programs, this rule already avoids 
burdensome reporting requirements for smaller emissions sources in two 
ways. First, the rule excludes small facilities through the application 
of the 25,000 metric tons of CO2e threshold. As described 
earlier in this preamble, that threshold appropriately balances the 
number and size of reporter with the coverage of emissions. The source 
categories included in the rule are typically for larger sources of 
emissions. Second, reporters must report only the emissions from 
sources for which calculation methods are provided in the rule. 
Calculation methods are generally not included for smaller sources of 
emissions (e.g., coal piles on industrial sites). In some cases, where 
a source category includes relatively small sources, the rule provides 
simplified emissions calculation methods for those sources. For 
example, reporters may use a default emission factor and heat rate to 
calculate emissions from small stationary combustion units, rather than 
the fuel measurements required for larger stationary combustion units. 
Given that this rule has taken steps to avoid burdensome calculations, 
we have concluded that de minimis reporting cutoffs are not necessary.
    Furthermore, de minimis cutoffs would compromise the quality of the 
data collected. The goal of this rule is to collect accurate and 
consistent data of sufficient quality to inform future CAA policy and 
regulatory decisions. Allowing sources to report up to 20,000 metric 
tons CO2e emissions annually using their own simplified 
calculation methods (as allowed under some programs) would impact the 
usefulness of the data. The reported emissions would not be comparable 
across a given industry because the calculation methods, accuracy and 
reliability of a portion of the reported emissions would vary 
substantially from one reporter to another.
    In response to comments, we have made several changes to this rule 
that further reduce any need for a de minimis reporting provision. As 
discussed in Section III of this preamble for individual source 
categories, we have revised monitoring and reporting requirements to 
allow simpler GHG calculation methods for many combustion units and 
other source categories. These changes reduce the reporting burden for 
various types of small emission sources. Also, as noted earlier in 
Section II.D of this preamble, there are a number of source categories 
that are not being finalized at this time. A few of them (e.g., 
industrial landfills and wastewater) represent the type of emission 
sources that commenters referenced as de minimis at some facilities. 
EPA is taking some additional time with these source categories, which 
affects commenters in two ways: (1) Until EPA promulgates a final rule 
for these source categories, these emissions would not be included in a 
facility's annual report and (2) EPA can further consider the comments 
and evaluate our options with respect to the methods for these source 
categories to ensure the methods adequately address our need for high 
quality data as well as recognize the commenters' requests for 
additional flexibility for smaller sources.

L. Summary of Comments and Responses on General Monitoring Approach

    This section contains a brief summary of major comments and 
responses on general monitoring requirements. See sections III.C 
through PP of this preamble for summaries of comments and responses on 
specific monitoring requirements for the individual source categories 
contained in 40 CFR part 98, subparts C through PP. A large number of 
comments were received on general monitoring requirements covering 
numerous topics. Responses to significant comments received can be 
found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, General Montoring Approach, the Need for Detailed 
Reporting, and Other General Rationale Comments.''
    Comment: Many commenters favored the general monitoring approach 
contained in the proposed rule, which is a combination of direct 
emissions measurement and facility-specific calculations. These 
commenters agreed that the selected approach results in high quality 
data and strikes a reasonable balance between data accuracy and cost. 
Other commenters believed that the approach contained in the proposed 
rule is overly stringent and costly. They contended that since the data 
are not being used to demonstrate compliance with a cap and trade 
program or other regulation with emission limits or emissions reduction 
requirements, a lower level of accuracy is acceptable, simpler 
monitoring approaches should be allowed, and/or facilities should have 
flexibility to choose monitoring methods. Some commenters requested 
clarification on whether there were accuracy requirements or 
performance standards for flow monitoring equipment, outside of the 
accuracy requirements already required for CEMS. Some commenters 
requested clarification on whether upgrades to CEMS were needed under 
various circumstances. Some requested additional time for upgrading 
CEMS or installing and calibrating other equipment such as flow meters.
    Response: After reviewing the comments in light of the analysis

[[Page 56280]]

presented in Section IV.H of the preamble to the proposed rule (74 FR 
16474, April 10, 2009), EPA decided not to change the general 
monitoring approach from the proposal. In general, the rule requires 
direct measurement of emissions from certain units that already are 
required to collect and report data using CEMS under other programs 
(e.g., ARP, NSPS, NESHAP, State Implementation Plans (SIPs)). In some 
cases, this may require upgrading existing CEMS that currently monitor 
criteria pollutants to also monitor CO2 or add a volumetric 
flow meter. For facilities with units that do not have CEMS installed, 
reporters have the choice to either install and operate CEMS to 
directly measure emissions or to use facility-specific GHG calculation 
methods. The measurement and calculation methods for each source 
category are specified in each subpart. As policies and programs evolve 
and/or particular calculation or monitoring equipment improves EPA will 
evaluate whether or not to update the methodologies in this rule.
    The data collected by the rule are expected to be used in analyzing 
and developing a range of potential CAA GHG policies and programs. A 
consistent and accurate data set is crucial to serve this intended 
purpose. Therefore, the selected monitoring approach that combines 
direct measurement and facility-specific calculations is warranted even 
though the rule does not contain any emissions limits or emissions 
reduction requirements. EPA remains convinced that this approach 
strikes an appropriate balance between data accuracy and cost. It makes 
use of existing data and methodologies to the extent feasible, and 
avoids the cost of installing and operating CEMS at numerous 
facilities. It is consistent with the types of methods contained in 
other GHG reporting programs (e.g., the California mandatory reporting 
rule, WCI, RGGI, TCR, and Climate Leaders). Because this option 
specifies methods for each source category, it will result in data that 
are comparable across facilities.
    EPA chose not to adopt simplified calculation methods as a general 
monitoring approach (e.g., using default emission factors) because the 
data would be less accurate than under the selected option and would 
not make use of site-specific data that many facilities already have 
available and refined calculation approaches that many facilities are 
already using. EPA is not allowing reporters full flexibility to use 
any method because the accuracy and reliability of the data would be 
unknown. Because consistent methods would not be used under such an 
approach, the reported data would not be comparable across similar 
facilities.
    While the general approach is unchanged, it is important to note 
that EPA has made changes to the General Provisions and to the specific 
monitoring requirements for particular source categories in response to 
public comments on the proposal. EPA has added to the General 
Provisions (40 CFR part 98, subpart A) an accuracy specification of 
plus or minus five percent for the calibration of flow meters used to 
collect data for the emissions calculations under this rule. It 
provides procedures for calculating calibration error, including 
specific procedures for orifice, nozzle, and venturi flow meters. Given 
the comments that were submitted regarding concerns on the timing of 
performing meter calibration, EPA is providing flexibility to reporters 
subject to certain operational limitations. For example, facilities 
that operate continuously may postpone calibration until the next 
scheduled maintenance outage to avoid operational disruptions.
    Individual rule subparts for each source category, rather than the 
General Provisions, contain the specific monitoring methods for that 
source category. Comments received on the specific methods are 
described and responded to in Section III of this preamble and in the 
relevant source category volumes of ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments.'' Where appropriate, 
the final rule has been modified based on those comments. For example, 
since proposal, in response to public comments, EPA has made changes to 
individual subparts of 40 CFR part 98 to clarify when CEMS and CEMS 
upgrades are required and has made other changes to reduce the 
monitoring burden. Interested parties are encouraged to review the 
relevant sections of the preamble and rule. Furthermore, some subparts 
for which significant monitoring approach comments were received are 
not included in the final rule and will be finalized later as explained 
in Section II.D of this preamble. These changes to the rule address 
monitoring approach concerns raised by some commenters.
    Comment: Some commenters expressed concern that duplicative 
reporting would occur if the rule was interpreted to require a reporter 
to submit data on general stationary fuel combustion emissions at a 
facility both under 40 CFR part 98, subpart C and also under one of the 
other source category subparts that applies to the same facility. Some 
of them indicated that language used in the source category subparts to 
reference subpart C was not sufficiently clear and consistent. Other 
commenters indicated the proposed rule was not clear about whether CEMS 
can be used to report combustion emissions, process CO2 
emissions, or combined emissions.
    Response: EPA reviewed each subpart in light of these comments and 
acknowledges that the proposed rule language referencing 40 CFR part 98 
subpart C and the language discussing the of CEMS was inconsistent 
between subparts and was not always clear. EPA has revised the final 
rule to clarify our intent.
    As indicated by the commenters, many manufacturing facilities are 
subject to one of the source category subparts and also to the general 
stationary fuel combustion subpart. For most facilities, emissions from 
stationary fuel combustion sources (e.g., boilers or engines) are 
emitted from separate equipment and through separate stacks/emission 
points than process GHG emissions covered by 40 CFR part 98, subparts E 
through GG. We have edited the rule to make it clear that in such 
cases, the reporter would report stationary fuel combustion emissions 
under 40 CFR part 98, subpart C, and they would report process GHG 
emissions under each applicable source category subpart.
    We have further clarified those source category subparts that 
require reporting of process CO2 emissions. We have made it 
clear that the reporter can elect to monitor and report process 
CO2 emissions by either: (1) Installing and operating CEMS 
and following the Tier 4 methodology in 40 CFR part 98, subpart C, or 
(2) using the source category-specific monitoring and calculation 
procedure specified in the subpart. In either case, process 
CO2 emissions would be reported under the source category 
subpart. The source category subparts have also been revised to specify 
that if process CO2 emissions are comingled with and emitted 
through the same stack as emissions from combustion units or process 
equipment required to use CEMS, than the reporter must use the CEMS and 
follow the Tier 4 methodology to report combined emissions from the 
common stack under the specified subpart. This approach makes sense for 
comingled emissions because CEMS accurately measure total stack 
CO2 emissions and the reporter would not be able to 
accurately separate the fraction of the CO2 emissions that 
came from the combustion units and process emission points that are 
comingled in the same stack.

[[Page 56281]]

    Source categories with direct-fired equipment (e.g., kilns, 
furnaces) present a special situation. Examples include cement 
production, glass production, lead production, lime manufacturing, and 
soda ash manufacturing. In direct-fired units, fuel combustion 
emissions and process emissions are both generated within the kiln or 
furnace and are always emitted together. If CEMS are used on such 
units, the CEMS will always be measuring combined combustion and 
process emissions. The language regarding CO2 reporting and 
use of CEMS for these source categories has been clarified and 
harmonized to reflect this situation.
     For kilns or furnaces in these source categories that have 
CEMS in place and meet specified conditions, the reporter must use the 
CEMS and follow Tier 4 methodology to determine combined process and 
combustion CO2 emissions. The combined emissions are 
reported under the relevant source category subpart (e.g., for cement 
production, combined combustion and process emissions from a kiln with 
a CEMS would be reported under 40 CFR part 98, subpart H, Cement 
Production).
     For other kilns or furnaces in these source categories, 
the reporter has the choice to (1) install and operate CEMS to measure 
combined process and combustion CO2 emissions, or (2) 
calculate process CO2 emissions using the source category-
specific monitoring and calculation procedures contained in the 
subpart. If reporters don't have CEMS and choose the source category-
specific calculation approach, then they report process CO2 
emissions under the relevant source category subpart, and report 
combustion emissions under 40 CFR part 98, subpart C (general 
stationary fuel combustion).
    See the sections for the relevant source categories in Section III 
of this preamble for summary and discussion of the specific monitoring 
and reporting requirements for each source category.

M. Summary of Comments and Responses on General Recordkeeping 
Requirements

    This section contains a brief summary of major comments and 
responses on the general recordkeeping requirements contained in the 
general provisions (40 CFR part 98, subpart A). See sections III.C 
through PP of this preamble for summaries of comments and responses on 
specific recordkeeping requirements for the individual source 
categories contained in 40 CFR part 98, subparts C through PP. A large 
number of comments were received on general recordkeeping requirements 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart A, Content of the Annual Report, 
the Abbreviated Emission Report, Recordkeeping, and the Monitoring 
Plan'' and in the individual source category volumes of ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments.''
1. Record Retention
    Comment: Several commenters suggested that EPA require retention of 
records for three years rather than the five years specified in the 
proposed rule. Some of these commenters stated that three years is 
consistent with ARP, which is a comparable program that requires 
electronic reporting of similar, detailed data. Many contended that 
retaining the large amount of data required by this rule for five years 
rather than three years is overly burdensome and is not necessary. They 
indicated that three years of records is sufficient to allow 
verification of annual GHG reports. A smaller number of commenters 
supported record retention for five years, which is consistent with 
permitting and other programs.
    Response: In response to public comments, EPA has changed the 
record retention requirement in the final rule from five years to three 
years.\19\ We agree that a 3-year time period is sufficient to allow 
for EPA audit and review of records needed to verify the emissions data 
submitted in annual reports. Changing the record retention duration to 
three years will reduce the recordkeeping burden for many facilities 
reporting under this rule. As stated by various commenters, a 3-year 
record retention requirement would be consistent with the recordkeeping 
provisions of the ARP and other Federal reporting programs, including 
the TRI rules and the DOE Energy Information Administration's 1605(b) 
Voluntary Reporting of GHG Emission and Reductions program.
---------------------------------------------------------------------------

    \19\ As described earlier in this section, facilities or 
suppliers that have emissions or products with emission less than 
25,000 metric tons CO2e for five years in a row may cease 
reporting. Those that cease reporting must have records to cover 
those five years of emissions. Similarly, reporters who demonstrate 
emissions less than 15,000 metric CO2e for three years is 
a row may cease reporting, and must have records to cover those 
three years of emissions.
---------------------------------------------------------------------------

2. Monitoring Plan
    Comment: We received several comments on the QAPP recordkeeping 
requirement in proposed 40 CFR 98.3(g). Some had questions about the 
content and level of detail required in the QAPP, and indicated it 
would be a costly and burdensome requirement. Others stated that the 
QAPP would be duplicative of their facility SOPs or documentation kept 
under ARP or other programs. Some commenters indicated that the list of 
items to report in 40 CFR 98.3(g) was repetitive because a few of the 
items listed separately would typically be contained in a QAPP.
    Response: The final rule requires a ``monitoring plan.'' The 
``QAPP'' terminology in the proposed rule caused confusion because 
``QAPP'' is used in a variety of other contexts, has various 
connotations to different readers, and caused readers to presume 
requirements EPA did not intend. The final rule specifies monitoring 
plan contents such as:
     Identification of persons responsible for collecting 
emissions data.
     Explanation of the processes and methods used to collect 
the necessary data for the GHG emissions calculation.
     Description of the procedures that are used for QA, 
maintenance, and repair of all CEMS, flow meters, and other 
instrumentation used to provide data for the GHG emissions reported 
under 40 CFR part 98.
    The first two items in this list were formerly listed as separate 
line items in the recordkeeping requirements, but would logically be a 
part of the monitoring plan, so were consolidated under the monitoring 
plan to avoid repetition.
    The monitoring plan paragraph in the final rule explicitly states 
that the monitoring plan can rely on references to existing corporate 
documents. Such documents include SOPs, QA programs under Appendix F to 
40 CFR part 60 or Appendix B to 40 CFR part 75, and other documents 
provided that the information required by the monitoring plan is 
clearly recognizable. The provision allowing the monitoring plan to 
refer to such documents avoids duplicative effort and addresses the 
commenters' concerns that monitoring plan information is already 
contained in other documents.
    The final rule also contains a provision to update the monitoring 
plan. Reporters need their monitoring plan to be up to date in order to 
ensure that facility or supplier personnel follow the right monitoring 
and QA procedures and that the reporter meets the requirements of the 
reporting rule. Likewise, EPA needs to be able to view an up-to-date 
monitoring plan during facility audits. Updates to the plan would be 
needed if, for example, the facility makes a process change, changes 
monitoring instrumentation or QA

[[Page 56282]]

procedures, or improves procedures for maintenance and repair of 
monitoring systems to reduce the frequency of monitoring equipment 
downtime.

N. Summary of Comments and Responses on Emissions Verification Approach

    This section contains a brief summary of major comments and 
responses on emissions verification of the GHG reports. A large number 
of comments were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Approach to 
Verification and Missing Data.''
    Comment: Many commenters, including most facilities and suppliers 
required to report under the rule and several other stakeholders, 
supported EPA's proposal to require self-certification with EPA 
verification of GHG reports. These commenters provided a variety of 
reasons. Many supported EPA emissions verification because the 
alternative of third party verification would be more costly to 
reporters. Several also commented that EPA emissions verification would 
provide a consistent and transparent data set.
    Other commenters suggested that EPA require third party 
verification of GHG reports, and they provided a variety of reasons. A 
few noted that third party verification is consistent with other GHG 
reporting systems (e.g., the European Emissions Trading Scheme, The 
Climate Registry, the California mandatory GHG reporting rule, and 
other State programs). Many stated that third party emissions 
verification will improve the quality of the data submittals and told 
us that third party verification led to the correction of inaccuracies 
in GHG emission reports submitted under other programs. Some of the 
commenters questioned whether EPA would have the time to conduct 
verification, given the number of reports and volume of supporting data 
that must be submitted. Others were concerned that EPA verification 
requires submittal of detailed supporting data and contended that some 
of these supporting data would be CBI.
    A smaller number of commenters favored self-certification without 
independent emissions verification. They believed the designated 
representative provisions in the rule would cause reporters to take 
self-certification seriously and ensure the emissions they report are 
correct. Some also stated that independent verification is not needed 
for a reporting program that does not require emissions reductions.
    Response: In selecting the approach to emissions verification, EPA 
reviewed all of the comments, as well as emissions verification 
requirements and procedures under a number of existing EPA regulatory 
programs and domestic and international GHG reporting programs. Based 
on this review, EPA considered three alternatives: (1) Self-
certification without independent verification, (2) self-certification 
with third party verification, and (3) self-certification with EPA 
verification. For this particular program, EPA is not changing the 
verification approach from the proposal and is requiring self-
certification with EPA emissions verification. We decided to retain 
this verification approach because it provides greater assurance of 
accuracy and impartiality than self-certification without verification, 
and has a number of advantages over third party verification for this 
type of Federal program. Our objective with emissions verification in 
this program is to ensure collection and dissemination of high-quality 
data while providing the reporters a ``level playing field'' in terms 
of requirements and process.
    To enable effective review of the large volume of data reported, 
the rule requires reporters to submit data electronically in a standard 
format through a centralized data system. EPA is developing this system 
and intends to make it available to reporters, along with training and 
instructional materials, before the reporting deadlines. To the extent 
possible, EPA will leverage existing reporting systems and work with 
other State and regional programs and systems to develop a reporting 
scheme that minimizes the burden on reporters.
    In implementing the emissions verification under this rule, EPA 
envisions a two step process. First, we will conduct an initial 
centralized review of the data which will be largely automated. EPA 
intends to build into the data system an electronic data QA program for 
use by reporters and EPA to help assure the completeness and accuracy 
of data. In addition, to verify reported data and ensure consistency, 
EPA may review facility-level monitoring plans and procedures, and will 
perform detailed, automated checks on data utilizing recent and 
historical data submittals, comparison against like facilities and/or 
other electronic audit tools where appropriate. Second, EPA intends to 
follow-up with facilities should potential errors, discrepancies, or 
questions arise through the review of reported data and conduct on-site 
audits of selected facilities. The on-site audits may be conducted by 
private verifiers contracted by EPA or by Federal, State or local 
personnel, as appropriate. We plan to coordinate closely with the 
States to develop an efficient approach toward on-site auditing that 
can meet the needs of multiple programs. We do not anticipate 
conducting on-site audits of every facility every year.
    EPA decided to finalize the rule with EPA emissions verification 
for several reasons. First, we determined that the combination of 
comprehensive electronic review and a flexible and adaptive program of 
on-site auditing will enable us to effectively target verification 
resources while also providing the necessary consistency and quality in 
the data. Utilizing the national data set developed under this rule 
will provide unique resources for the review of reports. A centralized 
emissions verification system provides greater ability for EPA to 
identify trends and outliers in data and thus assist with targeted 
follow-up review, and our approach can evolve over time as we gain 
experience with GHG reporting. This approach also provides opportunity 
to work closely with and leverage both the experience and ongoing 
activities of States and others already engaged in similar and 
different types of GHG reporting.
    Our emissions verification approach in this rule is consistent with 
other EPA emission reporting programs and follows a model similar to 
the ARP which is a highly successful emissions cap and trade program 
that consistently produces credible, high-quality data. Facilities 
regulated under ARP must have a Designated Representative sign data 
reports to self-certify that the reported data are accurate. Then, 
facilities and EPA use a series of electronic tools to ensure proper 
data collection and reporting, including establishing a monitoring 
plan, calibrating equipment to certain specifications, frequent testing 
and data submittal. Similar to what we are intending with this program, 
EPA conducts site audits on those facilities targeted during the 
electronic review as having been outliers or had anomalies in their 
reported data. These audits are done by EPA personnel, States and/or 
contractors to EPA. We support these audits by providing a field audit 
manual to both government and private auditors as well as additional 
training to State and Federal auditors.
    Second, this approach is the best way to address the many comments 
we received on the importance of obtaining 2010 data and making the 
data widely available. EPA has determined that this

[[Page 56283]]

verification approach will enable us to make data available more 
quickly than under a third party verification approach. We will be able 
to share a complete data set promptly upon completion of the electronic 
review (subject to relevant CBI concerns, please see the discussion of 
our plans to address CBI and emissions data in Section II.S of this 
preamble and ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Legal Issues''). We determined that the third party 
verification approach could take from three to six months after initial 
data submission, and EPA would still need to review and perform 
consistency checks after the third party verification was complete.
    In addition, developing the third party verification approach would 
require EPA to establish and develop emissions verification protocols 
and a system to qualify and accredit the third party verifiers, and to 
develop and administer a process to ensure that verifiers hired by 
reporting facilities do not have conflicts of interest. Such a program 
could require EPA to review numerous individual conflict of interest 
screening determinations made each time a reporter hires a third party 
verifier. Even if EPA were to partner with an existing program or 
organization to accredit verifiers, EPA would still need to develop the 
criteria and systems described above to implement this rule and ensure 
high quality emissions verification given the unique reporting 
requirements of this rule. These efforts would slow down implementation 
of the rule and sharing of data.
    Finally, we agree with many of the commenters regarding their 
concerns about the cost of third party verification. Given the 
information currently available to us, under a third party verification 
approach we would have required that each facility verify its 
submission each year. As a national reporting program with a 
substantially larger number of reporters than existing State programs, 
we determined that the costs to the reporters of third party 
verification would have been substantial. By finalizing self-
certification with EPA emissions verification for this rule, it also 
ensures a lower cost burden for reporters.
    EPA's decision to use self certification with EPA emissions 
verification was made in the context of the specific scope of this 
rulemaking, the types of data to be collected, and the intended uses of 
the emissions data. For other types of programs (e.g., offsets, 
corporate footprinting, energy efficiency) other verification 
approaches may be more suitable. We recognize that many GHG reporting 
and reduction programs developed by the States and Regions are broader 
in scope and for this and other reasons, the use of third party 
verifiers is an appropriate way to verify the data they collect. EPA's 
decision in this rulemaking does not preempt State GHG reporting 
programs or any other programs from requiring third party verification. 
More importantly, the selection of EPA emissions verification for this 
rule is not intended to suggest that third party verification cannot 
result in accurate, high quality data.
    EPA received a smaller number of comments in support of self-
certification without emissions verification. While recognizing that 
this approach would place a low burden on both reporters and the 
government, it also has major disadvantages. Without any verification 
of submitted reports, there is far greater potential for inconsistent 
and inaccurate data and this will result in less confidence at EPA and 
with public stakeholders in the data. These disadvantages would make 
the data collected under this option less useful for informing 
decisions on climate policy and supporting the development of potential 
future policies and regulations.
    Comment: Commenters asked what role State and local regulatory 
agencies will have in verification of reported emissions data. Some 
suggested that State and local agencies should assist with emissions 
verification because they already have detailed knowledge of the 
facilities in their areas. Some indicated that States would need 
resources to play a role in verification and other rule implementation 
activities.
    Response: While EPA is responsible for emissions verification as 
explained in the previous response, EPA will likely enlist State 
assistance, when it is available, during the implementation phase of 
the final rule. (However, State and local agencies will not be required 
to provide EPA any assistance with verification or implementation 
activities, given State and local agency resource constraints and 
priorities.) For example, in concert with their routine inspection and 
other compliance and enforcement activities for other CAA programs, 
State and local agencies could, as resources allow, assist with 
educating facilities and assuring compliance at facilities subject to 
this rule.
    Assistance from State and local agencies could include such 
activities as identifying the facilities for on-site audits or 
conducting audits where appropriate. This type of assistance from State 
and local governments has been valuable in other programs. State and 
local air pollution control agencies routinely interact as part of 
other regulatory programs with many of the sources that would report 
under this rule. States have knowledge of specific facilities and 
sources that would be required to report under this rule. In addition, 
many States have already implemented or are in the process of 
implementing GHG reporting and reduction programs. Therefore, some 
State and local agencies could serve a role in communicating the 
requirements of the rule and providing compliance assistance.

O. Summary of Comments and Responses on the Role of States and 
Relationship of This Rule to Other Programs

    This section contains a brief summary of major comments and 
responses. A large number of comments on the relationship between this 
rule and other programs were received covering numerous topics. 
Responses to significant comments received can be found in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Relationship to Other GHG Reporting Programs'' and ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Legal 
Issues.''
    Comment: Several commenters requested that EPA make it clear that 
States can collect additional GHG data under State rules and GHG 
programs and are not limited to collecting only the data in this 
Federal mandatory reporting rule. Other commenters requested that this 
rule preempt or supersede State GHG reporting rules.
    Response: EPA reaffirms that States can collect additional data 
under State rules and GHG programs, and that this rule does not preempt 
or replace State reporting programs. This rule has been developed in 
response to a specific request from Congress (in the Appropriations 
Act) and is narrower and more targeted than many existing State 
programs that are coupled with GHG emission reduction programs. As EPA 
stated in Section II of the proposal preamble (74 FR 16457, April 10, 
2009) and Section I.E of this preamble, many State programs are broader 
in scope, in a more advanced state of development, and have different 
policy objectives than this rulemaking. These are important programs 
that not only led the way in reporting of GHG emissions before the 
Federal government acted but also have catalyzed important GHG 
reductions.

[[Page 56284]]

    EPA supports and recognizes the success and necessity of State 
programs as a vital component in achieving GHG emissions reductions, 
particularly those focused on energy efficiency improvements. It is 
appropriate that State and regional GHG reporting and reduction 
programs have different scopes or implementation schedules, and that 
they require reporting of different information than this rule for 
various program-specific reasons. For example, some State programs 
might require reporting of electricity purchases and other data to 
provide information for energy efficiency programs; they may require or 
allow reporting of a variety of indirect emissions to gather data to 
help facilities reduce their carbon footprint; they may require or 
allow reporting of emissions such as from fleet vehicles to encourage 
fleet operators to take steps to reduce emissions; or they may be 
developing or implementing GHG reduction rules including cap and trade 
programs, and require specific information on emissions and offsets to 
implement those programs. State programs already have, or may evolve to 
include, additional monitoring and reporting requirements than those 
included in this rule. Many States are actively collecting additional 
data they need for their programs and policies, and this reporting rule 
does not preempt State programs.
    Comment: Some commenters were concerned that the Federal GHG 
reporting rule will result in duplicative reporting for facilities that 
are also reporting GHG emissions under State rules or voluntary GHG 
reporting programs. Some requested that to reduce burden, facilities 
should be required to submit data only once, and not have to submit 
different data to multiple different programs. Some commenters strongly 
recommended that the electronic data systems used by this reporting 
rule and other programs need to be consistent and allow data exchange 
between this rule and TCR, State rules, National Emissions Inventory 
(NEI), ARP, or other programs. Many commenters supported submittal of 
all data directly to EPA, while others favored delegation of data 
collection to State agencies to encourage consistency between State and 
Federal data collection efforts.
    Response: EPA carefully considered the issue of State delegation, 
particularly in light of the leadership and experience of several 
States in developing GHG reporting and reduction programs, and also in 
the context of the pressing need for a national reporting program and 
the strong emphasis placed by the vast majority of the commenters on 
this rule for EPA to ensure that data collection begins on January 1, 
2010 and that data are reported early in 2011. We determined that 
developing a program to delegate to States would take additional time 
and would not be available for 2010 reporting, and we also determined 
that a significant number of States would likely not request 
delegation, which would increase the complexity of assembling a 
consistent national data set. For these reasons, we determined that the 
most effective way to achieve nationwide GHG reporting of 2010 data was 
for reporters to submit data directly to EPA, as proposed. Additional 
reasons for selection of this data flow approach are described in the 
response on emissions verification in Section II.N of this preamble, 
the responses on collection, management, and dissemination of GHG 
emissions data in Section V of this preamble, and the responses on 
compliance and enforcement in Section VI of this preamble.
    While EPA is not formally delegating rule implementation and 
enforcement to States, we are committed to working in partnership to 
address the issues expressed in their comments on interaction between 
State and Federal reporting programs. Design and implementation of 
electronic systems for data systems has been an area of particular 
focus in determining how to ease reporting burdens and facilitate use 
of the many different types of data collected by State and Federal 
reporting programs by all levels of government.
    EPA is committed to working with States to develop electronic 
reporting tools that can both collect and share data in an efficient 
and timely manner. At this time, EPA is in the process of developing 
the reporting format and tools and therefore has not specified the 
exact reporting format, other than it will be electronic, in order to 
maintain flexibility to modify the reporting format and tools in a 
timely manner. To the extent possible, EPA will work with existing 
reporting programs and systems to develop a reporting scheme that 
minimizes the burden on sources.
    EPA recognizes the need to develop reporting tools that can support 
reporting across programs that collect different types of data, and we 
intend to coordinate with States and other organizations to explore 
development of shared web-based tools that can simplify and expedite 
reporting. We recognize that State and regional programs may be 
collecting additional GHG information beyond what is required in this 
rule. For example, many of these programs collect emissions data on 
fleet vehicles, indirect emissions data for utility purchase, and other 
data not required by the Federal rule. Moreover, our rule requires 
reporting of additional data necessary for emissions verification, 
which is likely more expansive than what many existing State and 
regional programs are collecting. For example this rule requires 
reporting of emissions at the process or unit level for many source 
categories, rather than the company or facility level as allowed by 
various other mandatory and voluntary reporting programs. We will also 
collect detailed monitoring data and activity data used to calculate 
emissions, which will enable emissions verification. We are interested 
in working with others to determine the extent to which shared tools 
can be designed to facilitate reporting across multiple programs, 
consistent with obligations regarding CBI.
    EPA carefully reviewed Federal, State, and international voluntary 
and mandatory programs during development of the reporting rule and 
attempted to be consistent with the GHG protocols and requirements 
within these rules, to the extent feasible given the differing scopes 
and policy objectives. (See Section II of the preamble for the proposed 
rule (74 FR 16457, April 10, 2009), the Review of Existing Programs 
memorandum (EPA-HQ-OAR-2008-0508-052), and the memorandum summarizing 
State mandatory rules (EPA-HQ-OAR-2008-0508-054).) EPA has worked with 
and will continue to coordinate closely with other Federal, State, and 
regional programs to facilitate data exchange when designing the data 
reporting systems that will be used for the rule and planning 
implementation activities. We will work with the States, TCR, and 
others on data exchange standards to ease sharing of data between 
systems, consistent with CBI obligations. And finally, we see 
substantial opportunities for EPA and States to cooperate on strategic 
efforts to identify uses of the data collected under this rule and work 
together on a broad array of climate change issues.

P. Summary of Comments and Responses on Other General Rule Requirements

    This section contains a brief summary of major comments and 
responses on other general rule requirements. A large number of other 
general comments were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's

[[Page 56285]]

Response to Public Comments'' volumes on subpart A.
1. Research and Development
    Comment: Commenters representing institutions and industries 
subject to the reporting rule requested an exclusion for R&D 
activities. They noted that the aluminum production and glass 
production subparts of the proposed rule excluded R&D process units, 
but requested that R&D be excluded from the rule as a whole, not only 
from the two subparts. Some also commented that the exclusion should 
encompass R&D activities other than R&D process units, including bench 
scale laboratory research and pilot plants. Commenters pointed out that 
many other EPA air rules exclude R&D and they explained that R&D 
activities are small-scale, emissions change frequently as the focus 
and scope of the R&D activity changes, reliable information on 
CO2e emissions during any particular phase of the research 
might not be available, and quantifying R&D emissions would impose a 
high burden relative to the quantity of emissions.
    Response: In response to these public comments, EPA has added an 
R&D exclusion in 40 CFR 98.2(a)(5) stating that R&D activities are not 
considered to be part of any source category defined in 40 CFR part 98. 
Because R&D activities are not included in any source category, their 
GHG emissions are not reported. EPA agreed with the commenters that R&D 
process units and laboratory R&D for new processes, technologies, or 
products should be excluded. It is not reasonable to calculate GHG 
emissions from processes and activities that continually change as the 
research focus changes and have highly variable inputs and operating 
conditions due to their R&D nature. Also, emissions from R&D are 
expected to be small. Therefore, the final rule defines R&D as 
activities conducted in process units or at laboratory bench scale 
settings whose purpose is to conduct R&D for new processes, 
technologies, or products, and whose purpose is not for the manufacture 
of products for commercial sale, except in a de minimis manner.
    We point out that the exclusion applies to each individual R&D 
activity that meets the R&D definition, not to an entire facility as a 
whole. For example, a facility that has some commercial process units 
and some R&D process units can exclude only the R&D process units. A 
facility that meets the applicability criteria in 40 CFR part 98, 
subpart A and contains general stationary combustion sources must 
report emissions from the combustion units, even if the steam, heat, or 
electricity generated by a combustion unit is used in an R&D process 
unit. Laboratory activities are excluded only if they are for R&D 
purposes. Laboratory analyses activities conducted for commercial 
purposes, process operating purposes, or to comply with a rule would 
not be excluded.
    We decided not to include pilot plants in the definition of R&D. 
Pilot plants that meet the rule applicability criteria must report 
their GHG emissions. Pilot plants tend to be relatively large in scale 
compared to the excluded R&D activities. Because pilot plants are 
designed to prove the viability of a particular process or technology 
rather than to research a wide range of processes and products, their 
operations and emissions are more consistent than the excluded R&D 
activities. Pilot plants also tend to be operated for relatively long 
periods of time and in some cases are converted to commercial 
facilities. For these reasons, EPA views the data as more useful and 
has not applied the R&D exclusion to pilot plants.
2. Determining Applicability
    Comment: Some commenters were concerned that the GHG reporting rule 
will virtually require every commercial and industrial facility to 
collect fuel usage data and perform relatively complex calculations, 
and in some cases modeling, in strict accordance with the prescribed 
monitoring methodologies and emissions calculation procedures, to 
determine if they are subject to the rule. The commenters added that 
this will be burdensome, especially for small sources that will just be 
documenting that the calculated GHG emissions from the facility are 
well below the reporting threshold. They also indicated that 
recordkeeping would be needed to show that facilities are below the 
reporting threshold, and anticipated that the rule will be nearly as 
burdensome on facilities that do not have to report, as on those that 
must report. Many of the commenters asked that EPA provide simplified 
source category thresholds to determine applicability, like the 30 
mmBtu/hr aggregate maximum rated heat input capacity for stationary 
fuel combustion units, to reduce the burden on the majority of 
facilities making applicability determinations.
    Response: We disagree that the initial applicability determination 
process is burdensome. While the rule requires reporters who are 
subject to the rule to determine applicability using the calculation 
procedures required in the rule, the rule does not contain any 
requirements for facilities that are not subject to the rule. 
Therefore, the rule does not necessarily require monitoring in 2010 to 
determine applicability. To determine applicability, anyone who 
believes their facility might be subject to the rule could start by 
calculating emissions using the relevant equations provided in each 
applicable subpart along with the available data from company records 
and the likely operating scenario for the reporting year that would 
lead to worst case GHG emissions. For example, for the input parameters 
needed for the equations, use the 2010 production goals from the 
company's business plan, company records, process knowledge, 
engineering judgment, and vendor data (e.g., vendor information could 
be used to estimate the carbon content of feedstocks, using the highest 
likely carbon content of those feedstocks.) EPA expects that for most 
facilities, emissions calculated in this manner are likely to be 
significantly above or below the 25,000 metric ton CO2e per 
year threshold, such that most potential reporters can determine their 
applicability to the rule solely using the available data.
    For those facilities with estimated emissions that are near the 
25,000 tons/year threshold using available data, the company will have 
to make the decision on whether to install monitoring equipment to 
calculate emissions during the 2010 reporting year for purposes of 
determining applicability and/or reporting emissions. It is in a 
facility's interest to collect the GHG data required by the rule if 
they think they will meet or exceed the applicability criteria in 40 
CFR 98.2 by the end of the year. EPA anticipates that relatively few 
potential reporters will face uncertainty in making this decision.
    Given the large number of industrial and commercial facilities 
potentially subject to the rule due to stationary fuel combustion 
emissions, EPA has provided in 40 CFR 98.2 simplified procedures for 
calculating emissions from fuel combustion. These facilities may first 
assess applicability based on the aggregate heat input capacity of all 
their fuel combustion units. Per 40 CFR 98.2(a)(3), facilities with an 
aggregate maximum rated heat input capacity of less than 30 mmBtu/hour 
are automatically not covered under the rule, because emissions of 
CO2e will be less than 25,000 metric tons of CO2e 
per year in all cases. If a facility is not below the 30 mmBTU/hour 
cutoff, the next logical step to determine applicability is to use any 
of the four calculation methods provided in subpart C, as allowed by 40 
CFR 98.2(b). The simplest of the four methods requires determination of 
only one parameter--

[[Page 56286]]

annual fuel use. Most companies already record fuel use, and can use 
this to calculate emissions and determine applicability.
    To assist facilities in determining applicability, EPA plans to 
provide implementation guidance with simplified means to determine 
applicability. For combustion sources, EPA plans to publish tables that 
will specify by fuel type both an annual fuel consumption level and 
maximum heat input capacity that correlates with emissions of 25,000 
metric tons per year of CO2e. For non-combustion source 
categories with a 25,000 metric ton CO2e threshold, EPA 
plans to publish guidance, as feasible, on equipment capacities, 
production levels, or other parameters that correlate with emissions of 
25,000 metric tons per year of CO2e. The capacity and 
production levels provided in these tables would be based on worst-case 
assumptions, but would allow facilities to quickly and easily determine 
if they need to develop more precise estimates or plan to implement 
monitoring in 2010.

Q. Summary of Comments and Responses on Statutory Authority

    This section contains a brief summary of some major comments and 
responses. A large number of comments on statutory authority were 
received covering numerous topics. This section will highlight only two 
of the key categories of comments. Additional discussion on these 
comments and others can be found in the comment response documents.
    Responses to significant comments received can be found in 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Legal Issues''.
    Comment: EPA received numerous comments on whether the CAA or the 
FY 2008 Consolidated Appropriations Act authorized the rule. Some 
commenters argued that EPA was required to issue the reporting rule 
under the authority created by the Appropriations Act, not the CAA. 
Others argued that the Appropriation Act could not create new 
authority, and therefore either (1) EPA had to rely on the CAA, or (2) 
EPA was not authorized to issue the rule at all.
    Response: As noted above, EPA is relying on the authority provided 
in the CAA, not the Appropriations Act, for this final rule. While the 
Appropriations Act required that EPA spend a certain amount of money on 
a rule requiring mandatory reporting of GHG emissions, the authority to 
gather such information already existed in the CAA. Indeed, EPA could 
have promulgated this rule in the absence of the Appropriations Act. 
Thus, the comments about the inability of an appropriations law to 
create new legal authority are inapposite to this rulemaking.
    Comment: Commenters opined on whether the statute in question 
(either the Appropriations Act or the CAA) contained sufficient 
authority for various elements of the rule, ranging from broad issues 
like the scope and duration of the rule as a whole, to more specific 
issues related to particular source categories covered, and specific 
monitoring, recordkeeping and reporting requirements.
    Several commenters argued that the appropriations language 
contained limitations on the scope of the rule EPA could promulgate, 
regardless of the underlying authority for the rule. For example, some 
commenters contended that because the appropriations were for a single 
fiscal year, EPA was authorized to promulgate only a one-time data 
collection. Others argued that the Appropriations Act authorized the 
collection solely of GHG emissions, and not any of the additional data 
elements related to verification of emissions data.
    As for the CAA, some commenters questioned whether section 114 
authorized a broad reporting rule, as opposed to the targeted 114 
information requests used by EPA in the past. Many commenters 
questioned whether EPA had adequately linked the requirements of the 
reporting rule to particular provisions of the CAA that EPA was 
carrying out. Others questioned EPA's general ability to gather 
information about GHGs before it had made an endangerment finding and/
or regulated GHGs under the CAA.
    Not all comments were negative. Some commenters supported EPA's 
interpretation of the CAA, and agreed that it authorized the proposed 
reporting rule.
    Response: We disagree that the language in the Appropriations Act 
limited EPA's authority for this rule. First, the Environmental 
Programs and Management (EP&M) funds Congress appropriated for the GHG 
reporting rule are available for two fiscal years as are the funds EPA 
historically has used for most other Agency rules. The fact that the 
appropriations EPA uses to develop rules are available for specified 
fiscal years does not mean that the effectiveness of the rules is 
limited by the same period of time that the funds are available. 
Moreover, as noted above, EPA is issuing this rule under the authority 
of the CAA, and indeed EPA could have issued this rule absent the 
direct instruction from Congress to spend at least a certain amount of 
money on a mandatory GHG reporting rule. Thus, we do not agree that the 
appropriations language limited EPA's ability to collect the 
information under this rule, either in duration or scope of the 
information requested.
    Regarding the scope of the rule, while it is true that EPA has used 
section 114 in a more targeted fashion in the past, there is nothing in 
the CAA that so limits our ability. EPA is undertaking a comprehensive 
evaluation of GHGs under the CAA and hence, is issuing a comprehensive 
reporting rule.
    Moreover, as noted above, CAA sections 114 and 208 authorize EPA to 
gather the information under this rule, which will prove useful to EPA 
in carrying out numerous provisions of the CAA. This final rule imposes 
requirements on direct sources of GHG emissions. These sources are 
clearly persons from whom the Administrator may gather information 
under CAA section 114, as long as that information is for purposes of 
carrying out any provision of the CAA. As discussed further in 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Selection of Source Categories to Report and Level of 
Reporting'' and ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Legal Issues,'' the information provided 
by direct emitters will prove invaluable to the Agency in several 
areas, including the evaluation of the appropriate action to take under 
section 111 regarding NSPS, and the investigation into non-regulatory 
strategies to encourage pollution prevention pursuant to section 
103(g). For example, the Agency currently has pending before it a court 
remand, comments in an ongoing rulemaking, a petition for 
reconsideration, notices of intent to sue and litigation regarding 
EPA's treatment of GHGs under section 111.
    The requirements applicable to manufacturers of mobile sources are 
authorized by section 208 because they will help inform various options 
regarding the regulation of these sources under title II of the CAA. 
The Agency currently has pending before it several petitions requesting 
that the Agency regulate emissions from a variety of mobile sources, 
including motor vehicles, aircraft, nonroad engines and marine engines.
    Finally, the final rule also gathers information from upstream 
suppliers of industrial GHGs and fossil fuels (except for suppliers of 
coal). The information gathered from suppliers of fossil fuels, in 
particular petroleum products, is relevant to an evaluation of possible 
regulation of fuels under title II of the

[[Page 56287]]

CAA, as well as for potential efforts to address GHG emissions at 
downstream sources. Information from suppliers of industrial GHGs is 
relevant to understanding the quantities and types of gases being 
supplied to the economy, in particular those that could be emitted 
downstream which will aid in evaluating action under CAA section 111 as 
well as various sections of title VI (e.g., 609 and 612) that address 
substitutes to ozone depleting substances (ODS). Additional discussion 
on this issue is available in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Selection of Source Categories 
to Report and Level of Reporting'' and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues.''
    Finally, we disagree with commenters who argue that we cannot use 
CAA sections 114 of 208 to gather information on a pollutant until we 
have issued an endangerment finding for that pollutant, or actually 
decided to regulate it under the CAA. The statute is not so inflexible. 
\20\ For example, the information collected under sections 114 and 208 
could inform the contribution element of endangerment determinations 
(e.g., whether emissions from the relevant sector contribute to air 
pollution which may reasonably be anticipated to endanger public health 
or welfare). Similarly, information gathered under these sections could 
inform decisions on whether to regulate a pollutant or source category. 
Commenters' interpretation would prevent EPA from gathering information 
that could be critical to key decisions until after those decisions are 
made. EPA does not agree with, and will not adopt, such an 
interpretation.
---------------------------------------------------------------------------

    \20\ We note that the statute is ambiguous, and thus EPA may 
adopt any reasonable interpretation. See Chevron v. NRDC et al., 467 
U.S. 837, 864 (1984).
---------------------------------------------------------------------------

    Thus, as discussed in more detail above and in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, Legal 
Issues,'' EPA has adequate authority to issue this rule.

R. Summary of Comments and Responses on CBI

    This section contains a brief summary of major comments and 
responses on CBI issues. A large number of comments were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Legal Issues.''
    Comment: EPA received numerous comments addressing the issue of 
CBI. Industry commenters generally expressed concern that much of the 
information reported under this rule would be CBI (e.g., production and 
process data). Many commenters also presented arguments regarding why 
certain information would not be ``emissions data'' under the CAA. 
Among the various recommendations were that the final rule (i) not 
require the reporting of such information at all, (ii) require only 
that the source maintain such information on site, but not report it to 
EPA, and/or (iii) clearly state that some classes of information are 
CBI. Some commenters expressed concern about EPA's ability to maintain 
the confidentiality of CBI, and thus suggested that EPA should provide 
further detail regarding how we will protect CBI from disclosure. The 
agricultural industry expressed particular concerns about making 
information about the location of facilities public due to concerns 
about biosecurity and other potential threats. Other commenters favored 
the wide dissemination of information, and argued that the information 
gathered under this rule should be ``emissions data'' and hence not 
protected as CBI.
    Response: As discussed in Section II.N of this preamble, EPA is 
finalizing its proposal that EPA verify the information collected by 
this rule. Data regarding inputs into emissions calculations and 
monitoring are critical elements of that verification process. Because 
EPA will routinely need this data in order to verify the information 
collected under this rule, we are not adopting the recommendation that 
sources maintain such information on site and only provide it during an 
inspection or when otherwise specifically requested.
    EPA also recognizes the importance of this issue to both reporters 
and the public. EPA's public information regulations contain a 
definition of ``emissions data'' at 40 CFR 2.301, and EPA has discussed 
in an earlier Federal Register notice what data elements constitute 
emissions data that cannot be withheld as CBI (56 FR 7042-7043, 
February 21, 1991). We further recognize that while determinations 
about whether information claimed as CBI meets the definition of CBI, 
as well as whether it meets the definition of emissions data, are 
usually made on a case-by-case basis, such an approach would be 
cumbersome given the scope of this rule and the potential 
inconsistencies across reporters and source categories and the 
compelling need to make data that are not CBI, or are emissions data, 
available to the public. For this reasons, EPA intends to undertake an 
effort similar to what was done in 1991 for the data elements collected 
in this rule. Through a notice and comment process, we will establish 
those data elements that are ``emissions data'' and therefore will not 
be afforded the protections of CBI. As part of that exercise, in 
response to requests provided in comments, we may identify classes of 
information that are not emissions data, and are CBI. EPA plans to 
initiate this effort later this year, or in early 2010. We will 
consider the comments received on this issue as part of that notice and 
comment process.
    As stated in the proposed rule, EPA will protect any information 
claimed as CBI in accordance with regulations in 40 CFR part 2, subpart 
B. As we noted previously however, in general the CAA prohibits the 
treatment of emission data collected under CAA sections 114 and 208 as 
CBI.

S. Summary of Comments and Responses on Other Legal Issues

    This section contains a brief summary of major comments and 
responses on other legal issues. A large number of other legal issue 
comments were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Legal Issues.''
    Comment: We received numerous comments on EPA's statements in the 
proposed rule that a final rule requiring the monitoring and reporting 
of GHG emissions would not render GHGs ``regulated pollutants'' under 
the CAA. See, e.g., ``EPA's Interpretation of Regulations that 
Determine Pollutants Covered By Federal Prevention of Significant 
Deterioration (PSD) Permit Program'' (Dec. 18, 2008) (``PSD 
Interpretive Memo). Some agreed, while others took issue with the 
position in the memorandum.
    Response: As we noted in the proposal, EPA is reconsidering the PSD 
Interpretive Memo and will be seeking public comment on the issues 
raised in it. That proceeding, not this rulemaking, is the appropriate 
venue for submitting comments on the substantive issue of whether 
monitoring regulations under the CAA should make GHGs subject to 
regulation. At this time however, the PSD Interpretive Memo reflects 
EPA's current position, and hence, this final rule does not make GHGs 
subject to regulation under the CAA.
    Comment: EPA also received numerous comments about whether the 
requirements imposed by this rule are

[[Page 56288]]

``applicable requirements'' under the title V operating permit program. 
The majority of the comments took the position that the current 
definitions of ``applicable requirement'' at 40 CFR 70.2 and 71.2 do 
not include a rule such as this, promulgated under CAA section 
114(a)(1) and 208. Commenters requested that EPA confirm their 
interpretation of the regulations.
    Response: As currently written, the definition of ``applicable 
requirement'' in 40 CFR 70.2 and 71.2 does not include a monitoring 
rule such as today's action, which is promulgated under CAA sections 
114(a)(1) and 208.

III. Reporting and Recordkeeping Requirements for Specific Source 
Categories

A. Overview

    Once a reporter has determined that its facility or supply 
operation meets any of the reporting rule applicability criteria in 40 
CFR 98.2(a), the reporter must calculate and report GHG emissions or 
alternate information as required (e.g., suppliers report quantities 
supplied and the quantity of CO2e that could be emitted when 
the products they supply are combusted or used). The applicability 
threshold determination is separately assessed for suppliers (fossil 
fuel suppliers and industrial GHG suppliers) and downstream source 
categories (facilities with direct GHG emissions).
    The required GHG information must be reported for all source 
categories at the facility for which there are measurement methods 
provided. For suppliers (facilities or corporations) that trigger only 
the applicability criteria for upstream fossil fuel or industrial GHG 
supply (40 CFR part 98, subparts KK through PP), reporters need only 
follow the methods and report the information specified in those 
respective subparts. For downstream facilities that contain exclusively 
direct emitting source categories covered in 40 CFR part 98, subparts C 
through JJ, and are not suppliers, reporters must monitor and report 
GHG emissions the methods presented in each applicable subpart. Some 
reporters will need to report under multiple subparts because multiple 
source categories are collocated at their facility. For example, a 
facility with petrochemical production processes (described in Section 
III.X of the preamble), should also review Sections III.C (general 
stationary fuel combustion), III.G (ammonia manufacturing) and III.Y 
(petroleum refineries) of this preamble. In some cases, such as 
petroleum refineries that supply petroleum products and also meet 
applicability criteria for direct emissions from the refinery, 
reporters will have to report on both supply operations and direct 
facility emissions.
    Table 2 of this preamble (in the SUPPLEMENTARY INFORMATION section 
of this preamble) provides a cross walk to aid facilities and suppliers 
in identifying potentially relevant source categories. The cross-walk 
table should only be seen as a guide as to the types of source 
categories that may be present in any given facility and therefore the 
methodological guidance in Section III of this preamble that should be 
reviewed. Additional source categories (beyond those listed in Table 2 
of this preamble) may be relevant to a given reporter. Similarly, not 
all listed source categories will be relevant to all reporters.
    Consistent with the requirements in the 40 CFR part 98, subpart A, 
reporters must report GHG emissions from all source categories located 
at their facility including stationary combustion 40 CFR part 98, 
subpart C) and process emissions (e.g., from adipic acid production, 
iron and steel production, and other source categories in 40 CFR 
subparts C through JJ), as well as the required data for any supplier 
source categories (KK through PP). The methods presented typically 
account for normal operating conditions, as well as startup, shutdown, 
or malfunction (SSM), where significant (e.g., HCFC-22 production and 
oil and gas systems). Although SSM is not specifically addressed for 
many source categories, emissions calculation methodologies relying on 
CEMS or mass balance approaches would capture these different operating 
conditions.
    For many facilities, calculating facility-wide emissions will 
simply involve adding GHG emissions from combustion sources calculated 
under Section III.C of this preamble (General Stationary Fuel 
Combustion Sources) and process GHG emissions calculated under the 
applicable the source category subpart(s). The rule also clarifies 
reporting for more complex situations, such as where combustion and 
process emissions are comingled. See Section II.L of this preamble for 
a response to comments on the general monitoring and reporting approach 
for facilities with both combustion and process emissions. See sections 
III.C through PP of this preamble for discussion of the specific 
monitoring and reporting requirements for each source category.

B. Electricity Purchases

1. Summary of the Final Rule
    The final rule does not require facilities to report their 
electricity purchases or indirect emissions from electricity 
consumption.
2. Summary of Major Changes Since Proposal
    There have been no changes since proposal. The proposed rule did 
not require reporting of electricity purchases and neither does the 
final rule.
3. Summary of Comments and Responses
    The proposal preamble (74 FR 16479, April 10, 2009) requested 
comments on the value of collecting information on electricity 
purchases under this rule. It also outlined three options for reporting 
and requested comments on these options:
     Option 1: Do not require any reporting on electricity 
purchases or associated indirect emissions from purchased electricity 
as part of this rule.
     Option 2: Require reporting of purchased electricity from 
all facilities that are already required to report their GHG emissions 
under this rule.
     Option 3: Require reporting of indirect emissions from 
purchased electricity for facilities that exceed a prescribed total 
facility emission threshold (including indirect emissions from the 
purchased electricity). Reporting under this option could be either in 
terms of electricity purchases or calculated CO2e emission 
based on purchased electricity.
    While EPA is not including reporting requirements for electricity 
purchases in the final rule at this time, below we have provided a 
brief summary of major comments and our initial responses. As EPA 
considers next steps, we will be reviewing the public comments and 
other relevant information.
In Favor of Collecting Data on Electricity Purchases
    Comment: Commenters in favor of collecting data on purchased 
electricity stated that collection of this data, in conjunction with 
data on direct emissions from facilities, will present a more 
comprehensive picture of emissions nationwide. They argued that 
collection of this data will also serve to spur investment in energy 
efficiency and renewable energy since companies will want to improve 
their emissions numbers once the information is made public. Several 
commenters noted that while this reporting should occur, it should 
happen at the corporate level,

[[Page 56289]]

rather than at the facility level. Others stated that the collection 
should begin at a later time, perhaps in a second phase of this rule.
    Response: While EPA is not collecting data on electricity purchases 
in this rule, we understand that acquiring such data may be important 
in the future. Therefore, we are exploring options for possible future 
data collection on electricity purchases and indirect emissions, and 
the uses of such data. Such a future data collection on indirect 
emissions would complement EPA's interest in spurring investment in 
energy efficiency and renewable energy. Energy efficiency is a low 
cost, vital first step toward reducing GHG emissions. To this end, EPA 
has in place several programs in which corporations and individual 
facilities can participate to reduce their contribution to GHG 
emissions through increased energy efficiency of buildings and 
industry. These include EPA's ENERGY STAR and Climate Leaders programs.
    EPA has been working for more than a decade through the ENERGY STAR 
program to help companies reduce their energy use through cost-
effective energy efficiency investments and practices. ENERGY STAR 
provides nonresidential building owners and operators and energy 
intensive industries with a wide variety of tools and resources to 
assist in their efforts to reduce building energy use. These include an 
online energy benchmarking and tracking tool called Portfolio Manager, 
Guidelines for Energy Management, technical resources to assist in 
assessing building upgrades, and many others.
    Through the Climate Leaders Program, EPA works corporate-wide with 
companies to develop comprehensive climate change strategies. Partner 
companies commit to reducing their impact on the global environment by 
completing a corporate-wide inventory of their GHG emissions based on a 
quality management system, setting aggressive reduction goals to be 
achieved over 5 to 10 years, and annually reporting their progress to 
EPA. Through program participation, companies create a credible record 
or audit of their accomplishments and receive EPA recognition as 
corporate environmental leaders.
    In addition to these programs that support GHG emissions reductions 
in both the private and public sectors, EPA's Climate and Energy State 
and Local Program assists governments in their clean energy efforts by 
providing technical assistance, analytical tools, and outreach support. 
While EPA assists States in this way, we also have much to learn from 
their efforts. Throughout the country, States are engaged in activities 
on energy efficiency, energy auditing, and some collect data on 
electricity purchases for use in inventories and in energy efficiency 
programming.
    Since the goal of today's rule is to collect data on emissions from 
downstream direct emitters and upstream production, the collection of 
indirect emissions will not be included at this time. In exploring the 
possibility of collecting data on electricity purchases nationwide, EPA 
will be looking to the States as examples. While facility level 
collection is a possibility, collection from other sources, such as 
load serving entities will also be explored. Moreover, the collection 
of indirect emissions data from the types of facilities covered by this 
rule (e.g., facilities and suppliers with emissions over 25,000 metric 
tons of CO2e) would not provide the complete picture or 
focus on the types of facilities that likely have large indirect 
emissions. Reports from additional facilities could be required in any 
future data collection.
Against Collecting Data on Electricity Purchases
    Comment: Many commenters were against the collection of data on 
purchased electricity for several reasons. Primarily they felt it would 
constitute double counting if electricity data are collected from 
electric utilities and EPA also collects the same data from facilities 
and adds it together. Others stated that collecting information on 
electricity purchases was outside the scope of the rule, that it is not 
useful information in attempting to quantify emissions, that it would 
be burdensome for facilities, and that it is CBI that companies are not 
able to share with EPA. Those commenters suggested instead the data 
should come from utilities, as EPA proposed.
    Response: The final rule does not require facilities to report 
their electricity purchases or indirect emissions from electricity 
consumption. While EPA is not collecting data on electricity purchases 
in this rule, we understand that acquiring such data may be important 
in the future. Therefore, we are exploring options for possible future 
data collection on electricity purchases and indirect emissions, and 
the uses of such data. In the event that a future data collection 
effort is pursued, EPA will consider the issues raised by these 
commenters with regard to the most effective source for this data, and 
methods to reduce burden on reporting entities.
    With regard to, double reporting and/or double counting of the same 
data, the data collected under this rule is consistent with the 
appropriations language, and provides valuable information to EPA and 
stakeholders in the development of climate change policy and programs. 
Policies such as low carbon fuel standards can only be applied 
upstream, whereas end use emission standards can only be applied 
downstream. Data from upstream and downstream sources would be 
necessary to formulate and assess the impacts of such potential 
policies. Eliminating reporting by either upstream or downstream 
sources would not satisfy EPA's data needs and policy objectives of 
this rule. Any future rule makings to collect data on electricity 
purchases and indirect emissions will follow a similar approach in 
order to inform policy decisions.
    With regard to CBI, EPA recognizes the importance of this issue to 
both reporters and the public. EPA's public information regulations 
contain a definition of ``emissions data'' at 40 CFR 2.301, and EPA has 
discussed in an earlier Federal Register notice what data elements 
constitute emissions data that cannot be considered CBI (56 FR 7042-
7043, February 21, 1991).
    As explained in Section II.R. of this preamble, EPA intends to 
undertake a similar effort regarding the data elements collected in 
this rule, and any subsequent rules. Through a notice and comment 
process, we will establish those data elements that are ``emissions 
data'' and therefore will not be afforded the protections of CBI.

C. General Stationary Fuel Combustion Sources

1. Summary of the Final Rule
    Source Category Definition. Stationary fuel combustion sources are 
devices that combust any solid, liquid, or gaseous fuel to:
     Produce electricity, steam, useful heat, or energy for 
industrial, commercial, or institutional use; or
     Reduce the volume of waste by removing combustible matter.
    These devices include, but are not limited to, boilers, combustion 
turbines, engines, incinerators, and process heaters.
    Portable equipment, emergency generators, and emergency equipment 
are excluded from this source category. Stationary combustion devices 
that combust hazardous waste must report emissions only from the co-
firing of any fuels that are covered by 40 CFR part 98, subpart C. 
Flares are also excluded from subpart 40 CFR part 98, subpart C. Flare 
emissions must be reported only if

[[Page 56290]]

required by the provisions of another subpart of part 98.
    Reporters must submit annual GHG reports for stationary fuel 
combustion units if the facility meets the applicability criteria in 
the General Provisions (40 CFR 98.2) as summarized in Section II.A of 
this preamble.
    EGUs that are subject to the ARP and other EGUs that are required 
to monitor and report to EPA CO2 mass emissions year-round 
according to 40 CFR part 75, are covered under 40 CFR part 98, subpart 
D (Electricity Generation).
    GHGs to Report. For stationary fuel combustion, report:
     CO2, CH4, and N2O 
emissions from each stationary fuel combustion unit. For each unit, 
CO2, CH4, and N2O emissions must be 
reported for each fuel combusted (including biomass). Reporters can 
aggregate emissions from multiple units in certain cases.
     Facility-level CO2 emissions from combustion of 
biomass (in addition to unit-level reporting).
    GHG Emissions Calculation and Monitoring. Reporters must use the 
following methodologies to calculate emissions:
     Calculating CO2 Emissions from Combustion: 
Calculate CO2 emissions using one of four methodological 
tiers, subject to certain restrictions based on unit size, type of fuel 
burned, and other factors. For each Tier, CO2 mass emissions 
are determined as follows:

--Tier 1: Use annual fuel consumption (from company records) together 
with fuel-specific default high heat values and default CO2 
emission factors.
--Tier 2: Use annual fuel consumption (from company records) together 
with measured fuel-specific high heat values and default CO2 
emission factors.
--Tier 3: Use annual fuel consumption, either from company records (for 
solid fuels) or directly measured with fuel flow meters (for liquid and 
gaseous fuels) together with periodic measurements of fuel carbon 
content.
--Tier 4: Use CEMS. Use Tier 4 only for combustion units that have 
certain types of existing CEMS in place and that meet several other 
specific criteria, such as fuel type and hours of operation. Sources 
that have all of the necessary CEMS installed and certified by January 
1, 2010 are required to use Tier 4 in 2010. However, for sources that 
need additional time to upgrade their CEMS, the use of CEMS can begin 
on January 1, 2011; and a lower tier calculation methodology may be 
used in 2010.
--As an alternative to any of the four tier methods, the rule provides 
that units that report to EPA year-round heat input data under 40 CRF 
part 75 can calculate CO2 mass emissions using part 75 
calculation methods.

     Calculating CO2 Emissions From Sorbent Use. For fluidized 
bed boilers that use sorbent injection and units equipped with wet flue 
gas desulfurization systems, calculate CO2 emissions from 
sorbent use using methods provided in the rule, except when 
CO2 emissions are measured with CEMS.
     Calculating CO2 Emissions From Biomass Fuel Combustion. 
Calculate CO2 emissions from biomass combustion for only the 
specific types of biomass that are listed in the rule. The approach 
used for most units is to use a default high heat value and default 
CO2 emission factor to estimate emissions. For determining 
the biomass fraction of CO2 emissions from units that burn 
MSW or mixed fuels, and from units that co-fire biomass with fossil 
fuels and measure CO2 emissions using CEMS, use the specific 
methods provided in the rule.
     Calculating N2O and CH4 Emissions From Combustion. 
Calculate N2O and CH4 emissions only for units 
that are required to report CO2 emissions under this subpart 
and only for fuels for which default emission factors are provided in 
40 CFR part 98, subpart C.
     Fuel Sampling and Analysis. The Tier 2 and Tier 3 
calculation methodologies require periodic measurements of fuel heating 
value and carbon content. The minimum required frequency of these 
measurements is daily, weekly, monthly, quarterly, or semiannually, 
depending on the type of fuel combusted and other factors.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are needed for EPA verification of the reported GHG emissions from 
stationary combustion. The specific data to be reported are found in 40 
CFR part 98, subpart C.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. These records are described in 40 CFR part 98, 
subpart C.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart C: General Stationary Fuel 
Combustion Sources.''
     Exemptions to GHG emissions reporting have been added for 
unconventional types of fuel. Reporters are required to calculate GHG 
emissions only for fuels that are listed in Table C-1 of subpart C, 
except that units larger than 250 mmBtu/hr, also must calculate GHG 
emissions for any other fuels that provide, on average, at least 10 
percent of the annual heat input to the unit.
     The use of the Tier 2 calculation method for 
CO2 emissions has been expanded to include units greater 
than 250 mmBtu/hr that combust only pipeline natural gas and/or 
distillate oil.
     Two new alternative methods have been added, allowing 
sources that monitor and report heat input according to 40 CFR part 75, 
but are not required to report CO2 mass emissions, to use 
established Part 75 CO2 emissions calculation methods to 
meet the 40 CFR part 98 reporting requirements.
     A definition of ``company records'', as it pertains to 
quantifying fuel consumption in Tiers 1, 2, and 3, has been added to 40 
CFR 98.6.
     The required fuel sampling frequency in Tiers 2 and 3 has 
been reduced for many fuels, particularly those that are homogeneous or 
that are delivered in shipments or lots.
     Averaging of fuel sampling results is allowed for many 
fuels when the frequency of sampling and analysis is less than the 
minimum monthly frequency.
     The rule has been clarified to affirm that the use of fuel 
sampling results provided by the fuel supplier is permissible, and that 
the use of fuel billing records to quantify fuel consumption is also 
allowed.
     Additional deadline extensions for calibrating the fuel 
flow meters are provided in certain situations.
     The use of Tier 4 has been clarified; i.e., all of the 
conditions listed in 40 CFR 98.33(b)(4)(ii) and all of the conditions 
listed in 40 CFR 98.33(b)(4)(iii) must be met before Tier 4 is 
required.
     Units that must upgrade their existing CEMS to meet Tier 4 
requirements may use either Tier 2 or Tier 3 in 2010.
     The methods for calculating CH4 and 
N2O emissions have been clarified.
     An expanded list of default emission factors are provided 
for certain solid, gaseous, and liquid biomass fuels.
     The use of steam production and combustion unit efficiency 
to calculate CO2 emissions is extended to other solid fuels 
in addition to MSW. These

[[Page 56291]]

parameters may also be used to quantify the amount of biomass combusted 
in a unit.
     The use of American Society for Testing and Materials 
(ASTM) Methods D7459-08 and D6866-06a to determine CO2 
emissions from combustion of mixed biomass fuels has been expanded to 
include the combustion of other biomass fuels in addition to those 
mixed with MSW.
     The missing data provisions have been made more flexible.
     The limit of 250 mmBtu/hr total heat input for aggregating 
units into groups for reporting purposes has been lifted.
     The reporting of combined units served by a common supply 
line, or common pipe configuration, has been clarified.
     The amount of required unit-level data and emissions 
verification information has been reduced for some of the measurement 
Tiers.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Many comments on general stationary fuel combustion were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart C: General Stationary Fuel 
Combustion Sources.''
Definition of Source Category
    Comment: Several commenters asked EPA to clarify whether sources 
such as flares, hazardous waste incinerators, thermal oxidizers, 
pollution control devices, fume incinerators, burnout furnaces, and 
small equipment such as stoves and space heaters are included in the 
stationary combustion source category. Others suggested that EPA should 
consider requiring that only the GHG emissions from combustion of 
traditional fossil fuels (if any) in these types of sources be 
reported.
    Comments were also received on the proposed language for excluding 
emergency generators and the associated definitions.
    Response: The final rule retains the broad definition of a 
stationary fuel combustion source, which is any device that combusts 
fuel. Fuel is defined very broadly to mean any combustible material. 
However, in evaluating public comments, we agree that in some cases the 
reporting of GHG emissions is unreasonable given the cost of monitoring 
and the relative level of GHG emissions. Monitoring can be particularly 
burdensome for vents with highly variable gas characteristics (e.g., 
carbon content and heat value). Accordingly, the final rule expands the 
list of combustion sources and fuels that are exempted from GHG 
emissions reporting under 40 CFR part 98, subpart C, as summarized 
below:
     Flares are exempted from 40 CFR part 98, subpart C. 
However, flares at some facilities might be covered by other subparts 
of the rule.
     Stationary combustion units that combust hazardous waste, 
as defined in 40 CFR 261.3, are also exempted. These units would report 
only the emissions from combustion of any fuels covered by subpart C 
that are co-fired with hazardous wastes.
     For calculations at the unit level, units less than 250 
mmBtu/hour heat input are required to report GHG emissions only for 
fuels for which EPA has provided default emission factors in the rule.
     Units larger than 250 mmBtu/hour heat input GHG that 
combust miscellaneous, non-traditional fuels such as refinery gas, 
process gas, vent gases, waste liquids, and others must report only if 
CEMS are used or if these fuels contribute 10 percent or more of the 
annual unit heat input to the unit. With this exclusion, we have 
concluded that devices such as thermal oxidizers, pollution control 
devices, fume incinerators, burnout furnaces, and other such equipment 
would report only GHG emissions from the firing of supplemental fossil 
fuels.
    In response to comments on the exclusion of emergency generators, 
EPA removed proposed language that would have required emergency 
generators to be identified as such in the facility's State or local 
air permit in order to qualify for an exemption. We also added language 
to exclude other emergency equipment. See Section III.D of this 
preamble for the response to the comments on exclusion of emergency 
generators from 40 CFR part 98, subparts C and D. See ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart A: Definitions, Incorporation by Reference, and Other Subpart A 
Comments'' for responses to comments on definitions, including changes 
to the emergency generator definition and the addition of a definition 
for emergency equipment.
    Comment: Multiple commenters asked EPA to institute a ``de 
minimis'' provision in the rule to exclude stationary combustion 
sources other than the largest units at a facility.
    Response: The final rule contains no de minimis exclusions. 
However, to simplify reporting, the rule allows small units to be 
aggregated and reported as a single emissions value, if certain 
conditions apply. The final rule has expanded the availability of this 
provision. The proposed rule limited the aggregation of any one group 
to a combined maximum capacity of 250 mmBtu/hour heat input. The final 
rule removes this limit and allows grouping of any units that 
individually are less than 250 mmBtu/hour heat input. EPA has also 
clarified the use of the common pipe metering option, so that all 
stationary combustion units at a facility using the same fuel that is 
metered through a common supply line may report a single emissions 
value under this rule. In addition, the changes listed above in Section 
III.C.2 of this preamble will simplify emissions calculations for many 
combustion units.
Method for Calculating GHG Emissions
    Comment: EPA received numerous comments on the proposed GHG 
calculation methods for stationary combustion sources. Most of the 
comments centered on the use of the four-tiered approach for 
calculating CO2 emissions. Several commenters requested that 
EPA remove the 250 mmBtu/hr unit size restriction on the use of Tier 1 
and 2 calculation methods, especially for the combustion of relatively 
homogeneous fuels such as natural gas and fuel oil. Objections were 
raised to the specified frequency of fuel sampling under Tiers 2 and 3, 
as being excessive and unnecessary. Two commenters recommended that 
annual sampling be allowed for natural gas and fuel oil. A number of 
commenters asked the Agency to allow averaging of fuel sampling results 
(to simplify the CO2 emissions calculations) and to affirm 
that the use of fuel sampling results provided by the fuel supplier is 
permissible. Others sought confirmation that fuel billing meters could 
be used to quantify fuel usage. Multiple commenters asked EPA to 
clarify who must use the Tier 4 calculation method, which requires the 
use of continuous emission monitoring systems (CEMS) to measure stack 
gas flow rate and CO2 concentration. A number of comments 
were received requesting that sources currently monitoring and 
reporting heat input data under 40 CFR Part 75, but not reporting 
CO2 mass emissions, be allowed to implement established Part 
75 CO2 emissions calculation methods in lieu of using Tiers 
1 through 4. Finally, EPA received diverse comments on the proposed 
calculation method for CH4 and N2O emissions. 
Several commenters recommended that these emissions either not be 
reported at all, or that emissions reporting should be

[[Page 56292]]

excluded for certain fuel types. Others asked for flexibility in 
determining the appropriate emission factors for CH4 and 
N2O. Some suggested that the use of operator-defined 
emission factors or factors from other GHG registries should be 
allowed.
    Response: The final rule significantly expands the use of Tier 1 
and Tier 2 calculation methodologies. All units rated at 250 mmBtu/hr 
or less are allowed to use the Tier 1 or Tier 2 calculation 
methodologies, depending on fuel sampling provisions at either the 
facility or by the supplier of the fuel. In addition, units rated at 
over 250 mmBtu/hr that combust pipeline quality natural gas and 
distillate oil are allowed to use the Tier 2 calculation methodology, 
because of the homogeneous nature and low variability in the 
characteristics of these fuels. However, the 250 mmBtu/hr unit size 
cutoff remains for units that combust residual oil, other gaseous 
fuels, and solid fossil fuel.
    The mandatory monthly fuel sampling and analysis requirements for 
traditional fossil fuels have been dropped from Tiers 2 and 3. EPA 
agrees with the commenters that for a homogeneous fuel such as pipeline 
natural gas, monthly sampling is not necessary. Therefore, 40 CFR 98.34 
has been revised to require that natural gas be sampled semiannually. 
For other fuels such as oil and coal, which are delivered in shipments 
or lots, requiring monthly sampling may be impractical, because new 
fuel lots or deliveries may not be received on a monthly basis. For 
fuel oil and coal, a representative sample is required for each fuel 
lot, i.e., for each shipment or delivery. For other liquid fuels and 
biogas, quarterly sampling is required. For solid fuels other than 
coal, excluding MSW, weekly composite sampling with monthly analysis is 
required. For gaseous fuels other than natural gas and biogas, the 
daily sampling requirement has been retained, but only for facilities 
with existing equipment in place that is capable of providing the data. 
Otherwise, weekly sampling is required if such equipment for daily 
sampling is not installed.
    The final rule clarifies that fuel sampling and analysis data 
provided by the supplier may be used in the emission calculations, and 
that fuel billing meters may be used to quantify fuel consumption. To 
simplify the emission calculations in Tiers 2 and 3, arithmetic 
averaging of higher heating value and carbon content data over the 
reporting year is permitted if these data are collected less frequently 
than monthly (see Equation C-2b in 40 CFR 98.33). However, regardless 
of the sampling frequency required by the rule, reporters must use the 
results of all available valid fuel analyses in the emissions 
calculations.
    Today's rule clarifies the applicability of the Tier 4 methodology. 
Many commenters were unsure whether only one or all six of the 
conditions listed in proposed 40 CFR 98.33(b)(4)(ii) and all three of 
the conditions listed in proposed 40 CFR 98.33(b)(4)(iii) must be met 
to trigger the requirement to use CEMS. EPA's intent has always been 
that a source must meet all conditions listed in those sections to 
require the use of Tier 4. This has been made clear in the final rule 
text.
    The final rule adds two methods that can be used as alternatives to 
any of the four tier calculation methods. These alternative methods 
apply to sources that are currently required to monitor and report heat 
input data according to 40 CFR part 75, but are not required to report 
CO2 mass emissions. Many units subject to the Clean Air 
Interstate Regulation (CAIR) are in this category. These alternative 
methods allow these sources to use their 40 CFR part 75 heat input data 
together with one of the CO2 emissions calculation 
methodologies in part 75 to meet 40 CFR part 98 CO2 
emissions reporting requirements. For instance, sources monitoring 
hourly heat input according to Appendix D of 40 CFR part 75 may use 
Equation G-4 in Appendix G of 40 CFR part 75 to calculate 
CO2 emissions. Similarly, low mass emitting sources 
monitoring heat input under 40 CFR 75.19 may use Equation LM-11 in 40 
CFR 75.19 to calculate CO2 emissions. Sources using 40 CFR 
part 75 flow rate and CO2 CEMS to continuously monitor heat 
input may use the CEMS measurements together with an appropriate 
equation from Appendix F of 40 CFR part 75 to determine CO2 
mass emissions.
    The methodology for calculating CH4 and N2O 
emissions has been clarified in the final rule. Reporting of these 
emissions is required only for the fuels listed in Table C-2 of 40 CFR 
part 98, subpart C. Further, reporting of CH4 and 
N2O emissions is required only for units that are required 
to report CO2 emissions under 40 CFR part 98, subpart C and 
only for fuels for which default emission factors are provided in 
subpart C. The emission factors in Table C-2 of 40 CFR part 98, subpart 
C are both fuel-specific and heat input-based. Therefore, when more 
than one type of fuel is combusted in a unit, direct measurements or 
engineering estimates of the annual heat input from each fuel are 
needed to calculate the CH4 and N2O emissions. 
Consequently, when CEMS (which are not fuel-specific) are used to 
monitor the CO2 emissions and heat input for a multi-fuel 
unit, the total heat input measured by the CEMS must be apportioned to 
each fuel type. The owner or operator should use the best available 
information (e.g., fuel feed rates, high heat values) to do the 
necessary heat input apportionment. To provide greater consistency in 
reporting, EPA has chosen to retain the requirements for using the 
default factors in Table C-2 of 40 CFR part 98, subpart C, rather than 
allow reporters to select their own emission factors.
Procedures for Estimating Missing Data
    Comment: EPA received several requests to modify the proposed 
missing data substitution procedures in 40 CFR part 98, subpart C. One 
commenter recommended that a minimum data capture requirement should be 
specified rather than requiring the use of substitute data to fill in 
missing data gaps. Another commenter suggested that only the ``before'' 
value be used for data substitution, rather than the average of the 
quality-assured values before and after the missing data period. Others 
favored using emission factors or the ``best available estimates'' for 
all parameters, rather than following a prescriptive missing data 
algorithm. Finally, several commenters asserted that 40 CFO part 75 
missing data procedures for CO2 are too conservative (i.e., 
may overestimate emissions significantly) and seem to be contrary to 
the objectives of 40 CFR part 98.
    Response: The final rule provides additional flexibility to the 
missing data provisions of 40 CFR part 98, subpart C. The rule requires 
the use of ``before and after'' average values for only three 
parameters (fuel HHV, carbon content, and molecular weight). If the 
``after'' value is not yet available when the GHG emissions report is 
due, the ``before'' value may be used for missing data substitution. 
For all other parameters, the reporter can substitute data values that 
are based on the best available estimates, based on all available 
process information.
    EPA does not agree with the commenters who believe that the 40 CFR 
part 75 CO2 missing data procedures are too conservative and 
contrary to 40 CFR part 98 program objectives. Nearly all 40 CFR part 
75 sources maintain very high monitor data availability (95 percent or 
better) and use very little substitute data. Only when the data 
availability drops below 80 percent (which very seldom occurs) are the 
substitute data values significantly higher than the true 
CO2 concentrations. Therefore, sources that

[[Page 56293]]

monitor CO2 emissions according to 40 CFR part 75 should 
continue to use the standard part 75 missing data provisions, and no 
adjustments to those substitute data values are deemed necessary for 40 
CFR part 98 reporting purposes.
Data Reporting Requirements
    Comment: A number of commenters objected to the amount of unit-
level data and emissions verification information that is required to 
be reported electronically under 40 CFR 98.36 as ``burdensome'', 
``unnecessary,'' and ``excessive.'' The commenters recommended that the 
auxiliary information should instead be kept on file and made available 
to EPA upon request. Several commenters recommended that EPA remove the 
250 mmBtu/hr limit on the cumulative heat input capacity of units that 
can be aggregated into groups for reporting purposes. Other commenters 
asserted that EPA should consider the 40 CFR part 75 emissions data 
submitted under the ARP to be sufficient to satisfy 40 CFR part 98 
requirements, and that there is no need to submit the same data twice.
    Response: EPA does not agree with the assertion that the amount of 
unit-level data to be reported is excessive, burdensome, or 
unnecessary. For this mandatory GHG emissions reporting rule, two 
approaches to emissions data verification were considered, EPA 
verification and third-party verification. The Agency decided on EPA 
emissions verification. To verify GHG emissions estimates, EPA needs 
supporting data that are reported at the same level as the emissions 
are calculated. Because the rule requires that emissions be calculated 
at the unit level, it is imperative for EPA to obtain unit level 
verification data, particularly given the variety of requirements for 
estimating fuel combustion emissions under 40 CFR part 98, subpart C. 
Subpart C provides four different methods of estimating CO2 
emissions. The four methods require measurement of different parameters 
to estimate emissions, and the use of the methods is conditioned on a 
variety of operating factors. In addition, facilities use fuel 
combustion units of a variety of different sizes, types, and fuel 
firing scenarios. Under these circumstances, EPA could not verify that 
the correct methods were selected or applied correctly without unit-
level data. If unit-level data were not submitted or were aggregated at 
a gross level, EPA could not reasonably verify the accuracy of reported 
facility-wide GHG emissions data, because EPA could not evaluate the 
relationship between unit capacity, fuel characteristics, fuel 
consumption, and emissions. However, as explained below, in the final 
rule EPA has made a number of significant adjustments to the data 
reporting requirements to clarify requirements and to reduce the 
reporting burden.
    First, for units that use Tiers 1, 2 and 3 to calculate 
CO2 mass emissions, the cumulative 250 mmBtu/hr heat input 
capacity limit on the aggregation of units into groups has been 
dropped. Rather, the 250 mmBtu/hr restriction applies only to the 
individual units in a group. Therefore, for reporting purposes, 
individual units with maximum rated heat input capacities of 250 mmBtu/
hr or less may be aggregated without limit into a single group, 
provided that the Tier 4 methodology is not required for any of the 
units, and all units in the group use the same calculation methodology 
for any common fuels that they combust. Units with maximum rated heat 
inputs greater than 250 mmBtu/hr using Tiers 1, 2, and 3 must report as 
individual units, unless they burn the same type of fuel and the fuel 
is provided by a common pipe or supply line. In that case, the owner or 
operator may opt to aggregate emission for all units fed by the common 
fuel line. Units using Tier 4 must report as individual units unless 
they share a monitored common stack.
    Second, the rule requires minimal data to be reported for units 
that monitor and report emissions and heat input data according to 40 
CFR part 75. Units that meet these criteria include units that are 
subject to the ARP, and potentially units that are subject to CAIR, and 
other programs. The final rule clarifies that 40 CFR part 75 sources 
must report 40 CFR part 98 GHG emissions data under the exact same 
unit, stack, or pipe ID numbers that are used for electronic reporting 
in the part 75 programs (e.g., 1, 2, CT5, CS001, MS1A, CP001, etc.). 
Even though most 40 CFR part 75 sources report CO2 mass 
emissions data to EPA year-round, these data alone are not sufficient 
to satisfy the Part 98 reporting requirements for the following 
reasons. The emissions reports required under 40 CFR part 98 are 
facility-wide reports that require GHG emissions from all stationary 
combustion units at the facility, whether or not the units are subject 
to a 40 CFR part 75 program. Many electricity generating facilities 
have both ARP units and non-ARP units on site. Further, the 
CO2 emissions data reported under 40 CFR part 75 are in 
units of short tons; Part 98 requires reporting in metric tons. 
Finally, 40 CFR part 98 also requires CH4 and N2O 
emissions to be reported, neither of which are reported under any 40 
CFR part 75 program.
    Third, the required verification data have been clarified and, in 
some cases, differ substantively from the proposed rule. No additional 
verification information is required for sources that monitor and 
report emissions and heat input data using 40 CFR part 75. This 
includes sources that elect to use the new alternative calculation 
methodologies for units monitoring heat input year round according to 
40 CFR part 75 programs. For sources using Tiers 1, 2, 3, and 4, the 
final rule streamlines some of the reporting. Sources using Tier 3 are 
required to report only monthly averages of fuel carbon content and 
molecular weight rather than the proposed requirement to submit the 
results of each individual determination. Sources that use Tier 4 are 
required to report quarterly cumulative CO2 mass emissions, 
rather than daily CO2 emissions, as proposed. Also, to 
address concerns raised by some of the commenters, certain data 
elements need only be retained on file and provided to EPA upon 
request. These data elements include the methods used for fuel sampling 
and analysis, the methods used to calibrate fuel flow meters, the dates 
and results of fuel flow meter calibrations, and the dates and results 
of CEMS certification tests and on-going QA tests of the CEMS.

D. Electricity Generation

1. Summary of the Final Rule
    Source Category Definition. This source category consists of EGUs 
that are subject to the ARP and any other EGUs that are required to 
monitor and report to EPA CO2 mass emissions year-round 
according to 40 CFR part 75. All other EGUs are part of the general 
stationary fuel combustion source category and report under 40 CFR part 
98 subpart C, if the facility meets the reporting rule applicability 
criteria. This source category excludes portable equipment, emergency 
generators, and emergency equipment.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Report annual CO2, N2O, and 
CH4 mass emissions from each EGU.
    GHG Emissions Calculation and Monitoring. For EGUs subject to the 
ARP and other EGUs that are required to monitor and report to EPA 
CO2 mass emissions year-round according to 40

[[Page 56294]]

CFR part 75, the reporter must continue to monitor CO2 
emissions according to 40 CFR part 75. The cumulative CO2 
mass emissions reported in the fourth quarter electronic data reports 
must be converted from short tons to metric tons, for 40 CFR part 98 
reporting purposes. The N2O and CH4 emissions 
must be calculated using fuel-specific default emission factors and 
heat input measurements in accordance with 40 CFR 98.33(c) in subpart C 
(General Stationary Fuel Combustion Sources).
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit unit-level data 
and other information that are used to verify the reported GHG 
emissions. The additional data and information to be reported for this 
source category are specified in 40 CFR 98.46.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. The specific records that must be retained for 
this source category are identified in 40 CFR 98.47.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart D: Electricity Generation.''
     The source category has been more precisely defined and 
includes only EGUs subject to the ARP and any other EGUs that are 
required to monitor and report to EPA CO2 mass emissions 
year-round according to 40 CFR part 75.
     The proposed emergency generator exclusion language no 
longer requires that emergency generators be identified as such in 
State or local air permits.
     A CO2 calculation methology was provided for 
units that are not in the ARP, but report CO2 mass emissions 
year-round using 40 CFR part 75 methodologies.
3. Summary of Comments and Responses
Definition of Source Category
    Comment: Several commenters were concerned that covering non-ARP 
EGUs in both subparts C and D of proposed 40 CFR part 98 was confusing 
and repetitive. Several commenters stated that the definition of an EGU 
is too inclusive and recommended that EPA revise it. The commenters 
were concerned that any unit, regardless of electrical output, could be 
identified as an EGU and place a facility in the electricity generation 
source category. One commenter suggested that a 25 megawatts (MW) 
threshold should be added to the EGU definition in 40 CFR 98.6 and to 
40 CFR part 98, subpart D. A multitude of commenters objected to the 
language in proposed 40 CFR 98.40 requiring emergency generators to be 
designated as such in a State or local air permit, in order for the 
generators to be exempted from GHG emissions reporting. Many of these 
same commenters recommended changes to the definition of ``emergency 
generator'' in 40 CFR 98.6, suggesting that the term ``generator'' 
should be replaced with the term ``reciprocating internal combustion 
engine (RICE)'', to be consistent with 40 CFR 63.6675, subpart ZZZZ. 
Others recommended that EPA should also exempt emergency equipment such 
as fire pumps, fans, etc. from GHG emissions reporting.
    Response: The electricity generation source category definition in 
subpart D (40 CFR 98.40) has been modified based on the comments 
received. The final rule limits the source category to EGUs that are 
subject to ARP and to other EGUs that monitor and report to EPA 
CO2 mass emissions year-round according to 40 CFR part 75. 
The final subpart D does not cover any other EGUs. The GHG emissions 
from other EGUs are covered under subpart C (General Stationary Fuel 
Combustion).
    The definition of an ``emergency generator'' in 40 CFR 98.6, the 
final rule has been changed to clarify that it includes both RICE and 
turbines. EPA has also added a definition of ``emergency equipment'' to 
40 CFR 98.6, and exempts such equipment from GHG emissions reporting 
under both 40 CFR part 98, subparts C and D.
    The proposed requirements in 40 CFR part 98, subparts C and D for 
emergency generators to be identified as such in State and local air 
permits in order to be exempt from GHG emissions reporting has been 
revised. There is considerable variation from State to State regarding 
the regulation of emergency generators, including whether or not 
permits are required. Some States specifically exempt emergency 
generators from permitting requirements. Other States use a permit by 
rule approach for emergency units. In view of this, the Agency has 
revised the wording of the exclusion for emergency generators to allow 
for situations where they are not specifically identified in a 
facility's permit.
Method for Calculating GHG Emissions
    Comment: Several commenters suggested that for units that are not 
in the ARP but are required by other regulatory programs to report part 
75 emissions and heat input data, EPA should expand the four-tiered 
calculation method for CO2 mass emissions in 40 CFR 98.33(a) 
to allow the use of CO2 emissions calculation methods based 
on Appendices D and G of part 75.
    Response: The electricity generation source category definition has 
been narrowed to only include EGUs that are subject to ARP and to other 
EGUs that monitor and report to EPA CO2 mass emissions year-
round according to 40 CFR part 75 (e.g., RGGI units). The final subpart 
D provides a CO2 calculation methodology for such EGUs that 
are not in the ARP, but report to EPA CO2 mass emissions 
year-round using part 75 methodologies. For the purposes of part 98, 
the CO2 emissions from these units are calculated and 
reported using the same methods as part 75.
    Other units that are not in the ARP but report data under part 75, 
subpart C are now covered by 40 CFR part 98, subpart C instead of 
subpart D, and subpart C has been revised to allow the use of part 75 
calculation methodologies. The response to the comment on these units 
is contained in Section III.C of this preamble (General Stationary Fuel 
Combustion Sources).

E. Adipic Acid Production

1. Summary of the Final Rule
    Source Category Definition. The adipic acid production source 
category consists of all processes that use oxidation to produce adipic 
acid.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Report N2O process emissions from adipic 
acid production.
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. Unless an alternative 
method of determining N2O emissions is requested, calculate 
N2O process emissions from adipic acid production

[[Page 56295]]

by multiplying a facility-specific emission factor by the annual adipic 
acid production level. Determine the facility-specific emission factor 
by an annual performance test to measure N2O emissions from 
the waste gas stream of each oxidation process and the production rate 
recorded during the test.
    When N2O abatement devices (such as nonselective 
catalytic reduction) are used, adjust the N2O process 
emissions for the amount of N2O removed using the 
destruction efficiency for the control device and the fraction of 
annual production for which the control device is operating. The 
destruction efficiency can be specified by the abatement device 
manufacturer or can be determined using process knowledge or another 
performance test.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart E.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart E.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found in this section or ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart E: Adipic Acid Production.''
     The re-testing trigger was changed. Performance testing to 
determine the N2O emissions factor is required annually, 
whenever the ratio of cyclohexanone to cyclohexanol is changed, and 
when new abatement equipment is installed.
     Equation E-2 was edited to correct a calculation error and 
to allow multiple types of abatement technologies.
     40 CFR 98.56 was reorganized and updated to improve the 
data reporting requirements as needed for the emissions verification 
process. Some data elements were moved from 40 CFR 98.57 to 40 CFR 
98.56, and some data elements that a reporter must already use to 
calculate GHGs as specified in 40 CFR 98.53 were added to 40 CFR 98.56 
for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments on adipic acid production were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart E: Adipic Acid Production.''
GHGs To Report
    Comment: Multiple commenters asked that the language in 40 CFR 
98.52(b) be clarified to include emissions under 40 CFR part 98, 
subpart E only from units that are 100 percent dedicated to adipic acid 
production to avoid double counting of combustion emissions.
    Response: We reviewed this issue but decided not to make any 
changes to 40 CFR part 98, subpart E. We do not foresee a potential for 
double counting of combustion emissions at the facility because all 
combustion unit emissions at adipic acid facilities are to be reported 
under 40 CFR part 98, subpart C. 40 CFR part 98, subpart E provides 
methods for reporting only the process N2O emissions. Also 
see Section III.C of this preamble for responses to comments related to 
40 CFR part 98, subpart C (General Stationary Combustion).
Selection of Proposed GHG Emissions Calculations and Monitoring Methods
    Comment: One commenter stated that emissions of N2O do 
not correlate with the production of adipic acid at their facility. A 
portion of the process off gas, which contains N2O, is sold 
to an offsite facility via dedicated piping. The amount sold depends on 
customer needs and the amount is metered. The commenter asked that the 
language in the final rule address this issue.
    Response: We agree that N2O emitted from the production 
of adipic acid that is sold or transferred offsite is not covered in 
the proposed rule. The final rule has been changed to require this 
amount of N2O to be reported. Allowing for this additional 
reporting requirement ensures that the reported N2O 
emissions attributed to the adipic acid facility are accurate. 
Reporting of the N2O sold or transferred offsite will help 
EPA improve methodologies for reporting of GHG emissions.
Method for Calculating GHG Emissions
    Comment: Multiple commenters asked that the requirement to repeat 
the annual performance test be removed. In the proposal, re-testing was 
triggered whenever the adipic acid production rate changed by more than 
10 percent. Commenters asserted that production depends on demand for 
adipic acid and often varies by 15 percent.
    Response: Upon review, we decided to eliminate re-testing. We 
believe that annual determination of the N2O emissions 
factor is sufficient to accurately calculate N2O emissions 
as long as the production equipment remains consistent over the year-
long period (i.e. no new abatement technology).
    Comment: Multiple commenters asked that alternative methods be 
allowed for calculating N2O emissions from adipic acid 
production. Specifically the commenters asked that EPA allow the use of 
N2O and flow CEMS to directly measure N2O 
emissions and use the performance test to evaluate the CEMS accuracy. 
The commenters also asked that EPA allow the use of existing process 
flow meters and process N2O analyzers to determine the 
amount of N2O sent to control devices and use the 
performance test to measure control device destruction efficiency.
    Response: We agree that there are other means of determining site-
specific N2O emissions. The final rule has been changed to 
allow alternative test methods. Any alternative must be approved by the 
Administrator before being used to comply with this rule. An 
implementation plan that details how the alternative method will be 
implemented must be included in the request for the alternative method. 
Until the method is approved facilities must use the alternatives 
proposed in the rule for a performance test. As one commenter noted, at 
minimum the performance test will help to QA/QC alternative methods 
currently used to monitor N2O emissions (such as 
N2O CEMS).
    EPA understands the need to further evaluate and establish 
alternative comparable methods for sources to use in accurately 
calculating N2O emissions from adipic production and will 
address in future rulemakings or amendments to rulemaking.
    The final rule does allow the use of existing process flow meters 
and process knowledge in the determination of the destruction factor of 
N2O abatement technologies. This parameter is often based on 
site-specific knowledge and operations. We believe

[[Page 56296]]

that using existing methods can also reduce the potential cost impacts 
of this rulemaking and that it is in the best interest of the 
facilities that process parameters be accurately measured.
    Comment: One commenter asked that Equation E-2 be edited to follow 
the summation format used in the IPCC Tier 2 methodology. The current 
format does not allow for multiple abatement technologies (including no 
abatement).
    Response: We agree with the commenter. The equation in the proposed 
rule contained an error and did not allow for multiple abatement 
technologies. The final rule contains a corrected version of the 
equation.

F. Aluminum Production

1. Summary of the Final Rule
    Source Category Definition. The aluminum production source category 
consists of facilities that manufacture primary aluminum using the 
Hall-H[eacute]roult manufacturing process. The primary aluminum 
manufacturing process consists of the following operations:
     Electrolysis in prebake and S[oslash]derberg cells.
     Anode baking for prebake cells.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For aluminum production, report:
     Perfluoromethane (CF4) emissions and 
perfluoroethane (C2F6) emissions from anode 
effects in all prebake and S[oslash]derberg electrolysis cells 
combined.
     CO2 emissions from anode consumption during 
electrolysis in all prebake and S[oslash]derberg cells.
     All CO2 emissions from anode baking.
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. Reporters must calculate 
process emissions using the following methods:
     CF4 from anode effects: Calculate annual CF4 
emissions based on the frequency and duration of anode effects in the 
aluminum electrolytic reduction process for each prebake and 
S[oslash]derberg electrolysis cell using the following parameters:

--Anode effect minutes (AEM) per cell-day calculated monthly.
--Aluminum metal production calculated monthly.
--A slope coefficient relating CF4 emissions to anode effect 
minutes per cell-day and aluminum production. The slope coefficient is 
specific to each smelter and must be measured in accordance with the 
protocol specified in the rule at least once every 10 years.
--Facilities are allowed to use historic smelter-specific slope 
coefficients for the first three years of reporting under the rule. 
Historic measurements include all those made under EPA's Voluntary 
Aluminum Industry Partnership or at facilities owned or operated by 
companies participating in the Voluntary Aluminum Industry Partnership. 
Facilities without historic measurements are required to complete 
measurements by the end of first year of reporting.
--Facilities which operate at less than 0.2 anode effect minutes per 
cell day or, when overvoltage is recorded, operate with less than 1.4mV 
overvoltage, can use either smelter-specific measured slope 
coefficients or the technology-specific (Tier 2) default coefficients 
from Volume III, Chapter 4, Section 4.4 Metal Industry Emissions of the 
2006 IPCC Guidelines for National Greenhouse Gas Inventories as 
specified in the rule.

     C2F6 from anode effects: Calculate annual 
C2F6 emissions from anode effects from each 
prebake and S[oslash]derberg electrolysis cell using the calculated 
CF4 emissions and the mass ratio of 
C2F6 to CF4 emissions, as determined 
during the same test during which the slope coefficient is determined.
     Process CO2 emissions--general approaches. Most reporters 
can elect to calculate and report process CO2 emissions from 
anode consumption during electrolysis and from anode baking by either 
(1) installing and operating CEMS and following the Tier 4 methodology 
(in 40 CFR part 98, subpart C) or (2) using the calculation procedures 
specified below.
     However, if process CO2 emissions from anode consumption 
during electrolysis or anode baking are emitted through the same stack 
as a combustion unit or process equipment that uses a CEMS and follows 
Tier 4 methodology to report CO2 emissions, then the CEMS 
must be used to measure and report combined CO2 emissions 
from that stack, instead of using the calculation procedures specified 
below.
     CO2 emissions from anode consumption in prebake cells: 
Calculate annual CO2 emissions at the facility level using a 
mass balance equation based on measurements of the following 
parameters:

--Net prebaked anode consumption rate per metric ton of aluminum metal 
produced.
--Ash and sulfur contents of the anodes.
--Total mass of aluminum metal produced per year for all prebake cells.

     CO2 emissions from S[oslash]derberg cells: Calculate 
CO2 emissions from paste consumption in S[oslash]derberg 
cells using a mass balance equation at the facility level based on the 
following parameters:

--Paste consumption rate per metric ton of aluminum metal produced and 
the total mass of aluminum metal produced per year for all 
S[oslash]derberg cells.
--Emissions of cyclohexane-soluble matter per metric ton of aluminum 
produced.
--Binder content of the anode paste.
--Sulfur, ash, and hydrogen contents of the coal tar pitch used as the 
binder in the anode paste.
--Sulfur and ash contents of the calcined coke used in the anode paste.
--Carbon in the skimmed dust from the cell, per metric ton of aluminum 
produced.

     CO2 emissions from anode baking of prebake cells: 
Calculate CO2 emissions at the facility level separately for 
pitch volatiles combustion and for bake furnace packing material.
     To calculate CO2 emissions from the pitch 
volatiles, use a mass balance equation based on the following 
parameters:

--Initial weight of the green anodes.
--Mass of hydrogen in the green anodes.
--Mass of the baked anodes.
--Mass of waste tar collected.

     To calculate CO2 emissions from bake furnace 
packing material, use a mass balance equation based on the following 
parameters:

--Packing coke consumption rate per metric ton of baked anode 
production.
--Sulfur and ash contents of the packing coke.

     The variables used to calculate CO2 emissions 
from anode and paste consumption (e.g., sulfur, ash, and hydrogen 
contents) can be determined for each facility, or the source can use 
default values from the 2006 IPCC Guidelines for National Greenhouse 
Gas Inventories as specified in 40 CFR 98.64.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit

[[Page 56297]]

additional data that are used to calculate GHG emissions. A list of the 
specific data to be reported for this source category is contained in 
40 CFR part 98, subpart F.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart F.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart F: Aluminum Production.''
     A new subsection was added in 40 CFR 98.63 providing a new 
equation (Eq. F-1) to sum monthly PFC emission values into annual PFC 
emission value.
     The equation for CO2 emissions from 
S[oslash]derberg cells (paste consumption) was corrected.
     Language was updated to request reporting of all 
CO2 emissions from on-site anode baking.
     Language was updated to request reporting of smelter-
specific slope coefficients (plural).
     A new equation was added in 40 CFR 98.63 (Eq. F-3) to 
calculate CF4 emissions from overvoltage; and updated 
language in subsequent sections to accommodate the overvoltage method.
     Language was added to permit facilities that operate with 
low anode effect minutes or low overvoltages to use IPCC Tier 2 default 
slope factors.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Three comments on aluminum production were received covering 
numerous topics. Responses to significant comments received can be 
found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Subpart F: Aluminum Production.''
    Comment: Several commenters suggested that smelters should be 
permitted to use International Aluminum Institute default slope 
coefficients which are based on global technology-specific averages to 
calculate PFC emissions, especially at high performance facilities.
    Response: The use of smelter-specific slope coefficients as 
required in the rule leads to significantly more precise PFC emission 
calculations than the use of default slope coefficients (95 percent 
confidence interval of 15 compared to 50 
percent). For a typical U.S. smelter emitting 175,000 metric tons of 
CO2-eq in PFCs, these errors result in absolute 
uncertainties of 88,000 MTCO2e and 26,000 MTCO2e, respectively. The reduction in 
uncertainty associated with moving from default to smelter-specific 
slope coefficients, 62,000 MTCO2e, is as large as the 
emissions from many of the sources that would be subject to the rule. 
However, for ``high performance'' facilities, which are defined by the 
2006 IPCC Guidelines as those at or below 0.2 anode effect minutes per 
cell day or less than 1.4 mV overvoltage, the IPCC analysis indicates 
that impact of moving from a Tier 2 to a Tier 3 slope coefficient would 
not result in a significant improvement in PFC emissions. Therefore, 
EPA agrees that high performance facilities should be allowed to use 
technology specific (Tier 2) default values from Volume III, Chapter 4, 
Section 4.4 Metal Industry Emissions of the 2006 IPCC Guidelines for 
National Greenhouse Gas Inventories. These values are identical to the 
``Aluminum Sector Greenhouse Gas Protocol (Addendum to the WRI/WBCSD 
Greenhouse Gas Protocol),'' October 2006 default coefficients.
    Comment: Several commenters argued the requirement to re-measure 
smelter-specific slope coefficients every three years is expensive and 
unnecessary.
    Response: While the cost to require smelter-specific slope 
coefficients is significantly greater than the cost to use default 
slope coefficients, the benefit of reduced uncertainty is considerable, 
as noted above. The costs that would be incurred by smelters measuring 
slope factors are discussed in the Regulatory Impact Analysis (RIA) for 
the proposed rulemaking (EPA-HQ-OAR-2008-0508-002).
    Of the currently operating U.S. smelters, all but one has measured 
a smelter specific coefficient at least once; and at least three used 
the 2003 EPA/IAI protocol for measuring smelter-specific slope 
coefficients.
    The USEPA/IAI Protocol for Measurement of Tetrafluoromethane and 
Hexafluoroethane from Primary Aluminum Production establishes 
guidelines to ensure that measurements of smelter-specific slope-
coefficients are consistent and accurate (e.g., representative of 
typical smelter operating conditions and emission rates). The Protocol 
currently recommends that smelter operators re-measure their slope 
coefficients at least every three years, and more frequently if they 
adopt changes to process control algorithms or observe changes to 
typical anode effect duration. Specifically, the Protocol recommends 
that operators repeat measurements of slope coefficients for 
CF4 and C2F6 if one or more of the 
following apply: (1) Thirty-six months have passed since the last 
measurements (i.e., triennial measurements are recommended); (2) 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; 
and, (3) changes occur in the distribution of duration of anode effects 
(e.g. when the percentage of manual kills changes or if, over time, the 
number of anode effects decreases and results in a fewer number of 
longer anode effects).
    Changes to process control algorithms or to the typical duration of 
anode effects can change the relationship between anode effect minutes, 
production, and emissions, that is, they can change slope coefficients. 
In addition, more subtle changes can also change slope coefficients 
over time. According to industry experts, the rate of these more subtle 
changes has not been sufficiently studied to specify a frequency for 
re-measurement nor have there been a sufficient number of facilities 
that have been measured repeatedly to document the benefit of the 
additional incremental cost of measurement once every three years.
    During the past few years, multiple U.S. smelters have adopted 
changes to their production process which are likely to have changed 
their slope coefficients. These include the adoption of slotted anodes 
and improvements to process control algorithms. Although some U.S. 
smelters have recently updated their measurements of smelter-specific 
coefficients, others may not have.
    In view of these recent process changes, EPA is requiring smelters 
that have not already measured their slope factors under the ``2008 
USEPA/IAI Protocol for Measurement of Tetrafluoromethane and 
Hexafluoroethane from Primary Aluminum Production,'' to do so in time 
for the 2013 reporting year. EPA believes that this will ensure that 
slope factors are appropriately updated while providing sufficient 
lead-time for smelters to perform the measurements without encountering 
excessive costs or logistical barriers. However, after this initial 
update, EPA agrees that every three years is burdensome, therefore,

[[Page 56298]]

further updates are required only every ten years unless there are 
major technological or process changes at a facility such as changes to 
the control algorithm that affect the mix of types of anode effects or 
the nature of the anode effect termination routine; or changes occur in 
the distribution of duration of anode effects (e.g. when the percentage 
of manual kills changes or if, over time, the number of anode effects 
decreases and results in a fewer number of longer anode effects).
    Comment: Several commenters suggested that the rule should include 
the overvoltage measurement method, which is specific to use with 
Pechiney technology, in case one or more U.S. smelters decide to adopt 
this technology in the future.
    Response: The Overvoltage Method relates PFC emissions to an 
overvoltage coefficient, anode effect overvoltage, current efficiency, 
and aluminum production. The overvoltage method was developed for 
smelters using the Pechiney technology. While it is EPA's understanding 
that no U.S. smelters have used the Pechiney technology for at least a 
decade, if one or more U.S. smelters decide to adopt this 
internationally accepted technology in the future they would be 
expected to use the overvoltage method which follow the established 
guidelines in the ``USEPA/IAI Protocol for Measurement of 
Tetrafluoromethane and Hexafluoroethane from Primary Aluminum 
Production.''

G. Ammonia Manufacturing

1. Summary of the Final Rule
    Source Category Definition. The ammonia manufacturing source 
category consists of process units in which ammonia is manufactured 
from a fossil-based feedstock via steam reforming of the hydrocarbon. 
It also includes ammonia manufacturing processes in which ammonia is 
manufactured through the gasification of solid and liquid raw material.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For ammonia manufacturing, report the following 
emissions:
     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 part.
     CO2, CH4, and N2O 
emissions from each stationary combustion unit. Report these emissions 
under 40 CFR 98, subpart C (General Stationary Fuel Combustion Sources) 
by following the requirements of 40 CFR part 98, subpart C.
     For CO2 collected and transferred off site, 
report these emissions under 40 CFR part 98, subpart PP (Suppliers of 
CO2) following the requirements of 40 CFR part 98, subpart 
PP.
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. Reporters must use one of 
two methods to calculate CO2 process emissions, as 
appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions from each ammonia manufacturing process unit 
by either (1) installing and operating CEMS and following the Tier 4 
methodology (in 40 CFR part 98, subpart C) or (2) using the calculation 
procedures contained in the rule and summarized below.
     However, if process CO2 emissions from an 
ammonia manufacturing process unit are emitted through the same stack 
as CO2 emissions from a combustion unit or process equipment 
that uses a CEMS and follows Tier 4 methodology to report 
CO2 emissions, then the CEMS must be used to measure and 
report combined emissions from that stack, instead of using the 
calculation procedures described below.
     To calculate process CO2 emissions, use the 
equations provided in 40 CFR part 98, subpart G for solid, liquid, and 
gaseous feedstock and the following measurements:

--Continuous measurement of gaseous or liquid feedstock consumed using 
a flowmeter, or monthly aggregate of solid feedstock consumed.
--Carbon content of the feedstock (required to be measured monthly 
using supplier data or analysis using the appropriate test methods). If 
supplier data are used, facilities must QA/QC the supplier analysis on 
an annual basis using the appropriate test methods.

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart G.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart G.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart G: Ammonia Manufacturing.''
     Monitoring and QA/QC requirements were revised to allow 
for obtaining carbon content of feedstock used in ammonia manufacturing 
from the feedstock supplier. Facilities that obtain monthly carbon 
content information from their supplier are required to QA/QC supplier 
information through annual sampling and analysis of the feedstock.
     Missing data procedures were added under 40 CFR 98.75 for 
parameters that facilities must measure such as feedstock consumption, 
the quantity of the waste recycle stream, and the monthly carbon 
content of both the feedstock consumption and waste recycle stream 
quantity.
     Reporting requirements were added for the quantity of urea 
produced and the emissions associated with waste recycle streams 
commonly found at ammonia manufacturing facilities.
     40 CFR 98.76 was reorganized and updated to improve the 
emissions data verification process. Some data elements were moved from 
40 CFR 98.77 to 40 CFR 98.76, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.73 were 
added to 40 CFR 98.76 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments on ammonia manufacturing were received 
covering numerous topics. Several of these comments were directed at 
the requirements for 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources), and responses to those comments are provided in 
Section III.C of this preamble. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to

[[Page 56299]]

Public Comments, Subpart G: Ammonia Manufacturing.''
Method for Calculating GHG Emissions
    Comment: Several commenters asked EPA to clarify that ammonia 
production units must use Tier 4 calculation only if all of the 
conditions under proposed 40 CFR 98.33(b)(5)(ii)(A) through (F) apply 
to the unit and only where the ammonia manufacturing unit already has 
installed a stack gas volumetric flow rate monitor and a CO2 
concentration monitor.
    Response: We agree with the comment and have modified the text 
under 40 CFR 98.73(a) and (b) to state that if a facility operates and 
maintains CEMS that meet the requirements of 40 CFR 98.33(b)(4)(ii) or 
(iii), then process or combined process and combustion CO2 
emissions shall be calculated and reported under this subpart by 
following the Tier 4 Calculation Methodology specified in 40 CFR 
98.33(a)(4) and all associated requirements for Tier 4 in 40 CFR part 
98, subpart C (General Stationary Fuel Combustion Sources). If CEMS are 
not used to determine CO2 emissions from ammonia processing 
units, then facilities must calculate and report process CO2 
emissions under this subpart by using equations provided in 40 CFR 
98.73(b)(1) through (b)(4). CO2 combustion emissions from 
ammonia processing units must be reported under 40 CFR part 98, subpart 
C (General Stationary Fuel Combustion Sources). For additional 
clarification on the requirements on use of CEMS see 40 CFR part 98, 
subpart C (General Stationary Fuel Combustion Sources), and Section 
III.C of this preamble.
    Comment: One commenter noted that most ammonia facilities utilize 
natural gas combustion combined with approximately five percent recycle 
flow of gas containing methane from the process. The carbon content of 
the recycle stream is already accounted for when measuring the 
feedstock flow rate and carbon content to the process. EPA should allow 
ammonia manufacturers to exclude this recycle stream in calculating 
combustion emissions, as the carbon in the recycle stream would be 
double counted.
    Response: We agreed with commenters that it is important to account 
for use of the waste process stream in the case that it is recycled 
since carbon in the recycle stream is not actually emitted. In response 
to this comment we have added reporting requirements for quantifying 
emissions associated with the recycle stream. This will help EPA 
improve methodologies for calculating emissions from ammonia 
manufacturing in the future.
Monitoring and QA/QC Requirements
    Comment: Several commenters stated that monthly carbon content 
sampling and analysis requirement is overly burdensome. Some commenters 
asked that EPA allow the use of a default value for carbon content 
while one commenter suggested use of carbon content data generated by 
the feedstock supplier.
    Response: We agreed with commenters that flexibility should be 
added to the rule to allow for use of supplier data. This information 
is readily available from the feedstock supplier in most cases. The 
most common feedstock for ammonia production is pipeline quality 
natural gas. Supplier data on carbon contents of feedstock will have 
sufficient or comparable accuracy for the purposes of calculating 
CO2 emissions. We modified the monitoring and QA/QC 
procedures in the rule to allow use of carbon content data obtained 
from the feedstock supplier(s). Facilities that obtain monthly carbon 
content information from their supplier are required to QA/QC supplier 
information through annual sampling and analysis of the feedstocks 
consumed.
Procedures for Missing Data
    Comment: Two commenters suggested that the proposed procedures for 
calculating emissions in the event of missing feedstock data would 
yield significant overstatements of GHG emissions. As proposed, if 
feedstock supply rate data are missing for a specific day or days 
(e.g., if a meter malfunctions during unit operation), the reporting 
entity must use the lesser of the maximum supply rate that the 
production unit is capable of processing or the maximum supply rate 
that the meter can measure. If this substitution is applied to the 
feedstock for reformers used in ammonia production, either of these 
proposed approaches would likely result in significant over reporting 
of carbon emissions. The commenter proposed two alternatives that a 
reporting facility could use: Either (1) substitute an estimated value 
for feedstock supply rate, based on the arithmetic average of the 
previous thirty days of available feedstock supply rate data; or (2) 
utilize missing data estimating procedures similar to the procedure 
under 40 CFR 98.35(b)(2), based upon all available process data. These 
approaches would result in much more accurate estimates of emissions 
derived from the true historical operation of a specific ammonia 
manufacturing source.
    Response: We agreed with commenters that the proposed missing data 
procedures would overestimate emissions when applied. While some of 
feedstock should be readily available and collected as a part of normal 
business practices, circumstances could arise where data could be 
missing. We added procedures consistent with the commenter's second 
recommendation, referencing the missing data procedures in 98.35(b)(2). 
Ammonia facilities with missing data on feedstock supply rate must 
provide the best available estimate from all available process data. 
Facilities must document and keep records of missing data procedures 
applied. We find that these revised procedures will provide accurate 
information for the purposes of this rulemaking.
Data To Be Reported
    Comment: One commenter noted that the CO2 produced 
through ammonia manufacturing can be utilized and that much of it is in 
the manufacture of urea. The commenter stated that EPA makes 
unsubstantiated assumptions that all CO2 in urea will be 
released into the atmosphere. The commenter asked EPA not to tie 
emissions from applied urea, or emissions that result from urea once 
the product has been sold, to the producing industry.
    Response: We added reporting requirements for annual urea 
production under 40 CFR 98.76. Information on urea production will help 
us improve our understanding of the quantity of CO2 consumed 
from ammonia production that is used in the manufacture of urea. We 
know from the US GHG inventory and subsequent conversations with 
ammonia producers that on average it takes 0.733 tons of CO2 
to produce one ton of urea. We have also requested that producers 
report, if known, the uses of the urea sold. Collecting information on 
urea production and its uses will help EPA to improve methodologies for 
calculating emissions from ammonia manufacturing, urea production, and 
urea consumption in the future.

H. Cement Production

1. Summary of the Final Rule
    Source Category Definition. The cement production source category 
consists of each kiln and each inline kiln/raw mill at any Portland 
cement manufacturing facility, including alkali bypasses and kilns and 
inline kilns/raw mills that burn hazardous waste.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.

[[Page 56300]]

    GHGs to Report. For cement production, report the following 
emissions:
     CO2 process emissions from calcination, 
reported for each kiln.
     CO2 combustion emissions from each kiln.
     N2O and CH4 emissions from fuel 
combustion at each kiln under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources) using the methodologies in subpart 
C.
     CO2, N2O, and CH4 
emissions from each stationary combustion unit other than kilns under 
40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
     In addition, report GHG emissions for any other source 
categories for which calculation methods are provided in other subparts 
of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2 
emissions from kilns, reporters must select one of two methods, as 
appropriate:
     For kilns with certain types of CEMS in place, reporters 
must use the CEMS and follow the Tier 4 methodology (in 40 CFR part 98, 
subpart C) to measure and report under the Cement Production subpart 
(40 CFR part 98, subpart H) combined calcination and fuel combustion 
CO2 emissions.
     For other kilns, the reporter can elect to either (1) 
install or operate a CEMS and follow the Tier 4 methodology to measure 
and report combined calcination and fuel combustion CO2 
emissions or (2) calculate process CO2 emissions as the sum 
of clinker emissions and emissions from raw materials. If using 
approach (2):

--Calculate clinker emissions monthly from each kiln using monthly 
clinker production (required to be measured); a kiln-specific, monthly 
clinker emission factor calculated from the monthly CaO and MgO content 
of the clinker (required to be measured); quarterly cement kiln dust 
not recycled to the kiln (required to be measured); and a quarterly 
kiln-specific factor of calcined material in the cement kiln dust not 
recycled to the kiln (measured or default values can be used).
--Calculate raw material emissions annually from the annual consumption 
of raw materials and the organic carbon content in the raw material 
(measured annually for each type of raw material, or a default value of 
0.2 percent may be used).
--Report process CO2 emissions from each kiln under 40 CFR 
part 98, subpart H (Cement Production), and report combustion 
CO2 emissions from each kiln under 40 CFR part 98, subpart C 
(General Stationary Fuel Combustion Sources).
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
Subpart H (Cement Production).
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart H (Cement Production).
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart H: Cement Production.''
     The CO2 calculation equations in 40 CFR 98.83 
were revised to account for non-carbonate sources of calcium and 
magnesium in the kiln feed and uncalcined carbonates in the product.
     Methods for monitoring CaO and MgO in clinker and CKD were 
changed from XRF to ASTM c114-07, Standard Test Methods for Chemical 
Analysis of Hydraulic Cement.
     40 CFR 98.84 was revised to clarify required monitoring 
frequency and to allow for alternative monitoring methods for raw 
materials and CKD.
     Missing data procedures were added to 40 CFR 98.85 for 
parameters reporters must measure, clinker, CKD not recycled to the 
kiln, raw material consumption, carbonate contents of clinker CKD, non-
calcined content of clinker and CKD, and organic carbon content of raw 
materials.
     Requirements in 40 CFR 98.81 through 40 CFR 98.87 were 
revised to clarify which requirements apply to reporters who elect to 
report CO2 emissions using CEMS.
     40 CFR 98.86 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.87 to 40 CFR 98.86, and some data elements that a reporter must 
already use to calculate GHGs as specified in 40 CFR 98.83 were added 
to 40 CFR 98.86 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. We received several comments on cement production covering a 
number of topics. Many of these comments were directed at the 
requirements for 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources), and responses to those comments are provided in 
Section III.C of this preamble dealing with that source category. Also 
see Section II.N of this preamble for the response to comments on the 
emissions verification approach.
    Responses to significant comments received related to process 
emissions from cement production can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subpart H: 
Cement Production.''
Selection of Threshold
    Comment: One commenter suggested that EPA could reduce the burden 
presented by the Proposed Rule by reducing the number of facilities 
required to report (i.e., raise the reporting thresholds). The 
commenter further noted that by requiring GHG reporting for all cement 
plants, regardless of the magnitude of the plant's emissions, EPA 
removes an incentive for those plants to reduce GHG emissions to get 
below a threshold in order to avoid the burden of monitoring and 
reporting.
    Response: In considering the comment, we acknowledge the potential 
benefit of a reporting threshold providing cement plants with incentive 
to reduce their GHG emissions. The ``once in, always in'' provision has 
been removed. The final rule now contains provisions to cease reporting 
if annual reports demonstrate emissions less than specified levels for 
multiple years. These provisions apply to all reporting facilities. See 
Section II.H of this preamble for the response on provisions to cease 
reporting. See Section II.D of this preamble for the response on 
selection of source categories to report.
    In developing the Proposed Rule, we considered emission-based 
thresholds of 1,000 metric tons CO2e, 10,000 metric tons 
CO2e, 25,000 metric tons CO2e, and 100,000 metric 
tons CO2e. All of these emission thresholds covered more 
than 99.9 percent of CO2e emissions from cement facilities. 
Only one plant out of 107 in the dataset would be excluded by the 
highest considered thresholds of 100,000 metric tons CO2e. 
Therefore, we

[[Page 56301]]

determined that it was appropriate to include all cement production 
facilities in the reporting requirements.
Method for Calculating GHG Emissions
    Comment: Two commenters stated that the cement industry already has 
an established, proven protocol for calculating and reporting GHG 
emissions, and requested that EPA use the existing Cement 
CO2 Protocol as the basis for the Proposed Rule. Commenters 
further stated that the Cement CO2 Protocol already provides 
many of the benefits that EPA ascribes to the Proposed Rule, including 
uniformity of reported data from one facility to another; availability 
of verifiable data to provide to the public, investors, and others; and 
other suggested benefits.
    Both commenters stated that EPA needs to revise its clinker-based 
calculation to account for any non-carbonated CaO or MgO in the raw 
materials.
    Response: In developing the proposed Rule, we considered many 
domestic and international GHG monitoring guidelines and protocols, 
including the Cement Sustainability Initiative Protocol referenced in 
the cement industry's comments. We combined elements of the Cement 
CO2 Protocol with elements of other protocols including the 
2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), CARB mandatory GHG 
emissions reporting program, EPA's Climate Leaders program, and the EU 
Emissions Trading System to develop two proposed methods for 
quantifying GHG emissions from cement manufacturing. These proposed 
methods include the use of CEMS to directly measure emissions and the 
use of calculation methods to determine emissions.
    While finalizing today's rule, we revisited the Cement 
CO2 Protocol and compared its requirements to our 
requirements. We feel that the rule closely mirrors the GHG calculation 
methods and requirements of the Cement CO2 Protocol with 
some minor differences. For example, our rule requires cement plants to 
use plant-specific emission factors to calculate CO2 
emissions and does not allow the use of default emission factors. As 
stated in the proposal, we have determined that applying default 
emission factors to clinker production is more appropriate for 
national-level emissions estimates than facility-specific estimates, 
where data are readily available to develop site-specific emission 
factors. Default approaches would not provide site-specific calculation 
of emissions that reflect differences in inputs, operating conditions, 
fuel combustion efficiency, variability in fuels, and other differences 
among facilities. Further, it is our understanding that facilities 
analyze data relevant for site-specific determinations such as the 
carbonate contents of their raw materials to the kiln and products on a 
frequent basis, either on a daily basis or every time there is a change 
in the raw material mix. Using data from direct measurements will 
provide a more accurate representation of site specific emissions 
rates.
    We also note that the Cement CO2 Protocol does not 
specify measurement methods. Our rule specifies methods for measuring 
CaO, MgO, and clinker weight. We selected these methods to be 
consistent with measurement techniques that are common within the 
cement industry. Prescribing standardized measurement procedures 
ensures the uniformity and consistency in the results and quality of 
data reported that the commenters agree is important for comparability 
of emissions.
    We also used the Cement CO2 Protocol as a model for 
revising our equations in 40 CFR 98.83 to account for non-carbonate 
sources of calcium and magnesium that may be present in the kiln feed.
Monitoring and QA/QC Requirements
    Comment: One commenter expressed concern that 40 CFR 98.84(e) and 
(f) seem to require continuous, direct weight measurement of CKD 
discarded and raw materials used, by category of material. The 
commenter stated that most cement plants do not have that capability, 
and that the proposed rule does not clearly state whether installation 
of additional measurement equipment will be required if not already 
installed.
    One industry representative further recommended that EPA add truck 
weight scales as an acceptable option for raw material weight 
measurement to address certain limited cases in which this method may 
be more appropriate to use. In addition, the commenter recommended that 
EPA allow CKD samples to be taken either as CKD exits the kiln or from 
bulk storage.
    Response: We revised the text in 40 CFR 98.84(e) and (f) to more 
clearly state that CKD quantities are required to be measured on a 
quarterly basis and raw material quantities are required to be measured 
on a monthly basis. Furthermore, the Proposed Rule was never intended 
to require installation of new monitoring equipment for this purpose. 
We agree with the commenter that continuous, direct weight measurement 
of these materials and installation of additional measurement equipment 
would be unnecessary. The proposed rule clearly stated that the 
quantity of CKD produced and raw materials consumed must be determined 
using the same plant instruments that the cement plant currently uses 
for accounting purposes. Moreover, because the quantities of raw 
materials and CKD do not greatly impact the CO2 calculation, 
we added further clarification to this section to allow cement plants 
to use potentially less accurate, but commonly used, methods of 
measurement, such as truck weigh scales, to determine quantities of CKD 
and raw materials. We also added clarification to 40 CFR 98.84 to allow 
facilities to collect CKD samples either as CKD exits the kiln or from 
bulk storage.
Data Reporting Requirements
    Comment: Two commenters asserted that EPA needs to provide 
clarifying language within 40 CFR part 98, subpart H (Cement 
Production) to define which requirements apply to facilities using CEMS 
to monitor CO2 emissions. One commenter noted that the 
Proposed Rule, as written, appears to require cement plants using CEMS 
to collect maintain, and report process data related to calculating 
CO2 process emissions for kilns pursuant to proposed 40 CFR 
98.84 through 98.87. This commenter claimed that requiring plants to 
collect and report such process data are redundant if the facility is 
continuously monitoring CO2 emissions. Another commenter 
recommended that EPA state within 40 CFR part 98, subpart H (Cement 
Production) that all of the requirements detailed in the subpart do not 
apply to cement kilns using Tier 4 (CEMS) method.
    Response: We agree with the comment that reporters who are using 
CEMS to monitor CO2 do not need to collect, report, and 
maintain all of the process data required in proposed 40 CFR 98.84 
through 98.87. However, we determined that some of the process data are 
necessary for emissions verification purposes, and therefore, plants 
using CEMS are not completely excluded from the requirements in 40 CFR 
part 98, subpart H (Cement Production). We added clarifying language 
throughout the Subpart to clearly state which requirements will apply 
to facilities that use CEMS to measure CO2 emissions. 
Specifically, we created separate lists of reporting requirements and 
recordkeeping requirements for cement plants using CEMS.

[[Page 56302]]

    Comment: One commenter noted that the data reporting requirements 
for cement plants, set forth in proposed 40 CFR 98.86, are expressed in 
different terms that those used for the specified procedures for 
calculating emissions. For example, the commenter stated that it is 
unclear what emission sources go into the ``site-specific emission 
factor (metric tons CO2/metric ton clinker produced)'' 
required to be reported under proposed 40 CFR 98.86(h), and how that 
factor would be calculated.
    Response: We agree with the commenter that there were 
inconsistencies between 40 CFR 98.83 and 98.86. We updated reporting 
requirements in 40 CFR 98.86 to be consistent with the terms used in 
the emission calculation procedures in 40 CFR 98.83 and provide 
clarification in 40 CFR 98.83 for terms if needed. As a result, some 
calculations that are performed on a kiln-specific basis, such as 
CO2 emission factors, will be required to be reported on a 
kiln-specific basis in 40 CFR 98.86. Also see the Section II.N of this 
preamble for the response to comments on the emissions verification 
approach.

I. Electronics Manufacturing

    At this time EPA is not going final with the electronics 
manufacturing subpart. As we consider next steps, we will be reviewing 
the public comments and other relevant information.
    The Agency received a number of lengthy, detailed comments 
regarding the electronics manufacturing subpart. Commenters generally 
opposed the proposed reporting requirements and stated the proposal 
required excessive detail. For example, commenters asserted that they 
currently do not collect the data required to report using an IPCC Tier 
3 approach and that to collect such data would entail significant 
burden and capital costs. In most cases, commenters provided 
alternative approaches to each of the reporting requirements proposed 
by EPA.
    Commenters also requested clarification from EPA on a number of the 
proposed reporting provisions.
    Based on careful review of comments received on the proposal 
preamble, rule, and technical support documents (TSDs) under proposed 
40 CFR part 98, subpart I, EPA will perform additional analysis and 
evaluate a range of data collection procedures and methodologies. EPA's 
goal is to optimize methods of data collection to ensure data accuracy 
while considering industry burden.

J. Ethanol Production

    At this time, EPA is not finalizing the Ethanol Production Subpart. 
The sources of GHG emissions at ethanol production facilities that were 
to be reported under the proposed rule were stationary fuel combustion, 
onsite landfills, and onsite wastewater treatment. EPA has decided not 
to finalize the portion of 40 CFR part 98, subpart HH (Landfills) that 
addresses industrial landfills nor 40 CFR part 98, subpart II 
(Wastewater Treatment). Stationary fuel combustion sources at ethanol 
production facilities are subject to the requirements of 40 CFR part 
98, subpart C if general stationary fuel combustion emissions exceed 
the 25,000 metric tons CO2e threshold.
    As EPA considers next steps, we will be reviewing the public 
comments and other relevant information. Based on careful review of 
comments received on the proposal preamble, rule and TSDs under 
proposed 40 CFR part 98, subparts J, HH, and II, EPA will perform 
additional analysis and consider alternatives to data collection 
procedures and methodologies contained in those subparts.

K. Ferroalloy Production

1. Summary of the Final Rule
    Source Category Definition. The ferroalloy production source 
category consists of facilities that use pyrometallurgical techniques 
to produce any of the following metals: ferrochromium, ferromanganese, 
ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, 
ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For ferroalloy production, report the following 
emissions.
     Annual process CO2 emissions from each EAF used 
for production of any ferroalloy listed in the source category 
definition.
     Annual process CH4 emissions for those EAFs 
used for the production of silicon metal, ferrosilicon 65 percent, 
ferrosilicon 75 percent, or ferrosilicon 90 percent.
     CO2, N2O, and CH4 
emissions from each stationary combustion unit on site under 40 CFR 
part 98, subpart C (General Stationary Fuel Combustion Sources).
     In addition, report emissions from any other source 
categories for which calculation methodologies are specified in the 
rule, as applicable.
    GHG Emissions Calculation and Monitoring. To calculate process 
CO2 emissions from EAFs, reporters can use one of two 
methods, as appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions from each EAF by either (1) installing and 
operating a CEMS and following the Tier 4 methodology (in 40 CFR part 
98, subpart C) or (2) using the carbon mass balance calculation 
procedure specified in the rule and summarized below.
     However, if CO2 process emissions from an EAF 
are emitted through the same stack as CO2 emissions from a 
combustion unit or process equipment that uses a CEMS and follows Tier 
4 methodology to report CO2 emissions, then the CEMS must be 
used to measure and report combined emissions from that stack, instead 
of using the carbon mass balance calculation procedure described below.
     If using the carbon mass balance procedure, perform a once 
per year calculation using equations in the rule and:

--Recorded monthly production data, and
--The average carbon content for each EAF input and output material 
determined by either using material supplier information or by annual 
analysis of representative samples of the material.

     For those EAF's for which the reporter must report annual 
CH4 emissions, annual ferroalloy production data are used 
with an applicable emissions factor provided in the rule.

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart K.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart K.
2. Summary of Major Changes Since Proposal
    The major changes to the rule since proposal for ferroalloy 
production facilities were revisions to the carbon

[[Page 56303]]

mass balance calculation procedure for calculating process 
CO2 emissions from EAFs. These changes reduce the reporting 
burden and are consistent with revisions made to other similar 
industries. The rationale for these and any other significant changes 
can be found below or in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart K: Ferroalloy Production.''
     Frequency of performing the carbon mass balance 
calculations was revised to be required on an annual basis instead of 
the proposed monthly basis.
     Frequency of material carbon content sampling and analysis 
of each EAF input and output material used for the material balance was 
revised to be performed by annual analysis of representative samples of 
the material instead of the proposed monthly basis.
     Materials contributing less than one percent of the total 
carbon into or out of the EAF do not need to be included carbon mass 
balance calculations.
     40 CFR 98.116 and 98.117 were reorganized and updated to 
improve the emissions verification process. Some data elements were 
moved from 40 CFR 98.117 to 40 CFR 98.116, and some data elements that 
a reporter must already use to calculate GHGs as specified in 40 CFR 
98.173 were added to 40 CFR 98.116 for clarity. See Section II.N of 
this preamble for the response to comments on the emissions 
verification approach.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Other comments on ferroalloy production were received 
covering various topics. Responses to significant comments received can 
be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart K: Ferroalloy Production.''
    Comment: One comment was received on the proposed rule specific to 
ferroalloy production facilities. The commenter requested that EPA 
allow ferroalloy production facilities to use alternative methods for 
determining EAF process CO2 emissions other than those 
proposed, and specifically a protocol for silicon metal production 
facilities developed for use by the Chicago Climate Exchange. This 
smelting protocol was developed a protocol for calculating the 
CO2 emissions from based on the World Resources Institute 
(WRI) aluminum smelting protocol.
    Response: We reviewed the WRI aluminum smelting protocol, which was 
publicly available and we tried to obtain a copy of the specific 
protocol that the commenter mentions to fully evaluate whether it is an 
appropriate alternative. However, we never received it in the long run. 
The commenter did not provide additional or more specific 
recommendations beyond the reference to improve or revise the proposed 
methodology. At this time, given insufficient information, we have 
decided not to include additional alternative methods in the final rule 
for ferroalloy production facilities. As we stated at proposal, the 
selected methodology was based on review of several existing 
methodologies used by the 2006 IPCC Guidelines for National Greenhouse 
Gas Inventories, Canadian Mandatory Greenhouse Gas Reporting Program, 
the Australian National Greenhouse Gas Reporting Program, and EU 
Emissions Trading System.
    However, we have revised the frequency of sampling and analysis of 
carbon contents for carbon containing input and output materials 
monthly to annual consistent with revisions made in response to 
comments for similar production processes (e.g. emissions from metal 
production). These revisions reduce the reporting burden for ferroalloy 
production facilities. We understand that the carbon content of 
material inputs and outputs does not vary widely at a given facility 
for the significant process inputs that contain carbon, and we continue 
to account for variations due to changes in production rate, which is 
likely a more significant source of variability. The response to the 
comment can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart K: Ferroalloy Production.''

L. Fluorinated GHG Production

    At this time EPA is not going final with the subpart for emissions 
from fluorinated GHG production. As we consider next steps, we will be 
reviewing the public comments and other relevant information.
    The Agency received a number of lengthy, detailed comments 
regarding the fluorinated GHG production subpart. Commenters generally 
opposed the proposed reporting requirements. Several commenters stated 
that facilities could not meet the proposed accuracy, precision, and 
frequency requirements using existing equipment and practices. These 
commenters stated that they would need to expend significant funds 
(millions of dollars in some cases) and time to install Coriolis 
flowmeters in multiple streams and to implement daily sampling 
protocols to analyze the contents of these streams. Some commenters 
stated that even after such equipment was installed, the proposed mass-
balance approach was likely to be inaccurate, particularly for batch 
processes. In most cases, commenters provided alternative approaches, 
such as emission-factor based approaches, to the proposed mass-balance 
approach.
    Based on careful review of comments received on the proposal 
preamble, rule, and TSDs under proposed 40 CFR part 98, subpart L, EPA 
will perform additional analysis and evaluate a range of data 
collection procedures and methodologies. EPA's goal is to optimize 
methods of data collection to ensure data accuracy while considering 
industry burden.

M. Food Processing

    At this time, EPA is not going final with the Food Processing 
Subpart. The sources of GHG emissions at food processing facilities 
that were to be reported under the proposed rule were stationary fuel 
combustion, onsite landfills, and onsite wastewater treatment. EPA has 
decided not to finalize the portion of 40 CFR part 98, subpart HH 
(Landfills) that addresses industrial landfills nor 40 CFR part 98, 
subpart II (Wastewater Treatment). Note, however, that Stationary fuel 
combustion sources at food processing facilities are subject to the 
requirements of 40 CFR part 98, subpart C if general stationary fuel 
combustion emissions exceed the 25,000 metric ton CO2e 
threshold. As EPA considers next steps, we will be reviewing the public 
comments and other relevant information.
    Based on careful review of comments received on the proposal 
preamble, rule and TSDs under proposed 40 CFR part 98, subparts M, HH, 
and II, EPA will perform additional analysis and consider alternatives 
to data collection procedures and methodologies contained in those 
subparts.

N. Glass Production

1. Summary of the Final Rule
    Source Category Definition. The glass production source category 
consists of facilities that manufacture glass (including flat, 
container, pressed, or blown glass) or wool fiberglass using one or 
more continuous glass melting furnaces. Experimental furnaces and 
research and development process units are excluded.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.

[[Page 56304]]

    GHGs to Report. For glass production facilities, report the 
following emissions:
     CO2 process emissions from each continuous 
glass melting furnace.
     CO2 combustion emissions from each continuous 
glass melting furnace,
     CH4 and N2O emissions from fuel 
combustion at each continuous glass melting furnace under 40 CFR part 
98, subpart C (General Stationary Combustion Sources) using the 
methodologies in subpart C.
     CO2, CH4, and N2O 
emissions and from each onsite stationary fuel combustion unit other 
than continuous glass melting furnaces under 40 CFR part 98, subpart C 
(General Stationary Combustion Sources).
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2 
process emissions from glass melting furnaces, reporters must use one 
of two methods, as appropriate:
     For glass melting furnaces with certain types of CEMS in 
place, reporters must use the CEMS and follow the Tier 4 methodology 
(in 40 CFR part 98, subpart C) to measure and report under the glass 
production subpart (40 CFR part 98, subpart N) combined process and 
combustion CO2 emissions.
     For other glass melting furnaces, the reporter can elect 
to either (1) install and operate a CEMS and follow the Tier 4 
methodology to measure and report combined process and combustion 
CO2 emissions or (2) calculate process CO2 
emissions for each furnace using an emission factor and process data. 
If using approach (2), multiply a default emission factor appropriate 
for the carbonate raw material by:

--The annual mass of carbonate-based raw material charged to the 
furnace (required to be measured); and
--The mass-fraction of carbonate in the raw material (based on data 
supplied by the raw material supplier and verified by an annual 
measurement).
--Under approach (2), report process CO2 emissions from each 
glass melting furnace under 40 CFR part 98, subpart N (Glass 
Production), and report combustion CO2 emissions from each 
glass furnace under 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources).

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart N.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart N.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart N: Glass Production.''
     The definition of the term ``glass produced'' was added to 
the definitions in 40 CFR part 98, subpart A.
     40 CFR 98.146 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.147 to 40 CFR 98.146, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.143 were 
added to 40 CFR 98.146 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments on glass production were received covering 
numerous topics. Responses to significant comments received can be 
found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments, Subpart N: Glass Production.''
Definition of Source Category
    Comment: One commenter stated that EPA should exempt from the rule 
all fiber glass and rock and slag wool insulation facilities within the 
glass production source category because glass production facilities 
subject to the proposed rule are a miniscule portion of the total 
national emissions of CO2e, and amount to less than 0.1 
percent of total GHG emissions in the U.S. and the subset of fiber 
glass and rock and slag wool insulation facilities is an even smaller 
portion. The commenter stated that there is virtually no benefit to 
having the glass production source category subject to the proposed 
rule, and any benefit is outweighed by the burden imposed on these 
facilities. The commenter also pointed out the importance of the fiber 
glass and rock and slag wool insulation industry's products in meeting 
the nation's energy needs and reducing GHG emissions. Exempting the 
industry from the proposed rule's reporting requirements will help the 
industry focus more of its scarce resources on producing insulation.
    Response: We recognize that the glass manufacturing industry is 
comprised of a wide range of facilities, many of which are small in 
size and have relatively low levels of emissions. However, the data we 
have collected on the industry indicate that there are several large 
glass manufacturing plants with significant GHG emissions. These plants 
include some that produce glass fiber, flat glass, and container glass, 
as well as other types of pressed and blown glass products. As a 
result, we do not agree with the commenter that fiber glass and other 
types of insulation facilities should be exempt from reporting. 
However, we tried to reduce the burden on the glass manufacturing 
industry by incorporating into the proposed rule a 25,000 metric ton 
CO2e threshold, which should preclude small facilities from 
having to report GHGs. This threshold remains in the final rule. Thus, 
any small fiber glass and rock and slag wool insulation facilities with 
low GHG emissions will fall under the threshold and will be exempt from 
reporting. To further minimize the burden on the industry, we have 
tried to limit recordkeeping and reporting requirements to the types of 
data that glass production facilities already collect as part of normal 
business operations.
    Commenters may also be interested in reviewing Section II.H of this 
preamble for the response on provisions to cease reporting. The final 
rule contains provisions to cease reporting if annual reports 
demonstrate emissions less than specified levels for multiple years.
Selection of Threshold
    Comment: One commenter remarked that EPA should raise the threshold 
for reporting for fiberglass and rock and slag wool insulation 
entities. Doing so would reduce the number of entities reporting with 
only a minimal impact on the amount of emissions covered. The commenter 
stated that EPA's analysis did not address reasonable alternative 
thresholds between 25,000 and 100,000 metric tons.
    Response: When evaluating potential thresholds for reporting GHG 
emissions, we considered several thresholds

[[Page 56305]]

between 1,000 and 100,000 metric tons CO2e. We selected the 
25,000 metric tons CO2e threshold for reporting GHG 
emissions in order to achieve a balance between quantifying the 
majority of the emissions and minimizing the number of facilities 
impacted. For example, at a 1,000 metric tons CO2e 
threshold, 98 percent of emissions would be covered, with about 58 
percent of facilities being required to report. Compared to the 100,000 
metric tons CO2e threshold, the proposed 25,000 metric tons 
CO2e threshold achieves reporting of 11 times more emissions 
while requiring less than 15 percent of the facilities to report. 
Compared to the 10,000 metric tons CO2e threshold, the 
25,000 metric tons CO2e threshold captures more than half of 
those emissions, but only requires a third of the facilities in the 
industry to report. This threshold offers significant coverage of the 
GHG emissions while impacting a relatively small portion of the 
industry. Although a threshold of 50,000 metric tons CO2e 
would greatly reduce the number of facilities reporting, it would 
capture less than 20 percent of total emissions for the industry. We 
believe the proposed threshold of 25,000 metric tons CO2e 
represents the best option for ensuring that the majority of emissions 
are reported without imposing an unreasonable burden on the industry.
    Section II.E of this preamble contains a general discussion of the 
selection of the 25,000 metric tons CO2e threshold.
Method for Calculating GHG Emissions
    Comment: One commenter fully supports EPA's proposed rule for 
measuring, calculating, monitoring, and reporting emissions from the 
glass melting process. They agree that 40 CFR part 98, subpart N 
represents a good balance between site reporting burden, cost, and data 
accuracy and consistency. Specifically, the commenter supports using 
raw-material emissions factors and usage rates, as proposed, to 
calculate emissions from glass production in lieu of requiring 
installing CEMs on sources that another regulation does not currently 
require to be installed.
    Response: We acknowledge this support for the proposal and 
appreciate these comments. We have retained the proposed calculation 
methodology in the final rule.
Data Reporting Requirements
    Comment: One commenter stated that, at various places in the 
preamble and proposed rule, EPA uses the phrase ``glass produced,'' but 
has not defined this phrase in the rule. The commenter noted that the 
phrase could be interpreted to mean either glass melted or glass 
product produced. The commenter assumed that the phrase refers to the 
amount of glass melted, but requested clarification.
    Response: We agree that the term glass produced is subject to 
interpretation. We have added a definition of the term to 40 CFR part 
98, subpart A of the final rule. ``Glass produced'' means the weight of 
glass exiting a glass melting furnace.
    Comment: One commenter remarked that some of the information that 
would have to be reported under the proposed rule, such as annual 
quantity of glass produced, is considered to be company confidential 
and could be used by competitors to back-calculate product formulas. 
The commenter requested that EPA remove these reporting requirements 
from the rule and instead, require that the data be retained by the 
facility and made available for review by EPA. Should EPA require the 
reporting of all of this information in the final rule, the commenter 
requests that EPA explicitly state in the final rule and confirm in the 
preamble to the final rule that all information provided under 40 CFR 
part 98, subpart N, other than the annual process emissions of 
CO2, is considered confidential information and would not be 
considered ``emission data'' under this reporting rule. The commenter 
requests that a new paragraph (e) be added to 40 CFR 98.146 that reads: 
``No information required to be reported by this section, other than 
the information required by 40 CFR 98.146(a), is considered to be 
emission data under 40 CFR 2.301(a)(2)(i) and (ii).''
    Response: We acknowledge the commenter's concerns. However, the 
quantity of glass produced is an important variable for EPA to verify 
whether reported emissions are within a reasonable range and therefore 
is a required reporting parameter under 40 CFR part 98, subpart N.
    We have reviewed CBI comments received across the rule (both 
general and subpart-specific comments) and our response is discussed in 
Section II.R of this preamble and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues.''

O. HCFC-22 Production and HFC-23 Destruction

1. Summary of the Final Rule
    Source Category Definition. This source category consists of:
     Processes that produce HCFC-22 (chlorodifluoromethane or 
CHClF2) using chloroform and hydrogen fluoride.
     HFC-23 destruction processes located at HCFC-22 production 
facilities.
     HFC-23 destruction processes that destroy more than 2.14 
metric tons of HFC-23 per year and that are not located at HCFC-22 
production facilities.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For facilities that produce HCFC-22 or that destroy 
HFC-23, report the following emissions:
     HFC-23 emissions from all HCFC-22 production processes at 
the facility.
     HFC-23 emissions from each destruction process.
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
by following the requirements of 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources).
    GHG Emissions Calculation and Monitoring. Reporters must calculate 
HFC-23 emissions as follows:
     For HCFC-22 production processes that do not use a thermal 
oxidizer or that have a thermal oxidizer that is not connected to the 
production equipment, calculate annual HFC-23 emissions at the facility 
level using a mass balance equation and the following information: 
annual HFC-23 generated, the annual HFC-23 sent off site for sale, the 
annual HFC-23 sent off site for destruction, the annual increase in the 
HFC-23 inventory, and the annual HFC-23 destroyed on site (calculated 
by multiplying the mass of HFC-23 fed to the destruction device by the 
destruction efficiency).
     For HCFC-22 production processes with a thermal oxidizer 
that is connected to the production equipment, calculate annual HFC-23 
emissions at the facility level by summing the following emissions:

--Annual HFC-23 emissions from equipment leaks (calculated using 
default emission factors and the measured number of leaks in valves, 
pump seals, compressor seals, pressure relief valves, connectors, and 
open-ended lines).
--Annual HFC-23 emissions from process vents (calculated for each vent 
using the HFC-23 emission rate from the most recent emission test and 
the ratio of the actual production

[[Page 56306]]

rate and the production rate during the emission test).
--Annual HFC-23 from the thermal oxidizer (calculated by subtracting 
the amount of HFC-23 destroyed by the destruction device from the 
measured mass of HFC-23 fed to the destruction device).

     For other HFC-23 destruction processes, calculate HFC-23 
emissions based on the mass of HFC-23 fed to the destruction device and 
the destruction efficiency.
     For the destruction efficiency, conduct a performance test 
or use the destruction efficiency determined during a previous 
performance test. To confirm the destruction efficiency, measure the 
fluorinated GHG concentration at the outlet to the destruction device 
annually.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart O.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart O.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart O: HCFC-22 Production and HFC-23 
Destruction.''
     The minimum required frequency of mass flow and 
concentration measurements has been decreased from daily to weekly.
     The required frequency of emissions tests at process vents 
has been decreased to once every five years. A test is also required 
after a significant change is made to the process.
     The required annual measurements at the outlet of the 
thermal oxidizer now omit measurements of mass flow. Three samples are 
required to be taken; the average of these is compared to the 
concentration at the outlet of the oxidizer that was measured during 
the initial performance test that established the destruction 
efficiency.
     A term has been added to the mass-balance equation for 
HCFC-22 production facilities that do not have a thermal oxidizer that 
is directly connected to the HCFC-22 production equipment. This term 
accounts for increases in the inventory of stored HFC-23 that can occur 
during the year.
     EPA has added an additional method for estimating missing 
mass flow data in the event that a secondary mass measurement for that 
stream is not available.
     The option for reporters to develop their own methods for 
estimating missing data if they believe that the prescribed method will 
over- or under-estimate the data has been removed.
     Some reporting requirements have been added to be 
consistent with the changes to the calculations and monitoring sections 
and to permit verification of emissions calculations.
    EPA decreased the minimum frequency of gas flow and concentration 
measurements from daily to weekly because EPA's research indicates that 
HFC-23 concentrations are not likely to vary significantly over a one 
week period. This change also makes the required measurement frequency 
more consistent with current industry practice.
    As noted above, EPA removed the option for reporters to develop 
their own methods for estimating missing data if they believe that the 
prescribed method will over- or underestimate the data. EPA removed 
this option for two reasons. First, the proposed provision lacked clear 
guidance on when alternative methods should be used (e.g., on the size 
of an underestimate that would justify use of an alternative method) 
and on how they should be developed. Second, the proposed provision was 
redundant with the new provision that permits reporters to estimate 
missing data using a related parameter and the historical relationship 
between the related parameter and the missing parameter. This new 
option provides reporters with flexibility in substituting for missing 
data in the event that a secondary mass measurement is not available, 
but sets out general guidance on how to select the substitute data.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A number of comments on HCFC-22 production and HFC-23 
destruction were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subpart O: HCFC-
22 Production and HFC-23 Destruction.''
Monitoring and QA/QC Requirements
    Comment: EPA received a comment that the requirement to annually 
conduct emissions tests at process vents is overly burdensome and 
unnecessary because it is unlikely that the emissions rate would 
deviate from an initial process vent test unless there were a 
significant change in the process. This commenter argued that testing 
should be required at least every five years or after a significant 
change in the process.
    Response: In response to this comment, EPA has reduced the required 
frequency of emissions tests at process vents to once every five years, 
or after a significant change to the process. EPA has also clarified 
that the requirement applies only to HCFC-22 production facilities that 
use a thermal oxidizer connected to the HCFC-22 production equipment. 
These are the only facilities that use process vent emission estimates 
in their calculation of facility-wide HFC-23 emissions.
    EPA is decreasing the frequency of emissions tests at process vents 
for two reasons. First, EPA agrees with the commenter that, in the 
absence of a significant process change, the process vent emission rate 
is not likely to vary much (in percentage terms) from year to year. 
Second, although small variations in the emission rate could still lead 
to significant absolute errors for facilities with large process vent 
emissions, the facilities that are required to test their process vent 
emissions are likely to have small process vent emissions (because they 
use thermal oxidizers connected to the production equipment). 
(Facilities that do not use thermal oxidizers connected to the 
equipment would be expected to have larger process vent emissions, but 
they are required to use a mass-balance approach to calculate emissions 
rather than summing emissions across process vents, equipment leaks, 
and thermal oxidizers.) Together, these considerations lead to the 
conclusion that testing process vent emissions every five years should 
sufficiently minimize errors in the overall HFC-23 emission 
calculations of the facilities affected by the testing requirement.
    Comment: EPA should add a term to Equation O-4 (the mass-balance 
equation for HCFC-22 production facilities that do not have a thermal 
oxidizer that is directly connected to the HCFC-22 production 
equipment) to account for increases in the inventory of

[[Page 56307]]

stored HFC-23 that can occur during the year.
    Response: EPA added a term to Equation O-4 for increases in the 
inventory of stored HFC-23. EPA agrees that the equation should account 
for changes in the inventory of HFC-23 that is stored on site. It is 
important to track all reservoirs of HFC-23 at the facility; mass-
balance approaches used to track emissions from other sources (e.g., 
from electrical equipment) frequently include terms to account for the 
increase in inventory.
Definition of Source Category
    Comment: EPA received a comment that the measurement of HFC-23 
emissions from HCFC-22 production should be moved to Subpart L, which 
covers the reporting of fluorinated GHG production.
    Response: EPA proposed provisions for facilities producing 
fluorinated gases in three separate subparts: 40 CFR part 98, Subpart 
L, Subpart O, and Subpart OO. Although there are many similarities 
across the chemicals and processes covered by the three subparts, the 
subparts were deliberately tailored to different sources and types of 
emissions. Subpart L was intended to address emissions of fluorinated 
GHGs from fluorinated GHG production. 40 CFR part 98, subpart O was 
intended to address HFC-23 generation and emissions from HCFC-22 
production. 40 CFR part 98, subpart OO was intended to address flows 
affecting the U.S. industrial gas supply, including production, 
transformation, and destruction.
    EPA determined that 40 CFR part 98, subpart O was necessary because 
HCFC-22 production and HFC-23 destruction facilities differ from other 
fluorinated gas production facilities in two key respects. First, the 
primary fluorinated GHG that they generate (HFC-23) is made as a 
byproduct to the production of a substance that is not defined as a 
fluorinated GHG (HCFC-22). Second, due to the very high GWP of HFC-23, 
each HCFC-22 facility generates very large quantities of 
CO2-equivalent. For the second reason, EPA has worked with 
HCFC-22 producers for over ten years to understand and reduce HFC-23 
emissions. The requirements for HCFC-22 producers are therefore based 
on a close knowledge of their production processes and methods for 
accounting for emissions. These methods are also comprehensive (e.g., 
accounting for emissions from equipment leaks and losses during 
transport of HFC-23 that is shipped off-site for destruction). These 
requirements may not be appropriate for other fluorinated gas 
producers, and, at the same time, the requirements for fluorinated gas 
producers may not be appropriate for HCFC-22 producers.

P. Hydrogen Production

1. Summary of the Final Rule
    Source Category Definition. The merchant hydrogen production source 
consists of process units that produce hydrogen by reforming, 
gasification, or other transformation of feedstock and transfer the 
hydrogen produced off site. Hydrogen production facilities located at 
petroleum refineries or other large facilities are included in this 
source category only if they are not owned by or under the direct 
control of the refinery owner. Otherwise, they are considered to be a 
captive hydrogen production source that reports emissions under the 
subpart applicable to the larger facility, e.g., 40 CFR part 98, 
subpart Y (Petroleum Refineries).
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For hydrogen production, report the following 
emissions:
     CO2 process emissions from hydrogen production.
     CO2, N2O, and CH4 
emissions from each stationary combustion unit on site by following the 
requirements of 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources).
     CO2 collected and transferred off site under 40 
CFR part 98, subpart PP (Suppliers of Carbon Dioxide).
     In addition, report GHG emissions for other source 
categories for which calculation methods are provided in the rule, as 
applicable.
    GHG Emissions Calculation and Monitoring.
     To calculate and report process CO2 emissions 
from hydrogen production, most reporters can elect to either (1) 
install and operate CEMS and follow the Tier 4 methodology (in 40 CFR 
part 98, subpart C) or (2) calculate process CO2 emissions 
using equations in the 40 CFR part 98, subpart P and the following 
data:

--Measurements of monthly feedstocks and fuel consumed.
--Carbon content of the feedstock measured monthly.
--Molecular weight of the feedstock (gaseous fuels only).

     However, if process CO2 emissions from hydrogen 
production are vented through the same stack as a combustion unit or 
process equipment that uses a CEMS to follow Tier 4 methodology to 
report CO2 emissions, then the CEMS must be used to measure 
and report combined CO2 emissions from that stack instead of 
the calculation procedure described in approach 2 above.
    Monitoring and QA/QC Requirements. The methods for the initial 
calibration and annual recalibration of flow meters are defined in a 
prescriptive list of industry standard test methods incorporated by 
reference in the Tier 3 method in 40 CFR part 98, subpart C, while the 
methods for determining carbon content of fuels and feedstocks are 
defined in a prescriptive list of an assortment of industry standard 
test methods incorporated by reference.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart P.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart P.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart P: Hydrogen Prodution.''

     40 CFR 98.160 was reworded to clarify the definition of 
reporting entity.
     40 CFR 98.162 was revised to allow reporting of combined 
process and combustion CO2, CH4, and 
N2O emissions.
     In 40 CFR 98.163(b), ``feedstock'' was changed to ``fuel 
and feedstock''.
     40 CFR 98.164 was restructured to clarify between CEMS 
measurements and QA/QC and feedstock method measurements and QA/QC.
     40 CFR 98.164 was reworded to allow the characterization 
of feedstocks to be conducted by either the consumer or the supplier, 
to allow standard gaseous hydrocarbon fuels of commerce to be 
characterized annually, and to allow liquid and solid hydrocarbon fuels 
of commerce to be characterized

[[Page 56308]]

upon delivery if delivered by bulk transport.

     The recalibration requirements in 40 CFR 98.164 were 
changed to reduce economic impact.
     The list of standards incorporated by reference in 40 CFR 
98.164 was broadened.
     The missing data procedures in 40 CFR 98.165 were revised 
to be consistent with 40 CFR 98.35(b).
     40 CFR 98.166 and 98.167 were restructured to distinguish 
between CEMS recordkeeping and feedstock method recordkeeping.
     40 CFR 98.166 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.167 to 40 CFR 98.166, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.163 were 
added to 40 CFR 98.166 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on hydrogen production were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart P: Hydrogen Production.''
Definition of Source Category
    Comment: Multiple commenters pointed out the lack of clarity 
regarding the definition of the reporting entity, and suggested 
defining the entity holding the air permit for an affected facility as 
the reporting entity. For example, ``If the owner/operator of the 
facility is the holder of the air permit for an affected facility, then 
the operator should be responsible for reporting GHG emissions. If not, 
then EPA should clarify the responsibility for reporting.''
    Response: EPA reviewed this complex issue. First, a facility is 
defined in 40 CFR 98.6: ``Facility means any physical property, plant, 
building, structure, source, or stationary equipment located on one or 
more contiguous or adjacent properties in actual physical contact or 
separated solely by a public roadway or other public right-of-way and 
under common ownership or common control, that emits or may emit any 
greenhouse gas.'' Therefore, any hydrogen production process unit that 
is not part of a larger facility covered by another subpart of this 
rule is a merchant hydrogen production facility which reports emissions 
under 40 CFR part 98, subpart P. On the other hand, a hydrogen 
production process unit that is part of a larger facility covered by 
another subpart of this rule is a captive hydrogen production facility 
that does not report emissions under 40 CFR part 98, subpart P. Their 
emissions, including those emissions from the captive hydrogen 
production facility, are reported under the subpart applicable to the 
larger facility. Second, in answer to the question, ``Do I need to 
report?'', 40 CFR 98.2 states that the rule applies to a facility that 
contains any source category listed in 40 CFR 98.2(a)(2) (which 
includes hydrogen production) and that emits 25,000 metric tons 
CO2e or more per year in combined emissions from stationary 
fuel combustion units, miscellaneous uses of carbonates, and all source 
categories listed in 40 CFR 98.2(a)(2). EPA has concluded that the rule 
explains this clearly in 40 CFR 98.2 and 98.6, and that it is not 
necessary to change the rule. To add clarity, however, EPA has revised 
40 CFR 98.160(c) as follows: ``This source category includes merchant 
hydrogen production facilities located within a petroleum refinery if 
they are not owned by, or under the direct control of, the refinery 
owner and operator.''
GHGs To Report
    Comment: Multiple commenters requested clarification on the 
CO2 emission reporting obligation as combined ``process'' 
and ``combustion'' CO2 emissions, regardless of the 
calculation method employed. If separate, discrete reporting of such 
emissions is actually required, commenters asked EPA to provide 
explicit protection for this information which they stated was very 
critical CBI.
    Response: In response to these multiple commenters, EPA has 
clarified the rule in 40 CFR 98.162 to provide operators the option of 
providing combined process and combustion CO2 emissions for 
each hydrogen production process unit whether or not it meets the 
conditions in 40 CFR 98.33(b)(4)(ii) and (iii) for CEMs. Under 40 CFR 
98.166, facilities must report additional parameters for emissions 
verification.
    See Sections II.I and II.N of this preamble for responses to the 
comments received on the general content of the annual GHG report and 
the emissions verification approach, respectively. EPA reviewed CBI 
comments received across the rule (both general and subpart-specific 
comments) and our response is discussed in Section II.R of this 
preamble and in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Legal Issues.''
Method for Calculating GHG Emissions
    Comment: Multiple commenters pointed out the need for a calculation 
method to account for feedstock carbon that does not exit the hydrogen 
production facility as CO2, but rather in the form of other 
products or co-products that contain carbon (such as synthesis gas, CO, 
CH4). Many argued in favor of correcting equations P-1, P-2 
and P-3 to account for feedstock carbon that does not exit the hydrogen 
production facility as CO2, but rather as products (such as 
synthesis gas, CO, CH4) that are manufactured which contain 
carbon.
    Response: EPA generally concurs with the need to account for 
``carbon other than CO2'' that exits the facility. EPA 
considered several options for reporting such carbon and chose to have 
facilities report CO2 and ``carbon other than 
CO2'' as separate data reporting elements in 40 CFR 98.166 
rather than including this carbon in equations P-1, P-2, and P-3. As a 
result, EPA has added data reporting elements under 40 CFR 98.166 for 
(1) quarterly quantity of CO2 collected and transferred off 
site in either gas, liquid, or solid forms (metric tons), following the 
requirements of 40 CFR part 98, subpart PP of this part, and (2) annual 
quantity of carbon other than CO2 collected and transferred 
off site in either gas, liquid, or solid forms (metric tons).
Monitoring and QA/QC Requirements
    Comment: Multiple commenters recommended that EPA should allow the 
characterization of feedstocks (sampling and analysis) to be conducted 
by either the feedstock consumer (the regulated source) or the 
feedstock supplier. They state that the characterization of standard 
fuels of commerce used as hydrogen production feedstocks, such as 
natural gas, should not be required since default values will yield a 
sufficiently accurate emission estimate. Commenters recommend that 
characterization of such standard fuels of commerce used as feedstocks 
be optional, at the source's discretion.
    Response: EPA concurs with this comment, since feedstock suppliers 
regularly monitor the carbon content of their fuels and also, the 
carbon content of standard fuels of commerce are quite consistent month 
to month. EPA has revised this section to allow the characterization of 
feedstocks to be conducted by either the consumer or the supplier, to 
allow standard gaseous hydrocarbon fuels of commerce to be 
characterized annually, and allow liquid

[[Page 56309]]

and solid hydrocarbon fuels of commerce to be characterized upon 
delivery if delivered by bulk transport (e.g., by truck or rail). Other 
non-standard gaseous fuels and feedstocks must still be subjected to 
weekly sampling and analysis to determine the carbon content and 
molecular weight.
    Comment: Commenters recommended that EPA limit the requirement for 
sampling non-gaseous fuels to new deliveries rather than monthly in 
order to pinpoint the onset of fuel parameter variations.
    Response: EPA concurs that the carbon content of a liquid or solid 
hydrocarbon fuel delivered in bulk will remain constant as the stock on 
hand from the delivery is consumed, and therefore periodic testing 
during the interim is not needed. EPA has revised this section to allow 
the characterization of feedstocks to be conducted by either the 
consumer or the supplier, to allow standard gaseous hydrocarbon fuels 
of commerce to be characterized annually, and allow liquid and solid 
hydrocarbon fuels of commerce to be characterized upon delivery if 
delivered by bulk transport (e.g., by truck or rail). On the other 
hand, other non-standard gaseous fuels and feedstocks must still be 
subjected to weekly sampling and analysis to determine the carbon 
content and molecular weight since their carbon content can vary 
significantly from week to week.
    Comment: Multiple commenters recommended that EPA should include 
provisions for an extension of the required meter/monitor calibration 
deadline (as well as the initial calibration, if appropriate) when the 
calibration would require removing the process line from service. They 
recommend that the calibration requirement be extended to the next 
scheduled maintenance shutdown for the impacted unit/process.
    Response: EPA concurs that requiring the facility to remove the 
process line from service represents an undue hardship and has 
therefore revised 40 CFR part 98, subpart P to refer to the less 
stringent monitoring and QA/QC requirements for the Tier 3 methodology 
included in 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources).
    Comment: One commenter suggested adding ISO 5167-1 through ISO 
5167-4 (Measurement of Fluid Flow by Means of Pressure Differential 
Devices) to list of standards incorporated by reference.
    Response: EPA agrees ISO 5167-1 through ISO 5167-4 are suitable 
calibration standards and would be good additions to the list of 
standards. However, given that the issues covered by these standards 
(Venturi and orifice plate differential pressure flow meters) are 
covered by two American Society of Mechanical Engineers (ASME) 
standards, one ASHRAE standard, and one AGA report which are already 
included in 40 CFR 98.164, EPA has not explicitly added these 
references to the list of standards incorporated by reference.
Procedures for Missing Data
    Comment: Multiple commenters recommended that the data substitution 
method for missing feedstock supply rate data should be changed to be 
consistent with 40 CFR 98.35(b)(2), allowing use of the ``best 
available estimate'', and that the data substitution method for missing 
feedstock carbon content data should be changed to be consistent with 
40 CFR 98.35(b)(1), allowing use of the average before/after values.
    Response: EPA concurs that the required level of accuracy for 
hydrogen production is similar to that required for stationary 
combustion, and that the less stringent ``best available estimate'' 
approach is appropriate for hydrogen production. Therefore, EPA has 
changed 40 CFR 98.165 to follow the data substitution method for 
missing fuel carbon content data prescribed in 40 CFR 98.35 and the 
data substitution method for missing fuel usage data prescribed in 40 
CFR 98.35.
Data Reporting Requirements
    Comment: Multiple commenters stated that annual feedstock 
consumption, annual hydrogen production, and feedstock carbon content 
are confidential business information (CBI) and should not be reported. 
The commenters asked that this information be maintained by the 
facility and be made available to the Agency upon request. One 
commenter further stated that if data must be reported, the reporting 
rules must provide explicit protection for this very critical 
confidential business information.
    Response: Feedstock consumption and feedstock carbon content are 
parameters used to calculate emissions. Since annual CO2 
emissions are calculated from the sum of the products of monthly 
feedstock consumption multiplied by the monthly average carbon content 
of the feedstock, all of these parameters are required for emissions 
data verification purposes. Annual hydrogen production is an additional 
parameter which is necessary for EPA to effectively verify emissions, 
since the ratio of carbon emissions to hydrogen production is 
relatively consistent for each hydrogen production facility. See 
Section II.N of this preamble for information on emissions 
verification. EPA reviewed CBI comments received across the rule (both 
general and subpart-specific comments) and our response is discussed in 
Section II.R of this preamble and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues.''

Q. Iron and Steel Production

1. Summary of the Final Rule
    Source Category Definition. The iron and steel production source 
category consists of facilities with any of the following processes:
     Taconite iron ore processing.
     Integrated iron and steel manufacturing.
     Cokemaking not co-located with an integrated iron and 
steel manufacturing process.
     EAF steelmaking not co-located with an integrated iron and 
steel manufacturing process.
    Integrated iron and steel manufacturing means the production of 
steel from iron ore or iron ore pellets. At a minimum, an integrated 
iron and steel manufacturing process has a basic oxygen furnace for 
refining molten iron into steel. Each cokemaking process and EAF 
process located at a facility with an integrated iron and steel 
manufacturing process is part of the integrated iron and steel 
manufacturing facility.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Report the following emissions annually:
     CO2, CH4, and N2O 
emissions from fuel combustion at each stationary combustion unit 
according to the requirements in 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources). Stationary combustion units 
include, but are not limited to, byproduct recovery coke oven battery 
combustion stacks, blast furnace stoves, boilers, process heaters, 
reheat furnaces, annealing furnaces, flame suppression, ladle 
reheaters, and any other miscellaneous combustion sources (except 
flares).
     CO2 emissions from flares according to the 
requirements in 40 CFR part 98, subpart Y (Petroleum Refineries) and 
CH4 and N2O emissions from flares using the 
default emission factors for coke oven gas and blast furnace gas.
     CO2 process emissions from each taconite 
indurating furnace, basic oxygen furnace, nonrecovery coke oven

[[Page 56310]]

battery combustion stack, coke pushing process, sinter process, EAF, 
argon-oxygen decarburization vessel, and direct reduction furnace.
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2 
process emissions at each taconite indurating furnace, basic oxygen 
furnace, nonrecovery coke oven battery, sinter process, EAF, argon-
oxygen decarburization vessel, and direct reduction furnace, reporters 
must calculate emissions using one of the following methods, as 
appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions by either: (1) Installing and operating a CEMS 
and following the Tier 4 methodology (in 40 CFR part 98, subpart C) or 
(2) using one of the following two calculation procedures:

--Use a carbon balance method described in 40 CFR part 98, subpart Q to 
calculate the annual mass emissions rate of CO2 for each 
process, based on the annual mass of inputs and outputs and an annual 
analysis of the respective weight fraction of carbon in each process 
input or output that contains carbon. Use separate procedures and 
equations for taconite indurating furnaces, basic oxygen process 
furnaces, nonrecovery coke oven batteries, sinter processes, EAFs, 
argon-oxygen decarburization vessels, and direct reduction furnaces, or
--Use a site-specific emission factor determined from a performance 
test that measures CO2 emissions from all exhaust stacks and 
also measures either the feed rate of materials into the process or the 
production rate during the test for taconite indurating furnaces, basic 
oxygen process furnaces, nonrecovery coke oven batteries, sinter 
processes, EAFs, argon-oxygen decarburization vessels, and direct 
reduction furnaces.

     However, if process CO2 emissions from a 
taconite indurating furnace, basic oxygen furnace, nonrecovery coke 
oven battery, sinter process, EAF, argon-oxygen decarburization vessel, 
and direct reduction furnace are emitted through the same stack as 
CO2 emissions from a combustion unit or process equipment 
that uses a CEMS and follows the Tier 4 methodology to report 
CO2 emissions, then the CEMS must be used to measure and 
report combined CO2 emissions from that stack. In such 
cases, the reporter cannot use the other process CO2 
calculation approaches outlined above.
     For coke oven pushing, facilities must use a 
CO2 emission factor provided in the rule.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart Q.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart Q.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart Q: Iron and Steel Production.''
    The major changes made since proposal include:
     The carbon mass balance method was revised to require an 
annual analysis of all process inputs and outputs for carbon content 
rather than weekly sampling and monthly analysis.
     The site-specific emission factor method was revised to: 
(1) Require testing based on representative performance rather than at 
90 percent of capacity, (2) sampling for a minimum of three hours or 
production cycles rather than nine, (3) conducting separate tests for 
each different process condition that is a part of normal operation if 
the change in CO2 emissions at the different conditions is 
more than 20 percent, and (4) adding a provision to clarify testing 
requirements when the EAF and argon-oxygen decarburization vessel are 
ducted to the same control device and stack.
     To improve the emissions verification process, 40 CFR 
98.176 was reorganized and updated. Some data elements were moved from 
40 CFR 98.177 to 40 CFR 98.176, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.173 were 
added to 40 CFR 98.176 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses related to the requirements for iron and steel processes. A 
large number of comments on iron and steel production were received 
covering numerous topics. Many of these comments were directed at the 
requirements for 40 CFR part 98, subpart C (General Stationary Fuel 
Combustion Sources), and responses to those comments are provided in 
Section III.C of this preamble. Also see the Section II.N of this 
preamble for the response to comments on the emissions verification 
approach. Responses to other significant comments received related to 
process emissions from iron and steel production can be found in 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Subpart Q: Iron and Steel Production.''
Method for Calculating GHG Emissions
    Comment: Several industry representatives and their three trade 
associations requested that EPA allow the use of a simplified facility-
wide carbon balance approach developed by the American Iron and Steel 
Institute (AISI) to calculate CO2 emissions from iron and 
steel production facilities. According to the commenters, the AISI 
methodology has recently been adapted to facility-wide reporting and is 
emerging as the preferred reporting protocol internationally. The 
commenters described the approach as based on determining the mass of 
carbon in the most significant carbon-containing inputs entering the 
plant and in the most significant carbon-containing outputs that leave 
as products or byproducts (excluding, for example, iron ore, scrap, 
steel). The difference between the mass of carbon entering the facility 
and leaving the facility is assumed to be converted to CO2. 
The annual mass rates of significant inputs and outputs are determined 
from company records, and their carbon contents are based on typical or 
default values. The commenters noted that the AISI approach provides a 
single estimate of the combined total CO2 emissions from all 
processes and combustion sources at the facility. The commenters 
claimed that the approach would provide a more accurate and complete 
accounting of facility-wide emissions at a much lower cost than that of 
the proposed EPA process-specific methods.
    Response: As we explained at proposal (74 FR 16517), we considered 
the many domestic and international

[[Page 56311]]

monitoring guidelines and protocols for process and combustion sources 
at iron and steel production facilities, including the AISI facility-
wide approach. The vast majority of these guidelines and protocols are 
process-specific rather than facility-wide approaches (e.g., 2006 IPCC 
Guidelines, U.S. Inventory, the World Business Council for Sustainable 
Development (WBCSD)/WRI GHG protocol, DOE 1605(b), TCR, European Union 
Emissions Trading System, and Environment Canada's mandatory reporting 
guidelines). In addition, the ``higher tier'' (more accurate) site-
specific methods use process-specific approaches. We explained at 
proposal (74 FR 16517) that we did not choose to propose these 
approaches based on the use of default values in general (such as the 
AISI approach) because the use of default values and lack of direct 
measurements results in a very high level of uncertainty (greater than 
25 percent), and default approaches would not provide site-
specific estimates of emissions that reflect differences in feedstocks, 
operating conditions, fuel combustion efficiency, variability in fuels, 
and other differences among facilities.
    We also stated at proposal that we decided not to finalize the 
proposal using methodologies that relied on default emission factors or 
default values for carbon content of materials because the differences 
among facilities described above could not be discerned, such default 
approaches are inherently inaccurate for site-specific determinations, 
and the use of default values is more appropriate for sector wide or 
national total estimates from aggregated activity data than for 
determining emissions from a specific facility.
    We further note here that the AISI approach is not adequate for our 
reporting needs because it provides only a single emissions number 
aggregated from the numerous individual processes and combustion units 
at the iron and steel facility. In contrast, the approaches we are 
promulgating today for determining CO2 emissions provide 
information at the process level and distinguish between combustion 
emissions and process emissions. Information at the process level is 
needed for many reasons, such as verification of the reported emissions 
from comparison with known ranges expected from various types of 
processes for a given production rate and emissions verification based 
on data for different plants for similar processes. Process-level 
reporting also provides information that will be useful in identifying 
processes that have reduced emissions over time and processes at 
specific plants that have the most potential for future reductions in 
emissions. In addition, the process-level reporting may provide 
information that can be used to improve methodologies for specific 
processes under future programs and to identify processes that may use 
a technology that could be the basis for an emission standard at a 
later time.
    We developed estimates of costs for the proposed options for 
determining CO2 emissions and concluded that the costs were 
reasonable. However, as explained below, we have revised the proposed 
options in response to comments, and these revisions significantly 
reduce the burden and costs of the carbon mass balance and site-
specific emission factor methods while maintaining a similar level of 
accuracy.
    Comment: Several commenters claimed that the proposed carbon mass 
balance method is unnecessarily burdensome because it requires weekly 
sampling, monthly analyses, and determining the monthly mass quantities 
of all process inputs and outputs. The commenters suggested that EPA 
allow the use of default values for carbon content, neglect streams 
that have very little or no carbon, drop the requirement for analysis 
by an ``independent certified laboratory,'' and allow the use of 
analyses from suppliers. One commenter recommended sampling and 
analysis for carbon content no more frequently than annually. The 
commenters stated that lime, dolomite and slag contain no appreciable 
carbon and do not need to be tracked, and that it is not necessary to 
account for the carbon in scrap that is charged to the furnace or in 
the steel product because they offset each other. One commenter noted 
that ``independent certified laboratory'' is not defined or explained, 
and another claimed that it is an unnecessary complication and expense 
because these carbon analyses are typically done in an in-house 
laboratory.
    One commenter stated that the carbon mass balance equations were 
incomplete because they did not account for carbon removed by pollution 
control devices. Another commenter recommended that EPA use default 
carbon contents for different grades of steel scrap and noted that 
because companies already track the chemical content of each grade of 
scrap, highly accurate carbon calculations could be made with minimal 
additional burden.
    Response: We received several useful suggestions for improving the 
carbon mass balance method without significantly decreasing the 
accuracy in the estimates. After a close review of the sampling and 
analysis requirements and comparing them to the requirements applied to 
other source categories in other subparts of this reporting rule, we 
concluded that the weekly sampling and monthly analysis of carbon 
content could be reduced in frequency to an annual analysis of all 
inputs and outputs at each facility. We also revised the rule to allow 
the use of carbon content analyses from the material supplier, which is 
consistent with what is required in other subparts using the carbon 
balance method. Carbon content does not vary widely at a given facility 
for the significant process inputs and outputs that contain carbon, and 
we continue to account for variations due to changes in production 
rate, which is likely a more significant source of variability. We 
continue to choose not to use default values for the reasons given in 
the previous comment response, and we have determined that an annual 
analysis of carbon content to provide plant-specific values is not 
burdensome because facilities already perform many such analyses. We 
agree that the analysis does not have to be performed by an independent 
certified laboratory, especially since we specify the analytical 
procedures that must be used by any laboratory, and we note that in-
house laboratories may have more applicable experience in analyses of 
their particular process inputs and outputs.
    We agree with the suggestion to evaluate carbon content by the 
grade or type of ferrous material charged to the furnace, and we 
incorporated a provision to calculate an average carbon content of 
ferrous materials charged based on the average weight percent of each 
type that is used. In addition, we have corrected the equations as 
suggested to account for carbon in the residue collected by emission 
control equipment. Finally, we agree that inputs and outputs that 
contain no carbon or an insignificant amount (i.e., contributing to 
less than one percent of the carbon in or out) do not need to be 
tracked in the carbon balance method.
    Comment: Several commenters claimed that the site-specific emission 
factor method is not a viable option as proposed and should be 
streamlined to: (1) Eliminate annual re-testing, (2) reduce the test 
length from nine hours (or from nine production cycles for batch 
processes), (3) clarify that a separate test is not required for each 
grade of steel, and (4) remove the

[[Page 56312]]

requirement to operate at 90 percent of capacity. One commenter stated 
that the most frequent re-testing currently required in operating 
permits is once every 2.5 years rather than annually. Another commenter 
noted that nine production cycles for certain small specialty steel 
producers would require 27 hours of testing for each grade of steel 
because each production cycle is three hours. Commenters stated that 
testing at 90 percent of production is problematic and is beyond their 
control because it is dictated by upstream and downstream production 
levels as well as economic conditions. In addition, capacity is 
difficult to determine because steelmaking furnaces do not have a 
nameplate capacity since it is determined by the iron production rate, 
how fast downstream processes (such as the caster) operate, process 
inputs, and product specifications that may require different operating 
cycle times.
    One commenter questioned the value of the requirement to re-test if 
the carbon content of feed materials changes by more than 10 percent 
because this type of change could occur on a daily or weekly basis when 
the grade of steel being produced changes. Another commenter noted that 
EPA did not define what constituted a significant change in fuel type 
or mix and recommended that the provision be changed to 20 percent to 
allow for environmentally beneficial process improvements. Two 
commenters stated that the 10 percent threshold for re-testing is 
infeasible for steelmaking and sinter processes because of routine 
changes in the type of steel produced and the types of materials 
recycled to the sinter plant. The commenters requested that they be 
permitted to develop separate emission factors based on various modes 
that represent different operating scenarios or product categories. The 
commenters also recommended that EPA eliminate the 10 percent change 
threshold for re-testing and require that testing be conducted under 
conditions that are representative of normal operation. One commenter 
noted that the rule did not address how a site-specific emission factor 
would be developed when emissions from the EAF and argon-oxygen 
decarburization vessel are combined and routed to a single emission 
control device and stack.
    Response: We further reviewed the testing requirement in other 
rules and those in operating permits and found that typical 
requirements (such as test requirements for particulate matter) include 
3 one-hour runs or production cycles for representative testing of 
process emissions. Consequently, we are revising the testing 
requirements to three hours or three production cycles. We also agree 
with the commenters who noted that different routine operating modes 
may result in different levels of CO2 emissions, and it is 
necessary to develop separate emission factors for these different 
operating conditions. Consequently, we have dropped the 10 percent re-
testing threshold and instead require that separate emission factors be 
developed for each of different routine operating conditions that 
result in a change in CO2 emissions by 20 percent or more.
    We disagree that annual re-testing is excessive because testing for 
CO2 emissions is much simpler and less costly than sampling 
for hazardous pollutants or for particulate matter, and annual sampling 
is consistent with our requirement for annual reporting. We agree that 
it is not necessary or always possible to test while operating at 90 
percent of capacity for the reasons identified by the commenters. 
Instead, we are requiring that the test be performed based on 
representative performance, i.e., under normal operating conditions. We 
have revised the rule to clarify and provide options for testing when 
emissions from the EAF and argon-oxygen decarburization vessel are 
combined.
    Comment: Several commenters asked EPA to clarify that 
CH4 and N2O emissions do not have to be reported 
for iron and steel production processes, and other commenters requested 
that CH4 and N2O emissions reporting not be 
required for the combustion of coke oven gas and blast furnace gas. 
Commenters noted that default emission factors for CO2, 
CH4, and N2O were not provided in the tables in 
40 CFR part 98, subpart C, and in the absence of such emission factors, 
asked if they would be required to test for these minor emissions.
    Response: We have clarified that 40 CFR part 98, subpart Q does not 
require reporting of CH4 and N2O emissions from 
the iron and steel production processes because we expect these 
emissions (if any) to be very low, and we have no protocols for 
calculating them. However, emission factors are available in the 2006 
IPCC guidelines for combustion sources, including the combustion of 
coke oven gas and blast furnace gas. We have added the IPCC default 
emission factors for CO2 and N2O for these 
process gases to the tables in 40 CFR part 98, subpart C, and we 
developed new emission factors for CH4 based on the typical 
CH4 content of coke oven gas (28 percent) and blast furnace 
gas (0.2 percent).

R. Lead Production

1. Summary of the Final Rule
    Source Category Definition. The lead production source category 
consists of primary lead smelters and secondary lead smelters. A 
primary lead smelter is a facility engaged in the production of lead 
metal from lead sulfide ore concentrates through the use of 
pyrometallurgical techniques (smelting). A secondary lead smelter is a 
facility at which lead-bearing scrap materials (including but not 
limited to lead-acid batteries) are recycled by smelting into elemental 
lead or lead alloys.
    Reporters must submit annual GHG reports for primary lead smelters 
and secondary lead smelters that meet the applicability criteria in the 
General Provisions (40 CFR 98.2) summarized in Section II.A of this 
preamble.
    GHGs to Report. For lead production, report the following 
emissions:
     CO2 process emissions from each smelting 
furnace used for lead production.
     CO2 combustion emissions from each smelting 
furnace used for lead production.
     N2O and CH4 emissions from each 
smelting furnace under 40 CFR part 98, subpart C (General Stationary 
Fuel Combustion Sources) using the methodologies in subpart C.
     CO2, N2O, and CH4 
emissions from each on-site stationary combustion unit other than 
smelting furnaces under 40 CFR part 98, subpart C (General Stationary 
Fuel Combustion Sources).
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. To calculate annual 
process CO2 emissions from an affected smelting furnace, the 
reporter must use the following methods, as applicable to the affected 
smelting furnace.
     For each affected smelting furnace with certain types of 
CEMS in place, the reporter must use the CEMS and follow the Tier 4 
methodology (in 40 CFR part 98, subpart C) to measure and report under 
the Lead Production subpart (40 CFR part 98, subpart R) combined 
process and combustion CO2 emissions.
     For other affected smelting furnaces, the reporter can 
elect to either (1) install and operate a CEMS and follow the Tier 4 
methodology to measure and report combined process and combustion 
CO2 emissions or (2) calculate annual process CO2 
emissions using a carbon mass balance procedure specified in 40 CFR 
part 98, subpart R. If using approach (2):


[[Page 56313]]


--Calculate emissions once per year using recorded monthly production 
data and the average carbon content for each smelting furnace input 
material determined by either using material supplier information or by 
annual analysis of representative samples of the material.
--Report process CO2 emissions from each smelting furnace 
under 40 CFR part 98, subpart H (Cement Production), and report 
combustion CO2 emissions from each kiln under 40 CFR part 
98, subpart C (General Stationary Fuel Combustion Sources).

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart R.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart R.
2. Summary of Major Changes Since Proposal
    The major changes to the rule since proposal for lead production 
facilities were revisions to the carbon mass balance calculation 
procedure used by reporters for calculating process CO2 
emissions from affected smelting furnaces. The rationale for these and 
any other significant changes can be found below or in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart R: Lead Production.''
     The frequency of performing the carbon mass balance 
calculations was revised to be required on an annual basis instead of 
the proposed monthly basis.
     The frequency of material carbon content sampling and 
analysis of each smelting furnace input material used for the carbon 
mass balance was revised to be performed by annual analysis of 
representative samples of the material instead of the proposed monthly 
basis.
     A de minimis carbon content level was added to exclude the 
need to account for carbon-containing materials contributing less than 
one percent of the total carbon into the smelting furnace in the carbon 
mass balance calculations.
     Data reporting procedures (40 CFR 98.186) were reorganized 
and updated to consolidate and clarify the emissions verification 
process. Some data elements for the carbon mass balance calculation 
were moved from 40 CFR 98.187 to 40 CFR 98.186, and some data elements 
that a reporter must already use to calculate GHGs as specified in 40 
CFR 98.183 were added to 40 CFR 98.186 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses specific to the lead production source category. Comments 
were received from one commenter regarding several topics. Responses to 
significant comments received are presented in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subpart R: Lead 
Production.''
Selection of Threshold
    Comment: The commenter stated that Lead Production is not a source 
of significant GHG emissions and that EPA cannot assert that the Lead 
Production sector is a significant part of the stationary source 
combustion sector. The commenter notes that based on EPA's estimates in 
the TSDs for the proposal, estimated emissions from the Lead Production 
sector are 0.02 percent of the total estimated nationwide emissions 
from stationary fossil fuel combustion. Moreover, they argue that the 
combustion-related emissions from lead production are overstated by 
incorrect assumptions in the TSD. The commenter states that given Lead 
Production's relative contribution, it is not a significant source of 
emissions and should be eliminated from further consideration. The 
commenter further states that Lead Production is the only category 
evaluated where raising the threshold to the 100,000 ton level would 
results in zero facilities being covered. Accordingly, when the 
analysis shows that all facilities in a particular source category are 
not covered at the 100,000 ton threshold level, no insignificant GHG 
emitters in the category should be required to report under the 
Proposed Rule. The commenter noted that using the 100,000 threshold 
would not significantly reduce the coverage of emissions of EPA's rule, 
as the majority of sources identified would still have well over 90 
percent of emissions from that source category covered under the 
100,000 threshold. EPA provides no justification for imposing 
substantially more costs on industry for limited estimated benefits and 
small likelihood for regulation under the CAA. For these reasons, the 
Lead Production sector should be eliminated as a source category, and 
EPA should raise the threshold to 100,000 for non-source category 
facilities.
    Response: We acknowledge this comment and concerns; however, the 
final rule retains the applicability requirement for this source 
category. We used information available to us for estimating GHG 
emissions from this industry which involved several assumptions related 
to the emission factors in the IPCC Guidance and other sources. As 
noted by the commenter, many of the underlying assumptions were based 
on an international perspective as opposed to the primary and secondary 
lead production industry in the U.S. The final rule contains a 
threshold of 25,000 metric tons CO2e and only lead 
production facilities with emissions that equal or exceed 25,000 metric 
tons CO2e will have to report emissions. In addition, the 
final rule now contains provisions allowing a reporter to cease 
reporting if the annual reports for a given facility demonstrate 
emissions less than specified levels for multiple years. These 
provisions apply to all reporting facilities, including those with lead 
production processes. See Section II.H of this preamble for the 
response on provisions to cease reporting.
    We have further simplified the reporting requirement to further 
reduce burden for lead and similar industries by requiring annual as 
opposed to monthly sampling of carbon inputs. The purpose of this rule 
is to collect information on emissions sources for future policy 
development. Requiring reporting for these sources will provide EPA 
with valuable data to better characterize them and provide a more 
credible position if EPA elects to exclude these sources from future 
GHG policy analyses. Additionally, while some of these sources are 
currently believed to be small compared to the larger sources, they are 
not necessarily insignificant. The inclusion of reporting data for 
these sources is critical to support analysis of future policy 
decisions for lead production facilities.
    When evaluating potential thresholds for reporting GHG emissions, 
we considered several thresholds between 1,000 and 100,000 metric tons 
CO2e. We selected the 25,000 metric tons CO2e 
threshold for reporting GHG emissions in order to achieve a balance 
between quantifying the majority of the emissions, while minimizing the 
number of facilities impacted. For example, at a 1,000 metric tons 
CO2e threshold, 99 percent of emissions would be covered, 
with about 63

[[Page 56314]]

percent of facilities being required to report. The 100,000 metric tons 
CO2e threshold captures no emissions or facilities while the 
proposed 25,000 metric tons CO2e threshold achieves 
reporting of 92 percent of the GHG emissions while requiring less than 
50 percent of the facilities to report. We consider this a significant 
coverage of the emissions, while impacting a relatively small portion 
of the industry. We believe the proposed threshold of 25,000 metric 
tons CO2e represents the best option for ensuring that the 
majority of emissions are reported without imposing an unreasonable 
burden on the industry. See also Section II.E of this preamble and 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Selection of Reporting Thresholds, Greenhouse Gases, and De 
Minimis Provisions.''
Method for Calculating GHG Emissions
    Comment: The commenter made several comments regarding the proposed 
procedures used to calculate process CO2 emissions from 
smelting furnaces at secondary lead smelters. First, use of default 
emission factors should be allowed as a calculation method alternative 
because the smelting furnaces operated at used lead battery recycling 
facilities consistently process furnace feed materials with low carbon 
content variability. For affected sources using the carbon mass balance 
procedure, the frequency required for monitoring carbon content of the 
smelting furnace input materials should be reduced to reflect 
consistency and low carbon content variability of these materials.
    Response: We decided not to finalize the proposal using 
methodologies for calculating CO2 emissions from lead 
production that relied on published default emission factors or default 
values for carbon content of materials because the differences among 
individual lead production facilities could not be discerned using 
these factors. Consequently, the available default factors for lead 
production facilities are inherently less accurate for calculating 
smelting furnace process CO2 emissions than using procedures 
that include use of site-specific material carbon data. Default 
approaches do not provide site-specific estimates of emissions that 
reflect differences in use of and variability in feedstocks, 
variability in fuels, operating conditions, fuel combustion efficiency, 
and other differences among facilities. For some carbon-containing 
input materials, such as lead scrap, representative published defaults 
do not exist. Therefore, the use of default values is more appropriate 
for sector wide or national total estimates from aggregated production 
data for multiple facilities rather than for providing an accurate 
representation of CO2 emissions from a specific facility.
    For the final rule, we did reduce the monitoring frequency for 
determining carbon contents of the smelting furnace input materials 
used for the carbon mass balance to be determined on annual rather than 
monthly basis. Facilities can determine carbon contents either by using 
material supplier information or by annual analysis of representative 
samples of the input materials. We agree that the carbon content for 
the significant input materials typically does not vary widely at a 
given lead production facility. Annual carbon content determinations 
will still provide representative carbon content data for the smelting 
furnace process CO2 emissions calculations while minimizing 
the monitoring burden on reporters. We continue to account for process 
variations due to changes in production rate, which is likely a more 
significant source of variability in the CO2 emissions from 
an affected smelting furnace during the year, by maintaining the 
requirement to measure and record monthly carbon containing input 
materials.

S. Lime Manufacturing

1. Summary of the Final Rule
    Source Category Definition. Lime manufacturing plants (LMPs) engage 
in the manufacture of a lime product (e.g., calcium oxide, high-calcium 
quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, 
dolomitic hydrate, or other products) by calcination of limestone, 
dolomite, shells or other cacareous substances. This source category 
includes all LMPs unless the LMP is located at a kraft pulp mill, soda 
pulp mill, sulfite pulp mill, or only processes sludge containing 
calcium carbonate from water softening processes.
    Lime kilns at pulp and paper manufacturing facilities need to 
report emissions under 40 CFR part 98, subpart AA (Pulp and Paper 
Manufacturing).
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble and meet the definition of 
lime manufacturing plants in 40 CFR 63.7081(a)(1).
    GHGs to Report. For lime manufacturing, report the following 
emissions:
     Total CO2 process emissions from all lime kilns 
combined.
     CO2 combustion emissions from lime kilns.
     N2O and CH4 emissions from fuel 
combustion at each kiln under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources) using the methodologies in subpart 
C.
     CO2, N2O, and CH4 
emissions from each stationary combustion unit other than kilns under 
40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
     CO2 collected and transferred off site under 40 
CFR part 98, subpart PP (Suppliers of CO2).
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2 
emissions from kilns, facilities must use one of two methods, as 
appropriate:
     If all lime kilns at a facility have certain types of CEMS 
in place, the reporter must use the CEMS and follow the Tier 4 
methodology (in 40 CFR part 98, subpart C) to measure and report under 
the Lime Manufacturing subpart (40 CFR part 98, subpart S) combined 
process and combustion CO2 emissions.
     If CEMS meeting the specifications above are not in place 
for all kilns at the facility, the reporter can elect to either (1) 
install and operate a CEMS and follow the Tier 4 methodology to measure 
and report combined process and combustion CO2 emissions 
from all lime kilns or (2) calculate CO2 process emissions 
for each lime type using an emission factor for each lime type, the 
mass of lime produced, an emission factor for byproduct/waste (such as 
lime kiln dust and scrubber sludge), and the mass of byproduct/waste. 
If using approach (2):

--Each emission factor must be determined monthly for each lime type 
from monthly measurements of the calcium oxide and magnesium oxide 
content of the lime and stoichiometric ratios of CO2 to each 
oxide in the lime.
--The emission factor for each lime byproduct/waste sold (such as lime 
kiln dust) must be determined monthly.
--The emissions from lime byproducts/wastes that are not sold (such as 
lime kiln dust and scrubber sludge) must be determined annually.
--The mass of each lime type produced and lime byproduct/waste sold 
(such as lime kiln dust) must be recorded on a monthly basis.

[[Page 56315]]

--The mass of each lime byproduct/waste not sold (such as lime kiln 
dust and scrubber sludge) must be recorded annually.
--Report process CO2 emissions from all kilns combined under 
40 CFR part 98, subpart S (Lime Manufacturing), and report combustion 
CO2 emissions from each kiln under 40 CFR part 98, subpart C 
(General Stationary Fuel Combustion Sources).

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart S.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart S.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart S: Lime Manufacturing.''
     The definition of lime manufacturing was revised to be 
similar to the definition in the Lime NESHAP at Sec.  63.7081(a) and 
(a)(1).
     Reporting requirements were revised from a ``per kiln'' 
basis to ``all kilns combined''.
     The emissions calculations were revised to determine 
monthly emissions factors for each lime type and byproduct/waste type 
rather than for each kiln.
     Emission calculations for byproducts/wastes were added.
     The requirement to measure the calcium oxide and magnesium 
oxide content of byproducts/wastes on a monthly basis was changed to an 
annual basis for byproducts/wastes that are not sold.
     The correction factor for byproducts/wastes was removed 
from the rule.
     Additional direct measurement devices/methods are being 
allowed to include those currently in use by the industry.
     40 CFR 98.196 was reorganized and updated. Some data 
elements were moved from 40 CFR 98.197 to 40 CFR 98.196, and some data 
elements that a reporter must already use to calculate GHGs as 
specified in 40 CFR 98.193 were added to 40 CFR 98.196 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on lime manufacturing were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart S: Lime Manufacturing.''
Definition of Source Category
    Comment: Multiple commenters requested more clarification in 
defining which sources and equipment are covered by the proposed rule. 
The rule defines the source category as a facility that contains ``a 
rotary lime kiln to produce a lime product.'' In addition, proposed 40 
CFR 98.192(b) required sources to report emissions from ``each lime 
kiln and any other stationary combustion unit.''
    Response: We have reviewed the rule language and decided the source 
category definition should provide more clarity. The source category is 
meant to include all kiln types used in the lime manufacturing 
industry; therefore, language in the final rule has been changed to be 
similar to the definition from the Lime NESHAP in 40 CFR 63.7081(a) and 
(a)(1). This Lime NESHAP effectively characterizes lime plants as those 
engaging in the manufacture of a lime product by calcination. The final 
rule requires all stationary combustion units to report under 40 CFR 
part 98, subpart C of the final rule.
    Final rule language under 40 CFR 98.192 requires facilities to 
report CO2, CH4, and N2O emissions 
from kilns used in the lime manufacturing process and all other 
combustion units at the lime manufacturing facility other than kilns. 
The language has also been clarified in 40 CFR 98.193. Facilities using 
CEMS for all lime kilns report combined process and combustion 
emissions from kilns under 40 CFR part 98, subpart S, according to the 
Tier 4 methodology in 40 CFR part 98 subpart C (General Stationary Fuel 
Combustion Sources). Facilities must follow the requirements of subpart 
C for estimating and reporting combustion related emissions for all 
other combustion units and report these emissions under subpart C. See 
Section III.C of this preamble for an overview of the requirements for 
stationary combustion units.
Selection of Proposed GHG Emissions Calculation and Monitoring Methods
    Comment: Multiple commenters requested the language in 40 CFR part 
98, subpart S be changed to allow emissions to be reported by ``all 
kilns combined'' instead of the proposed rule's request to report 
emission for each kiln. Multiple commenters further recommended that 
the process emissions calculations be changed to calculate emissions by 
the lime type produced as opposed to the current rule calculations 
which use a kiln specific emission factor. Two commenters stated that 
lime products are commonly aggregated at the plant making it difficult 
to estimate the amount of product produced at an individual kiln. These 
commenters stated that current lime plant configuration do not allow 
accurate kiln specific calculations.
    Response: We have reviewed the common lime plant configuration and 
the currently proposed rule language and have decided that it is not 
necessary to require kiln-specific emissions reporting. We have 
observed that some kilns would have to retrofit weigh belt scales in 
the production line between kilns and storage silos, since they do not 
currently exist. Calculating emissions by kiln could increase the 
reporting burden for these facilities. According to one commenter, when 
kiln-specific emissions have been reported in the past, the data are 
usually derived by distributing the aggregated emissions among the 
kilns. Accurate measurements at the kiln level are rarely achieved. If 
this is true for most lime manufacturing facilities, the data does not 
necessarily provide a better estimate of emissions.
    For the purposes of this rulemaking, reporting for all kilns 
combined will simplify and minimize the reporting burden without 
significant loss in accuracy because: (1) Kilns may produce more than 
one type of lime in a given reporting period, (2) emission factors are 
based on lime type, and (3) lime plants collect products in combined 
bagging areas (separated by lime type). The final rule language has 
been changed to require reporting by lime type from all kilns combined 
rather than all lime types for each kiln. This final rule language is 
consistent with the National Lime Association (NLA) Protocol, which was 
used as the basis for the methodology in the proposed rule. Information 
collected under this rule will help to inform future methodologies and 
determine whether

[[Page 56316]]

kiln level reporting could be more appropriate for future reporting.
    Comment: The proposed rule used a default correction factor in 
calculating lime product and byproduct/waste emissions. Multiple 
commenters suggested using the National Lime Association Protocol to 
determine lime product and by-product/waste process emissions. 
According to the commenters, this method is more precise due to the use 
of measured oxide values and stoichiometric ratios rather than 
correction factors.
    Response: We have reviewed the proposed rule and NLA Protocol 
calculation methods and noted that the use of actual oxide measurements 
in calculating emissions from lime plants does not cause an additional 
burden to the reporter since this is a currently used practice. We also 
agree that the use of actual measurements is more accurate. Therefore, 
we have decided to remove the use of a correction factor in the final 
rule equations; emissions will be calculated from actual oxide 
measurements of each type of lime and calcined byproducts/wastes.
Monitoring and QA/QC Requirements
    Comment: Multiple commenters asked that the language pertaining to 
allowable measurement devices for lime products and byproducts/wastes 
sold, be changed to include measurement devices commonly used in the 
lime industry. The current rule language requires weigh hoppers and 
belt weigh feeders as the measurement devices; the aforementioned 
commenters have identified bag, truck and rail scales as reliable 
(annually calibrated) direct measurement methods commonly used in the 
lime industry. In addition, commenters have requested lime byproducts/
wastes not sold be calculated by a facility generation rate.
    Response: After reviewing the rule language and common industry 
practices, we have decided to include other direct measurement devices 
used for accounting purposes, including but not limited to, weigh 
feeders, calibrated bag, rail or truck scales, and barge measurements. 
These methods are consistent with the original intent of the rule and 
add further clarification on measurement methods applicable to 
determine quantities of both lime produced and byproducts/waste 
generated.
    In addition, reporters are required to perform an annual cross 
check by measuring lime products at the beginning and end of the year. 
For calcined byproducts/wastes not sold, a material balance approach 
that indirectly measures the generation rate should be used.
    Comment: Multiple commenters asked that the language in 40 CFR part 
98, subpart S pertaining to testing the chemical composition of each 
type of lime (including the byproducts and waste) be changed to allow 
testing by onsite lab facilities. Currently the rule specifies an 
``off-site laboratory analysis'' but according to the commenter, 
commercial lime plants normally have onsite lab facilities.
    Response: We agree that the analysis does not have to be performed 
by an independent certified laboratory, especially since we specify the 
analytical procedures that must be used by any laboratory, and we note 
that in-house laboratories may have more applicable experience in 
determining chemical composition. Reporters can determine whether to 
perform the test onsite or send the samples to offsite laboratory 
facilities. Therefore the language in the final rule has been changed.
Data Reporting Requirements
    Comment: Multiple commenters requested the language in 40 CFR part 
98, subpart S pertaining to reporting information to EPA be changed so 
that business sensitive information is kept in company records. 
Commenters agree that the production capacity, product quality (i.e., 
oxide content), emission factors and operating hours and days for each 
kiln, are required for emissions calculations but are concerned that 
making this information public would give information about their 
efficiency, productivity and capacity of kilns and facility.
    Response: EPA reviewed CBI comments received across the rule (both 
general and subpart-specific comments) and our response is discussed in 
Section II.R of this preamble for legal issues. Also, see Section II.N 
of this preamble for the response to comments on the emissions 
verification approach.
    We agree that annual operating hours and capacities are not used in 
the calculation of CO2 emissions and these parameters have 
been moved to recordkeeping. This information can help to verify 
anomalies in emissions data if there were temporary shutdowns, etc.
    We disagree that emission factors and product quality be maintained 
as records rather than be reported. Emission factors and product 
quality are used in calculations to establish the site specific rate of 
CO2 emissions generated for each type of lime produced. 
Therefore these data are required in order to verify the CO2 
emissions that are being reported. This internal verification system 
ensures that the GHG emissions reported are accurate.

T. Magnesium Production

    At this time EPA is not going final with the magnesium production 
subpart (40 CFR part 98, subpart T). For the immediate future, EPA 
believes that emissions of GHGs from magnesium production are 
sufficiently covered by the reporting requirements under 40 CFR part 
98, subpart OO for Industrial Gas Supply. This information on U.S. 
production, imports, and exports of SF6 will provide at 
least a general, order-of-magnitude check on consumption of 
SF6 by magnesium production and other uses of 
SF6. EPA will finalize the proposed reporting requirements 
for the magnesium production industry at a later date.

U. Miscellaneous Uses of Carbonate

1. Summary of the Final Rule
    Source Category Definition. The Miscellaneous Uses of Carbonate 
source category consists of any facility that uses carbonates listed in 
Table U-1 of 40 CFR part 98, subpart U in manufacturing processes that 
emit carbon dioxide. The Table includes the following carbonates: 
Limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or 
sodium carbonate. Facilities are considered to emit CO2 if 
they consume at least 2,000 tons per year of the carbonates listed 
above and that are heated to a temperature sufficient to allow 
calcination to occur.
    This source category does not include facilities processing 
carbonates or carbonate containing minerals consumed for producing 
cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric 
acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide or 
zinc as CO2 emissions from these processes are covered 
elsewhere in this rule.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For miscellaneous uses of carbonates, report the 
following emissions:
     Annual CO2 process emissions for all 
miscellaneous uses of carbonates as specified in this subpart.
     CO2, N2O, and CH4 
emissions from carbonates used in sorbent technology and each 
stationary combustion unit on site under 40 CFR part 98, subpart C 
(General Stationary Fuel Combustion Sources).
    In addition, report GHG emissions for other source categories at 
the facility for

[[Page 56317]]

which calculation methods are provided in the rule, as applicable.
    GHG Emissions Calculation and Monitoring. Calculate process 
CO2 emissions using annual carbonate consumption. All 
reporters must calculate the annual mass of carbonates used in 
processes which are heated to temperatures that allow calcination. If 
the annual amount of carbonates consumed is greater than 2,000 tons, 
CO2 emissions must be calculated using either calcination 
fractions or the actual mass of input/output carbonates.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart U.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of analyses and calculations 
required for this source category.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart U: Miscellaneous Uses of 
Carbonates.''
     The source category definition was revised to exclude non-
emissive uses of carbonates.
     A de minimis reporting threshold was added to exclude 
facilities with minor emissions based on annual carbonate consumption.
     The GHG calculation methodology was changed to allow 
reporters to determine emissions from the mass of carbonate input/
output or calcination fractions.
     To improve the emissions verification process, 40 CFR 
98.216 was reorganized and updated. Some data elements were moved from 
40 CFR 98.217 to 40 CFR 98.216, and some data elements that a reporter 
must already use to calculate GHG as specified in 40 CFR 98.213 were 
added to 40 CFR 98.216 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on miscellaneous uses of 
carbonates were received covering numerous topics. Most comments 
requested clarification on the definition of the source category and 
its applicability to affected sources. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart U: Miscellaneous Uses 
of Carbonates.''
Definition of Source Category
    Comment: Multiple commenters requested that the source category be 
revised to exclude non-emissive uses of carbonates. Commenters stated 
that the source category is poorly defined, making it difficult to 
accurately assess its applicability to an industrial facility. 
Commenters noted a number of non-emissive uses as examples, such as the 
production of sodium bicarbonate and sodium hydroxide, during which 
sodium carbonates are used, but no carbon dioxide is released; onsite 
mixing of processed cement with aggregate, limestone used in poultry 
grit and as an asphalt filler; or adding sodium carbonate to a water 
softener system.
    Response: The rule language has been modified to exclude non-
emissive uses of carbonates. Non-emissive uses do not result in 
CO2 emissions, such as adding sodium carbonate to a water 
softener system. Acid-induced releases of CO2 from the use 
of carbonates are addressed in other subparts, where they are 
significant, such as Phosphoric Acid Production.
Selection of Threshold
    Comment: Multiple commenters requested that a de minimus reporting 
threshold be added to exclude facilities with minor emissions. One 
commenter noted that some facilities use limestone and other carbonate 
as refractory in furnaces, and it is unclear whether or not this use of 
carbonates triggers 40 CFR part 98, subpart U, and at what level it is 
triggered.
    One commenter noted that at a pharmaceutical manufacturing facility 
there would also be a significant listing of small operations and 
activities which use carbonate compounds in trace quantities, including 
the creation of reagent solutions, and wastewater treatment operations 
employing carbonate compounds for buffering, chemical precipitation, or 
solids stabilization. This commenter recommended that EPA implement a 
threshold of 2,000 tons per year of carbonates per facility, which 
would correlate to CO2 emissions of about 1,000 tons per 
year.
    One commenter requested that EPA incorporate a de minimis threshold 
to only include equipment where carbonate is present at greater than 10 
percent by weight and heated to a temperature that allows for 
decomposition. This commenter suggested an alternative threshold, where 
EPA would require facilities to calculate CO2 emissions from 
each type of carbonate used in quantities exceeding 2,000 tons per 
year.
    Response: The rule language has been modified to specify that GHG 
emissions from miscellaneous carbonate use are required to be reported 
only from processes that consume at least 2,000 tons per year and, 
further, where the carbonates are heated to a temperature sufficient to 
allow the calcination reaction to occur. This modification to the 
definition of the source category allows facilities with minimal 
carbonate consumption and low amounts of GHG emissions to be excluded 
from reporting emissions.
Method for Calculating GHG Emissions
    Comment: Multiple commenters requested that EPA allow emission 
calculations to be based on carbonate fraction of the product instead 
of calcination fractions.
    Response: The rule has been changed to allow emission calculations 
by either the mass of carbonate input/output or calcination fraction. 
These methods should provide comparable estimates of emissions.
    The calcination fraction method calculates the amount of 
CO2 emissions based on the amount of each carbonate that is 
calcined during the process. The mass and calcination fraction of each 
carbonate are measured and used with a default CO2 emission 
factor to determine CO2 emissions.
    The carbonate fraction method calculates the amount of 
CO2 emissions as a mass balance between the input and output 
amount of each type of carbonate. The masses are measured and used with 
a default CO2 emission factor to determine CO2 
emissions.
    The mass of carbonate input/output is determined by use of the same 
plant instruments used for accounting purposes or by direct 
measurement. Calcination fractions can be measured by the appropriate 
industry consensus standards that require laboratory analysis of each 
carbonate type. Alternatively, a default value of one can be used as 
the calcination fraction.
Data Reporting Requirements and Records That Must Be Retained
    Comment: One commenter requested that recordkeeping and reporting

[[Page 56318]]

requirements be exempted for carbonates kept on-site for emergency 
purposes (not manufacturing or equipment), such as for neutralizing a 
chemical spill. This commenter explained that when used, these 
emergency reserves of carbonate material typically generate 
insignificant amounts of CO2 and should therefore be 
excluded from reporting requirements.
    Response: The final rule does not cover carbonates that are used in 
quantities of less than 2,000 tons per year and that are not heated to 
the point of calcination. Also, this subpart does not include 
requirements for calculating and reporting CO2 emissions 
from acid neutralization. Therefore, the use of carbonates in the 
manner described is not covered by the final rule.
    Comment: One commenter noted that the required records are 
duplicated in proposed 40 CFR 98.217(a) and 98.217(c), and requested 
that EPA revise this so as not to place unnecessary costs on 
facilities.
    Response: EPA agrees that asking facilities to maintain records on 
procedures used to ensure the accuracy of monthly carbonate consumption 
will be duplicative with maintaining records of all carbonate purchases 
and deliveries. This is especially true if purchase records are used to 
determine monthly carbonate consumption. We removed this duplicative 
recordkeeping requirement from the rule.
    To improve the emissions verification process, 40 CFR 98.216 was 
reorganized and updated. Some data elements were moved from 40 CFR 
98.217 to 40 CFR 98.216, and some data elements that a reporter must 
already use to calculate GHG as specified in 40 CFR 98.213 were added 
to 40 CFR 98.216 for clarity. All affected sources must follow the 
general recordkeeping provisions under 40 CFR part 98.3(g) in subpart 
A.
    Commenters may also want to review Section II.M for the response on 
the general recordkeeping requirements and Section II.N of this 
preamble for the response on the emissions verification approach.

V. Nitric Acid Production

1. Summary of the Final Rule
    Source Category Definition. The nitric acid production source 
category consists of facilities that use one or more trains to produce 
weak nitric acid (30 to 70 percent in strength) through the catalytic 
oxidation of ammonia.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For nitric acid production facilities, report 
N2O process emissions from each nitric acid train.
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. Reporters must calculate 
N2O process emissions for each nitric acid train. Calculate 
the emissions by multiplying the site-specific emission factor for each 
train by the measured annual nitric acid production for that train. 
Determine the site-specific emission factor for each train through an 
annual performance test to measure N2O from the absorber 
tail gas vent and the production rate for that train.
    When N2O abatement devices (such as nonselective 
catalytic reduction) are used, adjust the N2O process 
emissions for the amount of N2O removed using a destruction 
efficiency factor. The destruction factor is the destruction efficiency 
and can be specified by the abatement device manufacturer or can be 
determined using process knowledge or another performance test.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart V.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart V.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart V: Nitric Acid Production.''
     The re-testing trigger was changed. Performance testing to 
determine the N2O emissions factor is required annually and 
whenever new abatement technology is installed. The performance test 
should be conducted under normal operating parameters.
     Equation V-2 was edited to correct a calculation error and 
to allow multiple types of abatement technologies.
     Reorganized and updated 40 CFR 98.226 to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.227 to 40 CFR 98.226, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.223 were 
added to 40 CFR 98.226 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on nitric acid production were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart V: Nitric Acid Production.''
GHGs To Report
    Comment: Multiple commenters asked that the language in 40 CFR 
98.222(b) be clarified to include emissions under 40 CFR part 98, 
subpart V only from units that are 100 percent dedicated to nitric acid 
production to avoid double counting of combustion emissions.
    Response: We appreciate the comments but have decided not to make 
any changes to 40 CFR part 98, subpart V. According to the 
applicability criteria in subpart C, all combustion unit emissions from 
nitric acid facilities (regardless of whether or not the combustion 
units are associated with nitric acid production operations) are to be 
reported under subpart C. There will be no potential for double 
counting of combustion emissions at the facility because Subpart V 
provides methods for reporting only the process emissions. Also see the 
preamble for responses on comments related to Subpart C (General 
Stationary Combustion).
Method for Calculating GHG Emissions
    Comment: Multiple commenters asked that the requirement to repeat 
the annual performance test be removed. In the proposal, re-testing was 
triggered whenever the nitric acid production rate changed by more than 
10 percent. Commenters asserted that production depends on demand for 
nitric acid and often varies by up to 20 percent.
    Response: We appreciate the comments and have decided to eliminate 
re-testing. We believe that

[[Page 56319]]

annual determination of the N2O emissions factor is 
sufficient to accurately calculate N2O emissions as long as 
the train equipment remains consistent over the year-long period (i.e., 
no installation of abatement technology).
    Comment: Multiple commenters asked that alternative methods be 
allowed for calculating N2O emissions from nitric acid 
production. Specifically the commenters asked that EPA allow the use of 
N2O and flow CEMS to directly measure N2O 
emissions and use the performance test to evaluate the CEMS accuracy. 
They also requested that EPA allow use of existing process flow meters, 
process N2O analyzers to determine the amount of 
N2O sent to control devices and conduct a performance test 
measuring control device destruction efficiency for each control device 
and then calculate N2O emissions.
    Commenters also asked that finalizing a methodology for 
N2O stack testing for nitric acid units be delayed until EPA 
can coordinate with the commenters in formulating a more accurate means 
of measurement from these sources.
    Response: We agree that there are other accurate means of 
determining N2O emissions, such as N2O CEMS. The 
final rule has been changed to allow alternative test methods, in 
addition to the proposed methods. Any alternative must be approved by 
the Administrator before being used to comply with this rule. An 
implementation plan that details how the alternative method will be 
implemented must be included in the request for the alternative method. 
Currently there is no EPA method for using N2O CEMS. EPA 
understands the need to further evaluate and establish alternative 
comparable or potentially more accurate methods for sources to use in 
calculating N2O emissions from nitric acid production and 
will address this in future rulemakings or amendments to rulemaking. 
Until the method is approved, facilities must use the alternatives 
proposed in the rule for a performance test. At minimum the performance 
test will help to QA/QC alternative methods currently used to monitor 
N2O emissions (including N2O CEMS).
    The final rule allows the use of existing process flow meters and 
process knowledge in the determination of the destruction efficiency of 
N2O abatement technologies. This parameter is often based on 
site-specific knowledge of operations in combination with manufacturer 
specifications. We believe that using existing methods reduces the 
potential cost impacts of this rulemaking and that it is in the best 
interest of the facilities that required parameters be accurately 
measured.
    Comment: Multiple commenters asked that Equation V-2 be edited to 
follow the summation format used in the IPCC Tier 2 methodology. The 
current format does not allow for multiple abatement technologies 
(including no abatement).
    Response: We agree with this comment. The equation in the proposed 
rule contained an error and did not allow for multiple abatement 
technologies. The final rule contains a corrected version of the 
equation.
Data Reporting Requirements
    Comment: Multiple commenters argued that the annual production 
rates, capacity and operating hours are considered CBI and should not 
be reported. The commenters asked that this information be maintained 
by the facility and made available to the Agency upon request.
    Response: We reviewed CBI comments received across the rule (both 
general and subpart-specific comments) and our response is discussed in 
Section II.R of this preamble and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues.'' See 
also Section II.N of this preamble for the response on the emissions 
verification approach.
    We agree that annual operating hours are not used in the 
calculation of N2O emissions and this parameter has been 
moved to recordkeeping. However, this parameter is still important for 
emissions verification. This information can help to verify anomalies 
in emissions data if there were temporary shutdowns, etc.
    We disagree that production be maintained as records rather than be 
reported. Nitric acid production is a parameter in the method for 
determining annual N2O emissions so we need production rate 
in order to verify the N2O emissions that are being 
reported. The internal verification system ensures that the GHG 
emissions reported are as accurate as possible.
    We disagree that capacities be considered confidential information. 
During the data gathering process, we located multiple publicly 
available sources that included production capacities for nitric acid 
production facilities. Capacity information can help EPA determine a 
reasonable range within which reported emissions should be. We agree 
that capacities are not used in the calculation of N2O 
emissions; however, this is still an important parameter for verifying 
emissions. Therefore, this parameter has been moved to recordkeeping.

W. Oil and Natural Gas Systems

    At this time, EPA is not going final with the fugitive and vented 
methane emissions from the oil and gas sector under 40 CFR part 98, 
subpart W. As EPA considers next steps, we will be reviewing the public 
comments and other relevant information.
    EPA received a number of lengthy, detailed comments regarding 40 
CFR part 98, subpart W. Commenters generally opposed the proposed 
reporting requirements and thought they would entail significant burden 
and cost. For example, many commenters asserted that use of direct 
measurement to collect data required under 40 CFR part 98, subpart W 
would entail significant burden and that the proposal lacked standards 
for leak detection and measurement equipment. In many cases, commenters 
provided alternative approaches to the reporting requirements proposed 
by EPA such as the use of emission factors and/or reducing the number 
of sources and sites requiring direct measurement e.g., through 
statistical sampling. In addition to comments on burden, commenters 
requested clarification from EPA on a number of proposed reporting 
provisions.
    As EPA received extensive comments on this subpart, EPA plans to 
take additional time to perform additional analysis and consider 
alternatives to data collection procedures and methodologies. These 
alternatives will provide similar coverage of vented and fugitive 
methane and other GHG emissions in the oil and gas sector, while 
concurrently taking into account industry burden. As stated in Section 
V.W of the preamble to the proposed rule (74 FR 166606, April 10, 
2009), EPA will also consider the inclusion of GHG reporting from other 
sectors of the oil and gas industry.
    Where applicable, EPA will also consider the applicability of 
engineering estimates, emissions modeling software and emissions 
factors rather than relying so extensively on the use of direct 
measurement. EPA will consider optimal methods of data collection in 
order to maximize data accuracy, while considering industry burden.

X. Petrochemical Production

1. Summary of the Final Rule
    Source Category Definition. The petrochemical production source 
category consists of all processes that produce acrylonitrile, carbon 
black, ethylene, ethylene dichloride, ethylene oxide, or methanol, with 
certain exceptions. Exceptions include processes that produce a 
petrochemical

[[Page 56320]]

as a byproduct, processes that produce methanol from synthesis gas when 
the annual mass production of hydrogen or ammonia exceeds the annual 
mass of methanol produced, direct chlorination processes operated 
independently of oxychlorination processes to produce ethylene 
dichloride, processes that produce bone black, and processes that 
produce a petrochemical from bio-based feedstock.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For petrochemical production facilities, report 
CO2, CH4, and N2O process emissions 
from each petrochemical production unit. Process emissions include 
CO2 generated by reaction in the process. Process emissions 
also include CO2, CH4, and N2O 
emissions generated by combustion of off-gas from the process in 
stationary combustion units and flares. For some of the GHG emission 
calculation and monitoring options, 40 CFR part 98, subpart X 
references procedures in 40 CFR part 98, subpart C for calculating 
emissions from stationary combustion sources, and it references 
procedures in 40 CFR part 98, subpart Y for calculating emissions from 
flares.
    In addition, report GHG emissions for other source categories at 
the facilities for which calculation methods are provided in the rule, 
as applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
that does not burn process off-gas under 40 CFR part 98, subpart C 
(General Stationary Fuel Combustion Sources). The quantity of 
CO2 captured must also be reported by following the 
requirements of 40 CFR part 98, subpart PP.
    GHG Emissions Calculation and Monitoring. CO2 process 
emissions from petrochemical production must be determined by one of 
three methods. Process emissions include emissions from CO2 
generated by chemical reactions in the process and from the combustion 
of process off-gas and liquid wastes.
    One emission calculation option is to route all process vent 
emissions to one or more stacks and use CEMS to measure the 
CO2 emitted from each stack (except flare stacks). For each 
stack that includes emissions from combustion of process off-gas, 
reporters must calculate CH4 and N2O emissions by 
the procedures specified in 40 CFR part 98, subpart C. For each flare, 
the final rule requires CO2, CH4, and 
N2O emissions to be calculated using the procedures in 40 
CFR 98.253(b) (Petroleum Refineries). If CO2 CEMS are used 
on all subject stacks, even if the CEMS were installed for reasons 
other than compliance with this rule, then the rule requires the use of 
this reporting option.
    A second emission calculation option is to use a mass balance. 
Under this option, the quantity of each carbon-containing feedstock 
added to the process and the quantity of each carbon-containing product 
produced by the process must be measured for each calendar month, or it 
may be calculated based on measured changes in the liquid level in 
storage tanks. The carbon content of each feedstock and product also 
must be determined at least once per month. The carbon content may be 
measured directly, or it may be calculated based on measurements of the 
composition and known compound molecular weights. Under this option, 
the procedures for products also apply to byproducts and liquid organic 
wastes that are not combusted onsite. To prevent double-counting of 
combustion emissions, this option specifies that the procedures for 
stationary combustion sources in 40 CFR part 98, subpart C apply only 
to the supplemental fuel (e.g., natural gas) burned in combustion units 
that supply energy needs for petrochemical processes. The final rule 
specifies numerous measurement method options and related calibration 
requirements in 40 CFR 98.244. To potentially minimize the sampling and 
analysis burden, the final rule, like the proposed rule, includes an 
option that allows reporters to assume a feedstock or product is always 
100 percent pure if they determine that the specified compound is 
always present at greater than 99.5 percent.
    A third emission calculation option is available only for ethylene 
processes. Because nearly all process emissions from this process are 
from combustion of process off-gas, the final rule allows calculation 
of emissions from all stationary combustion units that burn process 
off-gas (with or without supplemental fuel) in accordance with the Tier 
3 or Tier 4 procedures in 40 CFR part 98, subpart C. In addition, this 
option requires CO2, CH4, and N2O 
emissions from each flare to be calculated using the procedures in 40 
CFR 98.253(b) (Petroleum Refineries).
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR 98.246.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR 98.247.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart X: Petrochemical Production.''
     The definition of the source category was changed to 
exclude ethylene dichloride production by the direct chlorination 
process alone from the petrochemical production source category because 
the only GHG emissions from this process are from the combustion of 
supplemental fuel and the combustion of hydrocarbon emissions in air 
pollution control devices. Ethylene dichloride produced by both direct 
chlorination and oxychlorination in the ``balanced process'' is still 
part of the source category.
     For the mass balance option, the measurement and emission 
calculation frequency was changed from weekly to monthly.
     For ethylene processes, an alternative was added to the 
mass balance option that allows reporters to calculate emissions from 
stationary combustion sources that burn ethylene process off-gas (with 
or without supplemental fuel) using the Tier 3 or Tier 4 procedures in 
40 CFR part 98, subpart C. This includes all such combustion units, 
including units that supply energy to processes other than the ethylene 
process. This option does not affect requirements for stationary 
combustion sources related to ethylene processes that burn no process 
off-gas; emissions from these combustion units still must be calculated 
using the methods in any applicable Tier in 40 CFR part 98, subpart C.
     The reporting requirements in 40 CFR 98.246 were 
reorganized and updated to facilitate the emissions verification 
process, simplify and clarify requirements, and address requirements 
for the new monitoring option for ethylene processes.

[[Page 56321]]

3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Many comments on petrochemical production were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart X: Petrochemical Production.''
    Definition of Source Category.
    Comment: Several commenters stated that ethylene production should 
be removed from the petrochemical production source category because 
essentially all GHG emissions from such processes are from combustion 
sources, which would be subject to reporting under 40 CFR part 98, 
subpart C regardless of whether the process is included in the 
petrochemical production source category. According to two commenters, 
using a mass balance approach is irrelevant and confusing because 
ethylene processes have no normal process vents. One commenter noted 
that methane is produced in ethylene processes, but the vast majority 
is returned as fuel within the plant or another plant at the same site 
and thus would produce CO2 emissions only when combusted. 
Another commenter noted that off-gas from ethylene processes that are 
co-located with a petroleum refinery or other chemical plants is sent 
to the fuel gas system where it is mixed with other process gases from 
non-ethylene units in a fuel gas blend drum and then distributed to 
combustion units throughout the refinery and/or chemical plant. 
According to two commenters, the mass balance approach is onerous due 
to the number of product streams that would have to be measured, and 
the results of a mass balance most likely would be less accurate than a 
fuel combustion methodology. These two commenters also noted that 
calculating GHG emissions based on fuel combustion is the methodology 
used currently by most ethylene units. One commenter suggested that as 
an alternative to excluding ethylene units from the petrochemical 
production source category, EPA could add an emission calculation 
methodology to 40 CFR part 98, subpart X that would allow facilities to 
calculate combustion emissions based on fuel consumption.
    Response: As one commenter noted, methane (and other light ends) 
are generally burned in combustion units to supply energy needs for the 
ethylene process itself and possibly other processes. Emissions from 
combustion of these process off-gases are process emissions that are 
intended to be reported under 40 CFR part 98, subpart X. At facilities 
where the ethylene process off-gases are not mixed with off-gas from 
other processes, we do not believe that the mass balance approach is 
illogical; the flows and carbon contents of feedstocks and products can 
be determined for an ethylene process, and the resulting values can be 
used in the mass balance equations, just as they can for any other 
petrochemical process. Furthermore, we do not know if the views of the 
commenters reflect the views of all ethylene manufacturers. Therefore, 
we have retained ethylene in the petrochemical production source 
category, and we have retained the mass balance option in the final 
rule.
    Although we still think a mass balance approach is appropriate and 
valid for ethylene processes, we have also evaluated combustion-based 
methodology options for the final rule. Given that the cracking and 
separation operations generate negligible CO2, we agree with 
the commenters that the only significant source of emissions in 
ethylene production is from combustion operations. One concern we have 
with using the Tier 1 and Tier 2 methodologies in 40 CFR part 98, 
subpart C is that they rely on default emission factors and company 
records (rather than measurements) of fuel flow. Given the variety of 
feedstocks and the corresponding variety in process off-gas, we do not 
believe default emission factors or fuel flow based on company records 
are appropriate. Therefore, we rejected the Tier 1 and Tier 2 
methodologies. On the other hand, Tier 3 requires measurement of the 
total fuel flow and relatively frequent measurement of the carbon 
content of the fuel. Using CEMS to measure CO2 emissions 
(i.e., the Tier 4 methodology in 40 CFR part 98, subpart C) is also a 
good way to measure CO2 emissions from any combustion unit. 
Therefore, we determined that use of the Tier 3 or Tier 4 methodology 
is acceptable for calculating emissions from combustion units that burn 
ethylene process off-gas (with or without mixing with supplemental 
fuel), and these options are included in the final rule. In addition, 
because the methodology used for calculating emissions from one 
combustion unit has no bearing on the emissions from any other 
combustion unit, the final rule states that a facility is not required 
to use the same Tier for each stationary combustion unit.
    Comment: One commenter requested that EPA remove ethylene 
dichloride (EDC) from the petrochemical source category because EDC is 
not manufactured using a fossil fuel-based feedstock (e.g., crude oil, 
naphtha, natural gas condensate, methane, or other fossil fuel-based 
chemicals), no GHGs are used in the manufacturing process, and only a 
trace amount of CO2 is generated in the process. Another 
commenter requested clarification that EDC produced as an intermediate 
in the production of vinyl chloride monomer is not part of the 
petrochemical source category because the entire process is considered 
to be an ``integrated process'', and the primary product of the process 
is not EDC. The commenter noted that the term ``primary product'' is 
also used in the Hazardous Organic NESHAP (HON) (40 CFR part 63, 
subpart F), but it has a different definition. To avoid confusion 
created by multiple definitions for the same term, the commenter urged 
EPA to consider alternatives to the concept of primary product for 
determining applicability of an integrated process.
    Response: EDC is produced by two processes. In one process, the 
direct chlorination process, ethylene is reacted with chlorine to 
create EDC. As the commenters noted, reactions in this process produce 
negligible CO2 emissions and no other GHG emissions. The 
only GHG emissions associated with this process are from the combustion 
of process off-gas and supplemental fuel. We have determined that 
monitoring and reporting of these emissions will be required under 40 
CFR part 98, subpart C. Therefore, we have removed this process from 
the petrochemical source category.
    In the second EDC process, the oxychlorination process, ethylene is 
reacted with hydrochloric acid to create EDC and water. Some of the 
ethylene, however, oxidizes to CO2 and water in a competing 
side reaction. All facilities in the United States (U.S.) that operate 
this process operate it as part of an integrated process that includes 
vinyl chloride monomer production and a direct chlorination process. 
This integrated process is called a ``balanced process''. Although 
available estimates suggest the amount of CO2 emitted is 
small relative to emissions from combustion, we do not have data to 
support such estimates. Furthermore, even if small relative to other 
sources, the total amount is not necessarily insignificant. We continue 
to believe information about these emissions is needed in order to 
support future policy decisions regarding petrochemical processes. 
Therefore, we have not removed EDC production by the balanced process 
from the petrochemical production source category.

[[Page 56322]]

    In the proposed rule, an ``integrated process'' was defined as ``a 
process that produces a petrochemical as well as one or more other 
chemicals that are part of other source categories'' subject to 
reporting under 40 CFR part 98. This concept does not apply to 
production of EDC as an intermediate that is used in the onsite 
production of vinyl chloride monomer because vinyl chloride monomer 
production is not a source category that is subject to reporting under 
40 CFR part 98. We used general language in the proposed rule that 
would apply to various integrated process scenarios, but the only 
scenario we know of that meets these conditions is methanol production 
from synthesis gas that is sometimes also used to produce hydrogen and/
or ammonia (both of which are subject to reporting under other subparts 
in 40 CFR part 98). Because this is the only situation where the 
``integrated process'' concept would apply, we decided to replace it in 
the final rule with language in 40 CFR 98.240 that explicitly states 
the applicability determination procedures for a process that produces 
methanol, hydrogen, and/or ammonia from synthesis gas. Thus, the term 
``primary product'' has also been removed from the final rule, which 
eliminates the potential conflict with the definition in the HON.
Method for Calculating GHG Emissions
    Comment: Two commenters stated that the proposed CEMS requirements 
are overly restrictive. According to these commenters, a facility 
should have the option to install a CEMS on one or more sources without 
being required to have a CEMS on all sources associated with a 
petrochemical production process. For example, the commenters suggested 
that a facility should have the flexibility to use a CEMS on a large 
emission point while being allowed to use the combustion equations and/
or the mass balance approach for smaller emission points in the process 
(e.g., start-up heaters and steam jet exhausts from distillation 
columns operating under vacuum).
    Response: If some emissions were from stacks monitored with CEMS 
and all other emissions were from combustion units without CEMS, it 
would be possible to use a combination of CEMS and the combustion 
equation methodology to calculate the total GHG emissions from a 
petrochemical process. However, this scenario is unlikely, which means 
other methodology would be needed to estimate emissions from other 
emission points (e.g., the steam jet exhausts cited by the commenters). 
It is not clear to us how the mass balance methodology would be used to 
estimate these other emissions because the mass balance relies on 
knowledge of the total carbon input to the process and the total amount 
of carbon in all products (and organic liquid wastes); the difference 
is assumed to be the total CO2 emissions. Theoretically, 
other methodology could be developed to calculate emissions from 
specific other emission points, but the commenter has not suggested 
other techniques. Therefore, the final rule does not include an option 
to mix CEMS with other methodology for a given process unit.
    Comment: According to several commenters, weekly measurements of 
feedstocks and products are burdensome or unwarranted. Two commenters 
suggested changing the frequency to monthly because monthly accounting 
would align better with existing industry accounting procedures, reduce 
the burden, and provide 12 high-quality estimates per year. One 
commenter suggested monthly mass balance calculations for carbon black 
facilities because the emissions from a carbon black manufacturing 
facility do not vary significantly from week to week. Another commenter 
requested a provision to allow the reporter to determine a sampling 
frequency that is consistent with the variability of the stream.
    Response: We are sensitive to the burden imposed by the rule and 
want to minimize it when possible. Based on the results of an 
uncertainty analysis (see memorandum entitled ``Monte Carlo Simulation 
of Uncertainty in Monitoring Frequency for Mass Balance Option for 
Petrochemical Production Facilities'' in the docket) we believe longer 
monitoring periods will not significantly compromise the monitoring 
results for the mass balance option. Therefore, the mass balance option 
in the final rule requires monthly monitoring instead of the proposed 
weekly monitoring.
Data Reporting Requirements
    Comment: Two commenters stated that the proposed reporting 
requirements are excessive, particularly information such as each 
carbon content measurement and information on the calibration of each 
flow meter. According to the commenters, submitting this information 
will not improve the overall quality of the GHG emission calculation, 
and it is not necessary because the facilities are required to certify 
that the submitted information is true, accurate, and complete. 
Therefore, the commenters recommended that facilities be required to 
retain records of such information rather than submit it in reports.
    Response: A primary reason that additional information beyond 
annual emissions must be reported is so that EPA can verify the 
results. To facilitate the emissions verification process, 40 CFR 
98.246 was reorganized and updated. For example, the final rule 
requires reporting of all input data used in the emission calculation 
equations, not just the carbon content values and the annual 
quantities, because this information is needed so the calculations can 
be reproduced and confirmed as part of the emissions verification 
process. Note, however, that any increase in the burden to report flow 
measurements has been offset by the reduction in monitoring frequency 
from weekly to monthly. The reporting requirements in the final rule 
for the mass balance option also have been simplified and clarified by 
replacing the requirement to submit all information related to 
uncertainty estimates with a requirement to submit only the dates and 
summarized results of measurement device calibrations. The estimated 
accuracy of measurement devices and the technical basis for such 
measurements must also be documented as part of the monitoring plan 
that is maintained onsite. The reporting section also was updated to 
include reporting requirements for the new monitoring option for 
ethylene processes.

Y. Petroleum Refineries

1. Summary of the Final Rule
i. Source Category Definition
    Petroleum refineries are facilities that produce gasoline, gasoline 
blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel 
oils, lubricants, or asphalt (bitumen) by the distillation of petroleum 
or the redistillation, cracking, or reforming of petroleum derivatives. 
The definition of petroleum refineries excludes facilities that distill 
only pipeline transmix (off-spec material created when different 
specification products mix during pipeline transportation), regardless 
of the products produced.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
ii. GHGs to Report
    The refinery processes and gases that must be reported are listed 
in Table Y-1 of this preamble along with the rule subpart that 
specifies the calculation methodology that must be used.

[[Page 56323]]



                                            Table Y-1--GHGs To Report
----------------------------------------------------------------------------------------------------------------
                                                                Report emissions of the listed GHGs by following
                                                                the requirements of the 40 CFR part 98, subpart
               For this refinery process . . .                                  indicated . . .
                                                              --------------------------------------------------
                                                                     CO2              CH4              N2O
----------------------------------------------------------------------------------------------------------------
Stationary combustion........................................                C                C                C
Flares.......................................................               Y                Y                Y
Catalytic cracking...........................................               Y                Y                Y
Traditional fluid coking.....................................               Y                Y                Y
Fluid coking with flexicoking design.........................                C/Y              C/Y              C/Y
Delayed coking...............................................              --                Y               --
Catalytic reforming..........................................               Y                Y                Y
Onsite and offsite sulfur recovery...........................               Y               --               --
Coke calcining...............................................               Y                Y                Y
Asphalt blowing..............................................               Y                Y               --
Equipment leaks..............................................              --                Y               --
Storage tanks................................................              --                Y               --
Other process vents..........................................               Y                Y                Y
Uncontrolled blowdown systems................................              --                Y               --
Loading operations...........................................              --                Y               --
Hydrogen plants (nonmerchant)................................               P                P               --
----------------------------------------------------------------------------------------------------------------
Key:
C = 40 CFR part 98, subpart C (General Stationary Combustion Sources).
P = 40 CFR part 98, subpart P (Hydrogen Production).
Y = 40 CFR part 98, subpart Y (Petroleum Refineries).
-- = Reporting from this process is not required.

iii. GHG Emissions Calculation and Monitoring
    Under 40 CFR part 98, subpart Y, petroleum refineries must 
calculate CO2, CH4 and N2O emissions 
using the calculation methods described below for each refinery 
process.
    For CO2 emissions, reporters must use CEMS or specified 
calculation methods as follows:
     For refinery units with certain types of CEMS in place, 
reporters must use the CEMS and follow the Tier 4 methodology of 40 CFR 
part 98, subpart C to report combined process and combustion 
CO2 emissions.
     For refinery units without CEMS in place, reporters can 
elect to either (1) install and operate a CEMS to measure combined 
process and combustion CO2 emissions according to the 
requirements specified in 40 CFR part 98, subpart C or (2) calculate 
CO2 emissions using the methods summarized below.
    Flares. CO2 emissions from flares must be calculated 
using the gas flow rate (either measured with a continuous flow meter 
or calculated using engineering calculations) and either: (1) At least 
weekly measured carbon content of the flare gas, or (2) at least weekly 
measured heat content of the flare gas and an emission factor provided 
in the rule. If the carbon content and heat content of the gas are not 
measured at least weekly, engineering estimates of heat content during 
normal flare use is allowed, but CO2 emissions for each 
startup, shutdown, and malfunction event exceeding 500,000 standard 
cubic feet (scf) per day of flare gas must be calculated separately 
using engineering estimates of the quantity of gas discharged and the 
carbon content of the flared gas. CH4 and N2O 
emissions from flares must be calculated using the methods specified in 
40 CFR part 98, subpart Y.
    Catalytic Cracking Units, Fluid Coking Units, and Catalytic 
Reforming Units. CO2 emissions must be calculated using the 
volumetric flow rate of the exhaust gas (measured or calculated) and 
hourly measured carbon monoxide (CO) and CO2 concentrations 
in the exhaust stacks from the catalytic cracking unit regenerator and 
fluid coking unit burner from units exceeding 10,000 barrels per stream 
day. Catalytic cracking and fluid coking units below this threshold 
must use the required flow and gas monitors if they are in-place, but 
may use engineering estimates for determining CO2 emissions 
if the required flow and gas monitors are not in place. Similarly, 
catalytic reforming units may use the flow and gas monitors required 
for large catalytic cracking and fluid coking units; alternatively, 
reporters may use engineering estimates based on the quantity of coke 
burned off, the carbon content of the coke (using either a measured or 
a default value), and the number of regeneration cycles. CH4 
and N2O emissions may be measured or may be calculated using 
the CO2 emissions and default emission factors. Fluid coking 
units that use the flexicoking design may account for their GHG 
emissions either by using the methods specified for traditional fluid 
coking units, or by using the methods for stationary combustion 
specified in 40 CFR part 98, subpart C.
    Onsite and Off Site Sulfur Recovery. CO2 emissions must 
be calculated using the volumetric flow rate of the sour gas (measured 
continuously or calculated from engineering calculations) and the 
carbon content of the sour gas stream (using a measured or a default 
value).
    Coke Calcining Units. CO2 emissions must be calculated 
from the difference between the carbon input as green coke and the 
carbon output as marketable petroleum coke and as coke dust collected 
in the dust collection system. The CH4 and N2O 
emissions from coke calcining units may be measured or calculated using 
the calculated CO2 emissions and default emission factors.
    Asphalt Blowing Operations. For uncontrolled asphalt blowing 
operations or asphalt blowing operations controlled by vapor scrubbing, 
CH4 and CO2 emissions must be calculated using a 
facility-specific emission factor based on test data or, where test 
data are not available, a default emission factor provided in the rule. 
For asphalt blowing operations controlled by a thermal oxidizer or 
flare, CH4 and CO2 emissions must be calculated 
by assuming 98 percent of the CH4 and other hydrocarbons 
generated by the asphalt blowing operation are converted to 
CO2.
    Delayed Coking Units. CH4 emissions from the 
depressurization of delayed

[[Page 56324]]

coking vessels must be calculated using the method outlined below for 
other process vents. The emissions released during the opening of 
vessels for coke cutting operations must be calculated using the vessel 
parameters (height and diameter), vessel pressure, the number of times 
the vessel was opened, the void fraction of the coking vessel prior to 
steaming, and the mole fraction of CH4 in the gas released 
(using a measured or a default value provided in the rule). The rule 
provides an alternative of using only the vessel parameter equation if 
no water or steam is added to the vessel after the vessel is vented to 
the atmosphere.
    Other Process Vents. GHG emissions from other process vents that 
contain CO2, CH4, or N2O exceeding 
concentration thresholds specified in the rule must be calculated using 
the volumetric flow rate, the mole fraction of the GHG in the exhaust 
gas, and the number of hours during which venting occurred.
    Uncontrolled Blowdown Systems. CH4 emissions from 
uncontrolled blowdown systems must be calculated using either the 
method specified for process vents or a default emission factor and the 
sum of crude oil and intermediate products received from off site and 
processed at the facility.
    Equipment Leaks. CH4 emissions from equipment leaks must 
be calculated using either default emission factors or process-specific 
CH4 composition data and leak data collected using the leak 
detection methods specified in EPA's Protocol for Equipment Leak 
Emission Estimates.
    Storage Tanks. For storage tanks covered by the requirements of 
this rule, the methodology used to calculate the CH4 
emissions depends on the material stored. For storage tanks used to 
store unstabilized crude oil, facilities must use either: (1) The 
CH4 composition of the unstabilized crude oil (based on 
direct measurement or product knowledge) and the measured gas 
generation rate; or (2) an emission factor-based method using the 
quantity of unstabilized crude oil received at the facility, the 
pressure difference between the previous storage pressure and 
atmospheric pressure, the mole fraction of CH4 in the vented 
gas (using either a measured or a default value), and an emission 
factor provided in the rule. For storage tanks used to store material 
other than unstabilized crude oil with a vapor-phase CH4 
concentration of 0.5 percent by volume or more, facilities must use 
either tank-specific methane composition data and applicable 
correlations in AP-42, Section 7.1 (as implemented in the TANKS Model 
(Version 4.09D) or similar models) or a default emission factor 
provided in the rule.
    Loading Operations. CH4 emissions from loading 
operations must be calculated using vapor-phase methane composition 
data and the method in Section 5.2 of AP-42: ``Compilation of Air 
Pollution Emission Factors.'' Facilities must calculate CH4 
emissions only for loading materials that have an equilibrium vapor-
phase CH4 concentration equal to or greater than 0.5 percent 
by volume. Other facilities may assume zero CH4 emissions.
iv. Data Reporting
    In addition to the information required to be reported by the 
General Provisions (40 CFR 98.3(c)) and summarized in Section II.A of 
this preamble, reporters must submit additional data that are used to 
calculate GHG emissions. A list of the specific data to be reported for 
this source category is contained in 40 CFR part 98, subpart Y.
v. Recordkeeping
    In addition to the records required by the General Provisions (40 
CFR 98.3(g)) and summarized in Section II.A of this preamble, reporters 
must keep records of additional data used to calculate GHG emissions. A 
list of specific records that must be retained for this source category 
is included in 40 CFR part 98, subpart Y.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart Y: Petroleum Refineries.''
     The minimum monitoring frequency for flare gas heat value 
or carbon content was changed to weekly from daily. (For background on 
the selection of a weekly frequency, see memorandum entitled: 
``Uncertainty in Flare Estimates Based on Sampling Frequency'' in the 
docket.) Engineering calculations are allowed in the final rule for 
reporters that do not monitor flare gas flow continuously or flare 
heating value or carbon content at least weekly.
     The minimum monitoring frequency for refinery fuel gas 
carbon content and molecular weight was changed to weekly from daily in 
40 CFR part 98, subpart C for reporters that do not have continuous 
monitoring equipment, and we clarified in 40 CFR part 98, subpart Y 
that common (fuel) pipe monitoring is allowed for petroleum refineries.
     We added a flare combustion efficiency of 98 percent, and 
we revised the equation for flare CH4 emissions to account 
for uncombusted methane.
     The final rule allows engineering calculations to 
determine CO2 emissions for catalytic cracking units and 
fluid coking units below 10,000 bbl/stream day that do not have 
CO2/CO/O2 monitors already installed.
     The delayed coking unit depressurization emission 
equations and asphalt blowing equations were amended to address 
comments received.
     We added concentration thresholds for CO2, 
CH4 and N2O from process vents below which GHG 
emissions are not required to be calculated and reported.
     The reporting requirements were updated to facilitate the 
emissions verification process.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on petroleum refineries were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart Y: Petroleum Refineries.''
Definition of Source Category
    Comment: Several commenters expressed concern that EPA defined a 
Petroleum Refinery so broadly that it could be interpreted to include 
chemical facilities that use petroleum-based materials as raw 
materials. Of particular concern was the term ``* * * and other 
products * * *'' which many commenters interpreted to include the 
manufacture of chemicals, synthetic rubber, and a variety of plastics. 
One commenter also requested clarification that ``other products'' did 
not include sulfur, ammonia, or hydrogen sulfide. Several commenters 
requested clarification that the definition of petroleum refineries did 
not include lube oil production or fuel blending operations if the 
products were produced without distilling, redistilling, cracking, or 
reforming of the petroleum derivatives.
    Response: We have revised and clarified the definition of petroleum 
refinery to list a few additional refinery products (specifically 
gasoline blending stocks and naphtha) and deleted the term ``or other 
products.'' We believe that this change clarifies that companies that 
use petroleum derivatives to make

[[Page 56325]]

only petrochemicals, plastics, synthetic rubber, sulfur, or any other 
product other than those specifically listed are not considered 
petroleum refineries. We feel the definition also clearly excludes lube 
oil manufacturing provided the lube oil manufacturer does not distill, 
redistill, crack, or reform the petroleum derivatives at the facility.
    Comment: Numerous commenters requested that many of the emission 
sources for which 40 CFR part 98, subpart Y required reporting were 
small and should not have to be reported. Several commenters noted that 
EPA's TSD for the Petroleum Refining Sector: Proposed Rule for 
Mandatory Reporting of Greenhouse Gases, indicates that 92.9 percent of 
the refining sector's GHG emissions come from two sources, combustion 
and catalytic coke operations. The remaining 7.1 percent of emissions 
come from eight distinct categories, including: Hydrogen plants (2.7 
percent); Sulfur Plants (1.9 percent); Flaring (1.6 percent); 
Wastewater Treatment (0.43 percent); Blowdown (0.18 percent); Asphalt 
Blowing (0.10 percent); Delayed Coking (0.058 percent); Equipment Leaks 
(0.014 percent); Storage Tanks (0.007 percent); and Cooling Towers 
(0.003 percent). The commenters argued that the burden associated with 
the collection of data as prescribed in the proposed rule is not 
warranted for small sources and/or not consistent with EPA's stated 
intended purpose of the rule which is to support analysis of future 
policy decisions.
    Response: The TSD estimates are based largely on engineering 
estimates without significant supporting data. For the smaller sources, 
we have provided very simple methods to calculate the GHG emissions 
from these sources to minimize the monitoring, recordkeeping, and 
reporting burden associated with these sources when no measurement data 
are available. However, requiring reporting for these sources will 
provide EPA with valuable data to better characterize them and provide 
a better record upon which to formulate decisions regarding whether to 
include or exclude these sources from future GHG policy decisions. 
Additionally, while some of these sources are currently believed to be 
small compared to the larger sources present at petroleum refineries, 
they are not necessarily insignificant. The inclusion of reporting data 
for these sources is critical to support analysis of future policy 
decisions for petroleum refineries.
    Comment: Several commenters objected to the mandatory reporting of 
CH4 and N2O emissions within the Petroleum 
Refinery source category. Many commenters cited the TSD, which 
indicated that N2O emissions account for 0.09 percent of the 
GHG emissions and CH4 account for only 0.87 percent of the 
GHG emissions. The commenters argued that the measurement error for the 
larger sources (stationary combustion sources and catalytic cracking 
unit coke burn-off) exceeds the contributions of these sources. As 
such, the commenters stated that the burden associated with reporting 
these emissions is not warranted and/or not consistent with EPA's 
stated intended purpose of the rule which is to support analysis of 
future policy decisions.
    Response: The TSD estimates for CH4 and N2O 
are based largely on engineering estimates without significant 
supporting data. We specifically require reporting of these various 
GHGs to obtain better data by which to support future policy analysis. 
Moreover, EPA has pending before it a petition to reconsider the 
recently revised New Source Performance Standard (NSPS) for petroleum 
refineries asking EPA to reconsider, among other things, whether to 
establish GHG standards under section 111 for refineries. As such, we 
have a keen interest in obtaining improved GHG emissions data in order 
to better analyze policy options. For instance, refineries are a 
significant source of NOX emissions, but we have no data to 
determine the fraction of NOX that is N2O. With 
the increased use at refineries of NOX control devices, such 
as low-NOX burners, low excess air, selective catalytic 
reduction (SCR) systems, and selective non-catalytic reduction (SNCR) 
systems, it seems plausible that N2O may be a more 
significant portion of a refinery's NOX emissions. Thus, if 
a facility has measurement data for a source, the reporting of these 
data are important for better understanding the impact of current and 
future policy options. Consequently, we have provided additional 
alternatives that allow the use of measured N2O (and 
CH4) emissions or site-specific emission factors in addition 
to the default factors. Nonetheless, we have provided very simple 
default methods to calculate the emission of these GHGs when 
measurement data are not available. While emissions of CH4 
and N2O may not be large comparatively, the reporting method 
for these pollutants is straightforward and commensurate with the 
anticipated emissions contribution.
Method for Calculating GHG Emissions
    Comment: Several comments objected to the requirements for flares, 
particularly the requirements for SSM events. Some commenters also 
stated that daily sampling was too burdensome. The commenters suggested 
that flare emissions be dropped from the rule or that refineries be 
allowed to perform a one-time calculation. One commenter noted that the 
proposed equation did not account for flare combustion efficiency, 
which was inconsistent with other subparts, and recommended that a 
flare efficiency factor be added to the equation to calculate the 
CO2 emissions from flares.
    Response: EPA needs accurate data on flare emissions to better 
understand this emission source, as flare use can vary significantly 
from day-to-day and year-to-year. Use of flares is too episodic and 
variable to allow a one-time calculation. However, we recognize that 
flares may contribute about two percent of a refinery's GHG emissions. 
Therefore, we sought to reduce the burden associated with the flare 
monitoring and reporting requirements. As proposed, special 
calculations for SSM events were only required if daily measurement 
data were not available. In this final rule, we allow weekly monitoring 
of flare use without triggering special SSM event calculations, which 
should lessen the burden associated with calculating flare emissions 
while not significantly changing the accuracy of the data. 
Additionally, we included a threshold flaring rate of 500,000 scf/day 
for SSM events. Only SSM events exceeding this gas flare rate require 
special SSM calculations in the final rule. Some consent decree 
requirements and State rules require root cause analysis and 
quantification of emission events exceeding 500,000 scf/day. We 
consider events of this magnitude to be significant and believe a 
separate analysis is justified in addition to the procedures that apply 
to routine operation. We have also revised the equations for 
CO2 and CH4 to account for flare combustion 
efficiency.
Monitoring and QA/QC Requirements
    Comment: Several commenters argued that the monitoring and QA/QC 
requirements were excessive and that EPA significantly underestimated 
the costs associated with complying with the reporting requirements 
under 40 CFR part 98, subpart Y. One commenter noted that existing 
facility CO2 CEMS, HHV monitors, carbon content monitors, 
and flow meters are not necessarily for ``regulatory'' purposes and 
thus may not meet the accuracy requirements of the rule. The commenter 
suggested many more refineries would have to add or replace monitors as 
a result of the rule. Many commenters suggested EPA significantly

[[Page 56326]]

underestimated the labor hours required to collect and analyze daily 
samples as well as to develop and implement a QA plan. Various 
commenters supplied labor or cost estimates for various requirements in 
the rule, including costs of implementing an LDAR program and flare SSM 
calculations. Several commenters stated that the requirement to use a 
CEMS for monitoring CO2 from the catalytic cracking unit was 
expensive and burdensome, especially for small refineries that do not 
have a CEMS infrastructure.
    Response: We have significantly revised our rule requirements for 
petroleum refineries and stationary combustion sources to reduce burden 
to the industry. We have provided in the final rule (in 40 CFR part 98, 
subpart C) a default emission factor for refinery (still) gas to allow 
combustion sources that combust refinery gas and meet the applicability 
requirements in 40 CFR part 98, subpart C to use Tier 2 methods. For 
sources that do not meet the Tier 2 requirements, weekly monitoring for 
refinery fuel gas under Tier 3 (40 CFR part 98, subpart C) and for 
flare gas (40 CFR part 98, subpart Y) is allowed. We have also re-
assessed our costs based on the comments received and increased the 
labor hours estimated to collect and analyze samples, develop QA plans, 
and to perform QA/QC of existing equipment. We did review our QA/QC 
requirements and see no validity to the argument that our QA/QC 
requirements are so stringent that refineries will have to replace 
existing monitors to comply with the rule. While we note that some cost 
elements suggested by commenters are relevant and have been addressed 
in the changes in the labor estimates for sampling, analysis, and QA/QC 
as described above, other cost elements suggested by commenters are not 
relevant. For example, revisions of LDAR programs are not required 
under the rule; the proposed and final rule specifically provides a 
simple process-based emission factor approach for estimating 
CH4 emissions from equipment leaks. We are cognizant that 
refineries with small catalytic cracking units are most likely to elect 
a compliance option under 40 CFR part 63, subpart UUU that does not 
require monitoring of coke burn-off, so these small refineries are most 
likely the facilities that would have been required to install 
monitoring equipment under the proposed rule. After reviewing these 
costs and impacts on the small refineries, we have allowed engineering 
calculations to determine CO2 emissions for catalytic 
cracking units below 10,000 bbl/stream day that do not have 
CO2/CO/O2 monitors already installed.
    Even though we have reduced the stringency of the rule in many 
places, our revised cost estimates indicate that the average cost per 
refinery is approximately 60 percent higher than projected at proposal. 
We believe our revised refinery costs accurately portray the burden 
associated with the final reporting requirements in 40 CFR part 98, 
subpart Y. Nonetheless, we continue to believe that the costs are 
reasonable for this rule, especially considering that petroleum 
refineries are among the larger sources of GHG emissions in the U.S.

Z. Phosphoric Acid Production

1. Summary of the Final Rule
    Source Category Definition. The phosphoric acid production source 
category consists of facilities that use a wet-process phosphoric acid 
process to produce phosphoric acid. A wet-process phosphoric acid 
process line is any system that manufactures phosphoric acid by 
reacting phosphate rock and acid and is usually identified by an 
individual identification number in a CAA operating permit.
    Reporters must submit annual GHG reports for Facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Report CO2 emissions from each wet-
process phosphoric acid process line.
    In addition, report GHG emissions at each facility for other source 
categories for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. Calculate process 
emissions of CO2 using one of two methods, as appropriate:
     Most reporters can elect to either (1) install and 
operating CEMS and follow the Tier 4 methodology (in 40 CFR part 98, 
subpart C) or (2) calculate CO2 emissions based on monthly 
measurements of the mass of phosphate rock consumed and inorganic 
carbon content of each grab sample of phosphate rock.
     However, if process CO2 emissions from 
phosphoric acid production are emitted through the same stack as a 
combustion unit or process equipment that uses a CEMS and follows Tier 
4 methodology to report CO2 emissions, then the CEMS must be 
used to measure and report combined CO2 emissions from that 
stack. In such cases, the reporter cannot use the CO2 
calculation methodology outlined in approach (2) in the previous 
bullet.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart Z.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart Z.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart Z: Phosphoric Acid Production.''
     The rule was revised to allow the use of techniques from 
Part 60 and Part 63 for calculating the weight of phosphorous-
containing rock.
     The missing data provisions were revised to allow the use 
of default inorganic carbon content values based on the origin of the 
phosphorous-containing rock, in addition to determining missing 
inorganic carbon contents of phosphate rock consumed using an 
arithmetic average of measured values from of inorganic carbon contents 
of phosphate rock of the appropriate origin preceding and following the 
missing data incident.
     40 CFR 98.266 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.267 to 40 CFR 98.266, and some data elements that are already 
used to calculate GHG emissions as specified in 40 CFR 98.263 were 
added to 40 CFR 98.266 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Several comments on phosphoric acid production were received 
covering numerous topics shown below.

[[Page 56327]]

Responses to significant comments received can be found in ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments, 
Subpart Z: Phosphoric Acid Production.''
Selection of Threshold
    Comment: Multiple commenters asked that phosphoric acid production 
units not be included as an ``all-in'' category. According to the 
commenters, the facilities are very minor sources of GHG emissions. The 
commenter conceded that most (if not all) would still fall within the 
reporting threshold requirement, but asserted that it was unnecessary 
to include all phosphoric acid production units as regulated facilities 
regardless of the amount of emissions. The commenters stated that EPA 
inaccurately suggests that these units are major emitters of GHGs which 
could have significant impacts on these minor sources.
    Response: We acknowledge the comments and concerns; however the 
final rule retains the ``all-in'' applicability requirement for this 
source category. The ``once in, always in'' provision has been removed. 
The final rule now contains provisions to cease reporting if annual 
reports demonstrate emissions less than specified levels for multiple 
years. These provisions apply to all reporting facilities, including 
those with phosphoric acid production processes. The purpose of this 
rule is to collect information on emissions sources for future policy 
development. Requiring reporting for these sources will provide EPA 
with valuable data to better characterize GHG emissions from phosphoric 
acid production and provide a more credible position if EPA elects to 
exclude these sources from future GHG policy analyses. We also believe 
that the accurate assessment of the emissions from phosphoric acid 
production will address the commenters' concerns about potential future 
impacts.
    Commenters may also be interested in reviewing Section II.H of this 
preamble for the response on provisions to cease reporting.
Method for Calculating GHG Emissions and Monitoring and QA/QC 
Requirements
    Comment: Multiple commenters asked that production measurements in 
this rule be consistent with the existing MACT and NSPS regulations for 
the phosphate industry. In these regulations, production measurement is 
determined by the mass of phosphate feed (as 
P2O5). Two commenters stated that the change 
would provide consistency, and ensure a reporting structure that fits 
with the actual practices of the industry.
    Response: We agree with the commenters that consistency among EPA 
regulations is important. Therefore, the final rule allows for 
techniques from part 60 and part 63 to calculate the weight of 
phosphorous-containing rock. This request is consistent with the intent 
of the proposed rule. Under existing regulations in part 60 and part 
63, phosphoric acid manufacturing facilities already measure the mass 
of phosphorous bearing feed on a ton/hour basis. This feed rate can be 
used to determine monthly phosphate rock consumption. Process 
CO2 emissions from phosphoric acid production are calculated 
from the total phosphate rock consumption multiplied by the inorganic 
carbon content of that rock. Further, part 60 and part 63 establish the 
appropriate monitoring and QA/QC procedures for determining this feed 
rate.
Procedures for Estimating Missing Data
    Comment: Multiple commenters asked that the final rule allow 
options for missing data. The commenters asked that the use of default 
carbon content values based on the origin of the rock be allowed if 
analytical data are unavailable. In addition, commenters requested that 
procedures be added for measurement of the mass of phosphate rock 
consumed, suggesting procedures similar to those in 40 CFR part 98, 
subpart C, the lesser of the maximum capacity of the system, the 
maximum rate the meter can measure, or best available estimate based on 
available process data.
    Response: We agree with the commenters on this point. The final 
rule has been changed to allow the use of a default factor (by origin 
of the phosphate rock) for each missing value of the inorganic carbon 
content of phosphate rock. Use of a default carbon value in place of 
the missing data will provide a reasonable estimate of the total 
emissions from the facility and will avoid assuming the maximum 
possible facility emissions when no data are available. These default 
values have been added to the final rule in Table Z-1 of 40 CFR part 
98, subpart Z.
    Missing data procedures have also been added as suggested for 
missing monthly estimates of the mass of phosphate rock consumed 
consistent with the later recommendation. Again use of the best 
available data based on all available process data will avoid assuming 
the maximum possible facility emissions when no data are available. 
Facilities must document and keep records of the procedures used for 
all such estimates.

AA. Pulp and Paper Manufacturing

1. Summary of the Final Rule
    Source Category Definition. This source category consists of 
facilities that produce market pulp (i.e., stand-alone pulp 
facilities), manufacture pulp and paper (i.e., integrated mills), 
produce paper products from purchased pulp, produce secondary fiber 
from recycled paper, convert paper into paperboard products (e.g., 
containers), or operate coating and laminating processes.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Table AA-1 of this preamble lists the GHG emission 
sources at pulp and paper manufacturing facilities for which GHG 
emissions must be reported along with the rule subpart that specifies 
the calculation methodology.

                                           Table AA-1--GHGs To Report
----------------------------------------------------------------------------------------------------------------
                                 Report emissions of the listed GHGs by following the requirements of the 40 CFR
                                                         part 98, subpart indicated ...
 For pulp and paper mills ...  ---------------------------------------------------------------------------------
                                                Biogenic                                  Biogenic     Biogenic
                                     CO2           CO2           CH4           N2O          CH4          N2O
----------------------------------------------------------------------------------------------------------------
Chemical recovery furnace at    C             AA            C             C             AA           AA
 kraft and soda facilities.
Chemical recovery combustion    C             AA            C             C             AA           AA
 units at sulfite facilities.
Chemical recovery combustion    C             AA            C             C             AA           AA
 units at stand alone semi-
 chemical facilities.
Lime kilns of kraft and soda    AA/C          AA            AA/C          AA/C          AA           AA
 facilities.
Makeup chemicals used in pulp   AA            ............  ............  ............  ...........  ...........
 mills.

[[Page 56328]]

 
Stationary combustion units...  C             C             C             C             C            C
----------------------------------------------------------------------------------------------------------------
Key:
C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing).
AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and subpart C to determine default High Heating
  Values.

    GHG Emissions Calculation and Monitoring. Under 40 CFR part 98, 
subpart AA, reporters must calculate emissions from pulp and paper 
manufacturing facilities as follows:
     Chemical recovery furnaces: Calculate biogenic 
CO2 emissions from combustion of biomass in spent pulping 
liquor using:

--Measured quantities of spent liquor solids fired, site-specific high 
heating value (HHV), and default or site-specific emission factors for 
each chemical recovery furnace located at kraft or soda facilities.
--Measured quantities of spent liquor solids fired and the carbon 
content of the spent liquor solids for each chemical recovery unit at 
sulfite or stand-alone semichemical facilities.

     Calculate CO2 emissions from fossil fuels used 
in chemical recovery furnaces using direct measurement of fossil fuels 
consumed and default emission factors according to the Tier 1 
methodology for stationary combustion sources in 40 CFR part 98, 
subpart C.

 Calculate CH4 and N2O emissions as the 
sum of emissions from the combustion of fossil fuels and the combustion 
of biomass in spent pulping liquor, as follows:
--For fossil fuel emissions, use direct measurement of fuels consumed, 
a default HHV, and default emission factors according to the 
methodology for stationary combustion sources in 40 CFR 98.33(c).
--For biomass emissions, use measured quantities of spent liquor solids 
fired, site-specific HHV, and default or site-specific emission 
factors.
--Lime kilns at kraft and soda facilities.

     Lime kilns: Calculate CO2, CH4, and 
N2O emissions from combustion \21\ of fossil fuels in pulp 
mill lime kilns using direct measurement of fossil fuels consumed and 
default emission factors and HHV found in 40 CFR part 98, subparts AA 
and C, respectively.
---------------------------------------------------------------------------

    \21\ Biogenic CO2 from the conversion of 
CaCO3 to CaO in kraft or soda pulp mill lime kilns is 
accounted for in the biogenic CO2 emission factor for the 
recovery furnace.
---------------------------------------------------------------------------

     Makeup chemicals: Calculate CO2 emissions from 
the use of makeup chemicals using direct or indirect measurement of the 
quantity of chemicals added and ratios of the molecular weights of 
CO2 and the makeup chemicals.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart AA.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart AA.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart AA: Pulp and Paper 
Manufacturing.''
     Language was added to clarify that 40 CFR part 98, subpart 
AA GHG emissions are to be reported for makeup chemicals added in the 
chemical recovery areas of pulp mills (as opposed to makeup chemicals 
used at paper coating and laminating facilities).
     The frequency of measurements for the spent liquor solids 
mass fired (TAPPI Test Method T 650), heating value (TAPPI Test Method 
T 684), and carbon content (ASTM D5373-08) was reduced from monthly to 
annually.
     An option to use data from existing online solids meters 
to determine the annual mass of spent liquor solids fired is provided 
(in lieu of conducting an annual TAPPI Test Method T 650).
     The requirement to report quarterly data was eliminated.
     The reporting requirements were revised to specify units 
to standardize inputs into the data reporting system.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A number of comments on pulp and paper manufacturing were 
received covering numerous topics. Responses to significant comments 
received can be found in ``Mandatory Greenhouse Gas Reporting Rule: 
EPA's Response to Public Comments, Subpart AA: Pulp and Paper 
Manufacturing.''
Definition of Source Category
    Comment: Two commenters stated that literal interpretation of 40 
CFR part 98, subpart AA could require any facility operating paper 
coating and laminating processes to report emissions for any system 
used to add makeup chemicals. The commenters requested that language be 
added to 40 CFR part 98, subpart AA to clearly exclude facilities not 
intended to be covered and which have not traditionally been part of 
the pulp and paper source category.
    Response: Definitions of terms used in 40 CFR part 98, subpart AA 
are provided in 40 CFR 98.6 (in subpart A of part 98). The definition 
of ``makeup chemicals'' is specific to the chemical recovery areas of 
pulp mills and serves to limit the scope of the pulp and paper 
subcategory. As defined in Sec.  98.6 (emphasis added):

    ``Chemical recovery combustion unit means a combustion device, 
such as a recovery furnace or fluidized-bed reactor where spent 
pulping liquor from sulfite or semi-chemical pulping processes is 
burned to recover pulping chemicals.''
    ``Makeup chemicals means carbonate chemicals (e.g., sodium and 
calcium carbonates) that are added to the chemical recovery areas of 
chemical pulp mills to replace chemicals lost in the process.''


[[Page 56329]]


    Thus, we disagree that the rule could be interpreted to require any 
facility operating coating and laminating processes to report emissions 
for any system used to add makeup chemicals. This was not the intent of 
the rule. Nevertheless, we have added language consistent with the 
definition of ``makeup chemicals'' to 40 CFR 98.270(b)(5) and 98.272(e) 
to further clarify that GHG emissions are to be reported for systems 
adding makeup chemicals (CaCO3 and 
Na2CO3) in the chemical recovery areas of pulp 
mills.
    Comment: Commenters stated the rule should include categorical 
exemptions for emissions from the combustion of non-condensable gases 
(NCG), stripper off gases (SOG), tall oil and turpentine (small sources 
of GHG that are difficult to measure). The commenters noted that these 
streams are of biogenic origin. One commenter described safety issues 
associated with sampling these gas streams.
    Response: Pulp mill NCG, SOG, tall oil and turpentine were 
discussed in the Proposed Rule TSD for the pulp and paper manufacturing 
sector. The Proposed Rule TSD noted that process vent gases such as NCG 
and SOG and the byproducts tall oil and turpentine are derived from 
biomass. We acknowledge the safety and measurement issues described by 
commenters regarding sampling of NCG and SOG streams. No methods are 
specified in the rule for calculation of GHG associated with combustion 
of NCG, SOG, tall oil and turpentine. Thus, calculation of these 
emissions is not required and there is no need for categorical 
exemptions.
Method for Calculating GHG Emissions
    Comment: Commenters stated that monthly measurements of the mass of 
spent liquor solids, HHV, and carbon content of spent liquor solids are 
unnecessary. The commenters requested that EPA either allow default 
fuel carbon content and heating value for spent pulping liquor, or 
reduce the frequency of measurements to annually or every two years. 
Commenters noted that spent liquor HHV and carbon content are measured 
from time to time but less frequently than monthly. In addition, one 
commenter pointed out that chemical recovery furnaces often have online 
solids meters installed to provide continuous measurement of the mass 
of spent liquor solids entering the furnace for safety and process 
control reasons. This commenter requested that EPA allow use of such 
continuous measurement devices instead of requiring monthly measurement 
of the mass of spent liquor solids with TAPPI Test Method T 650.
    Response: We disagree with commenters that default fuel carbon 
content and high heating values should be allowed instead of measured 
values. These parameters are already measured by mills (though less 
frequently than monthly) and thus are available for use and more 
accurate than default values. We are reducing the frequency of fuel 
property measurements from monthly to annual. There is little monthly 
variation in fuel properties over the course of a year. Therefore, 
annual measurements are sufficient to develop site specific emission 
factors. This change also reduces the burden associated with complying 
with the rule. These changes have been incorporated throughout the text 
and equations of 40 CFR part 98, subpart AA.
    In addition, the final rule allows use of either an annual 
measurement of the mass of spent liquor solids fired (with TAPPI Test 
Method T 650) or use of annual spent liquor solids data calculated from 
continuous measurements already performed for process control purposes 
(e.g., with existing online solids meters). If the annual spent liquor 
solids fired is determined using existing measurement equipment, then 
reporters must retain records of the calculations used to determine the 
annual mass of spent liquor solids fired from the continuous 
measurements in order to demonstrate, if necessary, that calculations 
where done correctly. Reporters must also document that these 
measurement devices have been regularly and properly calibrated 
according to the manufacturer's specifications.
Data Reporting Requirements
    Comment: One commenter noted that presenting quarterly data in 
annual reports for pulp and paper manufacturing annual emissions, 
consumption of biomass fuels, and quantity of spent liquor solids fired 
is unnecessary for an annual reporting system.
    Response: We have revised 40 CFR 98.276 and 98.277(a) to remove the 
requirement for providing quarterly details in the annual report. EPA 
agrees that requiring quarterly details was not necessary for ensuring 
the accuracy of data reported annually.
    Comment: One commenter requested that the spreadsheets developed by 
the National Council for Air and Stream Improvement (NCASI) for the 
International Council of Forest and Paper Associations (ICFPA) be 
allowed as an option for facilities subject to the Rule to determine 
emissions. These spreadsheets segregate calculated GHG emissions into 
fossil fuel and biogenic categories. The commenter believes that tools 
like those developed by NCASI and others should be allowed as an option 
for facilities subject to the emission calculation requirements imposed 
by 40 CFR 98.3. This streamlined approach will provide the Agency with 
valid GHG emission data without imposing extraordinary capital and 
labor burdens on the industry.
    Response: The ICFPA/NCASI tools were considered in developing the 
requirements of the GHG reporting rule. However, the ICFPA/NCASI 
spreadsheets, though valuable tools, are not broadly applicable to all 
industrial sectors covered under the GHG reporting rule, as are the 
monitoring, reporting, recordkeeping, and emissions verification 
requirements specified in 40 CFR 98.3. Additionally, these tools often 
use default factors and estimates, which differs from the approach 
proposed by EPA. The data collected from all subparts of the GHG 
reporting rule will be tabulated in EPA's electronic reporting system. 
This system will be used to verify emission calculations and will 
require specific data be reported in order to run the calculations used 
for verification. The tools suggested by the commenter, however, would 
only provide a total emission number. Consequently, EPA would not be 
able to check the underlying calculations for accuracy. The final GHG 
reporting rule reflects the data reporting requirements necessary for 
emissions verification by EPA. Edits to the reporting and recordkeeping 
language (40 CFR 98.276 and 98.277) of 40 CFR part 98, subpart AA were 
made to clarify calculation inputs and units of measure to be reported. 
As part of the implementation phase of today's final rule, EPA intends 
to prepare guidance documents to assist the industry in complying with 
the rule's requirements. In recognition of the fact that the pulp and 
paper industry has been using the ICFPA/NCASI spreadsheets, EPA will 
consider including in the guidance materials a comparison between these 
spreadsheets and EPA's electronic reporting system to reduce the burden 
on the industry and minimize confusion.

BB. Silicon Carbide Production

1. Summary of the Final Rule
    Source Category Definition. The silicon carbide production source 
category consists of any process that produces silicon carbide for 
abrasive purposes.
    Reporters must submit annual GHG reports for facilities that meet 
the

[[Page 56330]]

applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. Report process CO2 and CH4 
emissions from all silicon carbide production furnaces or process units 
at the facility combined.
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable. For example, report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. For CO2 
emissions, reporters must use one of the following methods, as 
appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions from silicon carbide production processes by 
either (1) installing and operating CEMS and following the Tier 4 
methodology (in 40 CFR part 98, subpart C) or (2) calculating emissions 
using the measured petroleum coke consumption and a monthly facility-
specific emission factor. The facility-specific emission factor is the 
carbon content of the petroleum coke (provided monthly by the supplier 
or measured monthly using the appropriate test methods) adjusted for 
carbon in the silicon carbide product.
     However, if process CO2 emissions from silicon 
carbide production are vented through the same stack as a combustion 
unit or process equipment that uses a CEMS and follows Tier 4 
methodology to report process CO2 emissions, then the CEMS 
must be used to measure and report combined CO2 emissions 
from that stack. In such cases, the reporter cannot use the 
CO2 calculation approach (2) outlined in the above bullet.
    For CH4 emissions, reporters must use the measured 
petroleum coke consumption and a default emission factor of 10.2 
kilograms (kg) per metric ton of coke consumed.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart BB.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart BB.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart BB: Silicon Carbide Production.''
     The emissions calculation method under 40 CFR 98.283(b) 
was revised to require data on monthly petroleum coke consumption and 
monthly petroleum coke carbon contents rather than quarterly 
determinations.
     Missing data procedures were added under 40 CFR 98.285 for 
monthly parameters used to calculate emissions, including mass of 
petroleum coke, and carbon contents of petroleum coke.
     40 CFR 98.286 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.287 to 40 CFR 98.286, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.283 were 
added to 40 CFR 98.286 for clarity.
3. Summary of Comments and Responses
    No specific comments were received pertaining to the proposed 
reporting requirements for silicon carbide production facilities. 
However, the proposed rule did not clearly specify how quarterly carbon 
contents should be determined. This determination should be made on a 
monthly basis as proposed for other chemical production processes where 
process emissions arise from use of petroleum coke, such as titanium 
dioxide production. Quarterly reporting of carbon contents of petroleum 
coke consumed for the quarter would have to be averaged from monthly 
data. For verification, EPA would require reporting of the monthly 
carbon contents of the petroleum coke. Therefore, we revised the 
emissions calculation method to directly require monthly petroleum coke 
consumption and monthly petroleum coke contents, rather than quarterly 
based on an arithmetic average of the monthly estimates to improve 
accuracy of emissions calculations. We have retained the flexibility in 
use of supplier data to determine carbon contents. We understand that 
most supplier data on carbon contents of petroleum coke is readily 
available and that businesses track production inputs and outputs on a 
monthly basis as a part of normal business practice or existing 
accounting procedures. The increased frequency of data collection from 
quarterly to monthly provides greater clarity and accuracy without 
significantly increasing burden. In addition, see the Section II.N of 
this preamble for an explanation of the emissions verification 
approach.

CC. Soda Ash Manufacturing

1. Summary of the Final Rule
    Source Category Definition. A soda ash manufacturing facility is 
any facility with a manufacturing line that produces soda ash by 
either: calcining trona or sodium sesquicarbonate; or by using a liquid 
alkaline feedstock process that directly produces CO2. In 
the context of the soda ash manufacturing sector, ``calcining'' means 
the thermal/chemical conversion of the bicarbonate fraction of the 
feedstock to sodium carbonate.
    Soda ash produced from a liquid alkaline feedstock using sodium 
hydroxide does not emit process CO2 and therefore is not 
subject to the requirements of Subpart CC. However, such facilities may 
be covered under Subpart C (General Stationary Combustion) if they meet 
the requirements of either Sec.  98.2(a)(1) or (2).
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For soda ash manufacturing, report the following 
emissions:
     CO2 process emissions from soda ash 
manufacturing, reported for each manufacturing line.
     CO2 combustion emissions from each soda ash 
manufacturing line.
     N2O and CH4 emissions from fuel 
combustion at each soda ash manufacturing line under 40 CFR part 98, 
subpart C (General Stationary Fuel Combustion Sources) using the 
methodologies in subpart C.
     CO2, N2O, and CH4 
emissions from each stationary combustion unit other than soda ash 
manufacturing lines under 40 CFR part 98, subpart C (General Stationary 
Fuel Combustion Sources).
    In addition, report GHG emissions for any other source categories 
at the facility for which calculation methods are provided in other 
subparts of the rule, as applicable.
    GHG Emissions Calculation and Monitoring. For CO2 
emissions from soda ash manufacturing lines, reporters must select one 
of the following methods, as appropriate:

[[Page 56331]]

     For each soda ash manufacturing line with certain types of 
CEMS in place, reporters must use the CEMS and follow the Tier 4 
methodology (in 40 CFR part 98, subpart C) to report under the Soda Ash 
Manufacturing subpart (40 CFR part 98, subpart CC) combined process and 
combustion CO2 emissions.
     For other soda ash manufacturing lines, reporters can 
elect to either (1) install and operate a CEMS and follow Tier 4 
methodology to measure and report combined process and combustion 
CO2 emissions or (2) calculate CO2 process 
emissions using the procedures specified in 40 CFR part 98, subpart CC 
and summarized below.
     If using approach 2, calculate process CO2 
emissions using one of three alternative methods, as appropriate for 
each manufacturing line:

--The trona input method calculates the calcination emissions using: 
Monthly mass of trona input (required to be measured), the average 
monthly mass-fraction of inorganic carbon in the trona (required to be 
measured weekly), and the ratio of CO2 emitted for each ton 
of trona consumed (a default value is provided).
--The soda ash output method calculates the calcination emissions 
using: Monthly mass of soda ash produced (required to be measured), the 
monthly average mass-fraction of inorganic carbon in the soda ash 
(required to be measured weekly), and the ratio of CO2 
emitted for each ton of soda ash produced (a default value is 
provided).
--The site-specific emission factor method calculates emissions from 
production of soda ash using liquid alkaline feedstock through an 
annual performance test using: The average process vent flow rate from 
the mine water stripper/evaporator for each manufacturing line, direct 
measurements of hourly CO2 concentration, the hourly stack 
gas volumetric flow rate, the annual process vent flow rate from mine 
water stripper/evaporator, and annual operating hours.
--Report process CO2 emissions from each soda ash 
manufacturing line under 40 CFR part 98, subpart CC (Soda Ash 
Manufacturing), and report combustion CO2 emissions from 
each calciner (kiln) in each manufacturing line under 40 CFR part 98, 
subpart C (General Stationary Fuel Combustion Sources).

    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart CC.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart CC.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart CC: Soda Ash Manufacturing.''
     A site-specific emission factor method has been added for 
production of soda ash using liquid alkaline feedstock or mine water. 
This method was not included in the proposed rule.
     The frequency of inorganic carbon content determination of 
either trona or soda ash has been revised from daily to monthly based 
on a weekly composite.
     Procedures were added to 40 CFR 98.295 for estimating 
missing data for monthly values of inorganic carbon content of trona 
and monthly values of trona consumption or soda ash production. We also 
added missing data procedures for parameters specific to calculating 
emissions from soda ash produced from liquid alkaline feedstock (i.e. 
site-specific emission factor method).
     40 CFR 98.296 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.297 to 40 CFR 98.296, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.293 were 
added to 40 CFR 98.296 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. Two sets of comments on soda ash manufacturing were received 
covering several topics. Responses to significant comments received can 
be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart CC: Soda Ash Manufacturing.''
Method for Calculating GHG Emissions
    Comment: Both commenters noted that facilities produced soda ash 
using alternative methods to calcining trona or other carbonate 
containing minerals. Facilities also produce soda ash from mine water, 
a liquid alkaline feedstock; this is a ``process'' emissive production 
process, but was not addressed in the proposal. The methods in the 
proposal did not include methods appropriate for calculating process 
CO2 from the liquid alkaline feedstock production process. 
One commenter using this production method recommended that the 
appropriate method for calculating emissions from this process would be 
an annual performance test and described the appropriate parameters 
that would be measured during the annual performance test to establish 
an emission factor for calculating annual emissions based on 
concentration of the CO2 in the evaporated stripped mine 
water and the annual flow from the mine water stripper/evaporator.
    Response: We agree that the final rule should address process 
CO2 emissions generated from this relatively new alternative 
production process which produces soda ash from liquid alkaline 
feedstock or mine water. From additional information provided by the 
commenter, process CO2 emissions from this production method 
are likely to be significant and exceed 25,000 metric tons 
CO2e. This process is currently used by a single company, 
but could become more widespread within the industry in the future as 
it makes more efficient use of raw materials previously not used. We 
have updated all sections of 40 CFR part 98, subpart CC for 
calculating, monitoring and QA/QC, and reporting of process 
CO2 emissions specific to production of soda ash from liquid 
alkaline feedstock or minewater. We added procedures for developing 
site-specific emission factor based on an annual performance test 
consistent with the recommendations provided by the commenter.
    Comment: One commenter noted that using the total alkalinity of 
either trona or soda ash as prescribed in Equations CC-2 and CC-3 is 
inappropriate given that the ratio of carbon dioxide to carbon is a 
factor in the equations. The equations' results artificially inflated 
the CO2 level by 3.67 times the actual amount.
    Response: Upon further review, we agree with the commenter's 
analysis that the ratio 44/12 will overestimate emissions and have 
removed this fraction, which is the ratio of carbon dioxide to carbon, 
from Equations CC-2 and CC-3. Equations CC-2 and CC-3

[[Page 56332]]

provide results directly for CO2 therefore it is not 
necessary to use a conversion factor to convert the carbon to carbon 
dioxide.
    Comment: One commenter noted that Equation CC-3 does not address 
plant inefficiency specific to each manufacturing line. The commenter 
suggested that an efficiency factor should be added to Equations CC-3 
to account for these inefficiencies.
    Response: The commenter has not suggested an efficiency factor or 
otherwise provided data with enough specificity to modify the equations 
and modify the calculation methods as suggested; therefore, we have 
decided not to add efficiency factors to Equations CC-3.
    EPA needs more information to effectively evaluate this comment and 
update the equations noted, if appropriate. Efficiency factors can 
relate to a number of factors including combustion and also kiln 
conditions, which may vary. We need more information to understand how 
this factor would be derived for each kiln or manufacturing line. The 
comment was specific to CC-3, and we suggest the use of Equation CC-2 
as an alternative calculation method.
Monitoring and QA/QC Requirements
    Comment: One commenter stated that daily sampling of inorganic 
carbon content of each manufacturing line is an unnecessary and 
potentially extremely costly requirement. They suggested that instead 
of daily testing, testing should be completed as a weekly composite 
analysis which would then be used in calculating the monthly average.
    Response: We concur that testing of the inorganic carbon content 
can be done on a weekly schedule and used to calculate a monthly 
composite without significant loss in accuracy. The weekly composite 
would still be based on several daily tests. We have updated the 
monitoring and QA/QC requirements accordingly in the rule under 40 CFR 
98.294.
    Comment: One commenter stated that the prescribed ASTM method, ASTM 
E359-00(2005), for determining the inorganic carbon content of trona or 
soda ash describes a manual titration method using a methyl orange 
endpoint. They stated that procedures that use autotitrators with fixed 
endpoint titration are commonly used in the soda ash manufacturing 
industry and should be allowed as an acceptable equivalent alternative.
    Response: We agree that methods using autotitration to determine 
inorganic carbon content of trona or soda ash expressed as total 
alkalinity are acceptable equivalent methods for determining the 
inorganic carbon content of trona or soda ash. We understand that 
manual titration offers good levels of accuracy but are labor and time 
intensive. From our understanding, autotitration methods provide 
comparable or improved levels of accuracy and are less labor and time 
intensive by ``automating'' the analysis process. Autotitration methods 
could provide more consistency in results across the industry. We have 
updated the procedures in 40 CFR 98.294 for monitoring and QA/QC in the 
rule to allow for such comparable methods.

DD. Sulfur Hexafluoride (SF6) From Electrical Equipment

    At this time EPA is not going final with the electrical equipment 
subpart. As we consider next steps, we will be reviewing the public 
comments and the relevant information.
    Based on careful review of comments received on the preamble, rule, 
and TSDs under 40 CFR part 98, subpart DD, EPA will perform additional 
analysis and evaluate a range of data collection procedures and 
methodologies. EPA's goal is to optimize methods of data collection to 
ensure data accuracy while considering industry burden. In addition, 
EPA will further evaluate the scope of coverage of electric power 
systems and the reporting boundaries in other subparts.

EE. Titanium Dioxide Production

1. Summary of the Final Rule
    Source Category Definition. The titanium dioxide production source 
category consists of any facility that uses the chloride process to 
produce titanium dioxide.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For titanium dioxide production, report 
CO2 process emissions from each chloride process line.
    In addition, report GHG emissions for other source categories for 
which calculation methods are provided in the rule, as applicable. For 
example, facilities must report CO2, N2O, and 
CH4 emissions from each stationary combustion unit on site 
under 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).
    GHG Emissions Calculation and Monitoring. Reporters must calculate 
CO2 process emissions using one of two methods, as 
appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions from titanium dioxide process lines by either 
(1) installing and operating CEMS and following the Tier 4 methodology 
(in 40 CFR part 98, subpart C) or (2) using the calculation procedures 
specified below.
     However, if process CO2 emissions from titanium 
dioxide production are emitted through the same stack as a combustion 
unit or process equipment that uses a CEMS and follows Tier 4 
methodology to report CO2 emissions, then the reporter must 
use the CEMS to measure and report combined CO2 emissions 
from that stack instead of using the calculation procedures described 
below.
     If using approach 2, calculate the process 
CO2 emissions using the equation provided 40 CFR part 98, 
subpart EE and monthly determination of the mass and carbon content of 
calcined petroleum coke consumed in each line and all lines combined. 
Determine petroleum coke consumption by either direct measurement or 
purchase records. Determine carbon content of petroleum coke using 
supplier data or measurement using appropriate test methods. If 
applicable, also determine the quantity of carbon containing waste 
generated and its carbon contents using direct measurement.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart EE.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart EE.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart EE: Titanium Dioxide Production.''
     Requirements were added for reporting of carbon-containing 
waste generated from less than 100 percent oxidation of coke during the 
titanium production process. 40 CFR 98.316

[[Page 56333]]

allows for reporting of quantity of carbon-containing waste generated 
and associated carbon contents.
     Missing data procedures were added under 40 CFR 98.315 for 
monthly parameters used to calculate emissions, including mass of 
calcined petroleum coke, mass of carbon-containing waste, and carbon 
contents of calcined petroleum coke.
     40 CFR 98.316 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.317 to 40 CFR 98.316, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.313 were 
added to 40 CFR 98.316 for clarity.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. We received three sets of comments on titanium dioxide 
production covering several topics. Several of these comments were 
directed at the requirements for General Stationary Fuel Combustion 
Sources in subpart C, and responses to those comments are provided in 
the preamble section dealing with that source category. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subpart EE: 
Titanium Dioxide Production.''
Method for Calculating GHG Emissions
    Comment: One commenter noted that the carbon oxidation factor for 
calcined petroleum coke is not always 100 percent. They point out that 
the calcined petroleum coke comes with impurities, and a certain amount 
of the calcined coke is returned to the ground as landfill along with 
components such as the un-converted TiO2. Thus, they suggest 
that EPA should revise the carbon oxidation factor to allow facilities 
to use the most appropriate factor for their process, with supporting 
documentation of its derivation available for EPA review as needed.
    Response: EPA has considered the comment but maintains the 
assumption of 100 percent oxidation across all sectors in the final 
rule. Data reporting requirements have been added to 40 CFR 98.316 to 
collect information on the quantity of carbon-containing waste 
generated that is landfilled and its carbon contents which are not 
emitted. This information will help inform future methods for 
calculating process emissions from titanium dioxide production (e.g., 
how to address oxidation rates). EPA interpreted that this comment may 
also be applicable to carbon content of calcined petroleum coke. EPA 
agrees that carbon content may not always be 100 percent and therefore 
has revised the rule to allow facilities to use supplier data or 
determine carbon contents using appropriate test methods as part of 
calculating emissions in 40 CFR 98.313.
Procedures for Estimating Missing Data
    Comment: Two commenters noted there can be numerous reasons data 
may not be available, on time, or in the format EPA requires. In cases 
where a required record is found to be missing or determined to be 
incorrect, the commenters requested that EPA should provide a procedure 
for estimating missing data.
    Response: We concur that there may be circumstances where data on 
carbon contents of coke and petroleum coke consumption may be missing. 
Records could be misplaced or lost. Thus, we have revised the rule and 
added specific procedures for estimating missing data in 40 CFR 98.315. 
These procedures are consistent with those allowed across the rule for 
similar parameters. For example, if a facility is missing data on 
carbon contents of petroleum coke we allow facilities to allow sources 
to substitute the missing data with another quality assured parameter, 
such as the arithmetic average of the carbon contents from the month 
immediately preceding and the month immediately following the missing 
data incident.
Data Reporting Requirements
    Comment: All commenters noted they are concerned that the level of 
information to be reported, which is considered available for public 
distribution, could put the domestic TiO2 producers at a 
disadvantage relative to international producers. The commenters do not 
believe that CBI provisions briefly outlined in the preamble are 
adequate to safeguard the proprietary technical and financial positions 
of titanium dioxide production facilities. The annual production of 
titanium dioxide, annual amount of petroleum coke consumed, and annual 
operating hours are considered CBI and are unnecessary to carry out the 
purposes of this proposed regulation. This data should only be 
available onsite or offsite (e.g., a centralized location), or as 
requested for security cleared EPA personnel and their security cleared 
contractors where a need is demonstrated for the purposes of this 
inventory.
    Response: EPA reviewed CBI comments received across the rule (both 
general and subpart-specific comments) and our response is discussed in 
Section II.R of this preamble and in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Legal Issues.''
    In addition, see the Section II.N of this preamble for the response 
on the emissions verification approach. The amount of petroleum coke 
consumed is necessary to calculate annual process CO2 
emissions. Production capacity and annual production of titanium 
dioxide are required for EPA to verify annual CO2 process 
emissions. These parameters help EPA to determine whether reported 
emissions are within a reasonable range. EPA concurs that data on 
operating hours can be retained as a record and does not need to be 
reported to EPA. It is not a parameter used in calculating process 
CO2 emissions. However, operating hours would help to verify 
any anomalies in reported emissions or supporting parameters related to 
temporary closures for repairs or maintenance. This data has been moved 
to recordkeeping requirements in 40 CFR 98.317.

FF. Underground Coal Mines

    At this time, EPA is not finalizing the Underground Coal Mines 
Subpart (40 CFR part 98, subpart FF). As EPA considers next steps, we 
will be reviewing the public comments on the proposal preamble, rule 
and TSDs for proposed 40 CFR 98 Subpart FF and other relevant 
information. EPA will perform additional analysis and consider 
alternatives to the monitoring requirements.

GG. Zinc Production

1. Summary of the Final Rule
    Source Category Definition. Zinc production facilities consist of 
zinc smelters and secondary zinc recycling facilities.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For zinc production, report the following:
     CO2 process emissions from each Waelz kiln and 
electrothermic furnace used for zinc production.
     CO2, N2O, and CH4 
combustion emissions from each Waelz kiln and each other stationary 
combustion unit on site under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources).
    In addition, report GHG emissions for other source categories at 
the facility for which calculation methods are provided in the rule, as 
applicable.

[[Page 56334]]

    GHG Emissions Calculation and Monitoring. Facilities must calculate 
CO2 process emissions using one of two methods, as 
appropriate:
     Most reporters can elect to calculate and report process 
CO2 emissions from each Waelz kiln and electrothermic 
furnace by either (1) installing and operating CEMS and following the 
Tier 4 methodology (in 40 CFR part 98, subpart C) or (2) using the 
calculation procedures specified in the rule.
     However, if process CO2 emissions from a Waelz 
kiln or electrothermic furnace are emitted through the same stack as a 
combustion unit or process equipment that uses a CEMS and follows Tier 
4 methodology to report CO2 emissions, then the CEMS must be 
used to measure and report combined CO2 emissions from that 
stack, instead of the calculation procedure described below.
     If using approach 2, calculate process 
CO2 emissions by determining on an annual basis the total 
mass (metric tons) of carbon-containing input materials (i.e., zinc-
bearing material, flux, electrodes, and any other carbonaceous 
materials) introduced into each kiln and furnace and the carbon content 
of each material. Determine carbon content annually either by using 
supplier data, or by direct measurement using appropriate test methods.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart GG.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart GG.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these changes can be found below.
     The carbon input method was revised to require an annual 
analysis of all process inputs and outputs for carbon content rather 
than monthly sampling and monthly analysis.
     A de minimis was added to exclude accounting for carbon-
containing materials contributing less than one percent of the total 
carbon into Waelz kiln or electrothermic furnaces. These materials do 
not need to be included in carbon mass balance calculations.
     40 CFR 98.336 was reorganized and updated to improve the 
emissions verification process. Some data elements were moved from 40 
CFR 98.337 to 40 CFR 98.336, and some data elements that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.333 were 
added to 40 CFR 98.336 for clarity.
3. Summary of Comments and Responses
    No comments specific to regulation of the zinc production sector 
were received. We revised the frequency of sampling and analysis of 
carbon contents for carbon containing input materials from monthly to 
annual consistent with revisions made in response to comments for 
similar production processes (e.g., emissions from metal production, 
see the preamble Section III.Q for iron and steel for specific 
responses to comments). These revisions reduce the reporting burden for 
zinc production facilities. We understand that the carbon content of 
material inputs does not vary widely at a given facility for the 
significant process inputs that contain carbon, and we continue to 
account for variations due to changes in production rate, which is 
likely a more significant source of variability.

HH. Municipal Solid Waste Landfills

1. Summary of the Final Rule
    Source Category Definition. This source category consists of 
municipal solid waste (MSW) landfills that accepted waste on or after 
January 1, 1980. The source category includes the MSW landfill, 
landfill gas collection systems, and landfill gas destruction devices 
(including flares) at the landfill.
    This source category does not include hazardous waste, construction 
and demolition, or industrial landfills.
    Reporters must submit annual GHG reports for facilities that meet 
the applicability criteria in the General Provisions (40 CFR 98.2) 
summarized in Section II.A of this preamble.
    GHGs to Report. For MSW landfills, report the following:
     Annual CH4 generation and CH4 
emissions from the landfill.
     Annual CH4 destruction (for landfills with gas 
collection and control systems).
     Annual CO2, CH4, and N2O 
emissions from stationary fuel combustion devices under 40 CFR part 98, 
subpart C (General Stationary Combustion Sources).
    GHG Emissions Calculation and Monitoring. All facilities must 
calculate modeled annual CH4 generation based on:
     Measured or estimated values of historic annual waste 
disposal quantities; and
     Appropriate values for model inputs (i.e., degradable 
organic carbon fraction in the waste, CH4 generation rate 
constant). Default parameter values are specified for bulk municipal 
waste and individual waste categories.
    Facilities that do not collect and destroy landfill gas must adjust 
the modeled annual CH4 generation to account for soil 
oxidation (CH4 that is converted to CO2 as it 
passes through the landfill cover before being emitted) using a default 
soil oxidation factor. The resulting value must be reported and 
represents both CH4 generation and CH4 emissions.
    Facilities that collect and control landfill gas must calculate the 
annual quantity of CH4 recovered and destroyed based on 
either continuous or weekly monitoring of landfill gas flow rate, 
CH4 concentration, temperature, and pressure of the 
collected gas prior to the destruction device.
    Those facilities that collect and control landfill gas must then 
calculate CH4 emissions in two ways and report both results. 
Emissions must be calculated by:
    1. Subtracting the measured amount of CH4 recovered from 
the modeled annual CH4 generation (with adjustments for soil 
oxidation using the default value and destruction efficiency of the 
destruction device) using the equations provided; and
    2. Applying a gas collection efficiency to the measured amount of 
CH4 recovered to calculate CH4 generation, then 
subtracting the measured amount of CH4 recovered (with 
adjustments for soil oxidation using the default value and destruction 
efficiency of the destruction device) using the equations provided. 
Default collection efficiencies are specified, based on cover material 
and other factors.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart HH.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and

[[Page 56335]]

summarized in Section II.A of this preamble, reporters must keep 
records of additional data used to calculate GHG emissions. A list of 
specific records that must be retained for this source category is 
included in 40 CFR part 98, subpart HH.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
founds below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart HH: Landfills.''
     Industrial landfills were removed from the applicability 
provisions of 40 CFR part 98, subpart HH. The applicability provisions 
were also modified to exempt landfills that did not accept any waste 
after January 1, 1980.
     Additional methods for estimating quantities of waste for 
prior (historic) years are provided.
     The requirement to continuously monitor CH4 
composition in the flare gas was removed. If a continuous monitoring 
system is in place, that data must be used, but weekly sampling of the 
gas is allowed if such a continuous system is not in place.
     Direct flame ionization methods were added to the rule as 
an alternative to the gas chromatographic methods for determining 
methane concentrations. To use a direct flame ionization method, a 
correction factor must be determined at least once each reporting year 
and applied to adjust the analyzer's total gaseous organic 
concentration to an unbiased methane concentration.
     More detailed default values are provided for landfill gas 
collection efficiencies based on cover material and other factors.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on landfills were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart HH: Landfills.''
Definition of Source Category
    Comment: Several commenters stated that EPA should limit the 
applicability of the industrial landfills to landfills located at food 
processing, pulp and paper, and ethanol production facilities (some 
also listed petroleum refineries) because these are the only industries 
for which landfills were specifically called out. Several commenters 
noted that impacts were only estimated for pulp and paper and food 
processing landfills, so EPA should limit the rule to those industries 
or correct the cost analysis to reflect the true burden of the rule on 
industrial landfills. Several commenters noted that the reporting 
requirements seemed tailored for MSW landfills and were generally 
inappropriate for industrial landfills (truck scales, etc.). One 
commenter also noted that, if reporting of GHG emissions from 
industrial landfills is not limited to the food processing, pulp and 
paper, and ethanol production facilities, then EPA should amend Table 
HH-1 of 40 CFR part 98, subpart HH and provide specific factors that 
are relevant to the regulated industry. Several commenters requested 
that EPA specifically exempt inorganic chemical manufacturing and 
mining landfills because they do not contain organic waste; other 
commenters suggested EPA delete requirements for landfills in 40 CFR 
part 98, subpart Y because landfills are insignificant compared to 
other sources at a petroleum refinery.
    On the other hand, one commenter suggested that EPA may be 
overlooking an important source of methane emissions by excluding 
construction and demolition landfills as it seems possible that these 
landfills receive organic materials such as wood or yard waste that 
could degrade in an anaerobic environment. This commenter requested EPA 
provide information on the waste composition of construction and 
demolition landfills to explain more fully the basis for its decision 
to categorically exempt these sources from GHG reporting requirements.
    Response: At this time, EPA is not going final with the industrial 
landfills proposed requirements of this subpart. In response to the 
proposal, EPA received numerous detailed public comments on the 
preamble, rule and TSDs under 40 CFR part 98, subpart HH. Comments 
addressed the appropriateness, coverage, and methodology for addressing 
GHG emissions from industrial landfills. In particular, commenters 
questioned which industrial landfills should be covered by the rule and 
the need for industry specific factors and methodologies for 
calculating and reporting emissions. As EPA considers next steps, we 
will be reviewing the comments and other relevant information and will 
perform additional analysis and consider alternatives to the proposed 
monitoring and reporting requirements for industrial landfills.
    With regard to construction and demolition landfills, we note that 
the IPCC 2006 Guidelines for National Greenhouse Gas Inventories 
estimates that construction and demolition waste has a degradable 
organic content (DOC) of 0.04 kg/kg waste (see Table 2.5 in Volume 5: 
Waste), and most of this organic matter is expected to be wood, with 
slow degradation rates (k=0.02 yr-1). Based on the 
anticipated properties of construction and demolition wastes, we 
anticipated that methane generation at dedicated construction and 
demolition debris landfills would be small compared to MSW landfills. 
We will further review these assumptions as we review comments on 
industrial landfills.
    Comment: Several commenters stated that the reporting requirements 
for closed landfills are burdensome, and the rule should be limited to 
reporting for active landfills. Information on waste disposal 
quantities and waste composition data are usually not available for 
closed MSW facilities. Thus, it is impossible to retain or provide the 
agency with such records for many old landfill sites. Several 
commenters suggested that EPA should provide additional guidance and 
screening tools to identify landfills likely to be below the threshold. 
The commenters noted that small and closed landfills have to collect 
all of the data needed to report their emissions in order to determine 
if they are above the reporting threshold.
    Response: Closed MSW landfills account for approximately half of 
the nationwide methane emissions from MSW landfills. This is because 
landfills can continue to emit for decades after they are closed and 
because these landfills are older, and less likely to have been 
required to add landfill gas collection systems. However, we do agree 
that we can remove reporting requirements for a subset of closed 
landfills to lessen the burden on long-closed landfill facilities. We 
evaluated the various landfill characteristics and identified that a 
30-year waste-in-place (i.e., the total quantity of waste added to the 
landfill in the past 30 years) provided the best correlation of the 
data to sites that account for the majority of the contribution to the 
nationwide GHG emissions from landfills (see memorandum entitled 
``Correlations with Landfill Methane Generation and Actual Emissions'' 
in the docket EPA-HQ-OAR-2008-0508-2165). Providing an applicability 
date for closed landfills is essential to minimize the burden 
associated with obtaining data on old landfills that provide only a 
small contribution to the nationwide GHG

[[Page 56336]]

emissions for landfills, and landfills closed prior to 1980 would not 
be relevant for the purposes of policy analyses. Therefore, the final 
rule excludes MSW landfills that have not accepted waste since January 
1, 1980. We have also expanded and clarified options for projecting 
waste disposal quantities that will help ease the burden associated 
with calculating emissions from landfills that have closed after 1980. 
EPA remains committed to providing additional outreach materials, 
guidelines, and screening tools to help potential reporters determine 
whether the reporting rule applies to their landfill.
Method for Calculating GHG Emissions
    Comment: Several commenters requested additional guidance on how to 
determine waste disposal rates for years prior to the first reporting 
year. One commenter noted that the population method provided in the 
rule was difficult for many landfills because of contract carriers that 
may haul waste to different landfills in different years, so that the 
population served by a landfill can be variable. Several commenters 
noted that the data needed to estimate waste disposal rates for past 
years was especially challenging for closed landfills and requested 
guidance on how to comply with the rule if the necessary data do not 
exist.
    Response: EPA acknowledges that the single proposed method of 
estimating past year disposal rates is limiting and may not provide the 
most accurate projection of waste disposal rates in all cases. We have 
provided a number of alternative approaches that could be used to 
estimate annual waste acceptance rates. These include using the current 
year's annual waste acceptance rate for all past years of operation 
(for active landfills) and using the landfill capacity and the 
operating life of the landfill to calculate an average annual 
acceptance rate (for active and closed landfills). These methods 
provide a reasonable estimate of historic disposal quantities based on 
readily available information, even for older landfills. Furthermore, 
these alternative methods may be just as appropriate or more 
appropriate for MSW landfills that do not serve a fixed population 
area.
    Comment: A few commenters noted that the Solid Waste Industry for 
Climate Solution (SWICS) has developed protocols for calculating GHG 
emissions from landfills [see paper titled, Current MSW Industry 
Position and State-of-the-Practice on LFG Collection Efficiency, 
Methane Oxidation, and Carbon Sequestration in Landfills (July 2007)]. 
The commenters requested that the SWICS recommended defaults for gas 
recovery system efficiency, soil oxidation, and flare combustion 
efficiency be provided in the rule. They also stated that an accurate 
inventory should account for carbon sequestered in the landfill.
    Response: We again reviewed the SWICS methods in light of these 
comments. We agree that the SWICS default recommendations for gas 
recovery system efficiency (which vary from 60 to 95 percent for 
different types of soil covers) could provide more refined data than 
using the default values provided in the rule. Therefore, we have 
included these cover-specific gas recovery efficiencies (commensurate 
with the SWICS Protocol) as an alternative to the 75 percent default 
value for collection efficiency. We have also reviewed the SWICS 
protocol for soil oxidation, which provides suggested oxidation factors 
ranging from 0.22 to 0.55 depending on the soil cover type. We have 
several concerns with these factors. First, the values were calculated 
using arithmetic means which appear to be biased high due to a few high 
oxidation factors; the median values were generally significantly lower 
than the average values suggested. Second, the recommended values 
included laboratory test values, which always yielded higher oxidation 
fractions. The percent of methane oxidized at the landfill surface is 
highly dependent on the velocity of gas flow. While areas of low flow 
are expected to have significant oxidation, areas of high flow will 
have little to no oxidation. Landfill gas will generally flow to the 
surface in fissures and channels that offer the least resistance to 
flow. Consequently, a significant portion of the landfill gas is likely 
to exit the landfill in a limited number of areas under much higher 
flow rates than other locations. These high volume flows will not have 
significant oxidation. Consequently, field test data tend to show lower 
oxidation factors than laboratory tests where flow is more uniform. 
Data for five field studies for clay covers (the predominant soil cover 
type used in the U.S.) were included in the SWICS report. Four of the 
five field studies had oxidation factors ranging from 0.08 to 0.21, and 
the median of all five field studies was 0.14. These data appear to 
support the default 0.10 oxidation factor as provided in the final rule 
more than they do the 0.22 oxidation factor suggested by SWICS. We will 
continue to assess the available data to improve soil oxidation 
estimates; however, we maintain that the use of the 10 percent default 
rate is appropriate for this final rule, and clarify that the site-
specific oxidation factors (based on the SWICS method or other method) 
are not to be used. We also find that the SWICS Protocol recommended 
flare efficiency of 99.996 percent appears unreasonably high. The 
combustion efficiency of flares is very difficult to assess and may be 
affected by wind speed and other variables that are not under the 
direct control of the landfill owner and operator. Consequently, we 
retained the proposed flare efficiency default. Finally, with respect 
to the suggested sequestration factors, since collecting data on carbon 
sequestration is not the purpose of this rule, we do not require 
facilities to calculate or report carbon storage in landfills.
Monitoring and QA/QC Requirements
    Comment: Several commenters stated that EPA's proposal to require 
landfills with gas collection systems to continuously measure the 
methane flow and concentration at the flare or energy device is 
financially burdensome. According to commenters, the capital costs as 
well as operation and maintenance costs of a continuous composition 
analyzer are prohibitive for many facilities, and EPA underestimated 
the number of facilities that would have to install the required 
monitors. The commenters also stated that the composition of landfill 
gas is not highly variable, so less frequent monitoring is justified. 
One commenter noted that the standard operating procedure at many 
landfills with gas collection systems is to collect monthly 
CH4, flow, and concentration data at the flare. Another 
commenter recommended that MSW landfills be allowed to calculate 
quarterly, by means of engineering formulae and/or modeling, the amount 
of methane present at the flare or energy device. The commenter further 
noted that, in many cases, it is not practical or even possible for the 
MSW facility to measure the amount of methane or even landfill gas at 
the energy device because this device is not owned, operated, or 
controlled by the facility. Several commenters also requested that EPA 
allow direct flame ionization analyzers in addition to the gas 
chromatography methods provided in the proposed rule.
    On the other hand, several commenters suggested that EPA should 
allow, require, or otherwise move towards direct measurement 
methodologies for characterizing landfill emissions.
    Response: Methane composition of landfill gas can be expected to 
vary

[[Page 56337]]

based on extreme barometric changes, rainfall event, etc. We expect 
diurnal variations as well (although not to the same extent as seasonal 
variations). We also expect variations if the gas collection system has 
a variable speed fan and the fan speed is adjusted. The commenters 
provided no data to support the claim that the anticipated fluctuations 
are not significant enough to warrant continuous monitoring. At 
proposal, we required continuous flow and composition monitors to 
improve the accuracy of the emissions estimate. However, after 
additional uncertainty analysis, we determined that the cost of 
continuous monitoring systems is not justified in relation to the 
relatively small improvement in certainty over somewhat less frequent 
monitoring, i.e. weekly. We do require landfill gas collection systems 
already equipped with continuous monitoring systems to determine daily 
average flow and concentrations and to use these data in their gas 
recovery calculations. For collection systems that do not have 
continuous gas monitors, weekly sampling is required. Weekly monitoring 
provides an adequate number of samples to evaluate the variability and 
uncertainty associated with methane generation. We did not select 
monthly monitoring because monthly monitoring would result in greater 
uncertainty and would not significantly reduce the costs compared to 
weekly monitoring.
    We did provide for direct flame ionization analyzers to be used as 
an alternative to the gas chromatography methods provided in the 
proposed rule. This alternative reduces the burden on landfills that do 
not have existing gas chromatography equipment. However, direct flame 
ionization analyzers will measure both methane and non-methane organic 
compounds and, as such, will tend to overstate the methane 
concentration in the landfill gas and provide a high bias to the amount 
of methane recovered. To eliminate this bias, we also required a 
correction factor that must be determined at least annually, to arrive 
at the ratio of the methane concentration to the direct flame 
ionization analyzer response (calibrated with methane). Including this 
alternative method with the correction factor reduces the burden on 
landfills, but still ensures that the calculated methane recovery 
quantities are unbiased and comparable to the recovery quantities 
calculated when gas chromatographic methods are used to speciate 
methane specifically.
    With respect to direct measurement methods, we find that direct 
soil measurements have high uncertainties due to heterogeneity of the 
landfill and cover soils and are, therefore, less desirable than the 
methods provided in the rule (cost more and have higher uncertainty). 
Optical sensing methods, while potentially more accurate, are very 
expensive. If measurements were done for only a one-time performance 
test, the measured emissions would have rather high uncertainties due 
to variations in temperature and atmospheric pressure. If the 
measurements were conducted more often, they would be prohibitively 
expensive. At this time, we cannot justify requiring these types of 
monitoring systems for this rule. Furthermore, we find that the 
monitoring requirements in the final rule provide for accurate emission 
estimates at a reasonable cost burden to reporters.

II. Wastewater Treatment

    At this time, EPA is not going final with the wastewater treatment 
subpart (40 CFR part 98, subpart II). As EPA considers next steps, we 
will be reviewing the public comments and other relevant information. 
Please note, as originally proposed for this rule, centralized domestic 
wastewater treatment plants continue to be excluded.
    The Agency received a number of comments regarding the 
applicability of this subpart as well as clarification of the 
definition of anaerobic wastewater treatment processes. In addition, 
commenters requested that EPA consider a de minimus exemption for 
emissions from wastewater treatment. The Agency also received a number 
of comments requesting redefinition of the monitoring requirements for 
this subpart.
    Based on careful review of comments received on the preamble, rule 
and TSDs under proposed 40 CFR part 98, subpart II, EPA will consider 
alternatives to data collection procedures and methodologies and 
examine additional study results that have been released since the 
proposal was issued. Specifically, EPA will consider requirements for 
the location of meters for taking flow measurements, the frequency of 
flow and chemical oxygen demand (COD) measurements taken, as well as 
the potential use of alternate parameters, such as BOD. EPA will also 
consider the inclusion of indirect or non-methane volatile organic 
compound emissions. Lastly, EPA will consider the acceptable methods 
for estimating missing data. EPA will consider optimal methods of data 
collection in order to maximize data accuracy, while considering 
industry burden.

JJ. Manure Management

1. Summary of the Final Rule
    Source Category Definition. A livestock facility that emits 25,000 
metric tons CO2e or more per year from manure management 
systems must report. A facility with an average annual animal 
population below those listed in Table JJ-1 of 40 CFR part 98, subpart 
JJ, does not need to calculate emissions or report. A facility with an 
average annual animal population that exceeds those listed in Table JJ-
1 should conduct a more thorough analysis to determine applicability. 
Average annual animal populations for static populations (e.g., dairy 
cows, breeding swine, layers) are estimated by performing an animal 
inventory or review of facility records. Average annual animal 
populations for growing populations (meat animals such as beef and veal 
cattle, market swine, broilers, and turkeys) are estimated using the 
average number of days each animal is kept at the facility and the 
number of animals produced annually. The rule also contains procedures 
for facilities with more than one animal group present (e.g., swine and 
poultry) to determine if they must report.
    A manure management system stabilizes or stores livestock manure, 
or does both, in one or more of the following system components:
     Uncovered anaerobic lagoons.
     Liquid/slurry systems with and without crust covers 
(including but not limited to ponds and tanks).
     Storage pits.
     Digesters, including covered anaerobic lagoons.
     Solid manure storage.
     Drylots, including feedlots.
     High-rise houses for poultry production (poultry without 
litter).
     Poultry production with litter.
     Deep bedding systems for cattle and swine.
     Manure composting.
     Aerobic treatment.
    GHG emissions from sources at livestock facilities unrelated to the 
stabilization and/or storage of manure are not covered under this rule 
and are not reported. Sources considered to be unrelated to the 
stabilization and/or storage of manure include daily spread or pasture/
range/paddock systems or land application activities or other methods 
of manure utilization not listed above. In addition, manure management 
activities located off site from a livestock operation are not included 
in this rule. These off site activities include but are not limited to 
off site

[[Page 56338]]

land application of manure, other off site methods of manure 
utilization, or off site manure composting operations.
    Facilities that meet the applicability criteria in the General 
Provisions (40 CFR 98.2) summarized in Section II.A of this preamble 
must report GHG emissions.
    GHGs to Report. For all livestock facilities with a manure 
management system that meets or exceeds the reporting threshold, the 
facility must report aggregate CH4 and N2O 
emissions from the system components listed above. For those manure 
management systems that include digesters, CH4 generated and 
destroyed, as well as any CH4 leakage, at the digester must 
also be reported.
    A facility that is subject to this rule only because of emissions 
from manure management systems is not required to report emissions 
under 40 CFR part 98 subparts C through PP other than subpart JJ.
    GHG Emissions Calculation and Monitoring. Detailed methods for 
calculating GHG emissions are included in the rule and are briefly 
described below. For each manure management system component other than 
digesters, facilities must calculate emissions using the following 
inputs and data:
     Type of system component.
     Average annual animal population (by animal type) 
contributing manure to the manure management system component.
     Typical animal mass (for each animal type).
     Fraction of manure by weight for each animal type managed 
in each system component (assumed to be equal to the fraction of 
volatile solids/nitrogen handled in each system component).
     Volatile solids excretion rates provided in look-up tables 
for the animal populations contributing manure to the manure management 
system component.
     Maximum CH4-producing potential of the managed 
manure and CH4 conversion factors provided in look-up tables 
for the animal populations contributing manure to the manure management 
system component.
     Methane conversion factor used (for each manure management 
system component).
     Nitrogen excretion rates (by animal type) using values 
provided in look-up tables for the animal populations contributing 
manure to the manure management system component.
     N2O emission factors (by animal type) provided 
in look-up tables for the animal populations contributing manure to the 
manure management system component.
    For anaerobic digesters, facilities must calculate CH4 
emissions and the annual mass of CH4 generated and destroyed 
based on the following inputs and data:
     Continuous monitoring of CH4 concentration, 
flow rate, temperature, and pressure of the digester gas.
     CH4 destruction efficiency of the destruction 
device and fugitive (leakage) emissions.
     The CH4 collection efficiency(ies) used (for 
each digester).
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, facilities must submit additional data 
that are used to calculate GHG emissions. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart JJ.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, facilities must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart JJ.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified below. The 
rationale for these and any other significant changes can be found 
below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart JJ: Manure Management.''
     To assist facilities in determining if they are subject to 
this rule, a table has been provided that presents average annual 
animal population values for specific livestock operations (i.e., beef, 
dairy, swine, and poultry). Facilities that have average annual animal 
population values below those shown in the table will not be required 
to report or complete the calculations to determine whether they need 
to report.
     Since proposal, the requirements for monthly manure 
sampling to determine volatile solids (VS) and nitrogen (N) content 
have been removed. Instead of obtaining VS and N content from manure 
sampling, facilities must use default VS and N excretion values as 
provided by EPA in look up tables. The default VS and N excretion 
values are consistent with the 1990-2008 U.S. GHG inventory for manure 
management and enteric fermentation. For beef and dairy cows, heifers, 
and steers, VS and N excretion rates were calculated using the IPCC 
Tier II methodology, based on the relationship between animal 
performance characteristics such as diet, lactation, and weight gain 
and energy utilization. In response to comments, EPA used the most up-
to-date information on U.S. animal diets to calculate these excretion 
rates. For other animal groups, reference values from ASAE and USDA are 
used.
     EPA has also adjusted the calculations for CH4 
and N2O emissions from manure management systems to account 
for volatile solids and nitrogen removal through solid separation. If 
solid separation occurs prior to the manure management system 
component, facilities must use default removal efficiencies as provided 
by EPA in look up tables. The default values are consistent with those 
cited in the ``Development Document for the Final Revisions to the 
National Pollutant Discharge Elimination System Regulation and the 
Effluent Guidelines for Concentrated Animal Feeding Operations'' (EPA-
821-R-03-001), published in December 2002.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on manure management were 
received covering numerous topics. Responses to significant comments 
received can be found in the comment response document for manure 
management in ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response 
to Public Comments, Subpart JJ: Manure Management.''
    Comment: A number of commenters supported EPA's decision to include 
livestock facilities with manure management systems in the proposed 
rule. These commenters noted that the establishment of a mandatory GHG 
reporting rule is the next logical step in reducing and mitigating GHG 
emissions in the U.S., and that manure management is a significant 
source of GHG emissions in the U.S. that should be addressed.
    However, other commenters stated that livestock facilities should 
not be required to report GHG emissions. These commenters noted that a 
small number of facilities would be covered by the proposed rule, and 
these facilities would represent a very small percentage of the total 
number of livestock facilities in the U.S. which would not provide a 
large enough set of data to help improve or reduce uncertainties 
associated with GHG inventories. Several of the commenters stated that 
manure management is not a major source of GHG emissions in the U.S., 
and the environmental benefits from the rule

[[Page 56339]]

would be minimal compared to the effort required to report emissions.
    Response: EPA disagrees that the manure management source category 
be excluded from this rule. Manure management has been determined to be 
a key source of GHG emissions in the U.S., based on the key source 
category methodology developed by the Intergovernmental Panel on 
Climate Change (IPCC). The IPCC identifies key sources as those sources 
that have significant impacts on the total emissions or emission trends 
in a country.
    While livestock manure GHG emissions represent a relatively small 
fraction of the total U.S. GHG emissions, these emissions are large in 
absolute terms. According to the 2009 U.S. GHG Inventory, 
CH4 emissions from manure management systems totaled 44 
million metric tons CO2e, and N2O emissions were 
14.7 million metric tons CO2e in 2007; manure management 
systems account for 7.5 percent of total anthropogenic CH4 
emissions and 4.7 percent of N2O emissions in the U.S.
    In addition, the collection of facility level GHG emission data, 
including the type of manure management systems in operation and the 
number and types of animals serviced by those systems, will help to 
inform future climate change policy decisions. While the actual number 
of facilities reporting will be quite small in comparison to the total 
number of facilities in the U.S., the data gathered through this effort 
is valuable. For example, these data will help to improve the 
understanding of emission rates and actions that facilities take to 
reduce emissions and may improve the effectiveness and design of 
voluntary and/or mandatory programs to reduce emissions.
    Comment: Multiple commenters stated that the monitoring 
requirements in the proposed rule would be too burdensome and expensive 
for industry to comply with. These commenters expressed concern that 
sampling manure for VS and N would require more time and effort and be 
more expensive than EPA estimated. Multiple commenters suggested that 
default values such as from the American Society of Agricultural and 
Biological Engineers (ASABE) be permitted for VS and N instead of 
measured values to eliminate some of the expense associated with the 
proposed rule.
    In addition, a number of commenters noted that there were some 
methodological issues associated with the monitoring requirements for 
VS and N. Multiple commenters noted that the requirements for manure 
sampling should be clarified.
    Response: EPA acknowledges these concerns and has removed the 
manure sampling requirements from the final rule. As discussed earlier, 
EPA used default values for VS and N excretion from USDA and ASAE for 
swine and poultry, and has calculated these rates for beef and dairy 
cows, heifers, and steers using the IPCC Tier II methodology, based on 
the relationship between animal performance characteristics such as 
diet, lactation, and weight gain and energy utilization. The use of 
these animal-specific default values for VS and N will greatly reduce 
the burden to comply with the reporting rule, while only minimally 
impacting the estimates of GHG emissions. The variation in sampling 
techniques from facility to facility when characterizing manure ``as 
excreted'' from the various animal populations on the facility (as 
would have been required by the proposal) would negate the benefit 
derived from this requirement. EPA considered designing a more complex 
and rigorous program to ensure consistency in the implementation of a 
manure sampling program and to ensure that manure samples represented 
``as excreted'' manure (prior to any storage or treatment). However, 
after reviewing comments, we determined that the expected burden of 
such a program, in terms of time, effort, and expense, outweighed the 
merits at this time.
    Comment: A number of commenters noted that calculation errors 
caused threshold head numbers to be overestimated, which caused the 
amount of emissions from these operations and the number of operations 
that would need to report to be underestimated.
    Response: To estimate the number of facilities at each threshold, 
EPA first developed a number of model facilities to represent the 
manure management systems that are most common on large livestock 
operations and have the greatest potential to exceed the GHG reporting 
threshold. Next, EPA used the U.S. GHG inventory methodology for manure 
management to estimate the numbers of livestock that would need to be 
present to exceed the threshold for each model livestock operation 
type. Finally, EPA combined the numbers of livestock required on each 
model operation to meet the thresholds with U.S. Department of 
Agriculture (USDA) data on farm sizes to determine how many farms in 
the United States have the livestock populations required to meet the 
GHG thresholds for each model livestock operation.
    Since proposal, EPA made revisions to the threshold analysis 
spreadsheet calculations based on information and data provided by 
commenters. EPA corrected conversion factors used in the nitrous oxide 
emission calculations, and corrected spreadsheet cell reference errors 
along with using updated VS and N values. EPA now estimates that there 
will be approximately 107 livestock facilities that will need to report 
under the rule.
    Comment: Commenters also expressed concerns with the emission 
calculations. Multiple commenters noted that the maximum methane 
producing capacity (Bo) values used do not reflect variations in animal 
diet. Several commenters had concerns about the methodology used to 
estimate the methane conversion factors. In addition, some commenters 
suggested that other data sources should be considered, such as the 
ASABE manure standards.
    Response: After a thorough review of available information, EPA has 
determined that the methodologies and data sources used to calculate 
emissions in this rule represent the best available methods and data. 
EPA reviewed many protocols and approaches prior to selecting the 
proposed methodology. EPA's selected methodology for reporting GHG 
emissions (methane and nitrous oxide) associated with manure management 
systems is based on EPA's Inventory of U.S. Greenhouse Gas Emissions 
and Sinks, as well as the IPCC Guidelines for National Greenhouse Gas 
Inventories. These methodologies rely on the use of activity data, such 
as the number of head of livestock, operational characteristics (e.g., 
physical and chemical characteristics of the manure, type of management 
system(s)), and climate data, to calculate GHG emissions associated 
with traditional manure management systems. In addition, the selected 
methodology for the reporting rule uses measured values for those 
manure management systems (e.g., anaerobic digesters) that collect and 
combust biogas.
    EPA considered requiring direct measurement of GHG emissions from 
manure management systems, but rejected this approach due to the 
extreme expense and complexity of such a measurement program. EPA is 
promulgating an approach that allows the use of default factors, such 
as a system emission factor, for certain elements of the calculation, 
and encourages the use of some site-specific data. The cost of such an 
approach is significantly lower than a direct measurement program. In 
addition, this approach is consistent with the methods used in offset 
programs throughout the world, including the California Climate Action 
Registry's (CCAR) Manure

[[Page 56340]]

Management Project Reporting Protocol. For these offset programs, 
livestock operations are required to complete calculations that 
establish their ``baseline'' emissions (prior to the use of a biogas 
collection system). These baseline emission calculations use similar 
emissions calculations and default values as are in EPA's Reporting 
Rule.
    The IPCC guidelines have been established by a recognized panel of 
experts and underwent significant peer review prior to their adoption. 
In addition, protocols for offset programs, such as CCAR, have gone 
through similar public review processes prior to their acceptance and 
use.
    Comment: Multiple commenters have requested more detailed look up 
tables and a tool to provide more clarity on which facilities are 
required to report under the final rule.
    Response: EPA agrees that additional tables and tools would 
facilitate compliance with the rule and ease the burden associated with 
reporting. In response to the comments, EPA has added a threshold table 
to the final rule (Table JJ-1) to help livestock facilities with manure 
management systems better determine if they might be subject to the 
requirements of the rule. EPA also intends to develop applicability 
tools that can assist facilities that could be covered by the rule, 
based on table JJ-1 in 450 CFR part 98, subpart JJ, in conducting a 
more detailed evaluation. These tools will include detailed look-up 
tables showing the estimated livestock head numbers that would be 
necessary in order to meet or exceed the threshold and a calculation 
tool to assist in performing the calculations in the proposed rule.

KK. Suppliers of Coal

    At this time, EPA is not going final with a subpart for suppliers 
of coal. As EPA considers next steps, we will be reviewing the public 
comments and other relevant information.
    The Agency received a number of lengthy, detailed comments 
regarding the coal suppliers subpart. Commenters generally opposed the 
proposed reporting requirements and raised multiple issues with EPA's 
legal authority for requiring coal suppliers to report CO2 
emissions. Several commenters stated that reporting by coal suppliers 
would represent a duplication of the reporting by coal users. For 
example, electric utilities and industrial plants, which consume the 
vast majority of coal supplied, are already required to report data on 
emissions based on their coal purchases. Commenters also stated that 
the reporting requirement would entail significant burden and capital 
costs to coal suppliers. In most cases, commenters provided alternative 
approaches to the reporting requirements proposed by EPA. For example, 
commenters suggested that EPA exempt from reporting coal mines that 
supply coal to mine-mouth power plants, modify the required coal 
weighing and sampling standards, and eliminate the required statistical 
correlation between HHV and carbon content.
    Commenters raised other issues regarding the reporting of data such 
as concerns that coal suppliers and laboratories could not 
realistically purchase and install new coal testing and sampling 
equipment and provide training to meet the requirements of the proposed 
rule.
    Based on careful review of comments received on the preamble, rule 
and TSDs under proposed 40 CFR part 98, subpart KK, EPA will perform 
additional analysis and consider alternatives to data collection 
procedures and methodologies. These alternatives will provide coverage 
of coal supplied, imported, or exported while concurrently taking into 
account industry burden.

LL. Suppliers of Coal-Based Liquid Fuels

1. Summary of the Final Rule
    Source Category Definition. This source category consists of 
producers, importers, and exporters of products listed in Table MM-1 of 
40 CFR part 98, subpart MM that are coal-based (coal-to-liquid 
products). A producer of coal-to-liquid products is any owner or 
operator who converts coal into liquid products (e.g., gasoline, 
diesel) using the Fischer-Tropsch or an alternative process.
    Suppliers of coal-to-liquid products that meet the applicability 
criteria in the General Provisions (40 CFR 98.2) summarized in Section 
II.A of this preamble must report GHG emissions.
    GHGs to Report. Suppliers of coal-to-liquid products must report 
the CO2 emissions that would result from the complete 
combustion or oxidation of the coal-to-liquid products.
    Suppliers of coal-to-liquid products are not required to report 
data on emissions of other GHGs that would result from the complete 
combustion or oxidation of their products, such as CH4 or 
N2O.
    GHG Emissions Calculation and Monitoring. For each type of coal-to-
liquid product, suppliers must calculate CO2 emissions that 
would result from the complete combustion or oxidation of the coal-to-
liquid products by following the procedures in 40 CFR 98.393.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate GHG emissions that would result from the 
complete combustion or oxidation of their products. A list of the 
specific data to be reported for this source category is contained in 
40 CFR 98.386.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions that would result from the complete combustion 
or oxidation of their products. A list of specific records that must be 
retained for this source category is included in 40 CFR 98.387.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below.
     We replaced the procedures and calculations proposed in 40 
CFR part 98, subpart LL with references to the 40 CFR part 98, subpart 
MM procedures and calculations. As a result of considerable comment and 
EPA analysis, 40 CFR part 98, subpart MM procedures and calculations 
were significantly updated. Since the procedures and calculations 
necessary for sampling, testing, and measuring coal-to-liquid products 
are intrinsically linked to the procedures and calculations used for 
petroleum products, we concluded that referencing 40 CFR part 98, 
subpart MM in 40 CFR part 98, subpart LL would achieve consistency and 
completeness.
     We reorganized and updated 40 CFR 98.386 by mirroring 40 
CFR 98.396 in order to reflect the updates we made to procedures and 
calculations and to assist in EPA data verification.
3. Summary of Comments and Responses
    EPA did not receive any specific comments on proposed 40 CFR part 
98, subpart LL (suppliers of coal-based liquid fuels). Changes made to 
this subpart were implemented to ensure consistency with changes made 
to 40 CFR part 98, subpart MM based on public comments provided and EPA 
analysis conducted.

[[Page 56341]]

MM. Suppliers of Petroleum Products

1. Summary of the Final Rule
    Source Category Definition. Suppliers of petroleum products consist 
of:
     Petroleum refineries that produce petroleum products 
through distillation of crude oil.
     Importers who satisfy the same meaning given in 40 CFR 
98.6, including any entity that imports petroleum products or NGLs as 
listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or 
refiner of refined or semi-refined petroleum products shall be 
considered an importer if it otherwise satisfies the aforementioned 
definition.
     Exporters who satisfy the same meaning given in 40 CFR 
98.6, including any entity that exports petroleum products or NGLs as 
listed in Table MM-1 of 40 CFR part 98, subpart MM. Any blender or 
refiner of refined or semi-refined petroleum products shall be 
considered an exporter if it otherwise satisfies the aforementioned 
definition.
    Suppliers of petroleum products that meet the applicability 
criteria in the General Provisions (40 CFR 98.2) summarized in Section 
II.A of this preamble must report GHG emissions that would result from 
the complete combustion or oxidation of the product(s) they supply.
    GHGs to Report. Suppliers of petroleum products must report 
annually:
     CO2 emissions that would result from the 
complete combustion or oxidation of each petroleum product and natural 
gas liquid produced, used as feedstock, imported, or exported during 
the calendar year.
     CO2 emissions that would result from the 
complete combustion or oxidation of any biomass co-processed with 
petroleum feedstocks at a refinery.
    Suppliers of petroleum products are not required to report data on 
emissions of other GHGs that would result from the complete combustion 
or oxidation of their products, such as CH4 or 
N20.
    GHG Emissions Calculation and Monitoring. Suppliers of petroleum 
products must choose one of two methods to calculate CO2 
emissions that would result from the combustion or oxidation of each 
petroleum product and natural gas liquid:
     Method 1: Use the default CO2 emission factors 
provided in the regulations for a given petroleum product or NGL; or
     Method 2: Develop an emission factor for a given petroleum 
product or natural gas liquid using direct measurements of density and 
carbon share.
    To calculate CO2 emissions that would result from the 
combustion or oxidation of biomass co-processed with petroleum 
feedstock, reporters must use a CO2 emission factor that is 
provided in the regulations for each type of biomass.
    In calculating total CO2 emissions that would result 
from the combustion or oxidation of all petroleum products and natural 
gas liquids that leave the refinery, refineries must subtract the 
emissions from petroleum products and natural gas liquids that enter 
the refinery to be further refined or used on site as well as biomass 
and biomass-based fuels that are co-processed or blended with petroleum 
feedstocks.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
used to calculate GHG emissions that would result from the complete 
combustion or oxidation of the product(s) supplied as well as 
information on the characteristics of crude oil used at a refinery. The 
specific list of data to be reported for this source category is 
contained in 40 CFR part 98.396 and includes information to support the 
data verification process.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
determine the quantities and characteristics of product(s) reported 
under this subpart and to calculate GHG emissions that would result 
from the complete combustion or oxidation of the product(s) supplied. A 
list of specific records that must be retained for this source category 
is included in 40 CFR part 98.387.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart MM: Suppliers of Petroleum 
Products.''
     We established a reporting threshold for importers and 
exporters of 25,000 metric tons of CO2 per year.
     We changed the source category definition of petroleum 
refinery for the purposes of 40 CFR part 98, subpart MM to only include 
facilities that process crude oil. As such, we are not requiring 
reporting from facilities that only handle intermediary petroleum 
products.
     We refined the definition of importers and exporters of 
petroleum products to clarify reporting requirements for blenders.
     We are not requiring reporters to rely on an exclusive 
list of standard methods for the measurement of the quantity of 
products or the calibration and recalibration of equipment. Instead, 
reporters must use an appropriate standard method published by a 
consensus-based standards organization. If no such standard exists, 
reporters are allowed to rely on industry standard practices.
     We provide more flexibility in the frequency of equipment 
recalibration. Reporters must now comply with the frequency specified 
by the manufacturer's directions or the selected quantity measurement 
method.
     We removed the option for reporters to directly measure 
density but not carbon share under Calculation Method 2. We determined 
that using a measured density and a default carbon share factor will 
likely adversely affect the accuracy of the calculated emission factor 
since the density and carbon share of hydrocarbons are, in the absence 
of impurities, correlated.
     We are not requiring reporters to rely on an exclusive 
list of standard methods for sampling products, measuring density, and 
measuring carbon share under Calculation Method 2. Instead, reporters 
must use an appropriate standard method published by a consensus-based 
standards organization.
     We added more specific requirements for the frequency of 
sampling under Calculation Method 2 and now allow for mathematical 
composites of samples in addition to physical composites of samples.
     To ensure consistent accounting of denaturant across 
reporters, we are requiring reporters to assume that 2.5 percent of the 
volume of any ethanol product that is blended into a petroleum-based 
product is a petroleum-based denaturant. See below for further 
explanation.
     For bulk NGLs, reporters must calculate the emissions that 
would result from the complete combustion or oxidation of the 
individual components that constitute the NGL (i.e., ethane, propane, 
butane, isobutane, and pentanes plus).
     We updated the definition of petroleum products to be 
clear that no petroleum product supplier must report on plastics and 
plastic products and that

[[Page 56342]]

importers and exporters must report on asphalt, road oil, and 
lubricants.
     We updated the default emissions factors based on 
technical research since the proposal. We updated certain factors to 
correct technical errors and to reflect more recent data. We expanded 
the factors to four significant digits to enhance precision. We also 
added grade-based sub-categories of finished motor gasoline and 
blendstocks, combined diesel and fuel oil categories into ``distillate 
fuel'' categories, and added sulfur-based subcategories of distillate 
fuel No. 1 and 2 to better distinguish between product categories with 
potentially different carbon contents. Full documentation of default 
emissions factors can be found in the TSD.
     We updated 40 CFR 98.396. First, we made 40 CFR 98.396 
more specific, in some cases breaking up one reporting requirement into 
two for clarity. Second, to allow for EPA verification of reporter 
calculations, we added reporting requirements for data that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.393 
through 98.396. Third, after removing the prescriptive list of 
allowable methods, we added data reporting requirements on the method 
selected to measure quantity, density, and carbon content and the 
method selected to sample in order to track the appropriateness of 
these methods.
    We require reporters to assume that ethanol contains 2.5 percent 
petroleum-based denaturant because we want to ensure that reporters 
account for the CO2 emissions that would result from the 
combustion or oxidation of the denaturant. All ethanol that is blended 
with petroleum products reported in 40 CFR part 98, subpart MM should 
contain more than 1.96 percent petroleum-based denaturant by volume, 
per the requirements in 27 CFR Parts 20 and 21 to make ethanol non-
potable. We considered relying on reporters to estimate the percent 
volume of denaturant in their products, but we determined that, in many 
cases, reporters would not know this information. We have concluded 
that 2.5 percent is a suitable assumption for the level of denaturant 
since, according to an Internal Revenue Service interpretation of 
Section 15332 in the Food, Conservation, and Energy Act of 2008 in 
notice 2009-06, ethanol containing greater than 2.5 percent denaturant 
by volume would not be eligible for the full value of the Volumetric 
Ethanol Excise Tax Credit. There may be cases where ethanol containing 
less than 2.5 percent denaturant is blended with petroleum-based 
products, but we concluded that it is better to conservatively account 
for potential petroleum-based carbon emissions rather than arbitrarily 
pick a number between 1.96 percent and 2.5 percent.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on suppliers of petroleum 
products were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Subpart MM: 
Suppliers of Petroleum Products.''
Selection of Threshold
    Comment: In the proposed rule, EPA sought comment on whether or not 
to establish a de minimis level of imported and exported petroleum 
products, either in terms of the quantity of products or the 
CO2 emissions associated with the combustion or oxidation of 
products, to eliminate any reporting burden for parties that may import 
or export a small amount of petroleum products on an annual basis. In 
response, EPA received several comments in support of establishing some 
type of de minimis value, including a threshold of 25,000 metric tons 
of CO2 from the complete combustion or oxidation of all 
products from individual importers and exporters. EPA also received at 
least one comment in support of establishing a threshold value for 
refineries reporting under 40 CFR part 98, subpart MM.
    Response: In today's rule, we are establishing a threshold of 
25,000 metric tons of CO2 per year for importers and 
exporters of petroleum products and natural gas liquids; the threshold 
is based on a calculation of CO2 emissions that would result 
from complete combustion or oxidation of the imported or exported 
petroleum products and natural gas liquids.
    When we conducted the threshold analysis for the proposed rule, we 
estimated from EIA data that 224 companies would be covered in 40 CFR 
part 98, MM as importers. Through this analysis, we found that at a 
threshold of 25,000 metric tons CO2 per year, 175 importers 
and 99.9 percent of total emissions that would result from the 
combustion or oxidation of imported products would be covered by the 
proposed rule. Therefore, establishing a 25,000 metric ton 
CO2 threshold would drop 49 reporters in exchange for a 0.1 
percent drop in total emissions. Nonetheless, we decided to propose 
reporting for all importers because we felt the reporting burden would 
be minimal since importers already report the product quantity data to 
other Federal agencies.
    Since proposing the rule, EPA has learned new information, through 
comments and research, about importers that could be covered as 
reporters under 40 CFR part 98, Subpart MM. EPA may have omitted some 
importers of small volumes of petroleum products or natural gas liquids 
from our original threshold analysis, due to lack of public data. We 
never intended to cover such small volume imports with this rule (e.g., 
importers of non-fossil fuel products that contain small quantities of 
petroleum or natural gas liquids, such as butane lighters). Therefore, 
for the final rule, EPA concludes that establishing a 25,000 metric ton 
CO2 threshold for importers will relieve burden on importers 
of insignificant quantities of petroleum products and natural gas 
liquids that we never intended to cover with this rule without 
significantly diminishing the amount of information received by the 
agency. In addition, a 25,000 metric ton CO2 threshold is 
consistent with other upstream fuel and industrial gas supplier 
thresholds for importers and exporters in today's rule.
    When we conducted the threshold analysis for the proposed rule, we 
could not estimate the number of exporting companies that would be 
covered in 40 CFR part 98, subpart MM because the necessary data was 
not publically available. Nonetheless, we decided to propose reporting 
for all exporters because we concluded that the reporting burden would 
be minimal given the type of information that exporters must maintain 
as part of their normal business operations.
    Since proposing the rule, based on analogous information learned on 
importers, EPA has concluded that some exporters of very small volumes 
of petroleum products or natural gas liquids could be covered as 
reporters under 40 CFR part 98, subpart MM. We never intended to cover 
such small volume exporters with this rule (e.g., exporters of non-
fossil fuel products that contain small quantities of petroleum or 
natural gas liquids, such as butane lighters). Therefore, for the final 
rule, EPA has concluded that establishing a threshold for exporters 
will relieve burden on exporters of insignificant quantities of 
petroleum products and natural gas liquids that we never intended to 
cover with this rule. In today's rule, we have selected a 25,000 metric 
ton CO2 threshold because we conclude that it will not 
significantly diminish the amount of information received by the 
agency;

[[Page 56343]]

overall, exports of refined and semi-refined products are lower than 
imports, so the threshold adopted for imports will be adequate for 
collecting data on exports. In addition, a 25,000 metric ton 
CO2 threshold is consistent with other upstream fuel and 
industrial gas supplier thresholds for importers and exporters in 
today's rule.
    In today's rulemaking, we require all refineries as defined in 40 
CFR part 98, subpart MM to report, as was proposed. Our threshold 
analysis of refineries in the proposed rule indicated that all 
refineries would be covered even if we were to establish a 100,000 
metric ton CO2 threshold. Furthermore, we have determined 
that all refineries covered by this subpart are already tracking the 
necessary data to comply with the reporting requirements so the 
requirements would not pose an undue burden.
Monitoring and QA/QC Requirements
    Comment: EPA received several comments that the proposed approach 
to determining product quantity was too prescriptive. These comments 
indicated that the list of allowable methods and equipment types for 
determining the quantity of products in the proposed rule was 
incomplete, would result in significant costs for industry, and could 
adversely impact the quality of the measurements. Commenters noted that 
industry uses a much larger and ever-growing number of industry methods 
and equipment types to determine quantity for purposes of product 
transfers and financial records, including methods and equipment types 
used to comply with Internal Revenue Service, Securities and Exchange 
Commission, and Department of Homeland Security's Bureau of U.S. 
Customs & Border Protection regulations. Commenters suggested that 
EPA's ability to develop and maintain a comprehensive list of methods 
would require considerable resources, since companies and consensus-
based standards organizations review quantity measurement methods 
regularly to ensure consistency with technological changes and 
advancements. Commenters also suggested that methods may improve over 
time for certain products as a direct result of this rulemaking.
    Response: In today's rule, we are addressing these concerns by 
adopting an approach that recognizes the multitude of appropriate 
industry standard methods and practices and leaves open the possibility 
that industry may adopt better methods, equipment, and practices over 
time to determine quantities of products. EPA is requiring that 
petroleum product suppliers use an appropriate standard method 
developed by a consensus-based standards organization, when such a 
standard method exists. If no such standard method exists, reporters 
are allowed to follow industry standard practices. Consensus-based 
standards organizations include organizations such as ASTM 
International, the American National Standards Institute (ANSI), the 
American Gas Association (AGA), the American Society of Mechanical 
Engineers (ASME), the American Petroleum Institute (API), and North 
American Energy Standards Board (NAESB). Reporters must ensure that all 
equipment used for measuring quantity is calibrated and periodically 
recalibrated according to the manufacturer's directions or 
specifications in the appropriate consensus-based industry standard 
method.
    In order to further EPA's understanding of the methods and 
equipment that reporters use, and to help us better assess the 
appropriateness of the standard methods and industry practices that 
individual reporters select, we are requiring that all petroleum 
product suppliers report the standard method or industry standard 
practice they use to measure each distinct product quantity that they 
report to EPA.
    Comment: Several commenters recommended that EPA provide more 
flexible approaches to the direct measurement of carbon share and 
density under Calculation Method 2. Some noted that the proposed 
requirement to test samples at the end of the year could negatively 
impact the integrity and quality of those samples. These commenters 
suggested that EPA allow reporters to test samples monthly and create a 
mathematical composite of these test results at the end of the year. 
Some commenters suggested that EPA develop a mechanism whereby 
reporters could reduce the frequency of sampling once the reporter 
demonstrates that the variability in the density and carbon share of 
the product is sufficiently small, and even eliminate direct 
measurement requirements and allow reporters to use emissions factors 
developed in previous years. We also received comments requesting that 
we expand our list of acceptable carbon share measurement methods.
    Response: We have incorporated several of the suggestions to 
increase the flexibility of the Calculation Method 2 approach in 
today's rule. Reporters are now allowed to test their monthly samples 
throughout the year and conduct a mathematical composite of the test 
results at the end of the year. We have also expanded the list of 
acceptable sampling, density, and carbon share methods to include any 
appropriate standard method published by a consensus-based standards 
organization.
    We could not determine an adequate approach for allowing reporters 
to reduce the sampling frequency of products based on statistical 
evidence of low variability in the density and carbon share for a given 
product. We want to capture changes in product characteristics over 
time and have determined that taking monthly samples of an entire 
product category would not be overly burdensome. Furthermore, reporters 
are allowed to use default factors under Calculation Method 1 if they 
so choose.
Data Reporting Requirements
    Comment: EPA received several comments requesting that we eliminate 
reporting requirements related to products that have potentially non-
emissive uses, including plastics and plastic products, petrochemical 
feedstocks, petroleum coke sent to landfill, asphalt and road oil, and 
lubricants and waxes. One commenter questioned the incongruity in 
reporting requirements proposed for refiners, who would report on all 
products, and importers and exporters who would not be required to 
report on asphalt, road oil, lubricants, waxes, plastics, and plastic 
products.
    Response: Today's rule requires reporting on products with 
potentially non-emissive uses. Comprehensive upstream data will provide 
EPA with a full accounting of the emissions that would result from the 
complete combustion or oxidation of all petroleum products and natural 
gas liquids introduced into the economy. Furthermore, comprehensive 
facility-level data can help us conduct a more robust mass balance 
assessment for data verification purposes. While we recognize that 
carbon in some petroleum products, such as asphalt, can remain un-
oxidized for long periods, petroleum product supplier cannot always 
know with certainty whether or not the carbon in their products will be 
released into the atmosphere. Even asphalt can be burned as fuel or 
incinerated as waste. In the Inventory of US Greenhouse Gas Emissions 
and Sinks, EPA notes several areas of uncertainty surrounding the fate 
of carbon in petroleum products including those for which the Inventory 
assumes a 100 percent storage factor for the purposes of the national 
inventory (e.g., asphalt roofing, asphalt cement,

[[Page 56344]]

and asphalt paving materials). As discussed in the proposal, a 
comprehensive and rigorous system for tracking the fate of petroleum 
products that may have non-emissive uses is beyond the scope of this 
rule, and would require a much more burdensome reporting obligation for 
petroleum product suppliers and other downstream users of petroleum 
products and natural gas liquids. The data reported as a result of this 
rulemaking will allow EPA to conduct further research in the future on 
the pathways and ultimate fate of products with potential non-emissive 
uses.
    It was never EPA's intention to require reporting on plastics and 
plastic products, so we made this explicit in the definition of 
petroleum products as well as our definition of a refinery in 40 CFR 
part 98, subpart MM, which now excludes any facility (e.g. a plastics 
manufacturing plant) that does not process crude oil. Any 
CO2 emissions that would result from the combustion or 
oxidation of plastics and plastic products manufactured in the U.S. 
should already be accounted for when a petroleum product supplier 
introduces the petrochemical feedstock (e.g., propylene) into the 
economy.
    In response to comments on the incongruity of the reporting burden 
for refiners compared to importers and exporters, we have reevaluated 
the list of petroleum products with potentially non-emissive uses that 
importers and exporters do not have to report. In the proposed rule, 
this list included asphalt, road oil, lubricants, waxes, plastics, and 
plastic products. Our rationale for excluding these products for 
importers and exporters was our assessment that there is a much larger 
variety of these products entering and leaving the country than is 
produced at a petroleum refinery. Upon further consideration, however, 
we have concluded that only waxes, plastics, and plastic products would 
pose an undue administrative burden on importers and exporters. Waxes, 
plastics, and plastic products enter and leave the country in wide-
ranging forms (e.g., cosmetics, candles, lawn furniture, plastic wear) 
making it difficult to accurately assess the petroleum-based carbon 
content of these products. We have concluded that the types of asphalt, 
road oil, and lubricants imported in and exported from the country is 
much less variable, and importers already track these products and 
report the quantities to EIA. We have also established a 25,000 metric 
ton CO2 annual reporting threshold for importers and 
exporters in today's rule, which should reduce the number of reporters 
and minimize the reporting of products that are imported or exported in 
very low quantities. Therefore, we are requiring importers and 
exporters to report the volume and CO2 emissions that would 
result from the complete combustion or oxidation of the asphalt, road 
oil, and lubricants they supply.
    In response to comments that collecting data on products with 
potentially non-emissive uses will overestimate actual emissions 
released into the atmosphere, EPA has and will continue to characterize 
CO2 emissions data reported under 40 CFR part 98, subpart MM 
as emissions that would result from the complete combustion or 
oxidation of the reported product(s) and not as actual emissions.
    Comment: EPA received many comments urging us to leverage data that 
petroleum product suppliers already report to the Energy Information 
Administration (EIA) and to follow EIA's data collection procedures and 
protocols. For example, one commenter urged EPA to require refiners on 
a facility-level and company-wide basis to report to EPA the same level 
of information on crude imports and processing that is currently 
reported to the EIA and to follow a process similar to the one used by 
the EIA; and another commenter urged us to align our reporting 
requirements with what the industry is already providing to the EIA. 
Some commenters, urged EPA to make use of data already reported to EIA 
or other Federal agencies instead of requiring reporting directly to 
EPA through this rulemaking. EPA also received comments recommending 
that EIA reporting remain separate from the reporting requirements of 
this rule.
    Response: In the proposed rulemaking, EPA stated that we 
considered, but did not propose, the option of obtaining data by 
accessing existing Federal government reporting databases and we sought 
comment on this decision.
    In today's rulemaking, we are requiring reporters to report data 
directly to EPA. We have determined that in order to collect facility-
level data from refineries (and company-level data from importers and 
exporters) that is consistent with other reporters in this rule, in 
terms of timing, reporting, and verification procedures, we are not 
able to rely upon EIA data. In addition, EIA relies on a number of 
legal authorities to pledge confidentiality to statistical survey 
respondents for company-level information. Some data are collected with 
legal authority from the Confidential Information Protection and 
Statistical Efficiency Act of 2002 (CIPSEA), under which reported 
information must be held in confidence and must be used for statistical 
purposes only. Collection of data directly by EPA in a central system 
will allow EPA to electronically verify and publish the data quickly, 
to use the information for non-statistical purposes, and to handle 
confidential business information in accordance with the CAA (see the 
general provisions preamble for addition discussion on CBI). In today's 
rulemaking we did not replicate EIA's reporting requirements and 
methodologies if we did not consider them sufficient to achieve our 
objective, which is to collect comprehensive and accurate data on the 
CO2 emissions that would result from the complete combustion 
or oxidation of petroleum products introduced into the economy. For 
example, we provide a comprehensive list in Tables MM-1 and MM-2 of 40 
CFR part 98, subpart MM, according to which reporters must categorize 
their products for reporting under today's rulemaking. This list 
differs from EIA's list of products, according to which reporters must 
report to EIA. Some of the products are the same on both lists (e.g., 
aviation gasoline and kerosene) while some products are classified 
differently on one list than on the other (i.e., EPA's list breaks 
reformulated gasoline up by summer and winter varieties while EIA 
breaks reformulated gasoline up by type of oxygenate blended into it). 
We crafted EPA's product list carefully and we feel that each category 
has the potential to have a unique carbon share and/or density. 
Overall, the items on our list are common products in commerce and are 
already tracked by refineries, importers, and exporters. Therefore, we 
estimate that the additional burden to comply with this rule will be 
minimal.

NN. Suppliers of Natural Gas and Natural Gas Liquids

1. Summary of the Final Rule
    Source Category Definition. Suppliers of natural gas and natural 
gas liquids are:
     NGL fractionators, which are installations that 
fractionate NGLs into their constituent liquid products: ethane, 
propane, normal butane, isobutane or pentanes plus for supply to 
downstream facilities.
     Local natural gas distribution companies (LDCs) that own 
or operate distribution pipelines that deliver natural gas to end 
users. Companies that operate interstate pipelines transmission or 
intrastate transmission pipelines are not part of this source category.
    Suppliers of natural gas and NGLs that meet the applicability 
criteria in the General Provisions (40 CFR 98.2)

[[Page 56345]]

summarized in Section II.A of this preamble must report GHG emissions 
that would result from complete combustion or oxidation of products 
they supply.
    GHGs to Report. Natural gas fractionators must report 
CO2 emissions that would result from the complete combustion 
or oxidation of the annual quantities of propane, butane, ethane, 
isobutene, and pentanes plus supplied.
    Local distribution companies must report CO2 emissions 
that would result from the complete combustion or oxidation of the 
annual volume of natural gas distributed to their customers.
    Suppliers of natural gas and NGLs are not required to report data 
on emissions of other GHGs that would result from the complete 
combustion or oxidation of their products, such as CH4 or 
N20.
    GHG Emissions Calculation and Monitoring. Reporters must use one of 
two methods to calculate the CO2 emissions that would result 
from the complete combustion or oxidation of natural gas supply or NGL 
supply:
     One method uses either a measured or default fuel heating 
value and either a measured or default CO2 emissions factor. 
This method is most appropriate for liquid fuels.
     The second method uses either a measured or default 
CO2 emissions factor. This method is most appropriate for 
gaseous fuels.
     A NGL fractionator must then follow two additional 
equations, if applicable, to subtract the CO2 emissions that 
would result from the complete combustion or oxidation of NGL supply 
that are double-counted. A LDC must then follow up to four additional 
equations, if applicable, to subtract the CO2 emissions that 
would result from the complete combustion or oxidation of natural gas 
supply that is double-counted.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate natural gas or NGL supply. A list of the 
specific data to be reported for this source category is contained in 
40 CFR part 98, subpart NN.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate natural gas or NGL supply. A list of specific records that 
must be retained for this source category is included in 40 CFR part 
98, subpart NN.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart NN: Suppliers of Natural Gas and 
Natural Gas Liquids.''
     We changed the source category responsible for reporting 
NGL supply in 40 CFR part 98, subpart NN from all natural gas 
processors to only facilities that fractionate natural gas liquids.
     We eliminated the requirement to report bulk NGL since NGL 
fractionators do not supply bulk NGL.
     We added equations to calculate emissions that would 
result from the oxidation or combustion of the following volumes of 
natural gas and NGLs because they should be subtracted from the 
reporter's total emissions calculation, when applicable: fractionated 
NGLs received from other fractionators; natural gas injected for 
storage; natural gas delivered to individual customers already 
reporting under another Subpart of this rule; and natural gas delivered 
by an LDC to another LDC.
     We clarified the points of measurements for reporting 
purposes.
     We changed the rule to allow local distribution companies 
to use transmission pipeline metered volumes and calculated heating 
value where the local distribution companies do not perform their own 
measurements.
     We provide flexibility in frequency of equipment 
calibration, requiring reporters to comply with standard industry 
practices for measurements used for billing purposes as audited under 
Sarbanes Oxley regulations.
     We added a procedure for measuring the carbon content of 
blends of NGLs since NGL fractionators may supply blends of NGLs.
     We updated 40 CFR 98.406. First, we made 40 CFR 98.406 
more specific, in some cases breaking up one reporting requirement into 
two for clarity. Second, to allow for EPA verification of reporter 
calculations, we added reporting requirements for data that a reporter 
must already use to calculate GHGs as specified in 40 CFR 98.403 to 40 
CFR 98.406. This includes the addition of reporting requirements for 
new calculations introduced in the final rule to prevent supply double-
counting. Third, after removing the prescriptive list of allowed 
standards and methods, we added data reporting requirements on the 
method selected to measure quantity, HHV, and carbon content. Fourth, 
we added a reporting requirement for the quantity of odorized propane. 
Fifth, we added data reporting requirements for inputs received by a 
NGL fractionator in order to conduct verification using a mass-balance 
approach.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on suppliers of natural gas and 
NGLs were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart NN: Suppliers of 
Natural Gas and Natural Gas Liquids.''
Definition of Source Category
    Comment: EPA received many comments on the non-emissive use of 
natural gas liquids (NGLs). In general, these comments stated that NGLs 
such as ethane, butane, and isobutene, are either used as feedstocks in 
the petrochemical industry or as blendstocks that are reported by 
refineries in 40 CFR part 98, subpart MM, and should not be reported as 
though they are completely combusted or oxidized. Several commenters 
proposed that odorized propane should be the focus of 40 CFR part 98, 
subpart NN rather than all NGLs because odorized propane is the only 
NGL that is combusted as fuel.
    Response: Today's rule still requires reporting on all NGL 
products, even those with potentially non-emissive uses. Comprehensive 
upstream data will provide EPA with a full accounting of the emissions 
that would result from the complete combustion or oxidation of all 
natural gas liquids introduced into the economy.
    As discussed in the proposal, a comprehensive and rigorous system 
for tracking the fate of natural gas liquids that may have non-emissive 
uses is beyond the scope of this rule, and would require a much more 
burdensome reporting obligation for NGL fractionators and downstream 
users of natural gas liquids. Based on the data available today, we do 
not believe that a NGL fractionator can know with certainty whether or 
not the carbon in their products will be released into the atmosphere. 
The data reported as a result of this rulemaking will allow EPA to 
conduct further research on the pathways and ultimate fate of NGL and 
to refine our understanding of and

[[Page 56346]]

policy on products with potential non-emissive uses.
    Therefore, EPA does not concur with the proposal to replace NGL 
reporting with propane odorizers. However, EPA concurs that odorized 
propane lines up closely with propane combusted downstream, and that 
data collection on odorized propane would help EPA decide if and how to 
carry out a wide variety of CAA provisions on emission sources, as 
authorized broadly under CAA sections 114 and 208. As a result, we have 
added reporting requirements on the volume of propane odorized on site 
in today's rule.
    We do not concur that products reported under 40 CFR part 98, 
subpart NN, such as isobutane to be blended with fuel, will be double-
counted as products reported under 40 CFR part 98, subpart MM. Subpart 
MM requires refineries to report all non-crude feedstocks that enter 
the facility in order to subtract the emissions that would result from 
the oxidation or combustion of those products from their calculations. 
Such methodology allows EPA to collect data on the entire petroleum and 
natural gas liquids system without any double-counting.
    Finally, in response to comments that collecting data on products 
with potentially non-emissive uses will overestimate actual emissions 
released into the atmosphere, EPA will continue to characterize 
CO2 emissions data reported under 40 CFR part 98, subpart NN 
as emissions that would result from the complete combustion or 
oxidation of the reported product(s) and not as actual emissions.
    Comment: Many commenters discouraged EPA from requiring reporting 
from natural gas processors. In general, these comments stated that 
processors do not know the constituents of the gas they process. They 
further stated that since bulk NGLs are often sent from one processor 
to another, reporting by processors on bulk NGLs would result in 
double-counting of supply. Ultimately, several commenters were confused 
by the multiple definitions provided in the rule for a natural gas 
processor and were not clear on the exact covered party in 40 CFR part 
98, subpart NN.
    Response: In the final rule, we specify the source category as NGL 
fractionators rather than as natural gas processors, and we have 
removed the requirement to report bulk NGLs. To avoid any remaining 
potential for double-counting, we provide an equation for a 
fractionator to subtract from its calculations any NGL constituents 
received from other fractionators that would report those products 
under this rule.
    By requiring reporting from NGL fractionators, we have removed the 
need for the term ``natural gas processor'' in 40 CFR part 98, subpart 
NN. Multiple definitions for this term no long exist in the rule.
Monitoring and QA/QC Requirements
    Comment: Many commenters interpreted EPA's measurement and 
calibration requirements differently than we intended, and as a result 
pressed upon EPA the inability of industry to reasonably meet such 
requirements. Many commenters interpreted that EPA required meter 
reading and calibration of every customer meter. Other commenters 
interpreted that EPA required daily measurement totals of throughput.
    Response: In today's rule, we provide precise language to remove 
any confusion about monitoring and QA requirements. First, we clarify 
that the point of measurement for natural gas supply is the city gate 
meter. If the LDC makes its own measurements at the city gate according 
to business as usual practices, then it must use its own measurements. 
If not, it must use the delivering pipeline invoices measurements. The 
only exceptions are that the point of measurement for natural gas 
delivered to large end-users is the customer meter and the point of 
measurement for natural gas stored or removed from storage is the 
appropriate storage meter. However, we clarify that customer meters and 
storage meters are not subject to the 40 CFR part 98, subpart NN 
calibration requirements.
    Second, we clarify that the minimum frequency of the measurements 
of quantities of NGLs and natural gas shall be based on the reporter's 
standard practices for commercial operations. For NGL fractionators the 
minimum frequency of measurements shall be the measurements taken at 
custody transfers summed to the annual reportable volume. For natural 
gas the minimum frequency of measurement shall be based on the LDC's 
standard measurement schedules used for billing purposes and summed to 
the annual reportable volume. If daily measurements are not standard 
practice for a reporter, then that reporter need not conduct daily 
measurements.
    EPA clarifies in the final rule that customer meters do not face 
calibration requirements under 40 CFR part 98, subpart NN. Other 
equipment used to measure quantities must be calibrated prior to their 
first use for reporting under this subpart, using a suitable standard 
test method published by a consensus based standards organization or 
according to the equipment manufacturer's directions. Such equipment 
must also be recalibrated at the frequency specified by the standard 
test method used or by the manufacturer's directions. EPA has concluded 
that initial calibration requirements are necessary to ensure 
consistency across all reporters and accuracy of data. Since such a 
wide variety of calibration methods is allowed and since commenters 
stated that industry already calibrates carefully as a result of State 
Utility Commission and other regulations, EPA concluded that industry 
is already following such calibration requirements for usual business 
operations.
Data Reporting Requirements
    Comment: EPA received many comments on the requirement for LDCs to 
report information on individual customers. In general, commenters 
interpreted the reason for EPA to collect this data differently than 
was intended. Many commented on the CBI nature of customer-specific 
delivery information. Others commented that LDCs do not or may not have 
access to the EIA or EPA numbers of their customers. One commenter told 
us that a LDC can only attest to the gas volume delivered through a 
single particular meter at a single particular location, which is not 
necessarily an individual customer.
    Response: In the final rule, EPA has clarified that an LDC must 
report on customers that receive more than 460,000 million standard 
cubic feet (Mscf) per year in order to subtract that volume out of its 
total calculations. EPA's intention is to use this data to remove 
potential double-counting and to prevent a LDC from calculating and 
reporting an overstated supply volume. EPA can also use these data to 
verify that covered direct emitters are approximately reporting under 
the rule. In response to comments that LDCs do not or may not have 
access to customers' EIA or EPA numbers, we have changed the reporting 
of this from required to voluntary, if known. We have further specified 
that LDCs must report large volumes delivered to a single meter rather 
than to a particular end-user.

OO. Suppliers of Industrial GHGs

1. Summary of the Final Rule
    Source Category Definition. Suppliers of industrial GHGs consist of 
the following:
     Facilities producing any fluorinated GHG or 
N2O, except those that produce

[[Page 56347]]

only HFC-23 generated as a byproduct during HCFC-22 production.
     Bulk importers of fluorinated GHGs or N2O, if 
the total combined imports of industrial GHGs and CO2 exceed 
25,000 metric tons of CO2e per year.
     Bulk exporters of fluorinated GHGs or N2O, if 
the total combined exports of industrial GHGs and CO2 exceed 
25,000 metric tons CO2e per year.
    Suppliers of Industrial GHGs that meet the applicability criteria 
in the General Provisions (40 CFR 98.2) summarized in Section II.A of 
this preamble must report industrial GHG supply flows.
    GHGs to Report. Suppliers of industrial GHGs must report the amount 
of N2O and each fluorinated GHG produced, imported, 
exported, transformed, or destroyed during the calendar year. Importers 
and exporters of CO2 must calculate and report annual 
amounts of CO2 according to 40 CFR part 98, subpart PP.
    GHG Emissions Calculation and Monitoring. Suppliers must use the 
following methods to calculate annual industrial GHG supply flows:
     The mass of each fluorinated GHG or N2O 
produced must be determined by measurements of gas production, less the 
mass of that GHG added to the process upstream (e.g., where used GHGs 
are added back to the production process for reclamation).
     The mass of each fluorinated GHG transformed must be 
determined considering the mass of fluorinated GHG fed into the 
transformation process and the efficiency of that process (as indicated 
by yield calculations or quantities of unreacted fluorinated GHGs or 
nitrous oxide permanently removed from the process and recovered, 
destroyed, or emitted).
     The mass of each fluorinated GHG destroyed must be 
determined by measurements of the mass of fluorinated GHG fed to the 
destruction device and a measurement of the destruction efficiency.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate industrial GHG supply flows or that can be 
used to verify industrial gas supply flows. A list of the specific data 
to be reported for this source category is contained in 40 CFR part 98, 
subpart OO.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate GHG emissions. A list of specific records that must be 
retained for this source category is included in 40 CFR part 98, 
subpart OO.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Subpart OO: Suppliers of Industrial 
GHGs.''
     EPA has elaborated on the definition of ``produce'' to 
clarify what it does and does not include. The definition now 
explicitly includes (1) the manufacture of a fluorinated GHG for use in 
a process that will result in the transformation of that GHG (either at 
or outside of the production facility) and (2) the creation of a 
fluorinated GHG (with the exception of HFC-23) that is captured and 
shipped off site for any reason, including destruction. The definition 
now explicitly excludes the creation of by-products that are released 
or destroyed at the production facility.
     EPA has eased the accuracy and precision requirements for 
measuring production, transformation, and destruction. EPA is also 
permitting facilities flexibility in the frequency of measurements and 
calibration of measurement devices. Masses produced, fed into 
transformation processes, and fed into destruction devices must now be 
estimated to a precision and accuracy of one percent rather than 0.2 
percent. Requirements to measure concentrations, which had previously 
been associated with the transformation and destruction provisions, 
have been changed to requirements to estimate concentrations or related 
quantities.
     EPA has eliminated the requirement that fluorinated GHG 
production facilities that destroy fluorinated GHGs annually verify the 
destruction efficiency of their destruction devices.
     EPA has added an additional method for estimating missing 
mass flow data in the event that a secondary mass measurement for that 
stream isn't available. In that event, producers can use a related 
parameter and the historical relationship between the related parameter 
and the missing parameter to estimate the flow.
     EPA has removed the option for reporters to develop their 
own methods for estimating missing data if they believe that the 
prescribed method will over- or under-estimate the data.
     EPA has added some reporting requirements to be consistent 
with the changes to the calculations and monitoring sections and to 
permit verification of emissions calculations.
     EPA has added an exemption from reporting requirements for 
import or export shipments containing less than 250 metric tons of 
CO2e.
     EPA has clarified that the criteria for imported container 
heels at paragraph 98.417(e) set forth the conditions under which 
importers do not need to report heels; they do not establish 
requirements for all containers containing residual gas. If importers 
import containers with residual gas that does not meet these 
conditions, they must simply report these imports under paragraph 
98.416(c). In addition, EPA is adding another condition under which 
imported heels do not need to be reported; that is the case in which 
the heels are recovered and included in a future shipment.
     EPA is requiring fluorinated GHG production facilities to 
submit a one-time report describing current measurement and estimation 
practices.
    EPA is requiring the one-time report on measurement practices 
because the Agency is providing some flexibility to reporters regarding 
the methods that they use to calculate industrial gas supply flows. 
This flexibility permits reporters to use a larger range of methods and 
measurement equipment than were proposed, and it is important for EPA 
to understand the methods and equipment and their accuracies. Similar 
reports are required under EPA's Stratospheric Ozone Protection 
Regulations at 40 CFR part 82.
    As noted above, EPA removed the option for reporters to develop 
their own methods for estimating missing data if they believe that the 
prescribed method will over- or underestimate the data. EPA removed 
this option for two reasons. First, the proposed provision lacked clear 
guidance on when alternative methods should be used (e.g., on the size 
of an underestimate that would justify use of an alternative method) 
and on how they should be developed. Second, the proposed provision was 
redundant with the new provision that permits reporters to estimate 
missing data using a related parameter and the historical relationship 
between the related parameter and the missing parameter. This new 
option provides reporters with flexibility in substituting for missing 
data in the event that a secondary mass measurement is not available, 
but sets out general guidance on how to select the substitute data.

[[Page 56348]]

3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on suppliers of industrial GHGs 
were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart OO: Suppliers of 
Industrial GHGs.''
Definition of Source Category
    Comment: EPA received a number of comments regarding the proposed 
definition of ``fluorinated greenhouse gas.'' Several commenters argued 
that the proposed definition was too broad because it would include 
nonvolatile materials that could not be emitted to the atmosphere and 
materials for which GWPs had not been calculated. One commenter 
suggested establishing a lower vapor pressure limit for fluorinated 
GHGs (heat transfer fluids) of 400 Pa (0.004 bar, or three mm Hg 
absolute) at 25 C. Some commenters expressed the concern that the lack 
of GWPs for some covered compounds would lead to incomplete or 
inconsistent reporting because facilities would assign their own GWPs 
to compounds for which GWPs were not provided in Table A-1 of 40 CFR 
part 98, subpart A.
    Some commenters recommended that EPA address these concerns by 
requiring reporting of only those fluorinated compounds listed in Table 
A-1 of 40 CFR part 98, subpart A. However, one of these commenters 
noted that the list in A-1 is incomplete and inconsistent, excluding 
for example, some high-GWP compounds whose low-GWP alternatives are 
included. This commenter recommended that EPA establish a ``visible and 
participative process'' to add other compounds as appropriate to Table 
A-1 of 40 CFR part 98, subpart A.
    Response: In today's final rule, EPA is modifying the proposed 
definition of fluorinated GHG by adding an exemption for ``substances 
with a vapor pressure of less than one mm of Hg absolute at 25 degrees 
C.'' This modification ensures that non-volatile fluorocarbons such as 
fluoropolymers are excluded from reporting requirements, while 
requiring reporting of fluorocarbons (as well as SF6 and 
NF3) that could reasonably be expected to be emitted to the 
atmosphere.
    As noted by several commenters, this definition would require 
reporting of some fluorocarbons to which GWPs have not been assigned in 
either IPCC or World Meteorological Organization (WMO) Scientific 
Assessments (i.e., fluorocarbons for which Table A-1 of 40 CFR part 98, 
subpart A does not provide GWPs). However, the lack of GWPs for some 
fluorocarbons will not impede reporting because EPA is requiring 
reporting of production and other quantities in tons of chemical rather 
than in tons of CO2e. For purposes of determining whether or 
not the 25,000 metric ton CO2e import or export threshold is 
exceeded, EPA is requiring facilities to include only substances whose 
GWPs appear in Table A-1 of 40 CFR part 98, subpart A.
    EPA believes that this approach is prudent and appropriate. As 
acknowledged by commenters, Table A-1 of 40 CFR part 98, subpart A is 
not a complete listing of current or potential fluorinated GHGs; the 
IPCC and WMO lists on which it is based reflect only the facts that the 
listed materials have been synthesized, their atmospheric properties 
investigated, the results published, and the publications found by the 
IPCC and WMO Assessment authors. Table A-1 is known to omit some 
existing fluorinated GHGs and it unavoidably omits future fluorinated 
GHGs that have not yet been synthesized. Given the radiative properties 
of the carbon-fluorine bond, any fluorocarbon emitted into the 
atmosphere may have a significant GWP. This is true even for some 
fluorocarbons with lifetimes of less than one year, including, for 
example, HFE-356pcc3, with a lifetime of four months and a 100-year GWP 
of 110.
    Reporting of fluorocarbons that do not appear in Table A-1 of 40 
CFR part 98, subpart A will provide valuable information on the full 
range of volatile fluorocarbons entering U.S. commerce. This 
information can be used to assess the overall volume and importance of 
compounds for which GWPs have not been evaluated and to help identify 
which compounds should have their GWPs evaluated first. In addition, 
once GWPs have been identified for these compounds, historical reports 
in tons of chemical can be converted into CO2e. Without a 
comprehensive reporting requirement, such historical information could 
be lost. Ultimately, all of this information can be used to inform 
policy decisions regarding the appropriate type and scope of emission 
reduction measures for these gases. Considering the modest cost of 
reporting production, import, and export of such compounds, the 
potential value of this information justifies a comprehensive 
definition of fluorinated GHG.
    EPA agrees with commenters who noted that Table A-1 of 40 CFR part 
98, subpart A should be periodically updated through a visible and 
participative process. EPA anticipates that as GWPs are evaluated or 
re-evaluated by the scientific community, the Agency will update Table 
A-1 of 40 CFR part 98, subpart A through notice and comment rulemaking. 
EPA may also, through rulemaking, establish a more proactive process 
for ensuring that GWPs are appropriately evaluated or re-evaluated.
    Comment: EPA received comments both supporting and opposing a 
requirement to report imports of fluorinated GHGs contained in 
equipment and foams. Commenters supporting such a requirement noted 
that these imports comprised a significant fraction of U.S. consumption 
of fluorinated GHGs, that excluding these imports from reporting would 
put domestic manufacturers at a disadvantage and lead to leakage of 
manufacturing and increased emissions of GHGs, and that the burden of 
reporting these imports would be low, since there are relatively few 
importers and the reported information is easily accessible. Commenters 
opposing such a requirement stated that the benefit of reporting would 
be small because pre-charged equipment and foams are ``hermetically 
sealed systems that essentially emit no GHGs,'' while the cost would be 
high due to the large number of importers.
    Response: EPA did not propose to require reporting of fluorinated 
GHGs contained in imported products because EPA was concerned that the 
administrative burden of such a requirement could be considerable, 
while the quantities imported in at least some types of products could 
be small. However, in the proposal EPA acknowledged that the quantities 
of fluorinated GHGs imported in pre-charged equipment and foams 
appeared significant, and that ascertaining the identity and quantity 
of fluorinated GHGs in these products might be relatively 
straightforward. EPA is continuing to research these issues, and is 
deferring the final decision on whether to include imports of equipment 
and foams containing fluorinated GHGs to a later rulemaking.
Monitoring and QA/QC Requirements
    Comment: Several commenters stated that facilities could not meet 
the proposed accuracy, precision, and frequency requirements for their 
measurements of production, transformation, and destruction using 
existing equipment and practices. These commenters stated that they 
would need to expend significant funds (millions of

[[Page 56349]]

dollars in some cases) and time to install Coriolis flowmeters in 
multiple streams and to implement daily sampling protocols to analyze 
the contents of these streams. One commenter requested that EPA revise 
its precision and accuracy requirements to one percent for measurements 
of mass. Other commenters argued that instead of establishing strict 
accuracy, precision, and frequency requirements for measuring 
production, EPA should permit facilities to use existing measurement 
instruments and practices, such as NIST Handbook 44 and the trial HFC 
reporting program patterned on EPA's reporting requirements for ozone-
depleting substances.
    Response: Given the limited amount of time before 2010 data 
collection must begin, EPA agrees that it is appropriate to ease the 
accuracy and precision requirements proposed for measuring production, 
transformation, and destruction. EPA is therefore revising these 
requirements in the final rule. EPA is also permitting facilities 
flexibility in the frequency of measurements and calibration of 
measurement devices.
    This approach will permit facilities to begin measuring their 
production, transformation, and destruction for purposes of the rule 
beginning in January 2010, using their current practices and equipment. 
However, EPA is planning to revisit the precision and accuracy 
requirements for industrial gas supply as we review public comments and 
perform analyses related to proposed 40 CFR part 98, subpart L 
(fluorinated gas production), which is not included in today's final 
rule. This is because the accuracy and precision with which production 
facilities track production, transformation, and destruction can have a 
profound influence on the accuracy and precision of these facilities' 
fluorinated GHG emission estimates. For one method of monitoring F-GHG 
emissions under consideration, a one percent relative error in 
production mass measurements could result in a much higher relative 
error in the emissions estimate, e.g., over 90 percent at an emission 
rate of 1.5 percent. For other methods of monitoring F-GHG emissions, 
however, a one percent relative error in production mass measurements 
would not lead to large errors in emission estimates. For both 40 CFR 
part 98, subpart OO and 40 CFR part 98, subpart L, EPA's goal is to 
optimize methods of data collection to ensure data accuracy while 
considering industry burden.

PP. Suppliers of Carbon Dioxide (CO2)

1. Summary of the Final Rule
    Source Category Definition. Under the rule, suppliers of 
CO2 consist of the following:
     Facilities with production process units that capture and 
supply CO2 for commercial applications or that capture and 
maintain custody of a CO2 stream in order to sequester or 
otherwise inject it underground.
     Facilities with CO2 production wells that 
extract a CO2 stream for the purpose of supplying 
CO2 for commercial applications.
     Importers of bulk CO2, if total combined 
imports of CO2 and other GHGs exceed 25,000 metric tons of 
CO2 equivalent (CO2e) per year.
     Exporters of bulk CO2, if total combined 
exports of CO2 and other GHGs exceed 25,000 metric tons 
CO2e per year.
    This source category is focused on upstream supply. It does not 
cover: Storage of CO2 above ground or in geologic 
formations; use of CO2 in enhanced oil and gas recovery; 
transportation or distribution of CO2; or purification, 
compression, on-site use of CO2 captured on site, or 
processing of CO2. This source category does not include 
CO2 imported or exported in equipment, such as fire 
extinguishers.
    Suppliers of CO2 that meet the applicability criteria in 
the General Provisions (40 CFR 98.2) summarized in Section II.A of this 
preamble must submit GHG reports.
    GHGs to Report. Suppliers of CO2 must report the mass of 
CO2 in a stream captured from production process units and 
extracted from production wells, and the mass of CO2 in 
containers that is imported and exported.
    GHG Emissions Calculation and Monitoring. While this source 
category is focused on upstream supply of CO2, EPA 
recognizes that all CO2 supplied to the economy does not 
necessarily result in an emission. There are a variety of downstream 
applications for CO2--some applications are emissive and 
some are non-emissive. Under this rulemaking, a CO2 supplier 
facility must calculate the mass of CO2 supplied quarterly 
by measuring the mass or volumetric flow of gas and multiplying by the 
CO2 concentration, and density in the case a volumetric flow 
meter is used, of the gas or liquid, as specified below. EPA requires 
quarterly monitoring because EPA has concluded that the CO2 
concentration of the stream varies throughout the year, and a quarterly 
concentration number multiplied by a quarterly volume will generate 
more accurate calculation of CO2 supply than annual 
measurements. EPA requires these quarterly numbers to be reported so 
that EPA can electronically verify the calculations. The CO2 
supplier must also provide information on the downstream CO2 
application, if known. Reporters must use the following methodologies, 
as applicable, for calculating CO2 supplied:
     For suppliers that make measurements with mass flow 
meters, calculate quarterly for each meter the total mass of 
CO2 in a CO2 stream in metric tons, prior to any 
subsequent purification, processing, or compressing, according to 
Equation PP-1 of 40 CFR 98.423. Measure mass flow and concentration in 
accordance with 40 CFR 98.424.
     For suppliers that make measurements with volumetric flow 
meters, calculate quarterly for each meter the total mass of 
CO2 in a CO2 stream in metric tons, prior to any 
subsequent purification, processing, or compressing, according to 
Equation PP-2 of 40 CFR 98.423. Measure volumetric flow, concentration 
and density in accordance with 40 CFR 98.424.
     For suppliers that have multiple flow meters, aggregate 
data according to methods specified in Equation PP-3 in 40 CFR 98.423.
     Importers or exporters that import or export 
CO2 in containers must calculate the total mass of 
CO2 supplied in metric tons, prior to any subsequent 
purification, processing, or compressing, according to equation PP-4 of 
40 CFR 98.423. Use weigh bills, scales, or load cells to measure the 
mass of CO2 imported or exported in containers.
    Data Reporting. In addition to the information required to be 
reported by the General Provisions (40 CFR 98.3(c)) and summarized in 
Section II.A of this preamble, reporters must submit additional data 
that are used to calculate CO2 supply. A list of the 
specific data to be reported for this source category is contained in 
40 CFR 98.426.
    Recordkeeping. In addition to the records required by the General 
Provisions (40 CFR 98.3(g)) and summarized in Section II.A of this 
preamble, reporters must keep records of additional data used to 
calculate CO2 supply. A list of specific records that must 
be retained for this source category is included in 40 CFR 98.427.
2. Summary of Major Changes Since Proposal
    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas

[[Page 56350]]

Reporting Rule: EPA's Response to Public Comments, Subpart PP: 
Suppliers of Carbon Dioxide.''
     We added equations and QA requirements to allow reporters 
to determine CO2 quantity using volumetric flow meters, 
weigh bills, scales, or load cells, as appropriate. These additions 
supplement the proposed equations and quality assurance requirements to 
determine CO2 quantity using mass flow meters.
     We revised the reporting procedures for missing data in 40 
CFR 98.425. Facilities must use quarterly values as substitute data as 
they can no longer use annual average values. We added missing data 
procedures to allow for more quarterly data points to be used, as 
appropriate. EPA concluded that quarterly missing data values will 
generate more accurate estimates than annual average values.
     To improve the emissions verification process, we 
reorganized and updated 40 CFR 98.426. We moved some data elements from 
40 CFR 98.427 to 40 CFR 98.426, and added some data elements that a 
reporter must already use to calculate GHGs as specified in 40 CFR 
98.423 to 40 CFR 98.426 for clarity.
     We revised the reporting and calculation procedures to 
require facilities using flow meters to determine annual mass for every 
flow meter used. To aggregate data at the facility level for 
CO2 being captured in production wells or production process 
units, we have added Equation PP-3.
     To decrease unnecessary sampling burden, we have removed 
the requirement of quarterly concentration sampling for importers and 
exporters that use containers of CO2.
3. Summary of Comments and Responses
    This section contains a brief summary of major comments and 
responses. A large number of comments on suppliers of CO2 
were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Subpart PP: Suppliers of 
Carbon Dioxide.''
Definition of Source Category
    Comment: EPA received many comments about how we defined the source 
category in this Subpart. One group of comments stated that the 
CO2 supplied to the economy should not be characterized as 
an emission. Some in this group of comments specified that much of the 
supplied CO2 is stored at enhanced oil recovery (EOR) sites, 
which are ``closed systems'', rather than emitted. In general, these 
same commenters stated that any CO2 reporting requirements 
placed by EPA on industry should be placed on downstream CO2 
users, such as EOR facilities, rather than CO2 suppliers and 
should be for actual emissions only. Other comments echoed that EPA 
needs to collect data from recipients of supplied CO2 such 
as EOR sites. This group pressed upon EPA the need to collect not only 
data on actual emissions but also data on injection, production, and 
geologic sequestration of CO2. Some of the benefits cited 
for collecting such comprehensive data include: Assisting in ensuring 
no more than negligible releases at a facility if it is properly sited, 
designed, and permitted; achieving full public accountability of 
CO2 geologic sequestration effectiveness; and tracking the 
CO2 throughout the entire carbon dioxide capture and 
sequestration (CCS) chain for the purposes of adjusting CO2 
emissions reported or assigning offsets. Along those lines, some 
commenters urged EPA to rely on or expand the existing underground 
injection control (UIC) program to deal with CCS.
    Response: EPA did not intend to characterize all CO2 
supplied to the economy as emissions and recognizes that there are a 
variety of applications for CO2, both emissive and non-
emissive. CO2 supplied to the economy would result in an 
emission if the CO2 were used in an application which would 
ultimately result in release of the CO2 to the atmosphere. 
EPA is also collecting information from upstream suppliers in other 
subparts of this rulemaking such as natural gas supply and petroleum 
product supply.
    EPA recognizes that, in order to determine whether or not supplied 
CO2 has been or will be released to the atmosphere (e.g., 
emitted), the Agency needs information on the downstream CO2 
end-use. In today's final rulemaking, CO2 suppliers must 
provide information on the downstream CO2 application, if 
known. EPA believes information on the end-use will provide some idea 
of the amounts of CO2 which are emitted. Where that end-use 
is geologic sequestration (at EOR or other types of facilities), EPA 
will need additional information on the amount of CO2 that 
is permanently and securely sequestered and on the monitoring and 
verification methodologies applied. With respect to EOR, the geology of 
an oil and gas reservoir can create a good barrier to trap 
CO2 underground. Because these formations effectively stored 
oil or gas for hundreds of thousands to millions of years, it is 
believed that they can be used to store injected CO2 for 
long periods of time. However, EPA also recognizes that the 
requirements to identify a suitable GS site extend beyond geophysical 
trapping parameters alone and include: The evaluation and appropriate 
management of potential leakage pathways, appropriate rate and pressure 
of injection, appropriate monitoring, and other such features. While 
some amount of CO2 injected into oil and gas reservoirs for 
EOR purposes will be trapped in the subsurface, these and other site-
specific elements influence the amount of CO2 securely 
sequestered and the potential for release of CO2 during EOR 
operations.
    Given the comments in support of downstream data collection, 
particularly with respect to EOR systems and CO2 geologic 
sequestration (at EOR or other types of facilities), EPA plans to issue 
a new proposal on geologic sequestration and will consider how to 
address emissions and sequestration at active EOR facilities. EPA will 
take action on this issue in the near future with the goal that data 
collection for these types of facilities can begin as quickly as 
possible. EPA will seek comment on monitoring, reporting, and 
verification methodologies which can be used to determine the amount of 
CO2 emitted and geologically sequestered at active EOR 
facilities and geologic sequestration sites where CO2 is 
injected (for long-term storage) into saline aquifers, oil and gas 
reservoirs, or other geologic formations. Furthermore, as stated in 
Section III.W of this preamble, EPA plans to take additional time to 
consider alternatives to data collection procedures and methodologies 
in the proposed 40 CFR part 98, subpart W and will consider inclusion 
of GHG reporting from other sectors of the oil and gas industry besides 
those proposed for reporting in proposed 40 CFR part 98, subpart W. EOR 
surface facility operations may be part of those considerations. The 
data reported under subsequent regulatory actions and the data reported 
under today's rulemaking will together enable EPA to understand the 
amount of CO2 supplied, emitted, and sequestered in the 
U.S., to carry out a wide variety of CAA provisions. The options that 
we will have considered and the resulting recommended approaches will 
be further fleshed out through a notice and comment process. See the 
next comment response for a discussion of why EPA still needs to 
collect CO2 supplier data in today's rulemaking even though 
a new rulemaking on sequestration is planned.
    In response to comments that EPA should rely on or expand the UIC 
program to address emissions of CO2,

[[Page 56351]]

that issue is outside the scope of this rulemaking. However, EPA agrees 
that the UIC program and EPA's authority under the Safe Drinking Water 
Act (SDWA) will provide a foundation for ensuring safe and effective 
containment of CO2. However, SDWA is focused on permitting 
sites for protection of ground and drinking water; the new proposal 
discussed above will be designed to address issues related to the CAA. 
EPA intends to harmonize CCS requirements across relevant statutory or 
other programs in order to minimize any redundancy and any burden on 
reporters. The reporting requirements in today's rulemaking for 
CO2 suppliers and the reporting requirements in new 
rulemaking for CO2 geologic sequestration sites will 
complement each other and together they can be harmonized with 
reporting requirements under the UIC proposed rulemaking. In a new CAA 
rulemaking on geologic sequestration reporting, EPA will rely on UIC 
permit requirements to the maximum extent possible. EPA will seek 
comment on these issues and will also endeavor to issue a geologic 
sequestration GHG reporting rule in the same time frame as it has 
planned for the stand-alone UIC GS rulemaking.
    Comment: EPA received comments requesting information on how 
CO2 supply will assist EPA in developing future climate 
policy. Commenters stated that they do not believe CO2 
supply data will provide EPA with useful information. Commenters stated 
that data collection from CO2 suppliers does not fit within 
EPA's mandate from Congress to measure upstream emissions only as 
appropriate.
    Response: As discussed in Sections I.C and II.Q of this preamble, 
EPA is collecting data from CO2 suppliers in today's rule to 
carry out a wide variety of CAA provisions, as authorized broadly under 
CAA Sections 114 and 208. For example, this data will enable EPA to 
evaluate the appropriate action to take under section 103 regarding 
non-regulatory strategies for pollution prevention. It will also inform 
evaluation of possible CAA regulation of the supplier and/or recipient 
of the CO2 Data on CO2 supply to the economy will 
allow EPA to make a well informed decision about whether and how to use 
the CAA to regulate facilities that capture, sequester, or otherwise 
receive CO2 as an end-user.
    Though CO2 capture and geologic sequestration are 
occurring now on a relatively small scale, CCS is expected to play a 
major role in mitigating GHG emissions from a wide variety of 
stationary sources. According to the Inventory of U.S. Greenhouse Gas 
Emissions and Sinks: 1990-2007 (EPA, April 2009), stationary sources 
contributed 67 percent of the total CO2 emissions from 
fossil fuel combustion in 2007. The stationary sources represent a wide 
variety of sectors amenable to CO2 capture; electric power 
plants (existing and new), natural gas processing facilities, petroleum 
refineries, iron & steel foundries, ethylene plants, hydrogen 
production facilities, ammonia refineries, ethanol production 
facilities, ethylene oxide plants, and cement kilns. Furthermore, 95 
percent of the 500 largest stationary sources are within 50 miles of a 
candidate CO2 reservoir.\22\
---------------------------------------------------------------------------

    \22\ Dooley, JJ, CL Davidson, RT Dahowski, MA Wise, N Gupta, SH 
Kim, EL Malone, ``Carbon Dioxide Capture and Geologic Storage: A Key 
Component of a Global Energy Technology Strategy to Address Climate 
Change.'' Joint Global Change Research Institute, Battelle Pacific 
Northwest Division. May 2006. PNWD-3602. College Park, MD.
---------------------------------------------------------------------------

    With this rule, EPA will begin building capacity to track the 
growth in CO2 supply and learn about its disposition 
throughout the economy. EPA has concluded that we need data now from 
CO2 suppliers--both industrial facilities and CO2 
production wells--in order to effectively track how the supply sources 
will change over time. For example, we will need to track if and by how 
much CO2 captured from industrial facilities will offset or 
displace CO2 produced from natural formations. Even after 
EPA begins collecting data on CO2 geologic sequestration 
under the proposed new rulemaking (discussed above), EPA will continue 
to need data from CO2 suppliers in order to track any 
CO2 that is not sequestered.
    Comment: EPA received some comments asking whether a specific 
situation results in coverage under 40 CFR part 98, subpart PP, and 
some comments requesting that their specific situation be exempt from 
coverage. For example, one commenter asked whether a facility 
separating CO2 that is not supplied to downstream customers 
is a covered facility. Another asked that a pulp and paper mill that 
transfers a CO2 stream to an adjacent facility by pipeline 
be exempt from 40 CFR part 98, subpart PP. Several commenters requested 
clarification on specific scenarios such as taking ownership of an 
already separated CO2 stream for further processing, 
separating CO2 for their own use, and operating versus 
owning the separation unit.
    Response: EPA did not intend for 40 CFR part 98, subpart PP to 
cover facilities that take ownership of a CO2 stream that 
has already been separated and removed from a manufacturing process or 
that has already been extracted from CO2 production wells in 
order to do any of the following: Store it in above ground storage of 
CO2; transport or distribute it via pipelines, vessels, 
motor carriers, or other means; purify, compress, or process it; or 
sell it to other commercial applications. 40 CFR part 98, subpart PP 
covers facilities that own or operate the equipment that physically 
separates and removes CO2 from an industrial or 
manufacturing process or physically extracts CO2 from 
production wells because we concluded that the entity with first touch 
of the CO2 supply was the most logical point of coverage. We 
wanted to minimize any unnecessary duplicative reporting of the same 
CO2 by being as specific as possible about who in the supply 
chain is responsible for reporting it.
    We did not intend for this source category to include facilities 
that capture CO2 for further processing or use within the 
fence line of the facility (e.g., for their own use). EPA proposed that 
40 CFR part 98, subpart PP only cover CO2 that is captured 
or extracted for purposes of sequestration or supply to other 
facilities for commercial applications because we concluded that 
CO2 captured and used on-site is equivalent to an 
intermediary step in production rather than an actual supply of 
CO2.
    Comment: EPA received a comment requesting that ethanol plants and 
other facilities capturing CO2 from biomass be exempt from 
Subpart PP.
    Response: A long standing inventory convention adopted by the IPCC, 
the UNFCCC, the US GHG Inventory, and many other reporting programs is 
separate treatment of emissions of CO2 from the combustion 
of biomass and biomass-based fuels from emissions of CO2 
from the combustion of fossil-based products. In national inventories, 
emissions from the combustion of biomass-based fuels are accounted for 
as part of a comprehensive system-wide tracking of carbon dioxide 
emissions and sequestration in the land-use, land-use change and 
forestry sector and the agriculture sector, rather than at the point of 
fuel combustion. Consistent with this approach, in the proposed and 
final rule, downstream emitters must only consider non-biogenic 
emissions when conducting a threshold analysis; however, downstream 
emitters must report both biogenic and non-biogenic emissions once they 
trigger the reporting threshold because data on non-biogenic emissions 
is useful and informative.
    For the final rule, EPA has decided not to apply the same approach 
to

[[Page 56352]]

suppliers of CO2. We have concluded that data on capture of 
biogenic CO2 would be useful and informative because 
biogenic CO2 can potentially be stored in GS sites, or 
displace fossil CO2 applications. We need a full picture of 
the CO2 being supplied into the economy. Though 
CO2 capture and sequestration is occurring now on a 
relatively small scale, it is expected to play a major role in 
mitigating GHG emissions. Therefore information on all potential 
sources of CO2 for sequestration is necessary for a complete 
picture. Thus, a facility that captures CO2 from biomass and 
otherwise meets the applicability test is covered under 40 CFR part 98, 
subpart PP and is required to report all CO2 supplied along 
with the percentage of that supply that is biomass-based.
Monitoring and QA/QC Requirements
    Comment: A large number of commenters requested that volumetric 
flow meters be allowed for purposes of calculating CO2 
supply in place of or in addition to mass flow meters. These comments 
indicated that mass flow meters are not in operation at many covered 
facilities, and the cost to comply with such an equipment requirement 
would be unnecessarily high. Some commenters suggested that reporters 
should be allowed to use sales contracts to determine quantity of 
CO2 as long as the CBI is protected. Some commenters 
indicated that CO2 liquefaction and purification facilities 
do not operate flow meters for the course of usual business. One of 
these also commented that importers and exporters of CO2 do 
not operate flow meters for the course of usual business if they handle 
the product in containers and requested consideration of this 
incongruity.
    Response: As a result of these comments, EPA added two equations to 
the methodology section of 40 CFR part 98, subpart PP in today's rule 
in order to ensure that all covered CO2 can be reported, 
irrespective of technical or physical conditions. Therefore, a reporter 
that measures CO2 in a stream using a volumetric flow meter 
may use this volumetric flow meter to determine quantity rather than 
having to purchase and install a mass flow meter. EPA has concluded 
that providing this additional methodology reduces the burden on 
reporters without compromising the quality of data received by the 
agency. In addition, a reporter that imports or exports CO2 
in containers may use weigh bills, scales, or load cells to determine 
quantity because applying a mass flow meter would be technically 
impossible. EPA has concluded that providing this additional 
methodology reduces the burden on reporters without compromising the 
quality of data received by the agency.
    The final rule does not require reporting from facilities that 
liquefy or purify CO2 that has already been separated or 
removed from a manufacturing process or already extracted from 
production wells. Therefore we did not give consideration to the types 
of equipment in operation at such facilities.
    Finally, the rule does not allow reporters to use sales contracts 
to determine quantity because EPA has concluded that reporters 
capturing or extracting CO2 already operate mass or 
volumetric flow meters, or already determine quantities of 
CO2 imported or exported in containers using weigh bills, 
scales, or load cells. EPA has concluded that mass and volumetric flow 
meters provide more accurate data than sales contracts.

IV. Mobile Sources

A. Summary of Requirements of the Final Rule

    For manufacturers of engines used in mobile sources outside of the 
light-duty sector,\23\ this rule includes new requirements for 
reporting emission rates of GHGs.\24\ Mobile source engine 
manufacturers have been measuring CO2 emission rates from 
their products for many years as a part of normal business practices 
and existing criteria pollutant emission certification programs, but 
they have not consistently reported these values to EPA. This final 
rule requires manufacturers to consistently measure and report 
CO2 for all engines beginning with model year 2011 and other 
GHGs in subsequent model years.\25\ Manufacturers meeting the 
definitions of ``small business'' or ``small volume manufacturer'' 
under EPA's existing mobile source emissions regulations will generally 
be exempt from any new GHG reporting requirements.\26\
---------------------------------------------------------------------------

    \23\ Manufacturers of light-duty vehicles, light-duty trucks, 
and medium-duty passenger vehicles are not covered in this final 
rule.
    \24\ The term ``manufacturer,'' as well as the term 
``manufacturing company,'' as used in this preamble, means companies 
that are subject to EPA emission certification requirements. This 
primarily includes companies that manufacture engines domestically 
and foreign manufacturers that import engines into the U.S. market. 
In some cases this also includes domestic companies that are 
required to meet EPA certification requirements when they import 
foreign-manufactured engines.
    \25\ For aircraft engine manufacturers, reporting requirements 
will apply for the engine models in production in 2011.
    \26\ Small business manufacturers will continue to be subject to 
measurement and/or reporting requirements for compliance with 
existing regulations.
---------------------------------------------------------------------------

    In addition to CO2, most manufacturers will now be 
required to report on two other major GHGs emitted by mobile sources, 
nitrous oxide (N2O) and methane (CH4). Although 
most current engines have relatively low emission rates of these GHGs 
compared to CO2, these compounds have global warming 
potentials significantly higher than CO2. It is important 
that EPA improve its understanding of these emissions from today's 
engines and monitor trends over time. The broad base of emission data 
that will begin to accrue from requirements in this rule will support 
emissions modeling by EPA and others, and will help guide future GHG 
policy.
    Emissions of N2O are related to catalytic treatment of 
engine exhaust, specifically aftertreatment of NOX 
emissions. Therefore, we will require that manufacturers begin to 
measure and report N2O emissions, but only for engine models 
that incorporate NOX aftertreatment technology (as shown in 
Table IV-1 of this preamble). The program will not require 
N2O reporting before model year 2013, and the requirements 
will only apply to new engines equipped with NOX 
aftertreatment technology. (Manufacturers of some engine categories 
have employed aftertreatment for many years to meet NOX 
standards; for other engine categories, manufacturers are unlikely to 
introduce NOX aftertreatment technologies for some years to 
come.)
    Emissions of CH4 are a part of overall hydrocarbon 
emissions from mobile sources. Because CH4 is not very 
reactive in the atmosphere, EPA has often excluded CH4 from 
mobile source hydrocarbon regulations since it has not traditionally 
been a major determinant of ozone formation.\27\ The new reporting 
requirements are necessary to evaluate the magnitude of mobile source 
CH4 emissions from a GHG (rather than ozone precursor) 
perspective.
---------------------------------------------------------------------------

    \27\ But see Ford Motor Co. v. EPA, 604 F. 2d 685 (D.C. Cir. 
1979) (permissible for EPA to regulate CH4 under CAA 
section 202 (b)). In addition, although CH4 is not itself 
regulated, manufacturers subject to ``non-methane hydrocarbon'' 
standards have needed to determine CH4 emission levels, 
in some cases by using a default value and in many cases by way of 
testing.
---------------------------------------------------------------------------

    As described above, we are finalizing manufacturer reporting 
requirements for N2O and CH4 emission rates in 
order to understand current emissions of these GHGs and to monitor 
potential changes as technologies and policies change in the future. 
However, we believe that manufacturers may be able to provide

[[Page 56353]]

alternative test data (and/or other information including engineering 
judgments based on test data) that would give EPA a reasonable basis 
for estimating the likely N2O and CH4 emission 
rates for each certified engine family. Therefore, we are including a 
provision in this final rule that would allow a manufacturer the 
opportunity to provide such alternative information in lieu of 
N2O and/or CH4 test data for each engine family.
    In assessing such alternative information, EPA would consider how 
well the information provided by the manufacturer allows EPA to 
reasonably anticipate the emission performance of each of the 
manufacturer's engines. For example, we expect that in most cases a 
manufacturer wishing to omit engine testing will provide EPA with 
N2O test data from relevant testing programs (by such 
sources as industry collaboratives and/or from the suppliers of the 
catalytic NOX aftertreatment systems they are using on an 
engine. We would expect the manufacturer to also include an explanation 
of the manufacturer's engineering judgment as to why the data should 
apply to the engine family in question. For CH4 emissions, 
our primary concern is the potential for unusually high emissions from 
natural gas fueled engines. Thus, we expect that in most cases a 
manufacturer of such an engine will provide test data on similar 
engines with similar catalyst systems for hydrocarbon control (with an 
explanation of their engineering judgment as to why the data should 
apply to that engine family).
    The reporting requirements related to C3 marine engines and 
turbofan and turbojet aircraft engines differ from other engine 
categories. As with other manufacturers, C3 marine engine and aircraft 
engine manufacturers will report CO2 emission rates 
beginning in 2011 (for aircraft engines, they will report 
CO2 separately for each mode of the landing and take-off 
(LTO) cycle used in the certification test, as well as the entire LTO 
cycle). For aircraft engine manufacturers, however, the reporting 
requirements will apply not just to engines introduced in that year, 
but for all engines still in production. (This should not require 
manufacturers to conduct any new testing, only to report existing 
data.) We are not requiring manufacturers of C3 marine engines and 
aircraft engines to measure or report N2O or CH4 
emission rates because of unique aspects of their industries and 
technologies.
    C3 marine engines are very large and manufacturers generally test 
them as they are installed into ships rather than in a laboratory 
setting. For this reason, we have determined that requiring the 
addition of new N2O and CH4 measurement equipment 
for C3 engines would not be practical, and, as proposed, are not 
requiring such reporting in this rule.
    Since aircraft engine manufacturers are unlikely to employ 
NOX after treatment devices in the foreseeable future, we 
did not propose requiring N2O reporting from aircraft 
engines and are not finalizing any requirements in this final rule. We 
are not finalizing our proposed requirement that aircraft engine 
manufacturers measure and report CH4, as we learned that 
aircraft jet turbine engines have been shown to consume CH4 
from the ambient air during the dominant operating modes.\28\ However, 
unlike NOX emissions from most mobile sources, 
NOX emissions from aircraft have been shown to make a 
potential contribution to climate change.\29\ For this reason, we are 
requiring that aircraft engine manufacturers report the NOX 
emission data for the LTO modes and the overall LTO cycle for all 
engine models currently in production, and for new engines as they are 
introduced. Manufacturers are already measuring NOX as part 
of current criteria pollutant certification requirements. 
NOX emissions rate data from LTO modes will support modeling 
of overall NOX emissions from aircraft.
---------------------------------------------------------------------------

    \28\ Aerodyne, Rich Miake-Lye, AAFEX Methane presentation at the 
Seventh Meeting of Primary Contributors for the Aviation Emissions 
Characterization Roadmap, June 9-10, 2009.
    \29\ IPCC, Aviation and the Global Atmosphere, 1999, at http://www.grida.no/climate/ipcc/aviation/index.htm, and NOAA, Written 
Testimony of Dr. David W. Fahey, Hearing on ``Aviation and the 
Environment: Emissions,'' Before the Committee on Transportation and 
Infrastructure, Subcommittee on Aviation, U.S. House of 
Representatives, May 6, 2008.
---------------------------------------------------------------------------

    For all engine categories, when a manufacturer certifies the engine 
in one year and then carries over the certification to subsequent 
years, EPA will not require re-testing of that engine model for 
reporting purposes.
    As proposed, we are not including any requirements for mobile 
source fleet operators or State and local governments to report in-use 
travel activity or other emissions-related data in this final rule.
    Table IV-1 of this preamble shows the basic reporting requirements 
we are finalizing in this notice for each engine category. We discuss 
in more detail how these reporting requirements will apply to 
manufacturers of each engine category in ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments, Motor Vehicle and 
Engine Manufacturing.''

                           Table IV-1--First Model Year for GHG Reporting Requirements
----------------------------------------------------------------------------------------------------------------
           Engine category                   CO2                         N2O\a\                         CH4
----------------------------------------------------------------------------------------------------------------
Highway Heavy-Duty (engine and                   2011  2013 or NOX AT...........................            2012
 vehicle).
Nonroad Diesel.......................            2011  2013 or NOX AT...........................            2012
Marine Diesel (other than C3)........            2011  2013 or NOX AT...........................            2012
C3 Marine............................            2011  None.....................................            None
Locomotives..........................            2011  2013 or NOX AT...........................            2012
Small Spark-Ignition.................            2011  2013 or NOX AT...........................            2012
Large Spark-Ignition.................            2011  2013 or NOX AT...........................            2012
Marine Spark-Ignition................            2011  2013 or NOX AT...........................            2012
Snowmobiles..........................            2011  2013 or NOX AT...........................            2012
Highway Motorcycles..................            2011  2013 or NOX AT...........................            2012
Off Highway Motorcycles/ATVs.........            2011  2013 or NOX AT...........................            2012
Aircraft \b\.........................            2011  None.....................................            None
----------------------------------------------------------------------------------------------------------------
\a\ N2O reporting for new engines begins in 2013 or when the manufacturer introduces NOX aftertreatment
  technology, whichever is later.
\b\ Applies to all turbofan and turbojet engines in production in 2011 with a rated output greater than 26.7
  kilonewtons. Reporting of NOX also required.


[[Page 56354]]

B. Summary of Major Changes Since Proposal

    The major changes since proposal are identified in the following 
list. The rationale for these and any other significant changes can be 
found below or in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Motor Vehicle and Engine Manufacturers.''
     We are not finalizing the proposed requirements related to 
light-duty vehicles (including light-duty trucks and medium-duty 
passenger vehicles). EPA expects to propose a comprehensive light-duty 
GHG emission control program commencing in MY 2012 (see Notice of 
Upcoming Joint Rulemaking to Establish Vehicle GHG Emissions and CAFE 
Standards, 74 FR 24007 (May 22, 2009)), which is likely to contain 
monitoring, reporting and GHG data retention requirements that would 
supersede any reporting requirements established in this rule. 
Eliminating light-duty reporting requirements from this final rule will 
avoid issues of inconsistency and duplication.
     We have revised our proposal that all engine manufacturers 
measure and report N2O for all of their engines, and instead 
will require N2O reporting only for engines that use 
NOX exhaust aftertreatment technology.
     We have delayed the proposed MY 2011 start year for 
N2O reporting until MY 2013, and later for categories where 
the manufacturer has not applied NOX aftertreatment 
technology.
     We have added additional emission test methods that 
manufacturers can choose for measuring N2O, to assure that 
an appropriate method is available for any foreseeable circumstance 
(including the need to measure very low N2O emission rates).
     The final rule incorporates an opportunity for a 
manufacturer to provide EPA with appropriate alternative information in 
lieu of N2O and/or CH4 testing, as described 
above.
     We have added one year of lead time to the proposed start 
year for reporting of CH4 emissions, until 2012.
     We are not finalizing our proposal to require reporting of 
CH4 for aircraft engines because, for the dominant operating 
modes, jet engines may consume CH4 in the air.
     We are finalizing a requirement that we took comment on in 
the proposal to have aircraft engine manufacturers report 
NOX emissions data they already collect, since, at altitude, 
NOX emissions from aircraft have been shown to make a 
potential contribution to climate change.
     Since aircraft engines are not certified every year (there 
is no annual certification as is the case with other mobile sources), 
we have removed references to ``model year'' in the regulations and 
revised them to reflect the change to a January 1, 2011 start date for 
reporting CO2 and NOX emissions.

C. Summary of Comments and Responses

    This section contains a brief summary of major comments and 
responses. A large number of comments on mobile source were received 
covering numerous topics. Responses to significant comments received 
can be found in ``Mandatory Greenhouse Gas Reporting Rule: EPA's 
Response to Public Comments, Motor Vehicle and Engine Manufacturers.''
    Comment: Light-duty vehicle manufacturers and their trade 
organizations raised several concerns about the timing and nature of 
the reporting requirements.
    Response: We agree in part with these comments. However, more 
fundamentally, we have concluded that the likelihood of GHG emission 
regulations affecting light-duty vehicles (including light-duty trucks 
and medium-duty passenger vehicles) in the near future argues for 
consolidating any new GHG reporting requirements into that upcoming 
rule. Therefore, we have elected to not finalize the proposed 
requirements relating to these vehicles at this time, and expect to 
incorporate similar provisions in a proposed rule on GHG standards for 
light-duty vehicles in the near future.
    Comment: Engine manufacturers and their trade organizations 
challenged the proposed rule in several ways. In general, they 
questioned the need for the data to be reported; expressed concern that 
the proposed timing of the requirements, especially for N2O 
and CH4, was too aggressive; and commented that the proposed 
test procedure for N2O was not adequate.
    Response: We still conclude that there is significant value to 
collecting CO2, N2O, and CH4 emissions 
rate data on the broad range of mobile sources being produced. As 
stated earlier, the domestic and international attention to GHGs and 
their effects will only grow, and the ability for EPA and the public to 
understand and monitor emissions from mobile sources will be 
increasingly important as policies relating to GHGs are considered. 
Collecting emissions rate data from engine manufacturers on their new 
engines can improve modeling of emissions for the entire mobile source 
sector since current modeling relies on assumptions about 
N2O and CH4 emissions based on a limited number 
of field surveys. The data from this rule will also help EPA track 
emissions impacts from changes in technologies and policies over time.
    For N2O and CH4, we agree that revisions in 
the proposed provisions are warranted. We have limited the reporting 
requirements for N2O to engines equipped with NOX 
aftertreatment technology as a way to reduce the reporting burden on 
engine manufacturers without significantly diminishing the amount of 
information we receive. As discussed earlier, emissions of 
N2O are related to catalytic treatment of engine exhaust, 
specifically aftertreatment of NOX emissions, and we have 
concluded that collecting N2O emissions data from engines 
without NOX aftertreatment technology would provide marginal 
value to the agency. We expanded the number of approved test methods 
for N2O measurement since we learned from comments and our 
own technical research that our proposed test methods for 
N2O were not appropriate for every foreseeable circumstance, 
including measurement of very low levels of N2O. We also 
extended the lead time available to manufacturers before N2O 
and CH4 reporting is required. We are providing this 
flexibility based on our conclusion that we can reduce the burden of 
purchasing and installing the required CH4 and 
N2O emissions rate measurement equipment by extending the 
lead time, without significantly diminishing the amount of information 
we receive. Finally, as described above, the final rule includes an 
opportunity for a manufacturer to provide EPA with appropriate 
alternative information in lieu of N2O and/or CH4 
testing.
    Comment: States and environmental organizations were generally 
supportive of the proposed reporting requirements, although some argued 
for earlier implementation, in 2010.
    Response: We believe that the lead times we are finalizing for each 
GHG and for each engine category represent the earliest feasible 
timing, taking into consideration existing test capabilities and past 
experience, or the lack thereof.
    Comment: Aircraft engine manufacturers commented that reporting of 
CO2 emissions from each mode of the LTO \30\ cycle used in 
the emission certification test, as proposed, is acceptable as long as 
existing methods for CO2 are retained. In particular, 
commenters noted that reporting would result in minimal

[[Page 56355]]

burden as long as CO2 is calculated utilizing the engine 
fuel mass flow rate measurements, which are currently part of the test 
procedure requirements for the LTO cycle. However, an industry trade 
association expressed concern that reporting CO2 from the 
LTO cycle is unjustified because LTO measurements do not include 
CO2 emissions from an entire aircraft flight, which is 
affected by the propulsion system, drag, etc.
---------------------------------------------------------------------------

    \30\ Modes of the landing and takeoff cycle are taxi/idle, 
takeoff, climb out, and approach.
---------------------------------------------------------------------------

    Response: We determined that calculating aircraft engine 
CO2 emissions from fuel mass flow rate measurements is an 
appropriate method for reporting CO2 emissions. Therefore, 
for turbofan and turbojet engines of rated output greater than 26.7 
kilonewtons, we are finalizing that manufacturers report CO2 
separately for each mode of the LTO cycle by calculation of 
CO2 from fuel mass flow rate measurements or, alternatively, 
according to the measurement criteria for CO2 in Appendices 
3 and 5 to ICAO Annex 16, volume II. Comprehensive and consistent 
reporting of LTO CO2 emissions, along with knowledge of 
aircraft aerodynamic performance, will support modeling of full-flight 
CO2 emissions and help us to better understand overall 
contributions to global warming from aircraft operations.
    Comment: Aircraft engine manufacturers raised two major issues 
related to our proposed CH4 reporting. First, in response to 
EPA's request for comment on the degree to which engine manufacturers 
now have the needed equipment in their certification test cells to 
measure CH4, manufacturers replied that test stands are not 
currently equipped to measure CH4, and thus, they would 
incur additional costs to measure CH4. Second, manufacturers 
noted that aircraft jet turbine engines have been shown to be consumers 
of CH4 from the ambient air during the dominant operating 
modes (CH4 is emitted at aircraft engine idle operation, but 
at higher power modes aircraft engines usually consume CH4. 
Over the range of engine operating modes--including cruise--aircraft 
engines are typically net consumers of CH4).
    Response: Given that aircraft engines are likely net consumers of 
CH4 and that manufacturers do not currently collect 
CH4 data as part of existing test procedures, we are not 
requiring CH4 to be measured and reported at this time.
    Comment: We received several responses to our request for comment 
on whether to require aircraft engine manufacturers to report 
NOX emissions in the four LTO test modes and for the overall 
LTO cycle. Manufacturers commented that NOX emissions do not 
need to be reported directly to EPA, since this information is already 
voluntarily reported to the International Civil Aviation Organization 
(ICAO) and provided to the Federal Aviation Administration (FAA), and 
redundancy of reporting is unnecessary. Environmental organizations 
commented that EPA should require manufacturers to report 
NOX since they currently do not report the data to EPA. In 
addition, environmental organizations commented that NOX at 
high altitude can contribute to global warming.
    Response: In this final rule, we are requiring that engine 
manufacturers of turbofan and turbojet engines of rated output greater 
than 26.7 kilonewtons record and report NOX emissions in the 
four LTO test modes and for the overall LTO cycles. As discussed in the 
proposal and earlier in this final rule, NOX from aircraft 
have been shown to make a potential contribution to climate change at 
high altitude. As required in 40 CFR part 87, manufacturers must 
already measure and record NOX emissions in each of the four 
LTO test modes in order to comply with the LTO NOX emission 
standard (for the entire LTO cycle). These data are not currently 
reported to EPA for public consideration as is the case with all other 
mobile sources. Manufacturers voluntarily report the data to ICAO, but 
there is no assurance that EPA will receive this information. Likewise, 
the information provided to FAA is not readily accessible to EPA, and 
it is not of the detail provided to ICAO. Comprehensive and consistent 
reporting of LTO NOX emissions rate data will support 
modeling of overall NOX emissions from aircraft and help us 
to better understand overall contributions to global warming from 
aircraft operations.

V. Collection, Management, and Dissemination of GHG Emissions Data

    This section of the preamble describes the general processes by 
which EPA intends to collect, manage, and disseminate data under the 
GHG reporting rule. Section A contains a brief description of the 
provisions in the final rule concerning these processes, and Section B 
summarizes public comments and responses on data collection, 
management, and dissemination.
    Major changes since proposal include revisions in 40 CFR 98.4 that 
provide flexibility for designated representatives to delegate their 
responsibility to agents, and to submit revisions to the certificate of 
representation within 90 days of a change in owners or operators 
(rather than 30 days). In addition, the final rule includes a 
requirement that the designated representative submit the certificate 
of representation at least 60 days before the deadline of the facility 
or supplier's initial GHG report. The rationale for these and any other 
significant changes can be found in Section V.B of this preamble or in 
``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to Public 
Comments, Designated Representative, and Data Collection, Reporting, 
Management, and Dissemination.''

A. Summary of Data Collection, Management and Dissemination for the 
Final Rule

1. Designated Representatives, Alternate Designated Representatives, 
and Agents
    Each covered facility and each supplier must identify one and only 
one designated representative who is responsible for certifying, 
signing, and submitting all submissions to EPA. A designated 
representative must certify and sign a submission, in accordance with 
the final rule, before it is considered a complete submission.
    The designated representative also serves as a single point of 
contact for EPA to provide information about the program or a 
submission or to ask questions about a submission. Those facilities 
submitting any other emission report under 40 CFR part 75, for example, 
ARP facilities, must use the same designated representative for 
certifying, signing and submitting all submissions and reports under 
this rule.
    Each covered facility or supplier may also identify one alternate 
designated representative to act in lieu of the designated 
representative. The alternate designated representative can perform the 
same duties as the designated representative, but the designated 
representative is responsible for ensuring the appropriate information 
is submitted to EPA by the timelines specified in the rule.
    A designated representative or alternate designated representative 
may delegate the submission of information to one or more ``agents.'' 
The agent can make electronic submissions to EPA, but is not allowed to 
certify or sign a submission. By delegating to an agent the ability to 
make electronic submissions to EPA, a designated representative or 
alternate designated representative agrees that a submission to EPA by 
the agent is deemed to be a submission that is certified, signed, and 
submitted by such designated representative or alternate designated 
representative.

[[Page 56356]]

2. Certificate of Representation
    A designated representative must submit a certificate of 
representation that identifies the owners and operators of the facility 
or supplier, the designated representative, any alternate designated 
representative, and other information as specified in 40 CFR 98.4. EPA 
will establish an electronic data reporting system that provides for 
the submission of initial, as well as subsequently signed, certificates 
of representation.
    In order to ensure sufficient processing time before a facility or 
supplier's initial GHG report under this part, EPA is requiring that 
the designated representative submit a certificate of representation at 
least 60 days before the deadline for the initial GHG report.
3. Data Collection
    Methods. If a reporting entity already reports GHG emissions data 
to an existing EPA program, the Agency will make efforts to minimize 
any additional burden on the reporter when developing the reporting 
system for the final rule. Some existing programs, however, have data 
collection and reporting requirements that are inconsistent with the 
requirements for the mandatory GHG reporting rule. When it is not 
feasible to adapt an existing program to collect the appropriate GHG 
data and supplemental data, EPA will require reporters to submit the 
data required by the mandatory GHG reporting rule to the new data 
reporting system for this rule. Such reporters would also continue to 
submit data to the existing reporting systems for other applicable 
programs as required by those programs.
    Reporters may fall into one or more categories:
    (1) Reporters that use existing data collection and reporting 
methods and will not be required to report separately to the new data 
reporting system for the GHG reporting rule.
    (2) Reporters that use existing data collection and reporting 
methods but will be required to report the data separately to the new 
data reporting system for the GHG reporting rule.
    (3) Reporters that are not currently required to collect and report 
GHG emissions data to EPA and will be required to report using the new 
data reporting system for the mandatory GHG reporting rule.
    For categories (2) and (3), EPA is developing a new system for 
reporters to submit the required data. The detailed data elements that 
must be reported are specified in the rule. In general, reporters using 
this new system must report annually to the Agency according to the 
schedule specified in 40 CFR 98.3(b).
    Data Submission. The Designated Representative (described in 40 CFR 
98.4) must use an electronic signature device (for example, a personal 
identification number (PIN) or password) to submit a report. If the 
Designated Representative holds an electronic signature device that is 
currently used for valid electronic signatures accepted under another 
Agency program, we intend to design the new reporting system to also 
accept valid electronic signatures executed with that device where 
feasible. (See 40 CFR 3.10 and the definitions of ``electronic 
signature device'' and ``valid electronic signature'' under 40 CFR 
3.3.)
    Unique Identifiers for Facilities and Units. The Agency's reporting 
format for a given reporting year could make use of several ID codes--
unique codes for a unit or facility. To ensure proper matching between 
databases, e.g., EPA-assigned facility ID codes and the Office of 
Regulatory Information Systems (ORIS) (DOE) ID code, and consistency 
from one reporting year to the next, we plan for the reporting system 
to provide each facility with a unique identification code to be 
specified by the Administrator.
    Reporting Emissions in a Single Unit of Measure. To maintain 
consistency with existing State-level and Federal-level GHG programs in 
the U.S. and internationally, all emission measurements must be 
reported in the SI, also referred to as metric units. Data used in 
calculations and supplemental data for QA could still be submitted in 
English weights and measures (e.g., mmBtu/hr) but the specific units of 
measure must be included in the data submission. All emissions data 
must be submitted to the Agency in kg or metric tons per unit of time.
    Conversion of Emissions to CO2e. Reporters must submit the quantity 
of each applicable GHG emitted (or other metric such as quantities 
supplied for industrial GHG suppliers) in two forms. The data will be 
in the form of quantity of the gas emitted (e.g., metric tons of 
N2O) per unit of time and CO2e emissions per unit 
of time.
    Delegation of Authority to State Agencies to Collect GHG Data. 
Reporters must submit the emissions data and supplemental data directly 
to EPA. At this time, EPA does not intend to delegate the authority to 
collect data to State or local agencies.
    Submission Method. All entities covered by this rule must report in 
an electronic format to be specified by the Administrator. The 
electronic format, which will reflect the underlying electronic data 
reporting system, will be developed prior to the first reporting date. 
By specifying in the rule text the exact information that must be 
reported but not specifying the exact reporting format, EPA informs 
reporters about exactly what information they must report and has 
flexibility to modify the electronic reporting format and electronic 
data reporting system in a timely manner based on implementation 
experience and new technology. EPA has used this approach successfully 
in existing programs, such as the ARP and the Title VI Stratospheric 
Ozone Protection Program, facilitating the deployment of new reporting 
formats and reporting systems that take advantage of technologies such 
as, eXtensible Markup Language (XML), and reducing the burden on 
reporters and the Agency. The electronic reports submitted under this 
rule are subject to the provisions of 40 CFR part 3, specifying EPA 
systems to which electronic submissions must be made and the 
requirements for valid electronic signatures.
4. Data Management
    QA Procedures. The new reporting system will include automated 
checks for data completeness, data quality, and data consistency. Such 
automated checks are used for many other Agency programs (e.g., ARP).
    Providing Feedback to Reporters. EPA has established a variety of 
mechanisms under existing programs to provide feedback to reporters who 
have submitted data to the Agency. EPA will consider the approaches 
used by other programs (e.g., electronic confirmations, results of QA 
checks) and develop appropriate mechanisms to provide feedback to 
reporters for the GHG reporting rule when we develop the electronic 
data reporting system. Regardless of data collection system specifics, 
the goal is to ensure appropriate transparency and timeliness when 
providing feedback to reporters who submitted data.
5. Data Dissemination
    Public Access to Emissions Data. The Agency plans to publish data 
submitted or collected under this rulemaking through EPA's Web site, 
reports, and other formats (e.g., XML), with the exception of any 
confidential business information (CBI) data. For further discussion of 
CBI, see Section II.R of this preamble.
    EPA will disseminate data after the reporting deadline. The Agency 
recognizes the high level of public interest in this data and plans to 
disclose it in a timely manner, while

[[Page 56357]]

also assuring completeness and accuracy.
    Sharing Emission Data with Other Agencies. There are a growing 
number of programs at the State, Tribe, Territory, and local level that 
require emission sources in their respective jurisdictions to monitor 
and report GHG emissions. In order to be consistent with and supportive 
of these programs and to reduce burden on reporters and program 
agencies, EPA plans to share emissions data, with the exception of any 
CBI data, with relevant agencies or approved entities using, where 
practical, common data exchange standards and infrastructure.

B. Summary of Comments and Responses on Collection, Management, and 
Dissemination of GHG Emissions Data

    This section contains a brief summary of major comments and 
responses. A large number of comments on data collection, management, 
and dissemination were received covering numerous topics. Responses to 
significant comments received can be found in ``Mandatory Greenhouse 
Gas Reporting Rule: EPA's Response to Public Comments, Designated 
Representative and Data Collection, Reporting, Management, and 
Dissemination.''
1. Designated Representatives, Alternative Designated Representatives, 
and Agents

Designated Representatives

    Comment: Several commenters requested that EPA use the ARP 
definition for designated representatives to maintain consistency 
across the two EPA programs and provide more flexibility regarding who 
can be a designated representative. Other commenters requested that EPA 
use the responsible official definition from Title V or senior 
management official from TRI to maintain consistency with those 
programs. Other commenters raised concerns over the employment status 
of designated representatives.
    Comment: A commenter noted that rule language was inconsistent in 
defining the relationships between designated representatives, 
facilities and suppliers, and owners and operators.
    Response: EPA agrees that owners and operators should have more 
flexibility to identify a designated representative, including third-
party representatives. EPA is striking the language requiring the 
designated representative to be a person responsible for the overall 
operation of the facility or supplier. Further, EPA is not requiring 
the use of a responsible official or senior management official because 
either approach would be more restrictive than the designated 
representative definition of the final rule. EPA believes that the 
proposed rule was neutral with respect to the employment status of the 
designated representative. The final rule provides flexibility for the 
owners and operators to choose any individual, employee or non-
employee, to represent them. EPA modified the rule to clarify that each 
facility and each supplier shall have one and only one designated 
representative and that the designated representative must be 
authorized by binding agreement of the owners and operators.

Agents

    Comment: Several commenters requested that EPA allow designated 
representatives and alternate designated representatives the option of 
delegating their responsibility to prepare and submit reports to EPA to 
a preparer or agent. Commenters also stated that the designated 
representative requirement is inconsistent with Title V reporting.
    Response: EPA agrees that it is beneficial to give the designated 
representatives and alternate designated representatives flexibility 
concerning who prepares the reports that they are responsible for 
submitting. The final rule does not specify who must prepare reports, 
but only specifies who must certify, sign, and submit them. EPA also 
agrees that flexibility should be provided concerning who actually 
submits the reports, similar to the flexibility provided in the ARP. 
This flexibility was implied in the provision in the proposed rule that 
reports be submitted ``in a format specified by the Administrator,'' 
which format has included, in other programs such as the ARP, the 
ability to use agents. However, EPA decided to make this flexibility 
explicit by including in the rule provisions allowing and setting 
requirements for agents selected by designated representatives or 
alternate designated representatives. The structure of designated 
representative, alternate designated representative and agent fits a 
wide range of circumstances from large companies to small, including 
those accustomed to reporting under Title V.

Certification Statement

    Comment: Several commenters described the self-certification 
procedures in the proposed rule as too restrictive or suggested that 
the rule should be consistent with requirements of the Title V or TRI 
program. For example, the rule's requirement that the designated 
representative certify that they have ``personally examined'' the data 
should be replaced by the Title V requirement that a responsible 
official certify that they have made a ``reasonable inquiry'' as to the 
accuracy of the data.
    Response: EPA believes that the high level of public interest in 
the data collected under this rule, as well as its importance to future 
policy, warrants establishment, by rule pursuant to CAA Sections 114, 
208, and 301(a)(1), of a high standard for data quality and consistency 
and a high level of accountability for reported data, which will help 
ensure that the data quality and consistency standard is met. The 
certification requirements set forth in this rule are similar to the 
ARP (Title IV). EPA has successfully implemented this approach in the 
ARP and found that it provides a high degree of both data quality and 
consistency and accountability.
2. Certificate of Representation
    Comment: One commenter requested that EPA designate a deadline for 
the submission of the certificate of representation to ensure 
sufficient time to process the submissions.
    Response: EPA agrees that an earlier deadline for submitting 
certificates of representation is advisable to provide additional lead 
time to process the certificates and, if necessary, verify identities 
and resolve issues. Because any delay in processing a certificate of 
representation could delay the submission of data, EPA is requiring 
that the designated representative submit the initial certificate of 
representation at least 60 days prior to the deadline for a facility or 
supplier's initial GHG report.
    Comment: Several commenters noted that a certificate of 
representation for each facility and supplier is burdensome either due 
to timing with the annual report, the need to maintain current 
information, or ambiguities as to whether the certificate is complete. 
Commenters also requested that reporters be allowed more than 30 days 
to submit a revised certificate of representation in the event of a 
change in operators or owners.
    Comment: Several commenters requested that EPA provide an 
electronic system for submitting and processing certificates of 
representation.
    Response: EPA does not agree that certificates of representation 
are unnecessary or overly burdensome or that there should be any 
uncertainty as to whether a certificate of representation is complete. 
The information required on the certificate of representation is

[[Page 56358]]

listed in the rule and should be well known to the owners and operators 
of the facility or supplier. It is the responsibility of the individual 
submitting the certificate to ensure its completeness. This certificate 
of representation has been used successfully for over a decade in the 
ARP.
    To minimize burden, the electronic data reporting system will 
provide the means to electronically submit both the initial and any 
subsequent certificate of representation. EPA agrees that reporters 
should be allowed more time to update changes in owners or operators 
but does not agree that doing so in the annual report is sufficient. 
The designated representative is the primary point of contact between 
the owners and operators and the EPA. However, the owners and operators 
are ultimately responsible for compliance with the requirements of 
reporting rule, and it is therefore essential that the information in 
the certificate of representation be timely and accurate in the event 
EPA finds it necessary to contact the owners and operators of the 
facility or supplier during periods in between the submission dates of 
the annual reports, for example, to perform an audit. The final rule 
allows reporters up to 90 days to submit a revised certificate of 
representation when a change in owners or operators occurs. In 
addition, EPA modified both the owner definition and rule to clarify 
that the certificate of representation does not need to list persons 
whose legal or equitable title to or leasehold interest in a facility 
or supplier arises solely because they are limited partners in a 
partnership with legal or equitable title to, a leasehold interest in, 
or control of, the facility or supplier.
3. Data Collection Methods
    Comment: Several commenters requested that EPA use current emission 
inventory reporting programs (e.g., NEI) to handle data collection or 
to sunset the GHG reporting rule, and instead use such programs, after 
five years.
    Response: EPA is requiring electronic reports to be submitted 
directly to EPA using a new data reporting system for the GHG reporting 
rule. The rationale for the decision to report directly to EPA is 
contained in Sections II.N (emissions verification) and VI.B 
(compliance and enforcement) of this preamble. EPA recognizes the value 
of integrating the GHG data reported under this rule with other 
emission reporting programs. NEI, for example, plans to incorporate the 
GHG emissions data from this collection, as feasible.
    Comment: Commenters requested that the design of the new data 
system be modeled on existing electronic reporting programs, 
incorporate measures to handle system errors, and provide opportunities 
for testing and user training.
    Response: EPA agrees that a national electronic emissions database 
should be the basis for receiving GHG data, and that the ARP database 
provides a useful model for a future GHG emissions database. Data would 
be provided to EPA electronically to reduce the burden on the reporters 
and EPA, and to increase the accuracy of the reported emissions, among 
other reasons. The issue of transmission failures and transmission 
errors will be addressed in the development of the electronic reporting 
system. EPA agrees that is it important for data reporters to be able 
to confirm that their data were accepted by the system and to compare 
the data in the system to the data that they reported to ensure it was 
accurately incorporated into the database. The new data system will 
meet Agency requirements for security and hosting. EPA acknowledges 
comments supporting a ``user friendly'' reporting system. EPA plans to 
follow well known design practices within the constraints of security, 
accessibility and Agency design requirements.
    EPA agrees with commenters on the need for testing and user 
training. We will continue the outreach effort undertaken during this 
rulemaking to encourage stakeholder participation in `beta' testing and 
training opportunities.

Unique Identifiers for Facilities and Units

    Comment: Several commenters requested that EPA assign and track 
corporate identifiers for reporting facilities to facilitate corporate-
level analysis of emission data. Commenters also requested that EPA 
publish a list of identifiers for all EPA programs that a covered 
facility may report to.
    Response: EPA is collecting owner and operator information through 
the Certificate of Representation (40 CFR 98.4). At this time, EPA is 
not proposing to assign unique identifiers to the owners and operators 
because of the complexity of ownership structures (including percentage 
shares of owners, subsidiaries, holding companies, and limited 
liability partnerships) that can be used in the multiplicity of 
industrial sectors required to report emission data under this rule. 
Although as explained earlier in the preamble, we are exploring options 
for adding additional data elements to the reports, such as name of 
parent company and NAICS code(s), to allow easier aggregation of 
facility-level data to the corporate level under this program. EPA 
expects to subject any additional requests to notice and comment 
rulemaking.
    EPA's Facility Registry System (FRS) links EPA program 
identification numbers under a unique facility record. The FRS database 
is publicly available to queries from the EPA.GOV Web site under the 
Envirofacts Data Warehouse home page: http://www.epa.gov/enviro/html/fii/fii_query_java.html. Descriptive information about FRS can be 
found at: http://www.epa.gov/enviro/html/fii/index.html. FRS may be 
searched by program identification, facility name or geographic 
location. The Agency will continue to make FRS and all program 
identification numbers readily available and will include the 
facilities reporting under this rule in the FRS collection of program 
ID's once public release of the data is authorized.

Submission Method

    Comment: Several commenters requested that EPA specify the format 
of the data collection methods and subject it to public comment before 
finalizing the rule. These commenters indicated that without the 
details of the data collection methods it was not possible to evaluate 
the GHG reporting rule, including implementation costs and reporting 
burden.
    Response: The final rule requires reports to be submitted ``in a 
format specified by the Administrator.'' EPA is thereby retaining the 
flexibility to specify the electronic format, and the underlying 
electronic reporting system reflected in the format, after promulgation 
of this rule but well before the first reporting deadline and, if 
necessary, to change the electronic format and electronic reporting 
system based on implementation experience and new technology. Several 
other reporting programs (e.g., ARP) use a similar approach where the 
specific electronic reporting system is not included within the rule or 
subjected to formal notice and comment. The relevant subparts of the 
proposed GHG reporting rule specified the data elements that each 
entity must report, and therefore parties could evaluate the reporting 
burden and costs under the proposed rule and had an opportunity to 
comment on that aspect of the proposed rule. In addition, before 
specifying the electronic format and underlying electronic reporting 
system, EPA will conduct outreach and provide opportunities for 
stakeholder feedback on the specific reporting format and reporting 
system.

[[Page 56359]]

    Comment: Several commenters requested that EPA provide alternative 
methods to report emission data, including paper submissions, scanned 
documents, and direct data upload.
    Response: EPA is requiring electronic reporting of the GHG and 
supplemental data to increase the accuracy and timeliness of the 
reported emission data and is not providing options for paper or 
scanned GHG reports. Requiring electronic submission of data allows EPA 
to conduct electronic QA testing of all such data when it is received 
and to provide electronic feedback to the reporters almost 
instantaneously. This gives reporters the opportunity to correct any 
errors, or to provide explanations of potentially problematic data, 
within a short time frame, thereby increasing the accuracy and 
timeliness of the data. Moreover, electronically submitted data can be 
readily sorted and analyzed by EPA and members of the public. In 
contrast, submission of hardcopy data (whether in paper or scanned 
documents) would make audit and correction, as well as sorting and 
analysis, of the data much more cumbersome, inefficient, and time 
consuming. Indeed, particularly in light of the large number of 
facilities and suppliers that will be reporting and the large amounts 
of reported data that will be received as a result, the ability to 
audit and analyze the data received in hardcopy format would likely be 
significantly limited. This would adversely affect the usefulness, as 
well as the accuracy and timeliness of the data.
    In requiring electronic data submission, EPA will provide a Web-
based reporting system to guide reporters through the data entry, 
emission calculation, and submission process. This reporting system 
will conform to EPA information technology standards and 40 CFR part 3. 
In addition, EPA will provide a mechanism for reporters to submit data 
files directly to EPA using a standard format (e.g., XML) to be 
prescribed by the Administrator before the first reporting date. To 
reduce the burden on reporters and reduce errors, EPA will conduct 
outreach and training for reporters on the reporting format and 
underlying reporting systems. EPA will also provide a hotline to answer 
questions about the program and reporting format and reporting systems. 
EPA expects that most reporters affected by this rule are already 
familiar with Web-based or electronic reporting systems through other 
EPA programs.

Delegation of Authority to State Agencies To Collect GHG Data

    Comment: Several commenters requested that EPA delegate rule 
implementation, including data collection, to State and local agencies. 
These commenters indicated that several States already have GHG 
reporting requirements and have systems in place to collect and verify 
this data, and suggested that delegation of the rule could help reduce 
inconsistency or duplication of effort between State programs and this 
Federal mandatory GHG reporting rule. Other commenters supported 
requiring facilities to submit data directly to EPA, without delegation 
of data collection to State and local agencies, in order to provide 
national consistency.
    Response: EPA is requiring electronic reports to be submitted 
directly to EPA, and is not delegating data collection to State and 
local agencies. The rationale for this decision is provided in Section 
VI.B of this preamble.
5. Data Dissemination

Public Access to Emissions Data

    Comment: Several commenters supported EPA's proposal to make the 
data submitted under the reporting rule available to the public. Some 
requested that data be published in real time, while others requested 
the data be released in a timely manner.
    Response: With the exception of CBI, EPA intends to make data 
submitted under this program available to the public in a timely manner 
after the reports have been submitted and EPA has completed QA/QC of 
the data. To that end, EPA intends to establish a new reporting system 
that will accept electronic submissions of GHG emissions and supporting 
data and facilitate EPA's verification of the submissions. EPA plans to 
provide public access to the data by posting electronic data on a Web 
site in a timely manner after the reporting deadline. This level of 
transparency is important to public participation in future policy 
development and for building public confidence in the quality of the 
data collected.

Sharing Emissions Data With Other Agencies

    Comment: Some commenters stressed that electronic data reporting 
systems need to be consistent and inter-operable and allow data 
exchange between TCR, State rules, NEI, ARP, other stakeholders and 
EPA.
    Response: EPA will continue to coordinate with other Federal, 
State, and regional programs and will make efforts to facilitate data 
exchange when designing the data reporting system that will be used for 
the GHG reporting rule. EPA intends to employ inter-operable data 
exchange standards. EPA intends to design and manage the GHG data 
collection to take advantage of existing efforts on data exchange 
standards and to work with stakeholder groups to promote the easy 
exchange and sharing of the data collected under this rule. For 
example, EPA is extending the Consolidated Emissions Reporting Schema 
(CERS), currently in use by the EPA's NEI program, to support data 
reporting and publication under this rule. EPA also intends to use 
existing tools, such as FRS and SRS, to ensure data consistency.
    To the extent possible, EPA will consider existing reporting 
systems and work with those programs and systems to develop a reporting 
scheme that facilitates data exchange. EPA anticipates that this 
coordination will reduce the burden of reporting for both reporters and 
government agencies. However, as explained in Section II.O of this 
preamble, the various reporting programs do not have identical data 
needs and requirements. Therefore, at this time, it is not possible for 
companies reporting under State and Federal rules and voluntary 
programs to file a single report that will satisfy all reporting 
requirements.
    Comment: Commenters requested that the data system utilize common 
standards, such as XML and geographic identifiers, and provide 
descriptive text wherever codes or abbreviations are used.
    Response: EPA agrees that publishing the results of this data 
collection using common, standards-based schemas and formats will 
promote the exchange of data between EPA, States and other entities. 
The published results will include the latitude and longitude of 
facilities as well as help text with definitions of codes and 
abbreviations.

VI. Compliance and Enforcement

    This section of the preamble generally describes the compliance 
assistance and enforcement activities EPA intends to implement for the 
GHG reporting rule and summarizes public comments and responses on 
compliance assistance, role of the States, and enforcement.

A. Compliance and Enforcement Summary

1. Compliance Assistance
    EPA plans to conduct an active outreach and technical assistance 
program following publication of the final rule. The primary audience 
is

[[Page 56360]]

potentially affected industries. We intend to develop implementation 
and outreach materials and training to help potential reporters 
understand whether the rule applies to them and explain the reporting 
requirements and timetables. The program particularly will target 
industrial, commercial, and institutional sectors that do not routinely 
deal with air pollution regulations.
    Compliance materials will be tailored to the needs of various 
sectors. These materials might include, for example, fact sheets, 
information sheets, plain English guides, frequently asked question and 
answer documents, applicability tools, monitoring and recordkeeping 
checklists, and training on rule requirements and the electronic 
reporting system. We also expect to implement a compliance assistance 
e-mail and telephone hotline for answering questions and providing 
technical assistance. Note that while EPA plans to issue compliance 
assistance materials, reporters should always consult the final rule to 
resolve any ambiguities or questions.
2. Role of the States
    While EPA does not intend to formally delegate data collection and 
enforcement of the GHG reporting rule to State agencies, EPA will 
likely enlist State assistance, when it is available, for outreach and 
compliance assistance with the final rule. (However, State and local 
agencies will not be required to provide EPA any assistance with these 
activities, given State and local agency resource constraints and 
priorities.). State and local air pollution control agencies routinely 
interact with many of the sources that would report under this rule. 
Further, several States have experience implementing State mandatory 
GHG reporting and reduction programs. Therefore, we plan to work with 
those State and local agencies that are able to assist EPA to define 
their role in communicating the requirements of the rule and providing 
compliance assistance. In concert with their routine inspection and 
other compliance and enforcement activities for other CAA programs, 
State and local agencies may also be able to assist with educating 
facilities and assuring compliance at facilities subject to this rule.
3. Enforcement
    Facilities or suppliers that fail to monitor or report GHG 
emissions, quantities supplied, or other data elements according to the 
requirements of the applicable rule subparts could potentially be 
subject to enforcement action by EPA under CAA sections 113 and 203-
205. The CAA provides for several levels of enforcement that include 
administrative, civil, and criminal penalties. The CAA allows for 
injunctive relief to compel compliance and civil and administrative 
penalties of up to $37,500 per day per violation.\31\
---------------------------------------------------------------------------

    \31\ The Federal Civil Penalties Inflation Adjustment Act of 
1990, Public Law 101-410, 104 Stat. 890, 28 U.S.C. 2461, note, as 
amended by Section 31001(s)(1) of the Debt Collection Improvement 
Act of 1996, Public Law 104-134, 110 Stat. 1321-373, April 26, 1996, 
requires EPA and other agencies to adjust the ordinary maximum 
penalty that it will apply when assessing a civil penalty for a 
violation. Accordingly, EPA has adjusted the CAA's provision in 
Section 113(b) and (d) specifying $25,000 per day of violation for 
civil violations to $37,500 per day of violation.
---------------------------------------------------------------------------

    Actions (or inactions) that could ultimately be considered 
violations include but are not limited to the following:
     Failure to report GHG emissions (for suppliers, the 
emissions that would result from combustion or use of the products they 
supply).
     Failure to collect data needed to calculate GHG emissions.
     Failure to continuously monitor and test as required. Note 
that merely filling in missing data as specified does not excuse a 
failure to perform the monitoring or testing.
     Failure to calculate GHG emissions according to the 
methodology(s) specified in the rule.
     Failure to keep required records needed to verify reported 
GHG emissions.
     Falsification of reports.

B. Summary of Public Comments and Responses on Compliance and 
Enforcement

    This section contains a brief summary of major comments and 
responses. A large number of comments on compliance and enforcement 
were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Compliance and Enforcement.''
1. Role of States in Compliance and Enforcement
    Comment: Several commenters requested that EPA delegate rule 
implementation, including data collection, emissions verification, and 
enforcement of the rule to State and local agencies. These commenters 
indicated that several States already have GHG reporting requirements 
and have systems in place to collect and verify these data, and they 
suggested that delegation of the rule could help reduce inconsistency 
or duplication of effort between State programs and this Federal 
mandatory GHG reporting rule. However the majority of commenters, 
including industry, environmental organizations, and many public 
citizens supported requiring facilities to submit data directly to EPA, 
without delegation of data collection or emissions verification to 
State and local agencies, in order to provide national consistency.
    Response: Section 114(b) of the CAA allows EPA to delegate to 
States the authority to implement and enforce Federal rules. At this 
time, however, EPA does not propose to formally delegate implementation 
of the rule (such as data collection and enforcement activities) to 
State and local agencies, as discussed in Section II.O of this 
preamble. The goal of data collection under this rule is to establish a 
consistent, verified, national data set that is available to EPA, 
States, other agencies, policy makers, and the public for use in 
developing and implementing future GHG policies and reduction programs. 
To meet these data consistency and timeliness constraints, and to serve 
policy objectives, it is most efficient to have the data submitted 
directly into one central EPA system and have centralized emissions 
data verification. Direct reporting to EPA will also help us better 
understand and address common compliance problems that may arise from 
the GHG reporting rule.
    EPA recognizes that several States already have mandatory GHG 
reporting programs that are broader in scope, in a more advanced state 
of development, and have different policy objectives than this 
rulemaking. These are important programs that not only led the way in 
reporting of GHG emissions before the Federal government acted but also 
have catalyzed important GHG reductions.
    As discussed in Section II.O of this preamble, we are committed to 
working with States and other groups (e.g, TCR, Environmental Council 
of the States (ECOS)) to develop electronic reporting tools that can 
both collect and share data in an efficient and timely manner. At this 
time, EPA is in the process of developing the reporting format and 
tools and therefore has not specified the exact reporting format, other 
than it will be electronic, in order to maintain flexibility to modify 
the reporting format and tools in a timely manner. To the extent 
possible, EPA will work with existing reporting programs and systems to 
develop a reporting scheme that minimizes the burden on sources.
    While EPA is not delegating authority to the States, we will work 
with States as we develop rule implementation plans to determine 
appropriate

[[Page 56361]]

implementation roles, such as assisting with outreach efforts and site 
visits to audit facility reports. For related comments and responses, 
please see the following sections of this preamble: II.N (verification 
approach), II.O (role of States) and II.R (CBI).
2. Enforcement
    Comment: Some commenters suggested that States should be allowed to 
participate in the enforcement of the GHG reporting rule, perhaps 
through delegated enforcement authority.
    Response: EPA welcomes States' interest in helping EPA enforce this 
or any other Federal rule and we will work with States to determine 
appropriate roles as described above. We do not plan to delegate the 
enforcement of this rule in the same sense that we do under other CAA 
programs such as the NESHAP program in which, for example, notices may 
be sent only to the delegated States. If a State would like the 
authority to enforce this rule, then the State may adopt the provisions 
of this GHG reporting rule into State laws or regulations by reference. 
This would make the provisions enforceable as a matter of State law 
which can be enforced in a State court.
    Comment: Some commenters stated that they should be able to 
petition EPA to enforce against violators where they have evidence of 
or suspect violations.
    Response: EPA welcomes any tips from citizens about suspected 
violations of this or any rule through our tips Web site, http://www.epa.gov/tips. However, we are not including a formal petition 
process in the rule because such a process was not proposed. We do not 
favor a formal petition process because a formal petition is not 
necessary for us to investigate concerns raised by citizens and such a 
process might take extra time or divert resources from other 
priorities.
    Comment: Some commenters stated that a flexible enforcement policy 
is needed. They noted that the proposed rule cited the CAA for the 
authority for the GHG reporting rule and stated that a violation of the 
reporting rule is a violation of the CAA and subject to maximum daily 
penalties allowed under the CAA. However, the commenters were concerned 
that the maximum penalty should not be applied in most cases and argued 
that there are many instances when a less severe action is appropriate.
    Response: EPA agrees with the commenters that flexibility is needed 
in enforcing the rule. The penalty cited in the proposal preamble and 
rule is a statutory maximum, and would not be applied in every case. 
EPA's objective with the reporting rule is to collect accurate GHG data 
in a timely manner. In order to achieve that objective, EPA will 
generally work with sources that must submit GHG reports in order to 
facilitate compliance and provide the needed data to EPA. The CAA 
allows EPA discretion to pursue a variety of informal and formal 
actions in order to achieve compliance. While EPA is committed to 
working with reporters to ensure accuracy, this does not relieve 
reporters from their obligation to report data that are complete, 
accurate, and in accordance with the requirements of this rule.
    In many instances, based on past enforcement experience, less 
punitive enforcement actions are exhausted before more punitive fines 
and penalties are imposed on a non-complying source. These less 
punitive actions may include a warning to the source that it is in non-
compliance along with advice on what needs to be done to comply and a 
request for response from the facility. Initial actions may also 
include a formal legal notification from EPA that defines the 
violation, provides evidence, and requires (orders) corrective actions 
by specific dates. The EPA enforcement office always uses discretion 
and takes case-specific circumstances into account when determining the 
appropriate actions to address violations of CAA rules. We will 
continue to do so in enforcing the reporting rule, and we are not 
laying out a specific enforcement policy or hierarchy in order to 
maintain the necessary flexibility.

VII. Economic Impacts on the Rule

    This section of the preamble examines the costs and economic 
impacts of the GHG reporting rule, including the estimated costs and 
benefits of the rule, and the estimated economic impacts of the rule on 
affected entities, including estimated impacts on small entities. 
Complete detail of the economic impacts of the final rule can be found 
in the text of the Regulatory Impact Analysis (RIA) for the final rule 
(EPA-HQ-OAR-2008-0508).
    This section also contains a brief summary of major comments and 
responses. A large number of comments on economic impacts of the rule 
were received covering numerous topics. Responses to significant 
comments received can be found in ``Mandatory Greenhouse Gas Reporting 
Rule: EPA's Response to Public Comments, Cost and Economic Impacts of 
the Rule.''

A. How were compliance costs estimated?

1. Summary of Method Used To Estimate Compliance Costs
    EPA estimated costs of complying with the rule for reporting 
process emissions of GHGs in each affected industrial facility, as well 
as emissions from stationary combustion sources at industrial 
facilities and other facilities, GHG and supply data from fuel 
suppliers and industrial gas suppliers, and GHG data for mobile 
sources. 2006 is the representative year of the analysis in that the 
annual costs were estimated using the 2006 population of emitting 
sources. EPA used available industry and EPA data to characterize 
conditions at affected sources. Incremental monitoring, recordkeeping, 
and reporting activities were then identified for each type of facility 
and the associated costs were estimated.
    The costs of complying with the rule will vary from one facility to 
another, depending on the types of emissions, the number of affected 
sources at the facility, existing monitoring, recordkeeping, and 
reporting activities at the facility, etc. The costs include labor 
costs for performing the monitoring, recordkeeping, and reporting 
activities necessary to comply with the rule. For some facilities, 
costs include costs to monitor, record, and report emissions of GHGs 
from production processes and from stationary combustion units. For 
other facilities, the only emissions of GHGs are from stationary 
combustion. EPA's estimated costs of compliance are discussed in 
greater detail below:
    Labor Costs. The costs of complying with and administering this 
rule include time of managers, technical, and administrative staff in 
both the private sector and the public sector. Staff hours are 
estimated for activities, including:
     Monitoring (private): Staff hours to operate and maintain 
emissions monitoring systems.
     Reporting (private): Staff hours to gather and process 
available data and reporting it to EPA through electronic systems.
     Assuring and releasing data (public): Staff hours to 
quality assure, analyze, and release reports.
    Staff activities and associated labor costs will potentially vary 
over time. Thus, cost estimates are developed for start-up and first-
time reporting, and subsequent reporting. Wage rates to monetize staff 
time are obtained from the Bureau of Labor Statistics (BLS).
    Equipment Costs. Equipment costs include both the initial purchase 
price of monitoring equipment and any

[[Page 56362]]

facility/process modification that may be required. For example, the 
cost estimation method for mobile sources involves upstream measurement 
by the vehicle manufacturers. This may require an upgrade to their test 
equipment and facility. Based on expert judgment, the engineering costs 
analyses annualized capital equipment costs with appropriate lifetime 
and interest rate assumptions. Cost recovery periods and interest rates 
vary by industry, but typically, one-time capital costs are amortized 
over a 10-year cost recovery period at a rate of seven percent.
2. Summary of Comments and Responses
    Comment: A majority of the comments received on the compliance 
costs of the reporting rule focused on facility level costs for 
monitoring and reporting. Commenters noted that costs estimated for a 
representative facility may differ from actual facility level costs. 
Some commenters specifically referred to the costs associated with 
installing and maintaining capital equipment. Other commenters noted 
that some source categories had higher estimated compliance costs than 
others. Several commenters expressed confusion over how combustion 
related monitoring costs are added to process related monitoring costs.
    Response: EPA recognizes that the costs presented for facilities 
represent costs that would be incurred by a representative facility, 
and may not reflect the costs that would be incurred by each individual 
facility in each industry because facilities affected by each subpart 
vary.
    Nevertheless, after reviewing the comments received, EPA has 
determined that its analysis provides a reasonable characterization of 
costs for facilities affected by each subpart and that its 
documentation provides adequate documentation of how the costs were 
estimated. As described in the next section, EPA collected and 
evaluated cost data from multiple sources, and weighed the analysis 
prepared at proposal against the input received through public 
comments. In any analysis of this type, there will be variations in 
costs among facilities, and after thoroughly reviewing the available 
information, we have concluded that the costs developed for this rule 
appropriately reflect a ``representative facility'' in the sector.
    The costs facing facilities in some sectors include not only 
process costs but additional costs associated with other subparts of 
the rule. While these costs are presented individually in Section 4 of 
the RIA for the final rule, where these conditions apply the costs are 
summed across applicable subparts and compared to revenues in the 
economic and small entity impact analyses.

B. What are the costs of the rule?

1. Summary of Costs
    For the cost analysis, EPA gathered existing data from EPA, 
industry trade associations, States, and publicly available data 
sources (e.g., labor rates from the BLS) to characterize the processes, 
sources, sectors, facilities, and companies/entities affected. EPA also 
considered cost data submitted in public comments on the proposed rule, 
as further discussed in Section VII.B.2 of this preamble. Costs were 
estimated on a per entity basis and then weighted by the number of 
entities affected at the 25,000 metric tons CO2e threshold.
    To develop the costs for the rule, EPA estimated the number of 
affected facilities in each source category, the number and types of 
combustion units at each facility, the number and types of production 
processes that emit GHGs, process inputs and outputs (especially for 
monitoring procedures that involve a carbon mass balance), and the 
measurements that are already being made for reasons not associated 
with the rule (to allow only the incremental costs to be estimated). 
Many of the affected source categories, especially those that are the 
largest emitters of GHGs (e.g., electric utilities, industrial boilers, 
petroleum refineries, cement plants, iron and steel production, pulp 
and paper) are subject to national emission standards and we use data 
generated in the development of these standards to estimate the number 
of sources affected by the reporting rule.
    Other components of the cost analysis included estimates of labor 
hours to perform specific activities, cost of labor, and cost of 
monitoring equipment. Estimates of labor hours were based on previous 
analyses of the costs of monitoring, reporting, and recordkeeping for 
other rules; information from the industry characterization on the 
number of units or process inputs and outputs to be monitored; and 
engineering judgment by industry and EPA industry experts and 
engineers. Labor costs were taken from the BLS and adjusted to account 
for overhead. Monitoring costs were generally based on cost algorithms 
or approaches that had been previously developed, reviewed, accepted as 
adequate, and used specifically to estimate the costs associated with 
various types of measurements and monitoring.
    A detailed engineering analysis was conducted for each subpart of 
the rule to develop unique unit costs. This analysis is documented in 
the RIA for the final rule. The TSDs for each source category provide a 
discussion of the applicable measurement technologies and any existing 
programs and practices. The appropriate volume of ``Mandatory 
Greenhouse Gas Reporting Rule: EPA's Response to Public Comments'' for 
each source category provide responses to any public comments on these 
source category engineering and cost analyses. Section 4 of the RIA for 
the final rule contains a description of the engineering cost analysis.
    Table VII-1 of this preamble presents by subpart: The number of 
entities, the downstream emissions covered, the first year capital 
costs and the first year annualized costs of the rule. EPA estimates 
that the total national annualized cost for the first year is $132 
million, and the total national annualized cost for subsequent years is 
$89 million (2006$). Of these costs, roughly 13 percent fall upon the 
public sector for program administration in the first year, while 87 
percent fall upon the private sector. General stationary combustion 
sources, which are widely distributed throughout the economy, are 
estimated to incur approximately 26 percent of costs in the first year; 
other sectors incurring relatively large shares of costs are pulp and 
paper manufacturing (9 percent) and vehicle and engine manufacturers (9 
percent).
    The threshold, in large part, determines the number of entities 
required to report GHG emissions and hence the costs of the rule. The 
number of entities excluded increases with higher thresholds. Table 
VII-2 of this preamble provides the cost-effectiveness analysis for 
various thresholds examined. Two metrics are used to evaluate the cost-
effectiveness of the emissions threshold. The first is the average cost 
per metric ton of emissions reported ($/metric ton CO2e). 
The second metric for evaluating the threshold option is the 
incremental cost of reporting emissions. The incremental cost is 
calculated as the additional (incremental) cost per metric ton starting 
with the least stringent option and moving successively from one 
threshold option to the next. For more information about the first year 
capital costs (unamortized), project lifetime and the amortized 
(annualized) costs for each subpart, please refer to section 4 of the 
RIA for the final rule and the RIA cost appendix. Not all subparts 
require capital expenditures but those that do

[[Page 56363]]

are clearly documented in the RIA for the final rule.

                 Table VII-1--Estimated Covered Entities, Emissions and Costs by Subpart (2006$)
----------------------------------------------------------------------------------------------------------------
                                           Downstream emissions     First year capital       First year total
                                Number   ------------------------          costs           annualized costs \2\
           Subpart            covered of                         -----------------------------------------------
                               entities    (Million      Share                   Share                   Share
                                          of MtCO2e)   (percent)   (Million)   (percent)   (Million)   (percent)
----------------------------------------------------------------------------------------------------------------
Subpart A--General                     0         0.0           0        $0.0           0        $0.0           0
 Provisions.................
Subpart B--Reserved.........           0         0.0           0         0.0           0         0.0           0
Subpart C--General                 3,000       220.0           6        10.5          27        25.8          20
 Stationary Fuel Combustion
 Sources....................
Subpart D--Electricity             1,108      2262.0          59         0.0           0         3.3           2
 Generation.................
Subpart E--Adipic Acid                 4         9.3           0         0.0           0         0.1           0
 Production.................
Subpart F--Aluminum                   14         6.4           0         0.0           0         0.2           0
 Production.................
Subpart G--Ammonia                    23        12.9           0         0.0           0         0.4           0
 Manufacturing..............
Subpart H--Cement Production         107        86.8           2         5.4          14         6.8           5
Subpart K--Ferroalloy                  9         2.3           0         0.0           0         0.1           0
 Production.................
Subpart N--Glass Production.          55         2.2           0         0.0           0         0.5           0
Subpart O--HCFC-22                     3        13.8           0         0.0           0         0.0           0
 Production.................
Subpart P--Hydrogen                   41        15.0           0         0.0           0         0.4           0
 Production.................
Subpart Q--Iron and Steel            121        85.0           2         0.0           0         3.7           3
 Production.................
Subpart R--Lead Production..          13         0.8           0         0.0           0         0.1           0
Subpart S--Lime                       89        25.4           1         4.9          12         5.3           4
 Manufacturing..............
Subpart U--Miscellaneous               0         0.0           0         0.0           0         0.0           0
 Uses of Carbonates.........
Subpart V--Nitric Acid                45        17.7           0         0.2           1         0.9           1
 Production.................
Subpart X--Petrochemical              80        54.4           1         0.0           0         2.2           2
 Production.................
Subpart Y--Petroleum                 150       204.7           5         1.6           4         6.1           5
 Refineries.................
Subpart Z--Phosphoric Acid            14         3.8           0         0.8           2         0.8           1
 Production.................
Subpart AA--Pulp and Paper           425        57.7           2        14.8          37         8.6           7
 Manufacturing..............
Subpart BB--Silicon Carbide            1         0.1           0         0.0           0         0.0           0
 Production.................
Subpart CC--Soda Ash                   5         3.1           0         0.0           0         0.1           0
 Manufacturing..............
Subpart EE--Titanium Dioxide           8         3.7           0         0.0           0         0.1           0
 Production.................
Subpart GG--Zinc Production.           5         0.8           0         0.0           0         0.1           0
Subpart HH--Landfills.......       2,551        91.1           2         1.3           3        12.4           9
Subpart JJ--Manure                   107         4.5           0         0.0           0         0.3           0
 Management.................
Subpart LL -Suppliers of             315         0.0           0         0.0           0         3.7           3
 Coal & Subpart MM--
 Suppliers of Petroleum
 Products...................
Subpart NN--Suppliers of           1,502         0.0           0         0.0           0         6.8           5
 Natural Gas and Natural Gas
 Liquids....................
Subpart OO--Suppliers of             167       643.4          17         0.0           0         0.5           0
 Industrial Greenhouse Gases
Subpart PP--Suppliers of              13         0.0           0         0.0           0         0.0           0
 Carbon Dioxide (CO2).......
Subpart QQ--Motor Vehicle            317          NA          NA         0.0           0         8.6           7
 and Engine Manufacturers...
Coverage Determination Costs          NA          NA          NA          NA          NA        17.2          13
 for Non-Reporters..........
Private Sector, Total.......      10,152       3,827         100        39.6         100       115.0          87
Public Sector, Total........          NA          NA          NA          NA          NA        17.0          13
                             -----------------------------------------------------------------------------------
    Total...................      10,152       3,827         100        39.6         100       132.0         100
----------------------------------------------------------------------------------------------------------------
\1\ Emissions from upstream facilities are excluded from these estimates to avoid double counting.
\2\ Total costs include labor and capital costs incurred in the first year. Capital Costs are annualized using
  appropriate equipment lifetime and interest rate (see additional details in section 4 of the RIA for the final
  rule).


                           Table VII-2--Threshold Cost-Effectiveness Analysis (2006$)
----------------------------------------------------------------------------------------------------------------
                                                                              Percentage
                                                         Total    Downstream   of total    Average
                                           Facilities    costs     emissions  downstream  reporting  Incremental
          Threshold (tons CO2e)             required    (million   reported    emissions     cost      cost ($/
                                            to report    $2006)    (MtCO2e/    reported    ($2006/   metric ton)
                                                                     year)     (percent)     ton)
----------------------------------------------------------------------------------------------------------------
100,000..................................       6,269        $89       3,738          53      $0.02
25,000...................................      10,152        132       3,827          54       0.03        0.49
10,000...................................      16,718        160       3,861          55       0.04        0.83
1,000....................................      54,229        398       3,926          56       0.10        3.67
----------------------------------------------------------------------------------------------------------------
* Cost per metric ton relative to the selected option.
Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ).


[[Page 56364]]

    Table VII-3 of this preamble presents costs broken out by upstream 
and downstream sources. Upstream sources include the fuel suppliers and 
industrial GHG suppliers. Downstream suppliers include combustion 
sources, industrial processes, and biological processes. Most upstream 
facilities (e.g., refineries) are also direct emitters of GHGs and are 
included in the downstream side of the table. As shown in Table VII-3 
of this preamble, over 99 percent of industrial processes emissions are 
covered at the 25,000 metric tons CO2e threshold for a cost 
of approximately $36 million. However, it should be noted that due to 
data limitations the coverage estimates for upstream and downstream 
source categories are approximations.

                                                      Table VII-3--Upstream Versus Downstream Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                    Upstream 1                                                                Downstream 2 3 4
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Emissions  First year                                        No. of    Emissions  First year
                Source category                    No. of    coverage     cost               Source category           reporters  coverage 3    cost 3
                                                 reporters    (%) 10   (millions)                                          2       7 10 (%)   (millions)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Supply....................................          0          0       $0.00  Coal 5 6 Combustion...............        N/A       99.0       N/A
Petroleum Supply...............................        315        100        3.66  Petroleum 5 Combustion 9..........        N/A       20.0       N/A
Natural Gas Supply.............................      1,502         68        6.76  Natural Gas 5 Combustion..........        N/A       23.0       N/A
                                                 .........  .........  ..........  Sub Total Combustion..............      4,108      N/A         $29.04
Industrial Gas Supply..........................        167        100        0.52  Industrial Gas Consumption........         17       14           0.24
                                                 .........  .........  ..........  Industrial Processes..............      1,068       99.6        36.2
                                                 .........  .........  ..........  Fugitive Emissions (coal, oil and           0        0           0.00
                                                                                    gas).
                                                 .........  .........  ..........  Biological Processes..............      2,658       58          12.77
                                                 .........  .........  ..........  Vehicle 8 and Engine Manufacturers        317       80           8.61
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes
1 Most upstream facilities (e.g., refineries) are also direct emitters of greenhouse gases, and are included in the downstream side of the table.
2 Estimating the total number of downstream reporters by summing the rows will result in double-counting because some facilities are included in more
  than one row due to multiple types of emissions (e.g., facilities that burn fossil fuel and have process/fugitive/biological emissions will be
  included in each downstream category).
3 The coverage and costs for downstream reporters apply to the specific source category, i.e., the fixed costs are not ``double-counted'' in both
  stationary combustion and industrial processes for the same facility.
4 The thresholds used to determine covered facilities are additive, i.e., all of the source categories located at a facility (e.g., stationary
  combustion and process emissions) are added together to determine whether a facility meets the threshold (e.g., 25,000 metric tons of CO2e/yr).
5 Estimates for the number of reporters and total cost for downstream stationary combustion do not distinguish between fuels. National level data on the
  number of reporters could be estimated. However, estimating the number of reporters by fuel was not possible because a single facility can combust
  multiple fuels. For these reasons there is not a reliable estimate of the total of the emissions coverage from the downstream stationary combustion.
6 Approximately 90 percent of downstream coal combustion emissions are already reported to EPA through requirements for electricity generating units
  under the ARP.
7 Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take into account
  thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that will result from this rule. To estimate
  total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the industrial and electricity
  generation sectors and divided that by total national GHG emissions from the combustion of that fuel.
8 The percent of coverage here is percentage of total heavy-duty highway vehicles and engines, motorcycles, and nonroad engine sales covered by
  manufacturer reporting in this proposal rather than emissions coverage. The ``threshold'' for mobile sources is based on manufacturer size rather than
  total emissions. In this rule, all heavy-duty highway and nonroad vehicle and engine manufacturers, except those that meet EPA's definition of ``small
  business'' or ``small volume manufacturers'', would report emissions rates of CO2, CH4, and N2O from the products they supply. This source category is
  neither upstream nor downstream, but is included in the downstream column for illustrative purposes.
9 The emissions coverage for petroleum combustion includes combustion of fuel by transportation sources as well as other uses of petroleum (e.g., home
  heating oil). It cannot be broken out by transportation versus other uses as there are difficulties associated with tracking which products from
  petroleum refiners are used for transportation fuel and which were not. We know that although refiners make these designations for the products
  leaving their gate, the actual end use can and does change in the market. For example, designated transportation fuel can always be used as home
  heating oil.
10 Emissions coverage from the combustion of fossil fuels upstream represents CO2 emissions only. It is not possible to estimate nitrous oxide and
  methane emissions without knowing where and how the fuel is combusted. In the case of downstream emissions from stationary combustion of fossil fuels,
  nitrous oxide and methane emissions are included in the emissions coverage estimate. They represent approximately one percent of the total emissions.

2. Summary of Comments and Responses
    Comment: EPA received comments on source specific cost data 
reflected in the engineering cost analysis presented in section 4 of 
the RIA for the proposed rule (EPA-HQ-OAR-2008-0318-002). Some 
commenters asked EPA to not overly burden entities that may be required 
to report and to balance reporting costs with the need for accurate 
reporting of GHG emissions.
    Additional comments received questioned EPA's estimate of the costs 
associated with third party verification, as well as the estimated 
burden to the Federal government for self certification with EPA 
verification.
    Response: EPA considered all relevant comments regarding source 
specific cost data developed in the engineering cost analysis and used 
in the RIA for the proposed rule. In some cases, we revised our cost 
estimates, and in some cases we revised monitoring and reporting 
requirements in ways which reduced burden. Please see source specific 
comments and responses in Section III of this preamble and the relevant 
volume of ``Mandatory Greenhouse Gas Reporting Rule: EPA's Response to 
Public Comments''.
    EPA believes the selected option for the mandatory GHG reporting 
rule strikes a balance between impacts on small entities, consistency 
with other programs, costs incurred by the reporting entities, and 
emissions coverage. Section 5 of the RIA for the

[[Page 56365]]

final rule provides cost comparisons for each alternative evaluated.
    In evaluating the costs of self certification with EPA verification 
and third party verification, EPA conducted a thorough review of 
relevant cost information available. EPA also considered cost data 
submitted in public comments on the proposed rule. EPA's review of 
verification costs included examining estimated Agency costs for other 
EPA based reporting programs, as well as a study conducted by the 
California Air Resources Board (CARB). The results of EPA's review of 
verification costs can be found in the Memo on Verification Costs in 
the docket. The final rule retains self-certification with EPA 
verification. EPA's estimated cost for verification activities is $7 
million per year. Additional comments and responses on third party 
verification can be found in Section II.N of this preamble. Section 
5.1.6 of the RIA for the final rule contains the full economic analysis 
of verification costs and options.

C. What are the economic impacts of the rule?

1. Summary of Economic Impacts
    EPA prepared an economic impact analysis to evaluate the impacts of 
the rule on affected industries and economic sectors. In evaluating the 
various reporting options considered, EPA conducted a cost-
effectiveness analysis, comparing the cost per metric ton of GHG 
emissions across reporting options. EPA used this information to 
identify the preferred options described in today's rule.
    To estimate the economic impacts of the rule, EPA first conducted a 
screening assessment, comparing the estimated total annualized 
compliance costs by industry, where industry is defined in terms of 
North American Industry Classification System (NAICS) code, with 
industry average revenues. Overall national costs of the rule are 
significant because there is a large number of affected entities, but 
per-entity costs are low. Average cost-to-sales ratios for 
establishments in affected NAICS codes are uniformly less than 0.8 
percent.
    These low average cost-to-sales ratios indicate that the rule is 
unlikely to result in significant changes in firms' production 
decisions or other behavioral changes, and thus unlikely to result in 
significant changes in prices or quantities in affected markets. Thus, 
EPA followed its Guidelines for Preparing Economic Analyses (EPA, 2002, 
p.124-125) and used the engineering cost estimates to measure the 
social cost of the rule, rather than modeling market responses and 
using the resulting measures of social cost. Table VII-4 of this 
preamble summarizes cost-to-sales ratios for affected industries.

                        Table VII-4--Estimated Cost-to-Sales Ratios for Affected Entities
----------------------------------------------------------------------------------------------------------------
                                                                                   Average cost   Average entity
                                                                                    per entity     cost-to-sales
                     NAICS                              NAICS description            ($1,000/        ratio \1\
                                                                                      entity)        (percent)
----------------------------------------------------------------------------------------------------------------
211...........................................  Oil and Gas Extraction..........              $2            <0.1
221...........................................  SF6 from Electrical Systems.....               5            <0.1
322...........................................  Pulp & Paper Manufacturing......              20            <0.1
324...........................................  Petroleum and Coal Products.....              21            <0.1
325...........................................  Chemical Manufacturing..........              14            <0.1
327...........................................  Cement & Other Mineral                        50             0.8
                                                 Production.
331...........................................  Primary Metal Manufacturing.....              26            <0.1
486...........................................  Oil & Natural Gas Transportation               4            <0.1
562...........................................  Waste Management and Remediation               5             0.2
                                                 Services.
325199........................................  Adipic Acid.....................              24            <0.1
325311........................................  Ammonia.........................              17            <0.1
327310........................................  Cement..........................              63             0.2
331112........................................  Ferroalloys.....................               9            <0.1
3272..........................................  Glass...........................               8            <0.1
325120........................................  Hydrogen Production.............               3            <0.1
331112........................................  Iron and Steel..................              30            <0.1
3314..........................................  Lead Production.................              10            <0.1
327410........................................  Lime Manufacturing..............              60             0.4
325311........................................  Nitric Acid.....................              20            <0.1
324110........................................  Petrochemical...................              27            <0.1
325312........................................  Phosphoric Acid.................              60            <0.1
322110........................................  Pulp and Paper..................              20            <0.1
324110........................................  Refineries......................              41            <0.1
327910........................................  Silicon Carbide.................              10            <0.1
3251..........................................  Soda Ash Manufacturing..........              16            <0.1
325188........................................  Titanium Dioxide................              10            <0.1
3314..........................................  Zinc Production.................              13            <0.1
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
  include initial start-up activities.

2. Summary of Comments and Responses
    Comment: EPA received a number of comments on the overall economic 
impacts of the proposed rule. Some commenters stated that the economic 
impacts are understated, as costs will not be passed on to consumers 
from reporters. Other commenters stated that large increases in 
operating costs resulting from mandatory reporting of GHGs would lead 
facilities to close or move offshore.
    Response: As described previously, EPA conducted a thorough 
analysis of available information and reviewed comments submitted on 
this issue, and we have determined that this analysis provides a 
reasonable characterization of costs for facilities in each subpart and 
that the documentation provides adequate explanation of how the costs 
were estimated. Our economic impact analysis has been conducted without

[[Page 56366]]

taking into account the fact that some share of costs may be passed on 
to customers of each affected sector. Instead, facilities' annualized 
costs were compared to sales for entities in the sector, overall and 
for small entities. Even when all costs are absorbed by the facility, 
the costs represent less than one percent of sales and thus are not 
expected to result in significant hardship for affected firms.

D. What are the impacts of the rule on small businesses?

1. Summary of Impacts on Small Businesses
    As required by the RFA and Small Business Regulatory Enforcement 
and Fairness ACT (SBREFA), EPA assessed the potential impacts of the 
rule on small entities (small businesses, governments, and non-profit 
organizations). (See Section VIII.C of this preamble for definitions of 
small entities.)
    EPA has determined the selected thresholds maximize the rule 
coverage with 81 to 86 percent of U.S. GHG emissions reported by 
approximately 10,152 reporters, while keeping reporting burden to a 
minimum and excluding small emitters. Furthermore, many industry 
stakeholders that EPA met with expressed support for a 25,000 metric 
ton CO2e threshold because it sufficiently captures the 
majority of GHG emissions in the U.S., while excluding smaller 
facilities and sources. For small facilities that are covered by the 
rule, EPA has included simplified emission estimation methods in the 
rule where feasible (e.g., stationary combustion equipment under a 
certain rating can use a simplified calculation approach as opposed to 
more rigorous direct monitoring) to keep the burden of reporting as low 
as possible. We received many comments related to monitoring and 
reporting requirements in specific source categories, and made many 
changes in response to reduce burden on reporters. For information on 
these issues, refer to the discussion of each source category in this 
preamble and the relevant volume of ``Mandatory Greenhouse Gas 
Reporting Rule: EPA's Response to Public Comments.'' For further detail 
on the rationale for excluding small entities through threshold 
selection please see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and 
Section III.C.3 of this preamble.
    EPA conducted a screening assessment comparing compliance costs for 
affected industry sectors to industry-specific receipts data for 
establishments owned by small businesses. This ratio constitutes a 
``sales'' test that computes the annualized compliance costs of this 
rule as a percentage of sales and determines whether the ratio exceeds 
some level (e.g., one percent or three percent).\32\ The cost-to-sales 
ratios were constructed at the establishment level (average reporting 
program costs per establishment/average establishment receipts) for 
several business size ranges. This allowed EPA to account for receipt 
differences between establishments owned by large and small businesses 
and differences in small business definitions across affected 
industries. The results of the screening assessment are shown in Table 
VII-5 of this preamble.
---------------------------------------------------------------------------

    \32\ EPA's RFA guidance for rule writers suggests the ``sales'' 
test continues to be the preferred quantitative metric for economic 
impact screening analysis.

                                                          Table VII-5--Estimated Cost-to-Sales Ratios by Industry and Enterprise Size a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                   Owned by enterprises with:
                                                                                                         Average               -----------------------------------------------------------------
                                                                                  SBA size standard      cost per      All         <20                  100 to     500 to     750 to    1,000 to
                Industry                  NAICS        NAICS description        (effective March 11,      entity   enterprises  employees   20 to 99     499        749        999       1,499
                                                                                        2008)            ($1,000/   (percent)      \f\     employees  employees  employees  employees  employees
                                                                                                         entity)                (percent)  (percent)  (percent)  (percent)  (percent)  (percent)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Oil and Gas Extraction.................      211  Oil & gas extraction......  500.....................         $2         0.0         0.2        0.0        0.0        0.0        0.0        0.0
SF6 from Electrical Systems............      221  Utilities.................  (\b\)...................          5         0.0         0.2        0.0        0.0        0.0        0.0        0.0
Pulp & Paper Manufacturing.............      322  Paper mfg.................  500 to 750..............         20         0.1         1.2        0.2        0.1        0.0        0.0        0.0
Petroleum and Coal Products............      324  Petroleum & coal products   (\c\)...................         21         0.0         0.6        0.1        0.1        0.0        0.2        0.0
                                                   mfg.
Chemical Manufacturing.................      325  Chemical mfg..............  500 to 1,000............         14         0.0         0.7        0.1        0.0        0.0        0.0        0.0
Cement & Other Mineral Production......      327  Nonmetallic mineral         500 to 1,000............         50         0.8         4.8        0.9        0.5        0.4        0.5        0.4
                                                   product mfg.
Primary Metal Manufacturing............      331  Primary metal mfg.........  500 to 1,000............         26         0.1         2.1        0.3        0.1        0.1        0.0        0.0
Oil & Natural Gas Transportation.......      486  Pipeline transportation...  (\d\)...................          4         0.0         0.0        0.2        0.1         NA         NA         NA
Waste Management and Remediation             562  Waste management &          (\e\)...................          5         0.2         0.7        0.1        0.1        0.0        0.0        0.0
 Services.                                         remediation services.
Adipic Acid............................   325199  All other basic organic     1,000...................         24         0.0         0.9        0.3        0.1         NA        0.0         NA
                                                   chemical mfg.
Ammonia................................   325311  Nitrogenous fertilizer mfg  1,000...................         17         0.1         0.9        0.5         NA         NA         NA         NA
Cement.................................   327310  Cement mfg................  750.....................         63         0.2         2.0        1.5        0.3         NA         NA        0.1
Ferroalloys............................   331112  Electrometallurgical        750.....................          9         0.0          NA         NA         NA         NA         NA         NA
                                                   ferroalloy product mfg.
Glass..................................     3272  Glass & glass product mfg.  500 to 1,000............          8         0.1         1.4        0.2        0.0        0.0        0.1        0.0
Hydrogen Production....................   325120  Industrial gas mfg........  1,000...................          3         0.0         0.6        0.0        0.1         NA         NA         NA

[[Page 56367]]

 
Iron and Steel.........................   331112  Electrometallurgical        750.....................         30         0.1          NA         NA         NA         NA         NA         NA
                                                   ferroalloy product mfg.
Lead Production........................     3314  Nonferrous metal (except    750 to 1,000............         10         0.0         0.6        0.1        0.0         NA         NA        0.0
                                                   aluminum) production &
                                                   processing.
Lime Manufacturing.....................   327410  Lime mfg..................  500.....................         60         0.4        16.5        1.2         NA         NA         NA         NA
Nitric Acid............................   325311  Nitrogenous fertilizer mfg  1,000...................         20         0.1         1.0        0.6         NA         NA         NA         NA
Petrochemical..........................   324110  Petroleum refineries......  (\c\)...................         27         0.0         0.4        0.0        0.0        0.0         NA         NA
Phosphoric Acid........................   325312  Phosphatic fertilizer mfg.  500.....................         60         0.1        10.1         NA         NA         NA         NA         NA
Pulp and Paper.........................   322110  Pulp mills................  750.....................         20         0.0         1.4         NA         NA         NA         NA         NA
Refineries.............................   324110  Petroleum refineries......  (\c\)...................         41         0.0         0.6        0.0        0.0        0.0         NA         NA
Silicon Carbide........................   327910  Abrasive product mfg......  500.....................         10         0.1         0.8        0.2        0.1         NA         NA         NA
Soda Ash Manufacturing.................     3251  Basic chemical mfg........  500 to 1,000............         16         0.0         0.5        0.1        0.0        0.0        0.0        0.0
Titanium Dioxide.......................   325188  All other basic inorganic   1,000...................         10         0.0         0.7        0.4        0.1         NA         NA         NA
                                                   chemical mfg.
Zinc Production........................     3314  Nonferrous metal (except    750 to 1,000............         13         0.1         0.9        0.1        0.0         NA         NA        0.0
                                                   aluminum) production &
                                                   processing.
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The Census Bureau defines an enterprise as a business organization consisting of one or more domestic establishments that were specified under common ownership or control. The enterprise
  and the establishment are the same for single-establishment firms. Each multi-establishment company forms one enterprise--the enterprise employment and annual payroll are summed from the
  associated establishments. Enterprise size designations are determined by the summed employment of all associated establishments.
Since the SBA's business size definitions (http://www.sba.gov/size) apply to an establishment's ultimate parent company, we assume in this analysis that the enterprise definition above is
  consistent with the concept of ultimate parent company that is typically used for SBREFA screening analyses.
\b\ NAICS codes 221111, 221112, 221113, 221119, 221121, 221122--A firm is small if, including its affiliates, it is primarily engaged in the generation, transmission, and/or distribution of
  electric energy for sale and its total electric output for the preceding fiscal year did not exceed four million MW hours.
\c\ 500 to 1,500. For NAICS code 324110--For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more than 125,000 barrels per
  calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as facilities under a processing agreement or an arrangement
  such as an exchange agreement or a throughput. The total product to be delivered under the contract must be at least 90 percent refined by the successful bidder from either crude oil or bona
  fide feedstocks.
\d\ NAICS codes 486110 = 1,500 employees; NAICS 486210 = $6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 = $11.5 million annual receipts.
\e\ Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910--Environmental Remediation
  Services:
(1) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern must be engaged primarily in
  furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, preliminary assessment, site inspection, testing,
  remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated materials, storage of contaminated materials and security and site
  closeouts. If one of such activities accounts for 50 percent or more of a concern's total revenues, employees, or other related factors, the concern's primary industry is that of the
  particular industry and not the Environmental Remediation Services Industry.
(2) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a contaminated environment and also
  the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering), smaller sub-components of NAICS codes
  with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as: Heavy Construction; Special Trade Construction;
  Engineering Services; Architectural Services; Management Services; Refuse Systems; Sanitary Services, Not Elsewhere Classified; Local Trucking Without Storage; Testing Laboratories; and
  Commercial, Physical and Biological Research. If any activity in the procurement can be identified with a separate NAICS code, or component of a code with a separate distinct size standard,
  and that industry accounts for 50 percent or more of the value of the entire procurement, then the proper size standard is the one for that particular industry, and not the Environmental
  Remediation Service size standard.
\f\ Given the Agency's selected thresholds, enterprises with fewer than 20 employees are likely to be excluded from the reporting program.
NA: Not available. SUSB did not report the data necessary to calculate this ratio.

    EPA was not able to calculate a cost-to-sales ratio for manure 
management (NAICS 112) as Statistics of U.S. Businesses ([SUSB]SBA, 
2008a) data do not provide establishment information for agricultural 
NAICS codes (e.g., NAICS 112 which covers manure management). EPA 
estimates that the total first year reporting costs for the entire 
manure management industry to be $0.3 million with an average cost per 
ton of CO2e reported of $0.07.
    As shown, the cost-to-sales ratios are less than one percent for 
establishments owned by small businesses that EPA considers most likely 
to be covered by the reporting program (e.g., establishments owned by 
businesses with 20 or more employees).
    EPA acknowledges that several enterprise categories have ratios 
that exceed this threshold (e.g., enterprise with one to 20 employees). 
EPA took a conservative approach with the model entity analysis. 
Although the appropriate SBA size definition should be applied at the 
parent company (enterprise) level, data limitations allowed us only to 
compute and compare ratios for a model establishment within several 
enterprise size ranges. To assess the likelihood that

[[Page 56368]]

these small businesses will be covered by the rule, we performed 
several case studies for manufacturing industries where the cost-to-
receipt ratio exceeded one percent. For each industry, we used and 
applied emission data from a recent study examining emission thresholds 
\33\. This study provides industry-average CO2 emission 
rates (e.g., tons per employee) for these manufacturing industries.
---------------------------------------------------------------------------

    \33\ Nicholas Institute for Environmental Policy Solutions, Duke 
University. 2008. Size Thresholds for Greenhouse Gas Regulation: Who 
Would be Affected by a 10,000-ton CO2 Emissions Rule? 
Available at: http://www.nicholas.duke.edu/institute/10Kton.pdf.
---------------------------------------------------------------------------

    The case studies showed two industries (cement and lime 
manufacturing) where emission rates suggest small businesses of this 
employment size could potentially be covered by the rule. As a result, 
EPA examined corporate structures and ultimate parent companies were 
identified using industry surveys and the latest private databases such 
as Dun & Bradstreet. The results of this analysis show cost to sales 
ratios below one percent.
    For the other enterprise categories identified with ratios between 
one percent and three percent EPA examined industry specific bottom up 
databases and previous industry specific studies to ensure that no 
entities with less than 20 employees are captured under the rule.
    Although this rule will not have a significant economic impact on a 
substantial number of small entities, the Agency nonetheless tried to 
reduce the impact of this rule on small entities, including seeking 
input from a wide range of private- and public-sector stakeholders. 
When developing the rule, the Agency took special steps to ensure that 
the burdens imposed on small entities were minimal. The Agency 
conducted several meetings with industry trade associations to discuss 
regulatory options and the corresponding burden on industry, such as 
recordkeeping and reporting. The Agency investigated alternative 
thresholds and analyzed the marginal costs associated with requiring 
smaller entities with lower emissions to report. The Agency also 
recommended a hybrid method for reporting, which provides flexibility 
to entities and helps minimize reporting costs.
    Additional analysis for a model small government also showed that 
the annualized reporting program costs were less than one percent of 
revenue. These impacts are likely representative of ratios in 
industries where data limitations do not allow EPA to compute sales 
tests (e.g., general stationary combustion and manure management). 
Potential impacts of the rule on small governments were assessed 
separately from impacts on Federal Agencies. Small governments and 
small non-profit organizations may be affected if they own affected 
stationary combustion sources, landfills, or natural gas suppliers. 
However, the estimated costs under the rule are estimated to be small 
enough that no small government or small non-profit is estimated to 
incur significant impacts. For example, from the 2002 Census (in 
$2006), revenues for small governments (counties and municipalities) 
with populations fewer than 10,000 are $3 million, and revenues for 
local governments with populations less than 50,000 is $7 million. As 
an upper bound estimate, summing typical per-respondent costs of 
combustion plus landfills plus natural gas suppliers yields a cost of 
approximately $18,000 per local government. Thus, for the smallest 
group of local governments (<10,000 people), cost-to-revenue ratio is 
0.7 percent. For the larger group of governments less than 50,000, the 
cost-to-revenue ratio is 0.2 percent.
2. Summary of Comments and Responses
    Comment: Comments received on small business impacts focused on the 
economic burden to small businesses for compliance with mandatory GHG 
reporting. One commenter noted that lowering the reporting threshold 
below the proposed 25,000 metric ton CO2e level would 
disproportionately affect small businesses. Another commenter stated 
that small businesses are not well equipped to handle detailed 
requirements for reporting and that the proposed rule would impose a 
large burden for monitoring, recordkeeping, and reporting activities.
    Additional comments received requested that EPA establish a SBREFA 
process to investigate the impacts that the proposed rule would have on 
small businesses.
    Response: As summarized above, EPA investigated alternative 
thresholds and analyzed the marginal costs associated with requiring 
smaller entities with lower emissions to report. EPA recognized the 
additional burden placed on small entities at lower thresholds, and had 
retained the hybrid method for reporting that includes a 25,000 metric 
ton CO2e level threshold. Under this threshold, EPA has 
assessed the economic impact of the final rule on small entities and 
concluded that this action will not have a significant economic impact 
on a substantial number of small entities.
    For this reason, EPA did not establish a SBREFA panel process for 
the rulemaking. The summary of the factual basis for the certification 
is provided in the preamble for the rule. Complete documentation of the 
analysis can be found in Section 5.2 of the RIA for the final rule.

E. What are the benefits of the rule for society?

1. Summary of Method Used To Estimate Compliance Costs
    EPA examined the potential benefits of the GHG reporting rule. The 
benefits of a reporting system are based on their relevance to policy 
making, transparency issues, and market efficiency. Benefits are very 
difficult to quantify and monetize. Instead of a quantitative analysis 
of the benefits, EPA conducted a systematic literature review of 
existing studies including government, consulting, and scholarly 
reports.
    A mandatory reporting system will benefit the public by increased 
transparency of facility emissions data. Transparent, public data on 
emissions allows for accountability of polluters to the public 
stakeholders who bear the cost of the pollution. Citizens, community 
groups, and labor unions have made use of data from Pollutant Release 
and Transfer Registers to negotiate directly with polluters to lower 
emissions, circumventing greater government regulation. Publicly 
available emissions data also will allow individuals to alter their 
consumption habits based on the GHG emissions of producers.
    The greatest benefit of mandatory reporting of industry GHG 
emissions to government will be realized in developing future GHG 
policies. For example, in the EU's Emissions Trading System, a lack of 
accurate monitoring at the facility level before establishing 
CO2 allowance permits resulted in allocation of permits for 
emissions levels an average of 15 percent above actual levels in every 
country except the United Kingdom.
    Benefits to industry of GHG emissions monitoring include the value 
of having independent, verifiable data to present to the public to 
demonstrate appropriate environmental stewardship, and a better 
understanding of their emission levels and sources to identify 
opportunities to reduce emissions. Such monitoring allows for inclusion 
of standardized GHG data into environmental management systems, 
providing the necessary information to achieve and

[[Page 56369]]

disseminate their environmental achievements.
    Standardization will also be a benefit to industry, once facilities 
invest in the institutional knowledge and systems to report emissions, 
the cost of monitoring should fall and the accuracy of the accounting 
should improve. A standardized reporting program will also allow for 
facilities to benchmark themselves against similar facilities to 
understand better their relative standing within their industry.
2. Summary of Comments and Responses
    Comment: Comments received on the benefits of the mandatory 
reporting program focused on the potential future uses of the collected 
data. Additional comments on the benefits of the program were concerned 
that the benefits of the rule are not quantified.
    Response: The data collected under this rule will provide 
comprehensive and accurate data to inform future climate change 
policies. Potential future CAA and other climate policies include 
research and development initiatives, economic incentives, new or 
expanded voluntary programs, adaptation strategies, emission standards, 
a carbon tax, or a cap-and-trade program. Because EPA does not know at 
this time the specific policies that may be adopted, the data reported 
through this rule should be of sufficient quality to support a range of 
approaches.
    Section VI of the RIA for the final rule summarizes the anticipated 
benefits of the rule, which include providing the government with sound 
data on which to base future policies and providing industry and the 
public independently verified information documenting firms' 
environmental performance. While EPA has not quantified the benefits of 
the mandatory reporting rule, EPA believes that they are substantial 
and outweigh the estimated costs.

VIII. Statutory and Executive Order Reviews

A. Executive Order 12866: Regulatory Planning and Review

    Under section 3(f)(1) of EO 12866 (58 FR 51735, October 4, 1993), 
this action is an ``economically significant regulatory action'' 
because it is likely to have an annual effect on the economy of $100 
million or more. Accordingly, EPA submitted this action to the OMB for 
review under EO 12866 and any changes made in response to OMB 
recommendations have been documented in the docket for this action.
    In addition, EPA prepared an analysis of the potential costs and 
benefits associated with this action. A copy of the analysis is 
available in Docket No. EPA-HQ-OAR-2008-0508, the RIA for the final 
rule, and is briefly summarized in Section VII of this preamble.

B. Paperwork Reduction Act

    The information collection requirements in this rule have been 
submitted for approval to the Office of Management and Budget (OMB) 
under the Paperwork Reduction Act, 44 U.S.C. 3501 et seq. The 
information collection requirements are not enforceable until OMB 
approves them. The ICR document prepared by EPA has been assigned EPA 
ICR number 2300.03.
    EPA plans to collect complete and accurate economy-wide data on 
facility-level GHG emissions. Accurate and timely information on GHG 
emissions is essential for informing future climate change policy 
decisions. Through data collected under this rule, EPA will gain a 
better understanding of the relative emissions of specific industries, 
and the distribution of emissions from individual facilities within 
those industries. The facility-specific data will also improve our 
understanding of the factors that influence GHG emission rates and 
actions that facilities are already taking to reduce emissions. 
Additionally, EPA will be able to track the trend of emissions from 
industries and facilities within industries over time, particularly in 
response to policies and potential regulations. The data collected by 
this rule will improve EPA's ability to formulate climate change policy 
options and to assess which industries would be affected, and how these 
industries would be affected by the options.
    This information collection is mandatory and will be carried out 
under CAA sections 114 and 208. Information identified and marked as 
CBI will not be disclosed except in accordance with procedures set 
forth in 40 CFR part 2. However, emissions data collected under CAA 
sections 114 and 208 cannot generally be claimed as CBI and will be 
made public.\34\
---------------------------------------------------------------------------

    \34\ Although CBI determinations are usually made on a case-by-
case basis, EPA has issued guidance in an earlier Federal Register 
notice on what constitutes emissions data that cannot be considered 
CBI (956 FR 7042-7043, February 21, 1991). As discussed in Section 
II.R of this preamble, EPA will be initiating a separate notice and 
comment process to make CBI determinations for the data collected 
under this rulemaking.
---------------------------------------------------------------------------

    The projected cost and hour burden for non-Federal respondents is 
$86.3 million and 1.21 million hours per year. The estimated average 
burden per response is two hours; the frequency of response is annual 
for all respondents that must comply with the rule's reporting 
requirements, except for electricity generating units that are already 
required to report quarterly under 40 CFR part 75 (EPA Acid Rain 
Program); and the estimated average number of likely respondents per 
year is 16,725 \35\. The cost burden to respondents resulting from the 
collection of information includes the total capital cost annualized 
over the equipment's expected useful life (averaging $9.1 million), a 
total operation and maintenance component (averaging $11.0 million per 
year), and a labor cost component (averaging $66.1 million per year). 
Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from 
those shown elsewhere in the RIA for the final rule because the ICR 
costs represent the average cost over the first three years of the 
rule, but costs are reported elsewhere in the RIA for the final rule 
for the first year of the rule and for subsequent years of the rule. In 
addition, the ICR focuses on respondent burden, while the RIA for the 
final rule includes EPA Agency costs.
---------------------------------------------------------------------------

    \35\ EPA estimates that 30,000 facilities are potentially 
affected by the rule. Of these, EPA estimates that 10,152 facilities 
across various sectors will be over their sector-specific reporting 
threshold and thus required to report; the remaining 19,848 will 
determine during the first year that they are beneath the threshold 
and do not need to report. The average number of respondents is thus 
(30,000+10,152+10,152)/3 = 16,768; excluding 43 Federal facilities, 
the number of private respondents is 16,725.
---------------------------------------------------------------------------

    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. When this ICR is 
approved by OMB, the Agency will publish a technical amendment to 40 
CFR part 9 in the Federal Register to display the OMB control number 
for the approved information collection requirements contained in this 
final rule.

C. Regulatory Flexibility Act (RFA)

    The RFA generally requires an agency to prepare a regulatory 
flexibility analysis of any rule subject to notice and comment 
rulemaking requirements under the Administrative Procedure Act or any 
other statute unless the agency certifies that the rule will not have a 
significant economic impact on a substantial number of small entities. 
Small entities include small businesses, small organizations, and small 
governmental jurisdictions.
    For purposes of assessing the impacts of today's rule on small 
entities, small entity is defined as: (1) A small business

[[Page 56370]]

as defined by the Small Business Administration's regulations at 13 CFR 
121.201; (2) a small governmental jurisdiction that is a government of 
a city, county, town, school district or special district with a 
population of less than 50,000; and (3) a small organization that is 
any not-for-profit enterprise which is independently owned and operated 
and is not dominant in its field.
    After considering the economic impacts of today's final rule on 
small entities, I therefore certify that this final rule will not have 
a significant economic impact on a substantial number of small 
entities.
    The small entities directly regulated by this final rule include 
small businesses across all sectors encompassed by the rule, small 
governmental jurisdictions and small non-profits. We have determined 
that some small businesses will be affected because their production 
processes emit GHGs that must be reported, because they have stationary 
combustion units on site that emit GHGs that must be reported, or 
because they have fuel supplier operations for which supply quantities 
and GHG data must be reported. Small governments and small non-profits 
are generally affected because they have regulated landfills or 
stationary combustion units on site, or because they own an LDC.
    For affected small entities, EPA conducted a screening assessment 
comparing compliance costs for affected industry sectors to industry-
specific data on revenues for small businesses. This ratio constitutes 
a ``sales'' test that computes the annualized compliance costs of this 
final rule as a percentage of sales and determines whether the ratio 
exceeds some level (e.g., one percent or three percent). The cost-to-
sales ratios were constructed at the establishment level (average 
compliance cost for the establishment/average establishment revenues). 
As shown in Table VII-5 of this preamble, the cost-to-sales ratios are 
less than one percent for establishments owned by small businesses that 
EPA considers most likely to be covered by the reporting program, those 
with more than 20 employees.\36\ For the few sectors where the 
preliminary screening showed a cost-to-sales ratio exceeding one 
percent, EPA's examination of firm-specific sales information showed 
that no affected entity was likely to incur costs exceeding one percent 
of sales.
---------------------------------------------------------------------------

    \36\ U.S. Small Business Administration (SBA). 2008. Firm Size 
Data from the Statistics of U.S. Businesses: U.S. Detail Employment 
Sizes: 2002. http://www.census.gov/csd/susb/download_susb02.htm.
---------------------------------------------------------------------------

    The screening analysis thus indicates that the final rule will not 
have a significant economic impact on a substantial number of small 
entities. See Table VII-5 of this preamble for sector-specific results. 
The screening assessment for small governments compared the sum of 
average costs of compliance for combustion, local distribution 
companies, and landfills to average revenues for small governments. 
Even for a small government owning all three source types, the costs 
constitute less than one percent of average revenues for the smallest 
category of governments (those with fewer than 10,000 people).
    Although this final rule will not have a significant economic 
impact on a substantial number of small entities, EPA nonetheless took 
several steps to reduce the impact of this rule on small entities. For 
example, EPA determined appropriate thresholds that reduce the number 
of small businesses reporting. In addition, EPA is not requiring 
facilities to install CEMS if they do not already have them. Facilities 
without CEMS can calculate emissions using readily available data or 
data that are less expensive to collect such as process data or 
material consumption data. For some source categories, EPA developed 
tiered methods that are simpler and less burdensome. Also, EPA is 
requiring annual instead of more frequent reporting.
    Through comprehensive outreach activities prior to proposal of the 
rule, EPA held approximately 100 meetings and/or conference calls with 
representatives of the primary audience groups, including numerous 
trade associations and industries that include small business members. 
EPA's outreach activities prior to proposal of the rule are documented 
in the memorandum, ``Summary of EPA Outreach Activities for Developing 
the Greenhouse Gas Reporting Rule,'' located in Docket No. EPA-HQ-OAR-
2008-0508-055. After proposal, EPA posted a guide for small businesses 
on EPA's GHG reporting rule Web site, along with a general fact sheet 
for the rule, information sheets for every source category, and an FAQ 
document. EPA also operated a hotline to answer questions about the 
proposed rule. We continued to meet with stakeholders and entered 
documentation of all meetings into the docket. We considered public 
comments, including comments from small businesses and organizations 
that include small business members, in developing the final rule.
    During rule implementation, EPA will maintain an ``open door'' 
policy for stakeholders to ask questions about the rule or provide 
suggestions to EPA about the types of compliance assistance that would 
be useful to small businesses. EPA intends to develop a range of 
compliance assistance tools and materials and conduct extensive 
outreach for the final rule.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the Unfunded Mandates Reform Act of 1995 (UMRA), 2 
U.S.C. 1531-1538, requires Federal agencies, unless otherwise 
prohibited by law, to assess the effects of their regulatory actions on 
State, local, and Tribal governments and the private sector.
    EPA has developed this regulation under authority of CAA sections 
114 and 208. The required activities under this Federal mandate include 
monitoring, recordkeeping, and reporting of GHG emissions from multiple 
source categories (e.g., combustion, process, and biologic). This rule 
contains a Federal mandate that may result in expenditures of $100 
million for the private sector in any one year. As described below, we 
have determined that the expenditures for State, local, and Tribal 
governments, in the aggregate, will be approximately $12.1 million per 
year, based on average costs over the first three years of the rule, 
including approximately $2 million during the first year of the rule 
for governments to make a reporting determination and subsequently 
determine that their emissions are below the threshold and thus, they 
are not required to report their emissions. Accordingly, EPA has 
prepared under section 202 of the UMRA a written statement which is 
summarized below.
    Consistent with the intergovernmental consultation provisions of 
section 204 of the UMRA, EPA initiated an outreach effort with the 
governmental entities affected by this rule including State, local, and 
Tribal officials. EPA maintained an ``open door'' policy for 
stakeholders to provide input on key issues and to help inform EPA's 
understanding of issues, including impacts to State, local and Tribal 
governments. The outreach audience included State environmental 
protection agencies, regional and Tribal organizations, and other State 
and local government organizations. EPA contacted several States and 
State and regional organizations already involved in GHG emissions 
reporting. EPA also conducted several conference calls with Tribal 
organizations during the proposal phase. For example, EPA staff 
provided information to tribes through conference calls with multiple 
Tribal working groups and organizations at EPA and

[[Page 56371]]

through individual calls with two Tribal board members of TRI. In 
addition, EPA held meetings and conference calls with groups such as 
TRI, National Association of Clean Air Agencies (NACAA), ECOS, and with 
State members of RGGI, the Midwestern GHG Reduction Accord, and WCI. 
See the ``Summary of EPA Outreach Activities for Developing the 
Greenhouse Gas Reporting Rule,'' in Docket No. EPA-HQ-OAR-2008-0508-055 
for a complete list of organizations and groups that EPA contacted.
    At proposal of the rule, EPA posted a guide for State and local 
agencies on the Web site, along with other information sheets, to 
communicate key aspects of the proposed rule to these agencies. Several 
State and local agencies and three Tribal organizations or communities 
submitted written public comments, and EPA carefully considered these 
comments in developing the final rule. EPA also continued to meet with 
government agencies or organizations with State members such as 
California ARB, Connecticut DEP, New Jersey DEP, New Mexico ED, 
Washington DE, Massachusetts DEP, Illinois EPA, Iowa DNR, and TCR These 
meetings are documented in the docket. EPA intends to continue to work 
closely with State, local, and Tribal agencies during rule 
implementation.
    Consistent with section 205 of the UMRA, EPA has identified and 
considered a reasonable number of regulatory alternatives. EPA 
carefully examined regulatory alternatives, and selected the lowest 
cost/least burdensome alternative that EPA deems adequate to address 
Congressional concerns and to provide a consistent, comprehensive 
source of information about emissions of GHGs. EPA has considered the 
costs and benefits of the GHG reporting rule, and has concluded that 
the costs will fall mainly on the private sector (approximately $77 
million), with some costs incurred by State, local, and Tribal 
governments that must report their emissions (less than $10.1 million) 
that own and operate stationary combustion units, landfills, or natural 
gas local distribution companies (LDCs). EPA estimates that an 
additional 2,034 facilities owned by State, local, or Tribal 
governments will incur approximately $2.0 million in costs during the 
first year of the rule to make a reporting determination and 
subsequently determine that their emissions are below the threshold and 
thus, they are not required to report their emissions. Furthermore, we 
think it is unlikely that State, local, and Tribal governments would 
begin operating large industrial facilities, similar to those affected 
by this rulemaking operated by the private sector.
    Initially, EPA estimates that costs of complying with the final 
rule will be widely dispersed throughout many sectors of the economy. 
Although EPA acknowledges that over time changes in the patterns of 
economic activity may mean that GHG generation and thus reporting costs 
will change, data are inadequate for projecting these changes. Thus, 
EPA assumes that costs averaged over the first three years of the 
program are typical of ongoing costs of compliance. EPA estimates that 
future compliance costs will total approximately $104 million per year. 
EPA examined the distribution of these costs between private owners and 
State, local, and Tribal governments owning GHG emitters. In addition, 
EPA examined, within the private sector, the impacts on various 
industries. In general, estimated cost per entity represents less than 
0.1 percent of company sales in affected industries. These costs are 
broadly distributed to a variety of economic sectors and represent 
approximately 0.001 percent of 2008 Gross Domestic Product; overall, 
EPA does not believe the final rule will have a significant 
macroeconomic impact on the national economy. Therefore, this rule is 
not subject to the requirements of section 203 of UMRA because it 
contains no regulatory requirements that might significantly or 
uniquely affect small governments.
    EPA does not anticipate that substantial numbers of either public 
or private sector entities will incur significant economic impacts as a 
result of this final rule. EPA further expects that benefits of the 
final rule will include more and better information for EPA and the 
private sector about emissions of GHGs. This improved information will 
enhance EPA's ability to develop sound future climate policies, and may 
encourage GHG emitters to develop voluntary plans to reduce their 
emissions.
    This regulation applies directly to facilities that supply fuel or 
chemicals that when used emit greenhouse gases, to motor vehicle 
manufacturers, and to facilities that directly emit greenhouses gases. 
It does not apply to governmental entities unless the government entity 
owns a facility that directly emits GHGs above threshold levels such as 
a landfill or large stationary combustion source, or LDC. In addition, 
this rule does not impose any implementation responsibilities on State, 
local, or Tribal governments and it is not expected to increase the 
cost of existing regulatory programs managed by those governments. 
Thus, the impact on governments affected by the rule is expected to be 
minimal.

E. Executive Order 13132: Federalism

    EO 13132, entitled ``Federalism'' (64 FR 43255, August 10, 1999), 
requires EPA to develop an accountable process to ensure ``meaningful 
and timely input by State and local officials in the development of 
regulatory policies that have Federalism implications.'' ``Policies 
that have Federalism implications'' is defined in the EO to include 
regulations that have ``substantial direct effects on the States, on 
the relationship between the national government and the States, or on 
the distribution of power and responsibilities among the various levels 
of government.''
    This final rule does not have Federalism implications. It will not 
have substantial direct effects on the States, on the relationship 
between the national government and the States, or on the distribution 
of power and responsibilities among the various levels of government, 
as specified in EO 13132. However, for a more detailed discussion about 
how this final rule relates to existing State programs, please see 
Section II of the proposal preamble (74 FR 16457 to 16461, April 10, 
2009) and Sections I.E. and II.C.2 of this preamble.
    This regulation applies directly to facilities that supply fuel or 
chemicals that when used emit greenhouse gases, motor vehicle 
manufacturers, or facilities that directly emit greenhouses gases. It 
does not apply to governmental entities unless the government entity 
owns a facility that directly emits GHGs above threshold levels such as 
a landfill, large stationary combustion source, or LDC, so relatively 
few government facilities would be affected. This regulation also does 
not limit the power of States or localities to collect GHG data and/or 
regulate GHG emissions. Thus, EO 13132 does not apply to this rule.
    In the spirit of Executive Order 13132, and consistent with EPA 
policy to promote communications between EPA and State and local 
governments, EPA specifically solicited comments on the proposed rule 
from State and local officials. See Section VIII.D above, for 
discussion of outreach activities to State, local, or Tribal 
organizations.

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

    This final rule does not have Tribal implications, as specified in 
EO 13175 (65 FR 67249, November 9, 2000). This

[[Page 56372]]

regulation applies directly to facilities that supply fuel or chemicals 
that when used emit GHGs or facilities that directly emit greenhouses 
gases. Facilities expected to be affected by the final rule are not 
expected to be owned by Tribal governments. Thus, Executive Order 13175 
does not apply to this final rule.
    Although EO 13175 does not apply to this final rule, EPA sought 
opportunities to provide information to Tribal governments and 
representatives during development of the rule. In consultation with 
EPA's American Indian Environment Office, EPA's outreach plan included 
tribes. EPA conducted several conference calls with Tribal 
organizations during the proposal phase. For example, EPA staff 
provided information to tribes through conference calls with multiple 
Indian working groups and organizations at EPA that interact with 
tribes and through individual calls with two Tribal board members of 
TCR. In addition, EPA prepared a short article on the GHG reporting 
rule that appeared on the front page a Tribal newsletter--Tribal Air 
News--that was distributed to EPA/OAQPS's network of Tribal 
organizations. EPA gave a presentation on various climate efforts, 
including the mandatory reporting rule, at the National Tribal 
Conference on Environmental Management on June 24-26, 2008. In 
addition, EPA had copies of a short information sheet distributed at a 
meeting of the National Tribal Caucus. See the ``Summary of EPA 
Outreach Activities for Developing the GHG reporting rule,'' in Docket 
No. EPA-HQ-OAR-2008-0508-055 for a complete list of Tribal contacts. 
EPA participated in a conference call with Tribal air coordinators in 
April 2009 and prepared a guidance sheet for Tribal governments on the 
proposed rule. It was posted on the MRR Web site and published in the 
Tribal Air Newsletter.

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

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

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

    This final rule is not a ``significant energy action'' as defined 
in EO 13211 (66 FR 28355, May 22, 2001) because it is not likely to 
have a significant adverse effect on the supply, distribution, or use 
of energy. Further, we have concluded that this rule is not likely to 
have any adverse energy effects. This final rule relates to monitoring, 
reporting and recordkeeping at facilities that supply fuel or chemicals 
that when used emit GHGs or facilities that directly emit greenhouses 
gases and does not impact energy supply, distribution or use. 
Therefore, we conclude that this rule is not likely to have any adverse 
effects on energy supply, distribution, or use.

I. National Technology Transfer and Advancement Act

    Section 12(d) of the National Technology Transfer and Advancement 
Act of 1995 (NTTAA), Public Law 104-113 (15 U.S.C. 272 note) directs 
EPA to use voluntary consensus standards in its regulatory activities 
unless to do so would be inconsistent with applicable law or otherwise 
impractical. Voluntary consensus standards are technical standards 
(e.g., materials specifications, test methods, sampling procedures, and 
business practices) that are developed or adopted by voluntary 
consensus standards bodies. NTTAA directs EPA to provide Congress, 
through OMB, explanations when the Agency decides not to use available 
and applicable voluntary consensus standards.
    This rulemaking involves technical standards. EPA will use more 
than 60 voluntary consensus standards from 10 different voluntary 
consensus standards bodies, including the following: ASTM, ASME, ISO, 
Gas Processors Association, American Gas Association, and National Lime 
Association. These voluntary consensus standards will help facilities 
monitor, report, and keep records of GHG emissions. No new test methods 
were developed for this rule. Instead, from existing rules for source 
categories and voluntary GHG programs, EPA identified existing means of 
monitoring, reporting, and keeping records of GHG emissions. The 
existing methods (voluntary consensus standards) include a broad range 
of measurement techniques, including many for combustion sources such 
as methods to analyze fuel and measure its heating value; methods to 
measure gas or liquid flow; and methods to gauge and measure petroleum 
and petroleum products. The test methods are incorporated by reference 
into the final rule and are available as specified in 40 CFR 98.7.
    By incorporating voluntary consensus standards into this final 
rule, EPA is both meeting the requirements of the NTTAA and presenting 
multiple options and flexibility for measuring GHG emissions.

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

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

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, 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 a ``major rule'' as defined by 5 U.S.C. 
804(2). This rule will be effective December 29, 2009.

List of Subjects

40 CFR Part 86

    Environmental protection, Administrative practice and procedure,

[[Page 56373]]

Air pollution control, Reporting and recordkeeping requirements, Motor 
vehicle pollution.

40 CFR Part 87

    Environmental protection, Air pollution control, Aircraft, 
Incorporation by reference.

40 CFR Part 89

    Environmental protection, Administrative practice and procedure, 
Confidential business information, Imports, Labeling, Motor vehicle 
pollution, Reporting and recordkeeping requirements, Research, Vessels, 
Warranty.

40 CFR Part 90

    Environmental protection, Administrative practice and procedure, 
Confidential business information, Imports, Labeling, Reporting and 
recordkeeping requirements, Research, Warranty.

40 CFR Part 94

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Confidential business information, Imports, 
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and 
recordkeeping requirements, Warranties.

40 CFR Part 98

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

40 CFR Part 1033

    Environmental protection, Administrative practice and procedure, 
Confidential business information, Incorporation by reference, 
Labeling, Penalties, Railroads, Reporting and recordkeeping 
requirements.

40 CFR Part 1039

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Confidential business information, Imports, 
Incorporation by reference, Labeling, Penalties, Reporting and 
recordkeeping requirements, Warranties.

40 CFR Part 1042

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Confidential business information, Imports, 
Incorporation by reference, Labeling, Penalties, Vessels, Reporting and 
recordkeeping requirements, Warranties.

40 CFR Parts 1045, 1048, 1051, and 1054

    Environmental protection, Administrative practice and procedure, 
Air pollution control, Confidential business information, Imports, 
Incorporation by reference, Labeling, Penalties, Reporting and 
recordkeeping requirements, Warranties.

40 CFR Part 1065

    Environmental protection, Administrative practice and procedure, 
Incorporation by reference, Reporting and recordkeeping requirements, 
Research.

    Dated: September 22, 2009.
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 86--[AMENDED]

0
1. The authority citation for part 86 continues to read as follows:

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

Subpart A--[Amended]

0
2. Section 86.007-23 is amended by adding paragraph (n) to read as 
follows:


Sec.  86.007-23  Required data.

* * * * *
    (n) Measure CO2, N2O, and CH4 with 
each low-hour certification test for heavy-duty engines using the 
procedures specified in 40 CFR part 1065 as specified in this paragraph 
(n). Report these values in your application for certification. The 
requirements of this paragraph (n) apply starting with model year 2011 
for CO2 and 2012 for CH4. The requirements of 
this paragraph (n) related to N2O emissions apply for engine 
families that depend on NOx aftertreatment to meet emission 
standards starting with model year 2013. These measurements are not 
required for NTE testing. Use the same units and calculations as for 
your other results to report a single weighted value for 
CO2, N2O, and CH4 for each test. Round 
the final values as follows:
    (1) Round CO2 to the nearest 1 g/bhp-hr.
    (2) Round N2O to the nearest 0.001 g/bhp-hr.
    (3) Round CH4 to the nearest 0.001 g/bhp-hr.

0
3. Section 86.078-3 is amended by removing the paragraph designation 
``(a)'' and adding the abbreviations CH4 and N2O 
in alphanumeric order to read as follows:


Sec.  86.078-3  Abbreviations.

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

Subpart E--[Amended]

0
4. Section 86.403-78 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  86.403-78  Abbreviations.

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

0
5. Section 86.431-78 is amended by adding paragraph (e) to read as 
follows:


Sec.  86.431-78  Data submission.

* * * * *
    (e) Measure CO2, N2O, and CH4 as 
described in this paragraph (e) with each zero kilometer certification 
test (if one is conducted) and with each test conducted at the 
applicable minimum test distance as defined in Sec.  86.427-78. Use the 
analytical equipment and procedures specified in 40 CFR part 1065 as 
needed to measure N2O and CH4. Report these 
values in your application for certification. The requirements of this 
paragraph (e) apply starting with model year 2011 for CO2 
and 2012 for CH4. The requirements of this paragraph (e) 
related to N2O emissions apply for engine families that 
depend on NOX aftertreatment to meet emission standards 
starting with model year 2013. Small-volume manufacturers (as defined 
in Sec.  86.410-2006(e)) may omit measurement of N2O and 
CH4; other manufacturers may provide appropriate data and/or 
information and omit measurement of N2O and CH4 
as described in 40 CFR 1065.5. Use the same measurement methods as for 
your other results to report a single value for CO2, 
N2O, and CH4. Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/km.
    (2) Round N2O to the nearest 0.001 g/km.
    (3) Round CH4 to the nearest 0.001 g/km.

PART 87--[AMENDED]

0
6. The authority citation for part 87 is revised to read as follows:

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

[[Page 56374]]

Subpart A--[Amended]

0
7. Section 87.2 is amended by revising the section heading and adding 
the abbreviation CO2 in alphanumeric order to read as 
follows:


Sec.  87.2  Acronyms and abbreviations.

* * * * *
    CO2 Carbon dioxide.
* * * * *

0
8. Section 87.64 is revised to read as follows:


Sec.  87.64  Sampling and analytical procedures for measuring gaseous 
exhaust emissions.

    (a) The system and procedures for sampling and measurement of 
gaseous emissions shall be as specified by Appendices 3 and 5 to ICAO 
Annex 16 (incorporated by reference in Sec.  87.8).
    (b) Starting January 1, 2011, report CO2 values along 
with your emission levels of regulated NOX to the 
Administrator for engines of a type or model of which the date of 
manufacture of the first individual production model was on or after 
January 1, 2011. By January 1, 2011, report CO2 values along 
with your emission levels of regulated NOX to the 
Administrator for engines currently in production and of a type or 
model for which the date of manufacture of the individual engine was 
before January 1, 2011. Round CO2 to the nearest 1 g/
kilonewton rO.
    (c) Report CO2 by calculation from fuel mass flow rate 
measurements in Appendices 3 and 5 to ICAO Annex 16, volume II or 
alternatively, according to the measurement criteria of CO2 
in Appendices 3 and 5 to ICAO Annex 16, volume II.

PART 89--[AMENDED]

0
9. The authority citation for part 89 continues to read as follows:

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

Subpart B--[Amended]

0
10. Section 89.115 is amended by revising paragraph (d)(9) to read as 
follows:


Sec.  89.115  Application for certificate.

* * * * *
    (d) * * *
    (9) All test data obtained by the manufacturer on each test engine, 
including CO2 as specified in Sec.  89.407(d)(1);
* * * * *

Subpart E--[Amended]

0
11. Section 89.407 is amended by revising paragraph (d)(1) to read as 
follows:


Sec.  89.407  Engine dynamometer test run.

* * * * *
    (d) * * *
    (1) Measure HC, CO, CO2, and NOx 
concentrations in the exhaust sample. Use the same units and modal 
calculations as for your other results to report a single weighted 
value for CO2; round CO2 to the nearest 1 g/kW-
hr.
* * * * *

PART 90--[AMENDED]

0
12. The authority citation for part 90 continues to read as follows:

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

Subpart B--[Amended]

0
13. Section 90.107 is amended by revising paragraph (d)(8) to read as 
follows:


Sec.  90.107  Application for certification.

* * * * *
    (d) * * *
    (8) All test data obtained by the manufacturer on each test engine, 
including CO2 as specified in Sec.  90.409(c)(1);
* * * * *

Subpart E--[Amended]

0
14. Section 90.409 is amended by revising paragraph (c)(1) to read as 
follows:


Sec.  90.409  Engine dynamometer test run.

* * * * *
    (c) * * *
    (1) Measure HC, CO, CO2, and NOX 
concentrations in the exhaust sample. Use the same units and modal 
calculations as for your other results to report a single weighted 
value for CO2; round CO2 to the nearest 1 g/kW-
hr.
* * * * *

PART 94--[AMENDED]

0
15. The authority citation for part 94 continues to read as follows:

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

Subpart A--[Amended]

0
16. Section 94.3 is amended by adding the abbreviation CH4 
in alphanumeric order to read as follows:


Sec.  94.3  Abbreviations.

* * * * *
    CH4 methane.
* * * * *

Subpart B--[Amended]

0
17. Section 94.103 is amended by adding paragraph (c) to read as 
follows:


Sec.  94.103  Test procedures for Category 1 marine engines.

* * * * *
    (c) Measure CH4 as specified in 40 CFR 1042.235 starting 
in the 2012 model year.

0
18. Section 94.104 is amended by adding paragraph (e) to read as 
follows:


Sec.  94.104  Test procedures for Category 2 marine engines.

* * * * *
    (e) Measure CO2 as described in 40 CFR 92.129 through 
the 2010 model year. Measure CO2 as specified in 40 CFR 
1042.235 starting in the 2011 model year. Measure CH4 as 
specified in 40 CFR 1042.235 starting in the 2012 model year.

Subpart C--[Amended]

0
19. Section 94.203 is amended by revising paragraph (d)(10) to read as 
follows:


Sec.  94.203  Application for certification.

* * * * *
    (d) * * *
    (10) All test data obtained by the manufacturer on each test 
engine, including CO2 and CH4 as specified in 40 
CFR 89.407(d)(1) and Sec.  94.103(c) for Category 1 engines, Sec.  
94.104(e) for Category 2 engines, and Sec.  94.109(d) for Category 3 
engines. Small-volume manufacturers may omit measurement and reporting 
of CH4.
* * * * *

0
20. Add part 98 to read as follows:

PART 98--MANDATORY GREENHOUSE GAS REPORTING

Sec.
Subpart A--General Provisions
98.1 Purpose and scope.
98.2 Who must report?
98.3 What are the general monitoring, reporting, recordkeeping and 
verification requirements of this part?
98.4 Authorization and responsibilities of the designated 
representative.
98.5 How is the report submitted?
98.6 Definitions.
98.7 What standardized methods are incorporated by reference into 
this part?
98.8 What are the compliance and enforcement provisions of this 
part?
98.9 Addresses.
Table A-1 to Subpart A of Part 98--Global Warming Potentials (100-
Year Time Horizon)
Table A-2 to Subpart A of Part 98--Units of Measure Conversions

[[Page 56375]]

Subpart B--[RESERVED]
Subpart C--General Stationary Fuel Combustion Sources
98.30 Definition of the source category.
98.31 Reporting threshold.
98.32 GHGs to report.
98.33 Calculating GHG emissions.
98.34 Monitoring and QA/QC requirements.
98.35 Procedures for estimating missing data.
98.36 Data reporting requirements.
98.37 Records that must be retained.
98.38 Definitions.
Table C-1 to Subpart C of Part 98--Default CO2 Emission 
Factors and High Heat Values for Various Types of Fuel
Table C-2 to Subpart C of Part 98--Default CH4 and 
N2O Emission Factors for Various Types of Fuel
Subpart D--Electricity Generation
98.40 Definition of the source category.
98.41 Reporting threshold.
98.42 GHGs to report.
98.43 Calculating GHG emissions.
98.44 Monitoring and QA/QC requirements
98.45 Procedures for estimating missing data.
98.46 Data reporting requirements.
98.47 Records that must be retained.
98.48 Definitions.
Subpart E--Adipic Acid Production
98.50 Definition of source category.
98.51 Reporting threshold.
98.52 GHGs to report.
98.53 Calculating GHG emissions.
98.54 Monitoring and QA/QC requirements
98.55 Procedures for estimating missing data.
98.56 Data reporting requirements.
98.57 Records that must be retained.
98.58 Definitions.
Subpart F--Aluminum Production
98.60 Definition of the source category.
98.61 Reporting threshold.
98.62 GHGs to report.
98.63 Calculating GHG emissions.
98.64 Monitoring and QA/QC requirements.
98.65 Procedures for estimating missing data.
98.66 Data reporting requirements.
98.67 Records that must be retained.
98.68 Definitions.
Table F-1 to Subpart F of Part 98--Slope and Overvoltage 
Coefficients for the Calculation of PFC Emissions From Aluminum 
Production
Table F-2 to Subpart F of Part 98--Default Data Sources for 
Parameters Used for CO2 Emissions
Subpart G--Ammonia Manufacturing
98.70 Definition of source category.
98.71 Reporting threshold.
98.72 GHGs to report.
98.73 Calculating GHG emissions.
98.74 Monitoring and QA/QC requirements.
98.75 Procedures for estimating missing data.
98.76 Data reporting requirements.
98.77 Records that must be retained.
98.78 Definitions.
Subpart H--Cement Production
98.80 Definition of the source category.
98.81 Reporting threshold.
98.82 GHGs to report.
98.83 Calculating GHG emissions.
98.84 Monitoring and QA/QC requirements.
98.85 Procedures for estimating missing data.
98.86 Data reporting requirements.
98.87 Records that must be retained.
98.88 Definitions.
Subpart I--[RESERVED]
Subpart J--[RESERVED]
Subpart K--Ferroalloy Production
98.110 Definition of the source category.
98.111 Reporting threshold.
98.112 GHGs to report.
98.113 Calculating GHG emissions.
98.114 Monitoring and QA/QC requirements.
98.115 Procedures for estimating missing data.
98.116 Data reporting requirements.
98.117 Records that must be retained.
98.118 Definitions.
Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) CH4 
Emission Factors
Subpart L--[RESERVED]
Subpart M--[RESERVED]
Subpart N--Glass Production
98.140 Definition of the source category.
98.141 Reporting threshold.
98.142 GHGs to report.
98.143 Calculating GHG emissions.
98.144 Monitoring and QA/QC requirements.
98.145 Procedures for estimating missing data.
98.146 Data reporting requirements.
98.147 Records that must be retained.
98.148 Definitions.
Table N-1 to Subpart N of Part 98--CO2 Emission Factors 
for Carbonate-Based Raw Materials
Subpart O--HCFC-22 Production and HFC-23 Destruction
98.150 Definition of the source category.
98.151 Reporting threshold.
98.152 GHGs to report.
98.153 Calculating GHG emissions.
98.154 Monitoring and QA/QC requirements.
98.155 Procedures for estimating missing data.
98.156 Data reporting requirements.
98.157 Records that must be retained.
98.158 Definitions.
Table O-1 to Subpart O of Part 98--Emission Factors for Equipment 
Leaks
Subpart P--Hydrogen Production
98.160 Definition of the source category.
98.161 Reporting threshold.
98.162 GHGs to report.
98.163 Calculating GHG emissions.
98.164 Monitoring and QA/QC requirements.
98.165 Procedures for estimating missing data.
98.166 Data reporting requirements.
98.167 Records that must be retained.
98.168 Definitions.
Subpart Q--Iron and Steel Production
98.170 Definition of the source category.
98.171 Reporting threshold.
98.172 GHGs to report.
98.173 Calculating GHG emissions.
98.174 Monitoring and QA/QC requirements.
98.175 Procedures for estimating missing data.
98.176 Data reporting requirements.
98.177 Records that must be retained.
98.178 Definitions.
Subpart R--Lead Production
98.180 Definition of the source category.
98.181 Reporting threshold.
98.182 GHGs to report.
98.183 Calculating GHG emissions.
98.184 Monitoring and QA/QC requirements.
98.185 Procedures for estimating missing data.
98.186 Data reporting procedures.
98.187 Records that must be retained.
98.188 Definitions.
Subpart S--Lime Manufacturing
98.190 Definition of the source category.
98.191 Reporting threshold.
98.192 GHGs to report.
98.193 Calculating GHG emissions.
98.194 Monitoring and QA/QC requirements.
98.195 Procedures for estimating missing data.
98.196 Data reporting requirements.
98.197 Records that must be retained.
98.198 Definitions.
Table S-1 to Subpart S of Part 98--Basic Parameters for the 
Calculation of Emission Factors for Lime Production
Subpart T--[RESERVED]
Subpart U--Miscellaneous Uses of Carbonate
98.210 Definition of the source category.
98.211 Reporting threshold.
98.212 GHGs to report.
98.213 Calculating GHG emissions.
98.214 Monitoring and QA/QC requirements.
98.215 Procedures for estimating missing data.
98.216 Data reporting requirements.
98.217 Records that must be retained.
98.218 Definitions.
Table U-1 to Subpart U of Part 98--CO2 Emission Factors 
for Common Carbonates
Subpart V--Nitric Acid Production
98.220 Definition of source category.
98.221 Reporting threshold.
98.222 GHGs to report.
98.223 Calculating GHG emissions.
98.224 Monitoring and QA/QC requirements.
98.225 Procedures for estimating missing data.
98.226 Data reporting requirements.
98.227 Records that must be retained.
98.228 Definitions.

[[Page 56376]]

Subpart W--[RESERVED]
Subpart X--Petrochemical Production
98.240 Definition of the source category.
98.241 Reporting threshold.
98.242 GHGs to report.
98.243 Calculating GHG emissions.
98.244 Monitoring and QA/QC requirements.
98.245 Procedures for estimating missing data.
98.246 Data reporting requirements.
98.247 Records that must be retained.
98.248 Definitions.
Subpart Y--Petroleum Refineries
98.250 Definition of source category.
98.251 Reporting threshold.
98.252 GHGs to report.
98.253 Calculating GHG emissions.
98.254 Monitoring and QA/QC requirements.
98.255 Procedures for estimating missing data.
98.256 Data reporting requirements.
98.257 Records that must be retained.
98.258 Definitions.
Subpart Z--Phosphoric Acid Production
98.260 Definition of the source category.
98.261 Reporting threshold.
98.262 GHGs to report.
98.263 Calculating GHG emissions.
98.264 Monitoring and QA/QC requirements.
98.265 Procedures for estimating missing data.
98.266 Data reporting requirements.
98.267 Records that must be retained.
98.268 Definitions.
Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of 
Phosphate Rock by Origin
Subpart AA--Pulp and Paper Manufacturing
98.270 Definition of source category.
98.271 Reporting threshold.
98.272 GHGs to report.
98.273 Calculating GHG emissions.
98.274 Monitoring and QA/QC requirements.
98.275 Procedures for estimating missing data.
98.276 Data reporting requirements.
98.277 Records that must be retained.
98.278 Definitions.
Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions 
Factors for Biomass-Based CO2, CH4, and 
N2O
Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner 
Emissions Factors for Fossil Fuel-Based CO2, 
CH4, and N2O
Subpart BB--Silicon Carbide Production
98.280 Definition of the source category.
98.281 Reporting threshold.
98.282 GHGs to report.
98.283 Calculating GHG emissions.
98.284 Monitoring and QA/QC requirements.
98.285 Procedures for estimating missing data.
98.286 Data reporting requirements.
98.287 Records that must be retained.
98.288 Definitions.
Subpart CC--Soda Ash Manufacturing
98.290 Definition of the source category.
98.291 Reporting threshold.
98.292 GHGs to report.
98.293 Calculating GHG emissions.
98.294 Monitoring and QA/QC requirements.
98.295 Procedures for estimating missing data.
98.296 Data reporting requirements.
98.297 Records that must be retained.
98.298 Definitions.
Subpart DD--[RESERVED]
Subpart EE--Titanium Dioxide Production
98.310 Definition of the source category.
98.311 Reporting threshold.
98.312 GHGs to report.
98.313 Calculating GHG emissions.
98.314 Monitoring and QA/QC requirements.
98.315 Procedures for estimating missing data.
98.316 Data reporting requirements.
98.317 Records that must be retained.
98.318 Definitions.
Subpart FF--[RESERVED]
Subpart GG--Zinc Production
98.330 Definition of the source category.
98.331 Reporting threshold.
98.332 GHGs to report.
98.333 Calculating GHG emissions.
98.334 Monitoring and QA/QC requirements.
98.335 Procedures for estimating missing data.
98.336 Data reporting requirements.
98.337 Records that must be retained.
98.338 Definitions.
Subpart HH--Municipal Solid Waste Landfills
98.340 Definition of the source category.
98.341 Reporting threshold.
98.342 GHGs to report.
98.343 Calculating GHG emissions.
98.344 Monitoring and QA/QC requirements.
98.345 Procedures for estimating missing data.
98.346 Data reporting requirements.
98.347 Records that must be retained.
98.348 Definitions.
Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation 
Factors and Methods
Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal 
Rates
Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection 
Efficiencies
Subpart II--[RESERVED]
Subpart JJ--Manure Management
98.360 Definition of the source category.
98.361 Reporting threshold.
98.362 GHGs to report.
98.363 Calculating GHG emissions.
98.364 Monitoring and QA/QC requirements.
98.365 Procedures for estimating missing data.
98.366 Data reporting requirements.
98.367 Records that must be retained.
98.368 Definitions.
Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold 
Level Below which Facilities are not required to report Emissions 
under Subpart JJ
Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data
Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids 
(VS) and Nitrogen (N) Excretion Rates for Cattle
Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen 
Removal through Solids Separation
Table JJ-5 to Subpart JJ of Part 98--Methane Conversion Factors
Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of 
Anaerobic Digesters
Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors 
(kg N2O-N/kg Kjdl N)
Subpart KK--[RESERVED]
Subpart LL--Suppliers of Coal-based Liquid Fuels
98.380 Definition of the source category.
98.381 Reporting threshold.
98.382 GHGs to report.
98.383 Calculating GHG emissions.
98.384 Monitoring and QA/QC requirements.
98.385 Procedures for estimating missing data.
98.386 Data reporting requirements.
98.387 Records that must be retained.
98.388 Definitions.
Subpart MM--Suppliers of Petroleum Products
98.390 Definition of the source category.
98.391 Reporting threshold.
98.392 GHGs to report.
98.393 Calculating GHG emissions.
98.394 Monitoring and QA/QC requirements.
98.395 Procedures for estimating missing data.
98.396 Data reporting requirements.
98.397 Records that must be retained.
98.398 Definitions.
Table MM-1 to Subpart MM--Default CO2 Factors for 
Petroleum Products
Table MM-2 to Subpart MM--Default Factors for Biomass-Based Fuels 
and Biomass
Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids
98.400 Definition of the source category.
98.401 Reporting threshold.
98.402 GHGs to report.
98.403 Calculating GHG emissions.
98.404 Monitoring and QA/QC requirements.
98.405 Procedures for estimating missing data.
98.406 Data reporting requirements.
98.407 Records that must be retained.
98.408 Definitions.
Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation 
Methodology 1 of this Subpart
Table NN-2 to Subpart NN of Part 98--Lookup Default Values for 
Calculation Methodology 2 of this Subpart
Subpart OO--Suppliers of Industrial Greenhouse Gases
98.410 Definition of the source category.

[[Page 56377]]

98.411 Reporting threshold.
98.412 GHGs to report.
98.413 Calculating GHG emissions.
98.414 Monitoring and QA/QC requirements.
98.415 Procedures for estimating missing data.
98.416 Data reporting requirements.
98.417 Records that must be retained.
98.418 Definitions.
Subpart PP--Suppliers of Carbon Dioxide
98.420 Definition of the source category.
98.421 Reporting threshold.
98.422 GHGs to report.
98.423 Calculating CO2 supply.
98.424 Monitoring and QA/QC requirements.
98.425 Procedures for estimating missing data.
98.426 Data reporting requirements.
98.427 Records that must be retained.
98.428 Definitions.

    Authority:  42 U.S.C. 7401, et seq.

Subpart A--General Provisions


Sec.  98.1  Purpose and scope.

    (a) This part establishes mandatory greenhouse gas (GHG) reporting 
requirements for owners and operators of certain facilities that 
directly emit GHG as well as for certain fossil fuel suppliers and 
industrial GHG suppliers. For suppliers, the GHGs reported are the 
quantity that would be emitted from combustion or use of the products 
supplied.
    (b) Owners and operators of facilities and suppliers that are 
subject to this part must follow the requirements of subpart A and all 
applicable subparts of this part. If a conflict exists between a 
provision in subpart A and any other applicable subpart, the 
requirements of the subparts B through PP of this part shall take 
precedence.


Sec.  98.2  Who must report?

    (a) The GHG reporting requirements and related monitoring, 
recordkeeping, and reporting requirements of this part apply to the 
owners and operators of any facility that is located in the United 
States and that meets the requirements of either paragraph (a)(1), 
(a)(2), or (a)(3) of this section; and any supplier that meets the 
requirements of paragraph (a)(4) of this section:
    (1) A facility that contains any source category (as defined in 
subparts C through JJ of this part) that is listed in this paragraph 
(a)(1) in any calendar year starting in 2010. For these facilities, the 
annual GHG report must cover all source categories and GHGs for which 
calculation methodologies are provided in subparts C through JJ of this 
part.
    (i) Electricity generation (units that report CO2 
emissions year-round through 40 CFR part 75).
    (ii) Adipic acid production.
    (iii) Aluminum production.
    (iv) Ammonia manufacturing.
    (v) Cement production.
    (vi) HCFC-22 production.
    (vii) HFC-23 destruction processes that are not collocated with a 
HCFC-22 production facility and that destroy more than 2.14 metric tons 
of HFC-23 per year.
    (viii) Lime manufacturing.
    (ix) Nitric acid production.
    (x) Petrochemical production.
    (xi) Petroleum refineries.
    (xii) Phosphoric acid production.
    (xiii) Silicon carbide production.
    (xiv) Soda ash production.
    (xv) Titanium dioxide production.
    (xvi) Municipal solid waste landfills that generate CH4 
in amounts equivalent to 25,000 metric tons CO2e or more per 
year, as determined according to subpart HH of this part.
    (xvii) Manure management systems with combined CH4 and 
N2O emissions in amounts equivalent to 25,000 metric tons 
CO2e or more per year, as determined according to subpart JJ 
of this part.
    (2) A facility that contains any source category (as defined in 
subparts C through JJ of this part) that is listed in this paragraph 
(a)(2) in any calendar year starting in 2010 and that emits 25,000 
metric tons CO2e or more per year in combined emissions from 
stationary fuel combustion units, miscellaneous uses of carbonate, and 
all source categories that are listed in this paragraph. For these 
facilities, the annual GHG report must cover all source categories and 
GHGs for which calculation methodologies are provided in subparts C 
through JJ of this part.
    (i) Ferroalloy Production.
    (ii) Glass Production.
    (iii) Hydrogen Production.
    (iv) Iron and Steel Production.
    (v) Lead Production.
    (vi) Pulp and Paper Manufacturing.
    (vii) Zinc Production.
    (3) A facility that in any calendar year starting in 2010 meets all 
three of the conditions listed in this paragraph (a)(3). For these 
facilities, the annual GHG report must cover emissions from stationary 
fuel combustion sources only.
    (i) The facility does not meet the requirements of either paragraph 
(a)(1) or (a)(2) of this section.
    (ii) The aggregate maximum rated heat input capacity of the 
stationary fuel combustion units at the facility is 30 mmBtu/hr or 
greater.
    (iii) The facility emits 25,000 metric tons CO2e or more 
per year in combined emissions from all stationary fuel combustion 
sources.
    (4) A supplier (as defined in subparts KK through PP of this part) 
that provides products listed in this paragraph (a)(4) in any calendar 
year starting in 2010. For these suppliers, the annual GHG report must 
cover all applicable products for which calculation methodologies are 
provided in subparts KK through PP of this part.
    (i) Coal-to-liquids suppliers, as specified in this paragraph 
(a)(4)(i).
    (A) All producers of coal-to-liquid products.
    (B) Importers of an annual quantity of coal-to-liquid products that 
is equivalent to 25,000 metric tons CO2e or more.
    (C) Exporters of an annual quantity of coal-to-liquid products is 
equivalent to 25,000 metric tons CO2e or more.
    (ii) Petroleum product suppliers, as specified in this paragraph 
(a)(4)(ii):
    (A) All petroleum refineries that distill crude oil.
    (B) Importers of an annual quantity of petroleum products that is 
equivalent to 25,000 metric tons CO2e or more.
    (C) Exporters of an annual quantity of petroleum products that is 
equivalent to 25,000 metric tons CO2e or more.
    (iii) Natural gas and natural gas liquids suppliers, as specified 
in this paragraph (a)(4)(iii):
    (A) All natural gas fractionators.
    (B) All local natural gas distribution companies.
    (iv) Industrial greenhouse gas suppliers, as specified in this 
paragraph (a)(4)(iv):
    (A) All producers of industrial greenhouse gases.
    (B) Importers of industrial greenhouse gases with annual bulk 
imports of N2O, fluorinated GHG, and CO2 that in 
combination are equivalent to 25,000 metric tons CO2e or 
more.
    (C) Exporters of industrial greenhouse gases with annual bulk 
exports of N2O, fluorinated GHG, and CO2 that in 
combination are equivalent to 25,000 metric tons CO2e or 
more.
    (v) Carbon dioxide suppliers, as specified in this paragraph 
(a)(4)(v).
    (A) All producers of CO2.
    (B) Importers of CO2 with annual bulk imports of 
N2O, fluorinated GHG, and CO2 that in combination 
are equivalent to 25,000 metric tons CO2e or more.
    (C) Exporters of CO2 with annual bulk exports of 
N2O, fluorinated GHG, and CO2 that in combination 
are equivalent to 25,000 metric tons CO2e or more.
    (5) Research and development activities are not considered to be 
part of any source category defined in this part.
    (b) To calculate GHG emissions for comparison to the 25,000 metric 
ton CO2e per year emission threshold in paragraph (a)(2) of 
this section, the owner or operator shall calculate annual

[[Page 56378]]

CO2e emissions, as described in paragraphs (b)(1) through 
(b)(4) of this section.
    (1) Calculate the annual emissions of CO2, 
CH4, N2O,and each fluorinated GHG in metric tons 
from all applicable source categories listed in paragraph (a)(2) of 
this section. The GHG emissions shall be calculated using the 
calculation methodologies specified in each applicable subpart and 
available company records. Include emissions from only those gases 
listed in Table A-1 of this subpart.
    (2) For each general stationary fuel combustion unit, calculate the 
annual CO2 emissions in metric tons using any of the four 
calculation methodologies specified in Sec.  98.33(a). Calculate the 
annual CH4 and N2O emissions from the stationary 
fuel combustion sources in metric tons using the appropriate equation 
in Sec.  98.33(c). Exclude carbon dioxide emissions from the combustion 
of biomass, but include emissions of CH4 and N2O 
from biomass combustion.
    (3) For miscellaneous uses of carbonate, calculate the annual 
CO2 emissions in metric tons using the procedures specified 
in subpart U of this part.
    (4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and 
(b)(3) of this section for each GHG and calculate metric tons of 
CO2e using Equation A-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.000

Where:

CO2e = Carbon dioxide equivalent, metric tons/year.
GHGi = Mass emissions of each greenhouse gas listed in 
Table A-1 of this subpart, metric tons/year.
GWPi = Global warming potential for each greenhouse gas 
from Table A-1 of this subpart.
n = The number of greenhouse gases emitted.

    (5) For purpose of determining if an emission threshold has been 
exceeded, include in the emissions calculation any CO2 that 
is captured for transfer off site.
    (c) To calculate GHG emissions for comparison to the 25,000 metric 
ton CO2e/year emission threshold for stationary fuel 
combustion under paragraph (a)(3) of this section, calculate 
CO2, CH4, and N2O emissions from each 
stationary fuel combustion unit by following the methods specified in 
paragraph (b)(2) of this section. Then, convert the emissions of each 
GHG to metric tons CO2e per year using Equation A-1 of this 
section, and sum the emissions for all units at the facility.
    (d) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2 per year threshold for importers and exporters of 
coal-to-liquid products under paragraph (a)(4)(i) of this section, 
calculate the mass in metric tons per year of CO2 that would 
result from the complete combustion or oxidation of the quantity of 
coal-to-liquid products that are imported during the reporting year and 
that are exported during the reporting year. Calculate the emissions 
using the methodology specified in subpart LL of this part.
    (e) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold for importers and exporters of 
petroleum products under paragraph (a)(4)(ii) of this section, 
calculate the mass in metric tons per year of CO2 that would 
result from the complete combustion or oxidation of the volume of 
petroleum products and natural gas liquids that are imported during the 
reporting year and that are exported during the reporting year. 
Calculate the emissions using the methodology specified in subpart MM 
of this part.
    (f) To calculate GHG quantities for comparison to the 25,000 metric 
ton CO2e per year threshold under paragraph (a)(4) of this 
section for importers and exporters of industrial greenhouse gases and 
for importers and exporters of CO2, the owner or operator 
shall calculate the mass in metric tons per year of CO2e 
imports and exports as described in paragraphs (f)(1) through (f)(3) of 
this section.
    (1) Calculate the mass in metric tons per year of CO2, 
N2O, and each fluorinated GHG that is imported and the mass 
in metric tons per year of CO2, N2O, and each 
fluorinated GHG that is exported during the year. Include only those 
gases listed in Table A-1 of this subpart.
    (2) Convert the mass of each imported and each GHG exported from 
paragraph (f)(1) of this section to metric tons of CO2e 
using Equation A-1 of this section.
    (3) Sum the total annual metric tons of CO2e in 
paragraph (f)(2) of this section for all imported GHGs. Sum the total 
annual metric tons of CO2e in paragraph (f)(2) of this 
section for all exported GHGs.
    (g) If a capacity or generation reporting threshold in paragraph 
(a)(1) of this section applies, the owner or operator shall review the 
appropriate records and perform any necessary calculations to determine 
whether the threshold has been exceeded.
    (h) An owner or operator of a facility or supplier that does not 
meet the applicability requirements of paragraph (a) of this section is 
not subject to this rule. Such owner or operator would become subject 
to the rule and reporting requirements Sec.  98.3(b)(3), if a facility 
or supplier exceeds the applicability requirements of paragraph (a) of 
this section at a later time. Thus, the owner or operator should 
reevaluate the applicability to this part (including the revising of 
any relevant emissions calculations or other calculations) whenever 
there is any change that could cause a facility or supplier to meet the 
applicability requirements of paragraph (a) of this section. Such 
changes include but are not limited to process modifications, increases 
in operating hours, increases in production, changes in fuel or raw 
material use, addition of equipment, and facility expansion.
    (i) 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.
    (1) If reported emissions are less than 25,000 metric tons 
CO2e per year for five consecutive years, then the owner or 
operator may discontinue complying with this part provided that the 
owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and explains the reasons for the 
reduction in emissions. The notification shall be submitted no later 
than March 31 of the year immediately following the fifth consecutive 
year of emissions less than 25,000 tons CO2e per year. The 
owner or operator must maintain the corresponding records required 
under Sec.  98.3(g) for each of the five consecutive years and retain 
such records for three years following the year that reporting was 
discontinued. The owner or operator must resume reporting if annual 
emissions in any future calendar year increase to 25,000 metric tons 
CO2e per year or more.
    (2) If reported emissions are less than 15,000 metric tons 
CO2e per year for three consecutive years, then the owner or 
operator may discontinue complying with this part provided that the 
owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and explains the reasons for the 
reduction in emissions. The notification shall be submitted no later 
than March 31 of the year immediately following the third consecutive 
year of emissions less than 15,000 tons CO2e per year. The 
owner or operator must maintain the corresponding records required 
under Sec.  98.3(g) for each of the three

[[Page 56379]]

consecutive years and retain such records for three years following the 
year that reporting was discontinued. The owner or operator must resume 
reporting if annual emissions in any future calendar year increase to 
25,000 metric tons CO2e per year or more.
    (3) If the operations of a facility or supplier are changed such 
that all applicable GHG-emitting processes and operations listed in 
paragraphs (a)(1) through (a)(4) of this section cease to operate, then 
the owner or operator is exempt from reporting in the years following 
the year in which cessation of such operations occurs, provided that 
the owner or operator submits a notification to the Administrator that 
announces the cessation of reporting and certifies to the closure of 
all GHG-emitting processes and operations. This paragraph (i)(2) does 
not apply to seasonal or other temporary cessation of operations. This 
paragraph (i)(2) does not apply to facilities with municipal solid 
waste landfills. The owner or operator must resume reporting for any 
future calendar year during which any of the GHG-emitting processes or 
operations resume operation.
    (j) Table A-2 of this subpart provides a conversion table for some 
of the common units of measure used in part 98.


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

    The owner or operator of a facility or supplier that is subject to 
the requirements of this part must submit GHG reports to the 
Administrator, as specified in this section.
    (a) General. Except as provided in paragraph (d) of this section, 
follow the procedures for emission calculation, monitoring, quality 
assurance, missing data, recordkeeping, and reporting that are 
specified in each relevant subpart of this part.
    (b) Schedule. The annual GHG report must be submitted no later than 
March 31 of each calendar year for GHG emissions in the previous 
calendar year.
    (1) For an existing facility or supplier that began operation 
before January 1, 2010, report emissions for calendar year 2010 and 
each subsequent calendar year.
    (2) For a new facility or supplier that begins operation on or 
after January 1, 2010, report emissions beginning with the first 
operating month and ending on December 31 of that year. Each subsequent 
annual report must cover emissions for the calendar year, beginning on 
January 1 and ending on December 31.
    (3) For any facility or supplier that becomes subject to this rule 
because of a physical or operational change that is made after January 
1, 2010, report emissions for the first calendar year in which the 
change occurs, beginning with the first month of the change and ending 
on December 31 of that year. For a facility or supplier that becomes 
subject to this rule solely because of an increase in hours of 
operation or level of production, the first month of the change is the 
month in which the increased hours of operation or level of production, 
if maintained for the remainder of the year, would cause the facility 
or supplier to exceed the applicable threshold. Each subsequent annual 
report must cover emissions for the calendar year, beginning on January 
1 and ending on December 31.
    (c) Content of the annual report. Except as provided in paragraph 
(d) of this section, each annual GHG report shall contain the following 
information:
    (1) Facility name or supplier name (as appropriate) and physical 
street address including the city, state, and zip code.
    (2) Year and months covered by the report.
    (3) Date of submittal.
    (4) For facilities, 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 in subparts C through 
JJ of this part and expressed in metric tons of CO2e 
calculated using Equation A-1 of this subpart.
    (ii) Annual emissions of biogenic CO2 aggregated for all 
applicable source categories in subparts C through JJ of this part.
    (iii) Annual emissions from each applicable source category in 
subparts C through JJ of this part, expressed in metric tons of each 
GHG listed in paragraphs (c)(4)(iii)(A) through (c)(4)(iii)(E) of this 
section.
    (A) Biogenic CO2.
    (B) CO2 (excluding biogenic CO2).
    (C) CH4.
    (D) N2O.
    (E) Each fluorinated GHG (including those not listed in Table A-1 
of this subpart).
    (iv) Emissions and other data for individual units. processes, 
activities, and operations as specified in the ``Data reporting 
requirements'' section of each applicable subpart of this part.
    (5) For suppliers, report annual quantities of CO2, 
CH4, N2O, and each fluorinated GHG (as defined in 
Sec.  98.6) that would be emitted from combustion or use of the 
products supplied, imported, and exported during the year. Calculate 
and report quantities at the following levels:
    (i) Total quantity of GHG aggregated for all GHG from all 
applicable supply categories in subparts KK through PP of this part and 
expressed in metric tons of CO2e calculated using Equation 
A-1 of this subpart.
    (ii) Quantity of each GHG from each applicable supply category in 
subparts KK through PP of this part, expressed in metric tons of each 
GHG. For fluorinated GHG, report emissions of all fluorinated GHG, 
including those not listed in Table A-1 of this subpart.
    (iii) Any other data specified in the ``Data reporting 
requirements'' section of each applicable subpart of this part.
    (6) A written explanation, as required under Sec.  98.3(e), if you 
change emission calculation methodologies during the reporting period.
    (7) A brief description of each ``best available monitoring 
method'' used according to paragraph (d) of this section, the parameter 
measured using the method, and the time period during which the ``best 
available monitoring method'' was used.
    (8) Each data element for which a missing data procedure was used 
according to the procedures of an applicable subpart and the total 
number of hours in the year that a missing data procedure was used for 
each data element.
    (9) A signed and dated certification statement provided by the 
designated representative of the owner or operator, according to the 
requirements of Sec.  98.4(e)(1).
    (d) Special provisions for reporting year 2010.
    (1) Best available monitoring methods. During January 1, 2010 
through March 31, 2010, owners or operators may use best available 
monitoring methods for any parameter (e.g., fuel use, daily carbon 
content of feedstock by process line) that cannot reasonably be 
measured according to the monitoring and QA/QC requirements of a 
relevant subpart. The owner or operator must use the calculation 
methodologies and equations in the ``Calculating GHG Emissions'' 
sections of each relevant subpart, but may use the best available 
monitoring method for any parameter for which it is not reasonably 
feasible to acquire, install, and operate a required piece of 
monitoring equipment by January 1, 2010. Starting no later than April 
1, 2010, the owner or operator must discontinue using best available 
methods and begin following all applicable monitoring and QA/QC 
requirements of this part, except as

[[Page 56380]]

provided in paragraphs (d)(2) and (d)(3) of this section. Best 
available monitoring methods means any of the following methods 
specified in this paragraph:
    (i) Monitoring methods currently used by the facility that do not 
meet the specifications of an relevant subpart.
    (ii) Supplier data.
    (iii) Engineering calculations.
    (iv) Other company records.
    (2) Requests for extension of the use of best available monitoring 
methods. The owner or operator may submit a request to the 
Administrator to use one or more best available monitoring methods 
beyond March 31, 2010.
    (i) Timing of request. The extension request must be submitted to 
EPA no later than 30 days after the effective date of the GHG reporting 
rule.
    (ii) Content of request. Requests must contain the following 
information:
    (A) A list of specific item of monitoring instrumentation for which 
the request is being made and the locations where each piece of 
monitoring instrumentation will be installed.
    (B) Identification of the specific rule requirements (by rule 
subpart, section, and paragraph numbers) for which the instrumentation 
is needed.
    (C) A description of the reasons why the needed equipment could not 
be obtained and installed before April 1, 2010.
    (D) If the reason for the extension is that the equipment cannot be 
purchased and delivered by April 1, 2010, include supporting 
documentation such as the date the monitoring equipment was ordered, 
investigation of alternative suppliers and the dates by which 
alternative vendors promised delivery, backorder notices or unexpected 
delays, descriptions of actions taken to expedite delivery, and the 
current expected date of delivery.
    (E) If the reason for the extension is that the equipment cannot be 
installed without a process unit shutdown, include supporting 
documentation demonstrating that it is not practicable to isolate the 
equipment and install the monitoring instrument without a full process 
unit shutdown. Include the date of the most recent process unit 
shutdown, the frequency of shutdowns for this process unit, and the 
date of the next planned shutdown during which the monitoring equipment 
can be installed. If there has been a shutdown or if there is a planned 
process unit shutdown between promulgation of this part and April 1, 
2010, include a justification of why the equipment could not be 
obtained and installed during that shutdown.
    (F) A description of the specific actions the facility will take to 
obtain and install the equipment as soon as reasonably feasible and the 
expected date by which the equipment will be installed and operating.
    (iii) Approval criteria. To obtain approval, the owner or operator 
must demonstrate to the Administrator's satisfaction that it is not 
reasonably feasible to acquire, install, and operate a required piece 
of monitoring equipment by April 1, 2010. The use of best available 
methods will not be approved beyond December 31, 2010.
    (3) Abbreviated emissions report for facilities containing only 
general stationary fuel combustion sources. In lieu of the report 
required by paragraph (c) of this section, the owner or operator of an 
existing facility that is in operation on January 1, 2010 and that 
meets the conditions of Sec.  98.2 (a)(3) may submit an abbreviated GHG 
report for the facility for GHGs emitted in 2010. The abbreviated 
report must be submitted by March 31, 2011. 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 2011. The abbreviated facility report must include the 
following information:
    (i) Facility name and physical street address including the city, 
state and zip code.
    (ii) The year and months covered by the report.
    (iii) Date of submittal.
    (iv) Total facility GHG emissions aggregated for all stationary 
fuel combustion units calculated according to any method specified in 
Sec.  98.33(a) and expressed in metric tons of CO2, 
CH4, N2O, and CO2e.
    (v) Any facility operating data or process information used for the 
GHG emission calculations.
    (vi) A signed and dated certification statement provided by the 
designated representative of the owner or operator, according to the 
requirements of paragraph (e)(1) of this section.
    (e) Emission calculations. In preparing the GHG report, you must 
use the calculation methodologies specified in the relevant subparts, 
except as specified in paragraph (d) of this section. For each source 
category, you must use the same calculation methodology throughout a 
reporting period unless you provide a written explanation of why a 
change in methodology was required.
    (f) Verification. To verify the completeness and accuracy of 
reported GHG emissions, the Administrator may review the certification 
statements described in paragraphs (c)(8) and (d)(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. Nothing in this section prohibits the 
Administrator from using additional information to verify the 
completeness and accuracy of the reports.
    (g) Recordkeeping. An owner or operator that is required to report 
GHGs under this part must keep records as specified in this paragraph. 
Retain all required records for at least 3 years. The records shall be 
kept in an electronic or hard-copy format (as appropriate) and recorded 
in a form that is suitable for expeditious inspection and review. Upon 
request by the Administrator, the records required under this section 
must be made available to EPA. Records may be retained off site if the 
records are readily available for expeditious inspection and review. 
For records that are electronically generated or maintained, the 
equipment or software necessary to read the records shall be made 
available, or, if requested by EPA, electronic records shall be 
converted to paper documents. You must retain the following records, in 
addition to those records prescribed in each applicable subpart of this 
part:
    (1) A list of all units, operations, processes, and activities for 
which GHG emission were calculated.
    (2) The data used to calculate the GHG emissions for each unit, 
operation, process, and activity, categorized by fuel or material type. 
These data include but are not limited to the following information in 
this paragraph (g)(2):
    (i) The GHG emissions calculations and methods used.
    (ii) Analytical results for the development of site-specific 
emissions factors.
    (iii) The results of all required analyses for high heat value, 
carbon content, and other required fuel or feedstock parameters.
    (iv) Any facility operating data or process information used for 
the GHG emission calculations.
    (3) The annual GHG reports.
    (4) Missing data computations. For each missing data event, also 
retain a record of the duration of the event, actions taken to restore 
malfunctioning monitoring equipment, the cause of the event, and the 
actions taken to prevent or minimize occurrence in the future.
    (5) A written GHG Monitoring Plan.
    (i) At a minimum, the GHG Monitoring Plan shall include the 
elements listed in this paragraph (g)(5)(i).

[[Page 56381]]

    (A) Identification of positions of responsibility (i.e., job 
titles) for collection of the emissions data.
    (B) Explanation of the processes and methods used to collect the 
necessary data for the GHG calculations.
    (C) Description of the procedures and methods that are used for 
quality assurance, maintenance, and repair of all continuous monitoring 
systems, flow meters, and other instrumentation used to provide data 
for the GHGs reported under this part.
    (ii) The GHG Monitoring Plan may rely on references to existing 
corporate documents (e.g., standard operating procedures, quality 
assurance programs under appendix F to 40 CFR part 60 or appendix B to 
40 CFR part 75, and other documents) provided that the elements 
required by paragraph (g)(5)(i) of this section are easily 
recognizable.
    (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.
    (iv) Upon request by the Administrator, the owner or operator shall 
make all information that is collected in conformance with the GHG 
Monitoring Plan available for review during an audit. Electronic 
storage of the information in the plan is permissible, provided that 
the information can be made available in hard copy upon request during 
an audit.
    (6) The results of all required certification and quality assurance 
tests of continuous monitoring systems, fuel flow meters, and other 
instrumentation used to provide data for the GHGs reported under this 
part.
    (7) Maintenance records for all continuous monitoring systems, flow 
meters, and other instrumentation used to provide data for the GHGs 
reported under this part.
    (h) Annual GHG report revisions. The owner or operator shall submit 
a revised report within 45 days of discovering or being notified by EPA 
of errors in an annual GHG report. The revised report must correct all 
identified errors. The owner or operator shall retain documentation for 
3 years to support any revisions made to an annual GHG report.
    (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 calibration accuracy requirements of this paragraph (i).
    (1) Except as provided paragraphs (i)(4) through (i)(6) of this 
section, flow meters and other devices (e.g., belt scales) that measure 
data used to calculate GHG emissions shall be calibrated prior to April 
1, 2010 using the procedures specified in this paragraph and each 
relevant subpart of this part. All measurement devices must be 
calibrated according to the manufacturer's recommended procedures, an 
appropriate industry consensus standard, or a method specified in a 
relevant subpart of this part. All measurement devices shall be 
calibrated to an accuracy of 5 percent. For facilities and suppliers 
that become subject to this part after April 1, 2010, the initial 
calibration shall be conducted on the date that data collection is 
required to begin. Subsequent calibrations shall be performed at the 
frequency specified in each applicable subpart.
    (2) For flow meters, perform all calibrations at measurement points 
that are representative of normal operation 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] TR30OC09.001

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. 
Calibrate each transmitter at a zero point and at least one upscale 
point. Fixed reference points, such as the freezing point of water, may 
be used for temperature transmitter calibrations. Calculate the 
calibration error of each transmitter at each measurement point, using 
Equation A-3 of this subpart. The terms ``R'', ``A'', and ``FS'' in 
Equation A-3 of this subpart must be in consistent units of measure 
(e.g., milliamperes, inches of water, psi, degrees). For each 
transmitter, the CE value at each measurement point shall not exceed 
2.0 percent of full-scale. Alternatively, the results are acceptable if 
the sum of the calculated CE values for the three transmitters at each 
calibration level (i.e., at the zero level and at each upscale level) 
does not exceed 5.0 percent.
[GRAPHIC] [TIFF OMITTED] TR30OC09.002

Where:

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

    (4) Fuel billing meters are exempted from the calibration 
requirements 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.
    (5) For a flow meter or other measurement device that has been 
previously calibrated in accordance with this part, an initial 
calibration is not required by the date specified in paragraph (i)(1) 
of this section if, as of the date required for the initial 
calibration, the previous calibration is still active (i.e., the device 
is not yet due for recalibration because the time interval between 
successive calibrations, as required by this part, has not elapsed).
    (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 removing the device from service and 
shipping it to a remote location, thereby disrupting normal process 
operation. In such cases, the owner or operator may postpone the 
initial calibration until the next scheduled maintenance outage, and 
may similarly postpone the subsequent recalibrations. Such 
postponements shall be documented in the monitoring plan that is 
required under Sec.  98.3(g)(5).


Sec.  98.4  Authorization and responsibilities of the designated 
representative.

    (a) General. Except as provided under paragraph (f) of this 
section, each facility, and each supplier, that is subject to this 
part, shall have one and only one designated representative, who shall 
be responsible for certifying, signing, and submitting GHG emissions 
reports and any other submissions for such facility and supplier 
respectively to the Administrator under this part. If the facility is 
required under any other part of title 40 of the Code of Federal 
Regulations to submit to the Administrator any other emission report 
that is subject to any requirement in 40

[[Page 56382]]

CFR part 75, the same individual shall be the designated representative 
responsible for certifying, signing, and submitting the GHG emissions 
reports and all such other emissions reports under this part.
    (b) Authorization of a designated representative. The designated 
representative of the facility or supplier shall be an individual 
selected by an agreement binding on the owners and operators of such 
facility or supplier and shall act in accordance with the certification 
statement in paragraph (i)(4)(iv) of this section.
    (c) Responsibility of the designated representative. Upon receipt 
by the Administrator of a complete certificate of representation under 
this section for a facility or supplier, the designated representative 
identified in such certificate of representation shall represent and, 
by his or her representations, actions, inactions, or submissions, 
legally bind each owner and operator of such facility or supplier in 
all matters pertaining to this part, notwithstanding any agreement 
between the designated representative and such owners and operators. 
The owners and operators shall be bound by any decision or order issued 
to the designated representative by the Administrator or a court.
    (d) Timing. No GHG emissions report or other submissions under this 
part for a facility or supplier will be accepted until the 
Administrator has received a complete certificate of representation 
under this section for a designated representative of the facility or 
supplier. Such certificate of representation shall be submitted at 
least 60 days before the deadline for submission of the facility's or 
supplier's initial emission report under this part.
    (e) Certification of the GHG emissions report. Each GHG emission 
report and any other submission under this part for a facility or 
supplier shall be certified, signed, and submitted by the designated 
representative or any alternate designated representative of the 
facility or supplier in accordance with this section and Sec.  3.10 of 
this chapter.
    (1) Each such submission shall include the following certification 
statement signed by the designated representative or any alternate 
designated representative: ``I am authorized to make this submission on 
behalf of the owners and operators of the facility or supplier, as 
applicable, for which the submission is made. I certify under penalty 
of law that I have personally examined, and am familiar with, the 
statements and information submitted in this document and all its 
attachments. Based on my inquiry of those individuals with primary 
responsibility for obtaining the information, I certify that the 
statements and information are to the best of my knowledge and belief 
true, accurate, and complete. I am aware that there are significant 
penalties for submitting false statements and information or omitting 
required statements and information, including the possibility of fine 
or imprisonment.''
    (2) The Administrator will accept a GHG emission report or other 
submission for a facility or supplier under this part only if the 
submission is certified, signed, and submitted in accordance with this 
section.
    (f) Alternate designated representative. A certificate of 
representation under this section for a facility or supplier may 
designate one alternate designated representative, who shall be an 
individual selected by an agreement binding on the owners and 
operators, and may act on behalf of the designated representative, of 
such facility or supplier. The agreement by which the alternate 
designated representative is selected shall include a procedure for 
authorizing the alternate designated representative to act in lieu of 
the designated representative.
    (1) Upon receipt by the Administrator of a complete certificate of 
representation under this section for a facility or supplier 
identifying an alternate designated representative.
    (i) The alternate designated representative may act on behalf of 
the designated representative for such facility or supplier.
    (ii) Any representation, action, inaction, or submission by the 
alternate designated representative shall be deemed to be a 
representation, action, inaction, or submission by the designated 
representative.
    (2) Except in this section, whenever the term ``designated 
representative'' is used in this part, the term shall be construed to 
include the designated representative or any alternate designated 
representative.
    (g) Changing a designated representative or alternate designated 
representative. The designated representative or alternate designated 
representative identified in a complete certificate of representation 
under this section for a facility or supplier received by the 
Administrator may be changed at any time upon receipt by the 
Administrator of another later signed, complete certificate of 
representation under this section for the facility or supplier. 
Notwithstanding any such change, all representations, actions, 
inactions, and submissions by the previous designated representative or 
the previous alternate designated representative of the facility or 
supplier before the time and date when the Administrator receives such 
later signed certificate of representation shall be binding on the new 
designated representative and the owners and operators of the facility 
or supplier.
    (h) Changes in owners and operators. In the event an owner or 
operator of the facility or supplier is not included in the list of 
owners and operators in the certificate of representation under this 
section for the facility or supplier, such owner or operator shall be 
deemed to be subject to and bound by the certificate of representation, 
the representations, actions, inactions, and submissions of the 
designated representative and any alternate designated representative 
of the facility or supplier, as if the owner or operator were included 
in such list. Within 90 days after any change in the owners and 
operators of the facility or supplier (including the addition of a new 
owner or operator), the designated representative or any alternate 
designated representative shall submit a certificate of representation 
that is complete under this section except that such list shall be 
amended to reflect the change. If the designated representative or 
alternate designated representative determines at any time that an 
owner or operator of the facility or supplier is not included in such 
list and such exclusion is not the result of a change in the owners and 
operators, the designated representative or any alternate designated 
representative shall submit, within 90 days of making such 
determination, a certificate of representation that is complete under 
this section except that such list shall be amended to include such 
owner or operator.
    (i) Certificate of representation. A certificate of representation 
shall be complete if it includes the following elements in a format 
prescribed by the Administrator in accordance with this section:
    (1) Identification of the facility or supplier for which the 
certificate of representation is submitted.
    (2) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of the designated 
representative and any alternate designated representative.
    (3) A list of the owners and operators of the facility or supplier 
identified in paragraph (i)(1) of this section, provided that, if the 
list includes the operators of the facility or supplier and the owners 
with control of the facility or supplier, the failure to include any 
other owners shall not make the certificate of representation 
incomplete.

[[Page 56383]]

    (4) The following certification statements by the designated 
representative and any alternate designated representative:
    (i) ``I certify that I was selected as the designated 
representative or alternate designated representative, as applicable, 
by an agreement binding on the owners and operators of the facility or 
supplier, as applicable.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under 40 CFR part 98 on behalf of 
the owners and operators of the facility or supplier, as applicable, 
and that each such owner and operator shall be fully bound by my 
representations, actions, inactions, or submissions.''
    (iii) ``I certify that the owners and operators of the facility or 
supplier, as applicable, shall be bound by any order issued to me by 
the Administrator or a court regarding the facility or supplier.''
    (iv) ``If there are multiple owners and operators of the facility 
or supplier, as applicable, I certify that I have given a written 
notice of my selection as the `designated representative' or `alternate 
designated representative', as applicable, and of the agreement by 
which I was selected to each owner and operator of the facility or 
supplier.''
    (5) The signature of the designated representative and any 
alternate designated representative and the dates signed.
    (j) Documents of agreement. Unless otherwise required by the 
Administrator, documents of agreement referred to in the certificate of 
representation shall not be submitted to the Administrator. The 
Administrator shall not be under any obligation to review or evaluate 
the sufficiency of such documents, if submitted.
    (k) Binding nature of the certificate of representation. Once a 
complete certificate of representation under this section for a 
facility or supplier has been received, the Administrator will rely on 
the certificate of representation unless and until a later signed, 
complete certificate of representation under this section for the 
facility or supplier is received by the Administrator.

(l) Objections Concerning a Designated Representative

    (1) Except as provided in paragraph (g) of this section, no 
objection or other communication submitted to the Administrator 
concerning the authorization, or any representation, action, inaction, 
or submission, of the designated representative or alternate designated 
representative shall affect any representation, action, inaction, or 
submission of the designated representative or alternate designated 
representative, or the finality of any decision or order by the 
Administrator under this part.
    (2) The Administrator will not adjudicate any private legal dispute 
concerning the authorization or any representation, action, inaction, 
or submission of any designated representative or alternate designated 
representative.
    (m) Delegation by designated representative and alternate 
designated representative.
    (1) A designated representative or an alternate designated 
representative may delegate his or her own authority, to one or more 
individuals, to submit an electronic submission to the Administrator 
provided for or required under this part, except for a submission under 
this paragraph.
    (2) In order to delegate his or her own authority, to one or more 
individuals, to submit an electronic submission to the Administrator in 
accordance with paragraph (m)(1) of this section, the designated 
representative or alternate designated representative must submit 
electronically to the Administrator a notice of delegation, in a format 
prescribed by the Administrator, that includes the following elements:
    (i) The name, address, e-mail address (if any), telephone number, 
and facsimile transmission number (if any) of such designated 
representative or alternate designated representative.
    (ii) The name, address, e-mail address, telephone number, and 
facsimile transmission number (if any) of each such individual 
(referred to as an ``agent'').
    (iii) For each such individual, a list of the type or types of 
electronic submissions under paragraph (m)(1) of this section for which 
authority is delegated to him or her.
    (iv) For each type of electronic submission listed in accordance 
with paragraph (m)(2)(iii) of this section, the facility or supplier 
for which the electronic submission may be made.
    (v) The following certification statements by such designated 
representative or alternate designated representative:
    (A) ``I agree that any electronic submission to the Administrator 
that is by an agent identified in this notice of delegation and of a 
type listed, and for a facility or supplier designated, for such agent 
in this notice of delegation and that is made when I am a designated 
representative or alternate designated representative, as applicable, 
and before this notice of delegation is superseded by another notice of 
delegation under Sec.  98.4(m)(3) shall be deemed to be an electronic 
submission certified, signed, and submitted by me.''
    (B) ``Until this notice of delegation is superseded by a later 
signed notice of delegation under Sec.  98.4(m)(3), I agree to maintain 
an e-mail account and to notify the Administrator immediately of any 
change in my e-mail address unless all delegation of authority by me 
under Sec.  98.4(m) is terminated.''
    (vi) The signature of such designated representative or alternate 
designated representative and the date signed.
    (3) A notice of delegation submitted in accordance with paragraph 
(m)(2) of this section shall be effective, with regard to the 
designated representative or alternate designated representative 
identified in such notice, upon receipt of such notice by the 
Administrator and until receipt by the Administrator of another such 
notice that was signed later by such designated representative or 
alternate designated representative, as applicable. The later signed 
notice of delegation may replace any previously identified agent, add a 
new agent, or eliminate entirely any delegation of authority.
    (4) Any electronic submission covered by the certification in 
paragraph (m)(2)(iv)(A) of this section and made in accordance with a 
notice of delegation effective under paragraph (m)(3) of this section 
shall be deemed to be an electronic submission certified, signed, and 
submitted by the designated representative or alternate designated 
representative submitting such notice of delegation.


Sec.  98.5  How is the report submitted?

    Each GHG report and certificate of representation for a facility or 
supplier must be submitted electronically in accordance with the 
requirements of Sec.  98.4 and in a format specified by the 
Administrator.


Sec.  98.6  Definitions.

    All terms used in this part shall have the same meaning given in 
the Clean Air Act and in this section.
    Accuracy of a measurement at a specified level (e.g., one percent 
of full scale or one percent of the value measured) means that the mean 
of repeat measurements made by a device or technique are within 95 
percent of the range bounded by the true value plus or minus the 
specified level.
    Acid Rain Program means the program established under title IV of 
the Clean Air Act, and implemented under parts 72 through 78 of this 
chapter for the reduction of sulfur dioxide and nitrogen oxides 
emissions.
    Administrator means the Administrator of the United States

[[Page 56384]]

Environmental Protection Agency or the Administrator's authorized 
representative.
    AGA means the American Gas Association
    Alkali bypass means a duct between the feed end of the kiln and the 
preheater tower through which a portion of the kiln exit gas stream is 
withdrawn and quickly cooled by air or water to avoid excessive buildup 
of alkali, chloride and/or sulfur on the raw feed. This may also be 
referred to as the ``kiln exhaust gas bypass.''
    Anaerobic digester means the system where wastes are collected and 
anaerobically digested in large containment vessels or covered lagoons. 
Anaerobic digesters stabilize waste by the microbial reduction of 
complex organic compounds to CO2 and CH4, which is captured and may be 
flared or used as fuel. Anaerobic digestion systems, include but are 
not limited to covered lagoon, complete mix, plug flow, and fixed film 
digesters.
    Anaerobic lagoon means a type of liquid storage system component, 
either at manure management system or a wastewater treatment system, 
that is designed and operated to stabilize wastes using anaerobic 
microbial processes. Anaerobic lagoons may be designed for combined 
stabilization and storage with varying lengths of retention time (up to 
a year or greater), depending on the climate region, the volatile 
solids loading rate, and other operational factors.
    Anode effect is a process upset condition of an aluminum 
electrolysis cell caused by too little alumina dissolved in the 
electrolyte. The anode effect begins when the voltage rises rapidly and 
exceeds a threshold voltage, typically 8 volts.
    Anode Effect Minutes per Cell Day (24 hours) are the total minutes 
during which an electrolysis cell voltage is above the threshold 
voltage, typically 8 volts.
    ANSI means the American National Standards Institute.
    API means the American Petroleum Institute.
    Argon-oxygen decarburization (AOD) vessel means any closed-bottom, 
refractory-lined converter vessel with submerged tuyeres through which 
gaseous mixtures containing argon and oxygen or nitrogen may be blown 
into molten steel for further refining to reduce the carbon content of 
the steel.
    ASABE means the American Society of Agricultural and Biological 
Engineers.
    ASME means the American Society of Mechanical Engineers.
    ASTM means the American Society of Testing and Materials.
    Asphalt means a dark brown-to-black cement-like material obtained 
by petroleum processing and containing bitumens as the predominant 
component. It includes crude asphalt as well as the following finished 
products: cements, fluxes, the asphalt content of emulsions (exclusive 
of water), and petroleum distillates blended with asphalt to make 
cutback asphalts.
    Aviation Gasoline means a complex mixture of volatile hydrocarbons, 
with or without additives, suitably blended to be used in aviation 
reciprocating engines. Specifications can be found in ASTM 
Specification D910-07a, Standard Specification for Aviation Gasolines 
(incorporated by reference, see Sec.  98.7).
    B0 means the maximum CH4 producing capacity 
of a waste stream, kg CH4/kg COD.
    Basic oxygen furnace means any refractory-lined vessel in which 
high-purity oxygen is blown under pressure through a bath of molten 
iron, scrap metal, and fluxes to produce steel.
    bbl means barrel.
    Biodiesel means a mono-akyl ester derived from biomass and 
conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel 
Blend Stock (B100) for Middle Distillate Fuels.
    Biogenic CO2 means carbon dioxide emissions generated as 
the result of biomass combustion from combustion units for which 
emission calculations are required by an applicable part 98 subpart.
    Biomass means non-fossilized and biodegradable organic material 
originating from plants, animals or micro-organisms, including 
products, by-products, residues and waste from agriculture, forestry 
and related industries as well as the non-fossilized and biodegradable 
organic fractions of industrial and municipal wastes, including gases 
and liquids recovered from the decomposition of non-fossilized and 
biodegradable organic material.
    Blast furnace means a furnace that is located at an integrated iron 
and steel plant and is used for the production of molten iron from iron 
ore pellets and other iron bearing materials.
    Blendstocks are petroleum products used for blending or compounding 
into finished motor gasoline. These include RBOB (reformulated 
blendstock for oxygenate blending) and CBOB (conventional blendstock 
for oxygenate blending), but exclude oxygenates, butane, and pentanes 
plus.
    Blendstocks--Others are products used for blending or compounding 
into finished motor gasoline that are not defined elsewhere. Excludes 
Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock 
(DTAB), conventional blendstock for oxygenate blending (CBOB), 
reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. 
fuel ethanol and methyl tertiary butyl ether), butane, and pentanes 
plus.
    Blowdown mean the act of emptying or depressuring a vessel. This 
may also refer to the discarded material such as blowdown water from a 
boiler or cooling tower.
    British Thermal Unit or Btu means the quantity of heat required to 
raise the temperature of one pound of water by one degree Fahrenheit at 
about 39.2 degrees Fahrenheit.
    Bulk, with respect to industrial GHG suppliers and CO2 suppliers, 
means the transfer of a product inside containers, including but not 
limited to tanks, cylinders, drums, and pressure vessels.
    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 at 
lease separators and field facilities. 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.
    Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon 
with molecular formula C4H10.
    Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon 
with molecular formula C4H8.
    By-product coke oven battery means a group of ovens connected by 
common walls, where coal undergoes destructive distillation under 
positive pressure to produce coke and coke oven gas from which by-
products are recovered.
    Calcination means the process of thermally treating minerals to 
decompose carbonates from ore.
    Calculation methodology means a methodology prescribed under the 
section ``Calculating GHG Emissions'' in any subpart of part 98.
    Carbon dioxide equivalent or CO2e means the number of 
metric tons of CO2 emissions with the same global warming 
potential as one metric ton of another greenhouse gas, and is 
calculated using Equation A-1 of this subpart.
    Carbon dioxide production well means any hole drilled in the earth 
for the primary purpose of extracting carbon dioxide from a geologic 
formation or group of formations which contain deposits of carbon 
dioxide.

[[Page 56385]]

    Carbon dioxide production well facility means one or more carbon 
dioxide production wells that are located on one or more contiguous or 
adjacent properties, which are under the control of the same entity. 
Carbon dioxide production wells located on different oil and gas 
leases, mineral fee tracts, lease tracts, subsurface or surface unit 
areas, surface fee tracts, surface lease tracts, or separate surface 
sites, whether or not connected by a road, waterway, power line, or 
pipeline, shall be considered part of the same CO2 
production well facility if they otherwise meet the definition.
    Carbon dioxide stream means carbon dioxide that has been captured 
from an emission source (e.g. a power plant or other industrial 
facility) or extracted from a carbon dioxide production well plus 
incidental associated substances either derived from the source 
materials and the capture process or extracted with the carbon dioxide.
    Carbon share means the percent of total mass that carbon represents 
in any product.
    Carbonate means compounds containing the radical 
CO3-2. Upon calcination, the carbonate radical 
decomposes to evolve carbon dioxide (CO2). Common carbonates 
consumed in the mineral industry include calcium carbonate 
(CaCO3) or calcite; magnesium carbonate (MgCO3) 
or magnesite; and calcium-magnesium carbonate 
(CaMg(CO3)2) or dolomite.
    Carbonate-based mineral means any of the following minerals used in 
the manufacture of glass: Calcium carbonate (CaCO3), calcium 
magnesium carbonate (CaMg(CO3)2), and sodium 
carbonate (Na2CO3).
    Carbonate-based mineral mass fraction means the following: For 
limestone, the mass fraction of CaCO3 in the limestone; for 
dolomite, the mass fraction of CaMg(CO3)2 in the 
dolomite; and for soda ash, the mass fraction of 
Na2CO3 in the soda ash.
    Carbonate-based raw material means any of the following materials 
used in the manufacture of glass: Limestone, dolomite, and soda ash.
    Catalytic cracking unit means a refinery process unit in which 
petroleum derivatives are continuously charged and hydrocarbon 
molecules in the presence of a catalyst are fractured into smaller 
molecules, or react with a contact material suspended in a fluidized 
bed to improve feedstock quality for additional processing and the 
catalyst or contact material is continuously regenerated by burning off 
coke and other deposits. Catalytic cracking units include both 
fluidized bed systems, which are referred to as fluid catalytic 
cracking units (FCCU), and moving bed systems, which are also referred 
to as thermal catalytic cracking units. The unit includes the riser, 
reactor, regenerator, air blowers, spent catalyst or contact material 
stripper, catalyst or contact material recovery equipment, and 
regenerator equipment for controlling air pollutant emissions and for 
heat recovery.
    Deep bedding systems for cattle swine means a manure management 
system in which, as manure accumulates, bedding is continually added to 
absorb moisture over a production cycle and possibly for as long as 6 
to 12 months. This manure management system also is known as a bedded 
pack manure management system and may be combined with a dry lot or 
pasture.
    CBOB-Summer (conventional blendstock for oxygenate blending) means 
a petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Conventional-Summer.
    CBOB-Winter (conventional blendstock for oxygenate blending) means 
a petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Conventional-Winter.
    Certified standards means calibration gases certified by the 
manufacturer of the calibration gases to be accurate to within 2 
percent of the value on the label or calibration gases.
    CH4 means methane.
    Chemical recovery combustion unit means a combustion device, such 
as a recovery furnace or fluidized-bed reactor where spent pulping 
liquor from sulfite or semi-chemical pulping processes is burned to 
recover pulping chemicals.
    Chemical recovery furnace means an enclosed combustion device where 
concentrated spent liquor produced by the kraft or soda pulping process 
is burned to recover pulping chemicals and produce steam. Includes any 
recovery furnace that burns spent pulping liquor produced from both the 
kraft and soda pulping processes.
    Chloride process means a production process where titanium dioxide 
is produced using calcined petroleum coke and chlorine as raw 
materials.
    City gate means a location at which natural gas ownership or 
control passes from one party to another, neither of which is the 
ultimate consumer. In this rule, in keeping with common practice, the 
term refers to a point or measuring station at which a local gas 
distribution utility receives gas from a natural gas pipeline company 
or transmission system. Meters at the city gate station measure the 
flow of natural gas into the local distribution company system and 
typically are used to measure local distribution company system sendout 
to customers.
    CO2 means carbon dioxide.
    Coal means all solid fuels classified as anthracite, bituminous, 
sub-bituminous, or lignite by the American Society for Testing and 
Materials Designation ASTM D388-05 Standard Classification of Coals by 
Rank (incorporated by reference, see Sec.  98.7).
    COD means the chemical oxygen demand as determined using methods 
specified pursuant to 40 CFR part 136.
    Coke burn-off means the coke removed from the surface of a catalyst 
by combustion during catalyst regeneration. Coke burn-off also means 
the coke combusted in fluid coking unit burner.
    Cokemaking means the production of coke from coal in either a by-
product coke oven battery or a non-recovery coke oven battery.
    Commercial applications means executing a commercial transaction 
subject to a contract. A commercial application includes transferring 
custody of a product from one facility to another if it otherwise meets 
the definition.
    Company records means, in reference to the amount of fuel consumed 
by a stationary combustion unit (or by a group of such units), a 
complete record of the methods used, the measurements made, and the 
calculations performed to quantify fuel usage. Company records may 
include, but are not limited to, direct measurements of fuel 
consumption by gravimetric or volumetric means, tank drop measurements, 
and calculated values of fuel usage obtained by measuring auxiliary 
parameters such as steam generation or unit operating hours. Fuel 
billing records obtained from the fuel supplier qualify as company 
records.
    Connector means to flanged, screwed, or other joined fittings used 
to connect pipe line segments, tubing, pipe components (such as elbows, 
reducers, ``T's'' or valves) or a pipe line and a piece of equipment or 
an instrument to a pipe, tube or piece of equipment. A common connector 
is a flange. Joined fittings welded completely around the circumference 
of the interface are not considered connectors for the purpose of this 
part.
    Container glass means glass made of soda-lime recipe, clear or 
colored, which is pressed and/or blown into bottles, jars, ampoules, 
and other products listed in North American Industry Classification 
System 327213 (NAICS 327213).

[[Page 56386]]

    Continuous emission monitoring system or CEMS means the total 
equipment required to sample, analyze, measure, and provide, by means 
of readings recorded at least once every 15 minutes, a permanent record 
of gas concentrations, pollutant emission rates, or gas volumetric flow 
rates from stationary sources.
    Continuous glass melting furnace means a glass melting furnace that 
operates continuously except during periods of maintenance, 
malfunction, control device installation, reconstruction, or 
rebuilding.
    Conventional-Summer refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which do not meet 
the requirements of the reformulated gasoline regulations promulgated 
by the U.S. Environmental Protection Agency under 40 CFR 80.40, but 
which meet summer RVP standards required under 40 CFR 80.27 or as 
specified by the state. Note: This category excludes conventional 
gasoline for oxygenate blending (CBOB) as well as other blendstock.
    Conventional-Winter refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which do not meet 
the requirements of the reformulated gasoline regulations promulgated 
by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the 
summer RVP standards required under 40 CFR 80.27 or as specified by the 
state. Note: This category excludes conventional blendstock for 
oxygenate blending (CBOB) as well as other blendstock.
    Crude oil means a mixture of hydrocarbons that exists in the liquid 
phase in the underground reservoir and remains liquid at atmospheric 
pressure after passing through surface separating facilities.
    Daily spread means a manure management system component in which 
manure is routinely removed from a confinement facility and is applied 
to cropland or pasture within 24 hours of excretion.
    Day means any consistently designated 24 hour period during which 
an emission unit is operated.
    Degradable organic carbon (DOC) means the fraction of the total 
mass of a waste material that can be biologically degraded.
    Delayed coking unit means one or more refinery process units in 
which high molecular weight petroleum derivatives are thermally cracked 
and petroleum coke is produced in a series of closed, batch system 
reactors. A delayed coking unit consists of the coke drums and 
ancillary equipment associated with a single fractionator.
    Density means the mass contained in a given unit volume (mass/
volume).
    Destruction means:
    (1) With respect to landfills and manure management, the combustion 
of methane in any on-site or off-site combustion technology. Destroyed 
methane includes, but is not limited to, methane combusted by flaring, 
methane destroyed by thermal oxidation, methane combusted for use in 
on-site energy or heat production technologies, methane that is 
conveyed through pipelines (including natural gas pipelines) for off-
site combustion, and methane that is collected for any other on-site or 
off-site use as a fuel.
    (2) With respect to fluorinated GHGs, the expiration of a 
fluorinated GHG to the destruction efficiency actually achieved. Such 
destruction does not result in a commercially useful end product.
    Destruction Efficiency means the efficiency with which a 
destruction device reduces the GWP-weighted mass of greenhouse gases 
fed into the device, considering the GWP-weighted masses of both the 
greenhouse gases fed into the device and those exhausted from the 
device. Destruction efficiency, or flaring destruction efficiency, 
refers to the fraction of the gas that leaves the flare partially or 
fully oxidized. The Destruction Efficiency is expressed in Equation A-2 
of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.003

Where:

DE = Destruction Efficiency
tCO2eIN = The GWP-weighted mass of GHGs fed 
into the destruction device
tCO2eOUT = The GWP-weighted mass of GHGs 
exhausted from the destruction device, including GHGs formed during 
the destruction process

    Diesel--Other is any distillate fuel oil not defined elsewhere, 
including Diesel Treated as Blendstock (DTAB).
    DIPE (diisopropyl ether, 
(CH3)2CHOCH(CH3)2) is an 
ether as described in ``Oxygenates.''
    Direct liquefaction means the conversion of coal directly into 
liquids, rather than passing through an intermediate gaseous state.
    Direct reduction furnace means a high temperature furnace typically 
fired with natural gas to produce solid iron from iron ore or iron ore 
pellets and coke, coal, or other carbonaceous materials.
    Distillate Fuel Oil means a classification for one of the petroleum 
fractions produced in conventional distillation operations and from 
crackers and hydrotreating process units. The generic term distillate 
fuel oil includes kerosene, diesel fuels (Diesel Fuels No. 1, No. 2, 
and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4).
    Distillate Fuel No. 1 has a maximum distillation temperature of 550 
[deg]F at the 90 percent recovery point and a minimum flash point of 
100 [deg]F and includes fuels commonly known as Diesel Fuel No. 1 and 
Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided 
into categories of sulfur content: High Sulfur (greater than 500 ppm), 
Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and 
Ultra Low Sulfur (less than or equal to 15 ppm).
    Distillate Fuel No. 2 has a minimum and maximum distillation 
temperature of 540 [deg]F and 640 [deg]F at the 90 percent recovery 
point, respectively, and includes fuels commonly known as Diesel Fuel 
No. 2 and Fuel Oil No. 2. This fuel is further subdivided into 
categories of sulfur content: High Sulfur (greater than 500 ppm), Low 
Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and 
Ultra Low Sulfur (less than or equal to 15 ppm).
    Distillate Fuel No. 4 is a distillate fuel oil made by blending 
distillate fuel oil and residual fuel oil, with a minimum flash point 
of 131 [deg]F.
    DOCf means the fraction of DOC that actually decomposes 
under the (presumably anaerobic) conditions within the landfill.
    Dry lot means a manure management system component consisting of a 
paved or unpaved open confinement area without any significant 
vegetative cover where accumulating manure may be removed periodically.
    Electric arc furnace (EAF) means a furnace that produces molten 
alloy metal and heats the charge materials with electric arcs from 
carbon electrodes.
    Electric arc furnace steelmaking means the production of carbon, 
alloy, or specialty steels using an EAF. This definition excludes EAFs 
at steel foundries and EAFs used to produce nonferrous metals.
    Electrothermic furnace means a furnace that heats the charged 
materials with electric arcs from carbon electrodes.
    Emergency generator means a stationary combustion device, such as a 
reciprocating internal combustion engine or turbine that serves solely 
as a secondary source of mechanical or electrical power whenever the 
primary energy supply is disrupted or discontinued during power outages 
or natural disasters that are beyond the control of the owner or 
operator of a

[[Page 56387]]

facility. An emergency generator operates only during emergency 
situations, for training of personnel under simulated emergency 
conditions, as part of emergency demand response procedures, or for 
standard performance testing procedures as required by law or by the 
generator manufacturer. A generator that serves as a back-up power 
source under conditions of load shedding, peak shaving, power 
interruptions pursuant to an interruptible power service agreement, or 
scheduled facility maintenance shall not be considered an emergency 
generator.
    Emergency equipment means any auxiliary fossil fuel-powered 
equipment, such as a fire pump, that is used only in emergency 
situations.
    ETBE (ethyl tertiary butyl ether, 
(CH3)3COC2H) is an ether as described 
in ``Oxygenates.''
    Ethane is a paraffinic hydrocarbon with molecular formula 
C2H6.
    Ethanol is an anhydrous alcohol with molecular formula 
C2H5OH.
    Ethylene is an olefinic hydrocarbon with molecular formula 
C2H4.
    Ex refinery gate means the point at which a petroleum product 
leaves the refinery.
    Experimental furnace means a glass melting furnace with the sole 
purpose of operating to evaluate glass melting processes, technologies, 
or glass products. An experimental furnace does not produce glass that 
is sold (except for further research and development purposes) or that 
is used as a raw material for non-experimental furnaces.
    Export means to transport a product from inside the United States 
to persons outside the United States, excluding any such transport on 
behalf of the United States military including foreign military sales 
under the Arms Export Control Act.
    Exporter means any person, company or organization of record that 
transfers for sale or for other benefit, domestic products from the 
United States to another country or to an affiliate in another country, 
excluding any such transfers on behalf of the United States military or 
military purposes including foreign military sales under the Arms 
Export Control Act. An exporter is not the entity merely transporting 
the domestic products, rather an exporter is the entity deriving the 
principal benefit from the transaction.
    Facility means any physical property, plant, building, structure, 
source, or stationary equipment located on one or more contiguous or 
adjacent properties in actual physical contact or separated solely by a 
public roadway or other public right-of-way and under common ownership 
or common control, that emits or may emit any greenhouse gas. Operators 
of military installations may classify such installations as more than 
a single facility based on distinct and independent functional 
groupings within contiguous military properties.
    Feed means the prepared and mixed materials, which include but are 
not limited to materials such as limestone, clay, shale, sand, iron 
ore, mill scale, cement kiln dust and flyash, that are fed to the kiln. 
Feed does not include the fuels used in the kiln to produce heat to 
form the clinker product.
    Feedstock means raw material inputs to a process that are 
transformed by reaction, oxidation, or other chemical or physical 
methods into products and by-products. Supplemental fuel burned to 
provide heat or thermal energy is not a feedstock.
    Fischer-Tropsch process means a catalyzed chemical reaction in 
which synthesis gas, a mixture of carbon monoxide and hydrogen, is 
converted into liquid hydrocarbons of various forms.
    Flare means a combustion device, whether at ground level or 
elevated, that uses an open flame to burn combustible gases with 
combustion air provided by uncontrolled ambient air around the flame.
    Flat glass means glass made of soda-lime recipe and produced into 
continuous flat sheets and other products listed in NAICS 327211.
    Flowmeter means a device that measures the mass or volumetric rate 
of flow of a gas, liquid, or solid moving through an open or closed 
conduit (e.g. flowmeters include, but are not limited to, rotameters, 
turbine meters, coriolis meters, orifice meters, ultra-sonic 
flowmeters, and vortex flowmeters).
    Fluid coking unit means one or more refinery process units in which 
high molecular weight petroleum derivatives are thermally cracked and 
petroleum coke is continuously produced in a fluidized bed system. The 
fluid coking unit includes equipment for controlling air pollutant 
emissions and for heat recovery on the fluid coking burner exhaust 
vent. There are two basic types of fluid coking units: A traditional 
fluid coking unit in which only a small portion of the coke produced in 
the unit is burned to fuel the unit and the fluid coking burner exhaust 
vent is directed to the atmosphere (after processing in a CO boiler or 
other air pollutant control equipment) and a flexicoking unit in which 
an auxiliary burner is used to partially combust a significant portion 
of the produced petroleum coke to generate a low value fuel gas that is 
used as fuel in other combustion sources at the refinery.
    Fluorinated greenhouse gas means sulfur hexafluoride 
(SF6), nitrogen trifluoride (NF3), and any 
fluorocarbon except for controlled substances as defined at 40 CFR part 
82, subpart A and substances with vapor pressures of less than 1 mm of 
Hg absolute at 25 degrees C. With these exceptions, ``fluorinated GHG'' 
includes but is not limited to any hydrofluorocarbon, any 
perfluorocarbon, any fully fluorinated linear, branched or cyclic 
alkane, ether, tertiary amine or aminoether, any perfluoropolyether, 
and any hydrofluoropolyether.
    Fossil fuel means natural gas, petroleum, coal, or any form of 
solid, liquid, or gaseous fuel derived from such material, including 
for example, consumer products that are derived from such materials and 
are combusted.
    Fossil fuel-fired means powered by combustion of fossil fuel, alone 
or in combination with any other fuel, regardless of the percentage of 
fossil fuel consumed.
    Fractionators means plants that produce fractionated natural gas 
liquids (NGLs) extracted from produced natural gas and separate the 
NGLs individual component products: ethane, propane, butanes and 
pentane-plus (C5+). Plants that only process natural gas but do not 
fractionate NGLs further into component products are not considered 
fractionators. Some fractionators do not process production gas, but 
instead fractionate bulk NGLs received from natural gas processors. 
Some fractionators both process natural gas and fractionate bulk NGLs 
received from other plants.
    Fuel means solid, liquid or gaseous combustible material.
    Fuel gas means gas generated at a petroleum refinery, petrochemical 
plant, or similar industrial process unit, and that is combusted 
separately or in any combination with any type of gas.
    Fuel gas system means a system of compressors, piping, knock-out 
pots, mix drums, and, if necessary, units used to remove sulfur 
contaminants from the fuel gas (e.g., amine scrubbers) that collects 
fuel gas from one or more sources for treatment, as necessary, and 
transport to a stationary combustion unit. A fuel gas system may have 
an overpressure vent to a flare but the primary purpose for a fuel gas 
system is to provide fuel to the various combustion units at the 
refinery or petrochemical plant.
    Gas collection system or landfill gas collection system means a 
system of pipes used to collect landfill gas from different locations 
in the landfill to a

[[Page 56388]]

single location for treatment (thermal destruction) or use. Landfill 
gas collection systems may also include knock-out or separator drums 
and/or a compressor.
    Gas-fired unit means a stationary combustion unit that derives more 
than 50 percent of its annual heat input from the combustion of gaseous 
fuels, and the remainder of its annual heat input from the combustion 
of fuel oil or other liquid fuels.
    Gas monitor means an instrument that continuously measures the 
concentration of a particular gaseous species in the effluent of a 
stationary source.
    Gaseous fuel means a material that is in the gaseous state at 
standard atmospheric temperature and pressure conditions and that is 
combusted to produce heat and/or energy.
    Gasification means the conversion of a solid or liquid raw material 
into a gas.
    Gasoline--Other is any gasoline that is not defined elsewhere, 
including GTAB (gasoline treated as blendstock).
    Glass melting furnace means a unit comprising a refractory-lined 
vessel in which raw materials are charged and melted at high 
temperature to produce molten glass.
    Glass produced means the weight of glass exiting a glass melting 
furnace.
    Global warming potential or GWP means the ratio of the time-
integrated radiative forcing from the instantaneous release of one 
kilogram of a trace substance relative to that of one kilogram- of a 
reference gas, i.e., CO2.
    GPA means the Gas Processors Association.
    Greenhouse gas or GHG means carbon dioxide (CO2), 
methane (CH4), nitrous oxide (N2O), sulfur 
hexafluoride (SF6), hydrofluorocarbons (HFCs), perfluorocarbons (PFCs), 
and other fluorinated greenhouse gases as defined in this section.
    GTBA (gasoline-grade tertiary butyl alcohol, 
(CH3)3COH), or t-butanol, is an alcohol as 
described in ``Oxygenates.''
    Heavy Gas Oils are petroleum distillates with an approximate 
boiling range from 651 [deg]F to 1,000 [deg]F.
    Heel means the amount of gas that remains in a shipping container 
after it is discharged or off-loaded (that is no more than ten percent 
of the volume of the container).
    High heat value or HHV means the high or gross heat content of the 
fuel with the heat of vaporization included. The water is assumed to be 
in a liquid state.
    Hydrofluorocarbons or HFCs means a class of GHGs consisting of 
hydrogen, fluorine, and carbon.
    Import means, to land on, bring into, or introduce into, any place 
subject to the jurisdiction of the United States whether or not such 
landing, bringing, or introduction constitutes an importation within 
the meaning of the customs laws of the United States, with the 
following exemptions:
    (1) Off-loading used or excess fluorinated GHGs or nitrous oxide of 
U.S. origin from a ship during servicing.
    (2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from 
Mexico where the fluorinated GHGs or nitrous oxide had been admitted 
into Mexico in bond and were of U.S. origin.
    (3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when 
transported in a consignment of personal or household effects or in a 
similar non-commercial situation normally exempted from U.S. Customs 
attention.
    (4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction 
exclusively for U. S. military purposes.
    Importer means any person, company, or organization of record that 
for any reason brings a product into the United States from a foreign 
country, excluding introduction into U.S. jurisdiction exclusively for 
United States military purposes. An importer is the person, company, or 
organization primarily liable for the payment of any duties on the 
merchandise or an authorized agent acting on their behalf. The term 
includes, as appropriate:
    (1) The consignee.
    (2) The importer of record.
    (3) The actual owner.
    (4) The transferee, if the right to draw merchandise in a bonded 
warehouse has been transferred.
    Indurating furnace means a furnace where unfired taconite pellets, 
called green balls, are hardened at high temperatures to produce fired 
pellets for use in a blast furnace. Types of indurating furnaces 
include straight gate and grate kiln furnaces.
    Industrial greenhouse gases means nitrous oxide or any fluorinated 
greenhouse gas.
    In-line kiln/raw mill means a system in a portland cement 
production process where a dry kiln system is integrated with the raw 
mill so that all or a portion of the kiln exhaust gases are used to 
perform the drying operation of the raw mill, with no auxiliary heat 
source used. In this system the kiln is capable of operating without 
the raw mill operating, but the raw mill cannot operate without the 
kiln gases, and consequently, the raw mill does not generate a separate 
exhaust gas stream.
    Isobutane is a paraffinic branch chain hydrocarbon with molecular 
formula C4H10.
    Isobutylene is an olefinic branch chain hydrocarbon with molecular 
formula C4H8.
    Kerosene is a light petroleum distillate with a maximum 
distillation temperature of 400 [deg]F at the 10-percent recovery 
point, a final maximum boiling point of 572 [deg]F, a minimum flash 
point of 100 [deg]F, and a maximum freezing point of -22 [deg]F. 
Included are No. 1-K and No. 2-K, distinguished by maximum sulfur 
content (0.04 and 0.30 percent of total mass, respectively), as well as 
all other grades of kerosene called range or stove oil. Excluded is 
kerosene-type jet fuel (see definition herein).
    Kerosene-type jet fuel means a kerosene-based product used in 
commercial and military turbojet and turboprop aircraft. The product 
has a maximum distillation temperature of 400 [deg]F at the 10 percent 
recovery point and a final maximum boiling point of 572 [deg]F. 
Included are Jet A, Jet A-1, JP-5, and JP-8.
    Kiln means an oven, furnace, or heated enclosure used for thermally 
processing a mineral or mineral-based substance.
    Landfill means an area of land or an excavation in which wastes are 
placed for permanent disposal and that is not a land application unit, 
surface impoundment, injection well, or waste pile as those terms are 
defined under 40 CFR 257.2.
    Landfill gas means gas produced as a result of anaerobic 
decomposition of waste materials in the landfill. Landfill gas 
generally contains 40 to 60 percent methane on a dry basis, typically 
less than 1 percent non-methane organic chemicals, and the remainder 
being carbon dioxide.
    Lime is the generic term for a variety of chemical compounds that 
are produced by the calcination of limestone or dolomite. These 
products include but are not limited to calcium oxide, high-calcium 
quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and 
dolomitic hydrate.
    Liquid/Slurry means a manure management component in which manure 
is stored as excreted or with some minimal addition of water to 
facilitate handling and is stored in either tanks or earthen ponds, 
usually for periods less than one year.
    Lubricants include all grades of lubricating oils, from spindle oil 
to cylinder oil to those used in greases. Petroleum lubricants may be 
produced from distillates or residues.
    Makeup chemicals means carbonate chemicals (e.g., sodium and 
calcium carbonates) that are added to the chemical recovery areas of 
chemical

[[Page 56389]]

pulp mills to replace chemicals lost in the process.
    Manure composting means the biological oxidation of a solid waste 
including manure usually with bedding or another organic carbon source 
typically at thermophilic temperatures produced by microbial heat 
production. There are four types of composting employed for manure 
management: Static, in vessel, intensive windrow and passive windrow. 
Static composting typically occurs in an enclosed channel, with forced 
aeration and continuous mixing. In vessel composting occurs in piles 
with forced aeration but no mixing. Intensive windrow composting occurs 
in windrows with regular turning for mixing and aeration. Passive 
windrow composting occurs in windrows with infrequent turning for 
mixing and aeration.
    Maximum rated heat input capacity means the hourly heat input to a 
unit (in mmBtu/hr), when it combusts the maximum amount of fuel per 
hour that it is capable of combusting on a steady state basis, as of 
the initial installation of the unit, as specified by the manufacturer.
    Maximum rated input capacity means the maximum charging rate of a 
municipal waste combustor unit expressed in tons per day of municipal 
solid waste combusted, calculated according to the procedures under 40 
CFR 60.58b(j).
    Mcf means thousand cubic feet.
    Methane conversion factor means the extent to which the 
CH4 producing capacity (Bo) is realized in each 
type of treatment and discharge pathway and system. Thus, it is an 
indication of the degree to which the system is anaerobic.
    Methane correction factor means an adjustment factor applied to the 
methane generation rate to account for portions of the landfill that 
remain aerobic. The methane correction factor can be considered the 
fraction of the total landfill waste volume that is ultimately disposed 
of in an anaerobic state. Managed landfills that have soil or other 
cover materials have a methane correction factor of 1.
    Methanol (CH3OH) is an alcohol as described in 
``Oxygenates.''
    Midgrade gasoline has an octane rating greater than or equal to 88 
and less than or equal to 90. This definition applies to the midgrade 
categories of Conventional-Summer, Conventional-Winter, Reformulated-
Summer, and Reformulated-Winter. For midgrade categories of RBOB-
Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition 
refers to the expected octane rating of the finished gasoline after 
oxygenate has been added to the RBOB or CBOB.
    Miscellaneous products include all refined petroleum products not 
defined elsewhere. It includes, but is not limited to, naphtha-type jet 
fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic 
extracts and tars), absorption oils, ram-jet fuel, petroleum rocket 
fuels, synthetic natural gas feedstocks, waste feedstocks, and 
specialty oils. It excludes organic waste sludges, tank bottoms, spent 
catalysts, and sulfuric acid.
    MMBtu means million British thermal units.
    Motor gasoline (finished) means a complex mixture of volatile 
hydrocarbons, with or without additives, suitably blended to be used in 
spark ignition engines. Motor gasoline includes conventional gasoline, 
reformulated gasoline, and all types of oxygenated gasoline. Gasoline 
also has seasonal variations in an effort to control ozone levels. This 
is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline 
during the summer driving season. Depending on the region of the 
country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be 
further lowered by state regulations.
    Mscf means million standard cubic feet.
    MTBE (methyl tertiary butyl ether, 
(CH3)3COCH3) is an ether as described 
in ``Oxygenates.''
    Municipal solid waste landfill or MSW landfill means an entire 
disposal facility in a contiguous geographical space where household 
waste is placed in or on land. An MSW landfill may also receive other 
types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid 
waste, nonhazardous sludge, conditionally exempt small quantity 
generator waste, and industrial solid waste. Portions of an MSW 
landfill may be separated by access roads, public roadways, or other 
public right-of-ways. An MSW landfill may be publicly or privately 
owned.
    Municipal solid waste or MSW means solid phase household, 
commercial/retail, and/or institutional waste, such as, but not limited 
to, yard waste and refuse.
    N2O means nitrous oxide.
    Naphthas (< 401 [deg]F) is a generic term applied to a petroleum 
fraction with an approximate boiling range between 122 [deg]F and 400 
[deg]F. The naphtha fraction of crude oil is the raw material for 
gasoline and is composed largely of paraffinic hydrocarbons.
    Natural gas means a naturally occurring mixture of hydrocarbon and 
non-hydrocarbon gases found in geologic formations beneath the earth's 
surface, of which its constituents include, but are not limited to, 
methane, heavier hydrocarbons and carbon dioxide. Natural gas may be 
field quality (which varies widely) or pipeline quality. For the 
purposes of this subpart, the definition of natural gas includes 
similarly constituted fuels such as field production gas, process gas, 
and fuel gas.
    Natural gas 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 at lease 
separators and field facilities. 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.
    Natural gasoline means a mixture of liquid hydrocarbons (mostly 
pentanes and heavier hydrocarbons) extracted from natural gas. It 
includes isopentane.
    NIST means the United States National Institute of Standards and 
Technology.
    Nitric acid production line means a series of reactors and 
absorbers used to produce nitric acid.
    Nitrogen excreted is the nitrogen that is excreted by livestock in 
manure and urine.
    Non-crude feedstocks means any petroleum product or natural gas 
liquid that enters the refinery as a feedstock to be further refined or 
otherwise used on site.
    Non-recovery coke oven battery means a group of ovens connected by 
common walls and operated as a unit, where coal undergoes destructive 
distillation under negative pressure to produce coke, and which is 
designed for the combustion of the coke oven gas from which by-products 
are not recovered.
    Oil-fired unit means a stationary combustion unit that derives more 
than 50 percent of its annual heat input from the combustion of fuel 
oil, and the remainder of its annual heat input from the combustion of 
natural gas or other gaseous fuels.
    Open-ended valve or lines (OELs) means any valve, except pressure 
relief valves, having one side of the valve seat in contact with 
process fluid and one side open to atmosphere, either directly or 
through open piping.
    Operating hours means the duration of time in which a process or 
process unit is utilized; this excludes shutdown, maintenance, and 
standby.
    Operational change means, for purposes of Sec.  98.3(b), a change 
in the type of feedstock or fuel used, a change

[[Page 56390]]

in operating hours, or a change in process production rate.
    Operator means any person who operates or supervises a facility or 
supplier.
    Other oils ( 401 [deg]F) are oils with a boiling range 
equal to or greater than 401 [deg]F that are generally intended for use 
as a petrochemical feedstock and are not defined elsewhere.
    Owner means any person who has legal or equitable title to, has a 
leasehold interest in, or control of a facility or supplier, except a 
person whose legal or equitable title to or leasehold interest in the 
facility or supplier arises solely because the person is a limited 
partner in a partnership that has legal or equitable title to, has a 
leasehold interest in, or control of the facility or supplier shall not 
be considered an ``owner'' of the facility or supplier.
    Oxygenates means substances which, when added to gasoline, increase 
the oxygen content of the gasoline. Common oxygenates are ethanol, 
methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), 
tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and 
methanol.
    Pasture/Range/Paddock means the manure from pasture and range 
grazing animals is allowed to lie as deposited, and is not managed.
    Pentanes plus, or C5+, is a mixture of hydrocarbons that is a 
liquid at ambient temperature and pressure, and consists mostly of 
pentanes (five carbon chain) and higher carbon number hydrocarbons. 
Pentanes plus includes, but is not limited to, normal pentane, 
isopentane, hexanes-plus (natural gasoline), and plant condensate.
    Perfluorocarbons or PFCs means a class of greenhouse gases 
consisting on the molecular level of carbon and fluorine.
    Petrochemical means methanol, acrylonitrile, ethylene, ethylene 
oxide, ethylene dichloride, and any form of carbon black.
    Petrochemical feedstocks means feedstocks derived from petroleum 
for the manufacture of chemicals, synthetic rubber, and a variety of 
plastics. This category is usually divided into naphthas less than 401 
[deg]F and other oils greater than 401 [deg]F.
    Petroleum means oil removed from the earth and the oil derived from 
tar sands and shale.
    Petroleum coke means a black solid residue, obtained mainly by 
cracking and carbonizing of petroleum derived feedstocks, vacuum 
bottoms, tar and pitches in processes such as delayed coking or fluid 
coking. It consists mainly of carbon (90 to 95 percent), has low ash 
content, and may be used as a feedstock in coke ovens. This product is 
also known as marketable coke or catalyst coke.
    Petroleum product means all refined and semi-refined products that 
are produced at a refinery by processing crude oil and other petroleum-
based feedstocks, including petroleum products derived from co-
processing biomass and petroleum feedstock together, but not including 
plastics or plastic products. Petroleum products may be combusted for 
energy use, or they may be used either for non-energy processes or as 
non-energy products. The definition of petroleum product for importers 
and exporters excludes waxes.
    Pit storage below animal confinement (deep pits) means the 
collection and storage of manure typically below a slatted floor in an 
enclosed animal confinement facility. This usually occurs with little 
or no added water for periods less than one year.
    Portable means designed and capable of being carried or moved from 
one location to another. Indications of portability include but are not 
limited to wheels, skids, carrying handles, dolly, trailer, or 
platform. Equipment is not portable if any one of the following 
conditions exists:
    (1) The equipment is attached to a foundation.
    (2) The equipment or a replacement resides at the same location for 
more than 12 consecutive months.
    (3) The equipment is located at a seasonal facility and operates 
during the full annual operating period of the seasonal facility, 
remains at the facility for at least two years, and operates at that 
facility for at least three months each year.
    (4) The equipment is moved from one location to another in an 
attempt to circumvent the portable residence time requirements of this 
definition.
    Poultry manure with litter means a manure management system 
component that is similar to cattle and swine deep bedding except 
usually not combined with a dry lot or pasture. The system is typically 
used for poultry breeder flocks and for the production of meat type 
chickens (broiler) and other fowl.
    Poultry manure without litter means a manure management system 
component that may manage manure in a liquid form, similar to open pits 
in enclosed animal confinement facilities. These systems may 
alternatively be designed and operated to dry manure as it accumulates. 
The latter is known as a high-rise manure management system and is a 
form of passive windrow manure composting when designed and operated 
properly.
    Precision of a measurement at a specified level (e.g., one percent 
of full scale or one percent of the value measured) means that 95 
percent of repeat measurements made by a device or technique are within 
the range bounded by the mean of the measurements plus or minus the 
specified level.
    Premium grade gasoline is gasoline having an antiknock index, i.e., 
octane rating, greater than 90. This definition applies to the premium 
grade categories of Conventional-Summer, Conventional-Winter, 
Reformulated-Summer, and Reformulated-Winter. For premium grade 
categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, 
this definition refers to the expected octane rating of the finished 
gasoline after oxygenate has been added to the RBOB or CBOB.
    Pressed and blown glass means glass which is pressed, blown, or 
both, into products such as light bulbs, glass fiber, technical glass, 
and other products listed in NAICS 327212.
    Pressure relief device or pressure relief valve or pressure safety 
valve means a safety device used to prevent operating pressures from 
exceeding the maximum allowable working pressure of the process 
equipment. A common pressure relief device is but not limited to a 
spring-loaded pressure relief valve. Devices that are actuated either 
by a pressure of less than or equal to 2.5 psig or by a vacuum are not 
pressure relief devices.
    Process emissions means the emissions from industrial processes 
(e.g., cement production, ammonia production) involving chemical or 
physical transformations other than fuel combustion. For example, the 
calcination of carbonates in a kiln during cement production or the 
oxidation of methane in an ammonia process results in the release of 
process CO2 emissions to the atmosphere. Emissions from fuel 
combustion to provide process heat are not part of process emissions, 
whether the combustion is internal or external to the process 
equipment.
    Process unit means the equipment assembled and connected by pipes 
and ducts to process raw materials and to manufacture either a final 
product or an intermediate used in the onsite production of other 
products. The process unit also includes the purification of recovered 
byproducts.
    Process vent means means a gas stream that: Is discharged through a 
conveyance to the atmosphere either directly or after passing through a

[[Page 56391]]

control device; originates from a unit operation, including but not 
limited to reactors (including reformers, crackers, and furnaces, and 
separation equipment for products and recovered byproducts); and 
contains or has the potential to contain GHG that is generated in the 
process. Process vent does not include safety device discharges, 
equipment leaks, gas streams routed to a fuel gas system or to a flare, 
discharges from storage tanks.
    Propane is a paraffinic hydrocarbon with molecular formula 
C3H8.
    Propylene is an olefinic hydrocarbon with molecular formula 
C3H6.
    Pulp mill lime kiln means the combustion units (e.g., rotary lime 
kiln or fluidized bed calciner) used at a kraft or soda pulp mill to 
calcine lime mud, which consists primarily of calcium carbonate, into 
quicklime, which is calcium oxide.
    Pushing means the process of removing the coke from the coke oven 
at the end of the coking cycle. Pushing begins when coke first begins 
to fall from the oven into the quench car and ends when the quench car 
enters the quench tower.
    Raw mill means a ball and tube mill, vertical roller mill or other 
size reduction equipment, that is not part of an in-line kiln/raw mill, 
used to grind feed to the appropriate size. Moisture may be added or 
removed from the feed during the grinding operation. If the raw mill is 
used to remove moisture from feed materials, it is also, by definition, 
a raw material dryer. The raw mill also includes the air separator 
associated with the raw mill.
    RBOB-Summer (reformulated blendstock for oxygenate blending) means 
a petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Reformulated-Summer.
    RBOB-Winter (reformulated blendstock for oxygenate blending) means 
a petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of Reformulated-Winter.
    Reformulated-Summer refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which meet the 
requirements of the reformulated gasoline regulations promulgated by 
the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 
80.41, and summer RVP standards required under 40 CFR 80.27 or as 
specified by the state. Reformulated gasoline excludes Reformulated 
Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.
    Reformulated-Winter refers to finished gasoline formulated for use 
in motor vehicles, the composition and properties of which meet the 
requirements of the reformulated gasoline regulations promulgated by 
the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 
80.41, but which do not meet summer RVP standards required under 40 CFR 
80.27 or as specified by the state. Note: This category includes 
Oxygenated Fuels Program Reformulated Gasoline (OPRG). Reformulated 
gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) 
as well as other blendstock.
    Regular grade gasoline is gasoline having an antiknock index, i.e., 
octane rating, greater than or equal to 85 and less than 88. This 
definition applies to the regular grade categories of Conventional-
Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-
Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-
Summer, and CBOB-Winter, this definition refers to the expected octane 
rating of the finished gasoline after oxygenate has been added to the 
RBOB or CBOB.
    Rendered animal fat, or tallow, means fats extracted from animals 
which are generally used as a feedstock in making biodiesel.
    Research and development means those activities conducted in 
process units or at laboratory bench-scale settings whose purpose is to 
conduct research and development for new processes, technologies, or 
products and whose purpose is not for the manufacture of products for 
commercial sale, except in a de minimis manner.
    Residual Fuel Oil No. 5 (Navy Special) is a classification for the 
heavier fuel oil generally used in steam powered vessels in government 
service and inshore power plants. It has a minimum flash point of 131 
[deg]F.
    Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for 
the heavier fuel oil generally used for the production of electric 
power, space heating, vessel bunkering and various industrial purposes. 
It has a minimum flash point of 140 [deg]F.
    Residuum is residue from crude oil after distilling off all but the 
heaviest components, with a boiling range greater than 1,000 [deg]F.
    Road oil is any heavy petroleum oil, including residual asphaltic 
oil used as a dust palliative and surface treatment on roads and 
highways. It is generally produced in six grades, from 0, the most 
liquid, to 5, the most viscous.
    Rotary lime kiln means a unit with an inclined rotating drum that 
is used to produce a lime product from limestone by calcination.
    Safety device means a closure device such as a pressure relief 
valve, frangible disc, fusible plug, or any other type of device which 
functions exclusively to prevent physical damage or permanent 
deformation to a unit or its air emission control equipment by venting 
gases or vapors directly to the atmosphere during unsafe conditions 
resulting from an unplanned, accidental, or emergency event. A safety 
device is not used for routine venting of gases or vapors from the 
vapor headspace underneath a cover such as during filling of the unit 
or to adjust the pressure in response to normal daily diurnal ambient 
temperature fluctuations. A safety device is designed to remain in a 
closed position during normal operations and open only when the 
internal pressure, or another relevant parameter, exceeds the device 
threshold setting applicable to the air emission control equipment as 
determined by the owner or operator based on manufacturer 
recommendations, applicable regulations, fire protection and prevention 
codes and practices, or other requirements for the safe handling of 
flammable, combustible, explosive, reactive, or hazardous materials.
    Semi-refined petroleum product means all oils requiring further 
processing. Included in this category are unfinished oils which are 
produced by the partial refining of crude oil and include the 
following: Naphthas and lighter oils; kerosene and light gas oils; 
heavy gas oils; and residuum, and all products that require further 
processing or the addition of blendstocks.
    Sendout means, in the context of a local distribution company, the 
total deliveries of natural gas to customers over a specified time 
interval (typically hour, day, month, or year). Sendout is the sum of 
gas received through the city gate, gas withdrawn from on-system 
storage or peak shaving plants, and gas produced and delivered into the 
distribution system; and is net of any natural gas injected into on-
system storage. It comprises gas sales, exchange, deliveries, gas used 
by company, and unaccounted for gas. Sendout is measured at the city 
gate station, and other on-system receipt points from storage, peak 
shaving, and production.
    Sensor means a device that measures a physical quantity/quality or 
the change in a physical quantity/quality, such as temperature, 
pressure, flow rate, pH, or liquid level.
    SF6 means sulfur hexafluoride.

[[Page 56392]]

    Shutdown means the cessation of operation of an emission source for 
any purpose.
    Silicon carbide means an artificial abrasive produced from silica 
sand or quartz and petroleum coke.
    Sinter process means a process that produces a fused aggregate of 
fine iron-bearing materials suited for use in a blast furnace. The 
sinter machine is composed of a continuous traveling grate that conveys 
a bed of ore fines and other finely divided iron-bearing material and 
fuel (typically coke breeze), a burner at the feed end of the grate for 
ignition, and a series of downdraft windboxes along the length of the 
strand to support downdraft combustion and heat sufficient to produce a 
fused sinter product.
    Site means any combination of one or more graded pad sites, gravel 
pad sites, foundations, platforms, or the immediate physical location 
upon which equipment is physically located.
    Smelting furnace means a furnace in which lead-bearing materials, 
carbon-containing reducing agents, and fluxes are melted together to 
form a molten mass of material containing lead and slag.
    Solid storage is the storage of manure, typically for a period of 
several months, in unconfined piles or stacks. Manure is able to be 
stacked due to the presence of a sufficient amount of bedding material 
or loss of moisture by evaporation.
    Sour gas means any gas that contains significant concentrations of 
hydrogen sulfide. Sour gas may include untreated fuel gas, amine 
stripper off-gas, or sour water stripper gas.
    Special naphthas means all finished products with the naphtha 
boiling range (290 [deg] to 470 [deg]F) that are generally used as 
paint thinners, cleaners or solvents. These products are refined to a 
specified flash point. Special naphthas include all commercial hexane 
and cleaning solvents conforming to ASTM Specification D1836-07, 
Standard Specification for Commercial Hexanes, and D235-02 (Reapproved 
2007), Standard Specification for Mineral Spirits (Petroleum Spirits) 
(Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be 
blended or marketed as motor gasoline or aviation gasoline, or that are 
to be used as petrochemical and synthetic natural gas (SNG) feedstocks 
are excluded.
    Spent liquor solids means the dry weight of the solids in the spent 
pulping liquor that enters the chemical recovery furnace or chemical 
recovery combustion unit.
    Spent pulping liquor means the residual liquid collected from on-
site pulping operations at chemical pulp facilities that is 
subsequently fired in chemical recovery furnaces at kraft and soda pulp 
facilities or chemical recovery combustion units at sulfite or semi-
chemical pulp facilities.
    Standard conditions or standard temperature and pressure (STP) 
means 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.
    Steam reforming means a catalytic process that involves a reaction 
between natural gas or other light hydrocarbons and steam. The result 
is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.
    Still gas means any form or mixture of gases produced in refineries 
by distillation, cracking, reforming, and other processes. The 
principal constituents are methane, ethane, ethylene, normal butane, 
butylene, propane, and propylene.
    Storage tank means a vessel (excluding sumps) that is designed to 
contain an accumulation of crude oil, condensate, intermediate 
hydrocarbon liquids, or produced water and that is constructed entirely 
of non-earthen materials (e.g., wood, concrete, steel, plastic) that 
provide structural support.
    Sulfur recovery plant means all process units which recover sulfur 
or produce sulfuric acid from hydrogen sulfide (H2S) and/or 
sulfur dioxide (SO2) from a common source of sour gas at a 
petroleum refinery. The sulfur recovery plant also includes sulfur pits 
used to store the recovered sulfur product, but it does not include 
secondary sulfur storage vessels or loading facilities downstream of 
the sulfur pits. For example, a Claus sulfur recovery plant includes: 
Reactor furnace and waste heat boiler, catalytic reactors, sulfur pits, 
and, if present, oxidation or reduction control systems, or 
incinerator, thermal oxidizer, or similar combustion device. Multiple 
sulfur recovery units are a single sulfur recovery plant only when the 
units share the same source of sour gas. Sulfur recovery units that 
receive source gas from completely segregated sour gas treatment 
systems are separate sulfur recovery plants.
    Supplemental fuel means a fuel burned within a petrochemical 
process that is not produced within the process itself.
    Supplier means a producer, importer, or exporter of a fossil fuel 
or an industrial greenhouse gas.
    Taconite iron ore processing means an industrial process that 
separates and concentrates iron ore from taconite, a low grade iron 
ore, and heats the taconite in an indurating furnace to produce 
taconite pellets that are used as the primary feed material for the 
production of iron in blast furnaces at integrated iron and steel 
plants.
    TAME means tertiary amyl methyl ether, 
(CH3)2(C2H5)COCH3
).
    Trace concentrations means concentrations of less than 0.1 percent 
by mass of the process stream.
    Transform means to use and entirely consume (except for trace 
concentrations) nitrous oxide or fluorinated GHGs in the manufacturing 
of other chemicals for commercial purposes. Transformation does not 
include burning of nitrous oxide.
    Transshipment means the continuous shipment of nitrous oxide or a 
fluorinated GHG from a foreign state of origin through the United 
States or its territories to a second foreign state of final 
destination, as long as the shipment does not enter into United States 
jurisdiction. A transshipment, as it moves through the United States or 
its territories, cannot be re-packaged, sorted or otherwise changed in 
condition.
    Trona means the raw material (mineral) used to manufacture soda 
ash; hydrated sodium bicarbonate carbonate (e.g., 
Na2CO3.NaHCO3.2H2O).
    Ultimate analysis means the determination of the percentages of 
carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) 
oxygen in the gaseous products and ash after the complete combustion of 
a sample of an organic material.
    Unfinished oils are all oils requiring further processing, except 
those requiring only mechanical blending.
    United States means the 50 states, the District of Columbia, and 
U.S. possessions and territories.
    Unstabilized crude oil means, for the purposes of this part, crude 
oil that is pumped from the well to a pipeline or pressurized storage 
vessel for transport to the refinery without intermediate storage in a 
storage tank at atmospheric pressures. Unstabilized crude oil is 
characterized by having a true vapor pressure of 5 pounds per square 
inch absolute (psia) or greater.
    Valve means any device for halting or regulating the flow of a 
liquid or gas through a passage, pipeline, inlet, outlet, or orifice; 
including, but not limited to, gate, globe, plug, ball, butterfly and 
needle valves.
    Vegetable oil means oils extracted from vegetation that are 
generally used as a feedstock in making biodiesel.
    Volatile solids are the organic material in livestock manure and 
consist of both biodegradable and non-biodegradable fractions.
    Waelz kiln means an inclined rotary kiln in which zinc-containing 
materials are charged together with a carbon

[[Page 56393]]

reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite 
coal).
    Waxes means a solid or semi-solid material at 77 [deg]F consisting 
of a mixture of hydrocarbons obtained or derived from petroleum 
fractions, or through a Fischer-Tropsch type process, in which the 
straight chained paraffin series predominates. This includes all 
marketable wax, whether crude or refined, with a congealing point 
between 80 (or 85) and 240 [deg]F and a maximum oil content of 50 
weight percent.
    Wool fiberglass means fibrous glass of random texture, including 
fiberglass insulation, and other products listed in NAICS 327993.
    You means an owner or operator subject to Part 98.
    Zinc smelters means a facility engaged in the production of zinc 
metal, zinc oxide, or zinc alloy products from zinc sulfide ore 
concentrates, zinc calcine, or zinc-bearing scrap and recycled 
materials through the use of pyrometallurgical techniques involving the 
reduction and volatization of zinc-bearing feed materials charged to a 
furnace.


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

    The materials listed in this section are incorporated by reference 
in the corresponding sections noted. These incorporations by reference 
were approved by the Director of Federal Register in accordance with 5 
U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as 
they exist on the date of approval, and a notice of any change in the 
materials will be published in the Federal Register. The materials are 
available for purchase at the corresponding address in this section. 
The materials are available for inspection at the EPA Docket Center, 
Public Reading Room, EPA West Building, Room 3334, 1301 Constitution 
Avenue, NW., Washington, DC, phone (202) 566-1744 and at the National 
Archives and Records Administration (NARA). For information on the 
availability of this material at NARA, call 202-741-6030, or go to: 
http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
    (a) The following material is available for purchase from the 
Association of Fertilizer and Phosphate Chemists (AFPC), P.O. Box 1645, 
Bartow, Florida 33831, http://afpc.net.
    (1) Phosphate Mining States Methods Used and Adopted by the 
Association of Fertilizer and Phosphate Chemists AFPC Manual 10th 
Edition 2009--Version 1.9, incorporation by reference (IBR) approved 
for Sec.  98.264(a) and Sec.  98.264(b).
    (2) [Reserved]
    (b) The following material is available for purchase from the 
American Gas Association (AGA), 400 North Capitol Street, NW., 4th 
Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org.
    (1) AGA Report No. 3 Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids Part 1: General Equations & Uncertainty 
Guidelines (1990), incorporation by reference (IBR) approved for Sec.  
98.34(b) and Sec.  98.244(b).
    (2) AGA Report No. 3 Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids Part 2: Specification and Installation 
Requirements (2000), IBR approved for Sec.  98.34(b) and Sec.  
98.244(b).
    (3) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter 
(2003), IBR approved for Sec.  98.244(b) and Sec.  98.254(c).
    (4) AGA Transmission Measurement Committee Report No. 7 Measurement 
of Natural Gas by Turbine Meter (2006)/February, IBR approved for Sec.  
98.34(b) and Sec.  98.244(b).
    (c) The following material is available for purchase from the ASM 
International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-
5151, http://www.asminternational.org.
    (1) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon 
Steel of Medium Carbon Content), incorporation by reference (IBR) 
approved for Sec.  98.174(b).
    (2) [Reserved]
    (d) The following material is available for purchase from the 
American Society of Mechanical Engineers (ASME), Three Park Avenue, New 
York, NY 10016-5990, (800) 843-2763, http://www.asme.org.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved 
for Sec.  98.34(b), Sec.  98.244(b), Sec.  98.254(c), 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.  98.34(b), Sec.  98.244(b), Sec.  
98.254(c), Sec.  98.344(c), and Sec.  98.364(e).
    (3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters, IBR 
approved for Sec.  98.34(b) and Sec.  98.244(b).
    (4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters, IBR approved for Sec.  98.34(b), Sec.  98.244(b), 
Sec.  98.254(c), Sec.  98.344(c), and Sec.  98.364(e).
    (5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles, IBR approved for Sec.  
98.34(b), Sec.  98.244(b), Sec.  98.254(c), Sec.  98.344(c), 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.  98.34(b) 
and Sec.  98.244(b).
    (7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters, IBR approved for Sec.  98.244(b), Sec.  
98.254(c), and Sec.  98.344(c).
    (8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters, IBR approved for Sec.  98.244(b), Sec.  
98.254(c), Sec.  98.344(c), and Sec.  98.364(e).
    (9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flowmeters, IBR approved for Sec.  98.244(b).
    (10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable 
Area Meters, IBR approved for Sec.  98.244(b), Sec.  98.254(c),Sec.  
98.344(c), and Sec.  98.364(e).
    (11) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters, 
IBR approved for Sec.  98.244(b).
    (e) The following material is available for purchase from the 
American Society for Testing and Material (ASTM), 100 Barr Harbor 
Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, 
(800) 262-1373, http://www.astm.org.
    (1) ASTM C25-06 Standard Test Method for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime, incorporation by reference 
(IBR) approved for Sec.  98.114(b), Sec.  98.174(b), Sec.  98.184(b), 
Sec.  98.194(c), and Sec.  98.334(b).
    (2) ASTM C114-09 Standard Test Methods for Chemical Analysis of 
Hydraulic Cement, IBR approved for Sec.  98.84(a), Sec.  98.84(b), and 
Sec.  98.84(c).
    (3) ASTM D235-02 (Reapproved 2007) Standard Specification for 
Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), 
IBR approved for Sec.  98.6.
    (4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR 
approved for Sec.  98.34(a) and Sec.  98.254(e).
    (5) ASTM D388-05 Standard Classification of Coals by Rank, IBR 
approved for Sec.  98.6.
    (6) ASTM D910-07a Standard Specification for Aviation Gasolines, 
IBR approved for Sec.  98.6.
    (7) ASTM D1298-99 (Reapproved 2005) Standard Test Method for 
Density,

[[Page 56394]]

Relative Density (Specific Gravity), or API Gravity of Crude Petroleum 
and Liquid Petroleum Products by Hydrometer Method, IBR approved for 
Sec.  98.33(a).
    (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.  98.34(a) and Sec.  
98.254(e).
    (9) ASTM D1836-07 Standard Specification for Commercial Hexanes, 
IBR approved for Sec.  98.6.
    (10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography, IBR approved for Sec.  98.34(b), Sec.  98.74(c), 
Sec.  98.164(b), Sec.  98.244(b), Sec.  98.254(d), and Sec.  98.344(b).
    (11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography, IBR approved for Sec.  98.34(b), 
Sec.  98.74(c), Sec.  98.164(b), Sec.  98.254(d), Sec.  98.344(b), and 
Sec.  98.364(c).
    (12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for 
Analysis, IBR approved for Sec.  98.164(b).
    (13) ASTM D2234/D2234M-07 Standard Practice for Collection of a 
Gross Sample of Coal, IBR approved for Sec.  98.164(b).
    (14) ASTM D2502-04 Standard Test Method for Estimation of Mean 
Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, 
IBR approved for Sec.  98.34(b) and 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.  
98.34(b) and Sec.  98.74(c).
    (16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity 
Ethylene by Gas Chromatography, IBR approved for Sec.  98.244(b).
    (17) ASTM D2597-94 (Reapproved 2004) Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing 
Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for 
Sec.  98.164(b).
    (18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke, IBR approved for Sec.  98.74(c), Sec.  
98.164(b), Sec.  98.244(b), Sec.  98.254(i), Sec.  98.284(c), Sec.  
98.284(d), Sec.  98.314(c), Sec.  98.314(d), and Sec.  98.314(f).
    (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.  98.34(b), 
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.  98.34(a) and Sec.  98.254(e).
    (21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major 
and Minor Elements in Combustion Residues from Coal Utilization 
Processes, IBR approved for Sec.  98.144(b).
    (22) ASTM D4057-06 Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products, IBR approved for Sec.  98.164(b).
    (23) ASTM D4177-95 (Reapproved 2005) Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products, IBR approved 
for Sec.  98.164(b).
    (24) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR 
approved for Sec.  98.34(a) and 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.  98.34(a) and Sec.  98.254(e).
    (26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants, IBR approved for Sec.  98.34(b), 
Sec.  98.74(c), Sec.  98.164(b), Sec.  98.244(b), 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.  98.34(b), Sec.  98.74(c), Sec.  
98.114(b), Sec.  98.164(b), Sec.  98.174(b), Sec.  98.184(b), Sec.  
98.244(b), Sec.  98.254(i), Sec.  98.274(b), Sec.  98.284(c), Sec.  
98.284(d), Sec.  98.314(c), Sec.  98.314(d), Sec.  98.314(f), and Sec.  
98.334(b).
    (28) ASTM D5865-07a Standard Test Method for Gross Calorific Value 
of Coal and Coke, IBR approved for Sec.  98.34(a).
    (29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling 
of Process Vents With a Portable Gas Chromatograph, IBR approved for 
Sec.  98.244(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) and Sec.  
98.224(b).
    (31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, 
IBR approved for Sec.  98.164(b).
    (32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend 
Stock (B100) for Middle Distillate Fuels, IBR approved for Sec.  98.6.
    (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.  98.33(e), Sec.  98.34(d), 
Sec.  98.34(e), and Sec.  98.36(e).
    (34) ASTM D6883-04 Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR 
approved for Sec.  98.164(b).
    (35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of 
Coal, IBR approved for Sec.  98.164(b).
    (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.  98.33(e), Sec.  98.34(d), Sec.  98.34(e), and Sec.  98.36(e).
    (37) ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for 
Analysis of Soda Ash (Sodium Carbonate), IBR approved for Sec.  
98.294(a) and Sec.  98.294(b).
    (38) ASTM E1019-08 Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques, IBR approved for 
Sec.  98.174(b).
    (39) ASTM E1747-95 (Reapproved 2005) Standard Guide for Purity of 
Carbon Dioxide Used in Supercritical Fluid Applications, IBR approved 
for 98.424(b).
    (40) ASTM E1915-07a Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry, IBR approved for Sec.  98.174(b).
    (41) ASTM E1941-04 Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and Their Alloys, IBR approved for 
Sec.  98.114(b), Sec.  98.184(b), Sec.  98.334(b).
    (42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, 
IBR approved for Sec.  98.164(b), Sec.  98.244(b), and Sec.  98.254(d), 
and Sec.  98.344(b).
    (f) The following material is available for purchase from the Gas 
Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 
74143, (918) 493-3872, http://www.gasprocessors.com.
    (1) GPA 2172-09 Calculation of Gross Heating Value, Relative 
Density, Compressibility and Theoretical Hydrocarbon Liquid Content for 
Natural Gas Mixtures for Custody Transfer, IBR approved for Sec.  
98.34(a).
    (2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography, IBR approved for

[[Page 56395]]

Sec.  98.34(a), Sec.  98.164(b), Sec.  98.254(d), and Sec.  98.344(b).
    (g) The following material is available for purchase from the 
International Standards Organization (ISO), 1, ch. de la Voie-Creuse, 
Case postale 56, CH-1211 Geneva 20, Switzerland, +41 22 749 01 11, 
http://www.iso.org/iso/home.htm.
    (1) ISO 3170: Petroleum liquids--Manual sampling--Third Edition 
2004-02-01, IBR approved for Sec.  98.164(b).
    (2) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--
Second Edition 1988-12-01, IBR approved for Sec.  98.164(b).
    (3) ISO 8316: Measurement of Liquid Flow in Closed Conduits-- 
Method by Collection of the Liquid in a Volumetric Tank (1987-10-01)--
First Edition, IBR approved for Sec.  98.244(b).
    (4) ISO/TR 15349-1: 1998, Unalloyed steel--Determination of low 
carbon content. Part 1: Infrared absorption method after combustion in 
an electric resistance furnace (by peak separation) (1998-10-15)--First 
Edition, IBR approved for Sec.  98.174(b).
    (5) ISO/TR 15349-3: 1998, Unalloyed steel--Determination of low 
carbon content. Part 3: Infrared absorption method after combustion in 
an electric resistance furnace (with preheating) (1998-10-15)--First 
Edition, IBR approved for Sec.  98.174(b).
    (h) The following material is available for purchase from the 
National Lime Association (NLA), 200 North Glebe Road, Suite 800, 
Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org.
    (1) CO2 Emissions Calculation Protocol for the Lime 
Industry--English Units Version, February 5, 2008 Revision--National 
Lime Association, incorporation by reference (IBR) approved for Sec.  
98.194(c) and Sec.  98.194(e).
    (2) [Reserved]
    (i) The following material is available for purchase from the 
National Institute of Standards and Technology (NIST), 100 Bureau 
Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, http://www.nist.gov/index.html.
    (1) Specifications, Tolerances, and Other Technical Requirements 
For Weighing and Measuring Devices, NIST Handbook 44 (2009), 
incorporation by reference (IBR) approved for Sec.  98.244(b), Sec.  
98.254(h), and Sec.  98.344(a).
    (2) [Reserved]
    (j) The following material is available for purchase from the 
Technical Association of the Pulp and Paper Industry (TAPPI), 15 
Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.
    (1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation 
by reference (IBR) approved for Sec.  98.276(c) and Sec.  98.277(d).
    (2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, 
incorporation by reference (IBR) approved for Sec.  98.274(b).


Sec.  98.8  What are the compliance and enforcement provisions of this 
part?

    Any violation of any requirement of this part shall be a violation 
of the Clean Air Act, including section 114 (42 U.S.C. 7414). A 
violation includes but is not limited to failure to report GHG 
emissions, failure to collect data needed to calculate GHG emissions, 
failure to continuously monitor and test as required, failure to retain 
records needed to verify the amount of GHG emissions, and failure to 
calculate GHG emissions following the methodologies specified in this 
part. Each day of a violation constitutes a separate violation.


Sec.  98.9  Addresses.

    All requests, notifications, and communications to the 
Administrator pursuant to this part, other than submittal of the annual 
GHG report, shall be submitted to the following address:
    (a) For U.S. mail. Director, Climate Change Division, 1200 
Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.
    (b) For package deliveries. Director, Climate Change Division, 1310 
L St, NW., Washington, DC 20005.

                          Table A-1 to Subpart A of Part 98--Global Warming Potentials
                                             [100-Year Time Horizon]
----------------------------------------------------------------------------------------------------------------
                                                                                                 Global warming
                    Name                           CAS No.             Chemical formula          potential  (100
                                                                                                      yr.)
----------------------------------------------------------------------------------------------------------------
Carbon dioxide..............................          124-38-9  CO2...........................                 1
Methane.....................................           74-82-8  CH4...........................                21
Nitrous oxide...............................        10024-97-2  N2O...........................               310
HFC-23......................................           75-46-7  CHF3..........................            11,700
HFC-32......................................           75-10-5  CH2F2.........................               650
HFC-41......................................          593-53-3  CH3F..........................               150
HFC-125.....................................          354-33-6  C2HF5.........................             2,800
HFC-134.....................................          359-35-3  C2H2F4........................             1,000
HFC-134a....................................          811-97-2  CH2FCF3.......................             1,300
HFC-143.....................................          430-66-0  C2H3F3........................               300
HFC-143a....................................          420-46-2  C2H3F3........................             3,800
HFC-152.....................................          624-72-6  CH2FCH2F......................                53
HFC-152a....................................           75-37-6  CH3CHF2.......................               140
HFC-161.....................................          353-36-6  CH3CH2F.......................                12
HFC-227ea...................................          431-89-0  C3HF7.........................             2,900
HFC-236cb...................................          677-56-5  CH2FCF2CF3....................             1,340
HFC-236ea...................................          431-63-0  CHF2CHFCF3....................             1,370
HFC-236fa...................................          690-39-1  C3H2F6........................             6,300
HFC-245ca...................................          679-86-7  C3H3F5........................               560
HFC-245fa...................................          460-73-1  CHF2CH2CF3....................             1,030
HFC-365mfc..................................          406-58-6  CH3CF2CH2CF3..................               794
HFC-43-10mee................................       138495-42-8  CF3CFHCFHCF2CF3...............             1,300
Sulfur hexafluoride.........................         2551-62-4  SF6...........................            23,900
Trifluoromethyl sulphur pentafluoride.......          373-80-8  SF5CF3........................            17,700
Nitrogen trifluoride........................         7783-54-2  NF3...........................            17,200
PFC-14 (Perfluoromethane)...................           75-73-0  CF4...........................             6,500
PFC-116 (Perfluoroethane)...................           76-16-4  C2F6..........................             9,200
PFC-218 (Perfluoropropane)..................           76-19-7  C3F8..........................             7,000

[[Page 56396]]

 
Perfluorocyclopropane.......................          931-91-9  C-C3F6........................            17,340
PFC-3-1-10 (Perfluorobutane)................          355-25-9  C4F10.........................             7,000
Perfluorocyclobutane........................          115-25-3  C-C4F8........................             8,700
PFC-4-1-12 (Perfluoropentane)...............          678-26-2  C5F12.........................             7,500
PFC-5-1-14..................................          355-42-0  C6F14.........................             7,400
(Perfluorohexane)...........................
PFC-9-1-18..................................          306-94-5  C10F18........................             7,500
HCFE-235da2 (Isoflurane)....................        26675-46-7  CHF2OCHClCF3..................               350
HFE-43-10pccc (H-Galden 1040x)..............          E1730133  CHF2OCF2OC2F4OCHF2............             1,870
HFE-125.....................................         3822-68-2  CHF2OCF3......................            14,900
HFE-134.....................................         1691-17-4  CHF2OCHF2.....................             6,320
HFE-143a....................................          421-14-7  CH3OCF3.......................               756
HFE-227ea...................................         2356-62-9  CF3CHFOCF3....................             1,540
HFE-236ca12 (HG-10).........................        78522-47-1  CHF2OCF2OCHF2.................             2,800
HFE-236ea2 (Desflurane).....................        57041-67-5  CHF2OCHFCF3...................               989
HFE-236fa...................................        20193-67-3  CF3CH2OCF3....................               487
HFE-245cb2..................................        22410-44-2  CH3OCF2CF3....................               708
HFE-245fa1..................................        84011-15-4  CHF2CH2OCF3...................               286
HFE-245fa2..................................         1885-48-9  CHF2OCH2CF3...................               659
HFE-254cb2..................................          425-88-7  CH3OCF2CHF2...................               359
HFE-263fb2..................................          460-43-5  CF3CH2OCH3....................                11
HFE-329mcc2.................................        67490-36-2  CF3CF2OCF2CHF2................               919
HFE-338mcf2.................................       156053-88-2  CF3CF2OCH2CF3.................               552
HFE-338pcc13 (HG-01)........................       188690-78-0  CHF2OCF2CF2OCHF2..............             1,500
HFE-347mcc3.................................        28523-86-6  CH3OCF2CF2CF3.................               575
HFE-347mcf2.................................          E1730135  CF3CF2OCH2CHF2................               374
HFE-347pcf2.................................          406-78-0  CHF2CF2OCH2CF3................               580
HFE-356mec3.................................          382-34-3  CH3OCF2CHFCF3.................               101
HFE-356pcc3.................................       160620-20-2  CH3OCF2CF2CHF2................               110
HFE-356pcf2.................................          E1730137  CHF2CH2OCF2CHF2...............               265
HFE-356pcf3.................................        35042-99-0  CHF2OCH2CF2CHF2...............               502
HFE-365mcf3.................................          378-16-5  CF3CF2CH2OCH3.................                11
HFE-374pc2..................................          512-51-6  CH3CH2OCF2CHF2................               557
HFE-449sl (HFE-7100)........................       163702-07-6  C4F9OCH3......................               297
Chemical blend..............................       163702-08-7  (CF3)2CFCF2OCH3...............
HFE-569sf2 (HFE-7200).......................       163702-05-4  C4F9OC2H5.....................                59
Chemical blend..............................       163702-06-5  (CF3)2CFCF2OC2H5..............
Sevoflurane.................................        28523-86-6  CH2FOCH(CF3)2.................               345
HFE-356mm1..................................        13171-18-1  (CF3)2CHOCH3..................                27
HFE-338mmz1.................................        26103-08-2  CHF2OCH(CF3)2.................               380
(Octafluorotetramethy-lene)hydroxymethyl                    NA  X-(CF2)4CH(OH)-X..............                73
 group.
HFE-347mmy1.................................        22052-84-2  CH3OCF(CF3)2..................               343
Bis(trifluoromethyl)-methanol...............          920-66-1  (CF3)2CHOH....................               195
2,2,3,3,3-pentafluoropropanol...............          422-05-9  CF3CF2CH2OH...................                42
PFPMIE......................................                NA  CF3OCF(CF3)CF2OCF2OCF3........            10,300
----------------------------------------------------------------------------------------------------------------
NA = not available.


                         Table A-2 to Subpart A of Part 98--Units of Measure Conversions
----------------------------------------------------------------------------------------------------------------
             To convert from                             To                             Multiply by
----------------------------------------------------------------------------------------------------------------
Kilograms (kg)..........................  Pounds (lbs)...................  2.20462
Pounds (lbs)............................  Kilograms (kg).................  0.45359
Pounds (lbs)............................  Metric tons....................  4.53592 x 10-4
Short tons..............................  Pounds (lbs)...................  2,000
Short tons..............................  Metric tons....................  0.90718
Metric tons.............................  Short tons.....................  1.10231
Metric tons.............................  Kilograms (kg).................  1,000
Cubic meters (m\3\).....................  Cubic feet (ft\3\).............  35.31467
Cubic feet (ft\3\)......................  Cubic meters (m\3\)............  0.028317
Gallons (liquid, US)....................  Liters (l).....................  3.78541
Liters (l)..............................  Gallons (liquid, US)...........  0.26417
Barrels of Liquid Fuel (bbl)............  Cubic meters (m\3\)............  0.15891
Cubic meters (m\3\).....................  Barrels of Liquid Fuel (bbl)...  6.289
Barrels of Liquid Fuel (bbl)............  Gallons (liquid, US)...........  42
Gallons (liquid, US)....................  Barrels of Liquid Fuel (bbl)...  0.023810
Gallons (liquid, US)....................  Cubic meters (m\3\)............  0.0037854
Liters (l)..............................  Cubic meters (m\3\)............  0.001

[[Page 56397]]

 
Feet (ft)...............................  Meters (m).....................  0.3048
Meters (m)..............................  Feet (ft)......................  3.28084
Miles (mi)..............................  Kilometers (km)................  1.60934
Kilometers (km).........................  Miles (mi).....................  0.62137
Square feet (ft\2\).....................  Acres..........................  2.29568 x 10-5
Square meters (m\2\)....................  Acres..........................  2.47105 x 10-4
Square miles (mi\2\)....................  Square kilometers (km\2\)......  2.58999
Degrees Celsius ([deg]C)................  Degrees Fahrenheit ([deg]F)....  [deg]C = (\5/9\) x ([deg]F -32)
Degrees Fahrenheit ([deg]F).............  Degrees Celsius ([deg]C).......  [deg]F = (\9/5\) x [deg]C + 32
Degrees Celsius ([deg]C)................  Kelvin (K).....................  K = [deg]C + 273.15
Kelvin (K)..............................  Degrees Rankine ([deg]R).......  1.8
Joules..................................  Btu............................  9.47817 x 10-4
Btu.....................................  MMBtu..........................  1 x 10-6
Pascals (Pa)............................  Inches of Mercury (in Hg)......  2.95334 x 10-4
Inches of Mercury (inHg)................  Pounds per square inch (psi)...  0.49110
Pounds per square inch (psi)............  Inches of Mercury (in Hg)......  2.03625
----------------------------------------------------------------------------------------------------------------

Subpart B--[Reserved]

Subpart C--General Stationary Fuel Combustion Sources


Sec.  98.30  Definition of the source category.

    (a) Stationary fuel combustion sources are devices that combust 
solid, liquid, or gaseous fuel, generally for the purposes of producing 
electricity, generating steam, or providing useful heat or energy for 
industrial, commercial, or institutional use, or reducing the volume of 
waste by removing combustible matter. Stationary fuel combustion 
sources include, but are not limited to, boilers, simple and combined-
cycle combustion turbines, engines, incinerators, and process heaters.
    (b) This source category does not include:
    (1) Portable equipment, as defined in Sec.  98.6.
    (2) Emergency generators and emergency equipment, as defined in 
Sec.  98.6.
    (3) Irrigation pumps at agricultural operations.
    (4) Flares, unless otherwise required by provisions of another 
subpart of 40 CFR part 98 to use methodologies in this subpart.
    (5) Electricity generating units that are subject to subpart D of 
this part.
    (c) For a unit that combusts hazardous waste (as defined in 40 CFR 
261.3), reporting of GHG emissions is not required unless either of the 
following conditions apply:
    (1) Continuous emission monitors (CEMS) are used to quantify 
CO2 mass emissions.
    (2) Any fuel listed in Table C-1 of this subpart is also combusted 
in the unit. In this case, report GHG emissions from combustion of all 
fuels listed in Table C-1 of this subpart.


Sec.  98.31  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains one or more stationary fuel combustion sources and the 
facility meets the applicability requirements of either Sec. Sec.  
98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).


Sec.  98.32  GHGs to report.

    You must report CO2, CH4, and N2O 
mass emissions from each stationary fuel combustion unit.


Sec.  98.33  Calculating GHG emissions.

    You must calculate CO2 emissions according to paragraph 
(a) of this section, and calculate CH4 and N2O 
emissions according to paragraph (c) of this section.
    (a) CO2 emissions from fuel combustion. Calculate 
CO2 emissions by using one of the four calculation 
methodologies in this paragraph (a) subject to the conditions, 
requirements, and restrictions set forth in paragraph (b) of this 
section. If you co-fire biomass fuels with fossil fuels, report 
CO2 emissions from the combustion of biomass separately 
using the methods in paragraph (e) of this section.
    (1) Tier 1 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using Equation 
C-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.004

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.

    (2) Tier 2 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each type of fuel by using either 
Equation C2a or C2c of this section, as appropriate.
    (i) Equation C-2a of this section applies to any type of fuel 
listed in Table C-1 of the subpart, except for municipal solid waste 
(MSW). For MSW combustion, use Equation C-2c of this section.

[[Page 56398]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.005

Where:

CO2 = Annual CO2 mass emissions for a specific 
fuel type (metric tons).
Fuel = Mass or volume of the fuel combusted during the 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 = Annual average high heat value of the fuel from all valid 
samples for the year (mmBtu per mass or volume). The average HHV 
shall be calculated according to the requirements of paragraph 
(a)(2)(ii) of this section.
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) The minimum number of HHV samples for determining annual 
average HHV is specified (e.g., monthly, quarterly, semi-annually, or 
by lot) in Sec.  98.34. The method for computing the annual average HHV 
is a function of how frequently you perform or receive from the fuel 
supplier the results of fuel sampling for HHV. The method is specified 
in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as 
applicable.
    (A) If the results of fuel sampling are received monthly or more 
frequently, then the annual average HHV shall be calculated using 
Equation C-2b of this section. If multiple HHV determinations are made 
in any month, average the values for the month arithmetically.
[GRAPHIC] [TIFF OMITTED] TR30OC09.006

Where:

(HHV)annual = Weighted annual average high heat value of 
the fuel (mmBtu per mass or volume).
(HHV)i = High heat value of the fuel, for month ``i'' 
(mmBtu per mass or volume).
(Fuel)i = Mass or volume of the fuel combusted during 
month ``i'' (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 fuel is burned in the unit.

    (B) If the results of fuel sampling are received less frequently 
than monthly, then the annual average HHV shall be computed as the 
arithmetic average HHV for all values for the year (including valid 
samples and substitute data values under Sec.  98.35).
    (iii) For units that combust municipal solid waste (MSW) and that 
produce steam, use Equation C-2c of this section. Equation C-2c of this 
section may also be used for any other solid fuel listed in Table C-1 
of this subpart provided that steam is generated by the unit.
[GRAPHIC] [TIFF OMITTED] TR30OC09.007

Where:

CO2 = Annual CO2 mass emissions from MSW or 
solid fuel combustion (metric tons).
Steam = Total mass of steam generated by MSW or solid fuel 
combustion during the reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its 
design rated steam output capacity (mmBtu/lb steam).
EF = 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.

    (3) Tier 3 Calculation Methodology. Calculate the annual 
CO2 mass emissions for each fuel by using either Equation 
C3, C4, or C5 of this section, as appropriate.
    (i) For a solid fuel, use Equation C-3 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.008
    
Where:

CO2 = Annual CO2 mass emissions from the 
combustion of the specific solid fuel (metric tons).
Fuel = Annual mass of the solid fuel combusted, from company records 
as defined in Sec.  98.6 (short tons).
CC = Annual average carbon content of the solid fuel (percent by 
weight, expressed as a decimal fraction, e.g., 95% = 0.95). The 
annual average carbon content shall be determined using the same 
procedures as specified for HHV in paragraph (a)(2)(ii) of this 
section.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.91 = Conversion factor from short tons to metric tons.

    (ii) For a liquid fuel, use Equation C-4 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.009
    

[[Page 56399]]


Where:

CO2 = Annual CO2 mass emissions from the 
combustion of the specific liquid fuel (metric tons).
Fuel = Annual volume of the liquid fuel combusted (gallons). The 
volume of fuel combusted must be measured directly, using fuel flow 
meters calibrated according to Sec.  98.3(i). Fuel billing meters 
may be used for this purpose. Tank drop measurements may also be 
used.
CC = Annual average carbon content of the liquid fuel (kg C per 
gallon 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.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iii) For a gaseous fuel, use Equation C-5 of this section.
    [GRAPHIC] [TIFF OMITTED] TR30OC09.010
    
Where:

CO2 = Annual CO2 mass emissions from 
combustion of the specific gaseous fuel (metric tons).
Fuel = Annual volume of the gaseous fuel combusted (scf). The volume 
of fuel combusted must be measured directly, using fuel flow meters 
calibrated according to Sec.  98.3(i). Fuel billing meters may be 
used for this purpose.
CC = Annual average carbon content of the liquid fuel (kg C per 
gallon 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 carbon content shall be determined using 
the same procedures as specified for HHV in paragraph (a)(2)(ii) of 
this section.
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions, as defined in Sec.  98.6).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (iv) Fuel flow meters that measure mass flow rates may be used for 
liquid 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, using ASTM D1298-99 (Reapproved 
2005) ``Standard Test Method for Density, Relative Density (Specific 
Gravity), or API Gravity of Crude Petroleum and Liquid Petroleum 
Products by Hydrometer Method'' (incorporated by reference, see Sec.  
98.7).
    (v) The following default density values may be used for fuel oil, 
in lieu of using the ASTM method 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) Tier 4 Calculation Methodology. Calculate the annual 
CO2 mass emissions from all fuels combusted in a unit, by 
using quality-assured data from continuous emission monitoring systems 
(CEMS).
    (i) This methodology requires a CO2 concentration 
monitor and a stack gas volumetric flow rate monitor, except as 
otherwise provided in paragraph (a)(4)(iv) of this section. Hourly 
measurements of CO2 concentration and stack gas flow rate 
are converted to CO2 mass emission rates in metric tons per 
hour.
    (ii) When the CO2 concentration is measured on a wet 
basis, Equation C-6 of this section is used to calculate the hourly 
CO2 emission rates:
[GRAPHIC] [TIFF OMITTED] TR30OC09.011

Where:

CO2 = CO2 mass emission rate (metric tons/hr).
CCO2 = Hourly average CO2 concentration (% 
CO2).
Q = Hourly average stack gas volumetric flow rate (scfh).
5.18 x 10-7 = Conversion factor (metric tons/scf/% 
CO2).

    (iii) If the CO2 concentration is measured on a dry 
basis, a correction for the stack gas moisture content is required. You 
shall either continuously monitor the stack gas moisture content as 
described in Sec.  75.11(b)(2) of this chapter or, for certain types of 
fuel, use a default moisture percentage from Sec.  75.11(b)(1) of this 
chapter. For each unit operating hour, a moisture correction must be 
applied to Equation C-6 of this section as follows:
[GRAPHIC] [TIFF OMITTED] TR30OC09.012

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 40 CFR part 75, if the effluent 
gas stream monitored by the CEMS consists solely of combustion products 
(i.e., no process CO2 emissions 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 40 CFR part 75 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 40 CFR part 75, as 
applicable. If Equation F-14b is used, the hourly moisture percentage 
in the stack gas shall be either a measured value in accordance with 
Sec.  75.11(b)(2) of this chapter, or, for certain types of fuel, a 
default moisture value from Sec.  75.11(b)(1) of this chapter.
    (v) Each hourly CO2 mass emission rate from Equation C-6 
or C-7 of this section is multiplied by the operating time to convert 
it from metric tons per hour to metric tons. The operating time is the 
fraction of the hour during which fuel is combusted (e.g., the unit 
operating time is 1.0 if the unit operates for the whole hour and is 
0.5 if the unit operates for 30 minutes in the hour). For common stack 
configurations, the operating time is the fraction of the hour during 
which effluent gases flow through the common stack.
    (vi) The hourly CO2 mass emissions are then summed over 
each calendar quarter and the quarterly totals are summed to determine 
the annual CO2 mass emissions.
    (vii) If both biomass and fossil fuel are combusted during the 
year, determine and report the biogenic CO2 mass emissions 
separately, as described in paragraph (e) of this section.
    (5) Alternative methods for units with continuous monitoring 
systems. Units not subject to the Acid Rain Program that report data to 
EPA according to 40 CFR part 75 may use the alternative methods in this 
paragraph 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 the Acid Rain Program, monitors and reports heat input 
data year-round according to appendix D to 40 CFR part

[[Page 56400]]

75, but is not required by the applicable 40 CFR 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 40 CFR part 
75, together with Equation G-4 in appendix G to 40 CFR part 75 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 40 CFR part 75 to 
calculate the quarterly and cumulative annual CO2 mass 
emissions, respectively, in units of short tons; and
    (C) Divide the cumulative annual CO2 mass emissions 
value by 1.1 to convert it to metric tons.
    (ii) For a unit that combusts only natural gas and/or fuel oil, is 
not subject to the Acid Rain Program, monitors and reports heat input 
data year-round according to 40 CFR 75.19 of this chapter but is not 
required by the applicable 40 CFR 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 40 CFR 75.19(c)(4)(iii).
    (B) Sum the hourly CO2 mass emissions values over the 
entire reporting year to obtain the cumulative annual CO2 
mass emissions, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions 
value by 1.1 to convert it to metric tons.
    (iii) For a unit that is not subject to the Acid Rain Program, uses 
flow rate and CO2 (or O2) CEMS to report heat 
input data year-round according to 40 CFR part 75, but is not required 
by the applicable 40 CFR 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 40 
CFR part 75 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 40 CFR part 75 (as applicable), before 
applying Equation F-11 or F-2.
    (B) Use Equations F-12 and F-13 in appendix F to 40 CFR part 75 to 
calculate the quarterly and cumulative annual CO2 mass 
emissions, respectively, in units of short tons.
    (C) Divide the cumulative annual CO2 mass emissions 
value by 1.1 to convert it to metric tons.
    (D) If both biomass and fossil fuel are combusted during the year, 
determine and report the biogenic CO2 mass emissions 
separately, as described in paragraph (e) of this section.
    (b) Use of the four tiers. Use of the four tiers of CO2 
emissions calculation methodologies described in paragraph (a) of this 
section is subject to the following conditions, requirements, and 
restrictions:
    (1) The Tier 1 Calculation Methodology:
    (i) May be used for any fuel listed in Table C-1 of this subpart 
that is combusted in a unit with a maximum rated heat input capacity of 
250 mmBtu/hr or less.
    (ii) May be used for MSW in a unit of any size that does not 
produce steam, if the use of Tier 4 is not required.
    (iii) May be used for solid, gaseous, or liquid biomass fuels in a 
unit of any size provided that the fuel is listed in Table C-1 of this 
subpart.
    (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.
    (2) The Tier 2 Calculation Methodology:
    (i) May be used for the combustion of any type of fuel in a unit 
with a maximum rated heat input capacity of 250 mmBtu/hr or less 
provided that the fuel is listed in Table C-1 of this subpart.
    (ii) May be used in a unit with a maximum rated heat input capacity 
greater than 250 mmBtu/hr for the combustion of pipeline quality 
natural gas and distillate fuel oil.
    (iii) May be used for MSW in a unit of any size that produces 
steam, if the use of Tier 4 is not required.
    (3) The Tier 3 Calculation Methodology:
    (i) May be used for a unit of any size that combusts any type of 
fuel listed in Table C-1 of this subpart (except for MSW), unless the 
use of Tier 4 is required.
    (ii) Shall be used for a unit with a maximum rated heat input 
capacity greater than 250 mmBtu/hr that combusts any type of fuel 
listed in Table C-1 of this subpart (except MSW), unless either of the 
following conditions apply:
    (A) The use of Tier 1 or 2 is permitted, as described in paragraphs 
(b)(1)(iii) and (b)(2)(ii) of this section.
    (B) The use of Tier 4 is required.
    (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 provided that both of the 
following conditions apply:
    (A) The use of Tier 4 is not required.
    (B) The fuel provides 10% or more of the annual heat input to the 
unit or, if Sec.  98.36(c)(3) applies, to a group of units served by 
common supply pipe.
    (4) The Tier 4 Calculation Methodology:
    (i) May be used for a unit of any size, combusting any type of 
fuel.
    (ii) Shall be used if the unit meets all six of the conditions 
specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this 
section:
    (A) The unit has a maximum rated heat input capacity greater than 
250 mmBtu/hr, or if the unit combusts municipal solid waste and has a 
maximum rated input capacity greater than 250 tons per day of MSW.
    (B) The unit combusts solid fossil fuel or MSW, either as a primary 
or secondary fuel.
    (C) The unit has operated for more than 1,000 hours in any calendar 
year since 2005.
    (D) The unit has installed CEMS that are required either by an 
applicable Federal or State regulation or the unit's operating permit.
    (E) The installed CEMS include a gas monitor of any kind or a stack 
gas volumetric flow rate monitor, or both and the monitors have been 
certified, either in accordance with the requirements of 40 CFR part 
75, 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 40 CFR part 75, 
appendix F to 40 CFR part 60, or an applicable State continuous 
monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input 
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal 
solid waste with a maximum rated input capacity of 250 tons of MSW per 
day or less, if the unit meets all of the following three conditions:
    (A) The unit has both a stack gas volumetric flow rate monitor and 
a CO2 concentration monitor.
    (B) The unit meets the conditions specified in paragraphs 
(b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.
    (C) The CO2 and stack gas volumetric flow rate monitors 
meet the conditions specified in paragraphs (b)(4)(ii)(E) and 
(b)(4)(ii)(F) of this section.

[[Page 56401]]

    (5) The Tier 4 Calculation Methodology shall be used beginning on:
    (i) 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) 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.
    (6) You may elect to use any applicable higher tier for one or more 
of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit 
combusts natural gas and distillate fuel oil, you may elect to use Tier 
1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could 
have been used for both fuels. However, for units that use either the 
Tier 4 or the alternative calculation methodology specified in 
paragraph (a)(5) of this section, CO2 emissions from the 
combustion of all fuels shall be based solely on CEMS measurements.
    (c) Calculation of CH4 and N2O emissions from stationary combustion 
sources. You must calculate annual CH4 and N2O 
mass emissions only for units that are required to report 
CO2 emissions using the calculation methodologies of this 
subpart and for only those fuels that are listed in Table C-2 of this 
subpart.
    (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. Use the same 
values for fuel combustion that you use for the Tier 1 or Tier 3 
calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.013

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a particular type of 
fuel (metric tons).
Fuel = Mass or volume of the fuel combusted, either from company 
records or directly measured by a fuel flow meter, as applicable 
(mass or volume per year).
HHV = Default high heat value of the fuel from Table C-1 of this 
subpart (mmBtu per mass or volume).
EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (2) Use Equation C-9a of this section to estimate CH4 
and N2O emissions for any fuels for which you use the Tier 2 
Equation C-2a of this section to estimate CO2 emissions. Use 
the same values for fuel combustion and HHV that you use for the Tier 1 
or Tier 3 calculation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.014

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a particular type of 
fuel (metric tons).
Fuel = Mass or volume of the fuel combusted during the reporting 
year.
HHV = High heat value of the fuel, averaged for all valid 
measurements for the reporting year (mmBtu per mass or volume).
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.

    (3) Use Equation C-9b of this section to estimate CH4 
and N2O emissions for any fuels for which you use Equation 
C-2c of this section to calculate the CO2 emissions. Use the 
same values for steam generation and the ratio ``B'' that you use for 
Equation C-2c.
[GRAPHIC] [TIFF OMITTED] TR30OC09.015

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a solid fuel (metric 
tons).
Steam = Total mass of steam generated by solid fuel combustion 
during the reporting year (lb steam).
B = Ratio of the boiler's maximum rated heat input capacity to its 
design rated steam output (mmBtu/lb steam).
EF = Fuel-specific emission factor for CH4 or 
N2O, from Table C-2 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.

    (4) Use Equation C-10 of this section for units in the Acid Rain 
Program, units that monitor and report heat input on a year-round basis 
according to 40 CFR part 75, and units that use the Tier 4 Calculation 
Methodology.
[GRAPHIC] [TIFF OMITTED] TR30OC09.016

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a particular type of 
fuel (metric tons).
(HI)A = Cumulative annual heat input from the fuel, 
derived from the electronic data reports required under Sec.  75.64 
of this chapter or, for Tier 4 units, from the best available 
information as described in paragraph (c)(4)(ii) of this section 
(mmBtu).
EF = Fuel-specific emission factor for CH4 or 
N2O, from Table C-2 of this section (kg CH4 or 
N2O per mmBtu).
0.001 = Conversion factor from kg to metric tons.

    (i) If only one type of fuel listed in Table C-2 of this subpart is 
combusted during normal operation, 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.

[[Page 56402]]

    (ii) If more than one type of fuel listed in Table C-2 of this 
subpart is combusted during normal operation, use Equation C-10 of this 
section separately for each type of fuel. If flow rate and diluent gas 
monitors are used to measure the unit heat input, use the best 
available information (e.g., fuel feed rate measurements, fuel heating 
values, engineering analysis) to estimate the annual heat input from 
each type of fuel.
    (5) When multiple fuels are combusted during the reporting year, 
sum the fuel-specific results from Equations C-8, C-9a, C-9b, or C-10 
of this section (as applicable) to obtain the total annual 
CH4 and N2O emissions, in metric tons.
    (d) Calculation of CO2 from sorbent.
    (1) When a unit is a fluidized bed boiler, is equipped with a wet 
flue gas desulfurization system, or uses other acid gas emission 
controls with sorbent injection, use Equation C-11 of this section to 
calculate the CO2 emissions from the sorbent, if those 
CO2 emissions are not monitored by CEMS:
[GRAPHIC] [TIFF OMITTED] TR30OC09.017

Where:

CO2 = CO2 emitted from sorbent for the 
reporting year (metric tons).
S = Limestone or other sorbent used in the reporting year, from 
company records (short tons).
R = 1.00, the calcium-to-sulfur stoichiometric ratio.
MWCO2 = Molecular weight of carbon dioxide (44).
MWS = Molecular weight of sorbent (100 if calcium 
carbonate).
0.91 = Conversion factor from short tons to metric tons.

    (2) The annual CO2 mass emissions for the unit shall be 
the sum of the CO2 emissions from the combustion process and 
the CO2 emissions from the sorbent.
    (e) CO2 emissions from combustion of biomass. Use the procedures of 
this paragraph (e) to estimate biogenic CO2 emissions from 
units that combust a combination of biomass and fossil fuels. Reporting 
of CO2 emissions from combustion of biomass is required only 
for those biomass fuels listed in Table C-1 of this section, unless 
emissions are measured using CEMS.
    (1) If CEMS are not used to measure CO2, use Equation C-
1 of this subpart to calculate the annual CO2 mass emissions 
from the combustion of biomass (except MSW) for a unit of any size. 
Determine the mass of biomass combusted using one of the following 
procedures in this paragraph (e)(1), as appropriate.
    (i) Use company records.
    (ii) Follow the procedures in paragraph (e)(5) of this section.
    (iii) For premixed fuels that contain biomass and fossil fuels 
(e.g., mixtures containing biodiesel), use best available information 
to determine the mass of biomass fuels and document the procedure used 
in the GHG Monitoring Plan required by Sec.  98.3(g)(5).
    (2) If 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 40 CFR part 75, the 
Tier 4 Calculation Methodology, or the alternative calculation 
methodology specified in paragraph (a)(5)(iii); and if both fossil fuel 
and biomass (except for MSW) are combusted in the unit during the 
reporting year, you may use the following procedure to determine the 
annual biogenic CO2 mass emissions. If MSW is combusted in 
the unit, follow the procedures in paragraph (e)(3) of this section.
    (i) For each operating hour, use Equation C-12 of this section to 
determine the volume of CO2 emitted.
[GRAPHIC] [TIFF OMITTED] TR30OC09.018

Where:

VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly average CO2 
concentration, measured by the CO2 concentration monitor, 
or, if applicable, calculated from the hourly average O2 
concentration (%CO2).
Qh = Hourly average stack gas volumetric flow rate, 
measured by the stack gas volumetric flow rate monitor (scfh).
th = Source operating time (decimal fraction of the hour 
during which the source combusts fuel, i.e., 1.0 for a full 
operating hour, 0.5 for 30 minutes of operation, etc.).
100 = Conversion factor from percent to a decimal fraction.

    (ii) Sum all of the hourly VCO2h values for the 
reporting year, to obtain Vtotal, the total annual volume of 
CO2 emitted.
    (iii) Calculate the annual volume of CO2 emitted from 
fossil fuel combustion using Equation C-13 of this section. If two or 
more types of fossil fuel are combusted during the year, perform a 
separate calculation with Equation C-13 of this section for each fuel 
and sum the results.
[GRAPHIC] [TIFF OMITTED] TR30OC09.019

Where:

Vff = Annual volume of CO2 emitted from 
combustion of a particular fossil fuel (scf).
Fuel = Total quantity of the fossil fuel combusted in the reporting 
year, from company records, as defined in Sec.  98.6 (lb for solid 
fuel, gallons for liquid fuel, and scf for gaseous fuel).
Fc = Fuel-specific carbon based F-factor, either a 
default value from Table 1 in section 3.3.5 of appendix F to 40 CFR 
part 75 or a site-specific value determined under section 3.3.6 of 
appendix F to 40 CFR part 75 (scf CO2/mmBtu).
HHV = High heat value of the fossil fuel, from fuel sampling and 
analysis (annual average value in Btu/lb for solid fuel, Btu/gal for 
liquid fuel and Btu/scf for gaseous fuel, sampled as specified 
(e.g., monthly, quarterly, semi-annually, or by lot) in Sec.  
98.34(a)(2)). The average HHV shall be calculated according to the 
requirements of paragraph (a)(2)(ii) of this section.
10\6\ = Conversion factor, Btu per mmBtu.

    (iv) Subtract Vff from Vtotal to obtain 
Vbio, the annual volume of CO2 from the 
combustion of biomass. If a CEMS is being used to measure the combined 
combustion and process emissions from a unit that is subject to another 
subpart of part 98, then also subtract CO2 process emissions 
from Vtotal to determine Vbio. The CO2 
process emissions must be calculated according to the requirements of 
the applicable subpart.

[[Page 56403]]

    (v) Calculate the biogenic percentage of the annual CO2 
emissions,expressed as a decimal fraction, using Equation C-14 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.020

    (vi) Calculate the annual biogenic CO2 mass emissions, 
in metric tons, by multiplying the results obtained from Equation C-14 
of this section by the annual CO2 mass emissions in metric 
tons, as determined:
    (A) Under paragraph (a)(4)(vi) of this section, for units using the 
Tier 4 Calculation Methodology.
    (B) Under paragraph (a)(5)(iii)(B) of this section, for units using 
the alternative calculation methodology specified in paragraph 
(a)(5)(iii).
    (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 
40 CFR part 75. 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) For a unit that combusts MSW, the annual biogenic 
CO2 emissions shall be calculated using the procedures in 
this paragraph (e)(3).
    (i) If the Tier 1 or Tier 2 Calculation Methodology is used to 
quantify CO2 mass emissions:
    (A) Use Equation C-1 or C-2c of this subpart, as appropriate, to 
calculate the annual CO2 mass emissions from MSW combustion.
    (B) Determine the relative proportions of biogenic and non-biogenic 
CO2 emissions on a quarterly basis using the method 
specified in Sec.  98.34(d).
    (C) Determine the annual biogenic CO2 mass emissions 
from MSW combustion by multiplying the annual CO2 mass 
emissions by the annual average biogenic decimal fraction obtained from 
Sec.  98.34(d).
    (ii) If the unit uses Tier 4 to quantify CO2 emissions:
    (A) Follow the procedures in paragraphs (e)(2)(i) and (ii) of this 
section, to determine Vtotal.
    (B) If any fossil fuel was combusted during the year, follow the 
procedures in paragraph (e)(2)(iii) of this section, to determine 
Vff.
    (C) Subtract Vff from Vtotal, to obtain 
VMSW, the annual volume of CO2 emissions from MSW 
combustion.
    (D) Determine the annual volume of biogenic CO2 
emissions (Vbio) from MSW combustion as follows. Multiply 
the annual volume of CO2 emissions from MSW combustion 
(VMSW) by the annual average biogenic decimal fraction 
obtained from ASTM D6866-08 and ASTM D7459-08.
    (E) Calculate the biogenic percentage of the annual CO2 
emissions from the unit, using Equation C-14 of this section. For the 
purposes of this calculation, the term ``Vbio'' in the 
numerator of Equation C-14 of this section shall be the results of the 
calculation performed under paragraph (e)(3)(ii)(D) of this section.
    (F) Calculate the annual biogenic CO2 mass emissions 
according to paragraph (e)(2)(vi)(A) of this section.
    (4) As an alternative to the procedures in paragraph (e)(2) of this 
section, use ASTM Methods D7459-08 and D6866-08 to determine the 
biogenic portion of the annual CO2 emissions, as described 
in Sec.  98.34(e). If this option is selected, the results of each 
determination shall be expressed as a decimal fraction (e.g., 0.30, if 
30 percent of the CO2 is biogenic), and the values shall be 
averaged over the reporting year. The annual biogenic CO2 
mass emissions shall be calculated by multiplying the the total annual 
CO2 mass emissions by the annual average biogenic fraction 
obtained from ASTM D6866-08 and ASTM D7459-08.
    (5) If Equation C-1 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. Similar equations and 
calculation methodologies based on steam generation and boiler 
efficiency may be used, provided that they are documented in the GHG 
Monitoring Plan required by Sec.  98.3(g)(5).
[GRAPHIC] [TIFF OMITTED] TR30OC09.021

Where:

(Fuel)p = Quantity of biomass consumed during the 
measurement period ``p'' (tons/year or tons/month, as applicable).
H = Average enthalpy of the boiler steam for the measurement period 
(Btu/lb).
S = Total boiler steam production for the measurement period (lb/
month or lb/year, as applicable).
(HI)nb = Heat input from co-fired fossil fuels and non-
biomass-derived fuels for the measurement period, based on company 
records of fuel usage and default or measured HHV values (Btu/month 
or Btu/year, as applicable).
(HHV)bio = Default or measured high heat value of the 
biomass fuel (Btu/lb).
(Eff)bio = Percent efficiency of biomass-to-energy 
conversion, expressed as a decimal fraction.
2000 = Conversion factor (lb/ton).


Sec.  98.34  Monitoring and QA/QC requirements.

    The CO2 mass emissions data for stationary fuel 
combustion sources shall be monitored as follows:
    (a) For the Tier 2 Calculation Methodology:
    (1) All fuel samples shall be taken at a location in the fuel 
handling system that provides a sample representative of the fuel 
combusted. The fuel sampling and analysis may be performed by either 
the owner or operator or the supplier of the fuel.
    (2) The minimum required frequency of the HHV sampling and analysis 
for each type of fuel is specified in this paragraph. When the 
specified frequency is based on a specified time period (i.e., weekly, 
monthly, quarterly, or semiannually), fuel sampling and analysis is 
required only for those periods in which the unit operates.
    (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, analysis of at least one representative 
sample from each fuel lot is required. For the purposes of this 
section, a fuel lot is defined as a shipment or delivery of a single 
fuel (e.g., ship load, barge load, group of trucks, group of railroad 
cars, etc.).
    (iii) For liquid fuels other than fuel oil, for fossil fuel-derived 
gaseous fuels, 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.
    (iv) For solid fuels other than coal and MSW, weekly sampling is 
required to

[[Page 56404]]

obtain composite samples, which are then analyzed monthly.
    (3) If different types of fuel (e.g., different ranks of coal or 
different grades of fuel oil) are blended prior to combustion, use one 
of the following procedures in this paragraph.
    (i) Use a weighted HHV value in the emission calculations, based on 
the relative proportions of each fuel in the blend.
    (ii) Take a representative sample of the blend and analyze it for 
HHV.
    (4) If, for a particular type of fuel, HHV sampling and analysis is 
performed more often than the minimum frequency specified in paragraph 
(a)(2) of this section, the results of all valid fuel analyses shall be 
used in the GHG emission calculations.
    (5) If, for a particular type of fuel, valid HHV values are 
obtained at less than the minimum frequency specifed in paragraph 
(a)(2) of this section, appropriate substitute data values shall be 
used in the emissions calculations, in accordance with missing data 
procedures of Sec.  98.35.
    (6) Use any applicable fuel sampling and analysis methods in this 
paragraph (a)(6) to determine the high heat values. Alternatively, for 
gaseous fuels, the HHV may be calculated using chromatographic analysis 
together with standard heating values of the fuel constituents, 
provided that the gas chromatograph is operated, maintained, and 
calibrated according to the manufacturer's instructions.
    (i) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) 
(incorporated by reference, see Sec.  98.7).
    (ii) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat 
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 
(incorporated by reference, see Sec.  98.7).
    (iii) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter (incorporated by reference, see Sec.  98.7).
    (iv) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels (incorporated by reference, see Sec.  98.7).
    (v) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion (incorporated by reference, see Sec.  98.7).
    (vi) GPA Standard 2172-09 Calculation of Gross Heating Value, 
Relative Density, Compressibility and Theoretical Hydrocarbon Liquid 
Content for Natural Gas Mixtures for Custody Transfer (incorporated by 
reference, see Sec.  98.7).
    (vii) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (viii) ASTM D5865-07a, Standard Test Method for Gross Calorific 
Value of Coal and Coke (incorporated by reference, see Sec.  98.7).
    (b) For the Tier 3 Calculation Methodology:
    (1) Calibrate each oil and gas flow meter according to Sec.  
98.3(i) and the provisions of this paragraph (b).
    (i) Perform calibrations using any of the test methods and 
procedures in this paragraph (b)(1)(i):
    (A) An applicable flow meter test method listed in paragraphs 
(b)(4)(i) through (b)(4)(viii) of this section.
    (B) The calibration procedures specified by the flow meter 
manufacturer.
    (C) An industry-accepted or industry standard calibration practice.
    (ii) In addition to the initial calibration required by Sec.  
98.3(i), recalibrate each fuel flow meter (except for qualifying 
billing meters under paragraph (b)(1)(iii) of this section) either 
annually, at the minimum frequency specified by the manufacturer, or at 
the interval specified by the industry consensus standard practice 
used.
    (iii) Fuel billing meters are exempted from the initial and ongoing 
calibration requirements of this paragraph, 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.
    (iv) For the initial calibration of an orifice, nozzle, or venturi 
meter; in-situ calibration of the transmitters is sufficient. A primary 
element inspection (PEI) shall be performed at least once every three 
years.
    (v) For the continuously-operating units and processes described in 
Sec.  98.3(i)(6), the required flow meter recalibrations and, if 
necessary, the PEIs may be postponed until the next scheduled 
maintenance outage.
    (vi) If a mixture of fuels is transported by a common pipe (e.g., 
still gas and supplementary natural gas), you must either separately 
meter each of the fuels prior to mixing using flow meters calibrated 
according to Sec.  98.3(i), or use flow meters calibrated according to 
Sec.  98.3(i) to measure the mixed fuel at the common pipe and to 
separately meter an appropriate subset of the fuels prior to mixing. If 
the latter option is chosen, quantify the fuels that are not measured 
prior to mixing by subtracting out the fuels measured prior to mixing 
from the fuel measured at the common pipe.
    (2) Oil tank drop measurements (if used to determine liquid fuel 
use volume) shall be performed according to any an appropriate method 
published by a consensus-based standards organization (e.g., the 
American Petroleum Institute).
    (3) The carbon content and, if applicable, molecular weight of the 
fuels shall be determined according to the procedures in this paragraph 
(b)(3).
    (i) All fuel samples shall be taken at a location in the fuel 
handling system that provides a sample representative of the fuel 
combusted. The fuel sampling and analysis may be performed by either 
the owner or operator or by the supplier of the fuel.
    (ii) At a minimum, fuel samples shall be collected at the frequency 
specified in this paragraph. When sampling is required at a specified 
time interval (e.g., weekly, monthly, quarterly, or semiannually), fuel 
sampling and analysis is required for only those specified periods in 
which the unit operates.
    (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, analysis of at least one representative 
sample from each fuel lot is required. For the purposes of this 
section, a fuel lot is defined as a shipment or delivery of a single 
fuel (e.g., ship load, barge load, group of trucks, group of railroad 
cars, etc.).
    (C) For other liquid fuels other than fuel oil, for fossil fuel-
derived gaseous fuels, 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 solid fuels other than coal, 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., 
refinery gas), daily sampling and analysis to determine the carbon 
content and molecular weight of the fuel is required if the necessary 
equipment is in place to make these measurements. Otherwise, weekly 
sampling and analysis shall be performed.
    (iii) If, for a particular type of fuel, sampling and analysis for 
carbon content and molecular weight is performed more often than the

[[Page 56405]]

minimum frequency specified in paragraph (b)(3) of this section, the 
results of all valid fuel analyses shall be used in the GHG emission 
calculations.
    (iv) If, for a particular type of fuel, sampling and analysis for 
carbon content and molecular weight is performed at less than the 
minimum frequency specified in paragraph (b)(3) of this section, 
appropriate substitute data values shall be used in the emissions 
calculations, in accordance with the missing data procedures of Sec.  
98.35.
    (v) The procedures of paragraph (a)(3) of this section apply to 
carbon content and molecular weight determinations.
    (4) Use any applicable standard method from the following list to 
quality assure the data from each fuel flow meter.
    (i) AGA Report No. 3, Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty 
Guidelines (1990) and Part 2: Specification and Installation 
Requirements (2000) (incorporated by reference, see Sec.  98.7).
    (ii) AGA Transmission Measurement Committee Report No. 7, 
Measurement of Gas by Turbine Meters (2006) (incorporated by reference, 
see Sec.  98.7).
    (iii) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (iv) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (v) ASME MFC-5M-1985 (Reaffirmed 1994), Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters 
(incorporated by reference, see Sec.  98.7).
    (vi) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (vii) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow 
by Means of Critical Flow Venturi Nozzles (incorporated by reference, 
see Sec.  98.7).
    (viii) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid 
Flow in Closed Conduits by Weighing Method (incorporated by reference, 
see Sec.  98.7).
    (5) Use any applicable methods from the following list to determine 
the carbon content and molecular weight (for gaseous fuel) of the fuel. 
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.
    (i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (ii) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (iii) ASTM D2502-04 (Reapproved 2002) Standard Test Method for 
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum 
Oils from Viscosity Measurements (incorporated by reference, see Sec.  
98.7).
    (iv) ASTM D2503-92 (Reapproved 2007) Standard Test Method for 
Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure (incorporated by 
reference, see Sec.  98.7).
    (v) 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 (incorporated by reference, see 
Sec.  98.7).
    (vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec.  
98.7).
    (vii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7).
    (c) For the Tier 4 Calculation Methodology, the CO2 and 
flow rate monitors must be certified prior to the applicable deadline 
specified in Sec.  98.33(b)(5).
    (1) For initial certification, you may use any one of the following 
three procedures in this paragraph.
    (i) Sec.  75.20(c)(2) and (4) and appendix A to 40 CFR part 75.
    (ii) The calibration drift test and relative accuracy test audit 
(RATA) procedures of Performance Specification 3 in appendix B to part 
60 (for the CO2 concentration monitor) and Performance 
Specification 6 in appendix B to part 60 (for the continuous emission 
rate monitoring system (CERMS)).
    (iii) The provisions of an applicable State continuous monitoring 
program.
    (2) If an O2 concentration monitor is used to determine 
CO2 concentrations, the applicable provisions of 40 CFR part 
75, 40 CFR part 60, 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 40 CFR part 75, appendix F to 40 CFR part 60, 
or an applicable State continuous monitoring program. If appendix F to 
40 CFR part 60 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 40 CFR part 75 and the 
annual RATAs of the CERMS required by appendix F to 40 CFR part 60 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.
    (5) If, for any source operating hour, quality assured data are not 
obtained with a CO2 monitor (or surrogate O2 
monitor), flow rate monitor, or (if applicable) moisture monitor, use 
appropriate substitute data values in accordance with the missing data 
provisions of Sec.  98.35.
    (d) When municipal solid waste (MSW) is combusted in a unit, 
determine the biogenic portion of the CO2 emissions from MSW 
combustion 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 while MSW is the only fuel being combusted 
for at least 24 consecutive hours or for as long as is necessary to 
obtain a sample large enough to meet the specifications of ASTM D6866-
08. Separate CO2 emissions into the biogenic and non-
biogenic fraction 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 
from MSW combustion is biogenic). If there is a

[[Page 56406]]

common fuel source of MSW that feeds multiple units at the facility, 
performing the testing at only one of the units is sufficient.
    (e) For units that use CEMS to measure the total CO2 
mass emissions and combust a combination of biogenic fuels (other than 
MSW) with a fossil fuel, ASTM D6866-08 and ASTM D7459-08 may be used to 
determine the biogenic portion of the CO2 emissions. Perform 
the ASTM D7459-08 sampling and the ASTM D6866-08 analysis at least once 
in every calendar quarter in which biogenic and non-biogenic fuels are 
co-fired in the unit. The relative proportions of the biogenic and non-
biogenic fuels during the sampling shall be representative of the 
average fuel blend for a typical operating year. Collect each gas 
sample using ASTM D7459-08 during normal unit operation for at least 24 
consecutive hours or for as long as is necessary to obtain a sample 
large enough to meet the specifications of ASTM D6866-08.
    (f) Whenever company records are used in the calculation of 
CO2 emissions, the records required under Sec.  98.3(g) 
shall include both the company records and an explanation of how those 
records are used to estimate the following parameters:
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation 
Methodologies are used.
    (2) Fuel consumption, when solid fuel is combusted and the Tier 3 
Calculation Methodology is used.
    (3) Fossil fuel consumption when Sec.  98.33(e) applies to a unit 
that uses CEMS to quantify CO2 emissions and that combusts 
both fossil and biomass fuels.
    (4) Sorbent usage, when Sec.  98.33(d) applies.
    (5) Quantity of steam generated by a unit when Sec.  98.33(a)(2) 
applies.
    (6) Biogenic fuel consumption under Sec.  98.33(e)(5).
    (g) As part of the GHG Monitoring Plan required under Sec.  
98.3(g)(5), you must document the procedures used to ensure the 
accuracy of the estimates of fuel usage, sorbent usage, steam 
production, and boiler efficiency (as applicable) in paragraph (f) of 
this section, including but not limited to calibration of weighing 
equipment, fuel flow meters, steam flow meters, and other measurement 
devices. The estimated accuracy of measurements made with these devices 
shall also be recorded, and the technical basis for these estimates 
shall be provided.


Sec.  98.35  Procedures for estimating missing data.

    Whenever a quality-assured value of a required parameter is 
unavailable (e.g., if a CEMS malfunctions during unit operation or if a 
required fuel sample is not taken), a substitute data value for the 
missing parameter shall be used in the calculations.
    (a) For all units subject to the requirements of the Acid Rain 
Program, and all other stationary combustion units subject to the 
requirements of this part that monitor and report emissions and heat 
input data in accordance with 40 CFR part 75, the missing data 
substitution procedures in 40 CFR part 75 shall be followed for 
CO2 concentration, stack gas flow rate, fuel flow rate, high 
heating value, and fuel carbon content.
    (b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 
Calculation Methodologies, perform missing data substitution as follows 
for each parameter:
    (1) For each missing value of the high heating value, carbon 
content, or molecular weight of the fuel, substitute the arithmetic 
average of the quality-assured values of that parameter immediately 
preceding and immediately following the missing data incident. If the 
``after'' value has not been obtained by the time that the GHG 
emissions report is due, you may use the ``before'' value for missing 
data substitution or the best available estimate of the parameter, 
based on all available process data (e.g., electrical load, steam 
production, operating hours). If, for a particular parameter, no 
quality-assured data are available prior to the missing data incident, 
the substitute data value shall be the first quality-assured value 
obtained after the missing data period.
    (2) For missing records of CO2 concentration, stack gas 
flow rate, percent moisture, fuel usage, and sorbent usage, the 
substitute data value shall be the best available estimate of the 
parameter, based on all available process data (e.g., electrical load, 
steam production, operating hours, etc.). You must document and retain 
records of the procedures used for all such estimates.


Sec.  98.36  Data reporting requirements.

    (a) In addition to the facility-level information required under 
Sec.  98.3, the annual GHG emissions report shall contain the unit-
level or process-level emissions data in paragraphs (b) through (d) of 
this section (as applicable) and the emissions verification data in 
paragraph (e) of this section.
    (b) Units that use the four tiers. You shall report the following 
information for stationary combustion units that use the Tier 1, Tier 
2, Tier 3, or Tier 4 methodology in Sec.  98.33(a) to calculate 
CO2 emissions, except as otherwise provided in paragraphs 
(c) and (d) of this section:
    (1) The unit ID number.
    (2) A code representing the type of unit.
    (3) Maximum rated heat input capacity of the unit, in mmBtu/hr for 
boilers and process heaters only and relevant units of measure for 
other combustion sources.
    (4) Each type of fuel combusted in the unit during the report year.
    (5) The tier used to calculate the CO2 emissions for 
each type of fuel combusted (i.e., Tier 1, 2, 3, or 4).
    (6) For a unit that uses Tiers 1, 2, and 3; the CO2, 
CH4, and N2O emissions for each type of fuel 
combusted, expressed in metric tons of each gas and in metric tons of 
CO2e.
    (7) For a unit that uses Tier 4:
    (i) For units that burn fossil fuels only, the annual 
CO2 emissions for all fuels combined. Reporting 
CO2 emissions by type of fuel is not required.
    (ii) For units that burn both fossil fuels and biomass, the annual 
CO2 emissions from combustion of all fossil fuels combined 
and the annual CO2 emissions from combustion of all biomass 
fuels combined. Reporting CO2 emissions by type of fuel is 
not required.
    (iii) Annual CH4 and N2O emissions for each 
type of fuel combusted expressed in metric tons of each gas and in 
metric tons of CO2e.
    (8) Annual CO2 emissions from sorbent (if calculated 
using Equation C-11 of this subpart), expressed in metric tons.
    (9) Annual GHG emissions from all fossil fuels burned in the unit 
(i.e., the sum of the CO2, CH4, and 
N2O emissions), expressed in metric tons of CO2e.
    (10) Customer meter number for units that combust natural gas.
    (c) Reporting alternatives for units using the four Tiers. You may 
use any of the applicable reporting alternatives of this paragraph to 
simplify the unit-level reporting required under paragraph (b) of this 
section:
    (1) Aggregation of units. If a facility contains two or more units 
(e.g., boilers or combustion turbines), each of which has a maximum 
rated heat input capacity of 250 mmBtu/hr or less, you may report the 
combined GHG emissions for the group of units in lieu of reporting GHG 
emissions from the individual units, provided that the use of Tier 4 is 
not required or elected for

[[Page 56407]]

any of the units and the units use the same tier for any common fuels 
combusted. If this option is selected, the following information shall 
be reported instead of the information in paragraph (b) of this 
section:
    (i) Group ID number, beginning with the prefix ``GP''.
    (ii) An identification number for each unit in the group.
    (iii) Cumulative maximum rated heat input capacity of the group 
(mmBtu/hr).
    (iv) The highest maximum rated heat input capacity of any unit in 
the group (mmBtu/hr).
    (v) Each type of fuel combusted in the group of units during the 
reporting year.
    (vi) Annual CO2, CH4, and N2O mass 
emissions aggregated for each type of fuel combusted in the group of 
units during the year, expressed in metric tons of each gas and in 
metric tons of CO2e. 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 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 calculated CO2 mass emissions (if any) from 
sorbent.
    (ix) Annual GHG emissions from all fossil fuels burned in the group 
(i.e., the sum of the CO2, CH4, and 
N2O emissions), expressed in metric tons of CO2e.
    (2) Monitored common stack or duct configurations. When the flue 
gases from two or more stationary combustion units at a facility are 
discharged through 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. The following information 
shall be reported instead of the information in paragraph (b) of this 
section:
    (i) Common stack or duct identification number, beginning with the 
prefix ``CS''.
    (ii) Identification numbers of the units sharing the common stack 
or duct.
    (iii) Maximum rated heat input capacity of each unit sharing the 
common stack or duct (mmBtu/hr).
    (iv) Each type of fuel combusted in the units during the year.
    (v) The methodology used to calculate the CO2 mass 
emissions, i.e., Tier 4.
    (vi) If the any of the units burn both fossil fuels and biomass, 
annual CO2 mass emissions, annual CO2 emissions 
from combustion of fossil fuels, and annual CO2 emissions 
from combustion of biomass measured at the common stack or duct, 
expressed in metric tons.
    (vii) The annual CH4 and N2O emissions from 
the units sharing the common stack or duct, expressed in metric tons of 
each gas and in metric tons of CO2e.
    (viii) Annual GHG emissions from all fossil fuels burned in the 
group (i.e., the sum of the CO2, CH4, and 
N2O emissions), expressed in metric tons of CO2e.
    (3) Common pipe configurations. When two or more liquid-fired or 
gaseous-fired stationary combustion units at a facility combust the 
same type of fuel and the fuel is fed to the individual units through a 
common supply line or pipe, you may report the combined emissions from 
the units served by the common supply line, in lieu of separately 
reporting the GHG emissions from the individual units, provided that 
the total amount of fuel combusted by the units is accurately measured 
at the common pipe or supply line using a fuel flow meter that is 
calibrated in accordance with Sec.  98.34(a). If a portion of the fuel 
measured at the common pipe is diverted to a chemical or industrial 
process where it is used but not combusted, you may subtract the 
diverted fuel from the fuel measured at the common pipe prior to 
performing the GHG emissions calculations, provided that the amount of 
fuel diverted is also measured with a calibrated flow meter per Sec.  
98.3(i). If 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. The following 
information shall be reported instead of the information in paragraph 
(b) of this section:
    (i) Common pipe identification number, beginning with the prefix 
``CP''.
    (ii) The identification numbers of the units served by the common 
pipe.
    (iii) Maximum rated heat input capacity of each unit served by the 
common pipe (mmBtu/hr).
    (iv) The fuels combusted in the units during the reporting year.
    (v) The methodology used to calculate the CO2 mass 
emissions (i.e., Tier 1, Tier 2, or Tier 3).
    (vi) If the any of the units burns both fossil fuels and biomass, 
the annual CO2 mass emissions from combustion of all fossil 
fuels and annual CO2 emissions from combustion of all 
biomass fuels from the units served by the common pipe, expressed in 
metric tons.
    (vii) Annual CH4 and N2O emissions from the 
units served by the common pipe, expressed in metric tons of each gas 
and in metric tons of CO2e.
    (viii) Annual GHG emissions from all fossil fuels burned in units 
served by the common pipe (i.e., the sum of the CO2, 
CH4, and N2O emissions), expressed in metric tons 
of CO2e.
    (d) Units subject to 40 CFR part 75.
    (1) For stationary combustion units that are either subject to the 
Acid Rain Program or not in the Acid Rain Program but monitor and 
report CO2 mass emissions year-round according to 40 CFR 
part 75, you shall report the following unit-level information:
    (i) Unit or stack identification numbers. Use exact same unit, 
common stack, or multiple stack identification numbers that represent 
the monitored locations (e.g., 1, 2, CS001, MS1A, etc.) that are 
reported under Sec.  75.64 of this chapter.
    (ii) Annual CO2, CH4, and N2O 
emissions at each monitored location, expressed in metric tons of 
CO2e.
    (iii) Identification of the Part 75 methodology used to determine 
the CO2 mass emissions.
    (2) For units that use the alternative CO2 mass 
emissions calculation methods for units with continuous monitoring 
systems 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, or multiple stack identification numbers that represent the 
monitored locations (e.g., 1, 2, CS001, MS1A, 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 40 CFR part 75 or 40 CFR 75.19:
    (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) A code or flag to indicate whether heat input is calculated 
according to appendix D to 40 CFR part 75 or 40 CFR 75.19.
    (D) Annual CO2, CH4, and N2O 
emissions at each monitored location, across all fuel types, expressed 
in metric tons of CO2e.
    (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 40 
CFR part 75:
    (A) Fuel combusted during the reporting year.

[[Page 56408]]

    (B) Methodology used to calculate the CO2 mass 
emissions.
    (C) A code or flag to indicate that the heat input data is derived 
from CEMS measurements.
    (D) The total annual CO2, CH4, and 
N2O emissions at each monitored location, expressed in 
metric tons of CO2e.
    (e) Verification data. You must keep on file, in a format suitable 
for inspection and auditing, sufficient data to verify the reported GHG 
emissions. This data and information must, where indicated in this 
paragraph (e), be included in the annual GHG emissions report.
    (1) The applicable verification data specified in this paragraph 
(e) are not required to be kept on file or reported for units that meet 
any one of the three following conditions:
    (i) Are subject to the Acid Rain Program.
    (ii) Use the alternative methods for units with continuous 
monitoring systems provided in Sec.  98.33(a)(5).
    (iii) Are not in the Acid Rain Program, but are required monitor 
and report CO2 mass emissions and heat input data year-
round, in accordance with 40 CFR part 75.
    (2) For stationary combustion sources using the Tier 1, Tier 2, 
Tier 3, and Tier 4 Calculation Methodologies in Sec.  98.33(a) to 
quantify CO2 emissions, the following additional information 
shall be kept on file and included in the GHG emissions report, where 
indicated:
    (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.
    (ii) For the Tier 2 Calculation Methodology, report:
    (A) The total quantity of each type of fuel combusted in the unit 
or group of aggregated units (as applicable) during each month of the 
reporting year. Express the quantity of each fuel combusted during the 
measurement period in short tons for solid fuels, gallons for liquid 
fuels, and scf for gaseous fuels.
    (B) The frequency of the HHV determinations (e.g., once a month, 
once per fuel lot).
    (C) The high heat values used in the CO2 emissions 
calculations for each type of fuel combusted, in mmBtu per short ton 
for solid fuels, mmBtu per gallon for liquid fuels, and mmBtu per scf 
for gaseous fuels. Specify the date on which each fuel sample was 
taken. Indicate whether each HHV is a measured value of 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 the 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.
    (iv) For the Tier 3 Calculation Methodology, report:
    (A) The quantity of each type of fuel combusted in the unit or 
group of units (as applicable) during the year, in short tons for solid 
fuels, gallons for liquid fuels, and scf for gaseous fuels.
    (B) The frequency of carbon content and, if applicable, molecular 
weight determinations for each type of fuel for the reporting year 
(e.g., daily, weekly, monthly, semiannually, once per fuel lot).
    (C) The carbon content and, if applicable, gas molecular weight 
values used in the emission calculations (including both valid and 
substitute data values). Report all measured values if the fuel is 
sampled monthly or less frequently. Otherwise, for daily and weekly 
sampling, report monthly average values determined using the 
calculation procedures in Equation C-2b for each variable. 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.
    (D) The total number of valid carbon content determinations and, if 
applicable, molecular weight determinations made during the reporting 
year, for each fuel type.
    (E) The number of substitute data values used for carbon content 
and, if applicable, molecular weight used in the annual GHG emissions 
calculations.
    (v) For the Tier 3 Calculation Methodology, keep records of the 
following:
    (A) For liquid and gaseous fuel combustion, the dates and results 
of the initial calibrations and periodic recalibrations of the required 
fuel flow meters.
    (B) For fuel oil combustion, the method from Sec.  98.34(b) used to 
make tank drop measurements (if applicable).
    (C) The methods used to determine the carbon content for each type 
of fuel combusted.
    (D) The methods used to calibrate the fuel flow meters).
    (vi) For the Tier 4 Calculation Methodology, report:
    (A) The total number of source operating hours in the reporting 
year.
    (B) The cumulative CO2 mass emissions in each quarter of 
the reporting year, i.e., the sum of the hourly values calculated from 
Equation C-6 or C-7 of this subpart (as applicable), in metric tons.
    (C) For CO2 concentration, stack gas flow rate, and (if 
applicable) stack gas moisture content, the percentage of source 
operating hours in which a substitute data value of each parameter was 
used in the emissions calculations.
    (vii) For the Tier 4 Calculation Methodology, keep records of:
    (A) Whether the CEMS certification and quality assurance procedures 
of 40 CFR part 75, 40 CFR part 60, or an applicable State continuous 
monitoring program were used.
    (B) The dates and results of the initial certification tests of the 
CEMS.
    (C) The dates and results of the major quality assurance tests 
performed on the CEMS during the reporting year, i.e., linearity 
checks, cylinder gas audits, and relative accuracy test audits (RATAs).
    (viii) If CO2 emissions that are generated from acid gas 
scrubbing with sorbent injection are not captured using CEMS, report:
    (A) The total amount of sorbent used during the report year, in 
short tons.
    (B) The molecular weight of the sorbent.
    (C) The ratio (``R'') in Equation C-11 of this subpart.
    (ix) For units that combust both fossil fuel and biomass, when CEMS 
are used to quantify the annual CO2 emissions and biogenic 
CO2 is determined according to Sec.  98.33(e)(2), you shall 
report the following additional information, as applicable:
    (A) The annual volume of CO2 emitted from the combustion 
of all fuels, i.e., Vtotal, in scf.
    (B) The annual volume of CO2 emitted from the combustion 
of fossil fuels, i.e., Vff, in scf. If more than one type of 
fossil fuel was combusted, report the combustion volume of 
CO2 for each fuel separately as well as the total.
    (C) The annual volume of CO2 emitted from the combustion 
of biomass, i.e., Vbio, in scf.
    (D) The carbon-based F-factor used in Equation C-13 of this 
subpart, for each type of fossil fuel combusted, in scf CO2 
per mmBtu.
    (E) The annual average HHV value used in Equation C-13 of this 
subpart, for each type of fossil fuel combusted,

[[Page 56409]]

in Btu/lb, Btu/gal, or Btu/scf, as appropriate.
    (F) The total quantity of each type of fossil fuel combusted during 
the reporting year, in lb, gallons, or scf, as appropriate.
    (G) Annual biogenic CO2 mass emissions, in metric tons.
    (x) When ASTM methods D7459-08 and D6866-08 are used to determine 
the biogenic portion of the annual CO2 emissions from MSW 
combustion, report:
    (A) The results of each quarterly sample analysis, expressed as a 
decimal fraction (e.g., if the biogenic fraction of the CO2 
emissions from MSW combustion is 30 percent, report 0.30).
    (B) Annual combined biomass and fossil fuel CO2 
emissions from MSW combustion, in metric tons of CO2e.
    (C) The quantities Vff, Vtotal, and 
VMSW from Sec.  98.33(e)(4)(ii), if CEMS are used to measure 
CO2 emissions.
    (D) The annual volume of biogenic CO2 emissions from MSW 
combustion, in metric tons.
    (xi) When ASTM methods D7459-08 and D6866-08 are used to determine 
the biogenic portion of the annual CO2 emissions from a unit 
that co-fires biogenic (other than MSW) 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).
    (3) Within 30 days of receipt of a written request from the 
Administrator, you shall submit explanations of the following:
    (i) An explanation of how company records are used to quantify fuel 
consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to 
calculate CO2 emissions.
    (ii) An explanation of how company records are used to quantify 
fuel consumption, if solid fuel is combusted and the Tier 3 Calculation 
Methodology is used to calculate CO2 emissions.
    (iii) An explanation of how sorbent usage is quantified.
    (iv) An explanation of how company records are used to quantify 
fossil fuel consumption in units that uses CEMS to quantify 
CO2 emissions and combusts both fossil fuel and biomass.
    (v) An explanation of how company records are used to measure steam 
production, when it is used to calculate CO2 mass emissions 
under Sec.  98.33(a)(2)(iii) or to quantify solid fuel usage under 
Sec.  98.33(c)(3).
    (4) Within 30 days of receipt of a written request from the 
Administrator, you shall submit the verification data and information 
described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this 
section.


Sec.  98.37  Records that must be retained.

    In addition to the requirements of Sec.  98.3(g), you must retain 
the applicable records specified in Sec. Sec.  98.34(f) and (g), 
98.35(b), and 98.36(e).


Sec.  98.38  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Table C-1 to Subpart C of Part 98--Default CO2 Emission Factors and High
                  Heat Values for Various Types of Fuel
------------------------------------------------------------------------
                                  Default high heat       Default CO2
           Fuel type                    value           emission factor
------------------------------------------------------------------------
         Coal and coke             mmBtu/short ton        kg CO2/mmBtu
------------------------------------------------------------------------
Anthracite....................  25.09                             103.54
Bituminous....................  24.93                              93.40
Subbituminous.................  17.25                              97.02
Lignite.......................  14.21                              96.36
Coke..........................  24.80                             102.04
Mixed (Commercial sector).....  21.39                              95.26
Mixed (Industrial coking).....  26.28                              93.65
Mixed (Industrial sector).....  22.35                              93.91
Mixed (Electric Power sector).  19.73                              94.38
------------------------------------------------------------------------
          Natural gas                 mmBtu/scf           kg CO2/mmBtu
------------------------------------------------------------------------
Pipeline (Weighted U.S.         1.028 x 10-3                       53.02
 Average).
------------------------------------------------------------------------
      Petroleum products             mmBtu/gallon         kg CO2/mmBtu
------------------------------------------------------------------------
Distillate Fuel Oil No. 1.....  0.139                              73.25
Distillate Fuel Oil No. 2.....  0.138                              73.96
Distillate Fuel Oil No. 4.....  0.146                              75.04
Residual Fuel Oil No. 5.......  0.140                              72.93
Residual Fuel Oil No. 6.......  0.150                              75.10
Still Gas.....................  0.143                              66.72
Kerosene......................  0.135                              75.20
Liquefied petroleum gases       0.092                              62.98
 (LPG).
Propane.......................  0.091                              61.46
Propylene.....................  0.091                              65.95
Ethane........................  0.096                              62.64
Ethylene......................  0.100                              67.43
Isobutane.....................  0.097                              64.91
Isobutylene...................  0.103                              67.74
Butane........................  0.101                              65.15
Butylene......................  0.103                              67.73
Naphtha (<401 deg F)..........  0.125                              68.02
Natural Gasoline..............  0.110                              66.83
Other Oil (>401 deg F)........  0.139                              76.22
Pentanes Plus.................  0.110                              70.02
Petrochemical Feedstocks......  0.129                              70.97

[[Page 56410]]

 
Petroleum Coke................  0.143                             102.41
Special Naphtha...............  0.125                              72.34
Unfinished Oils...............  0.139                              74.49
Heavy Gas Oils................  0.148                              74.92
Lubricants....................  0.144                              74.27
Motor Gasoline................  0.125                              70.22
Aviation Gasoline.............  0.120                              69.25
Kerosene-Type Jet Fuel........  0.135                              72.22
Asphalt and Road Oil..........  0.158                              75.36
Crude Oil.....................  0.138                              74.49
------------------------------------------------------------------------
   Fossil fuel-derived fuels       mmBtu/short ton        kg CO2/mmBtu
            (solid)
------------------------------------------------------------------------
Municipal Solid Waste \1\.....  9.95                                90.7
Tires.........................  26.87                              85.97
------------------------------------------------------------------------
   Fossil fuel-derived fuels          mmBtu/scf           kg CO2/mmBtu
           (gaseous)
------------------------------------------------------------------------
Blast Furnace Gas.............  0.092 x 10-3                      274.32
Coke Oven Gas.................  0.599 x 10-3                       46.85
------------------------------------------------------------------------
     Biomass fuels--solid          mmBtu/short ton        kg CO2/mmBtu
------------------------------------------------------------------------
Wood and Wood Residuals.......  15.38                              93.80
Agricultural Byproducts.......  8.25                              118.17
Peat..........................  8.00                              111.84
Solid Byproducts..............  25.83                             105.51
------------------------------------------------------------------------
    Biomass fuels--gaseous            mmBtu/scf           kg CO2/mmBtu
------------------------------------------------------------------------
Biogas (Captured methane).....  0.841 x 10-3                       52.07
------------------------------------------------------------------------
Biomass Fuels--Liquid.........       mmBtu/gallon         kg CO2/mmBtu
------------------------------------------------------------------------
Ethanol (100%)................  0.084                              68.44
Biodiesel (100%)..............  0.128                              73.84
Rendered Animal Fat...........  0.125                              71.06
Vegetable Oil.................  0.120                              81.55
------------------------------------------------------------------------
\1\ Allowed only for units that do not generate steam and use Tier 1.


 Table C-2 to Subpart C of Part 98--Default CH4 and N2O Emission Factors
                        for Various Types of Fuel
------------------------------------------------------------------------
                              Default CH4 emission  Default N2O emission
          Fuel type              factor (kg CH4/       factor (kg N2O/
                                     mmBtu)                mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-2            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
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 CH4/MMBtu.
\1\ Allowed only for units that do not generate steam and use Tier 1.


Table C-2 to Subpart C--Default CH4 and N2O Emission Factors for Various
                              Types of Fuel
------------------------------------------------------------------------
                              Default CH4 emission  Default N2O emission
          Fuel type              factor (kg CH4/       factor (kg N2O/
                                     mmBtu)                mmBtu)
------------------------------------------------------------------------
Coal and Coke (All fuel       1.1 x 10-2            1.6 x 10-03
 types in Table C-1).
Natural Gas.................  1.0 x 10-03           1.0 x 10-04

[[Page 56411]]

 
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
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 1 g
  of CH4/MMBtu.

Subpart D--Electricity Generation


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 emissions 
year-round according to 40 CFR part 75.
    (b) This source category does not include portable equipment, 
emergency equipment, or emergency generators, as defined in Sec.  98.6.


Sec.  98.41  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains one or more electricity generating units and the facility 
meets the requirements of Sec.  98.2(a)(1).


Sec.  98.42  GHGs to report.

    (a) For each electricity generating unit that is subject to the 
requirements of the Acid Rain Program or is otherwise required to 
monitor and report to EPA CO2 emissions year-round according 
to 40 CFR part 75, you must report under this subpart the annual mass 
emissions of CO2, N2O, and CH4 by 
following the requirements of this subpart.
    (b) For each electricity generating unit that is not subject to the 
Acid Rain Program or otherwise required to monitor and report to EPA 
CO2 emissions year-round according to 40 CFR part 75, you 
must report under subpart C of this part (General Stationary Fuel 
Combustion Sources) the emissions of CO2, CH4, 
and N2O by following the requirements of subpart C.
    (c) For each stationary fuel combustion unit that does not generate 
electricity, you must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O by following the requirements of 
subpart C of this part.


Sec.  98.43  Calculating GHG emissions.

    Continue to monitor and report CO2 mass emissions as 
required under Sec.  75.13 or section 2.3 of apppendix G to 40 CFR part 
75, and Sec.  75.64. Calculate CO2, CH4, and 
N2O emissions as follows:
    (a) 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.
    (b) Calculate and report annual CH4 and N2O 
mass emissions under this subpart by following the applicable method 
specified in Sec.  98.33(c).


Sec.  98.44  Monitoring and QA/QC requirements.

    Follow the applicable quality assurance procedures for 
CO2 emissions in appendices B, D, and G to 40 CFR part 75.


Sec.  98.45  Procedures for estimating missing data.

    Follow the applicable missing data substitution procedures in 40 
CFR part 75 for CO2 concentration, stack gas flow rate, fuel 
flow rate, high heating value, and fuel carbon content.


Sec.  98.46  Data reporting requirements.

    The annual report shall comply with the data reporting requirements 
specified in Sec.  98.36(b) and, if applicable, Sec.  98.36(c)(2) or 
(c)(3).


Sec.  98.47  Records that must be retained.

    You shall comply with the recordkeeping requirements of Sec. Sec.  
98.3(g) and 98.37.


Sec.  98.48  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart E--Adipic Acid Production


Sec.  98.50  Definition of source category.

    The adipic acid production source category consists of all adipic 
acid production facilities that use oxidation to produce adipic acid.


Sec.  98.51  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an adipic acid production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.52  GHGs to report.

    (a) You must report N2O process emissions at the 
facility level.
    (b) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.


Sec.  98.53  Calculating GHG emissions.

    (a) You must determine annual N2O emissions from adipic 
acid production according to paragraphs (a)(1) or (a)(2) of this 
section.
    (1) Use a site-specific emission factor and production data 
according to paragraphs (b) through (h) of this section.
    (2) Request Administrator approval for an alternative method of 
determining N2O emissions according to paragraphs (a)(2)(i) 
and (a)(2)(ii) of this section.
    (i) You must submit the request within 45 days following 
promulgation of this subpart or within the first 30 days of each 
subsequent reporting year.
    (ii) If the Administrator does not approve your requested 
alternative method within 150 days of the end of the reporting year, 
you must determine the N2O emissions factor for the current 
reporting period using the procedures specified in paragraphs (b) 
through (h) of this section.
    (b) You must conduct an annual performance test according to

[[Page 56412]]

paragraphs (b)(1) through (b)(3) of this section.
    (1) You must conduct the test on the waste gas stream from the 
nitric acid oxidation step of the process using the methods specified 
in Sec.  98.54(b) through (d).
    (2) You must conduct the performance test under normal process 
operating conditions and without using N2O abatement 
technology.
    (3) You must measure the adipic acid production rate during the 
test and calculate the production rate for the test period in metric 
tons per hour.
    (c) You must determine an N2O emissions factor to use in 
Equation E-2 of this section according to paragraphs (c)(1) or (c)(2) 
of this section.
    (1) You may request Administrator approval for an alternative 
method of determining N2O concentration according to the 
procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section. 
Alternative methods include the use of N2O CEMs.
    (2) Using the results of the performance test in paragraph (b) of 
this section, you must calculate a facility-specific emissions factor 
according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.022

Where:

EFN2O = Average facility-specific N2O 
emissions factor (lb N2O generated/ton adipic acid 
produced).
CN2O = N2O concentration per text run during 
the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm 
N2O).
Q = Volumetric flow rate of effluent gas per test run during the 
performance test (dscf/hr).
P = Production rate per test run during the performance test (tons 
adipic acid produced/hr).
n = Number of test runs.

    (d) If applicable, you must determine the destruction efficiency 
for each N2O abatement technology used at your facility 
according to paragraphs (d)(1), (d)(2), or (d)(3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an 
additional performance test on the emissions stream following the 
N2O abatement technology.
    (e) If applicable, you must determine the abatement factor for each 
N2O abatement technology used at your facility. The 
abatement factor is calculated for each adipic acid facility according 
to Equation E-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.023

Where:

AFN = Abatement factor of N2O abatement 
technology (fraction of annual production that abatement technology 
is operating).
Pa Abate = Annual adipic acid production during which 
N2O abatement was used.
Pa = Total annual adipic acid production (ton acid 
produced).

    (f) You must determine the annual amount of adipic acid produced 
and the annual adipic acid production during which N2O 
abatement is operating.
    (g) You must calculate annual adipic acid production process 
emissions of N2O by multiplying the emissions factor 
(determined using Equation E-1 of this section) by the total annual 
adipic acid production and accounting for N2O abatement, 
according to Equation E-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.024

Where:

N2O = Annual N2O mass emissions from adipic 
acid production (metric tons).
EFN2O = Facility-specific N2O emissions factor 
(lb N2O generated/ton adipic acid produced).
Pa = Annual adipic acid produced (tons).
DFN = Destruction efficiency of N2O abatement 
technology N (abatement device destruction efficiency, percent of 
N2O removed from air stream).
AFN = Abatement factor of N2O abatement 
technology N (fraction of annual production abatement technology is 
operating).
2205 = Conversion factor (lb/metric ton).
N = Number of different N2O abatement technologies.

    (h) You must determine the amount of process N2O 
emissions that is sold or transferred off site (if applicable). You can 
determine the amount using existing process flow meters and 
N2O analyzers.


Sec.  98.54  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new 
facility-specific emissions factor according to the frequency specified 
in paragraphs (a)(1) through (a)(3) of this section.
    (1) Conduct the performance test annually.
    (2) Conduct the performance test when your adipic acid production 
process is changed either by altering the ratio of cyclohexanone to 
cyclohexanol or by installing abatement equipment.
    (3) If you requested Administrator approval for an alternative 
method of determining N2O concentration under Sec.  
98.53(a)(2), you must conduct the performance test if your request has 
not been approved by the Administrator within 150 days of the end of 
the reporting year in which it was submitted.
    (b) You must measure the N2O concentration during the 
performance test using one of the methods in paragraphs (b)(1) through 
(b)(3) of this section.
    (1) EPA Method 320, Measurement of Vapor Phase Organic and 
Inorganic Emissions by Extractive Fourier

[[Page 56413]]

Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A;
    (2) 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
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the production rate(s) during the 
performance test according to paragraph (c)(1) or (c)(2) of this 
section.
    (1) Direct measurement (such as using flow meters or weigh scales).
    (2) Existing plant procedures used for accounting purposes.
    (d) You must conduct all required performance tests according to 
the methods in Sec.  98.54(b) in conjunction with the applicable EPA 
methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three 
emissions test runs of 1 hour each. All QA/QC procedures specified in 
the reference test methods and any associated performance 
specifications apply. For each test, the facility must prepare an 
emissions factor determination report that must include the items in 
paragraphs (d)(1) through (d)(3) of this section:
    (1) Analysis of samples, determination of emissions, and raw data.
    (2) All information and data used to derive the emissions factor.
    (3) The production rate(s) during the performance test and how each 
production rate was determined.
    (e) You must determine the monthly adipic acid production quantity 
and the monthly adipic acid production during which N2O 
abatement technology is operating according to the methods in 
paragraphs (c)(1) or (c)(2) of this section.
    (f) You must determine the annual adipic acid production quantity 
and the annual adipic production quantity during which N2O 
abatement technology is operating by summing the respective monthly 
adipic acid production quantities.


Sec.  98.55  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of monthly adipic acid production, the 
substitute data shall be the best available estimate based on all 
available process data or data used for accounting purposes (such as 
sales records).
    (b) For missing values related to the performance test, including 
emission factors, production rate, and N2O concentration, 
you must conduct a new performance test according to the procedures in 
Sec.  98.54 (a) through (d).


Sec.  98.56  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (k) of this section at the facility level:
    (a) Annual process N2O emissions from adipic acid 
production (metric tons).
    (b) Annual adipic acid production (tons).
    (c) Annual adipic acid production during which N2O 
abatement technology is operating (tons).
    (d) Annual process N2O emissions from adipic acid 
production facility that is sold or transferred off site (metric tons).
    (e) Number of abatement technologies (if applicable).
    (f) Types of abatement technologies used (if applicable).
    (g) Abatement technology destruction efficiency for each abatement 
technology (percent destruction).
    (h) Abatement utilization factor for each abatement technology 
(fraction of annual production that abatement technology is operating).
    (i) Number of times in the reporting year that missing data 
procedures were followed to measure adipic acid production (months).
    (j) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.53(a)(1), each annual 
report must also contain the information specified in paragraphs (j)(1) 
through (j)(7) of this section for each adipic acid production 
facility.
    (1) Emissions factor (lb N2O/ton adipic acid).
    (2) Test method used for performance test.
    (3) Production rate per test run during performance test (tons/hr).
    (4) N2O concentration per test run during performance 
test (ppm N2O).
    (5) Volumetric flow rate per test run during performance test 
(dscf/hr).
    (6) Number of test runs.
    (7) Number of times in the reporting year that a performance test 
had to be repeated (number).
    (k) If you requested Administrator approval for an alternative 
method of determining N2O concentration under Sec.  
98.53(a)(2), each annual report must also contain the information 
specified in paragraphs (k)(1) through (k)(4) of this section for each 
adipic acid production facility.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.


Sec.  98.57  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (h) of this 
section at the facility level:
    (a) Annual adipic acid production capacity (tons).
    (b) Records of significant changes to process.
    (c) Number of facility operating hours in calendar year.
    (d) Documentation of how accounting procedures were used to 
estimate production rate.
    (e) Documentation of how process knowledge was used to estimate 
abatement technology destruction efficiency.
    (f) Performance test reports of N2O emissions.
    (g) Measurements, records and calculations used to determine 
reported parameters.
    (h) Documentation of the procedures used to ensure the accuracy of 
the measurements of all reported parameters, including but not limited 
to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.


Sec.  98.58  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart F--Aluminum Production


Sec.  98.60  Definition of the source category.

    (a) A primary aluminum production facility manufactures primary 
aluminum using the Hall-H[eacute]roult manufacturing process. The 
primary aluminum manufacturing process comprises the following 
operations:
    (1) Electrolysis in prebake and S[oslash]derberg cells.
    (2) Anode baking for prebake cells.
    (b) This source category does not include experimental cells or 
research and development process units.


Sec.  98.61  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an aluminum production process and the facility meets the

[[Page 56414]]

requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.62  GHGs to report.

    You must report:
    (a) Perfluoromethane (CF4), and perfluoroethane 
(C2F6) emissions from anode effects in all 
prebake and S[oslash]derberg electolysis cells.
    (b) CO2 emissions from anode consumption during 
electrolysis in all prebake and S[oslash]derberg electolysis cells.
    (c) CO2 emissions from on-site anode baking.
    (d) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
N2O, and CH4 emissions from each stationary fuel 
combustion unit by following the requirements of subpart C.


Sec.  98.63  Calculating GHG emissions.

    (a) The annual value for PFC emissions shall be estimated from the 
sum of monthly values using Equation F-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.025

Where:

EPFC = Annual PFC emissions from aluminum production 
(metric tons PFC).
Em = PFC emissions 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 electolysis cell.
[GRAPHIC] [TIFF OMITTED] TR30OC09.026

Where:

ECF4 = Monthly CF4 emissions from aluminum 
production (metric tons CF4).
SCF4 = The slope coefficient ((kg CF4/metric 
ton Al)/(AE-Mins/cell-day)).
AEM = The anode effect minutes per cell-day (AE-Mins/cell-day).
MP = Metal production (metric tons Al), where AEM and MP are 
calculated monthly.
[GRAPHIC] [TIFF OMITTED] TR30OC09.027

Where:

ECF4 = Monthly CF4 emissions from aluminum 
production (metric tons CF4).
EFCF4 = The overvoltage emission factor (kg 
CF4/metric ton Al).
MP = Metal production (metric tons Al), where MP is calculated 
monthly.
[GRAPHIC] [TIFF OMITTED] TR30OC09.028

Where:

EC2F6 = Monthly C2F6 emissions from 
aluminum production (metric tons C2F6).
ECF4 = CF4 emissions from aluminum production 
(kg CF4).
FC2F6/CF4 = The weight fraction of 
C2F6/CF4 (kg 
C2F6/kg CF4).
0.001 = Conversion factor from kg to metric tons, where 
ECF4 is calculated monthly.

    (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 or the procedures in paragraphs (e) and (f) of this section.
    (d) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (e) Use the following procedures to calculate CO2 
emissions from anode consumption during electrolysis:
    (1) For Prebake cells: you must calculate CO2 emissions 
from anode consumption using Equation F-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.029

Where:

ECO2 = Annual CO2 emissions from prebaked 
anode consumption (metric tons CO2).
NAC = Net annual prebaked anode consumption per metric ton Al 
(metric tons C/metric tons Al).
MP = Annual metal production (metric tons Al).
Sa = Sulfur content in baked anode (percent weight).
Asha = Ash content in baked anode (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) For S[oslash]derberg cells you must calculate CO2 
emissions using Equation F-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.030


[[Page 56415]]


Where:

ECO2 = Annual CO2 emissions from paste 
consumption (metric ton CO2).
PC = Annual paste consumption (metric ton/metric ton Al).
MP = Annual metal production (metric ton Al).
CSM = Annual emissions of cyclohexane soluble matter (kg/metric ton 
Al).
BC = Binder content of paste (percent weight).
Sp = Sulfur content of pitch (percent weight).
Ashp = Ash content of pitch (percent weight).
Hp = Hydrogen content of pitch (percent weight).
Sc = Sulfur content in calcined coke (percent weight).
Ashc = Ash content in calcined coke (percent weight).
CD = Carbon in skimmed dust from S[oslash]derberg cells (metric ton 
C/metric ton Al).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (f) Use the following procedures to calculate CO2 
emissions from anode baking of prebake cells:
    (1) Use Equation F-7 of this section to calculate emissions from 
pitch volatiles combustion.
[GRAPHIC] [TIFF OMITTED] TR30OC09.031

Where:

ECO2PV = Annual CO2 emissions from pitch 
volatiles combustion (metric tons CO2).
GA = Initial weight of green anodes (metric tons).
Hw = Annual hydrogen content in green anodes (metric 
tons).
BA = Annual baked anode production (metric tons).
WT = Annual waste tar collected (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) Use Equation F-8 of this section to calculate emissions from 
bake furnace packing material.
[GRAPHIC] [TIFF OMITTED] TR30OC09.032

Where:

ECO2PC = Annual CO2 emissions from bake 
furnace packing material (metric tons CO2).
PCC = Annual packing coke consumption (metric tons/metric ton baked 
anode).
BA = Annual baked anode production (metric tons).
Spc = Sulfur content in packing coke (percent weight).
Ashpc = Ash content in packing coke (percent weight).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (g) If process CO2 emissions from anode consumption 
during electrolysis or anode baking of prebake cells are vented through 
the same stack as any combustion unit or process equipment that reports 
CO2 emissions using a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Fuel Combustion Sources), then the calculation methodology in 
paragraphs (d) and (e) of this section shall not be used to calculate 
those process emissions. The owner or operation shall report under this 
subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).


Sec.  98.64  Monitoring and QA/QC requirements.

    (a) Effective one year after publication of the rule for smelters 
with no prior measurement or effective three years after publication 
for facilities with historic measurements, the smelter-specific slope 
coefficients used in Equations F-2, F-3, and F-4 of this subpart must 
be measured in accordance with the recommendations of the EPA/IAI 
Protocol for Measurement of Tetrafluoromethane (CF4) and 
Hexafluoroethane (C2F6) Emissions from Primary 
Aluminum Production (2008), except the minimum frequency of measurement 
shall be every 10 years unless a change occurs in the control algorithm 
that affects the mix of types of anode effects or the nature of the 
anode effect termination routine. Facilities which operate at less than 
0.2 anode effect minutes per cell day or operate with less than 1.4mV 
anode effect overvoltage can use either smelter-specific slope 
coefficients or the technology specific default values in Table F-1 of 
this subpart.
    (b) The minimum frequency of the measurement and analysis is 
annually except as follows: Monthly--anode effect minutes per cell day 
(or anode effect overvoltage and current efficiency), production.
    (c) Sources may use either smelter-specific values from annual 
measurements of parameters needed to complete the equations in Sec.  
98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values 
shown in Table F-2 of this subpart.


Sec.  98.65  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample measurement 
is not taken), a substitute data value for the missing parameter shall 
be used in the calculations, according to the following requirements:
    (a) Where anode or paste consumption data are missing, 
CO2 emissions can be estimated from aluminum production 
using Tier 1 method per Equation F-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.033

Where:

ECO2 = CO2 emissions from anode and/or paste 
consumption, metric tons CO2.
EFp = Prebake technology specific emission factor (1.6 
metric tons CO2/metric ton aluminum produced).
MPp = Metal production from prebake process (metric tons 
Al).
EFs = S[oslash]derberg technology specific emission 
factor (1.7 metric tons CO2/metric ton Al produced).
MPs = Metal production from S[oslash]derberg process 
(metric tons Al).


[[Page 56416]]


    (b) For other parameters, use the average of the two most recent 
data points after the missing data.


Sec.  98.66  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), you must 
report the following information at the facility level:
    (a) Annual aluminum production in metric tons.
    (b) Type of smelter technology used.
    (c) The following PFC-specific information on an annual basis:
    (1) Perfluoromethane emissions and perfluoroethane emissions from 
anode effects in all prebake and all S[oslash]derberg electolysis cells 
combined.
    (2) Anode effect minutes per cell-day (AE-mins/cell-day), anode 
effect frequency (AE/cell-day), anode effect duration (minutes). (Or 
anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/
cell day)), potline overvoltage (mV/cell day), current efficiency (%).)
    (3) Smelter-specific slope coefficients (or overvoltage emission 
factors) and the last date when the smelter-specific-slope coefficients 
(or overvoltage emission factors) were measured.
    (d) Method used to measure the frequency and duration of anode 
effects (or overvoltage).
    (e) The following CO2-specific information for prebake 
cells:
    (1) Annual anode consumption.
    (2) Annual CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells:
    (1) Annual paste consumption.
    (2) Annual CO2 emissions from the smelter.
    (g) Smelter-specific inputs to the CO2 process equations 
(e.g., levels of sulfur and ash) that were used in the calculation, on 
an annual basis.
    (h) Exact data elements required will vary depending on smelter 
technology (e.g., point-feed prebake or S[oslash]derberg) and process 
control technology (e.g., Pechiney or other).


Sec.  98.67  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Monthly aluminum production in metric tons.
    (b) Type of smelter technology used.
    (c) The following PFC-specific information on a monthly basis:
    (1) Perfluoromethane and perfluoroethane emissions from anode 
effects in prebake and S[oslash]derberg electolysis cells.
    (2) Anode effect minutes per cell-day (AE-mins/cell-day), anode 
effect frequency (AE/cell-day), anode effect duration (minutes). (Or 
anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/
cell day)), potline overvoltage (mV/cell day), current efficiency 
(%).))
    (3) Smelter-specific slope coefficients and the last date when the 
smelter-specific-slope coefficients were measured.
    (d) Method used to measure the frequency and duration of anode 
effects (or to measure anode effect overvoltage and current 
efficiency).
    (e) The following CO2-specific information for prebake 
cells:
    (1) Annual anode consumption.
    (2) Annual CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells:
    (1) Annual paste consumption.
    (2) Annual CO2 emissions from the smelter.
    (g) Smelter-specific inputs to the CO2 process equations 
(e.g., levels of sulfur and ash) that were used in the calculation, on 
an annual basis.
    (h) Exact data elements required will vary depending on smelter 
technology (e.g., point-feed prebake or S[oslash]derberg) and process 
control technology (e.g., Pechiney or other).


Sec.  98.68  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

 Table F-1 to Subpart F of Part 98--Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From
                                               Aluminum Production
----------------------------------------------------------------------------------------------------------------
                                                                     CF4 slope          CF4
                                                                    coefficient     overvoltage       Weight
                                                                     [(kg CF4/      coefficient   fraction C2F6/
                           Technology                             metric ton Al)/    [(kg CF4/    CF4 [(kg C2F6/
                                                                  (AE-Mins/cell-  metric ton Al)/    kg CF4)]
                                                                       day)]           (mV)]
----------------------------------------------------------------------------------------------------------------
CWPB............................................................           0.143            1.16           0.121
SWPB............................................................           0.272            3.65           0.252
VSS.............................................................           0.092              NA           0.053
HSS.............................................................           0.099              NA           0.085
----------------------------------------------------------------------------------------------------------------


 Table F-2 to Subpart F of Part 98--Default Data Sources for Parameters
                         Used for CO2 Emissions
------------------------------------------------------------------------
            Parameter                           Data source
------------------------------------------------------------------------
            CO2 Emissions from Prebake Cells (CWPB and SWPB)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
NAC: net annual prebaked anode     Individual facility records.
 consumption per metric ton Al
 (metric tons C/metric tons Al).
Sa: sulfur content in baked anode  2.0.
 (percent weight).
Asha: ash content in baked anode   0.4.
 (percent weight).
------------------------------------------------------------------------
         CO2 Emissions from S[oslash]derberg Cells (VSS and HSS)
------------------------------------------------------------------------
MP: metal production (metric tons  Individual facility records.
 Al).
PC: annual paste consumption       Individual facility records.
 (metric ton/metric ton Al).
CSM: annual emissions of           HSS: 4.0.
 cyclohexane soluble matter (kg/   VSS: 0.5.
 metric ton Al).
BC: binder content of paste        Dry Paste: 24.
 (percent weight).                 Wet Paste: 27.
Sp: sulfur content of pitch        0.6.
 (percent weight).
Ashp: ash content of pitch         0.2.
 (percent weight).

[[Page 56417]]

 
Hp: hydrogen content of pitch      3.3.
 (percent weight).
Sc: sulfur content in calcined     1.9.
 coke (percent weight).
Ashc: ash content in calcined      0.2.
 coke (percent weight).
CD: carbon in skimmed dust from    0.01.
 S[oslash]derberg cells (metric
 ton C/metric ton Al).
------------------------------------------------------------------------
       CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS)
------------------------------------------------------------------------
GA: initial weight of green        Individual facility records.
 anodes (metric tons).
Hw: annual hydrogen content in     0.005 x GA.
 green anodes (metric tons).
BA: annual baked anode production  Individual facility records.
 (metric tons).
WT: annual waste tar collected     (a) 0.005 x GA.
 (metric tons).
(a) Riedhammer furnaces..........  (b) insignificant.
(b) all other furnaces...........
------------------------------------------------------------------------
    CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB)
------------------------------------------------------------------------
PCC: annual packing coke           0.015.
 consumption (metric tons/metric
 ton baked anode).
BA: annual baked anode production  Individual facility records.
 (metric tons).
Spc: sulfur content in packing     2.
 coke (percent weight).
Ashpc: ash content in packing      2.5.
 coke (percent weight).
------------------------------------------------------------------------

Subpart G--Ammonia Manufacturing


Sec.  98.70  Definition of source category.

    The ammonia manufacturing source category comprises the process 
units listed in paragraphs (a) and (b) of this section.
    (a) Ammonia manufacturing processes in which ammonia is 
manufactured from a fossil-based feedstock produced via steam reforming 
of a hydrocarbon.
    (b) Ammonia manufacturing processes in which ammonia is 
manufactured through the gasification of solid and liquid raw material.


Sec.  98.71  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an ammonia manufacturing process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.72  GHGs to report.

    You must report:
    (a) 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 in this subpart.
    (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.
    (c) CO2 emissions collected and transferred off site 
under subpart PP of this part (Suppliers of CO2), following 
the requirements of subpart PP.


Sec.  98.73  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each ammonia manufacturing process unit using the 
procedures in either paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart process CO2 
emissions using the procedures in paragraphs (b)(1) through (b)(6) of 
this section for gaseous feedstock, liquid feedstock, or solid 
feedstock, as applicable.
    (1) Gaseous feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from gaseous 
feedstock according to Equation G-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.034

Where:

CO2,G = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
Fdstkn = Volume of the gaseous feedstock used in month n 
(scf of feedstock).
CCn = Carbon content of the gaseous feedstock, for month 
n (kg C per kg of feedstock), determined according to 98.74(c).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (2) Liquid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from liquid 
feedstock according to Equation G-2 of this section:

[[Page 56418]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.035

Where:

CO2,L = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
Fdstkn = Volume of the liquid feedstock used in month n 
(gallons of feedstock).
CCn = Carbon content of the liquid feedstock, for month n 
(kg C per gallon of feedstock) determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (3) Solid feedstock. You must calculate, from each ammonia 
manufacturing unit, the CO2 process emissions from solid 
feedstock according to Equation G-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.036

Where:

CO2,S = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
Fdstkn = Mass of the solid feedstock used in month n (kg 
of feedstock).
CCn = Carbon content of the solid feedstock, for month n 
(kg C per kg of feedstock), determined according to 98.74(c).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
k = Processing unit.
n = Number of month.

    (4) You must calculate the annual process CO2 emissions 
from each ammonia processing unit k at your facility summing emissions, 
as applicable from Equation G-1, G-2, and G-3 of this section using 
Equation G-4.
[GRAPHIC] [TIFF OMITTED] TR30OC09.037

Where:

ECO2k = Annual CO2 emissions from each ammonia 
processing unit k (metric tons).
k = Processing unit.

    (5) You must determine the combined CO2 emissions from 
all ammonia processing units at your facility using Equation G-5 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.038

Where:

CO2 = Annual combined CO2 emissions from all 
ammonia processing units (metric tons).
ECO2k = Annual CO2 emissions from each ammonia 
processing unit (metric tons).
k = Processing unit.
n = Total number of ammonia processing units.

    (6) If applicable, ammonia manufacturing facilities that utilize 
the waste recycle stream as a fuel must calculate emissions associated 
with the waste stream for each ammonia process unit according to 
Equation G-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.039

Where:

CO2 = Annual CO2 contained in waste recycle 
stream (metric tons).
RecycleStreamn = Volume of the waste recycle stream in 
month n (scf).
CCn = Carbon content of the waste recycle stream, for 
month n (kg C per kg of waste recycle stream) determined according 
to 98.74(f).
MW = Molecular weight of the waste recycle stream (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
n = Number of month

    (c) If GHG emissions from an ammonia manufacturing unit are vented 
through the same stack as any combustion unit or process equipment that 
reports CO2 emissions using a CEMS that complies with the 
Tier 4 Calculation Methodology in subpart C of this part (General 
Stationary Fuel Combustion Sources), then the calculation methodology 
in paragraph (b) of this section shall not be used to calculate process 
emissions. The owner or operator shall report under this subpart the 
combined stack emissions according to the Tier 4 Calculation 
Methodology in Sec.  98.33(a)(4) and all associated requirements for 
Tier 4 in subpart C of this part.


Sec.  98.74  Monitoring and QA/QC requirements.

    (a) You must continuously measure the quantity of gaseous or liquid 
feedstock consumed using a flow meter. The quantity of solid feedstock 
consumed can be obtained from company records and aggregated on a 
monthly basis.
    (b) You must document the procedures used to ensure the accuracy of 
the estimates of feedstock consumption.
    (c) You must determine monthly carbon contents and the average 
molecular weight of each feedstock consumed from reports from your 
supplier. As an alternative to using supplier information on carbon

[[Page 56419]]

contents, you can also collect a sample of each feedstock on a monthly 
basis and analyze the carbon content and molecular weight of the fuel 
using any of the following methods listed in paragraphs (c)(1) through 
(c)(8) of this section, as applicable.
    (1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for 
Estimation of Mean Relative Molecular Mass of Petroleum Oils from 
Viscosity Measurements (incorporated by reference, see Sec.  98.7).
    (4) 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).
    (5) 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 (incorporated by reference, see 
Sec.  98.7).
    (6) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec.  
98.7).
    (7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec.  98.7).
    (8) ASTM D5373-08 Standard Methods for Instrumental Determination 
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal 
(incorporated by reference, see Sec.  98.7).
    (d) Calibrate all oil and gas flow meters (except for gas billing 
meters) and perform oil tank measurements according to the monitoring 
and QA/QC requirements for the Tier 3 methodology in Sec.  98.34(b).
    (e) For quality assurance and quality control of the supplier data, 
on an annual basis, you must measure the carbon contents of a 
representative sample of the feedstocks consumed using the appropriate 
ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this 
section.
    (f) Facilities must continuously measure the quantity of waste gas 
recycled using a flow meter, as applicable. You must determine the 
carbon content and the molecular weight of the waste recycle stream by 
collecting a sample of each waste recycle stream on a monthly basis and 
analyzing the carbon content using the appropriate ASTM Method as 
listed in paragraphs (c)(1) through (c)(8) of this section.
    (g) If CO2 from ammonia production is used to produce 
urea at the same facility, you must determine the quantity of urea 
produced using methods or plant instruments used for accounting 
purposes (such as sales records). You must document the procedures used 
to ensure the accuracy of the estimates of urea produced.


Sec.  98.75  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever the monitoring 
and quality assurance procedures in Sec.  98.74 cannot be followed 
(e.g., if a meter malfunctions during unit operation), a substitute 
data value for the missing parameter shall be used in the calculations 
following paragraphs (a) and (b) of this section. You must document and 
keep records of the procedures used for all such estimates.
    (a) For missing data on monthly carbon contents of feedstock or the 
waste recycle stream, 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. If no quality-assured data are available prior to the missing 
data incident, the substitute data value shall be the first quality-
assured value for carbon content obtained in the month after the 
missing data period.
    (b) For missing feedstock supply rates or waste recycle stream used 
to determine monthly feedstock consumption or monthly waste recycle 
stream quantity, you must determine the best available estimate(s) of 
the parameter(s), based on all available process data.


Sec.  98.76  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable for each ammonia manufacturing 
process unit.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec.  
98.37(e)(2)(vi) for the Tier 4 Calculation Methodology and the 
following information in this paragraph (a):
    (1) Annual quantity of each type of feedstock consumed for ammonia 
manufacturing (scf of feedstock or gallons of feedstock or kg of 
feedstock).
    (2) Method used for determining quantity of feedstock used.
    (b) If a CEMS is not used to measure emissions, then you must 
report the following information:
    (1) Annual CO2 process emissions (metric tons) for each 
ammonia manufacturing process unit.
    (2) Monthly quantity of each type of feedstock consumed for ammonia 
manufacturing for each ammonia processing unit (scf of feedstock or 
gallons of feedstock or kg of feedstock).
    (3) Method used for determining quantity of monthly feedstock used.
    (4) Whether carbon content for each feedstock for month n is based 
on reports from the supplier or analysis of carbon content.
    (5) If carbon content of feedstock for month n is based on 
analysis, the test method used.
    (6) Sampling analysis results of carbon content of petroleum coke 
as determined for QA/QC of supplier data under Sec.  98.74(e).
    (7) If a facility uses gaseous feedstock, the carbon content of the 
gaseous feedstock, for month n, (kg C per kg of feedstock).
    (8) If a facility uses gaseous feedstock, the molecular weight of 
the gaseous feedstock (kg/kg-mole).
    (9) If a facility uses gaseous feedstock, the molar volume 
conversion factor of the gaseous feedstock (scf per kg-mole).
    (10) If a facility uses liquid feedstock, the carbon content of the 
liquid feedstock, for month n, (kg C per gallon of feedstock).
    (11) If a facility uses solid feedstock, the carbon content of the 
solid feedstock, for month n, (kg C per kg of feedstock).
    (12) Annual CO2 emissions associated with the waste 
recycle stream for each ammonia process unit (metric tons)
    (13) Carbon content of the waste recycle stream for month n for 
each ammonia process unit (kg C per kg of waste recycle stream).
    (14) Volume of the waste recycle stream for month n for each 
ammonia process unit (scf)
    (15) Method used for analyzing carbon content of waste recycle 
stream.
    (16) Annual urea production (metric tons) and method used to 
determine urea production.
    (17) Uses of urea produced, if known, such as but not limited to 
fertilizer, animal feed, manufacturing of plastics or resins, and 
pollution control technologies.
    (c) Total pounds of synthetic fertilizer produced through and total 
nitrogen contained in that fertilizer.

[[Page 56420]]

Sec.  98.77  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the following records specified in paragraphs (a) and (b) of 
this section for each ammonia manufacturing unit.
    (a) If a CEMS is used to measure emissions, retain records of all 
feedstock purchases in addition to the requirements in Sec.  98.37 for 
the Tier 4 Calculation Methodology.
    (b) If a CEMS is not used to measure process CO2 
emissions, you must also retain the records specified in paragraphs 
(b)(1) through (b)(2) of this section:
    (1) Records of all analyses and calculations conducted for reported 
data as listed in Sec.  98.76(b).
    (2) Monthly records of carbon content of feedstock from supplier 
and/or all analyses conducted of carbon content.


Sec.  98.78  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart H--Cement Production


Sec.  98.80  Definition of the source category.

    The cement production source category consists of each kiln and 
each in-line kiln/raw mill at any portland cement manufacturing 
facility including alkali bypasses, and includes kilns and in-line 
kiln/raw mills that burn hazardous waste.


Sec.  98.81  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a cement production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.82  GHGs to report.

    You must report:
    (a) CO2 process emissions from calcination in each kiln.
    (b) CO2 combustion emissions from each kiln.
    (c) CH4 and N2O combustion emissions from 
each kiln. You must calculate and report these emissions under subpart 
C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than kilns. You must report 
these emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.


Sec.  98.83  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each kiln using the procedure in paragraphs (a) and (b) 
of this section.
    (a) For each cement kiln that meets the conditions specified in 
Sec.  98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report 
under this subpart the combined process and combustion CO2 
emissions by operating and maintaining a CEMS to measure CO2 
emissions according to the Tier 4 Calculation Methodology specified in 
Sec.  98.33(a)(4) and all associated requirements for Tier 4 in subpart 
C of this part (General Stationary Fuel Combustion Sources).
    (b) For each kiln that is not subject to the requirements in 
paragraph (a) of this section, calculate and report the process and 
combustion CO2 emissions from the kiln by using the 
procedure in either paragraph (c) or (d) of this section.
    (c) Calculate and report under this subpart the combined process 
and combustion CO2 emissions by operating and maintaining a 
CEMS to measure CO2 emissions according to the Tier 4 
Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (d) Calculate and report process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(d)(1) through (d)(4) of this section.
    (1) Calculate CO2 process emissions from all kilns at 
the facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.040

Where:

CO2 CMF = Annual process emissions of CO2 from 
cement manufacturing, metric tons.
CO2 Cli,m = Total annual emissions of CO2 from 
clinker production from kiln m, metric tons.
CO2 rm = Total annual emissions of CO2 from 
raw materials, metric tons.
k = Total number of kilns at a cement manufacturing facility.

    (2) CO2 emissions from clinker production. Calculate 
CO2 emissions from each kiln using Equations H-2 through H-5 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.041

Where:

Cli,j = Quantity of clinker produced in month j from kiln 
m, tons.
EFCli,j = Kiln specific clinker emission factor for month 
j for kiln m, metric tons CO2/metric ton clinker computed 
as specified in Equation H-3 of this section.
CKD,i = Cement kiln dust (CKD) not recycled to the kiln 
in quarter i from kiln m, tons.
EFCKD,i = Kiln specific CKD emission factor for quarter i 
from kiln m, metric tons CO2/metric ton CKD computed as 
specified in Equation H-4 of this section.
p = Number of months for clinker calculation, 12.
r = Number of quarters for CKD calculation, 4.
2000/2205 = Conversion factor to convert tons to metric tons.

    (i) Kiln-Specific Clinker Emission Factor. (A) Calculate the kiln-
specific clinker emission factor using Equation H-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.042


[[Page 56421]]


Where:

CliCaO = Monthly total CaO content of Clinker, wt-
fraction.
ClincCaO = Monthly non-calcined CaO content of Clinker, 
wt-fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO = 
0.785.
CliMgO = Monthly total MgO content of Clinker, wt-
fraction.
ClincMgO = Monthly non-calcined MgO content of Clinker, 
wt-fraction.
MRMgO = Molecular-weight Ratio of CO2/MgO = 
1.092.

    (B) Non-calcined CaO is CaO that remains in the clinker in the form 
of CaCO3 and CaO in the clinker that entered the kiln as a 
non-carbonate species. Non-calcined MgO is MgO that remains in the 
clinker in the form of MgCO3 and MgO in the clinker that 
entered the kiln as a non-carbonate species.
    (ii) Kiln-Specific CKD Emission Factor. (A) Calculate the kiln-
specific CKD emission factor for CKD not recycled to the kiln using 
Equation H-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.043

Where:

CKDCaO = Quarterly total CaO content of CKD not recycled 
to the kiln, wt-fraction.
CKDCaO = Quarterly non-calcined CaO content of CKD not 
recycled to the kiln, wt-fraction.
MRCaO = Molecular-weight Ratio of CO2/CaO = 
0.785.
CKDMgO = Quarterly total MgO content of CKD not recycled 
to the kiln, wt-fraction.
CKDMgO = Quarterly non-calcined MgO content of CKD not 
recycled to the kiln, wt-fraction.
MRMgO = Molecular-weight Ratio of CO2/MgO = 
1.092.

    (B) Non-calcined CaO is CaO that remains in the CKD in the form of 
CaCO3 and CaO in the CKD that entered the kiln as a non-
carbonate species. Non-calcined MgO is MgO that remains in the CKD in 
the form of MgCO3 and MgO in the CKD that entered the kiln 
as a non-carbonate species.
    (3) CO2 emissions from raw materials. Calculate 
CO2 emissions using Equation H-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.044

Where:

rm = The amount of raw material i consumed annually, tons/yr (dry 
basis).
CO2,rm = Annual CO2 emissions from raw 
materials.
TOCrm = Organic carbon content of raw material i (dry basis), as 
determined in Sec.  98.84(c) or using a default factor of 0.2 
percent of total raw material weight.
M = Number of raw materials.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.

    (4) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions from the kiln according to the applicable requirements in 
subpart C.


Sec.  98.84  Monitoring and QA/QC requirements.

    (a) You must determine the weight fraction of total CaO and total 
MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09, 
Standard Test Methods for Chemical Analysis of Hydraulic Cement 
(incoporated by reference, see Sec.  98.7). The monitoring must be 
conducted quarterly for each kiln from a CKD sample drawn either as CKD 
is exiting the kiln or from bulk CKD storage.
    (b) You must determine the weight fraction of total CaO and total 
MgO in clinker from each kiln using ASTM C114-07 Standard Test Methods 
for Chemical Analysis of Hydraulic Cement (incorporated by reference, 
see Sec.  98.7). The monitoring must be conducted monthly for each kiln 
from a clinker sample drawn from bulk clinker storage.
    (c) The total organic carbon contents (dry basis) of each raw 
material must be determined annually using ASTM C114-09 Standard Test 
Methods for Chemical Analysis of Hydraulic Cement (incorporated by 
reference, see Sec.  98.7) or a similar industry standard practice or 
method approved for total organic carbon determination in raw mineral 
materials. The analysis must be conducted on sample material drawn from 
bulk raw material storage for each category of raw material (i.e., 
limestone, sand, shale, iron oxide, and alumina). Facilities that opt 
to use the default total organic carbon factor provided in Sec.  
98.83(d)(3), are not required to monitor for TOC.
    (d) The quantity of clinker produced monthly by each kiln must be 
determined by direct weight measurement using the same plant 
instruments used for accounting purposes, such as weigh hoppers or belt 
weigh feeders.
    (e) The quantity of CKD not recycled to the kiln by each kiln must 
be determined quarterly by direct weight measurement using the same 
plant instruments used for accounting purposes, such as weigh hoppers, 
truck weigh scales, or belt weigh feeders.
    (f) The quantity of each category of raw materials consumed 
annually by the facility (e.g., limestone, sand, shale, iron oxide, and 
alumina) must be determined monthly by direct weight measurement using 
the same plant instruments used for accounting purposes, such as weigh 
hoppers, truck weigh scales, or belt weigh feeders.
    (g) The monthly non-calcined CaO and MgO that remains in the 
clinker in the form of CaCO3 or that enters the kiln as a 
non-carbonate species may be assumed to be a default value of 0.0 or 
may be determined monthly by careful chemical analysis of feed material 
and clinker material from each kiln using well documented analytical 
and calculational methods or the appropriate industry standard 
practice.
    (h) The quarterly non-calcined CaO and MgO that remains in the CKD 
in the form of CaCO3 or that enters the kiln as a non-
carbonate species may be assumed to be a default value of 0.0 or may be 
determined quarterly by careful chemical analysis of feed material and 
CKD material from each kiln using well documented analytical and 
calculational methods or the appropriate industry standard practice.


Sec.  98.85  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.83 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for

[[Page 56422]]

the missing parameter shall be used in the calculations. The owner or 
operator must document and keep records of the procedures used for all 
such estimates.
    (a) If the CEMS approach is used to determine combined process and 
combustion CO2 emissions, the missing data procedures in 
Sec.  98.35 apply.
    (b) For CO2 process emissions from cement manufacturing 
facilities calculated according to Sec.  98.83(d), if data on the 
carbonate content (of clinker or CKD), noncalcined content (of clinker 
or CKD) or the annual organic carbon content of raw materials are 
missing, facilities must undertake a new analysis.
    (c) For each missing value of monthly clinker production the 
substitute data value must be the best available estimate of the 
monthly clinker production based on information used for accounting 
purposes, or use the maximum tons per day capacity of the system and 
the number of days per month.
    (d) For each missing value of monthly raw material consumption the 
substitute data value must be the best available estimate of the 
monthly raw material consumption based on information used for 
accounting purposes (such as purchase records), or use the maximum tons 
per day raw material throughput of the kiln and the number of days per 
month.


Sec.  98.86  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as appropriate.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec.  98.36(e)(2)(vi) and the information listed in this paragraph(a):
    (1) Monthly clinker production from each kiln at the facility.
    (2) Monthly cement production from each kiln at the facility.
    (3) Number of kilns and number of operating kilns.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b) for each 
kiln:
    (1) Kiln identification number.
    (2) Monthly clinker production from each kiln.
    (3) Monthly cement production from each kiln.
    (4) Number of kilns and number of operating kilns.
    (5) Quarterly quantity of CKD not recycled to the kiln for each 
kiln at the facility.
    (6) Monthly fraction of total CaO, total MgO, non-calcined CaO and 
non-calcined MgO in clinker for each kiln (as wt-fractions).
    (7) Method used to determine non-calcined CaO and non-calcined MgO 
in clinker.
    (8) Quarterly fraction of total CaO, total MgO, non-calcined CaO 
and non-calcined MgO in CKD not recycled to the kiln for each kiln (as 
wt-fractions).
    (9) Method used to determine non-calcined CaO and non-calcined MgO 
in CKD.
    (10) Monthly kiln-specific clinker CO2 emission factors 
for each kiln (metric tons CO2/metric ton clinker produced).
    (11) Quarterly kiln-specific CKD CO2 emission factors 
for each kiln (metric tons CO2/metric ton CKD produced).
    (12) Annual organic carbon content of each raw material (wt-
fraction, dry basis).
    (13) Annual consumption of each raw material (dry basis).
    (14) Number of times missing data procedures were used to determine 
the following information:
    (i) Clinker production (number of months).
    (ii) Carbonate contents of clinker (number of months).
    (iii) Non-calcined content of clinker (number of months).
    (iv) CKD not recycled to kiln (number of quarters).
    (v) Non-calcined content of CKD (number of quarters)
    (vi) Organic carbon contents of raw materials (number of times).
    (vii) Raw material consumption (number of months).


Sec.  98.87  Records that must be retained.

    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec.  98.37.
    (1) Documentation of monthly calculated kiln-specific clinker 
CO2 emission factor.
    (2) Documentation of quarterly calculated kiln-specific CKD 
CO2 emission factor.
    (3) Measurements, records and calculations used to determine 
reported parameters.
    (b) If a CEMS is not used to measure CO2 emissions, then 
in addition to the records required by Sec.  98.3(g), you must retain 
the records specified in paragraphs (a) through (b) of this section for 
each portland cement manufacturing facility.


Sec.  98.88  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart I--[Reserved]

Subpart J--[Reserved]

Subpart K--Ferroalloy Production


Sec.  98.110  Definition of the source category.

    The ferroalloy production source category consists of any facility 
that uses pyrometallurgical techniques to produce any of the following 
metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, 
ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, 
silicomanganese, or silicon metal.


Sec.  98.111  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a ferroalloy production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.112  GHGs to report.

    You must report:
    (a) Process CO2 emissions from each electric arc furnace 
(EAF) used for the production of any ferroalloy listed in Sec.  98.110.
    (b) CO2, CH4, and N2O emissions 
from each stationary combustion unit following the requirements of 
subpart C of this part. You must report these emissions under subpart C 
of this part (General Stationary Fuel Combustion Sources).


Sec.  98.113  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each EAF using the procedures in either paragraph (a) or 
(b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the annual process 
CO2 emissions using the procedure in either paragraph (b)(1) 
or (b)(2) of this section.
    (1) Calculate and report under this subpart the annual process 
CO2 emissions from EAFs by operating and maintaining a CEMS 
according to the Tier 4 Calculation Methodology specified in Sec.  
98.33(a)(4) and the applicable requirements for Tier 4 in subpart C of 
this part (General Stationary Fuel Combustion Sources).
    (2) Calculate and report under this subpart the annual process 
CO2 emissions from the EAFs using the carbon mass balance 
procedure specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this 
section.

[[Page 56423]]

    (i) For each EAF, determine the annual mass of carbon in each 
carbon-containing input and output material for the EAF and estimate 
annual process CO2 emissions from the EAF using Equation K-1 
of this section. Carbon-containing input materials include carbon 
electrodes and carbonaceous reducing agents. If you document that a 
specific input or output material contributes less than 1 percent of 
the total carbon into or out of the process, you do not have to include 
the material in your calculation using Equation K-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.045

Where:

ECO2 = Annual process CO2 emissions from an 
individual EAF (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Mreducing agenti = Annual mass of reducing agent i fed, 
charged, or otherwise introduced into the EAF (tons).
Creducing agenti = Carbon content in reducing agent i 
(percent by weight, expressed as a decimal fraction).
Melectrodem = Annual mass of carbon electrode m consumed 
in the EAF (tons).
Celectrodem = Carbon content of the carbon electrode m 
(percent by weight, expressed as a decimal fraction).
Moreh = Annual mass of ore h charged to the EAF (tons).
Coreh = Carbon content in ore h (percent by weight, 
expressed as a decimal fraction).
Mfluxj = Annual mass of flux material j fed, charged, or 
otherwise introduced into the EAF to facilitate slag formation 
(tons).
Cfluxj = Carbon content in flux material j (percent by 
weight, expressed as a decimal fraction).
Mproductk = Annual mass of alloy product k tapped from 
EAF (tons).
Cproductk = Carbon content in alloy product k. (percent 
by weight, expressed as a decimal fraction).
Mnon-product outgoingl = Annual mass of non-product 
outgoing material l removed from EAF (tons).
Cnon-product outgoingl = Carbon content in non-product 
outgoing material l (percent by weight, expressed as a decimal 
fraction).

    (ii) Determine the combined annual process CO2 emissions 
from the EAFs at your facility using Equation K-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.046

Where:

CO2 = Annual process CO2 emissions from EAFs 
at facility used for the production of any ferroalloy listed in 
Sec.  98.110 (metric tons).
ECO2k = Annual process CO2 emissions 
calculated from EAF k calculated using Equation K-1 of this section 
(metric tons).
k = Total number of EAFs at facility used for the production of any 
ferroalloy listed in Sec.  98.110.

    (c) If GHG emissions from an EAF are vented through the same stack 
as any combustion unit or process equipment that reports CO2 
emissions using a CEMS that complies with the Tier 4 Calculation 
Methodology in subpart C of this part (General Stationary Fuel 
Combustion Sources), then the calculation methodology in paragraph (b) 
of this section shall not be used to calculate process emissions. The 
owner or operator shall report under this subpart the combined stack 
emissions according to the Tier 4 Calculation Methodology in Sec.  
98.33(a)(4) and all associated requirements for Tier 4 in subpart C of 
this part.
    (d) For the EAFs at your facility used for the production of any 
ferroalloy listed in Table K-1 of this subpart, you must calculate and 
report the annual CH4 emissions using the procedure 
specified in paragraphs (d)(1) and (2) of this section.
    (1) For each EAF, determine the annual CH4 emissions 
using Equation K-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.047

Where:

ECH4 = Annual process CH4 emissions from an 
individual EAF (metric tons).
Mproducti = Annual mass of alloy product i produced in 
the EAF (tons).
2000/2205 = Conversion factor to convert tons to metric tons.

[[Page 56424]]

EFproducti = CH4 emission factor for alloy 
product i from Table K-1 in this subpart (kg of CH4 
emissions per metric ton of alloy product i).

    (2) Determine the combined process CH4 emissions from 
the EAFs at your facility using Equation K-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.048

Where:

CH4 = Annual process CH4 emissions from EAFs 
at facility used for the production of ferroalloys listed in Table 
K-1 of this subpart (metric tons).
ECH4j = Annual process CH4 emissions from EAF 
j calculated using Equation K-3 of this section (metric tons).
j = Total number of EAFs at facility used for the production of 
ferroalloys listed in Table K-1 of this subpart.


Sec.  98.114  Monitoring and QA/QC requirements.

    If you determine annual process CO2 emissions using the 
carbon mass balance procedure in Sec.  98.113(b)(2), you must meet the 
requirements specified in paragraphs (a) and (b) of this section.
    (a) Determine the annual mass for each material used for the 
calculations of annual process CO2 emissions using Equation 
K-1 of this subpart by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    (b) For each material identified in paragraph (a) of this section, 
you must determine the average carbon content of the material consumed, 
used, or produced in the calendar year using the methods specified in 
either paragraph (b)(1) or (b)(2) of this section. If you document that 
a specific process input or output contributes less than one percent of 
the total mass of carbon into or out of the process, you do not have to 
determine the monthly mass or annual carbon content of that input or 
output.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material inputs and outputs each year. The carbon content of the 
material must be analyzed at least annually using the standard methods 
(and their QA/QC procedures) specified in paragraphs (b)(2)(i) through 
(b)(2)(iii) of this section, as applicable.
    (i) ASTM E1941-04, Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and Their Alloys (incorporated by 
reference, see Sec.  98.7) for analysis of metal ore and alloy product.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7), for analysis of 
carbonaceous reducing agents and carbon electrodes.
    (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec.  98.7) for analysis of flux materials such as limestone or 
dolomite.


Sec.  98.115  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.113 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) If you determine CO2 emissions for the EAFs at your 
facility using the carbon mass balance procedure in Sec.  98.113(b), 
100 percent data availability is required for the carbon content of the 
input and output materials. You must repeat the test for average carbon 
contents of inputs according to the procedures in Sec.  98.114(b) if 
data are missing.
    (b) For missing records of the monthly mass of carbon-containing 
inputs and outputs, the substitute data value must be based on the best 
available estimate of the mass of the inputs and outputs from on all 
available process data or data used for accounting purposes, such as 
purchase records.
    (c) If you are required to calculate CH4 emissions for 
an EAF at your facility as specified in Sec.  98.113(d), the estimate 
is based an annual quantity of certain alloy products, so 100 percent 
data availability is required.


Sec.  98.116  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (e) of this section, as applicable:
    (a) Annual facility ferroalloy product production capacity (tons).
    (b) Annual production for each ferroalloy product (tons) identified 
in Sec.  98.110, as applicable.
    (c) Total number of EAFs at facility used for production of 
ferroalloy products reported in paragraph (a)(4) of this section.
    (d) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec.  98.37 for the Tier 4 Calculation Methodology and the following 
information specified in paragraphs (d)(1) through (d)(3) of this 
section.
    (1) Annual process CO2 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy listed in Table K-1 
of this subpart (metric tons).
    (2) Annual process CH4 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy listed in Table K-1 
of this subpart (metric tons).
    (3) Identification number of each EAF.
    (e) If a CEMS is not used to measure CO2 process 
emissions, and the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec.  
98.113(b), then you must report the following information specified in 
paragraphs (e)(1) through (e)(7) of this section.
    (1) Annual process CO2 emissions (in metric tons) from 
each EAF used for the production of any ferroalloy listed in Table K-1 
of this subpart (metric tons).
    (3) Identification number for each material.
    (4) Annual material quantity for each material included for the 
calculation of annual process CO2 emissions for each EAF.
    (5) Annual average of the carbon content determinations for each 
material included for the calculation of annual process CO2 
emissions for each EAF (percent by weight, expressed as a decimal 
fraction).
    (6) List the method used for the determination of carbon content 
for each material reported in paragraph (e)(5) of this section (e.g., 
supplier provided information, analyses of representative samples you 
collected).
    (7) If you use the missing data procedures in Sec.  98.115(b), you 
must report how monthly mass of carbon-containing inputs and outputs 
with missing data was determined and the number of months the missing 
data procedures were used.


Sec.  98.117  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section for each EAF, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according 
to the requirements in Sec.  98.113(a), then you must retain under this 
subpart the records required

[[Page 56425]]

for the Tier 4 Calculation Methodology in Sec.  98.37 and the 
information specified in paragraphs (a)(1) through (a)(3) of this 
section.
    (1) Monthly EAF production quantity for each ferroalloy product 
(tons).
    (2) Number of EAF operating hours each month.
    (3) Number of EAF operating hours in a calendar year.
    (b) If the carbon mass balance procedure is used to determine 
CO2 emissions according to the requirements in Sec.  
98.113(b)(2), then you must retain records for the information 
specified in paragraphs (b)(1) through (b)(5) of this section.
    (1) Monthly EAF production quantity for each ferroalloy product 
(tons).
    (2) Number of EAF operating hours each month.
    (3) Number of EAF operating hours in a calendar year.
    (4) Monthly material quantity consumed, used, or produced for each 
material included for the calculations of annual process CO2 
emissions (tons).
    (5) Average carbon content determined and records of the supplier 
provided information or analyses used for the determination for each 
material included for the calculations of annual process CO2 
emissions.
    (c) You must keep records that include a detailed explanation of 
how company records of measurements are used to estimate the carbon 
input and output to each EAF, including documentation of specific input 
or output materials excluded from Equation K-1 of this subpart that 
contribute less than 1 percent of the total carbon into or out of the 
process. You also must document the procedures used to ensure the 
accuracy of the measurements of materials fed, charged, or placed in an 
EAF including, but not limited to, calibration of weighing equipment 
and other measurement devices. The estimated accuracy of measurements 
made with these devices must also be recorded, and the technical basis 
for these estimates must be provided.
    (d) If you are required to calculate CH4 emissions for 
the EAF as specified in Sec.  98.113(d), you must maintain records of 
the total amount of each alloy product produced for the specified 
reporting period, and the appropriate alloy-product specific emission 
factor used to calculate the CH4 emissions.


Sec.  98.118  Definitions.

    All terms used of this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

    Table K-1 to Subpart K of Part 98--Electric Arc Furnace (EAF) CH4
                            Emission Factors
------------------------------------------------------------------------
                                      CH4 emission factor (kg CH4 per
                                            metric ton product)
                                  --------------------------------------
                                               EAF Operation
  Alloy product produced in EAF   --------------------------------------
                                                              Sprinkle-
                                      Batch-     Sprinkle-     charging
                                     charging     charging     and >750
                                                    \a\       [deg]C \b\
------------------------------------------------------------------------
Silicon metal....................          1.5          1.2          0.7
Ferrosilicon 90%.................          1.4          1.1          0.6
Ferrosilicon 75%.................          1.3          1.0          0.5
Ferrosilicon 65%.................          1.3          1.0          0.5
------------------------------------------------------------------------
\a\ Sprinkle-charging is charging intermittently every minute.
\b\ Temperature measured in off-gas channel downstream of the furnace
  hood.

Subpart L--[Reserved]

Subpart M--[Reserved]

Subpart N--Glass Production


Sec.  98.140  Definition of the source category.

    (a) A glass manufacturing facility manufactures flat glass, 
container glass, pressed and blown glass, or wool fiberglass by melting 
a mixture of raw materials to produce molten glass and form the molten 
glass into sheets, containers, fibers, or other shapes. A glass 
manufacturing facility uses one or more continuous glass melting 
furnaces to produce glass.
    (b) A glass melting furnace that is an experimental furnace or a 
research and development process unit is not subject to this subpart.


Sec.  98.141  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a glass production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.142  GHGs to report.

    You must report:
    (a) CO2 process emissions from each continuous glass 
melting furnace.
    (b) CO2 combustion emissions from each continuous glass 
melting furnace.
    (c) CH4 and N2O combustion emissions from 
each continuous glass melting furnace. You must calculate and report 
these emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary fuel combustion unit other than continuous glass 
melting furnaces. You must report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.


Sec.  98.143  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each continuous glass melting furnace using the 
procedure in paragraphs (a) and (b) of this section.
    (a) For each continuous glass melting furnace that meets the 
conditions specified in Sec.  98.33(b)(4)(ii) or (iii), you must 
calculate and report under this subpart the combined process and 
combustion CO2 emissions by operating and maintaining a CEMS 
to measure CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (b) For each continuous glass melting furnace that is not subject 
to the requirements in paragraph (a) of this section, calculate and 
report the process and combustion CO2 emissions from the 
glass melting furnace by using either the procedure in paragraph (b)(1) 
of this section or the procedure in paragraphs (b)(2) through (b)(7) of 
this section, except as specified in paragraph (c) of this section.
    (1) Calculate and report under this subpart the combined process 
and combustion CO2 emissions by operating

[[Page 56426]]

and maintaining a CEMS to measure CO2 emissions according to 
the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (2) Calculate and report the process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(b)(2)(i) through (b)(2)(vi) of this section.
    (i) For each carbonate-based raw material charged to the furnace, 
obtain from the supplier of the raw material the carbonate-based 
mineral mass fraction.
    (ii) Determine the quantity of each carbonate-based raw material 
charged to the furnace.
    (iii) Apply the appropriate emission factor for each carbonate-
based raw material charged to the furnace, as shown in Table N-1 to 
this subpart.
    (iv) Use Equation N-1 of this section to calculate process mass 
emissions of CO2 for each furnace:
[GRAPHIC] [TIFF OMITTED] TR30OC09.049

Where:

ECO2 = Process emissions of CO2 from the 
furnace (metric tons).
n = Number of carbonate-based raw materials charged to furnace.
MFi = Annual average mass fraction of carbonate-based 
mineral i in carbonate-based raw material i (percentage, expressed 
as a decimal).
Mi = Annual amount of carbonate-based raw material i 
charged to furnace (tons).
2000/2205 = Conversion factor to convert tons to metric tons.
EFi = Emission factor for carbonate-based raw material i 
(metric ton CO2 per metric ton carbonate-based raw 
material as shown in Table N-1 to this subpart).
Fi = Fraction of calcination achieved for carbonate-based 
raw material i, assumed to be equal to 1.0 (percentage, expressed as 
a decimal).

    (v) You must calculate the total process CO2 emissions 
from continuous glass melting furnaces at the facility using Equation 
N-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.050


Where:

CO2 = Annual process CO2 emissions from glass 
manufacturing facility (metric tons).
ECO2i = Annual CO2 emissions from glass 
melting furnace i (metric tons).
k = Number of continuous glass melting furnaces.

    (vi) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions in the glass furnace according to the applicable requirements 
in subpart C.
    (c) As an alternative to data provided by the raw material 
supplier, a value of 1.0 can be used for the mass fraction 
(MFi) of carbonate-based mineral i in Equation N-1 of this 
section.


Sec.  98.144  Monitoring and QA/QC requirements.

    (a) You must measure annual amounts of carbonate-based raw 
materials charged to each continuous glass melting furnace from monthly 
measurements using plant instruments used for accounting purposes, such 
as calibrated scales or weigh hoppers. Total annual mass charged to 
glass melting furnaces at the facility shall be compared to records of 
raw material purchases for the year.
    (b) You must measure carbonate-based mineral mass fractions at 
least annually to verify the mass fraction data provided by the 
supplier of the raw material; such measurements shall be based on 
sampling and chemical analysis conducted by a certified laboratory 
using ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major 
and Minor Elements in Combustion Residues from Coal Utilization 
Processes (incorporated by reference, see Sec.  98.7).
    (c) You must determine the annual average mass fraction for the 
carbonate-based mineral in each carbonate-based raw material by 
calculating an arithmetic average of the monthly data obtained from raw 
material suppliers or sampling and chemical analysis.
    (d) You must determine on an annual basis the calcination fraction 
for each carbonate consumed based on sampling and chemical analysis 
using an industry consensus standard. This chemical analysis must be 
conducted using an x-ray fluorescence test or other enhanced testing 
method published by an industry consensus standards organization (e.g., 
ASTM, ASME, API, etc.).


Sec.  98.145  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., carbonate raw materials 
consumed, etc.). If the monitoring and quality assurance procedures in 
Sec.  98.144 cannot be followed and data is missing, you must use the 
most appropriate of the missing data procedures in paragraphs (a) and 
(b) of this section. You must document and keep records of the 
procedures used for all such missing value estimates.
    (a) For missing data on the monthly amounts of carbonate-based raw 
materials charged to any continuous glass melting furnace use the best 
available estimate(s) of the parameter(s), based on all available 
process data or data used for accounting purposes, such as purchase 
records.
    (b) For missing data on the mass fractions of carbonate-based 
minerals in the carbonate-based raw materials assume that the mass 
fraction of each carbonate based mineral is 1.0.


Sec.  98.146  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
and (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required under 
Sec.  98.37 for the Tier 4 Calculation Methodology and the following 
information specified in paragraphs (a)(1) and (a)(2) of this section:
    (1) Annual quantity of each carbonate-based raw material charged to 
each continuous glass melting furnace and for all furnaces combined 
(tons).
    (2) Annual quantity of glass produced (tons).
    (b) If a CEMS is not used to determine CO2 emissions 
from continuous glass melting furnaces, and process CO2 
emissions are calculated according to the procedures specified in Sec.  
98.143(b), then you must report the following information as specified 
in paragraphs (b)(1) through (b)(9) of this section:
    (1) Annual process emissions of CO2 (metric tons) for 
each continuous glass melting furnace and for all furnaces combined.
    (2) Annual quantity of each carbonate-based raw material charged 
(tons) to each continuous glass melting furnace and for all furnaces 
combined.

[[Page 56427]]

    (3) Annual quantity of glass produced (tons) from each continuous 
glass melting furnace and from all furnaces combined.
    (4) Carbonate-based mineral mass fraction (percentage, expressed as 
a decimal) for each carbonate-based raw material charged to a 
continuous glass melting furnace.
    (5) Results of all tests used to verify the carbonate-based mineral 
mass fraction for each carbonate-based raw material charged to a 
continuous glass melting furnace, as specified in paragraphs (b)(5)(i) 
through (b)(5)(iii) of this section.
    (i) Date of test.
    (ii) Method(s) and any variations used in the analyses.
    (iii) Mass fraction of each sample analyzed.
    (6) The fraction of calcination achieved for each carbonate-based 
raw material, if a value other than 1.0 is used to calculate process 
mass emissions of CO2.
    (7) Method used to determine fraction of calcination (percentage, 
expressed as a decimal).
    (8) Total number of continuous glass melting furnaces.
    (9) The number of times in the reporting year that missing data 
procedures were followed to measure monthly quantities of carbonate-
based raw materials any continuous glass melting furnace or mass 
fraction of the carbonate-based minerals (months).


Sec.  98.147  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records listed in paragraphs (a), (b), and (c) of this 
section.
    (a) If a CEMS is used to measure emissions, then you must retain 
the records required under Sec.  98.37 for the Tier 4 Calculation 
Methodology and the following information specified in paragraphs 
(a)(1) and (a)(2) of this section:
    (1) Monthly glass production rate for each continuous glass melting 
furnace (tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (tons).
    (b) If process CO2 emissions are calculated according to 
the procedures specified in Sec.  98.143(b), you must retain the 
records in paragraphs (b)(1) through (b)(5) of this section.
    (1) Monthly glass production rate for each continuous glass melting 
furnace (metric tons).
    (2) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace (metric tons).
    (3) Data on carbonate-based mineral mass fractions provided by the 
raw material supplier for all raw materials consumed annually and 
included in calculating process emissions in Equation N-1 of this 
subpart.
    (4) Results of all tests used to verify the carbonate-based mineral 
mass fraction for each carbonate-based raw material charged to a 
continuous glass melting furnace, including the data specified in 
paragraphs (b)(4)(i) through (b)(4)(v) of this section.
    (i) Date of test.
    (ii) Method(s), and any variations of the methods, used in the 
analyses.
    (iii) Mass fraction of each sample analyzed.
    (iv) Relevant calibration data for the instrument(s) used in the 
analyses.
    (v) Name and address of laboratory that conducted the tests.
    (5) The fraction of calcination achieved for each carbonate-based 
raw material (percentage, expressed as a decimal), if a value other 
than 1.0 is used to calculate process mass emissions of CO2.
    (c) All other documentation used to support the reported GHG 
emissions.


Sec.  98.148  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

 Table N-1 to Subpart N of Part 98--CO2 Emission Factors for Carbonate-
                           Based Raw Materials
------------------------------------------------------------------------
                                                                 CO2
           Carbonate-based raw material--mineral               emission
                                                              factor \a\
------------------------------------------------------------------------
Limestone--CaCO3...........................................        0.440
Dolomite--CaMg(CO3)2.......................................        0.477
Sodium carbonate/soda ash--Na2CO3..........................        0.415
------------------------------------------------------------------------
\a\ Emission factors in units of metric tons of CO2 emitted per metric
  ton of carbonate-based raw material charged to the furnace.

Subpart O--HCFC-22 Production and HFC-23 Destruction


Sec.  98.150  Definition of the source category.

    The HCFC-22 production and HFC-23 destruction source category 
consists of HCFC-22 production processes and HFC-23 destruction 
processes.
    (a) An HCFC-22 production process produces HCFC-22 
(chlorodifluoromethane, or CHClF2) from chloroform 
(CHCl3) and hydrogen fluoride (HF).
    (b) An HFC-23 destruction process is any process in which HFC-23 
undergoes destruction. An HFC-23 destruction process may or may not be 
co-located with an HCFC-22 production process at the same facility.


Sec.  98.151  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an HCFC-22 production or HFC-23 destruction process and the 
facility meets the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.152  GHGs to report.

    (a) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.
    (b) You must report HFC-23 emissions from HCFC-22 production 
processes and HFC-23 destruction processes.


Sec.  98.153  Calculating GHG emissions.

    (a) The mass of HFC-23 generated from each HCFC-22 production 
process shall be estimated by using one of two methods, as applicable:
    (1) Where the mass flow of the combined stream of HFC-23 and 
another reaction product (e.g., HCl) is measured, multiply the weekly 
(or more frequent) HFC-23 concentration measurement (which may be the 
average of more frequent concentration measurements) by the weekly (or 
more frequent) mass flow of the combined stream of HFC-23 and the other 
product. To estimate annual HFC-23 production, sum the weekly (or more 
frequent) estimates of the quantities of HFC-23 produced over the year. 
This calculation is summarized in Equation O-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.051

Where:

G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HFC-23/other product 
stream.
Fp = Mass flow of HFC-23/other product stream during the 
period p (kg).
p = Period over which mass flows and concentrations are measured.
n = Number of concentration and flow measurement periods for the 
year.
10-3 = Conversion factor from kilograms to metric tons.

    (2) Where the mass of only a reaction product other than HFC-23 
(either HCFC-22 or HCl) is measured, multiply the ratio of the weekly 
(or more frequent) measurement of the HFC-23 concentration and the 
weekly (or more frequent) measurement of the other product 
concentration by the weekly (or more frequent) mass produced of the 
other product. To estimate annual HFC-23 production, sum the weekly (or 
more

[[Page 56428]]

frequent) estimates of the quantities of HFC-23 produced over the year. 
This calculation is summarized in Equation O-2 of this section, 
assuming that the other product is HCFC-22. If the other product is 
HCl, HCl may be substituted for HCFC-22 in Equations O-2 and O-3 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.052

Where:

G23 = Mass of HFC-23 generated annually (metric tons).
c23 = Fraction HFC-23 by weight in HCFC-22/HFC-23 stream.
c22 = Fraction HCFC-22 by weight in HCFC-22/HFC-23 
stream.
P22 = Mass of HCFC-22 produced over the period p (kg), 
calculated using Equation O-3 of this section.
p = Period over which masses and concentrations are measured.
n = Number of concentration and mass measurement periods for the 
year.
10-3 = Conversion factor from kilograms to metric tons.

    (b) The mass of HCFC-22 produced over the period p shall be 
estimated by using Equation O-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.053

Where:

P22 = Mass of HCFC-22 produced over the period p (kg).
O22 = mass of HCFC-22 that is measured coming out of the 
Production process over the period p (kg).
U22 = Mass of used HCFC-22 that is added to the 
production process upstream of the output measurement over the 
period p (kg).
LF = Factor to account for the loss of HCFC-22 upstream of the 
measurement. The value for LF shall be determined pursuant to Sec.  
98.154(e).

    (c) For HCFC-22 production facilities that do not use a thermal 
oxidizer or that have a thermal oxidizer that is not directly connected 
to the HCFC-22 production equipment, HFC-23 emissions shall be 
estimated using Equation O-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.054

Where:

E23 = Mass of HFC-23 emitted annually (metric tons).
G23 = Mass of HFC-23 generated annually (metric tons).
S23 = Mass of HFC-23 sent off site for sale annually 
(metric tons).
OD23 = Mass of HFC-23 sent off site for destruction 
(metric tons).
D23 = Mass of HFC-23 destroyed on site (metric tons).
I23 = Increase in HFC-23 inventory = HFC-23 in storage at 
end of year--HFC-23 in storage at beginning of year (metric tons).

    (d) For HCFC-22 production facilities that use a thermal oxidizer 
connected to the HCFC-22 production equipment, HFC-23 emissions shall 
be estimated using Equation O-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.055

Where:

E23 = Mass of HFC-23 emitted annually (metric tons).
EL = Mass of HFC-23 emitted annually from equipment 
leaks, calculated using Equation O-6 of this section (metric tons).
EPV = Mass of HFC-23 emitted annually from process vents, 
calculated using Equation O-7 of this section (metric tons).
ED = Mass of HFC-23 emitted annually from thermal 
oxidizer (metric tons), calculated using Equation O-8 of this 
section.

    (1) The mass of HFC-23 emitted annually from equipment leaks (for 
use in Equation O-5 of this section) shall be estimated by using 
Equation O-6 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.056

Where:

EL = Mass of HFC-23 emitted annually from equipment leaks 
(metric tons).
c23 = Fraction HFC-23 by weight in the stream(s) in the 
equipment.
FGt = The applicable leak rate specified in Table O-1 of 
this subpart for each source of equipment type and service t with a 
screening value greater than or equal to 10,000 ppmv (kg/hr/source).
NGt = The number of sources of equipment type and service 
t with screening values greater than or equal to 10,000 ppmv as 
determined according to Sec.  98.154(i).
FLt = The applicable leak rate specified in Table O-1 of 
this subpart for each source of equipment type and service t with a 
screening value of less than 10,000 ppmv (kg/hr/source).
NLt = The number of sources of equipment type and service 
t with screening values less than 10,000 ppmv as determined 
according to Sec.  98.154(j).
p = One hour.
n = Number of hours during the year during which equipment contained 
HFC-23.
t = Equipment type and service as specified in Table O-1 of this 
subpart .
10-3 = Factor converting kg to metric tons.

    (2) The mass of HFC-23 emitted annually from process vents (for use 
in Equation O-5 of this section) shall be estimated by using Equation 
O-7 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.057

Where:

EPV = Mass of HFC-23 emitted annually from process vents 
(metric tons).
ERT = The HFC-23 emission rate from the process vents 
during the period of the most recent test (kg/hr).
PRp = The HCFC-22 production rate during the period p 
(kg/hr).
PRT = The HCFC-22 production rate during the most recent 
test period (kg/hr).
lp = The length of the period p (hours).
10-3 = Factor converting kg to metric tons.
n = The number of periods in a year.

    (3) The total mass of HFC-23 emitted from destruction devices shall 
be estimated by using Equation O-8 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.058


[[Page 56429]]


Where:

ED = Mass of HFC-23 emitted annually from the destruction 
device (metric tons).
FD = Mass of HFC-23 fed into the destruction device 
annually (metric tons).
D23 = Mass of HFC-23 destroyed annually (metric tons).

    (4) For facilities that destroy HFC-23, the total mass of HFC-23 
destroyed shall be estimated by using Equation O-9 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.059

Where:

D23 = Mass of HFC-23 destroyed annually (metric tons).
FD = Mass of HFC-23 fed into the destruction device 
annually (metric tons).
DE = Destruction Efficiency of the destruction device (fraction).

Sec.  98.154  Monitoring and QA/QC requirements.

    These requirements apply to measurements that are reported under 
this subpart or that are used to estimate reported quantities pursuant 
to Sec.  98.153.
    (a) The concentrations (fractions by weight) of HFC-23 and HCFC-22 
in the product stream shall be measured at least weekly using equipment 
and methods (e.g., gas chromatography) with an accuracy and precision 
of 5 percent or better at the concentrations of the process samples.
    (b) The mass flow of the product stream containing the HFC-23 shall 
be measured at least weekly using weigh scales, flowmeters, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (c) The mass of HCFC-22 or HCl coming out of the production process 
shall be measured at least weekly using weigh scales, flowmeters, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (d) The mass of any used HCFC-22 added back into the production 
process upstream of the output measurement in paragraph (c) of this 
section shall be measured (when being added) using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 1.0 percent of full scale or better. If the 
mass in paragraph (c) of this section is measured by weighing 
containers that include returned heels as well as newly produced 
fluorinated GHGs, the returned heels shall be considered used 
fluorinated HCFC-22 for purposes of this paragraph (d) of this section 
and Sec.  98.153(b).
    (e) The loss factor LF in Equation O-3 of this subpart for the mass 
of HCFC-22 produced shall have the value 1.015 or another value that 
can be demonstrated, to the satisfaction of the Administrator, to 
account for losses of HCFC-22 between the reactor and the point of 
measurement at the facility where production is being estimated.
    (f) The mass of HFC-23 sent off site for sale shall be measured at 
least weekly (when being packaged) using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better.
    (g) The mass of HFC-23 sent off site for destruction shall be 
measured at least weekly (when being packaged) using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 1.0 percent of full scale or better. If the 
measured mass includes more than trace concentrations of materials 
other than HFC-23, the concentration of the fluorinated GHG shall be 
measured at least weekly using equipment and methods (e.g., gas 
chromatography) with an accuracy and precision of 5 percent or better 
at the concentrations of the process samples. This concentration (mass 
fraction) shall be multiplied by the mass measurement to obtain the 
mass of the HFC-23 sent to another facility for destruction.
    (h) The masses of HFC-23 in storage at the beginning and end of the 
year shall be measured using flowmeters, weigh scales, or a combination 
of volumetric and density measurements with an accuracy and precision 
of 1.0 percent of full scale or better.
    (i) The number of sources of equipment type t with screening values 
greater than or equal to 10,000 ppmv shall be determined using EPA 
Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as 
follows:
    (1) A leak source that could emit HFC-23, and
    (2) A leak source at whose surface a concentration of fluorocarbons 
equal to or greater than 10,000 ppm is measured.
    (j) The number of sources of equipment type t with screening values 
less than 10,000 ppmv shall be the difference between the number of 
leak sources of equipment type t that could emit HFC-23 and the number 
of sources of equipment type t with screening values greater than or 
equal to 10,000 ppmv as determined under paragraph (h) of this section.
    (k) The mass of HFC-23 emitted from process vents shall be 
estimated at least monthly by incorporating the results of the most 
recent emissions test into Equation O-6 of this subpart. HCFC-22 
production facilities that use a thermal oxidizer connected to the 
HCFC-22 production equipment shall conduct emissions tests at process 
vents at least once every five years or after significant changes to 
the process. Emissions tests shall be conducted in accordance with EPA 
Method 18 at 40 CFR part 60, appendix A-6, under conditions that are 
typical for the production process at the facility. The sensitivity of 
the tests shall be sufficient to detect an emission rate that would 
result in annual emissions of 200 kg of HFC-23 if sustained over one 
year.
    (l) For purposes of Equation O-9 of this subpart, the destruction 
efficiency must be equated to the destruction efficiency determined 
during a new or previous performance test of the destruction device. 
HFC-23 destruction facilities shall conduct annual measurements of HFC-
23 concentrations at the outlet of the thermal oxidizer in accordance 
with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall 
be taken under conditions that are typical for the production process 
and destruction device at the facility, and the average concentration 
of HFC-23 shall be determined. The sensitivity of the concentration 
measurement shall be sufficient to detect an outlet concentration equal 
to or less than the outlet concentration determined in the destruction 
efficiency performance test. If the concentration measurement indicates 
that the HFC-23 concentration is less than or equal to that measured 
during the performance test that is the basis for the destruction 
efficiency, continue to use the previously determined destruction 
efficiency. If the concentration measurement indicates that the HFC-23 
concentration is greater than that measured during the performance test 
that is the basis for the destruction efficiency, facilities shall 
either:
    (1) Substitute the higher HFC-23 concentration for that measured 
during the destruction efficiency performance test and calculate a new 
destruction efficiency, or
    (2) Estimate the mass emissions of HFC-23 from the destruction 
device based on the measured HFC-23 concentration and volumetric flow 
rate determined by measurement of volumetric flow rate using EPA Method 
2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40 
CFR part 60, appendix A-2. Determine the mass rate of HFC-23 into the 
destruction device by measuring the HFC-23 concentration and volumetric 
flow rate at the inlet or by a metering device for HFC-23 sent to the 
device. Determine a new destruction efficiency

[[Page 56430]]

based on the mass flow rate of HFC-23 into and out of the destruction 
device.
    (m) HCFC-22 production facilities shall account for HFC-23 
generation and emissions that occur as a result of startups, shutdowns, 
and malfunctions, either recording HFC-23 generation and emissions 
during these events, or documenting that these events do not result in 
significant HFC-23 generation and/or emissions.
    (n) The mass of HFC-23 fed into the destruction device shall be 
measured at least weekly using flow meters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 1.0 percent of full scale or better. If the measured mass 
includes more than trace concentrations of materials other than HFC-23, 
the concentrations of the HFC-23 shall be measured at least weekly 
using equipment and methods (e.g., gas chromatography) with an accuracy 
and precision of 5 percent or better at the concentrations of the 
process samples. This concentration (mass fraction) shall be multiplied 
by the mass measurement to obtain the mass of the HFC-23 destroyed.
    (o) In their estimates of the mass of HFC-23 destroyed, HFC-23 
destruction facilities shall account for any temporary reductions in 
the destruction efficiency that result from any startups, shutdowns, or 
malfunctions of the destruction device, including departures from the 
operating conditions defined in state or local permitting requirements 
and/or oxidizer manufacturer specifications.
    (p) Calibrate all flow meters, weigh scales, and combinations of 
volumetric and density measures using NIST-traceable standards and 
suitable methods published by a consensus standards organization (e.g., 
ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, 
and combinations of volumetric and density measures at the minimum 
frequency specified by the manufacturer.
    (q) All gas chromatographs used to determine the concentration of 
HFC-23 in process streams shall be calibrated at least monthly through 
analysis of certified standards (or of calibration gases prepared from 
a high-concentration certified standard using a gas dilution system 
that meets the requirements specified in Method 205 at 40 CFR part 51, 
appendix M) with known HFC-23 concentrations that are in the same range 
(fractions by mass) as the process samples.


Sec.  98.155  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required process sample is 
not taken), a substitute data value for the missing parameter shall be 
used in the calculations, according to the following requirements:
    (1) For each missing value of the HFC-23 or HCFC-22 concentration, 
the substitute data value shall be the arithmetic average of the 
quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If, for a particular 
parameter, no quality-assured data are available prior to the missing 
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
    (2) For each missing value of the product stream mass flow or 
product mass, the substitute value of that parameter shall be a 
secondary product measurement where such a measurement is available. If 
that measurement is taken significantly downstream of the usual mass 
flow or mass measurement (e.g., at the shipping dock rather than near 
the reactor), the measurement shall be multiplied by 1.015 to 
compensate for losses. Where a secondary mass measurement is not 
available, the substitute value of the parameter shall be an estimate 
based on a related parameter. For example, if a flowmeter measuring the 
mass fed into a destruction device is rendered inoperable, then the 
mass fed into the destruction device may be estimated using the 
production rate and the previously observed relationship between the 
production rate and the mass flow rate into the destruction device.


Sec.  98.156  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), the 
HCFC-22 production facility shall report the following information at 
the facility level:
    (1) Annual mass of HCFC-22 produced in metric tons.
    (2) Loss Factor used to account for the loss of HCFC- 22 upstream 
of the measurement.
    (3) Annual mass of reactants fed into the process in metric tons of 
reactant.
    (4) The mass (in metric tons) of materials other than HCFC-22 and 
HFC-23 (i.e., unreacted reactants, HCl and other by-products) that 
occur in more than trace concentrations and that are permanently 
removed from the process.
    (5) The method for tracking startups, shutdowns, and malfunctions 
and HFC-23 generation/emissions during these events.
    (6) The names and addresses of facilities to which any HFC-23 was 
sent for destruction, and the quantities of HFC-23 (metric tons) sent 
to each.
    (7) Annual mass of the HFC-23 generated in metric tons.
    (8) Annual mass of any HFC-23 sent off site for sale in metric 
tons.
    (9) Annual mass of any HFC-23 sent off site for destruction in 
metric tons.
    (10) Mass of HFC-23 in storage at the beginning and end of the 
year, in metric tons.
    (11) Annual mass of HFC-23 emitted in metric tons.
    (12) Annual mass of HFC-23 emitted from equipment leaks in metric 
tons.
    (13) Annual mass of HFC-23 emitted from process vents in metric 
tons.
    (b) In addition to the information required by Sec.  98.3(c), 
facilities that destroy HFC-23 shall report the following for each HFC-
23 destruction process:
    (1) Annual mass of HFC-23 fed into the thermal oxidizer.
    (2) Annual mass of HFC-23 destroyed.
    (3) Annual mass of HFC-23 emitted from the thermal oxidizer.
    (c) Each HFC-23 destruction facility shall report the results of 
the facility's annual HFC-23 concentration measurements at the outlet 
of the destruction device, including:
    (1) Flow rate of HFC-23 being fed into the destruction device in 
kg/hr.
    (2) Concentration (mass fraction) of HFC-23 at the outlet of the 
destruction device.
    (3) Flow rate at the outlet of the destruction device in kg/hr.
    (d) Emission rate calculated from paragraphs (c)(2) and (3) of this 
section in kg/hr.
    (e) HFC-23 destruction facilities shall submit a one-time report 
including the following information for each the destruction process:
    (1) Destruction efficiency (DE).
    (2) The methods used to determine destruction efficiency.
    (3) The methods used to record the mass of HFC-23 destroyed.
    (4) The name of other relevant federal or state regulations that 
may apply to the destruction process.
    (5) If any changes are made that affect HFC-23 destruction 
efficiency or the methods used to record volume destroyed, then these 
changes must be reflected in a revision to this report. The revised 
report must be submitted to EPA within 60 days of the change.

[[Page 56431]]

Sec.  98.157  Records that must be retained.

    (a) In addition to the data required by Sec.  98.3(g), HCFC-22 
production facilities shall retain the following records:
    (1) The data used to estimate HFC-23 emissions.
    (2) Records documenting the initial and periodic calibration of the 
gas chromatographs, weigh scales, volumetric and density measurements, 
and flowmeters used to measure the quantities reported under this rule, 
including the industry standards or manufacturer directions used for 
calibration pursuant to Sec.  98.154(p) and (q).
    (b) In addition to the data required by Sec.  98.3(g), the HFC-23 
destruction facilities shall retain the following records:
    (1) Records documenting their one-time and annual reports in Sec.  
98.156(b) through (d).
    (2) Records documenting the initial and periodic calibration of the 
gas chromatographs, weigh scales, volumetric and density measurements, 
and flowmeters used to measure the quantities reported under this 
subpart, including the industry standard practice or manufacturer 
directions used for calibration pursuant to Sec.  98.154(p) and (q).


Sec.  98.158  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

 Table O-1 to Subpart O of Part 98--Emission Factors for Equipment Leaks
------------------------------------------------------------------------
                                                 Emission factor (kg/hr/
                                                         source)
        Equipment type             Service     -------------------------
                                                  >=10,000     <10,000
                                                    ppmv         ppmv
------------------------------------------------------------------------
Valves.......................  Gas............       0.0782     0.000131
Valves.......................  Light liquid...       0.0892     0.000165
Pump seals...................  Light liquid...        0.243      0.00187
Compressor seals.............  Gas............        1.608       0.0894
Pressure relief valves.......  Gas............        1.691       0.0447
Connectors...................  All............        0.113    0.0000810
Open-ended lines.............  All............      0.01195      0.00150
------------------------------------------------------------------------

Subpart P--Hydrogen Production


Sec.  98.160  Definition of the source category.

    (a) A hydrogen production source category consists of facilities 
that produce hydrogen gas sold as a product to other entities.
    (b) This source category comprises process units that produce 
hydrogen by reforming, gasification, oxidation, reaction, or other 
transformations of feedstocks.
    (c) This source category includes merchant hydrogen production 
facilities located within a petroleum refinery if they are not owned 
by, or under the direct control of, the refinery owner and operator.


Sec.  98.161  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a hydrogen production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.162  GHGs to report.

    You must report:
    (a) CO2 process emissions from each hydrogen production 
process unit.
    (b) CO2, CH4 and N2O combustion 
emissions from each hydrogen production process unit. You must 
calculate and report these combustion emissions under subpart C of this 
part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.
    (c) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than hydrogen production 
process units. You must calculate and report these emissions under 
subpart C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.
    (d) For CO2 collected and transferred off site, you must 
follow the requirements of subpart PP of this part.


Sec.  98.163  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each hydrogen production process unit using the 
procedures specified in either paragraph (a) or (b) of this section.
    (a) Continuous Emissions Montoring Systems (CEMS). Calculate and 
report under this subpart the process CO2 emissions by 
operating and maintaining CEMS according to the Tier 4 Calculation 
Methodology specified in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (b) Fuel and feedstock material balance approach. Calculate and 
report process CO2 emissions as the sum of the annual 
emissions associated with each fuel and feedstock used for hydrogen 
production by following paragraphs (b)(1) through (b)(3) of this 
section.
    (1) Gaseous fuel and feedstock. You must calculate the annual 
CO2 process emissions from gaseous fuel and feedstock 
according to Equation P-1 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.060

Where:

CO2 = Annual CO2 process emissions arising 
from fuel and feedstock consumption (metric tons/yr).
Fdstkn = Volume of the gaseous fuel and feedstock used in 
month n (scf (at standard conditions of 68 [deg]F and atmospheric 
pressure) of fuel and feedstock).
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).
MW = Molecular weight of the gaseous fuel and feedstock (kg/kg-
mole).

[[Page 56432]]

MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon. 0.001 
= Conversion factor from kg to metric tons.

    (2) Liquid fuel and feedstock. You must calculate the annual 
CO2 process emissions from liquid fuel and feedstock 
according to Equation P-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.061

Where:

CO2 = Annual CO2 emissions arising from fuel 
and feedstock consumption (metric tons/yr).
Fdstkn = Volume of the liquid fuel and feedstock used in 
month n (gallons of fuel and feedstock).
CCn = Average carbon content of the liquid fuel and 
feedstock, from the results of one or more analyses for month n (kg 
carbon per gallon of fuel and feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (3) Solid fuel and feedstock. You must calculate the annual 
CO2 process emissions from solid fuel and feedstock 
according to Equation P-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.062

Where:

CO2 = Annual CO2 emissions from fuel and 
feedstock consumption in metric tons per month (metric tons/yr).
Fdstkn = Mass of solid fuel and feedstock used in month n 
(kg of fuel and feedstock).
CCn = Average carbon content of the solid fuel and 
feedstock, from the results of one or more analyses for month n (kg 
carbon per kg of fuel and feedstock).
k = Months in the year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (c) If GHG emissions from a hydrogen production process unit are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).


Sec.  98.164  Monitoring and QA/QC requirements.

    The GHG emissions data for hydrogen production process units must 
be quality-assured as specified in paragraphs (a) or (b) of this 
section, as appropriate for each process unit:
    (a) If a CEMS is used to measure GHG emissions, then the facility 
must comply with the monitoring and QA/QC procedures specified in Sec.  
98.34(c).
    (b) If a CEMS is not used to measure GHG emissions, then you must:
    (1) Calibrate all oil and gas flow meters (except for gas billing 
meters), solids weighing equipment, and oil tank drop measurements (if 
used to determine liquid fuel and feedstock use volume) according to 
the calibration accuracy requirements in Sec.  98.3(i) of this part.
    (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), weekly sampling and 
analysis is required to determine the carbon content and molecular 
weight of the fuel and feedstock.
    (3) Determine the carbon content of fuel oil, naphtha, and other 
liquid fuels and feedstocks at least monthly, except annually for 
standard liquid hydrocarbon fuels and feedstocks having consistent 
composition, or upon delivery for liquid fuels delivered by bulk 
transport (e.g., by truck or rail).
    (4) Determine the carbon content of coal, coke, and other solid 
fuels and feedstocks at least monthly, except annually for standard 
solid hydrocarbon fuels and feedstocks having consistent composition, 
or upon delivery for solid fuels delivered by bulk transport (e.g., by 
truck or rail).
    (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.
    (i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for 
Analysis of Reformed Gas by Gas Chromatography (incorporated by 
reference, see Sec.  98.7).
    (iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for 
Analysis (incorporated by reference, see Sec.  98.7).
    (iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a 
Gross Sample of Coal (incorporated by reference, see Sec.  98.7).
    (v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for 
Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing 
Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by 
reference, see Sec.  98.7).
    (vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for 
Ultimate Analysis of Coal and Coke (incorporated by reference, see 
Sec.  98.7).
    (vii) 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 (incorporated by reference, see 
Sec.  98.7).
    (viii) ASTM D4057-06 Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products (incorporated by reference, see Sec.  
98.7).

[[Page 56433]]

    (ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for 
Automatic Sampling of Petroleum and Petroleum Products (incorporated by 
reference, see Sec.  98.7).
    (x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec.  
98.7).
    (xi) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7).
    (xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal 
(incorporated by reference, see Sec.  98.7).
    (xiii) ASTM D6883-04 Standard Practice for Manual Sampling of 
Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles 
(incorporated by reference, see Sec.  98.7).
    (xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of 
Coal (incorporated by reference, see Sec.  98.7).
    (xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography (incorporated by reference, see Sec.  
98.7).
    (xvii) ISO 3170: Petroleum Liquids--Manual sampling--Third Edition 
(incorporated by reference, see Sec.  98.7).
    (xviii) ISO 3171: Petroleum Liquids--Automatic pipeline sampling--
Second Edition (incorporated by reference, see Sec.  98.7).
    (c) For units using the calculation methodologies described in this 
section, the records required under Sec.  98.3(g) must include both the 
company records and a detailed explanation of how company records are 
used to estimate the following:
    (1) Fuel and feedstock consumption, when solid fuel and feedstock 
is combusted and a CEMS is not used to measure GHG emissions.
    (2) Fossil fuel consumption, when, pursuant to Sec.  98.33(e), the 
owner or operator of a unit that uses CEMS to quantify CO2 
emissions and that combusts both fossil and biogenic fuels separately 
reports the biogenic portion of the total annual CO2 
emissions.
    (3) Sorbent usage, if the methodology in Sec.  98.33(d) is used to 
calculate CO2 emissions from sorbent.
    (d) The owner or operator must document the procedures used to 
ensure the accuracy of the estimates of fuel and feedstock usage and 
sorbent usage (as applicable) in paragraph (b) of this section, 
including, but not limited to, calibration of weighing equipment, fuel 
and feedstock flow meters, and other measurement devices. The estimated 
accuracy of measurements made with these devices must also be recorded, 
and the technical basis for these estimates must be provided.


Sec.  98.165  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation), a substitute data value for the 
missing parameter must be used in the calculations as specified in 
paragraphs (a), (b), and (c) of this section:
    (a) For each missing value of the monthly fuel and feedstock 
consumption, the substitute data value must be the best available 
estimate of the fuel and feedstock consumption, based on all available 
process data (e.g., hydrogen production, electrical load, and operating 
hours). You must document and keep records of the procedures used for 
all such estimates.
    (b) For each missing value of the carbon content or molecular 
weight of the fuel and feedstock, the substitute data value must be the 
arithmetic average of the quality-assured values of carbon contents or 
molecular weight of the fuel and feedstock immediately preceding and 
immediately following the missing data incident. If no quality-assured 
data on carbon contents or molecular weight of the fuel and feedstock 
are available prior to the missing data incident, the substitute data 
value must be the first quality-assured value for carbon contents or 
molecular weight of the fuel and feedstock obtained after the missing 
data period. You must document and keep records of the procedures used 
for all such estimates.
    (c) For missing CEMS data, you must use the missing data procedures 
in Sec.  98.35.


Sec.  98.166  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as appropriate:
    (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):
    (1) Unit identification number and annual CO2 process 
emissions.
    (2) Annual quantity of hydrogen produced (metric tons) for each 
process unit and for all units combined.
    (3) Annual quantity of ammonia produced (metric tons), if 
applicable, for each process unit and for all units combined.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the following information for each hydrogen production 
process unit:
    (1) Unit identification number and annual CO2 process 
emissions.
    (2) Monthly consumption of each fuel and feedstock used for 
hydrogen production and its type (scf of gaseous fuels and feedstocks, 
gallons of liquid fuels and feedstocks, kg of solid fuels and 
feedstocks).
    (3) Annual quantity of hydrogen produced (metric tons).
    (4) Annual quantity of ammonia produced, if applicable (metric 
tons).
    (5) Monthly analyses of carbon content for each fuel and feedstock 
used in hydrogen production (kg carbon/kg of gaseous and solid fuels 
and feedstocks, (kg carbon per gallon of liquid fuels and feedstocks).
    (6) Monthly analyses of the molecular weight of gaseous fuels and 
feedstocks (kg/kg-mole) used, if any.
    (c) Quarterly quantity of CO2 collected and transferred 
off site in either gas, liquid, or solid forms (kg), following the 
requirements of subpart PP of this part.
    (d) Annual quantity of carbon other than CO2 collected 
and transferred off site in either gas, liquid, or solid forms (kg 
carbon).


Sec.  98.167  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (b) of this 
section for each hydrogen production facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec.  98.37.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must retain records of all analyses and calculations conducted as 
listed in Sec. Sec.  98.166(b), (c), and (d).


Sec.  98.168  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart Q--Iron and Steel Production


Sec.  98.170  Definition of the source category.

    The iron and steel production source category includes facilities 
with any of the following processes: taconite iron

[[Page 56434]]

ore processing, integrated iron and steel manufacturing, cokemaking not 
colocated with an integrated iron and steel manufacturing process, and 
electric arc furnace (EAF) steelmaking not colocated with an integrated 
iron and steel manufacturing process. Integrated iron and steel 
manufacturing means the production of steel from iron ore or iron ore 
pellets. At a minimum, an integrated iron and steel manufacturing 
process has a basic oxygen furnace for refining molten iron into steel. 
Each cokemaking process and EAF process located at a facility with an 
integrated iron and steel manufacturing process is part of the 
integrated iron and steel manufacturing facility.


Sec.  98.171  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains an iron and steel production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.172  GHGs to report.

    (a) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C except for flares. Stationary 
combustion units include, but are not limited to, by-product recovery 
coke oven battery combustion stacks, blast furnace stoves, boilers, 
process heaters, reheat furnaces, annealing furnaces, flame 
suppression, ladle reheaters, and other miscellaneous combustion 
sources.
    (b) You must report CO2 emissions from flares according 
to the procedures in Sec.  98.253(b)(1) of subpart Y (Petroleum 
Refineries) of this part except you must use the default CO2 
emission factors for coke oven gas and blast furnace gas from Table C-1 
of subpart C in Equation Y-1 of subpart Y of this part. You must report 
CH4 and N2O emissions from flares according to 
the requirements in Sec.  98.33(c)(2) using the emission factors for 
coke oven gas and blast furnace gas in Table C-2 of subpart C of this 
part.
    (c) You must report process CO2 emissions from each 
taconite indurating furnace; basic oxygen furnace; non-recovery coke 
oven battery combustion stack; coke pushing process; sinter process; 
EAF; argon-oxygen decarburization vessel; and direct reduction furnace 
by following the procedures in this subpart.


Sec.  98.173  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each taconite indurating furnace, basic oxygen furnace, 
non-recovery coke oven battery, sinter process, EAF, argon-oxygen 
decarburization vessel, and direct reduction furnace using the 
procedures in either paragraph (a) or (b) of this section. Calculate 
and report the annual process CO2 emissions from the coke 
pushing process according to paragraph (c) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions using the procedure in paragraph (b)(1) or 
(b)(2) of this section.
    (1) Carbon mass balance method. Calculate the annual mass emissions 
of CO2 for the process as specified in paragraphs (b)(1)(i) 
through (b)(1)(vii) of this section. The calculations are based on the 
annual mass of inputs and outputs to the process and an annual analysis 
of the respective weight fraction of carbon as determined according to 
the procedures in Sec.  98.174(b). If you have a process input or 
output other than CO2 in the exhaust gas that contains 
carbon that is not included in Equations Q-1 through Q-7 of this 
section, you must account for the carbon and mass rate of that process 
input or output in your calculations according to the procedures in 
Sec.  98.174(b)(5).
    (i) For taconite indurating furnaces, estimate CO2 
emissions using Equation Q-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.063

Where:

CO2 = Annual CO2 mass emissions from the 
taconite indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fs) = Annual mass of the solid fuel combusted (metric 
tons).
(Csf) = Carbon content of the solid fuel, from the fuel 
analysis (percent by weight, expressed as a decimal fraction, e.g., 
95% = 0.95).
(Fg) = Annual volume of the gaseous fuel combusted (scf).
(Cgf) = Average carbon content of the gaseous fuel, from 
the fuel analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
0.001 = Conversion factor from kg to metric tons.
(Fl) = Annual volume of the liquid fuel combusted 
(gallons).
(Clf) = Carbon content of the liquid fuel, from the fuel 
analysis results (kg C per gallon of fuel).
(O) = Annual mass of greenball (taconite) pellets fed to the furnace 
(metric tons).
(C0) = Carbon content of the greenball (taconite) 
pellets, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).
(P) = Annual mass of fired pellets produced by the furnace (metric 
tons).
(Cp) = Carbon content of the fired pellets, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (ii) For basic oxygen process furnaces, estimate CO2 
emissions using Equation Q-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.064


[[Page 56435]]


Where:

CO2 = Annual CO2 mass emissions from the basic 
oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron) = Annual mass of molten iron charged to the furnace (metric 
tons).
(CIron) = Carbon content of the molten iron, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(Scrap) = Annual mass of ferrous scrap charged to the furnace 
(metric tons).
(CScrap) = Carbon content of the ferrous scrap, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) 
charged to the furnace (metric tons).
(CFlux) = Carbon content of the flux materials, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
from the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(Steel) = Annual mass of molten raw steel produced by the furnace 
(metric tons).
(CSteel) = Carbon content of the steel, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(Slag) = Annual mass of slag produced by the furnace (metric tons).
(CSlag) = Carbon content of the slag, from the carbon 
analysis (percent by weight, expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (iii) For non-recovery coke oven batteries, estimate CO2 
emissions using Equation Q-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.065

Where:

CO2 = Annual CO2 mass emissions from the non-
recovery coke oven battery (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Coal) = Annual mass of coal charged to the battery (metric tons).
(CCoal) = Carbon content of the coal, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(Coke) = Annual mass of coke produced by the battery (metric tons).
(CCoke) = Carbon content of the coke, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (iv) For sinter processes, estimate CO2 emissions using 
Equation Q-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.066

Where:

CO2 = Annual CO2 mass emissions from the 
sinter process (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg) = Annual volume of the gaseous fuel combusted (scf).
(Cgf) = Carbon content of the gaseous fuel, from the fuel 
analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
0.001 = Conversion factor from kg to metric tons.
(Feed) = Annual mass of sinter feed material (metric tons).
(CFeed) = Carbon content of the mixed sinter feed 
materials that form the bed entering the sintering machine, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(Sinter) = Annual mass of sinter produced (metric tons).
(CSinter) = Carbon content of the sinter pellets, from 
the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (v) For EAFs, estimate CO2 emissions using Equation Q-5 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.067

Where:

CO2 = Annual CO2 mass emissions from the EAF 
(metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron) = Annual mass of direct reduced iron (if any) charged to the 
furnace (metric tons).
(CIron) = Carbon content of the direct reduced iron, from 
the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(Scrap) = Annual mass of ferrous scrap charged to the furnace 
(metric tons).
(CScrap) = Carbon content of the ferrous scrap, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
(Flux) = Annual mass of flux materials (e.g., limestone, dolomite) 
charged to the furnace (metric tons).
(CFlux) = Carbon content of the flux materials, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).

[[Page 56436]]

(Electrode) = Annual mass of carbon electrode consumed (metric 
tons).
(CElectrode) = Carbon content of the carbon electrode, 
from the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
from the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(Steel) = Annual mass of molten raw steel produced by the furnace 
(metric tons).
(CSteel) = Carbon content of the steel, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(Slag) = Annual mass of slag produced by the furnace (metric tons).
(CSlag) = Carbon content of the slag, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (vi) For argon-oxygen decarburization vessels, estimate 
CO2 emissions using Equation Q-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.068

Where:

CO2 = Annual CO2 mass emissions from the 
argon-oxygen decarburization vessel (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Steel) = Annual mass of molten steel charged to the vessel (metric 
tons).
(CSteelin) = Carbon content of the molten steel before 
decarburization, from the carbon analysis results (percent by 
weight, expressed as a decimal fraction).
(CSteelout) = Carbon content of the molten steel after 
decarburization, from the carbon analysis results (percent by 
weight, expressed as a decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (vii) For direct reduction furnaces, estimate CO2 
emissions using Equation Q-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.069

Where:

CO2 = Annual CO2 mass emissions from the 
direct reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg) = Annual volume of the gaseous fuel combusted (scf).
(Cgf) = Carbon content of the gaseous fuel, from the fuel 
analysis results (kg C per kg of fuel).
MW = Molecular weight of the gaseous fuel (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
0.001 = Conversion factor from kg to metric tons.
(Ore) = Annual mass of iron ore or iron ore pellets fed to the 
furnace (metric tons).
(COre) = Carbon content of the iron ore or iron ore 
pellets, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).
(Carbon) = Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace (metric tons).
(CCarbon) = Carbon content of the carbonaceous materials, 
from the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(Other) = Annual mass of other materials charged to the furnace 
(metric tons).
(COther) = Average carbon content of the other materials 
charged to the furnace, from the carbon analysis results (percent by 
weight, expressed as a decimal fraction).
(Iron) = Annual mass of iron produced (metric tons).
(CIron) = Carbon content of the iron, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
(NM) = Annual mass of non-metallic materials produced by the furnace 
(metric tons).
(CNM) = Carbon content of the non-metallic materials, 
from the carbon analysis results (percent by weight, expressed as a 
decimal fraction).
(R) = Annual mass of air pollution control residue collected (metric 
tons).
(CR) = Carbon content of the air pollution control 
residue, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).

    (2) Site-specific emission factor method. Conduct a performance 
test and measure CO2 emissions from all exhaust stacks for 
the process and measure either the feed rate of materials into the 
process or the production rate during the test as described in 
paragraphs (b)(2)(i) through (b)(2)(iv) of this section.
    (i) You must measure the process production rate or process feed 
rate, as applicable, during the performance test according to the 
procedures in Sec.  98.174(c)(5) and calculate the average rate for the 
test period in metric tons per hour.
    (ii) You must calculate the hourly CO2 emission rate 
using Equation Q-8 of this section and determine the average hourly 
CO2 emission rate for the test.
[GRAPHIC] [TIFF OMITTED] TR30OC09.070

Where:

CO2 = CO2 mass emission rate, corrected for 
moisture (metric tons/hr).
5.18 x 10-7 = Conversion factor (metric tons/scf-% 
CO2).

[[Page 56437]]

CCO2 = Hourly CO2 concentration, dry basis (% 
CO2).
Q = Hourly stack gas volumetric flow rate (scfh).
%H2O = Hourly moisture percentage in the stack gas.

    (iii) You must calculate a site-specific emission factor for the 
process in metric tons of CO2 per metric ton of feed or 
production, as applicable, by dividing the average hourly 
CO2 emission rate during the test by the average hourly feed 
or production rate during the test.
    (iv) You must calculate CO2 emissions for the process by 
multiplying the emission factor by the total amount of feed or 
production, as applicable, for the reporting period.
    (c) You must determine emissions of CO2 from the coke 
pushing process in mtCO2e by multiplying the metric tons of 
coal charged to the coke ovens during the reporting period by 0.008.
    (d) If GHG emissions from a taconite indurating furnace, basic 
oxygen furnace, non-recovery coke oven battery, sinter process, EAF, 
argon-oxygen decarburization vessel, or direct reduction furnace are 
vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).


Sec.  98.174  Monitoring and QA/QC requirements.

    (a) If you operate and maintain a CEMS that measures CO2 
emissions consistent with subpart C of this part, you must meet the 
monitoring and QA/QC requirements of Sec.  98.34(c).
    (b) If you determine CO2 emissions using the carbon mass 
balance procedure in Sec.  98.173(b)(1), you must:
    (1) Except as provided in paragraph (b)(4) of this section, 
determine the mass of each process input and output other than fuels 
using the same plant instruments or procedures that are used for 
accounting purposes (such as weigh hoppers, belt weigh feeders, weighed 
purchased quantities in shipments or containers, combination of bulk 
density and volume measurements, etc.), record the totals for each 
process input and output for each calendar month, and sum the monthly 
mass to determine the annual mass for each process input and output. 
Determine the mass rate of fuels using the procedures for combustion 
units in Sec.  98.34.
    (2) Except as provided in paragraph (b)(4) of this section, 
determine the carbon content of each process input and output annually 
for use in the applicable equations in Sec.  98.173(b)(1) based on 
analyses provided by the supplier or by the average carbon content 
determined by collecting and analyzing at least three samples each year 
using the standard methods specified in paragraphs (b)(2)(i) through 
(b)(2)(vi) of this section as applicable.
    (i) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec.  98.7) for limestone, dolomite, and slag.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7) for coal, coke, and 
other carbonaceous materials.
    (iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry (incorporated by reference, see Sec.  98.7) for iron ore, 
taconite pellets, and other iron-bearing materials.
    (iv) ASTM E1019-08, Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt 
Alloys by Various Combustion and Fusion Techniques (incorporated by 
reference, see Sec.  98.7) for iron and ferrous scrap.
    (v) ASM CS-104 UNS No. G10460--Alloy Digest April 1985 (Carbon 
Steel of Medium Carbon Content) (incorporated by reference, see Sec.  
98.7); ISO/TR 15349-1:1998, Unalloyed steel--Determination of low 
carbon content, Part 1: Infrared absorption method after combustion in 
an electric resistance furnace (by peak separation) (1998-10-15) First 
Edition (incorporated by reference, see Sec.  98.7); or ISO/TR 15349-
3:1998, Unalloyed steel-Determination of low carbon content Part 3: 
Infrared absorption method after combustion in an electric resistance 
furnace (with preheating) (1998-10-15) First Edition (incorporated by 
reference, see Sec.  98.7) as applicable for steel.
    (vi) For each process input that is a fuel, determine the carbon 
content and molecular weight (if applicable) using the applicable 
methods listed in Sec.  98.34.
    (3) For solid ferrous materials charged to basic oxygen process 
furnaces or EAFs that differ in carbon content, you may determine a 
weighted average carbon content based on the carbon content of each 
type of ferrous material and the average weight percent of each type 
that is used. Examples of these different ferrous materials include 
carbon steel, low carbon steel, stainless steel, high alloy steel, pig 
iron, iron scrap, and direct reduced iron.
    (4) If you document that a specific process input or output 
contributes less than one percent of the total mass of carbon into or 
out of the process, you do not have to determine the monthly mass or 
annual carbon content of that input or output.
    (5) Except as provided in paragraph (b)(4) of this section, you 
must determine the annual carbon content and monthly mass rate of any 
input or output that contains carbon that is not listed in the 
equations in Sec.  98.173(b)(1) using the procedures in paragraphs 
(b)(1) and (b)(2) of this section.
    (c) If you determine CO2 emissions using the site-
specific emission factor procedure in Sec.  98.173(b)(2), you must:
    (1) Conduct an annual performance test that is based on 
representative performance (i.e., performance based on normal operating 
conditions) of the affected process.
    (2) For the furnace exhaust from basic oxygen furnaces, EAFs, 
argon-oxygen decarburization vessels, and direct reduction furnaces, 
sample the furnace exhaust for at least three complete production 
cycles that start when the furnace is being charged and end after steel 
or iron and slag have been tapped. For EAFs that produce both carbon 
steel and stainless or specialty (low carbon) steel, develop an 
emission factor for the production of both types of steel.
    (3) For taconite indurating furnaces, non-recovery coke batteries, 
and sinter processes, sample for at least 3 hours.
    (4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, 
appendix A-2 to measure the CO2 concentration, Method 2, 2A, 
2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR 
part 60, appendix A-2 to determine the stack gas volumetric flow rate, 
and Method 4 at 40 CFR part 60, at appendix A-3 to determine the 
moisture content of the stack gas.
    (5) Determine the mass rate of process feed or process production 
(as applicable) during the test using the same plant instruments or 
procedures that are used for accounting purposes (such as weigh 
hoppers, belt weigh feeders, combination of bulk density and volume 
measurements, etc.)
    (6) If your process operates under different conditions as part of 
normal operations in such a manner that CO2 emissions change 
by more than 20

[[Page 56438]]

percent (e.g., routine changes in the carbon content of the sinter feed 
or change in grade of product), you must perform emission testing and 
develop separate emission factors for these different operating 
conditions and determine emissions based on the number of hours the 
process operates and the production or feed rate (as applicable) at 
each specific different condition.
    (7) If your EAF and argon-oxygen decarburization vessel exhaust to 
a common emission control device and stack, you must sample each 
process in the ducts before the emissions are combined, sample each 
process when only one process is operating, or sample the combined 
emissions when both processes are operating and base the site-specific 
emission factor on the steel production rate of the EAF.
    (8) The results of a performance test must include the analysis of 
samples, determination of emissions, and raw data. The performance test 
report must contain all information and data used to derive the 
emission factor.
    (d) For a coke pushing process, determine the metric tons of coal 
charged to the coke ovens and record the totals for each pushing 
process for each calendar month. Coal charged to coke ovens can be 
measured using weigh belts or a combination of measuring volume and 
bulk density.


Sec.  98.175  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.173 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) For each missing data for the carbon content of inputs and 
outputs for facilities that estimate emissions using the carbon mass 
balance procedure in Sec.  98.173(b)(1) or for facilities that estimate 
emissions using the site-specific emission factor procedure in Sec.  
98.173(b)(2); 100 percent data availability is required. You must 
repeat the test for average carbon contents of inputs and outputs 
according to the procedures in Sec.  98.174(b)(2). Similarly, you must 
repeat the test to determine the site-specific emission factor if data 
on the CO2 emission rate, process production rate or process 
feed rate are missing.
    (b) For missing records of the monthly mass or volume of carbon-
containing inputs and outputs using the carbon mass balance procedure 
in Sec.  98.173(b)(1), the substitute data value must be based on the 
best available estimate of the mass of the input or output material 
from all available process data or data used for accounting purposes.


Sec.  98.176  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information required in paragraphs (a) 
through (f) of this section for each coke pushing operation; taconite 
indurating furnace; basic oxygen furnace; non-recovery coke oven 
battery; sinter process; EAF; argon-oxygen decarburization vessel; and 
direct reduction furnace:
    (a) Unit identification number and annual CO2 emissions 
(in metric tons).
    (b) Annual production quantity (in metric tons) for taconite 
pellets, coke, sinter, iron, and raw steel.
    (c) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec.  98.37 for the 
Tier 4 Calculation Methodology.
    (d) If a CEMS is not used to measure CO2 emissions, then 
you must report for each process whether the emissions were determined 
using the carbon mass balance method in Sec.  98.173(b)(1) or the site-
specific emission factor method in Sec.  98.173(b)(2).
    (e) If you use the carbon mass balance method in Sec.  98.173(b)(1) 
to determine CO2 emissions, you must report the following 
information for each process:
    (1) The carbon content of each process input and output used to 
determine CO2 emissions.
    (2) Whether the carbon content was determined from information from 
the supplier or by laboratory analysis, and if by laboratory analysis, 
the method used.
    (3) The annual volume of gaseous fuel (in standard cubic feet), the 
annual volume of liquid fuel (in gallons), and the annual mass (in 
metric tons) of all other process inputs and outputs used to determine 
CO2 emissions.
    (4) The molecular weight of gaseous fuels.
    (5) If you used the missing data procedures in Sec.  98.175(b), you 
must report how the monthly mass for each process input or output with 
missing data was determined and the number of months the missing data 
procedures were used.
    (f) If you used the site-specific emission factor method in Sec.  
98.173(b)(2) to determine CO2 emissions, you must report the 
following information for each process:
    (1) The measured average hourly CO2 emission rate during 
the test (in metric tons per hour).
    (2) The average hourly feed or production rate (as applicable) 
during the test (in metric tons per hour).
    (3) The site-specific emission factor (in metric tons of 
CO2 per metric ton of feed or production, as applicable).
    (4) The annual feed or production rate (as applicable) used to 
estimate annual CO2 emissions (in metric tons).


Sec.  98.177  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (e) of this 
section, as applicable. Facilities that use CEMS to measure emissions 
must also retain records of the verification data required for the Tier 
4 Calculating Methodology in Sec.  98.36(e).
    (a) Records of all analyses and calculations conducted, including 
all information reported as required under Sec.  98.176.
    (b) When the carbon mass balance method is used to estimate 
emissions for a process, the monthly mass of each process input and 
output that are used to determine the annual mass.
    (c) Production capacity (in metric tons per year) for the 
production of taconite pellets, coke, sinter, iron, and raw steel.
    (d) Annual operating hours for taconite furnaces, coke oven 
batteries, sinter production, blast furnaces, direct reduced iron 
furnaces, and electric arc furnaces.
    (e) Facilities must keep records that include a detailed 
explanation of how company records or measurements are used to 
determine all sources of carbon input and output and the metric tons of 
coal charged to the coke ovens (e.g., weigh belts, a combination of 
measuring volume and bulk density). You also must document the 
procedures used to ensure the accuracy of the measurements of fuel 
usage including, but not limited to, calibration of weighing equipment, 
fuel flow meters, coal usage including, but not limited to, calibration 
of weighing equipment and other measurement devices. The estimated 
accuracy of measurements made with these devices must also be recorded, 
and the technical basis for these estimates must be provided.


Sec.  98.178  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[[Page 56439]]

Subpart R--Lead Production


Sec.  98.180  Definition of the source category.

    The lead production source category consists of primary lead 
smelters and secondary lead smelters. A primary lead smelter is a 
facility engaged in the production of lead metal from lead sulfide ore 
concentrates through the use of pyrometallurgical techniques. A 
secondary lead smelter is a facility at which lead-bearing scrap 
materials (including but not limited to, lead-acid batteries) are 
recycled by smelting into elemental lead or lead alloys.


Sec.  98.181  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a lead production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.182  GHGs to report.

    You must report:
    (a) Process CO2 emissions from each smelting furnace 
used for lead production.
    (b) CO2 combustion emissions from each smelting furnace 
used for lead production.
    (c) CH4 and N2O combustion emissions from 
each smelting furnace used for lead production. You must calculate and 
report these emissions under subpart C of this part (General Stationary 
Fuel Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than smelting furnaces used 
for lead production. You must report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.


Sec.  98.183  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each smelting furnace using the procedure in paragraphs 
(a) and (b) of this section.
    (a) For each smelting furnace that meets the conditions specified 
in Sec.  98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report 
combined process and combustion CO2 emissions by operating 
and maintaining a CEMS to measure CO2 emissions according to 
the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) For each smelting furnace that is not subject to the 
requirements in paragraph (a) of this section, calculate and report the 
process and combustion CO2 emissions from the smelting 
furnace by using the procedure in either paragraph (b)(1) or (b)(2) of 
this section.
    (1) Calculate and report under this subpart the combined process 
and combustion CO2 emissions by operating and maintaining a 
CEMS to measure CO2 emissions according to the Tier 4 
Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (2) Calculate and report process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(b)(2)(i) through (b)(2)(iii) of this section.
    (i) For each smelting furnace, determine the annual mass of carbon 
in each carbon-containing material, other than fuel, that is fed, 
charged, or otherwise introduced into the smelting furnace and estimate 
annual process CO2 emissions using Equation R-1 of this 
section. Carbon-containing materials include carbonaceous reducing 
agents. If you document that a specific material contributes less than 
1 percent of the total carbon into the process, you do not have to 
include the material in your calculation using Equation R-1 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.071

Where:

ECO2 = Annual process CO2 emissions from an 
individual smelting furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
Ore = Annual mass of lead ore charged to the smelting furnace 
(tons).
COre = Carbon content of the lead ore, from the carbon 
analysis results (percent by weight, expressed as a decimal 
fraction).
Scrap = Annual mass of lead scrap charged to the smelting furnace 
(tons).
CScrap = Carbon content of the lead scrap, from the 
carbon analysis (percent by weight, expressed as a decimal 
fraction).
Flux = Annual mass of flux materials (e.g., limestone, dolomite) 
charged to the smelting furnace (tons).
CFlux = Carbon content of the flux materials, from the 
carbon analysis (percent by weight, expressed as a decimal 
fraction).
Carbon = Annual mass of carbonaceous materials (e.g., coal, coke) 
charged to the smelting furnace (tons).
CCarbon = Carbon content of the carbonaceous materials, 
from the carbon analysis (percent by weight, expressed as a decimal 
fraction).
Other = Annual mass of any other material containing carbon, other 
than fuel, fed, charged, or otherwise introduced into the smelting 
furnace (tons).
COther = Carbon content of the other material from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).

    (ii) Determine the combined annual process CO2 emissions 
from the smelting furnaces at your facility using Equation R-2 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.072

Where:

CO2 = Annual process CO2 emissions from 
smelting furnaces at facility used for lead production (metric 
tons).
ECO2k = Annual process CO2 emissions from 
smelting furnace k calculated using Equation R-1 of this section 
(metric tons/year).
k = Total number of smelting furnaces at facility used for lead 
production.

    (iii) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions from the smelting furnaces according to the applicable 
requirements in subpart C.


Sec.  98.184  Monitoring and QA/QC requirements.

    If you determine process CO2 emissions using the carbon 
mass balance procedure in Sec.  98.183(b)(2)(i) and (b)(2)(ii), you 
must meet the requirements specified in paragraphs (a) and (b) of this 
section.
    (a) Determine the annual mass for each material used for the 
calculations of annual process CO2 emissions using Equation 
R-1 of this subpart by summing the monthly mass for the material 
determined for each month of the calendar year. The monthly mass may be 
determined using plant instruments used for accounting purposes, 
including either direct measurement of the quantity of the material 
placed in the unit or by calculations using process operating 
information.
    (b) For each material identified in paragraph (a) of this section, 
you must determine the average carbon content of

[[Page 56440]]

the material consumed or used in the calendar year using the methods 
specified in either paragraph (b)(1) or (b)(2) of this section. If you 
document that a specific process input or output contributes less than 
one percent of the total mass of carbon into or out of the process, you 
do not have to determine the monthly mass or annual carbon content of 
that input or output.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material each year. The carbon content of the material must be 
analyzed at least annually using the methods (and their QA/QC 
procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of 
this section, as applicable.
    (i) ASTM E1941-04, Standard Test Method for Determination of Carbon 
in Refractory and Reactive Metals and Their Alloys (incorporated by 
reference, see Sec.  98.7) for analysis of metal ore and alloy product.
    (ii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7), for analysis of 
carbonaceous reducing agents and carbon electrodes.
    (iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see 
Sec.  98.7) for analysis of flux materials such as limestone or 
dolomite.


Sec.  98.185  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.183 is required. Therefore, whenever 
a quality-assured value of a required parameter is unavailable, a 
substitute data value for the missing parameter shall be used in the 
calculations as specified in the paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) For each missing data for the carbon content for the smelting 
furnaces at your facility that estimate annual process CO2 
emissions using the carbon mass balance procedure in Sec.  
98.183(b)(2)(i) and (ii), 100 percent data availability is required. 
You must repeat the test for average carbon contents of inputs 
according to the procedures in Sec.  98.184(b) if data are missing.
    (b) For missing records of the monthly mass of carbon-containing 
materials, the substitute data value must be based the best available 
estimate of the mass of the material from all available process data or 
data used for accounting purposes (such as purchase records).


Sec.  98.186  Data reporting procedures.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions according 
to the requirements in Sec.  98.183(a) or (b)(1), then you must report 
under this subpart the relevant information required by Sec.  98.36 and 
the information specified in paragraphs (a)(1) through (a)(4) of this 
section.
    (1) Identification number of each smelting furnace.
    (2) Annual lead product production capacity (tons).
    (3) Annual production for each lead product (tons).
    (4) Total number of smelting furnaces at facility used for lead 
production.
    (b) If a CEMS is not used to measure CO2 emissions, and 
you measure CO2 emissions according to the requirements in 
Sec.  98.183(b)(2)(i) and (b)(2)(ii), then you must report the 
information specified in paragraphs (b)(1) through (b)(9) of this 
section.
    (1) Identification number of each smelting furnace. (2) Annual 
process CO2 emissions (in metric tons) from each smelting 
furnace as determined by Equation R-1 of this subpart.
    (3) Annual lead product production capacity for the facility and 
each smelting furnace(tons).
    (4) Annual production for each lead product (tons).
    (5) Total number of smelting furnaces at facility used for 
production of lead products reported in paragraph (b)(4) of this 
section.
    (6) Annual material quantity for each material used for the 
calculation of annual process CO2 emissions using Equation 
R-1 of this subpart for each smelting furnace (tons).
    (7) Annual average of the carbon content determinations for each 
material used for the calculation of annual process CO2 
emissions using Equation R-1 of this subpart for each smelting furnace.
    (8) List the method used for the determination of carbon content 
for each material reported in paragraph (b)(7) of this section (e.g., 
supplier provided information, analyses of representative samples you 
collected).
    (9) If you use the missing data procedures in Sec.  98.185(b), you 
must report how the monthly mass of carbon-containing materials with 
missing data was determined and the number of months the missing data 
procedures were used.


Sec.  98.187  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), each annual 
report must contain the information specified in paragraphs (a) through 
(c) of this section, as applicable to the smelting furnaces at your 
facility.
    (a) If a CEMS is used to measure combined process and combustion 
CO2 emissions according to the requirements in Sec.  
98.183(a) or (b)(1), then you must retain the records required for the 
Tier 4 Calculation Methodology in Sec.  98.37 and the information 
specified in paragraphs (a)(1) through (a)(3) of this section.
    (1) Monthly smelting furnace production quantity for each lead 
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (b) If the carbon mass balance procedure is used to determine 
process CO2 emissions according to the requirements in Sec.  
98.183(b)(2)(i) and (b)(2)(ii), then you must retain under this subpart 
the records specified in paragraphs (b)(1) through (b)(5) of this 
section.
    (1) Monthly smelting furnace production quantity for each lead 
product (tons).
    (2) Number of smelting furnace operating hours each month.
    (3) Number of smelting furnace operating hours in calendar year.
    (4) Monthly material quantity consumed, used, or produced for each 
material included for the calculations of annual process CO2 
emissions using Equation R-1 of this subpart (tons).
    (5) Average carbon content determined and records of the supplier 
provided information or analyses used for the determination for each 
material included for the calculations of annual process CO2 
emissions using Equation R-1 of this subpart.
    (c) You must keep records that include a detailed explanation of 
how company records of measurements are used to estimate the carbon 
input to each smelting furnace, including documentation of any 
materials excluded from Equation R-1 of this subpart that contribute 
less than 1 percent of the total carbon into or out of the process. You 
also must document the procedures used to ensure the accuracy of the 
measurements of materials fed, charged, or placed in an smelting 
furnace including, but not limited to, calibration of weighing 
equipment and other measurement devices. The estimated accuracy of 
measurements made with these devices must also be recorded, and the 
technical

[[Page 56441]]

basis for these estimates must be provided.


Sec.  98.188  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart S--Lime Manufacturing


Sec.  98.190  Definition of the source category.

    (a) Lime manufacturing plants (LMPs) engage in the manufacture of a 
lime product (e.g., calcium oxide, high-calcium quicklime, calcium 
hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or 
other products) by calcination of limestone, dolomite, shells or other 
cacareous substances as defined in 40 CFR 63.7081(a)(1).
    (b) This source category includes all LMPs unless the LMP is 
located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or 
only processes sludge containing calcium carbonate from water softening 
processes. The lime manufacturing source category consists of marketed 
and non-marketed lime manufacturing facilities.
    (c) Lime kilns at pulp and paper manufacturing facilities must 
report emissions under subpart AA of this part (Pulp and Paper 
Manufacturing).


Sec.  98.191  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
is a lime manufacturing plant as defined in Sec.  98.190 and the 
facility meets the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.192  GHGs to report.

    You must report:
    (a) CO2 process emissions from lime kilns.
    (b) CO2 emissions from fuel combustion at lime kilns.
    (c) N2O and CH4 emissions from fuel 
combustion at each lime kiln. You must report these emissions under 40 
CFR part 98, subpart C (General Stationary Fuel Combustion Sources).
    (d) CO2, N2O, and CH4 emissions 
from each stationary fuel combustion unit other than lime kilns. You 
must report these emissions under 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources).
    (e) CO2 collected and transferred off site under 40 CFR 
part 98, following the requirements of subpart PP of this part 
(Suppliers of Carbon Dioxide (CO2)).


Sec.  98.193  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from all lime kilns combined using the procedure in 
paragraphs (a) and (b) of this section.
    (a) If all lime kilns meet the conditions specified in Sec.  
98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under 
this subpart the combined process and combustion CO2 
emissions by operating and maintaining a CEMS to measure CO2 
emissions according to the Tier 4 Calculation Methodology specified in 
Sec.  98.33(a)(4) and all associated requirements for Tier 4 in subpart 
C of this part (General Stationary Fuel Combustion Sources).
    (b) If CEMS are not required to be used to determine CO2 
emissions from all lime kilns under paragraph (a) of this section, then 
you must calculate and report the process and combustion CO2 
emissions from the lime kilns by using the procedures in either 
paragraph (b)(1) or (b)(2) of this section.
    (1) Calculate and report under this subpart the combined process 
and combustion CO2 emissions by operating and maintaining a 
CEMS to measure CO2 emissions from all lime kilns according 
to the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) 
and all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (2) Calculate and report process and combustion CO2 
emissions separately using the procedures specified in paragraphs 
(b)(2)(i) through (b)(2)(v) of this section.
    (i) You must calculate a monthly emission factor for each type of 
lime produced using Equation S-1 of this section. Calcium oxide and 
magnesium oxide content must be analyzed monthly for each lime type:
[GRAPHIC] [TIFF OMITTED] TR30OC09.073

Where:

EFLIME,i,n = Emission factor for lime type i, for month n 
(metric tons CO2/ton lime).
SRCaO = Stoichiometric ratio of CO2 and CaO 
for calcium carbonate [see Table S-1 of this subpart] (metric tons 
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO 
for magnesium carbonate (See Table S-1 of this subpart) (metric tons 
CO2/metric tons MgO).
CaOi,n = Calcium oxide content for lime type i, for month 
n, determined according to Sec.  98.194(c) (metric tons CaO/metric 
ton lime).
MgOi,n = Magnesium oxide content for lime type i, for 
month n, determined according to Sec.  98.194(c) (metric tons MgO/
metric ton lime).
2000/2205 = Conversion factor for metric tons to tons.

(ii) You must calculate a monthly emission factor for each type of 
byproduct/waste sold (including lime kiln dust) using Equation S-2 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.074

Where:

EFLKD,i,n = Emission factor for sold lime byproduct/waste 
type i, for month n (metric tons CO2/ton lime byproduct).
SRCaO = Stoichiometric ratio of CO2 and CaO 
for calcium carbonate (see Table S-1 of this subpart((metric tons 
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO 
for magnesium carbonate (See Table S-1 of this subpart) (metric tons 
CO2/metric tons MgO).
CaOLKD,i,n = Calcium oxide content for sold lime 
byproduct/waste type i, for month n (metric tons CaO/metric ton 
lime).
MgOLKD,i,n = Magnesium oxide content for sold lime 
byproduct/waste type i, for month n (metric tons MgO/metric ton 
lime).
2000/2205 = Conversion factor for metric tons to tons.

    (iii) You must calculate the annual CO2 emissions from 
each type of byproduct/waste that is not sold (including lime kiln dust 
and scrubber sludge) using Equation S-3 of this section:

[[Page 56442]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.075

Where:

Ewaste,i = Annual CO2 emissions for unsold 
lime byproduct/waste type i (metric tons CO2).
SRCaO = Stoichiometric ratio of CO2 and CaO 
for calcium carbonate (see Table S-1 of this subpart) (metric tons 
CO2/metric tons CaO).
SRMgO = Stoichiometric ratio of CO2 and MgO 
for magnesium carbonate (See Table S-1 of this subpart) (metric tons 
CO2/metric tons MgO).
CaOwaste,i = Calcium oxide content for unsold lime 
byproduct/waste type i (metric tons CaO/metric ton lime).
MgOwaste,i = Magnesium oxide content for unsold lime 
byproduct/waste type i (metric tons MgO/metric ton lime).
Mwaste,i = Annual weight or mass of unsold byproducts/
wastes for lime type i (tons).
2000/2205 = Conversion factor for metric tons to tons.

    (iv) You must calculate annual CO2 process emissions for 
all kilns using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.076


Where:

ECO2 = Annual CO2 process emissions from lime 
production from all kilns (metric tons/year).
EFLIME,i,n = Emission factor for lime type i, in calendar 
month n (metric tons CO2/ton lime) from Equation S-1 of 
this section.
MLIME,i,n = Weight or mass of lime type i in calendar 
month n (tons).
EFLKD,i,n = Emission factor of byproducts/wastes sold for 
lime type i in calendar month n, (metric tons CO2/ton 
byproduct/waste) from Equation S-2 of this section.
MLKD,i,n = Monthly weight or mass of byproducts/waste 
sold (such as lime kiln dust, LKD) for lime type i in calendar month 
n (tons).
Ewaste,i = Annual CO2 emissions for unsold 
lime byproduct/waste type i (metric tons CO2) from 
Equation S-3 of this section.
t = Number of lime types
b = Number of byproducts/wastes sold
z = Number of byproducts/wastes not sold

    (v) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2 
emissions from each lime kiln according to the applicable requirements 
in subpart C.


Sec.  98.194  Monitoring and QA/QC requirements.

    (a) You must determine the total quantity of each product type of 
lime and each calcined byproduct/waste (such as lime kiln dust) that is 
sold. The quantities of each should be directly measured monthly with 
the same plant instruments used for accounting purposes, including but 
not limited to, calibrated weigh feeders, rail or truck scales, and 
barge measurements. The direct measurements of each lime product shall 
be reconciled annually with the difference in the beginning of and end 
of year inventories for these products, when measurements represent 
lime sold.
    (b) You must determine the annual quantity of each calcined 
byproduct/waste generated that is not sold by either direct measurement 
using the same instruments identified in paragraph (a) of this section 
or by using a calcined byproduct/waste generation rate.
    (c) You must determine the chemical composition (percent total CaO 
and percent total MgO) of each type of lime and each type of calcined 
byproduct/waste sold according to paragraph (c)(1) or (c)(2) of this 
section. You must determine the chemical composition of each type of 
lime on a monthly basis. You must determine the chemical composition 
for each type of calcined byproduct/waste that is not sold on an annual 
basis.
    (1) ASTM C25-06 Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime (incorporated by reference--see 
Sec.  98.7).
    (2) The National Lime Association's CO2 Emissions 
Calculation Protocol for the Lime Industry English Units Version, 
February 5, 2008 Revision-National Lime Association (incorporated by 
reference--see Sec.  98.7).
    (d) You must use the analysis of calcium oxide and magnesium oxide 
content of each lime product collected during the same month as the 
production data in monthly calculations.
    (e) You must follow the quality assurance/quality control 
procedures (including documentation) in National Lime Association's 
CO2 Emissions Calculation Protocol for the Lime Industry 
English Units Version, February 5, 2008 Revision--National Lime 
Association (incorporated by reference--see Sec.  98.7).


Sec.  98.195  Procedures for estimating missing data.

    For the procedure in Sec.  98.193(b)(2), a complete record of all 
measured parameters used in the GHG emissions calculations is required 
(e.g., oxide content, quantity of lime products, etc.). Therefore, 
whenever a quality-assured value of a required parameter is 
unavailable, a substitute data value for the missing parameter shall be 
used in the calculations as specified in paragraphs (a) or (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) For each missing value of the quantity of lime produced (by 
lime type), and quantity of byproduct/waste produced and sold, the 
substitute data value shall be the best available estimate based on all 
available process data or data used for accounting purposes.
    (b) For missing values related to the CaO and MgO content, you must 
conduct a new composition test according to the standard methods in 
Sec.  98.194 (c)(1) or (c)(2).


Sec.  98.196  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required by 
Sec.  98.36 and the information listed in paragraphs (a)(1) through 
(a)(8) of this section.
    (1) Method used to determine the quantity of lime sold.
    (2) Method used to determine the quantity of lime byproduct/waste 
sold.
    (3) Beginning and end of year inventories for each lime product.
    (4) Beginning and end of year inventories for lime byproducts/
wastes.

[[Page 56443]]

    (5) Annual amount of lime byproduct/waste sold, by type (tons).
    (6) Annual amount of lime product sold, by type (tons).
    (7) Annual amount of lime byproduct/waste not sold, by type (tons).
    (8) Annual amount of lime product not sold, by type (tons).
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in paragraphs (b)(1) through 
(b)(17) of this section.
    (1) Annual CO2 process emissions from all kilns combined 
(metric tons).
    (2) Monthly emission factors for each lime type.
    (3) Monthly emission factors for each sold byproduct/waste by lime 
type.
    (4) Standard method used (ASTM or NLA testing method) to determine 
chemical compositions of each lime type and lime byproduct/waste type.
    (5) Monthly results of chemical composition analysis of each lime 
product and byproduct/waste sold.
    (6) Annual results of chemical composition analysis of each type of 
lime byproduct/waste not sold.
    (7) Method used to determine the quantity of lime sold.
    (8) Monthly amount of lime product sold, by type (tons).
    (9) Method used to determine the quantity of lime byproduct/waste 
sold.
    (10) Monthly amount of lime byproduct/waste sold, by type (tons).
    (11) Annual amount of lime byproduct/waste not sold (tons).
    (12) Monthly mass of each lime type produced (tons).
    (13) Beginning and end of year inventories for each lime product.
    (14) Beginning and end of year inventories for lime byproducts/
wastes.
    (15) Annual lime production capacity (tons) per facility.
    (16) Number of times in the reporting year that missing data 
procedures were followed to measure lime production (months) or the 
chemical composition of lime products sold (months).
    (17) Indicate whether CO2 was used on-site (i.e. for use 
in a purification process). If CO2 was used on-site, provide 
the information in paragraphs (b)(17)(i) and (b)(17)(ii) of this 
section.
    (i) The annual amount of CO2 captured for use in the on-
site process.
    (ii) The method used to determine the amount of CO2 
captured.


Sec.  98.197  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section.
    (a) Annual operating hours in calendar year.
    (b) Records of all analyses (e.g. chemical composition of lime 
products, by type) and calculations conducted.


Sec.  98.198  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

 Table S-1 to Subpart S of Part 98--Basic Parameters for the Calculation
                 of Emission Factors for Lime Production
------------------------------------------------------------------------
                                                         Stoichiometric
                       Variable                              ratio
------------------------------------------------------------------------
SRCaO................................................             0.7848
SRMgO................................................             1.0918
------------------------------------------------------------------------

Subpart T--[Reserved]

Subpart U--Miscellaneous Uses of Carbonate


Sec.  98.210  Definition of the source category.

    (a) This source category includes any equipment that uses 
carbonates listed in Table U-1 in manufacturing processes that emit 
carbon dioxide. Table U-1 includes the following carbonates: limestone, 
dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium 
carbonate. Facilities are considered to emit CO2 if they 
consume at least 2,000 tons per year of carbonates heated to a 
temperature sufficient to allow the calcination reaction to occur.
    (b) This source category does not include equipment that uses 
carbonates or carbonate containing minerals that are consumed in the 
production of cement, glass, ferroalloys, iron and steel, lead, lime, 
phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium 
hydroxide, or zinc.
    (c) This source category does not include carbonates used in 
sorbent technology used to control emissions from stationary fuel 
combustion equipment. Emissions from carbonates used in sorbent 
technology are reported under 40 CFR 98, subpart C (Stationary Fuel 
Combustion Sources).


Sec.  98.211  Reporting threshold.

    You must report GHG emissions from miscellaneous uses of carbonate 
if your facility uses carbonates as defined in Sec.  98.210 of this 
subpart and the facility meets the requirements of either Sec.  
98.2(a)(1) or (a)(2).


Sec.  98.212  GHGs to report.

    You must report CO2 process emissions from all 
miscellaneous carbonate use at your facility as specified in this 
subpart.


Sec.  98.213  Calculating GHG emissions.

    You must determine CO2 process emissions from carbonate 
use in accordance with the procedures specified in either paragraphs 
(a) or (b) of this section.
    (a) Calculate the process emissions of CO2 using 
calcination fractions with Equation U-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.077

Where:

ECO2 = Annual CO2 mass emissions from 
consumption of carbonates (metric tons).
Mi = Annual mass of carbonate type i consumed (tons).
EFi = Emission factor for the carbonate type i, as 
specified in Table U-1 to this subpart, metric tons CO2/
metric ton carbonate consumed.
Fi = Fraction calcination achieved for each particular 
carbonate type i (decimal fraction). As an alternative to measuring 
the calcination fraction, a value of 1.0 can be used.
n = Number of carbonate types.
2000/2205 = Conversion factor to convert tons to metric tons.

(b) Calculate the process emissions of CO2 using actual mass 
of output carbonates with Equation U-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.078


[[Page 56444]]


Where:

ECO2 = Annual CO2 mass emissions from 
consumption of carbonates (metric tons).
Mk = Annual mass of input carbonate type k (tons).
EFk = Emission factor for the carbonate type k, as 
specified in Table U-1 of this subpart (metric tons CO2/
metric ton carbonate input).
Mj = Annual mass of output carbonate type j (tons).
EFj = Emission factor for the output carbonate type j, as 
specified in Table U-1 of this subpart (metric tons CO2/
metric ton carbonate input).
m = Number of input carbonate types.
n = Number of output carbonate types.

Sec.  98.214  Monitoring and QA/QC requirements.

    (a) The annual mass of carbonate consumed (for Equation U-1 of this 
subpart) or carbonate inputs (for Equation U-2 of this subpart) must be 
determined annually from monthly measurements using the same plant 
instruments used for accounting purposes including purchase records or 
direct measurement, such as weigh hoppers or weigh belt feeders.
    (b) The annual mass of carbonate outputs (for Equation U-2 of this 
subpart) must be determined annually from monthly measurements using 
the same plant instruments used for accounting purposes including 
purchase records or direct measurement, such as weigh hoppers or belt 
weigh feeders.
    (c) If you follow the procedures of Sec.  98.213(a), as an 
alternative to assuming a calcination fraction of 1.0, you can 
determine on an annual basis the calcination fraction for each 
carbonate consumed based on sampling and chemical analysis using a 
suitable method such as using an x-ray fluorescence standard method or 
other enhanced industry consensus standard method published by an 
industry consensus standard organization (e.g., ASTM, ASME, etc.).


Sec.  98.215  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraph (b) of this section. You must document and keep 
records of the procedures used for all such estimates.
    (b) For each missing value of monthly carbonate consumed, monthly 
carbonate output, or monthly carbonate input, the substitute data value 
must be the best available estimate based on the all available process 
data or data used for accounting purposes.


Sec.  98.216  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (g) of this section at the facility level, as applicable.
    (a) Annual CO2 emissions from miscellaneous carbonate 
use (metric tons).
    (b) Annual mass of each carbonate type consumed (tons).
    (c) Measurement method used to determine the mass of carbonate.
    (d) Method used to calculate emissions.
    (e) If you followed the calculation method of Sec.  
98.213(b)(1)(i), you must report the information in paragraphs (e)(1) 
through (e)(3) of this section.
    (1) Annual carbonate consumption by carbonate type (tons).
    (2) Annual calcination fractions used in calculations.
    (3) If you determined the calcination fraction, indicate which 
standard method was used.
    (f) If you followed the calculation method of Sec.  
98.213(b)(1)(ii), you must report the information in paragraphs (f)(1) 
and (f)(2) of this section.
    (1) Annual carbonate input by carbonate type (tons).
    (2) Annual carbonate output by carbonate type (tons).
    (g) Number of times in the reporting year that missing data 
procedures were followed to measure carbonate consumption, carbonate 
input or carbonate output (months).


Sec.  98.217  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (d) of this 
section:
    (a) Monthly carbonate consumption (by carbonate type in tons).
    (b) You must document the procedures used to ensure the accuracy of 
the monthly measurements of carbonate consumption, carbonate input or 
carbonate output including, but not limited to, calibration of weighing 
equipment and other measurement devices.
    (c) Records of all analyses conducted to meet the requirements of 
this rule.
    (d) Records of all calculations conducted.


Sec.  98.218  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

   Table U-1 to Subpart U of Part 98--CO2 Emission Factors for Common
                               Carbonates
------------------------------------------------------------------------
                                                                 CO2
                                                               emission
                                                                factor
                  Mineral name--carbonate                     (tons CO2/
                                                                 ton
                                                              carbonate)
------------------------------------------------------------------------
Limestone--CaCO3...........................................      0.43971
Magnesite--MgCO3...........................................      0.52197
Dolomite--CaMg(CO3)2.......................................      0.47732
Siderite--FeCO3............................................      0.37987
Ankerite--Ca(Fe, Mg, Mn)(CO3)2.............................      0.47572
Rhodochrosite--MnCO3.......................................      0.38286
Sodium Carbonate/Soda Ash--Na2CO3..........................      0.41492
------------------------------------------------------------------------

Subpart V--Nitric Acid Production


Sec.  98.220  Definition of source category.

    A nitric acid production facility uses one or more trains to 
produce weak nitric acid (30 to 70 percent in strength). A nitric acid 
train produces weak nitric acid through the catalytic oxidation of 
ammonia.


Sec.  98.221  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a nitric acid train and the facility meets the requirements of 
either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.222  GHGs to report.

    (a) You must report N2O process emissions from each 
nitric acid production train as required by this subpart.
    (b) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
by following the requirements of subpart C.


Sec.  98.223  Calculating GHG emissions.

    (a) You must determine annual N2O process emissions from 
each nitric acid train according to paragraphs (a)(1) or (a)(2) of this 
section.
    (1) Use a site-specific emission factor and production data 
according to paragraphs (b) through (h) of this section.
    (2) Request Administrator approval for an alternative method of 
determining N2O emissions according to paragraphs (a)(2)(i) 
and (a)(2)(ii) of this section.
    (i) You must submit the request within 45 days following 
promulgation of this subpart or within the first 30 days of each 
subsequent reporting year.
    (ii) If the Administrator does not approve your requested 
alternative method within 150 days of the end of the reporting year, 
you must determine the N2O emissions factor for the current

[[Page 56445]]

reporting period using the procedures specified in paragraph (a)(1) of 
this section.
    (b) You must conduct an annual performance test according to 
paragraphs (b)(1) through (b)(3) of this section.
    (1) You must measure N2O emissions from the absorber 
tail gas vent for each nitric acid train using the methods specified in 
Sec.  98.224(b) through (d).
    (2) You must conduct the performance test under normal process 
operating conditions and without using N2O abatement 
technology (if applicable).
    (3) You must measure the production rate during the performance 
test and calculate the production rate for the test period in metric 
tons (100 percent acid basis) per hour.
    (c) You must determine an N2O emissions factor to use in 
Equation V-3 of this section according to paragraphs (c)(1) or (c)(2) 
of this section.
    (1) You may request Administrator approval for an alternative 
method of determining N2O concentration according to the 
procedures in paragraphs (a)(2)(i) and (a)(2)(ii) of this section. 
Alternative methods include the use of N2O CEMs.
    (2) Using the results of the performance test in paragraph (b) of 
this section, you must calculate an average site-specific emission 
factor for each nitric acid train ``t'' according to Equation V-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.079


Where:

EFN2Ot = Average site-specific N2O emissions 
factor for nitric acid train ``t'' (lb N2O generated/ton 
nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration for each test run 
during the performance test (ppm N2O).
1.14 x 10-7 = Conversion factor (lb/dscf-ppm 
N2O).
Q = Volumetric flow rate of effluent gas for each test run during 
the performance test (dscf/hr).
P = Production rate for each test run during the performance test 
(tons nitric acid produced per hour, 100 percent acid basis).
n = Number of test runs.

    (d) If applicable, you must determine the destruction efficiency 
for each N2O abatement technology according to paragraphs 
(d)(1), (d)(2), or (d)(3) of this section.
    (1) Use the manufacturer's specified destruction efficiency.
    (2) Estimate the destruction efficiency through process knowledge. 
Examples of information that could constitute process knowledge include 
calculations based on material balances, process stoichiometry, or 
previous test results provided the results are still relevant to the 
current vent stream conditions. You must document how process knowledge 
(if applicable) was used to determine the destruction efficiency.
    (3) Calculate the destruction efficiency by conducting an 
additional performance test on the emissions stream following the 
N2O abatement technology.
    (e) If applicable, you must determine the abatement factor for each 
N2O abatement technology. The abatement factor is calculated 
for each nitric acid train according to Equation V-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.080

Where:

AFN t = Abatement factor of N2O abatement 
technology at nitric acid train ``t'' (fraction of annual production 
that abatement technology is operating).
Pa t = Total annual nitric acid production from nitric 
acid train ``t'' (ton acid produced, 100 percent acid basis).
Pa t Abate = Annual nitric acid production from nitric 
acid train ``t'' during which N2O abatement was used (ton 
acid produced, 100 percent acid basis).

    (f) You must determine the annual amount of nitric acid produced 
and the annual amount of nitric acid produced while each N2O 
abatement technology is operating from each nitric acid train (100 
percent basis).
    (g) You must calculate N2O emissions for each nitric 
acid train by multiplying the emissions factor (determined in Equation 
V-1 of this section) by the annual nitric acid production and 
accounting for N2O abatement, according to Equation V-3 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.081

Where:

EN2Ot = N2O mass emissions per year for nitric 
acid train ``t'' (metric tons).
EFN2Ot = Average site-specific N2O emissions 
factor for nitric acid train ``t'' (lb N2O generated/ton 
acid produced, 100 percent acid basis).
Pa t = Annual nitric acid production from the train ``t'' 
(ton acid produced, 100 percent acid basis).
DFN t = Destruction efficiency of N2O 
abatement technology N that is used on nitric acid train ``t'' 
(percent of N2O removed from air stream).
AFN t = Abatement factor of N2O abatement 
technology for nitric acid train ``t'' (fraction of annual 
production that abatement technology is operating).
2204.63 = Conversion factor (lb/metric ton).
z = Number of different N2O abatement technologies.

    (h) You must determine the annual nitric acid production emissions 
combined from all nitric acid trains at your facility using Equation V-
4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.082



[[Page 56446]]


Where:

N2O = Annual process N2O emissions from nitric 
acid production facility (metric tons).
EN2Ot = N2O mass emissions per year for nitric 
acid train ``t'' (metric tons).
m = Number of nitric acid trains.


Sec.  98.224  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new 
site-specific emissions factor according to a test plan as specified in 
paragraphs (a)(1) through (a)(3) of this section.
    (1) Conduct the performance test annually.
    (2) Conduct the performance test when your nitric acid production 
process is changed, specifically when abatement equipment is installed.
    (3) If you requested Administrator approval for an alternative 
method of determining N2O concentration under Sec.  
98.223(a)(2), you must conduct the performance test if your request has 
not been approved by the Administrator within 150 days of the end of 
the reporting year in which it was submitted.
    (b) You must measure the N2O concentration during the 
performance test using one of the methods in paragraphs (b)(1) through 
(b)(3) of this section.
    (1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of 
Vapor Phase Organic and Inorganic Emissions by Extractive Fourier 
Transform Infrared (FTIR) Spectroscopy.
    (2) ASTM D6348-03 Standard Test Method for Determination of Gaseous 
Compounds by Extractive Direct Interface Fourier Transform Infrared 
(FTIR) Spectroscopy (incorporated by reference in Sec.  98.7).
    (3) An equivalent method, with Administrator approval.
    (c) You must determine the production rate(s) (100 percent basis) 
from each nitric acid train during the performance test according to 
paragraphs (c)(1) or (c)(2) of this section.
    (1) Direct measurement of production and concentration (such as 
using flow meters, weigh scales, for production and concentration 
measurements).
    (2) Existing plant procedures used for accounting purposes (i.e. 
dedicated tank-level and acid concentration measurements).
    (d) You must conduct all performance tests in conjunction with the 
applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. 
Conduct three emissions test runs of 1 hour each. All QA/QC procedures 
specified in the reference test methods and any associated performance 
specifications apply. For each test, the facility must prepare an 
emission factor determination report that must include the items in 
paragraphs (d)(1) through (d)(3) of this section.
    (1) Analysis of samples, determination of emissions, and raw data.
    (2) All information and data used to derive the emissions 
factor(s).
    (3) The production rate during each test and how it was determined.
    (e) You must determine the monthly nitric acid production and the 
monthly nitric acid production during which N2O abatement 
technology is operating from each nitric acid train according to the 
methods in paragraphs (c)(1) or (c)(2) of this section.
    (f) You must determine the annual nitric acid production and the 
annual nitric acid production during which N2O abatement 
technology is operating for each train by summing the respective 
monthly nitric acid production quantities.


Sec.  98.225  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter shall be used in the calculations as 
specified in paragraphs (a) and (b) of this section.
    (a) For each missing value of nitric acid production, the 
substitute data shall be the best available estimate based on all 
available process data or data used for accounting purposes (such as 
sales records).
    (b) For missing values related to the performance test, including 
emission factors, production rate, and N2O concentration, 
you must conduct a new performance test according to the procedures in 
Sec.  98.224 (a) through (d).


Sec.  98.226  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (o) of this section for each nitric acid production train.
    (a) Train identification number.
    (b) Annual process N2O emissions from each nitric acid 
train (metric tons).
    (c) Annual nitric acid production from each nitric acid train 
(tons, 100 percent acid basis).
    (d) Annual nitric acid production from each nitric acid train 
during which N2O abatement technology is operating (ton acid 
produced, 100 percent acid basis).
    (e) Annual nitric acid production from the nitric acid facility 
(tons, 100 percent acid basis).
    (f) Number of nitric acid trains.
    (g) Number of abatement technologies (if applicable).
    (h) Abatement technologies used (if applicable).
    (i) Abatement technology destruction efficiency for each abatement 
technology (percent destruction).
    (j) Abatement utilization factor for each abatement technology 
(fraction of annual production that abatement technology is operating).
    (k) Type of nitric acid process used for each nitric acid train 
(low, medium, high, or dual pressure).
    (l) Number of times in the reporting year that missing data 
procedures were followed to measure nitric acid production (months).
    (m) If you conducted a performance test and calculated a site-
specific emissions factor according to Sec.  98.223(a)(1), each annual 
report must also contain the information specified in paragraphs (m)(1) 
through (m)(7) of this section for each nitric acid production 
facility.
    (1) Emission factor calculated for each nitric acid train (lb 
N2O/ton nitric acid, 100 percent acid basis).
    (2) Test method used for performance test.
    (3) Production rate per test run during performance test (tons 
nitric acid produced/hr, 100 percent acid basis).
    (4) N2O concentration per test run during performance 
test (ppm N2O).
    (5) Volumetric flow rate per test run during performance test 
(dscf/hr).
    (6) Number of test runs during performance test.
    (7) Number of times in the reporting year that a performance test 
had to be repeated (number).
    (n) If you requested Administrator approval for an alternative 
method of determining N2O concentration under Sec.  
98.223(a)(2), each annual report must also contain the information 
specified in paragraphs (n)(1) through (n)(4) of this section for each 
nitric acid production facility.
    (1) Name of alternative method.
    (2) Description of alternative method.
    (3) Request date.
    (4) Approval date.
    (o) Total pounds of synthetic fertilizer produced through and total 
nitrogen contained in that fertilizer.


Sec.  98.227  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (g) of this 
section for each nitric acid production facility:

[[Page 56447]]

    (a) Records of significant changes to process.
    (b) Documentation of how process knowledge was used to estimate 
abatement technology destruction efficiency (if applicable).
    (c) Performance test reports.
    (d) Number of operating hours in the calendar year for each nitric 
acid train (hours).
    (e) Annual nitric acid permitted production capacity (tons).
    (f) Measurements, records, and calculations used to determine 
reported parameters.
    (g) Documentation of the procedures used to ensure the accuracy of 
the measurements of all reported parameters, including but not limited 
to, calibration of weighing equipment, flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must also be recorded, and the technical basis for these 
estimates must be provided.


Sec.  98.228  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart W--[Reserved]

Subpart X--Petrochemical Production


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 (f) of this section. The source category 
includes processes that produce the petrochemical as an intermediate in 
the onsite production of other chemicals as well as processes that 
produce the petrochemical as an end product for sale or shipment 
offsite.
    (b) A process that produces a petrochemical as a byproduct is not 
part of the petrochemical production source category.
    (c) A facility that makes methanol, hydrogen, and/or ammonia from 
synthesis gas is part of the petrochemical source category if the 
annual mass of methanol produced exceeds the individual annual mass 
production levels of both hydrogen recovered as product and ammonia. 
The facility is part of subpart P of this part (Hydrogen Production) if 
the annual mass of hydrogen recovered as product exceeds the individual 
annual mass production levels of both methanol and ammonia. The 
facility is part of subpart G of this part (Ammonia Manufacturing) if 
the annual mass of ammonia produced exceeds the individual annual mass 
production levels of both hydrogen recovered as product and methanol.
    (d) A direct chlorination process that is operated independently of 
an oxychlorination process to produce ethylene dichloride is not part 
of the petrochemical production source category.
    (e) A process that produces bone black is not part of the 
petrochemical source category.
    (f) A process that produces a petrochemical from bio-based 
feedstock is not part of the petrochemical production source category.


Sec.  98.241  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a petrochemical process as specified in Sec.  98.240, and the 
facility meets the requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.242  GHGs to report.

    You must report the information in paragraphs (a) through (c) of 
this section:
    (a) CO2 CH4, and N2O process 
emissions from each petrochemical process unit. Process emissions 
include CO2 generated by reaction in the process and by 
combustion of process off-gas in stationary combustion units and 
flares.
    (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.
    (2) If you comply with Sec.  98.243(c), report under this subpart 
the calculated CO2 emissions for each petrochemical process 
unit.
    (b) CO2, CH4, and N2O combustion 
emissions from stationary combustion units and flares.
    (1) If you comply with Sec.  98.243(b) or (d), report these 
emissions from stationary combustion units that are associated with 
petrochemical process units and burn only supplemental fuel under 
subpart C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.
    (2) If you comply with Sec.  98.243(c), report CO2, 
CH4, and N2O combustion emissions under subpart C 
of this part (General Stationary Fuel Combustion Sources) by following 
the requirements of subpart C only for the combustion of supplemental 
fuel. Determine the applicable Tier in subpart C of this part (General 
Stationary Fuel Combustion Sources) based on the maximum rated heat 
input capacity of the stationary combustion source.
    (c) CO2 captured. You must report the mass of 
CO2 captured under, subpart PP of this part (Suppliers of 
Carbon Dioxide (CO2) by following the requirements of 
subpart PP.


Sec.  98.243  Calculating GHG emissions.

    (a) If you route all process vent emissions and emissions from 
combustion of process off-gas to one or more stacks and use CEMS on 
each stack to measure CO2 emissions (except flare stacks), 
then you must determine process-based GHG emissions in accordance with 
paragraph (b) of this section. Otherwise, determine process-based GHG 
emissions in accordance with the procedures specified in paragraph (c) 
or (d) of this section.
    (b) Continuous emission monitoring system (CEMS). Route all process 
vent emissions and emissions from combustion of process off-gas to one 
or more stacks and determine CO2 emissions from each stack 
(except flare stacks) according to the Tier 4 Calculation Methodology 
requirements in subpart C of this part. For each stack (except flare 
stacks) that includes emissions from combustion of petrochemical 
process off-gas, calculate CH4 and N2O emissions 
in accordance with subpart C of this part (use the Tier 3 methodology 
and emission factors for ``Petroleum'' in Table C-2 of subpart C of 
this part). For each flare, calculate CO2, CH4, 
and N2O emissions using the methodology specified in Sec.  
98.253(b)(1) through (b)(3).
    (c) Mass balance for each petrochemical process unit. Calculate the 
emissions of CO2 from each process unit, for each calendar 
month as described in paragraphs (c)(1) through (c)(5) of this section.
    (1) For each gaseous and liquid feedstock and product, measure the 
volume or mass used or produced each calendar month with a flow meter 
by following the procedures specified in Sec.  98.244(b)(2). 
Alternatively, for liquids, you may calculate the volume used or 
collected in each month based on measurements of the liquid level in a 
storage tank at least once per month (and just prior to each change in 
direction of the level of the liquid) following the procedures 
specified in Sec.  98.244(b)(3). Fuels used for combustion purposes are 
not considered to be feedstocks.
    (2) For each solid feedstock and product, measure the mass used or 
produced each calendar month by following the procedures specified in 
Sec.  98.244(b)(1).
    (3) Collect a sample of each feedstock and product at least once 
per month and determine the carbon content of each

[[Page 56448]]

sample according to the procedures in Sec.  98.244(b)(4). 
Alternatively, you may use the results of analyses conducted by a fuel 
or feedstock supplier, provided the sampling and analysis are conducted 
at least once per month using any of the procedures specified in Sec.  
98.244(b)(4). If multiple valid carbon content measurements are made 
during the monthly measurement period, average them arithmetically.
    (4) If you determine that the monthly average concentration of a 
specific compound in a feedstock or product is greater than 99.5 
percent by volume (or mass for liquids and solids), then as an 
alternative to the sampling and analysis specified in paragraph (c)(3) 
of this section, you may calculate the carbon content assuming 100 
percent of that feedstock or product is the specific compound during 
periods of normal operation. You must maintain records of any 
determination made in accordance with this paragraph (c)(4) along with 
all supporting data, calculations, and other information. This 
alternative may not be used for products during periods of operation 
when off-specification product is produced. You must reevaluate 
determinations made under this paragraph (c)(4) after any process 
change that affects the feedstock or product composition. You must keep 
records of the process change and the corresponding composition 
determinations. If the feedstock or product composition changes so that 
the average monthly concentration falls below 99.5 percent, you are no 
longer permitted to use this alternative method.
    (5) Calculate the CO2 mass emissions for each 
petrochemical process unit using Equations X-1 through X-4 of this 
section.
    (i) Gaseous feedstocks and products. Use Equation X-1 of this 
section to calculate the net annual carbon input or output from gaseous 
feedstocks and products. Note that the result will be a negative value 
if there are no gaseous feedstocks in the process but there are gaseous 
products.
[GRAPHIC] [TIFF OMITTED] TR30OC09.083


Where:

Cg = Annual net contribution to calculated emissions from 
carbon (C) in gaseous materials (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i 
introduced in month ``n'' (standard cubic feet, scf).
(CCgf)i,n = Average carbon content of the 
gaseous feedstock i for month ``n'' (kg C per kg of feedstock).
(MWf)i = Molecular weight of gaseous feedstock 
i (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
(Pgp)i,n = Volume of gaseous product i 
produced in month ``n'' (scf).
(CCgp)i,n = Average carbon content of gaseous 
product i, including streams containing CO2 recovered for 
sale or use in another process, for month ``n'' (kg C per kg of 
product).
(MWp)i = Molecular weight of gaseous product i 
(kg/kg-mole).
j = Number of feedstocks.
k = Number of products.

    (ii) Liquid feedstocks and products. Use Equation X-2 of this 
section to calculate the net carbon input or output from liquid 
feedstocks and products. Note that the result will be a negative value 
if there are no liquid feedstocks in the process but there are liquid 
products.
[GRAPHIC] [TIFF OMITTED] TR30OC09.084


Where:

Cl = Annual net contribution to calculated emissions from 
carbon in liquid materials, including liquid organic wastes (kg/yr).
(Flf)i,n = Volume or mass of liquid feedstock 
i introduced in month ``n'' (gallons or kg).
(CClf)i,n = Average carbon content of liquid 
feedstock i for month ``n'' (kg C per gallon or kg of feedstock).
(Plp)i,n = Volume or mass of liquid product i 
produced in month ``n'' (gallons or kg).
(CClp)i,n = Average carbon content of liquid 
product i, including organic liquid wastes, for month ``n'' (kg C 
per gallon or kg of product).
j = Number of feedstocks.
k = Number of products.

    (iii) Solid feedstocks and products. Use Equation X-3 of this 
section to calculate the net annual carbon input or output from solid 
feedstocks and products. Note that the result will be a negative value 
if there are no solid feedstocks in the process but there are solid 
products.

[GRAPHIC] [TIFF OMITTED] TR30OC09.085

Where:

Cs = Annual net contribution to calculated emissions from 
carbon in solid materials (kg/yr).
(Fsf)i,n = Mass of solid feedstock i 
introduced in month ``n'' (kg).
(CCsf)i,n = Average carbon content of solid 
feedstock i for month ``n'' (kg C per kg of feedstock).
(Psp)i,n = Mass of solid product i produced in 
month ``n'' (kg).
(CCsp)i,n = Average carbon content of solid 
product i in month ``n'' (kg C per kg of product).
j = Number of feedstocks.
k = Number of products.

    (iv) Annual emissions. Use the results from Equations X-1 through 
X-3 of this section, as applicable, in Equation X-4 of this section to 
calculate annual CO2 emissions.


[[Page 56449]]


[GRAPHIC] [TIFF OMITTED] TR30OC09.086

Where:

CO2 = Annual CO2 mass emissions from process 
operations and process off-gas combustion (metric tons/year).
0.001 = Conversion factor from kg to metric tons.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of carbon (C) (kg/kg-mole).

    (d) Optional combustion methodology for ethylene production 
processes. For any ethylene production process, calculate 
CO2 emissions from combustion of fuel that contains ethylene 
process off-gas using the Tier 3 or Tier 4 methodology in subpart C of 
this part, and calculate CH4 and N2O emissions 
using the applicable procedures in Sec.  98.33(c) (use the emission 
factors for ``Petroleum'' in Table C-2 of subpart C of this part 
(General Stationary Fuel Combustion Sources)). You are not required to 
use the same Tier for each stationary combustion unit that burns 
ethylene process off-gas. For each flare, calculate CO2, 
CH4, and N2O emissions using the methodology 
specified in Sec.  98.253(b)(1) through (b)(3).


Sec.  98.244  Monitoring and QA/QC requirements.

    (a) If you use CEMS to determine emissions from process vents, you 
must comply with the procedures specified in Sec.  98.34(c).
    (b) If you use the mass balance methodology in Sec.  98.243(c), use 
the procedures specified in paragraphs (b)(1) through (b)(4) of this 
section to determine feedstock and product flows and carbon contents.
    (1) Operate and maintain 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. Calibrate the 
measurement device according to the procedures specified by the method, 
the procedures specified by the manufacturer, or Sec.  98.3(i). 
Recalibrate either biennially or at the minimum frequency specified by 
the manufacturer.
    (2) Operate and maintain all flow meters for gas and liquid 
feedstocks and products by following the procedures in Sec.  98.3(i) 
and using any of the flow meter methods specified in paragraphs 
(b)(2)(i) through (b)(2)(xv) of this section, as applicable, use a 
standard method published by a consensus-based standards organization 
(e.g., ASTM, API, etc.), or follow procedures specified by the flow 
meter manufacturer or Sec.  98.3(i). Recalibrate each flow meter either 
biennially or at the minimum frequency specified by the manufacturer.
    (i) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (ii) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (iii) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters 
(incorporated by reference, see Sec.  98.7).
    (iv) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (v) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (vi) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow 
in Closed Conduits by Weighing Method (incorporated by reference, see 
Sec.  98.7).
    (vii) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7).
    (viii) ASME MFC-14M-2003 (Reaffirmed 2008), Measurement of Fluid 
Flow Using Small Bore Precision Orifice Meters (incorporated by 
reference, see Sec.  98.7).
    (ix) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits 
with Electromagnetic Flowmeters (incorporated by reference, see Sec.  
98.7).
    (x) ASME MFC-18M-2001 (Reaffirmed 2006), Measurement of Fluid Flow 
Using Variable Area Meters (incorporated by reference, see Sec.  98.7).
    (xi) ASME MFC-22-2007 Measurement of Liquid by Turbine Flowmeters 
(incorporated by reference, see Sec.  98.7).
    (xii) AGA Report No. 3: Orifice Metering of Natural Gas and Other 
Related Hydrocarbon Fluids, Part 1: General Equations and Uncertainty 
Guidelines (1990), Part 2: Specification and Installation Requirements 
(2000) (incorporated by reference, see Sec.  98.7).
    (xiii) AGA Transmission Measurement Committee Report No. 7: 
Measurement of Natural Gas by Turbine Meter (2006)/February 
(incorporated by reference, see Sec.  98.7).
    (xiv) AGA Report No. 11: Measurement of Natural Gas by Coriolis 
Meter (2003) (incorporated by reference, see Sec.  98.7).
    (xv) ISO 8316: Measurement of Liquid Flow in Closed Conduits--
Method by Collection of the Liquid in a Volumetric Tank (1987-10-01) 
First Edition (incorporated by reference, see Sec.  98.7).
    (3) Perform tank level measurements (if used to determine feedstock 
or product flows) according to any standard method published by a 
consensus-based standards organization (e.g., ASTM, API, etc.) or 
follow procedures specified by the measurement device manufacturer or 
Sec.  98.3(i). Calibrate the measurement devices prior to the effective 
date of the rule, and recalibrate either biennially or at the minimum 
frequency specified by the manufacturer or Sec.  98.3(i).
    (4) Use any of the standard methods specified in paragraphs 
(b)(4)(i) through (b)(4)(x) of this section, as applicable, 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 the method and as specified in 
paragraphs (b)(4)(i) through (b)(4)(x), as applicable. For coal used as 
a feedstock, the samples for carbon content determinations shall be 
taken at a location that is representative of the coal feedstock used 
during the corresponding monthly period. For carbon black products, 
samples shall be taken of each grade or type of product produced during 
the monthly period. Samples of coal feedstock or carbon black product 
for carbon content determinations may be either grab samples collected 
and analyzed monthly or a composite of samples collected more 
frequently and analyzed monthly. Analyses conducted in accordance with 
methods specified in paragraphs (b)(4)(i) through (b)(4)(x) of this 
section may be performed by the owner or operator, by an indpendent 
laboratory, or by the supplier of a feedstock.
    (i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling 
of Process Vents With a Portable Gas

[[Page 56450]]

Chromatograph (incorporated by reference, see Sec.  98.7).
    (iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for 
Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity 
Ethylene by Gas Chromatography (incorporated by reference, see Sec.  
98.7).
    (iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for 
Ultimate Analysis of Coal and Coke (incorporated by reference, see 
Sec.  98.7).
    (vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec.  
98.7).
    (vii) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7).
    (viii) Methods 8031, 8021, or 8015 in ``Test Methods for Evaluating 
Solid Waste, Physical/Chemical Methods,'' EPA Publication No. SW-846, 
Third Edition, September 1986, as amended by Update I, November 15, 
1992.
    (ix) Method 18 at 40 CFR part 60, appendix A-6.
    (x) Performance Specification 9 in 40 CFR part 60, appendix B for 
continuous online gas analyzers. The 7-day calibration error test 
period must be completed prior to the effective date of the rule.


Sec.  98.245  Procedures for estimating missing data.

    For missing feedstock flow rates, product flow rates, and carbon 
contents, use the same procedures as for missing flow rates and carbon 
contents for fuels as specified in Sec.  98.35.


Sec.  98.246  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a), 
(b), or (c) of this section, as appropriate for each process unit.
    (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)(10) of this section for each type of petrochemical produced, 
reported by process unit.
    (1) The petrochemical process unit ID number or other appropriate 
descriptor.
    (2) The type of petrochemical produced, names of other products, 
and names of carbon-containing feedstocks.
    (3) Annual CO2 emissions calculated using Equation X-4 
of this subpart.
    (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. Indicate whether you used the alternative to 
sampling and analysis specified in Sec.  98.243(c)(4).
    (5) Annual quantity of each type of petrochemical produced from 
each process unit (metric tons).
    (6) Name of each method listed in Sec.  98.244 used to determine a 
measured parameter (or description of manufacturer's recommended 
method).
    (7) The dates and summarized results (e.g., percent calibration 
error) of the calibrations of each measurement device.
    (8) Identification of each combustion unit that burned both process 
off-gas and supplemental fuel.
    (9) If you comply with the alternative to sampling and analysis 
specified in Sec.  98.243(c)(4), the amount of time during which off-
specification product was produced, the volume or mass of off-
specification product produced, and if applicable, the date of any 
process change that reduced the composition to less than 99.5 percent.
    (10) You may elect to report the flow and carbon content of 
wastewater, and you may elect to report the carbon content of 
hydrocarbons 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.
    (b) If you use CEMS to measure CO2 emissions in 
accordance with Sec.  98.243(b), then you must report the relevant 
information required under Sec.  98.36 for the Tier 4 Calculation 
Methodology and the information listed in paragraphs (b)(1) through 
(b)(6) of this section.
    (1) For CEMS used on stacks for stationary combustion units, report 
the relevant information required under Sec.  98.36 for the Tier 4 
calculation methodology.
    (2) For CEMS used on stacks that are not used for stationary 
combustion units, report the information required under Sec.  
98.36(e)(2)(vi) and (vii).
    (3) The petrochemical process unit ID or other appropriate 
descriptor, and the type of petrochemical produced.
    (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. If 
a stationary combustion source serves multiple petrochemical process 
units or units other than the petrochemical process unit, estimate 
based on engineering judgment the fraction of fuel energy and emissions 
attributable to each petrochemical process unit.
    (5) The CH4 and N2O emissions from each stack 
and the combined CH4 and N2O emissions from all 
stationary combustion units that burn process off-gas from the 
petrochemical process unit, the cumulative annual heat input used in 
Equation C-10 in Sec.  98.33(c) of this subpart, and the annual flow of 
each fuel on which this heat input is based.
    (6) ID or other appropriate descriptor of each stationary 
combustion unit that burns process off-gas.
    (7) Information listed in Sec.  98.256(e) of subpart Y of this part 
for each flare that burns process off-gas.
    (8) Annual quantity of each type of petrochemical produced from 
each process unit (metric tons).
    (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)(4) of this section.
    (1) For each stationary combustion unit that burns ethylene process 
off-gas (or group of stationary sources with a common pipe), the 
relevant information listed in Sec.  98.36 for the selected Tier 3 or 
Tier 4 methodology. If a stationary combustion source serves multiple 
ethylene process units or units other than the ethylene process unit, 
estimate based on engineering judgment the fraction of fuel energy and 
emissions attributable to each ethylene process unit.
    (2) Information listed in Sec.  98.256(e) for each flare that burns 
ethylene process off-gas.
    (3) Name and annual quantity of each feedstock.
    (4) Annual quantity of each type of petrochemical produced from 
each process unit (metric tons).


Sec.  98.247  Records that must be retained.

    In addition to the recordkeeping requirements in Sec.  98.3(g), you 
must retain the records specified in paragraphs (a) through (c) of this 
section, as applicable.
    (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.

[[Page 56451]]

    (b) If you comply with the mass balance methodology in Sec.  
98.243(c), then you must retain records of the information listed in 
paragraphs (b)(1) through (b)(3) of this section.
    (1) Results of feedstock or product composition determinations 
conducted in accordance with Sec.  98.243(c)(4).
    (2) Start and end times and calculated carbon contents for time 
periods when off-specification product is produced, if you comply with 
the alternative methodology in Sec.  98.243(c)(4) for determining 
carbon content of feedstock or product.
    (3) A part of the monitoring plan required under Sec.  98.3(g)(5), 
record the estimated accuracy of measurement devices and the technical 
basis for these estimates.
    (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 Tier 3 and/or Tier 4 Calculation Methodologies in Sec.  98.37.


Sec.  98.248  Definitions.

    Except as specified in this section, all terms used in this subpart 
have the same meaning given in the Clean Air Act and subpart A of this 
part.
    Product, as used in Sec.  98.243, means each of the following 
carbon-containing outputs from a process: the petrochemical, recovered 
byproducts, and liquid organic wastes that are not incinerated onsite. 
Product does not include process vent emissions, fugitive emissions, or 
wastewater.

Subpart Y--Petroleum Refineries


Sec.  98.250  Definition of source category.

    (a) A petroleum refinery is any facility engaged in producing 
gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel 
oils, residual fuel oils, lubricants, or asphalt (bitumen) through 
distillation of petroleum or through redistillation, cracking, or 
reforming of unfinished petroleum derivatives, except as provided in 
paragraph (b) of this section.
    (b) For the purposes of this subpart, facilities that distill only 
pipeline transmix (off-spec material created when different 
specification products mix during pipeline transportation) are not 
petroleum refineries, regardless of the products produced.
    (c) This source category consists of the following sources at 
petroleum refineries: Catalytic cracking units; fluid coking units; 
delayed coking units; catalytic reforming units; coke calcining units; 
asphalt blowing operations; blowdown systems; storage tanks; process 
equipment components (compressors, pumps, valves, pressure relief 
devices, flanges, and connectors) in gas service; marine vessel, barge, 
tanker truck, and similar loading operations; flares; sulfur recovery 
plants; and non-merchant hydrogen plants (i.e., hydrogen plants that 
are owned or under the direct control of the refinery owner and 
operator).


Sec.  98.251  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a petroleum refineries process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.252  GHGs to report.

    You must report:
    (a) CO2, CH4, and N2O combustion 
emissions from stationary combustion units and from each flare. 
Calculate and report these emissions under subpart C of this part 
(General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C, except for CO2 emissions from 
combustion of refinery 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. 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.
    (b) CO2, CH4, and N2O coke burn-
off emissions from each catalytic cracking unit, fluid coking unit, and 
catalytic reforming unit under this subpart.
    (c) CO2 emissions from sour gas sent off site for sulfur 
recovery operations under this subpart. You must follow the calculation 
methodologies from Sec.  98.253(f) and the monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of this subpart.
    (d) CO2 process emissions from each on-site sulfur 
recovery plant under this subpart.
    (e) CO2, CH4, and N2O emissions 
from each coke calcining unit under this subpart.
    (f) CO2 and CH4 emissions from asphalt 
blowing operations under this subpart.
    (g) CH4 emissions from equipment leaks, storage tanks, 
loading operations, delayed coking units, and uncontrolled blowdown 
systems under this subpart.
    (h) CO2, CH4, and N2O emissions 
from each process vent not specifically included in paragraphs (a) 
through (g) of this section under this subpart.
    (i) CO2 and CH4 emissions from non-merchant 
hydrogen production under this subpart. You must follow the calculation 
methodologies, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements of subpart P of 
this part.


Sec.  98.253  Calculating GHG emissions.

    (a) Calculate GHG emissions required to be reported in Sec.  
98.252(b) through (i) using the applicable methods in paragraphs (b) 
through (n) of this section.
    (b) For flares, calculate GHG emissions according to the 
requirements in paragraphs (b)(1) through (b)(3) of this section.
    (1) Calculate the CO2 emissions according to the 
applicable requirements in paragraphs (b)(1)(i) through (b)(1)(iii) of 
this section.
    (i) Flow measurement. If you have a continuous flow monitor on the 
flare, you must use the measured flow rates when the monitor is 
operational and the flow rate is within the calibrated range of the 
measurement device to calculate the flare gas flow. If you do not have 
a continuous flow monitor on the flare and for periods when the monitor 
is not operational or the flow rate is outside the calibrated range of 
the measurement device, you must use engineering calculations, company 
records, or similar estimates of volumetric flare gas flow.
    (ii) Heat value or carbon content measurement. If you have a 
continuous higher heating value monitor or gas composition monitor on 
the flare or if you monitor these parameters at least weekly, you must 
use the measured heat value or carbon content value in calculating the 
CO2 emissions from the flare using the applicable methods in 
paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B).
    (A) If you monitor gas composition, calculate the CO2 
emissions from the flare using Equation Y-1 of this section. If daily 
or more frequent measurement data are available, you must use daily 
values when using Equation Y-1 of this section; otherwise, use weekly 
values.

[[Page 56452]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.087

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).
(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.

    (B) If you monitor heat content but do not monitor gas composition, 
calculate the CO2 emissions from the flare using Equation Y-
2 of this section. If daily or more frequent measurement data are 
available, you must use daily values when using Equation Y-2 of this 
section; otherwise, use weekly values.
[GRAPHIC] [TIFF OMITTED] TR30OC09.088

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.
(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) and (MW)p is the 
average molecular weight of the flare gas combusted during 
measurement period (kg/kg-mole).
(HHV)p = Higher heating value for the flare gas combusted 
during measurement period (British thermal units per scf, Btu/scf = 
MMBtu/MMscf). If measurements are taken more frequently than daily, 
use the arithmetic average of measurement values within the day to 
calculate a daily average.
EmF = Default CO2 emission factor of 60 kilograms 
CO2/MMBtu (HHV basis).
    (iii) Alternative to heat value or carbon content measurements. If 
you do not measure the higher heating value or carbon content of the 
flare gas at least weekly, determine the quantity of gas discharged to 
the flare separately for periods of routine flare operation and for 
periods of start-up, shutdown, or malfunction, and calculate the 
CO2 emissions as specified in paragraphs (b)(1)(iii)(A) 
through (b)(1)(iii)(C) of this section.
    (A) For periods of start-up, shutdown, or malfunction, use 
engineering calculations and process knowledge to estimate the carbon 
content of the flared gas for each start-up, shutdown, or malfunction 
event exceeding 500,000 scf/day.
    (B) For periods of normal operation, use the average heating value 
measured for the fuel gas for the heating value of the flare gas. If 
heating value is not measured, the heating value may be estimated from 
historic data or engineering calculations.
    (C) Calculate the CO2 emissions using Equation Y-3 of 
this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.089

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).
FlareNorm = Annual volume of flare gas combusted during 
normal operations from company records, (million (MM) standard cubic 
feet per year, MMscf/year).
HHV = Higher heating value for fuel gas or flare gas from company 
records (British thermal units per scf, Btu/scf = MMBtu/MMscf).
EmF = Default CO2 emission factor for flare gas of 60 
kilograms CO2/MMBtu (HHV basis).
n = Number of start-up, shutdown, and malfunction events during the 
reporting year exceeding 500,000 scf/day.
p = Start-up, shutdown, and malfunction event index.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
(FlareSSM)p = Volume of flare gas combusted 
during indexed start-up, shutdown, or malfunction event from 
engineering calculations, (scf/event).
(MW)p = Average molecular weight of the flare gas, from 
the analysis results or engineering calculations for the event (kg/
kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(CC)p = Average carbon content of the flare gas, from 
analysis results or engineering calculations for the event (kg C per 
kg flare gas).

    (2) Calculate CH4 using Equation Y-4 of this section.

[[Page 56453]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.090

Where:

CH4 = Annual methane emissions from flared gas (metric 
tons CH4/year).
CO2 = Emission rate of CO2 from flared gas 
calculated in paragraph (b)(1) of this section (metric tons/year).
EmFCH4 = Default CH4 emission factor for 
``PetroleumProducts'' from Table C-2 of subpart C of this part 
(General Stationary Fuel Combustion Sources) (kg CH4/
MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg 
CO2/MMBtu (HHV basis).
0.02/0.98 = Correction factor for flare combustion efficiency.
16/44 = Correction factor ratio of the molecular weight of 
CH4 to CO2.
fCH4 = Weight fraction of carbon in the flare gas prior 
to combustion that is contributed by methane from measurement values 
or engineering calculations (kg C in methane in flare gas/kg C in 
flare gas); default is 0.4.

    (3) Calculate N2O emissions using Equation Y-5 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.091

Where:

N2O = Annual nitrous oxide emissions from flared gas 
(metric tons N2O/year).
CO2 = Emission rate of CO2 from flared gas 
calculated in paragraph (b)(1) of this section (metric tons/year).
EmFN2O = Default N2O emission factor for 
``PetroleumProducts'' from Table C-2 of subpart C of this part 
(General Stationary Fuel Combustion Sources) (kg N2O/
MMBtu).
EmF = Default CO2 emission factor for flare gas of 60 kg 
CO2/MMBtu (HHV basis).

    (c) For catalytic cracking units and traditional fluid coking 
units, calculate the GHG emissions using the applicable methods 
described in paragraphs (c)(1) through (c)(5) of this section.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part (General Stationary Fuel 
Combustion Sources), you must calculate and report CO2 
emissions as provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this 
section. Other catalytic cracking units and traditional fluid coking 
units must either install a CEMS that complies with the Tier 4 
Calculation Methodology in subpart C of this part (General Stationary 
Combustion Sources), or follow the requirements of paragraphs (c)(2) or 
(3) of this section.
    (i) Calculate CO2 emissions by following the Tier 4 
Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (ii) If a CO boiler or other post-combustion device is used, you 
must also calculate the CO2 emissions from the fuel fired to 
the CO boiler or post-combustion device using the applicable methods 
for stationary combustion units in subpart C of this part. Calculate 
the process emissions from the catalytic cracking unit or fluid coking 
unit as the difference in the CO2 CEMS emissions and the 
calculated combustion emissions associated with the CO boiler.
    (2) For catalytic cracking units and fluid coking units with rated 
capacities greater than 10,000 barrels per stream day (bbls/sd) that do 
not use a continuous CO2 CEMS for the final exhaust stack, 
you must continuously or no less frequently than hourly monitor the 
O2, CO2, and (if necessary) CO concentrations in 
the exhaust stack from the catalytic cracking unit regenerator or fluid 
coking unit burner prior to the combustion of other fossil fuels and 
calculate the CO2 emissions according to the requirements of 
paragraphs (c)(2)(i) through (c)(2)(iii) of this section:
    (i) Calculate the CO2 emissions from each catalytic 
cracking unit and fluid coking unit using Equation Y-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.092

Where:

CO2 = Annual CO2 mass emissions (metric tons/
year).
Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner 
prior to the combustion of other fossil fuels (dry standard cubic 
feet per hour, dscfh).
%CO2 = Hourly average percent CO2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas 
stream from the fluid catalytic cracking unit regenerator or fluid 
coking unit burner (percent by volume--dry basis). When there is no 
post-combustion device, assume %CO to be zero.
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).
n = Number of hours in calendar year.

    (ii) Either continuously monitor the volumetric flow rate of 
exhaust gas from the fluid catalytic cracking unit regenerator or fluid 
coking unit burner prior to the combustion of other fossil fuels or 
calculate the volumetric flow rate of this exhaust gas stream using 
Equation Y-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.093

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).

[[Page 56454]]

%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.

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts 
materials other than catalytic cracking unit or fluid coking unit 
exhaust gas, you must determine the CO2 emissions resulting 
from the combustion of these fuels or other materials following the 
requirements in subpart C and report those emissions by following the 
requirements of subpart C of this part.
    (3) For catalytic cracking units and fluid coking units with rated 
capacities of 10,000 barrels per stream day (bbls/sd) or less that do 
not use a continuous CO2 CEMS for the final exhaust stack, 
comply with the requirements in paragraph (c)(3)(i) of this section or 
paragraphs (c)(3)(ii) and (c)(3)(iii) of this section, as applicable.
    (i) If you continuously or no less frequently than daily monitor 
the O2, CO2, and (if necessary) CO concentrations 
in the exhaust stack from the catalytic cracking unit regenerator or 
fluid coking unit burner prior to the combustion of other fossil fuels, 
you must calculate the CO2 emissions according to the 
requirements of paragraphs (c)(2)(i) through (c)(2)(iii) of this 
section, except that daily averages are allowed and the summation can 
be performed on a daily basis.
    (ii) If you do not monitor at least daily the O2, 
CO2, and (if necessary) CO concentrations in the exhaust 
stack from the catalytic cracking unit regenerator or fluid coking unit 
burner prior to the combustion of other fossil fuels, calculate the 
CO2 emissions from each catalytic cracking unit and fluid 
coking unit using Equation Y-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.094

Where:

CO2 = Annual CO2 mass emissions (metric tons/
year).
Qunit = Annual throughput of unit from company records 
(barrels (bbls) per year, bbl/yr).
CBF = Coke burn-off factor from engineering calculations (kg coke 
per barrel of feed); default for catalytic cracking units = 7.3; 
default for fluid coking units = 11.
0.001 = Conversion factor (metric ton/kg).
CC = Carbon content of coke based on measurement or engineering 
estimate (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg 
CO2 per kg C).

    (iii) If you have a CO boiler that uses auxiliary fuels or combusts 
materials other than catalytic cracking unit or fluid coking unit 
exhaust gas, you must determine the CO2 emissions resulting 
from the combustion of these fuels or other materials following the 
requirements in subpart C of this part (General Stationary Fuel 
Combustion Sources) and report those emissions by following the 
requirements of subpart C of this part.
    (4) Calculate CH4 emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source 
test of the unit, or Equation Y-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.095

Where:

CH4 = Annual methane emissions from coke burn-off (metric 
tons CH4/year).
CO2 = Emission rate of CO2 from coke burn-off 
calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or 
(g)(2) of this section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from Table C-1 of subpart C of this part (General 
Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF2 = Default CH4 emission factor for 
``PetroleumProducts'' from Table C-2 of subpart C of this part 
(General Stationary Fuel Combustion Sources) (kg CH4/
MMBtu).

    (5) Calculate N2O emissions using either unit specific 
measurement data, a unit-specific emission factor based on a source 
test of the unit, or Equation Y-10 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.096

Where:

N2O = Annual nitrous oxide emissions from coke burn-off 
(mt N2O/year).
CO2 = Emission rate of CO2 from coke burn-off 
calculated in paragraphs (c)(1), (c)(2), (e)(1), (e)(2), (g)(1), or 
(g)(2) of this section, as applicable (metric tons/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from Table C-1 of subpart C of this part (General 
Stationary Fuel Combustion Sources) (kg CO2/MMBtu).
EmF3 = Default N2O emission factor for 
``PetroleumProducts'' from Table C-2 of subpart C of this part (kg 
N2O/MMBtu).

    (d) For fluid coking units that use the flexicoking design, the GHG 
emissions from the resulting use of the low value fuel gas must be 
accounted for only once. Typically, these emissions will be accounted 
for using the methods described in subpart C of this part (General 
Stationary Fuel Combustion Sources). Alternatively, you may use the 
methods in paragraph (c) of this section provided that you do not 
otherwise account for the subsequent combustion of this low value fuel 
gas.
    (e) For catalytic reforming units, calculate the CO2 
emissions using the applicable methods described in paragraphs (e)(1) 
through (e)(3) of this section and calculate the CH4 and 
N2O emissions using the methods described in paragraphs 
(c)(4) and (c)(5) of this section, respectively.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part (General Stationary Fuel 
Combustion Sources), you must calculate CO2 emissions as 
provided in paragraphs (c)(1)(i) and (c)(1)(ii) of this section. Other 
catalytic reforming units must either install a CEMS that complies with 
the Tier 4 Calculation Methodology in subpart C of this part, or follow 
the requirements of paragraph (e)(2) or (e)(3) of this section.
    (2) If you continuously or no less frequently than daily monitor 
the O2, CO2, and (if necessary) CO concentrations 
in the exhaust stack from the catalytic reforming unit catalyst 
regenerator prior to the combustion of other fossil fuels, you must 
calculate the CO2 emissions according to the requirements of 
paragraphs (c)(2)(i) through (c)(2)(iii) of this section.

[[Page 56455]]

    (3) Calculate CO2 emissions from the catalytic reforming 
unit catalyst regenerator using Equation Y-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.097

Where:

CO2 = Annual CO2 emissions (metric tons/year).
CBQ = Coke burn-off quantity per regeneration cycle from 
engineering estimates (kg coke/cycle).
n = Number of regeneration cycles in the calendar year.
CC = Carbon content of coke based on measurement or engineering 
estimate (kg C per kg coke); default = 0.94.
44/12 = Ratio of molecular weight of CO2 to C (kg 
CO2 per kg C).
0.001 = Conversion factor (metric ton/kg).

    (f) For on-site sulfur recovery plants, calculate and report 
CO2 process emissions from sulfur recovery plants according 
to the requirements in paragraphs (f)(1) through (f)(5) of this 
section. Combustion emissions from the sulfur recovery plant (e.g., 
from fuel combustion in the Claus burner or the tail gas treatment 
incinerator) must be reported under subpart C of this part (General 
Stationary Fuel Combustion Sources). For the purposes of this subpart, 
the sour gas stream for which monitoring is required according to 
paragraphs (f)(2) through (f)(5) of this section is not considered a 
fuel.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part, you must calculate 
CO2 emissions under this subpart by following the Tier 4 
Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources). You must monitor fuel use in the 
Claus burner, tail gas incinerator, or other combustion sources that 
discharge via the final exhaust stack from the sulfur recovery plant 
and calculate the combustion emissions from the fuel use according to 
subpart C of this part. Calculate the process emissions from the sulfur 
recovery plant as the difference in the CO2 CEMS emissions 
and the calculated combustion emissions associated with the sulfur 
recovery plant final exhaust stack. 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.
    (2) Flow measurement. If you have a continuous flow monitor on the 
sour gas feed to the sulfur recovery plant, you must use the measured 
flow rates when the monitor is operational to calculate the sour gas 
flow rate. If you do not have a continuous flow monitor on the sour gas 
feed to the sulfur recovery plant, you must use engineering 
calculations, company records, or similar estimates of volumetric sour 
gas flow.
    (3) Carbon content. If you have a continuous gas composition 
monitor capable of measuring carbon content on the sour gas feed to the 
sulfur recovery plant or if you monitor gas composition for carbon 
content on a routine basis, you must use the measured carbon content 
value. Alternatively, you may develop a site-specific carbon content 
factor using limited measurement data or engineering estimates or use 
the default factor of 0.20.
    (4) Calculate the CO2 emissions from each sulfur 
recovery plant using Equation Y-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.098

Where:

CO2 = Annual CO2 emissions (metric tons/year).
FSG = Volumetric flow rate of sour gas feed (including 
sour water stripper gas) to the sulfur recovery plant (scf/year).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFC = Mole fraction of carbon in the sour gas to the 
sulfur recovery plant (kg-mole C/kg-mole gas); default = 0.20.
0.001 = Conversion factor, kg to metric tons.

    (5) If tail gas is recycled to the front of the sulfur recovery 
plant and the recycled flow rate and carbon content is included in the 
measured data under paragraphs (f)(2) and (f)(3) of this section, 
respectively, then the annual CO2 emissions calculated in 
paragraph (f)(4) of this section must be corrected to avoid double 
counting these emissions. You may use engineering estimates to perform 
this correction or assume that the corrected CO2 emissions 
are 95 percent of the uncorrected value calculated using Equation Y-12 
of this section.
    (g) For coke calcining units, calculate GHG emissions according to 
the applicable provisions in paragraphs (g)(1) through (g)(3) of this 
section.
    (1) If you operate and maintain a CEMS that measures CO2 
emissions according to subpart C of this part, you must calculate and 
report CO2 emissions under this subpart by following the 
Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources). You must monitor fuel use in the 
coke calcining unit that discharges via the final exhaust stack from 
the coke calcining unit and calculate the combustion emissions from the 
fuel use according to subpart C of this part. Calculate the process 
emissions from the coke calcining unit as the difference in the 
CO2 CEMS emissions and the calculated combustion emissions 
associated with the coke calcining unit final exhaust stack. Other coke 
calcining units must either install a CEMS that complies with the Tier 
4 Calculation Methodology in subpart C of this part, or follow the 
requirements of paragraph (g)(2) of this section.
    (2) Calculate the CO2 emissions from the coke calcining 
unit using Equation Y-13 of this section.

[[Page 56456]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.099

Where:

CO2 = Annual CO2 emissions (metric tons/year).
Min = Annual mass of green coke fed to the coke calcining 
unit from facility records (metric tons/year).
CCGC = Average mass fraction carbon content of green coke 
from facility measurement data (metric ton carbon/metric ton green 
coke).
Mout = Annual mass of marketable petroleum coke produced 
by the coke calcining unit from facility records (metric tons 
petroleum coke/year).
Mdust = Annual mass of petroleum coke dust collected in 
the dust collection system of the coke calcining unit from facility 
records (metric ton petroleum coke dust/year).
CCMPC = Average mass fraction carbon content of 
marketable petroleum coke produced by the coke calcining unit from 
facility measurement data (metric ton carbon/metric ton petroleum 
coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).

    (3) For all coke calcining units, use the CO2 emissions 
from the coke calcining unit calculated in paragraphs (g)(1) or (g)(2), 
as applicable, and calculate CH4 using the methods described 
in paragraph (c)(4) of this section and N2O emissions using 
the methods described in paragraph (c)(5) of this section.
    (h) For asphalt blowing operations, calculate GHG emissions 
according to the requirements in paragraph (j) of this section or 
according to the applicable provisions in paragraphs (h)(1) and (h)(2) 
of this section.
    (1) For uncontrolled asphalt blowing operations or asphalt blowing 
operations controlled by vapor scrubbing, calculate CO2 and 
CH4 emissions using Equations Y-14 and Y-15 of this section, 
respectively.
[GRAPHIC] [TIFF OMITTED] TR30OC09.100

Where:

CO2 = Annual CO2 emissions from uncontrolled 
asphalt blowing (metric tons CO2/year).
QAB = Quantity of asphalt blown (million barrels per 
year, MMbbl/year).
EFAB,CO2 = Emission factor for CO2 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CO2/MMbbl asphalt blown); default = 1,100.
[GRAPHIC] [TIFF OMITTED] TR30OC09.101

Where:

CH4 = Annual methane emissions from uncontrolled asphalt 
blowing (metric tons CH4/year).
QAB = Quantity of asphalt blown (million barrels per 
year, MMbbl/year).
EFAB,CH4 = Emission factor for CH4 from 
uncontrolled asphalt blowing from facility-specific test data 
(metric tons CH4/MMbbl asphalt blown); default = 580.

    (2) For asphalt blowing operations controlled by thermal oxidizer 
or flare, calculate CO2 and CH4 emissions using 
Equations Y-16 and Y-17 of this section, respectively, 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] TR30OC09.102

Where:

CO2 = Annual CO2 emissions from controlled 
asphalt blowing (metric tons CO2/year).
0.98 = Assumed combustion efficiency of thermal oxidizer or flare.
QAB = Quantity of asphalt blown (MMbbl/year).
CEFAB = Carbon emission factor from asphalt blowing from 
facility-specific test data (metric tons C/MMbbl asphalt blown); 
default = 2,750.
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
[GRAPHIC] [TIFF OMITTED] TR30OC09.103

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) For delayed coking units, calculate the CH4 
emissions from the depressurization of the coking unit vessel (i.e., 
the ``coke drum'') to atmosphere using either of the methods provided 
in paragraphs (i)(1) or (i)(2), provided no water or steam is added to 
the vessel once it is vented to the atmosphere. You must use the method 
in paragraph (i)(1) of this section if you add water or steam to the 
vessel after it is vented to the atmosphere.
    (1) Use the process vent method in paragraph (j) of this section 
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 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.
[GRAPHIC] [TIFF OMITTED] TR30OC09.104


[[Page 56457]]


Where:

CH4 = Annual methane emissions from the delayed coking 
unit vessel opening (metric ton/year).
N = Cumulative number of vessel openings for all delayed coking unit 
vessels of the same dimensions during the year.
H = Height of coking unit vessel (feet).
PCV = Gauge pressure of the coking vessel when opened to 
the atmosphere prior to coke cutting or, if the alternative method 
provided in paragraph (i)(2) of this section is used, gauge pressure 
of the coking vessel when depressurization gases are first routed to 
the atmosphere (pounds per square inch gauge, psig).
14.7 = Assumed atmospheric pressure (pounds per square inch, psi).
fvoid = Volumetric void fraction of coking vessel prior 
to steaming (cf gas/cf of vessel); default = 0.6.
D = Diameter of coking unit vessel (feet).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
MFCH4 = Mole fraction of methane in coking vessel gas 
(kg-mole CH4/kg-mole gas, wet basis); default value is 
0.01.
0.001 = Conversion factor (metric ton/kg).

    (2) Calculate the CH4 emissions from the 
depressurization vent and subsequent opening of the vessel for coke 
cutting operations using Equation Y-18 of this section and the pressure 
of the coking vessel when the depressurization gases are first routed 
to the atmosphere. If you have coke drums or vessels of different 
dimensions, use 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.
    (j) For each process vent not covered in paragraphs (a) through (i) 
of this section that can be reasonably expected to contain greater than 
2 percent by volume CO2 or greater than 0.5 percent by 
volume of CH4 or greater than 0.01 percent by volume (100 
parts per million) of N2O, calculate GHG emissions using the 
Equation Y-19 of this section. You must use Equation Y-19 of this 
section 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 (h)(1) or (h)(2) of this 
section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.105

Where:

Ex = Annual emissions of each GHG from process vent 
(metric ton/yr).
N = Number of venting events per year.
P = Index of venting events.
(VR)p = Average volumetric flow rate of process gas 
during the event (scf per hour).
(MFx)p = Mole fraction of GHG x in process 
vent during the event (kg-mol of GHG x/kg-mol vent gas).
MWx = Molecular weight of GHG x (kg/kg-mole); use 44 for 
CO2 or N2O and 16 for CH4.
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
(VT)p = Venting time for the event, (hours).
0.001 = Conversion factor (metric ton/kg).

    (k) For uncontrolled blowdown systems, you must either use the 
methods for process vents in paragraph (j) of this section or calculate 
CH4 emissions using Equation Y-20 of this section. Blowdown 
systems where the uncondensed gas stream is routed to a flare or 
similar control device is considered to be controlled and is not 
required to estimate emissions under this paragraph (k).

[GRAPHIC] [TIFF OMITTED] TR30OC09.106

Where:

CH4 = Methane emission rate from blowdown systems (mt 
CH4/year).
QRef = Quantity of crude oil plus the quantity of 
intermediate products received from off site that are processed at 
the facility (MMbbl/year).
EFBD = Methane emission factor for uncontrolled blown 
systems (scf CH4/MMbbl); default is 137,000.
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).

    (l) For equipment leaks, calculate CH4 emissions using 
the method specified in either paragraph (l)(1) or (l)(2) of this 
section.
    (1) Use process-specific methane composition data (from measurement 
data or process knowledge) and any of the emission estimation 
procedures provided in the Protocol for Equipment Leak Emissions 
Estimates (EPA-453/R-95-017, NTIS PB96-175401).
    (2) Use Equation Y-21 of this section.

    [GRAPHIC] [TIFF OMITTED] TR30OC09.107
    
Where:

CH4 = Annual methane emissions from equipment leaks 
(metric tons/year).
NCD = Number of atmospheric crude oil distillation 
columns at the facility.
NPU1 = Cumulative number of catalytic cracking units, 
coking units (delayed or fluid), hydrocracking, and full-range 
distillation columns (including depropanizer and debutanizer 
distillation columns) at the facility.
NPU2 = Cumulative number of hydrotreating/hydrorefining 
units, catalytic reforming units, and visbreaking units at the 
facility.
NH2 = Total number of hydrogen plants at the facility.
NFGS = Total number of fuel gas systems at the facility.

    (m) For storage tanks, except as provided in paragraph (m)(3) of 
this section, calculate CH4 emissions using the applicable 
methods in paragraphs (m)(1) and (m)(2) of this section.
    (1) For storage tanks other than those processing unstabilized 
crude oil, you must either calculate CH4 emissions from 
storage tanks that have a vapor-phase methane concentration of 0.5 
volume percent or more using tank-specific methane composition data 
(from measurement data or product knowledge) and the AP-42 emission

[[Page 56458]]

estimation methods provided in Section 7.1 of the AP-42: ``Compilation 
of Air Pollutant Emission Factors, Volume 1: Stationary Point and Area 
Sources'', including TANKS Model (Version 4.09D) or similar programs, 
or estimate CH4 emissions from storage tanks using Equation 
Y-22 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.108

Where:

CH4 = Annual methane emissions from storage tanks (metric 
tons/year).
0.1 = Default emission factor for storage tanks (metric ton 
CH4/MMbbl).
QRef = Quantity of crude oil plus the quantity of 
intermediate products received from off site that are processed at 
the facility (MMbbl/year).

    (2) For storage tanks that process unstabilized crude oil, 
calculate CH4 emissions from the storage of unstabilized 
crude oil using either tank-specific methane composition data (from 
measurement data or product knowledge) and direct measurement of the 
gas generation rate or by using Equation Y-23 of this section.

[GRAPHIC] [TIFF OMITTED] TR30OC09.109

Where:

CH4 = Annual methane emissions from storage tanks (metric 
tons/year).
Qun = Quantity of unstabilized crude oil received at the 
facility (MMbbl/year).
[Delta]P = Pressure differential from the previous storage pressure 
to atmospheric pressure (pounds per square inch, psi).
MFCH4 = Mole fraction of CH4 in vent gas from 
the unstabilized crude oil storage tank from facility measurements 
(kg-mole CH4/kg-mole gas); use 0.27 as a default if 
measurement data are not available.
995,000 = Correlation Equation factor (scf gas per MMbbl per psi).
16 = Molecular weight of CH4 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).

    (3) You do not need to calculate CH4 emissions from 
storage tanks that meet any of the following descriptions:
    (i) Units permanently attached to conveyances such as trucks, 
trailers, rail cars, barges, or ships;
    (ii) Pressure vessels designed to operate in excess of 204.9 
kilopascals and without emissions to the atmosphere;
    (iii) Bottoms receivers or sumps;
    (iv) Vessels storing wastewater; or
    (v) Reactor vessels associated with a manufacturing process unit.
    (n) For crude oil, intermediate, or product loading operations for 
which the equilibrium vapor-phase concentration of methane is 0.5 
volume percent or more, calculate CH4 emissions from loading 
operations using product-specific, vapor-phase methane composition data 
(from measurement data or process knowledge) and the emission 
estimation procedures provided in Section 5.2 of the AP-42: 
``Compilation of Air Pollutant Emission Factors, Volume 1: Stationary 
Point and Area Sources.'' For loading operations in which the 
equilibrium vapor-phase concentration of methane is less than 0.5 
volume percent, you may assume zero methane emissions.


Sec.  98.254  Monitoring and QA/QC requirements.

    (a) Fuel flow meters, gas composition monitors, and heating value 
monitors associated with stationary combustion sources must follow the 
monitoring and QA/QC requirements in Sec.  98.34.
    (b) All 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 stationary 
combustion sources shall be calibrated according to the procedures in 
the applicable methods specified in paragraphs (c) through (e) of this 
section, the procedures specified by the manufacturer, or Sec. Sec.  
98.3(i). Recalibrate each flow meter either biennially (every two 
years) or at the minimum frequency specified by the manufacturer. 
Recalibrate each gas composition monitor and heating value monitor 
either annually or at the minimum frequency specified by the 
manufacturer.
    (c) For flare or sour gas flow meters, operate and maintain the 
flow meter using any of the following methods, a method published by a 
consensus-based standards organization (e.g., ASTM, API, etc.) or 
follow the procedures specified by the flow meter manufacturer. Flow 
meters must have a rated accuracy of  5 percent or lower.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7).
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area 
Meters (incorporated by reference, see Sec.  98.7).
    (8) AGA Report No. 11 Measurement of Natural Gas by Coriolis Meter 
(2003) (incorporated by reference, see Sec.  98.7).
    (d) Determine flare gas composition using any of the following 
methods.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous 
Mixtures by Gas Chromatography (incorporated by reference, see Sec.  
98.7).
    (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (e) Determine flare gas higher heating value using any of the 
following methods.
    (1) ASTM D4809-06 Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) 
(incorporated by reference, see Sec.  98.7).
    (2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of 
Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter 
(incorporated by reference, see Sec.  98.7).
    (3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter (incorporated by reference, see Sec.  98.7).

[[Page 56459]]

    (4) ASTM D3588-98 (Reapproved 2003) Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels (incorporated by reference, see Sec.  98.7).
    (5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion (incorporated by reference, see Sec.  98.7).
    (f) For exhaust gas flow meters used to comply with the 
requirements in Sec.  98.253(c)(2)(ii), install, operate, calibrate, 
and maintain exhaust gas flow meter according to the requirements in 40 
CFR 63.1572(c) or according to the following requirements.
    (1) Locate the flow meter(s) and other necessary equipment such as 
straightening vanes in a position that provides representative flow; 
reduce swirling flow or abnormal velocity distributions due to upstream 
and downstream disturbances.
    (2) Use a flow rate meter with an accuracy within  5 
percent.
    (3) Use a continuous 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 Sec.  98.6).
    (4) Install, operate, and maintain each continuous monitoring 
system according to the manufacturer's specifications and requirements.
    (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(a) or according to the manufacturer's specifications and 
requirements.
    (h) Determine the mass of petroleum coke as required by Equation Y-
13 of this subpart using mass measurement equipment meeting the 
requirements for commercial weighing equipment as described in 
Specifications, Tolerances, and Other Technical Requirements For 
Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated 
by reference, see Sec.  98.7). Calibrate the measurement device 
according to the procedures specified by the method, the procedures 
specified by the manufacturer, or Sec.  98.3(i). Recalibrate either 
biennially or at the minimum frequency specified by the manufacturer.
    (i) Determine the carbon content of petroleum coke as required by 
Equation Y-13 of this subpart using any one of the following methods. 
Calibrate the measurement device according to procedures specified by 
the method or procedures specified by the measurement device 
manufacturer.
    (1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec.  98.7).
    (2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants (incorporated by reference, see Sec.  
98.7).
    (3) ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7).
    (j) Determine the quantity of petroleum process streams using 
company records. These quantities include the quantity of asphalt 
blown, quantity of crude oil plus the quantity of intermediate products 
received from off site, and the quantity of unstabilized crude oil 
received at the facility.
    (k) The owner or operator shall document the procedures used to 
ensure the accuracy of the estimates of fuel usage, gas composition, 
and heating value including but not limited to calibration of weighing 
equipment, fuel flow meters, and other measurement devices. The 
estimated accuracy of measurements made with these devices shall also 
be recorded, and the technical basis for these estimates shall be 
provided.
    (l) All CO2 CEMS and flow rate monitors used for direct 
measurement of GHG emissions must comply with the QA procedures in 
Sec.  98.34(c).


Sec.  98.255  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required (e.g., concentrations, flow rates, 
fuel heating values, carbon content values). Therefore, whenever a 
quality-assured value of a required parameter is unavailable (e.g., if 
a CEMS malfunctions during unit operation or if a required fuel sample 
is not taken), a substitute data value for the missing parameter shall 
be used in the calculations.
    (a) For stationary combustion sources, use the missing data 
procedures in subpart C of this part.
    (b) For each missing value of the heat content, carbon content, or 
molecular weight of the fuel, substitute the arithmetic average of the 
quality-assured values of that parameter immediately preceding and 
immediately following the missing data incident. If the ``after'' value 
is not obtained by the end of the reporting year, you may use the 
``before'' value for the missing data substitution. If, for a 
particular parameter, no quality-assured data are available prior to 
the missing data incident, the substitute data value shall be the first 
quality-assured value obtained after the missing data period.
    (c) For missing CO2, CO, O2, CH4, 
or N2O concentrations, gas flow rate, and percent moisture, 
the substitute data values shall be the best available estimate(s) of 
the parameter(s), based on all available process data (e.g., processing 
rates, operating hours, etc.). The owner or operator shall document and 
keep records of the procedures used for all such estimates.
    (d) For hydrogen plants, use the missing data procedures in subpart 
P of this part.


Sec.  98.256   Data reporting requirements.

    In addition to the reporting requirements of Sec.  98.3(c), you 
must report the information specified in paragraphs (a) through (q) of 
this section.
    (a) For combustion sources, follow the data reporting requirements 
under subpart C of this part (General Stationary Fuel Combustion 
Sources).
    (b) For hydrogen plants, follow the data reporting requirements 
under subpart P of this part (Hydrogen Production).
    (c) [Reserved]
    (d) [Reserved]
    (e) For flares, owners and operators shall report:
    (1) The flare ID number (if applicable).
    (2) A description of the type of flare (steam assisted, air-
assisted).
    (3) A description of the flare service (general facility flare, 
unit flare, emergency only or back-up flare).
    (4) The calculated CO2, CH4, and 
N2O annual emissions for each flare, expressed in metric 
tons of each pollutant emitted.
    (5) A description of the method used to calculate the 
CO2 emissions for each flare (e.g., reference section and 
equation number).
    (6) If you use Equation Y-1 of this subpart, the annual volume of 
flare gas combusted (in scf/year) and the annual average molecular 
weight (in kg/kg-mole) and carbon content of the flare gas (in kg 
carbon per kg flare gas).
    (7) If you use Equation Y-2 of this subpart, the annual volume of 
flare gas combusted (in million (MM) scf/year) and the annual average 
higher heating value of the flare gas (in MMBtu per MMscf).
    (8) If you use Equation Y-3 of this subpart, the annual volume of 
flare gas combusted (in MMscf/year) during

[[Page 56460]]

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, and the volume of gas flared (in scf/event) and the average 
molecular weight (in kg/kg-mole) and carbon content of the flare gas 
(in kg carbon per kg flare) for each SSM event over 500,000 scf/day.
    (9) The fraction of carbon in the flare gas contributed by methane 
used in Equation Y-4 of this subpart and the basis for its value.
    (f) For catalytic cracking units, traditional fluid coking units, 
and catalytic reforming units, owners and operators shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit (fluid catalytic cracking 
unit, thermal catalytic cracking unit, traditional fluid coking unit, 
or catalytic reforming unit).
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) The calculated CO2, CH4, and 
N2O annual emissions for each unit, expressed in metric tons 
of each pollutant emitted.
    (5) A description of the method used to calculate the 
CO2 emissions for each unit (e.g., reference section and 
equation number).
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36(e)(2)(vi) for the Tier 4 Calculation Methodology, the 
CO2 annual emissions as measured by the CEMS (unadjusted to 
remove CO2 combustion emissions associated with a CO boiler, 
if present) and the process CO2 emissions as calculated 
according to Sec.  98.253(c)(1)(ii). Report the CO2 annual 
emissions associated with fuel combustion under subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (7) If you use Equation Y-6 of this subpart, the annual average 
exhaust gas flow rate, %CO2, and %CO.
    (8) If you use Equation Y-7 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-8 of this subpart, the coke burn-off 
factor, annual throughput of unit, and the average carbon content of 
coke and the basis for the value.
    (10) 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 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.
    (11) 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 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) If you use Equation Y-11 of this subpart, the number of 
regeneration cycles during the reporting year, the average coke burn-
off quantity per cycle, and the average carbon content of the coke.
    (g) For fluid coking unit of the flexicoking type, the owner or 
operator shall report:
    (1) The unit ID number (if applicable).
    (2) A description of the type of unit.
    (3) Maximum rated throughput of the unit, in bbl/stream day.
    (4) Indicate whether the GHG emissions from the low heat value gas 
are accounted for in subpart C of this part or Sec.  98.253(c).
    (5) If the GHG emissions for the low heat value gas are calculated 
at the flexicoking unit, also report the calculated annual 
CO2, CH4, and N2O emissions for each 
unit, expressed in metric tons of each pollutant emitted, and the 
applicable equation input parameters specified in paragraphs (f)(7) 
through (f)(11) of this section.
    (h) For sulfur recovery plants and for emissions from sour gas sent 
off-site for sulfur recovery, the owner and operator shall report:
    (1) The plant ID number (if applicable).
    (2) Maximum rated throughput of each independent sulfur recovery 
plant, in metric tons sulfur produced/stream day.
    (3) The calculated CO2 annual emissions for each sulfur 
recovery plant, expressed in metric tons. The calculated annual 
CO2 emissions from sour gas sent off-site for sulfur 
recovery, expressed in metric tons.
    (4) If you use Equation Y-12 of this subpart, the annual volumetric 
flow to the sulfur recovery plant (in scf/year) and the annual average 
mole fraction of carbon in the sour gas (in kg-mole C/kg-mole gas).
    (5) If you recycle tail gas to the front of the sulfur recovery 
plant, indicate whether the recycled flow rate and carbon content are 
included in the measured data under Sec.  98.253(f)(2) and (3). 
Indicate whether a correction for CO2 emissions in the tail 
gas was used in Equation Y-12. If so, then report the value of the 
correction, the annual volume of recycled tail gas (in scf/year) and 
the annual average mole fraction of carbon in the tail gas (in kg-mole 
C/kg-mole gas). Indicate whether you used the default (95%) or a unit 
specific correction, and if used, report the approach used.
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36(e)(2)(vi) 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). Report the CO2 annual emissions associated 
with fuel combustion subpart C of this part (General Stationary Fuel 
Combustion Sources).
    (i) For coke calcining units, the owner and operator shall report:
    (1) The unit ID number (if applicable).
    (2) Maximum rated throughput of the unit, in metric tons coke 
calcined/stream day.
    (3) The calculated CO2, CH4, and 
N2O annual emissions for each unit, expressed in metric tons 
of each pollutant emitted.
    (4) A description of the method used to calculate the 
CO2 emissions for each unit (e.g., reference section and 
equation number).
    (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, and the annual mass of coke 
dust collected in dust collection systems.
    (6) If you use a CEMS, the relevant information required under 
Sec.  98.36(e)(2)(vi) 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). Report the CO2 annual emissions associated 
with fuel combustion under subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (7) Indicate whether you use a measured value, a unit-specific 
emission factor or a default for CH4 emissions. If you use a 
unit-specific emission factor for CH4, 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.
    (8) If you use a site-specific emission factor in Equation Y-10 of 
this subpart, the site-specific emission factor and the basis of the 
factor.
    (j) For asphalt blowing operations, the owner or operator shall 
report:

[[Page 56461]]

    (1) The unit ID number (if applicable).
    (2) The quantity of asphalt blown (in Million bbl) at the facility 
in the reporting year.
    (3) The type of control device used to reduce methane (and other 
organic) emissions from the unit.
    (4) The calculated annual CO2 and CH4 
emissions for each unit, expressed in metric tons of each pollutant 
emitted.
    (5) If you use Equation Y-14 of this subpart, the CO2 
emission factor used and the basis for the value.
    (6) If you use Equation Y-15 of this subpart, the CH4 
emission factor used and the basis for the value.
    (7) If you use Equation Y-16 of this subpart, the carbon emission 
factor used and the basis for the value.
    (8) If you use Equation Y-17 of this subpart, the CH4 
emission factor used and the basis for the value.
    (k) For delayed coking units, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of each pollutant emitted) for all delayed coking units at the 
facility.
    (2) A description of the method used to calculate the 
CH4 emissions for each unit (e.g., reference section and 
equation number).
    (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), and annual number of coke-cutting cycles.
    (4) For each set of coking drums that are the same dimensions: The 
number of coking drums in the set, the height and diameter of the coke 
drums (in feet), the cumulative number of vessel openings for all 
delayed coking drums in the set, the typical venting pressure (in 
psig), void fraction (in cf gas/cf of vessel), and the mole fraction of 
methane in coking gas (in kg-mole CF4/kg-mole gas, wet 
basis).
    (5) The basis for the volumetric void fraction of the coke vessel 
prior to steaming and the basis for the mole fraction of methane in the 
coking gas.
    (l) For process vents subject to Sec.  98.253(j), the owner or 
operator shall report:
    (1) The vent ID number (if applicable).
    (2) The unit or operation associated with the emissions.
    (3) The type of control device used to reduce methane (and other 
organic) emissions from the unit, if applicable.
    (4) The calculated annual CO2, CH4, and 
N2O emissions for each vent, expressed in metric tons of 
each pollutant emitted.
    (5) The annual volumetric flow discharged to the atmosphere (in 
scf), mole fraction of each GHG above the concentration threshold, and 
for intermittent vents, the number of venting events and the cumulative 
venting time.
    (m) For uncontrolled blowdown systems, the owner or operator shall 
report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of each pollutant emitted) for uncontrolled blowdown systems.
    (2) 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.
    (3) The methane emission factor used for uncontrolled blowdown 
systems and the basis for the value.
    (n) For equipment leaks, the owner or operator shall report:
    (1) The cumulative CH4 emissions (in metric tons of each 
pollutant emitted) for all equipment leak sources.
    (2) The method used to calculate the reported equipment leak 
emissions.
    (3) The number of each type of emission source listed in Equation 
Y-21 of this subpart at the facility.
    (o) For storage tanks, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of each pollutant emitted) for all storage tanks, except for those used 
to process unstabilized crude oil.
    (2) The method used to calculate the reported storage tank 
emissions for storage tanks other than those processing unstabilized 
crude (AP-42, TANKS 4.09D, Equation Y-22 of this subpart, other).
    (3) 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.
    (4) The cumulative CH4 emissions (in metric tons of each 
pollutant emitted) for storage tanks used to process unstabilized crude 
oil.
    (5) The method used to calculate the reported storage tank 
emissions for storage tanks processing unstabilized crude oil.
    (6) The quantity of unstabilized crude oil received during the 
calendar year (in MMbbl), the average pressure differential (in psi), 
and the mole fraction of CH4 in vent gas from the 
unstabilized crude oil storage tank, and the basis for the mole 
fraction.
    (7) The tank-specific methane composition data and the gas 
generation rate data, if you did not use Equation Y-23.
    (p) For loading operations, the owner or operator shall report:
    (1) The cumulative annual CH4 emissions (in metric tons 
of each pollutant emitted) for loading operations.
    (2) The quantity and types of materials loaded by vessel type 
(barge, tanker, marine vessel, etc.) that have an equilibrium vapor-
phase concentration of methane of 0.5 volume percent or greater, and 
the type of vessels in which the material is loaded.
    (3) The type of control system used to reduce emissions from the 
loading of material with an equilibrium vapor-phase concentration of 
methane of 0.5 volume percent or greater, if any (submerged loading, 
vapor balancing, etc.).
    (q) Name of each method listed in Sec.  98.254 or a description of 
manufacturer's recommended method used to determine a measured 
parameter.


Sec.  98.257  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records of all parameters monitored under Sec.  98.255.


Sec.  98.258  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart Z--Phosphoric Acid Production


Sec.  98.260  Definition of the source category.

    The phosphoric acid production source category consists of 
facilities with a wet-process phosphoric acid process line used to 
produce phosphoric acid. A wet-process phosphoric acid process line is 
the production unit or units identified by an individual identification 
number in an operating permit and/or any process unit or group of 
process units at a facility reacting phosphate rock from a common 
supply source with acid.


Sec.  98.261  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a phosphoric acid production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.262  GHGs to report.

    (a) You must report CO2 process emissions from each wet-
process phosphoric acid process line.
    (b) You must report under subpart C of this part (General 
Stationary Fuel

[[Page 56462]]

Combustion Sources) the emissions of CO2, CH4, 
and N2O from each stationary combustion unit following the 
requirements of subpart C of this part.


Sec.  98.263  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each wet-process phosphoric acid process line using the 
procedures in either paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining a CEMS according 
to the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) 
and all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions using the procedures in paragraphs (b)(1) and 
(b)(2) of this section.
    (1) Calculate and report the process CO2 emissions from 
each wet-process phosphoric acid process line using Equation Z-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.110

Where:
Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m (metric tons).
ICn,i = Inorganic carbon content of a grab sample batch 
of phosphate rock by origin i obtained during month n, from the 
carbon analysis results (percent by weight, expressed as a decimal 
fraction).
Pn,i = Mass of phosphate rock by origin i consumed in 
month n by wet-process phosphoric acid process line m (tons).
z = Number of months during which the process line m operates.
b = Number of different types of phosphate rock in month, by origin. 
If the grab sample is a composite sample of rock from more than one 
origin, b=1.
2000/2205 = Conversion factor to convert tons to metric tons.
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) You must determine the total emissions from the facility using 
Equation Z-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.111

Where:
CO2 = Annual process CO2 emissions from 
phosphoric acid production facility (metric tons/year).
Em = Annual process CO2 emissions from wet-
process phosphoric acid process line m (metric tons/year).
p = Number of wet-process phosphoric acid process lines.

    (c) If GHG emissions from a wet-process phosphoric acid process 
line are vented through the same stack as any combustion unit or 
process equipment that reports CO2 emissions using a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C of 
this part (General Stationary Fuel Combustion Sources), then the 
calculation methodology in paragraph (b) of this section shall not be 
used to calculate process emissions. The owner or operator shall report 
under this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.


Sec.  98.264  Monitoring and QA/QC requirements.

    (a) You must obtain a monthly grab sample of phosphate rock 
directly from the rock being fed to the process line. Conduct the 
representative bulk sampling using the applicable standard method in 
the Phosphate Mining States Methods Used and Adopted by the Association 
of Fertilizer and Phosphate Chemists AFPC Manual 10th Edition 2009--
Version 1.9 (incorporated by reference, see Sec.  98.7). If phosphate 
rock is obtained from more than one origin in a month, you must obtain 
a sample from each origin of rock or obtain a composite representative 
sample.
    (b) You must determine the inorganic carbon content of each monthly 
grab sample of phosphate rock (consumed in the production of phosphoric 
acid) using the applicable standard method in the Phosphate Mining 
States Methods Used and Adopted by the Association of Fertilizer and 
Phosphate Chemists AFPC Manual 10th Edition 2009--Version 1.9 
(incorporated by reference, see Sec.  98.7).
    (c) You must determine the mass of phosphate rock consumed each 
month (by origin) in each wet-process phosphoric acid process line. You 
can use existing plant procedures that are used for accounting purposes 
(such as sales records) or you can use data from existing monitoring 
equipment that is used to measure total mass flow of phosphorous-
bearing feed under 40 CFR part 60 or part 63.


Sec.  98.265  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations in Sec.  98.263(b) is required. Therefore, 
whenever a quality-assured value of a required parameter is 
unavailable, a substitute data value for the missing parameter shall be 
used in the calculations as specified in paragraphs (a) and (b) of this 
section. You must document and keep records of the procedures used for 
all such estimates.
    (a) For each missing value of the inorganic carbon content of 
phosphate rock (by origin), you must use the appropriate default factor 
provided in Table Z-1 of this subpart. Alternatively, the you must 
determine substitute data value by calculating the arithmetic average 
of the quality-assured values of inorganic carbon contents of phosphate 
rock of origin i (see Equation Z-1 of this subpart) from samples 
immediately preceding and immediately following the missing data 
incident. If no quality-assured data on inorganic carbon contents of 
phosphate rock of origin i are available prior to the missing data 
incident, the substitute data value shall be the first quality-assured 
value for inorganic carbon contents for phosphate rock of origin i 
obtained after the missing data period.
    (b) For each missing value of monthly mass consumption of phosphate 
rock (by origin), you must use the best available estimate based on all 
available process data or data used for accounting purposes.


Sec.  98.266  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
through (b) of this section.
    (a) Annual phosphoric acid production by origin (as listed in Table 
Z-1 to this subpart) of the phosphate rock (tons).
    (b) Annual phosphoric acid permitted production capacity (tons).
    (c) Annual arithmetic average percent inorganic carbon in phosphate 
rock from monthly records.
    (d) Annual phosphate rock consumption from monthly measurement 
records by origin, (as

[[Page 56463]]

listed in Table Z-1 to this subpart) (tons).
    (e) If you use a CEMS to measure CO2 emissions, then you 
must report the information in paragraphs (e)(1) and (e)(2) of this 
section.
    (1) The identification number of each wet-process phosphoric acid 
process line.
    (2) The annual CO2 emissions from each wet-process 
phosphoric acid process line (metric tons) and the relevant information 
required under 40 CFR 98.36 (e)(2)(vi) for the Tier 4 Calculation 
Methodology.
    (f) If you do not use a CEMS to measure emissions, then you must 
report the information in paragraphs (f)(1) through (f)(8) of this 
section.
    (1) Identification number of each wet-process phosphoric acid 
process line.
    (2) Annual CO2 emissions from each wet-process 
phosphoric acid process line (metric tons) as calculated by Equation Z-
1 of this subpart.
    (3) Annual phosphoric acid permitted production capacity (tons) for 
each wet-process phosphoric acid process line (metric tons).
    (4) Method used to estimate any missing values of inorganic carbon 
content of phosphate rock for each wet-process phosphoric acid process 
line.
    (5) Monthly inorganic carbon content of phosphate rock for each 
wet-process phosphoric acid process line (percent by weight, expressed 
as a decimal fraction).
    (6) Monthly mass of phosphate rock consumed by origin, (as listed 
in Table Z-1 of this subpart) in production for each wet-process 
phosphoric acid process line (tons).
    (7) Number of wet-process phosphoric acid process lines.
    (8) Number of times missing data procedures were used to estimate 
phosphate rock consumption (months) and inorganic carbon contents of 
the phosphate rock (months).


Sec.  98.267  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (c) of this 
section for each wet-process phosphoric acid production facility.
    (a) Monthly mass of phosphate rock consumed by origin (as listed in 
Table Z-1 of this subpart) (tons).
    (b) Records of all phosphate rock purchases and/or deliveries (if 
vertically integrated with a mine).
    (c) Documentation of the procedures used to ensure the accuracy of 
monthly phosphate rock consumption by origin, (as listed in Table Z-1 
of this subpart).


Sec.  98.268  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

   Table Z-1 to Subpart Z of Part 98--Default Chemical Composition of
                        Phosphate Rock by Origin
------------------------------------------------------------------------
                                                                Total
                                                                carbon
                           Origin                            (percent by
                                                               weight)
------------------------------------------------------------------------
Central Florida............................................          1.6
North Florida..............................................         1.76
North Carolina (Calcined)..................................         0.76
Idaho (Calcined)...........................................         0.60
Morocco....................................................         1.56
------------------------------------------------------------------------

Subpart AA--Pulp and Paper Manufacturing


Sec.  98.270  Definition of source category.

    (a) The pulp and paper manufacturing source category consists of 
facilities that produce market pulp (i.e., stand-alone pulp 
facilities), manufacture pulp and paper (i.e., integrated facilities), 
produce paper products from purchased pulp, produce secondary fiber 
from recycled paper, convert paper into paperboard products (e.g., 
containers), or operate coating and laminating processes.
    (b) The emission units for which GHG emissions must be reported are 
listed in paragraphs (b)(1) through (b)(5) of this section:
    (1) Chemical recovery furnaces at kraft and soda mills (including 
recovery furnaces that burn spent pulping liquor produced by both the 
kraft and semichemical process).
    (2) Chemical recovery combustion units at sulfite facilities.
    (3) Chemical recovery combustion units at stand-alone semichemical 
facilities.
    (4) Pulp mill lime kilns at kraft and soda facilities.
    (5) Systems for adding makeup chemicals (CaCO3, 
Na2CO3) in the chemical recovery areas of 
chemical pulp mills.


Sec.  98.271  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a pulp and paper manufacturing process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.272  GHGs to report.

    You must report the emissions listed in paragraphs (a) through (f) 
of this section:
    (a) CO2, biogenic CO2, CH4, and 
N2O emissions from each kraft or soda chemical recovery 
furnace.
    (b) CO2, biogenic CO2, CH4, and 
N2O emissions from each sulfite chemical recovery combustion 
unit.
    (c) CO2, biogenic CO2, CH4, and 
N2O emissions from each stand-alone semichemical chemical 
recovery combustion unit.
    (d) CO2, biogenic CO2, CH4, and 
N2O emissions from each kraft or soda pulp mill lime kiln.
    (e) CO2 emissions from addition of makeup chemicals 
(CaCO3, Na2CO3) in the chemical 
recovery areas of chemical pulp mills.
    (f) CO2, CH4, and N2O 
combustion emissions from each stationary combustion unit. You must 
calculate and report these emissions under subpart C of this part 
(General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.


Sec.  98.273  Calculating GHG emissions.

    (a) For each chemical recovery furnace located at a kraft or soda 
facility, you must determine CO2, biogenic CO2, 
CH4, and N2O emissions using the procedures in 
paragraphs (a)(1) through (a)(3) of this section. CH4 and 
N2O emissions must be calculated as the sum of emissions 
from combustion of fossil fuels and combustion of biomass in spent 
liquor solids.
    (1) Calculate fossil fuel-based CO2 emissions from 
direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 methodology for stationary combustion 
sources in Sec.  98.33(a)(1).
    (2) Calculate fossil fuel-based CH4 and N2O 
emissions from direct measurement of fossil fuels consumed, default 
HHV, and default emissions factors and convert to metric tons of 
CO2 equivalent according to the methodology for stationary 
combustion sources in Sec.  98.33(c).
    (3) Calculate biogenic CO2 emissions and emissions of 
CH4 and N2O from biomass using measured 
quantities of spent liquor solids fired, site-specific HHV, and default 
or site-specific emissions factors, according to Equation AA-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.112


[[Page 56464]]


Where:

CO2, CH4, or N2O, from Biomass = 
Biogenic CO2 emissions or emissions of CH4 or 
N2O from spent liquor solids combustion (metric tons per 
year).
Solids = Mass of spent liquor solids combusted (short tons per year) 
determined according to Sec.  98.274(b).
HHV = Annual high heat value of the spent liquor solids (mmBtu per 
kilogram) determined according to Sec.  98.274(b).
EF = Default emission factor for CO2, CH4, or 
N2O, from Table AA-1 of this subpart (kg CO2, 
CH4, or N2O per mmBtu).
0.90718 = Conversion factor from short tons to metric tons.

    (b) For each chemical recovery combustion unit located at a sulfite 
or stand-alone semichemical facility, you must determine 
CO2, CH4, and N2O emissions using the 
procedures in paragraphs (b)(1) through (b)(4) of this section:
    (1) Calculate fossil CO2 emissions from fossil fuels 
from direct measurement of fossil fuels consumed and default emissions 
factors according to the Tier 1 Calculation Methodology for stationary 
combustion sources in Sec.  98.33(a)(1).
    (2) Calculate CH4 and N2O emissions from 
fossil fuels from direct measurement of fossil fuels consumed, default 
HHV, and default emissions factors and convert to metric tons of 
CO2 equivalent according to the methodology for stationary 
combustion sources in Sec.  98.33(c).
    (3) Calculate biogenic CO2 emissions using measured 
quantities of spent liquor solids fired and the carbon content of the 
spent liquor solids, according to Equation AA-2 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.113

Where:

Biogenic CO2 = Annual CO2 mass emissions for 
spent liquor solids combustion (metric tons per year).
Solids = Mass of the spent liquor solids combusted (short tons per 
year) determined according to Sec.  98.274(b).
CC = Annual carbon content of the spent liquor solids, determined 
according to Sec.  98.274(b) (percent by weight, expressed as a 
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.90718 = Conversion from short tons to metric tons.

    (4) Calculate CH4 and N2O emissions from 
biomass using Equation AA-1 of this section and the default 
CH4 and N2O emissions factors for kraft 
facilities in Table AA-1 of this subpart and convert the CH4 
or N2O emissions to metric tons of CO2 equivalent 
by multiplying each annual CH4 and N2O emissions 
total by the appropriate global warming potential (GWP) factor from 
Table A-1 of subpart A of this part.
    (c) For each pulp mill lime kiln located at a kraft or soda 
facility, you must determine CO2, CH4, and 
N2O emissions using the procedures in paragraphs (c)(1) 
through (c)(3) of this section:
    (1) Calculate CO2 emissions from fossil fuel from direct 
measurement of fossil fuels consumed and default HHV and default 
emissions factors, according to the Tier 1 Calculation Methodology for 
stationary combustion sources in Sec.  98.33(a)(1); use the default HHV 
listed in Table C-1 of subpart C and the default CO2 
emissions factors listed in Table AA-2 of this subpart.
    (2) Calculate CH4 and N2O emissions from 
fossil fuel from direct measurement of fossil fuels consumed, default 
HHV, and default emissions factors and convert to metric tons of 
CO2 equivalent according to the methodology for stationary 
combustion sources in Sec.  98.33(c); 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.
    (3) Biogenic CO2 emissions from conversion of 
CaCO3 to CaO are included in the biogenic CO2 
estimates calculated for the chemical recovery furnace in paragraph 
(a)(3) of this section.
    (d) For makeup chemical use, you must calculate CO2 
emissions by using direct or indirect measurement of the quantity of 
chemicals added and ratios of the molecular weights of CO2 
and the makeup chemicals, according to Equation AA-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.114

Where:

CO2 = CO2 mass emissions from makeup chemicals 
(kilograms/yr).
M (CaCO3) = Make-up quantity of CaCO3 used for 
the reporting year (metric tons per year).
M (NaCO3) = Make-up quantity of 
Na2CO3 used for the reporting year (metric 
tons per year).
44 = Molecular weight of CO2.
100 = Molecular weight of CaCO3.
105.99 = Molecular weight of Na2CO3.

Sec.  98.274  Monitoring and QA/QC requirements.

    (a) Each facility subject to this subpart must quality assure the 
GHG emissions data according to the applicable requirements in Sec.  
98.34. All QA/QC data must be available for inspection upon request.
    (b) Fuel properties needed to perform the calculations in Equations 
AA-1 and AA-2 of this subpart must be determined according to 
paragraphs (b)(1) through (b)(3) of this section.
    (1) High heat values of black liquor must be determined no less 
than annually using T684 om-06 Gross Heating Value of Black Liquor, 
TAPPI (incorporated by reference, see Sec.  98.7). If measurements are 
performed more frequently than annually, then the high heat value used 
in Equation AA-1 of this subpart must be based on the average of the 
representative measurements made during the year.
    (2) The annual mass of spent liquor solids must be determined using 
either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of 
this section.
    (i) Measure the mass of spent liquor solids annually (or more 
frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI 
(incorporated by reference in Sec.  98.7). If measurements are 
performed more frequently than annually, then the mass of spent liquor 
solids used in Equation AA-1 of this subpart must be based on the 
average of the representative measurements made during the year.
    (ii) Determine the annual mass of spent liquor solids based on 
records of measurements made with an online measurement system that 
determines

[[Page 56465]]

the mass of spent liquor solids fired in a chemical recovery furnace or 
chemical recovery combustion unit.
    (3) Carbon analyses for spent pulping liquor must be determined no 
less than annually using ASTM D5373-08 Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal (incorporated by reference, see Sec.  98.7). 
If measurements using ASTM D5373-08 are performed more frequently than 
annually, then the spent pulping liquor carbon content used in Equation 
AA-2 of this subpart must be based on the average of the representative 
measurements made during the year.
    (c) Each facility must keep records that include a detailed 
explanation of how company records of measurements are used to estimate 
GHG emissions. The owner or operator must also document the procedures 
used to ensure the accuracy of the measurements of fuel, spent liquor 
solids, and makeup chemical usage, including, but not limited to 
calibration of weighing equipment, fuel flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices must be recorded and the technical basis for these 
estimates must be provided. The procedures used to convert spent 
pulping liquor flow rates to units of mass (i.e., spent liquor solids 
firing rates) also must be documented.
    (d) Records must be made available upon request for verification of 
the calculations and measurements.


Sec.  98.275  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements of paragraphs (a) 
through (c) of this section:
    (a) There are no missing data procedures for measurements of heat 
content and carbon content of spent pulping liquor. A re-test must be 
performed if the data from any annual measurements are determined to be 
invalid.
    (b) For missing measurements of the mass of spent liquor solids or 
spent pulping liquor flow rates, use the lesser value of either the 
maximum mass or fuel flow rate for the combustion unit, or the maximum 
mass or flow rate that the fuel meter can measure.
    (c) For the use of makeup chemicals (carbonates), the substitute 
data value shall be the best available estimate of makeup chemical 
consumption, based on available data (e.g., past accounting records, 
production rates). The owner or operator shall document and keep 
records of the procedures used for all such estimates.


Sec.  98.276  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information in paragraphs (a) through 
(k) of this section as applicable:
    (a) Annual emissions of CO2, biogenic CO2, 
CH4, biogenic CH4 N2O, and biogenic 
N2O (metric tons per year).
    (b) Annual quantities fossil fuels by type used in chemical 
recovery furnaces and chemical recovery combustion units in short tons 
for solid fuels, gallons for liquid fuels and scf for gaseous fuels.
    (c) Annual mass of the spent liquor solids combusted (short tons 
per year), and basis for determining the annual mass of the spent 
liquor solids combusted (whether based on T650 om-05 Solids Content of 
Black Liquor, TAPPI (incorporated by reference, see Sec.  98.7) or an 
online measurement system).
    (d) The high heat value (HHV) of the spent liquor solids used in 
Equation AA-1 of this subpart (mmBtu per kilogram).
    (e) The default emission factor for CO2, CH4, 
or N2O, used in Equation AA-1 of this subpart (kg 
CO2, CH4, or N2O per mmBtu).
    (f) The carbon content (CC) of the spent liquor solids, used in 
Equation AA-2 of this subpart (percent by weight, expressed as a 
decimal fraction, e.g., 95% = 0.95).
    (g) Annual quantities of fossil fuels by type used in pulp mill 
lime kilns in short tons for solid fuels, gallons for liquid fuels and 
scf for gaseous fuels.
    (h) Make-up quantity of CaCO3 used for the reporting 
year (metric tons per year) used in Equation AA-3 of this subpart.
    (i) Make-up quantity of Na2CO3 used for the 
reporting year (metric tons per year) used in Equation AA-3 of this 
subpart.
    (j) Annual steam purchases (pounds of steam per year).
    (k) Annual production of pulp and/or paper products produced 
(metric tons).


Sec.  98.277  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the records in paragraphs (a) through (f) of this section.
    (a) GHG emission estimates (including separate estimates of 
biogenic CO2) for each emissions source listed under Sec.  
98.270(b).
    (b) Annual analyses of spent pulping liquor HHV for each chemical 
recovery furnace at kraft and soda facilities.
    (c) Annual analyses of spent pulping liquor carbon content for each 
chemical recovery combustion unit at a sulfite or semichemical pulp 
facility.
    (d) Annual quantity of spent liquor solids combusted in each 
chemical recovery furnace and chemical recovery combustion unit, and 
the basis for detemining the annual quantity of the spent liquor solids 
combusted (whether based on T650 om-05 Solids Content of Black Liquor, 
TAPPI (incorporated by reference, see Sec.  98.7) or an online 
measurement system). If an online measurement system is used, you must 
retain records of the calculations used to determine the annual 
quantity of spent liquor solids combusted from the continuous 
measurements.
    (e) Annual steam purchases.
    (f) Annual quantities of makeup chemicals used.


Sec.  98.278  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

   Table AA-1 to Subpart AA of Part 98--Kraft Pulping Liquor Emissions
               Factors for Biomass-Based CO2, CH4, and N2O
------------------------------------------------------------------------
                                         Biomass-based emissions factors
                                                  (kg/mmBtu HHV)
              Wood furnish              --------------------------------
                                           CO2\a\      CH4        N2O
------------------------------------------------------------------------
North American Softwood................       94.4      0.030      0.005
North American Hardwood................       93.7
Bagasse................................       95.5
Bamboo.................................       93.7

[[Page 56466]]

 
Straw..................................       95.1
------------------------------------------------------------------------
\a\ Includes emissions from both the recovery furnace and pulp mill lime
  kiln.


 Table AA-2 to Subpart AA of Part 98--Kraft Lime Kiln and Calciner Emissions Factors for Fossil Fuel-Based CO2,
                                                  CH4, and N2O
----------------------------------------------------------------------------------------------------------------
                                                 Fossil fuel-based emissions factors (kg/mmBtu HHV)
                                   -----------------------------------------------------------------------------
               Fuel                            Kraft lime kilns                       Kraft calciners
                                   -----------------------------------------------------------------------------
                                        CO2          CH4          N2O          CO2          CH4          N2O
----------------------------------------------------------------------------------------------------------------
Residual Oil......................         76.7       0.0027            0         76.7       0.0027       0.0003
Distillate Oil....................         73.5                                   73.5                    0.0004
Natural Gas.......................         56.0                                   56.0                    0.0001
Biogas............................            0                                                           0.0001
----------------------------------------------------------------------------------------------------------------

Subpart BB--Silicon Carbide Production


Sec.  98.280  Definition of the source category.

    Silicon carbide production includes any process that produces 
silicon carbide for abrasive purposes.


Sec.  98.281  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a silicon carbide production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.282  GHGs to report.

    You must report:
    (a) CO2 and CH4 process emissions from all 
silicon carbide process units or furnaces combined.
    (b) CO2, CH4, and N2O emissions 
from each stationary 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.


Sec.  98.283  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each silicon carbide process unit or production furnace 
using the procedures in either paragraph (a) or (b) of this section. 
You must determine CH4 process emissions in accordance with 
the procedures specified in paragraph (d) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining CEMS according to 
the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) and 
all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions using the procedures in paragraphs (b)(1) and 
(b)(2) of this section.
    (1) Use Equation BB-1 of this section to calculate the facility-
specific emissions factor for determining CO2 emissions. The 
carbon content must be measured monthly and used to calculate a monthly 
CO2 emisssions factor:
[GRAPHIC] [TIFF OMITTED] TR30OC09.115


Where:

EFCO2,n = CO2 emissions factor in month n 
(metric tons CO2/metric ton of petroleum coke consumed).
0.65 = Adjustment factor for the amount of carbon in silicon carbide 
product (assuming 35 percent of carbon input is in the carbide 
product).
CCFn = Carbon content factor for petroleum coke consumed 
in month n from the supplier or as measured by the applicable method 
incorporated by reference in Sec.  98.7 according to Sec.  98.284(c) 
(percent by weight expressed as a decimal fraction).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) Use Equation BB-2 of this section to calculate annual 
CO2 process emissions from all silicone carbide production:
[GRAPHIC] [TIFF OMITTED] TR30OC09.116

Where:

CO2 = Annual CO2 emissions from silicon 
carbide production facility (metric tons CO2).
Tn = Petroleum coke consumption in month n (tons).

[[Page 56467]]

EFCO2,n = CO2 emissions factor from month n 
(calculated in Equation BB-1 of this section).
2000/2205 = Conversion factor to convert tons to metric tons.
n = Number of month.

    (c) If GHG emissions from a silicon carbide production furnace or 
process unit are vented through the same stack as any combustion unit 
or process equipment that reports CO2 emissions using a CEMS 
that complies with the Tier 4 Calculation Methodology in subpart C of 
this part (General Stationary Fuel Combustion Sources), then the 
calculation methodology in paragraph (b) of this section shall not be 
used to calculate process emissions. The owner or operator shall report 
under this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.
    (d) You must calculate annual process CH4 emissions from 
all silicon carbide production combined using Equation BB-3 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.117

Where:

CH4 = Annual CH4 emissions from silicon 
carbide production facility (metric tons CH4).
Tn = Petroleum coke consumption in month n (tons).
10.2 = CH4 emissions factor (kg CH4/metric ton 
coke).
2000/2205 = Conversion factor to convert tons to metric tons.
0.001 = Conversion factor from kilograms to metric tons.
n = Number of month.

Sec.  98.284  Monitoring and QA/QC requirements.

    (a) You must measure your consumption of petroleum coke using plant 
instruments used for accounting purposes including direct measurement 
weighing the petroleum coke fed into your process (by belt scales or a 
similar device) or through the use of purchase records.
    (b) You must document the procedures used to ensure the accuracy of 
monthly petroleum coke consumption measurements.
    (c) For CO2 process emissions, you must determine the 
monthly carbon content of the petroleum coke using reports from the 
supplier. Alternatively, facilities can measure monthly carbon contents 
of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard 
Practice for Ultimate Analysis of Coal and Coke (incorporated by 
reference, see Sec.  98.7) and ASTM D5373-08 Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal (incorporated by reference, see Sec.  98.7).
    (d) For quality assurance and quality control of the supplier data, 
you must conduct an annual measurement of the carbon content of the 
petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test 
Methods for Instrumental Determination of Carbon, Hydrogen, and 
Nitrogen in Laboratory Samples of Coal (incorporated by reference, see 
Sec.  98.7).


Sec.  98.285  Procedures for estimating missing data.

    For the petroleum coke input procedure in Sec.  98.283(b), a 
complete record of all measured parameters used in the GHG emissions 
calculations is required (e.g., carbon content values, etc.). 
Therefore, whenever a quality-assured value of a required parameter is 
unavailable, a substitute data value for the missing parameter shall be 
used in the calculations as specified in the paragraphs (a) and (b) of 
this section. You must document and keep records of the procedures used 
for all such estimates.
    (a) For each missing value of the monthly carbon content of 
petroleum coke, the substitute data value shall be the arithmetic 
average of the quality-assured values of carbon contents immediately 
preceding and immediately following the missing data incident. If no 
quality-assured data on carbon contents are available prior to the 
missing data incident, the substitute data value shall be the first 
quality-assured value for carbon contents obtained after the missing 
data period.
    (b) For each missing value of the monthly petroleum coke 
consumption, the substitute data value shall be the best available 
estimate of the petroleum coke consumption based on all available 
process data or information used for accounting purposes (such as 
purchase records).


Sec.  98.286  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable for each silicon carbide 
production facility.
    (a) If a CEMS is used to measure process CO2 emissions, 
you must report under this subpart the relevant information required 
for the Tier 4 Calculation Methodology in Sec.  98.36 and the 
information listed in this paragraph (a):
    (1) Annual consumption of petroleum coke (tons).
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (b) If a CEMS is not used to measure process CO2 
emissions, you must report the information listed in this paragraph (b) 
for all furnaces combined:
    (1) Monthly consumption of petroleum coke (tons).
    (2) Annual production of silicon carbide (tons).
    (3) Annual production capacity of silicon carbide (tons).
    (4) Carbon content factor of petroleum coke from the supplier or as 
measured by the applicable method in Sec.  98.284(c) for each month 
(percent by weight expressed as a decimal fraction).
    (5) Whether carbon content of the petroleum coke is based on 
reports from the supplier or through self measurement using applicable 
ASTM standard method.
    (6) CO2 emissions factor calculated for each month 
(metric tons CO2/metric ton of petroleum coke consumed).
    (7) Sampling analysis results for carbon content of consumed 
petroleum coke as determined for QA/QC of supplier data under Sec.  
98.284(d) (percent by weight expressed as a decimal fraction).
    (8) Number of times in the reporting year that missing data 
procedures were followed to measure the carbon contents of petroleum 
coke (number of months) and petroleum coke consumption (number of 
months).


Sec.  98.287  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section 
for each silicon carbide production facility.
    (a) If a CEMS is used to measure CO2 emissions, you must 
retain under this subpart the records required for the Tier 4 
Calculation Methodology in Sec.  98.37

[[Page 56468]]

and the information listed in this paragraph (a):
    (1) Records of all petroleum coke purchases.
    (2) Annual operating hours.
    (b) If a CEMS is not used to measure emissions, you must retain 
records for the information listed in this paragraph (b):
    (1) Records of all analyses and calculations conducted for reported 
data listed in Sec.  98.286(b).
    (2) Records of all petroleum coke purchases.
    (3) Annual operating hours.


Sec.  98.288  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart CC--Soda Ash Manufacturing


Sec.  98.290  Definition of the source category.

    (a) A soda ash manufacturing facility is any facility with a 
manufacturing line that produces soda ash by one of the methods in 
paragraphs (a)(1) through (3) of this section:
    (1) Calcining trona.
    (2) Calcining sodium sesquicarbonate.
    (3) Using a liquid alkaline feedstock process that directly 
produces CO2.
    (b) In the context of the soda ash manufacturing sector, 
``calcining'' means the thermal/chemical conversion of the bicarbonate 
fraction of the feedstock to sodium carbonate.


Sec.  98.291  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a soda ash manufacturing process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.292  GHGs to report.

    You must report:
    (a) CO2 process emissions from each soda ash 
manufacturing line combined.
    (b) CO2 combustion emissions from each soda ash 
manufacturing line.
    (c) CH4 and N2O combustion emissions from 
each soda ash manufacturing line. You must calculate and report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (d) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than soda ash manufacturing 
lines. You must calculate and report these emissions under subpart C of 
this part (General Stationary Fuel Combustion Sources) by following the 
requirements of subpart C.


Sec.  98.293  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions from each soda ash manufacturing line using the procedures 
specified in paragraph (a) or (b) of this section.
    (a) For each soda ash manufacturing line that meets the conditions 
specified in Sec.  98.33(b)(4)(ii) or (b)(4)(iii), you must calculate 
and report under this subpart the combined process and combustion 
CO2 emissions by operating and maintaining a CEMS to measure 
CO2 emissions according to the Tier 4 Calculation 
Methodology specified in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part (General Stationary 
Fuel Combustion Sources).
    (b) For each soda ash manufacturing line that is not subject to the 
requirements in paragraph (a) of this section, calculate and report the 
process CO2 emissions from the soda ash manufacturing line 
by using the procedure in either paragraphs (b)(1), (b)(2), or (b)(3) 
of this section; and the combustion CO2 emissions using the 
procedure in paragraph (b)(4) of this section.
    (1) Calculate and report under this subpart the combined process 
and combustion CO2 emissions by operating and maintaining a 
CEMS to measure CO2 emissions according to the Tier 4 
Calculation Methodology specified in Sec.  98.33(a)(4) and all 
associated requirements for Tier 4 in subpart C of this part (General 
Stationary Fuel Combustion Sources).
    (2) Use either Equation CC-1 or Equation CC-2 of this section to 
calculate annual CO2 process emissions from each 
manufacturing line that calcines trona to produce soda ash:
[GRAPHIC] [TIFF OMITTED] TR30OC09.118

[GRAPHIC] [TIFF OMITTED] TR30OC09.119


Where:

Ek = Annual CO2 process emissions from each 
manufacturing line, k (metric tons).
(ICT)n = Inorganic carbon content (percent by 
weight, expressed as a decimal fraction) in trona input, from the 
carbon analysis results for month n. This represents the ratio of 
trona to trona ore.
(ICsa)n = Inorganic carbon content (percent by 
weight, expressed as a decimal fraction) in soda ash output, from 
the carbon analysis results for month n. This represents the purity 
of the soda ash produced.
(Tt)n = Mass of trona input in month n (tons).
(Tsa)n = Mass of soda ash output in month n 
(tons).
2000/2205 = Conversion factor to convert tons to metric tons.
0.097/1 = Ratio of ton of CO2 emitted for each ton of 
trona.
0.138/1 = Ratio of ton of CO2 emitted for each ton of 
soda ash produced.

    (3) Site-specific emission factor method. Use Equations CC-3, CC-4, 
and CC-5 of this section to determine annual CO2 process 
emissions from manufacturing lines that use the liquid alkaline 
feedstock process to produce soda ash. You must conduct an annual 
performance test and measure CO2 emissions and flow rates at 
all process vents from the mine water stripper/evaporator for each 
manufacturing line and calculate CO2 emissions as described 
in paragraphs (b)(3)(i) through (b)(3)(iv) of this section.
    (i) During the performance test, you must measure the process vent 
flow from each process vent during the test and calculate the average 
rate for the test period in metric tons per hour.
    (ii) Using the test data, you must calculate the hourly 
CO2 emission rate using Equation CC-3 of this section:

[[Page 56469]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.120


Where:

ERCO2 = CO2 mass emission rate (metric tons/
hour).
CCO2 = Hourly CO2 concentration (percent 
CO2) as determined by Sec.  98.294(c).
10000 = Parts per million per percent
2.59 x 10-\9\ = Conversion factor (pounds-mole/dscf/ppm).
44 = Pounds per pound-mole of carbon dioxide.
Q = Stack gas volumetric flow rate per minute (dscfm).
60 = Minutes per hour
4.53 x 10 -\4\ = Conversion factor (metric tons/pound)

    (iii) Using the test data, you must calculate a CO2 
emission factor for the process using Equation CC-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.121


Where:
EFCO2 = CO2 emission factor (metric tons 
CO2/metric ton of process vent flow from mine water 
stripper/evaporator).
ERCO2 = CO2 mass emission rate (metric tons/
hour).
Vt = Process vent flow rate from mine water stripper/
evaporator during annual performance test (pounds/hour).
4.53 x 10-4 = Conversion factor (metric tons/pound)

    (iv) You must calculate annual CO2 process emissions 
from each manufacturing line using Equation CC-5 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.122


Where:
Ek = Annual CO2 process emissions for each 
manufacturing line, k (metric tons).
EFCO2 = CO2 emission factor (metric tons 
CO2/metric ton of process vent flow from mine water 
stripper/evaporator).
Va = Annual process vent flow rate from mine water 
stripper/evaporator (thousand pounds/hour).
H = Annual operating hours for the each manufacturing line.
0.453 = Conversion factor (metric tons/thousand pounds).

    (4) Calculate and report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the combustion CO2, 
CH4, and N2O emissions in the soda ash 
manufacturing line according to the applicable requirements in subpart 
C.


Sec.  98.294  Monitoring and QA/QC requirements.

    Section 98.293 provides three different procedures for emission 
calculations. The appropriate paragraphs (a) through (c) of this 
section should be used for the procedure chosen.
    (a) If you determine your emissions using Sec.  98.293(b)(2) 
(Equation CC-1 of this subpart) you must:
    (1) Determine the monthly inorganic carbon content of the trona 
from a weekly composite analysis for each soda ash manufacturing line, 
using a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard 
Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated 
by reference, see Sec.  98.7). ASTM E359-00(Reapproved 2005) e1 is 
designed to measure the total alkalinity in soda ash not in trona. The 
modified method of ASTM E359-00 adjusts the regular ASTM method to 
expresse the results in terms of trona. Although ASTM E359-00 
(Reapproved 2005) e1 uses manual titration, suitable autotitrators may 
also be used for this determination.
    (2) Measure the mass of trona input produced by each soda ash 
manufacturing line on a monthly basis using belt scales or methods used 
for accounting purposes.
    (3) Document the procedures used to ensure the accuracy of the 
monthly measurements of trona consumed.
    (b) If you calculate CO2 process emissions based on soda 
ash production (Sec.  98.293(b)(2) Equation CC-2 of this subpart), you 
must:
    (1) Determine the inorganic carbon content of the soda ash (i.e., 
soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test 
Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by 
reference, see Sec.  98.7). Although ASTM E359-00 (Reapproved 2005) e1 
uses manual titration, suitable autotitrators may also be used for this 
determination.
    (2) Measure the mass of soda ash produced by each soda ash 
manufacturing line on a monthly basis using belt scales, by weighing 
the soda ash at the truck or rail loadout points of your facility, or 
methods used for accounting purposes.
    (3) Document the procedures used to ensure the accuracy of the 
monthly measurements of soda ash produced.
    (c) If you calculate CO2 emissions using the site-
specific emission factor method in Sec.  98.293(b)(3), you must:
    (1) Conduct an annual performance test that is based on 
representative performance (i.e., performance based on normal operating 
conditions) of the affected process.
    (2) Sample the stack gas and conduct three emissions test runs of 1 
hour each.
    (3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, 
appendix A-2 to measure the CO2 concentration, Method 2, 2A, 
2C, 2D, or 2F at 40 CFR part 60, appendix A-1 or Method 26 at 40 CFR 
part 60, appendix A-2 to determine the stack gas volumetric flow rate. 
All QA/QC procedures specified in the reference test methods and any 
associated performance specifications apply. For each test, the 
facility must prepare an emission factor determination report that must 
include the items in paragraphs (c)(3)(i) through (c)(3)(iii) of this 
section.
    (i) Analysis of samples, determination of emissions, and raw data.
    (ii) All information and data used to derive the emissions 
factor(s).
    (iii) You must determine the average process vent flow rate from 
the mine water stripper/evaporater during each test and document how it 
was determined.
    (4) You must also determine the annual vent flow rate from the mine 
water stripper/evaporater from monthly information using the same plant 
instruments or procedures used for accounting purposes (i.e., 
volumetric flow meter).


Sec.  98.295  Procedures for estimating missing data.

    For the emission calculation methodologies in Sec.  98.293(b)(2) 
and (b)(3), a complete record of all measured parameters used in the 
GHG emissions calculations is required (e.g., inorganic carbon content 
values, etc.). Therefore, whenever a quality-assured value of a 
required parameter is unavailable, a substitute data value for the 
missing parameter shall be used in the calculations as specified in the 
paragraphs (a) through (d) of this

[[Page 56470]]

section. You must document and keep records of the procedures used for 
all such missing value estimates.
    (a) For each missing value of the weekly composite of inorganic 
carbon content of either soda ash or trona, the substitute data value 
shall be the arithmetic average of the quality-assured values of 
inorganic carbon contents from the week immediately preceding and the 
week immediately following the missing data incident. If no quality-
assured data on inorganic carbon contents are available prior to the 
missing data incident, the substitute data value shall be the first 
quality-assured value for carbon contents obtained after the missing 
data period.
    (b) For each missing value of either the monthly soda ash 
production or the trona consumption, the substitute data value shall be 
the best available estimate(s) of the parameter(s), based on all 
available process data or data used for accounting purposes.
    (c) For each missing value collected during the performance test 
(hourly CO2 concentration, stack gas volumetric flow rate, 
or average process vent flow from mine water stripper/evaporator during 
performance test), you must repeat the annual performance test 
following the calculation and monitoring and QA/QC requirements under 
Sec. Sec.  98.293(b)(3) and 98.294(c).
    (d) For each missing value of the monthly process vent flow rate 
from mine water stripper/evaporator, the subsititute data value shall 
be the best available estimate(s) of the parameter(s), based on all 
available process data or the lesser of the maximum capacity of the 
system or the maximum rate the meter can measure.


Sec.  98.296  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as appropriate for each soda ash manufacturing 
facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required under 
Sec.  98.36 and the following information in this paragraph (a):
    (1) Annual consumption of trona or liquid alkaline feedstock for 
each manufacturing line (metric tons).
    (2) Annual production of soda ash for each manufacturing line 
(tons).
    (3) Annual production capacity of soda ash for each manufacturing 
line (tons).
    (4) Identification number of each manufacturing line.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Identification number of each manufacturing line.
    (2) Annual process CO2 emissions from each soda ash 
manufacturing line (metric tons).
    (3) Annual production of soda ash (tons).
    (4) Annual production capacity of soda ash for each manufacturing 
line (tons).
    (5) Monthly consumption of trona or liquid alkaline feedstock for 
each manufacturing line (tons).
    (6) Monthly production of soda ash for each manufacturing line 
(metric tons).
    (7) Inorganic carbon content factor of trona or soda ash (depending 
on use of Equations CC-1 or CC-2 of this subpart) as measured by the 
applicable method in Sec.  98.294(b) or (c) for each month (percent by 
weight expressed as a decimal fraction).
    (8) Whether CO2 emissions for each manufacturing line 
were calculated using a trona input method as described in Equation CC-
1 of this subpart, a soda ash output method as described in Equation 
CC-2 of this subpart, or a site-specific emission factor method as 
described in Equations CC-3 through CC-5 of this subpart.
    (9) Number of manufacturing lines located used to produce soda ash.
    (10) If you produce soda ash using the liquid alkaline feedstock 
process and use the site-specific emission factor method (Sec.  
98.293(b)(3)) to estimate emissions then you must report the following 
relevant information:
    (i) Stack gas volumetric flow rate per minute (dscfm)
    (ii) Hourly CO2 concentration (percent CO2)
    (iii) CO2 emission factor (metric tons CO2/
metric tons of process vent flow from mine water stripper/evaporator).
    (iv) CO2 mass emission rate (metric tons/hour).
    (v) Average process vent flow from mine water stripper/evaporater 
during performance test (pounds/hour).
    (vi) Annual process vent flow rate from mine stripper/evaporator 
(thousand pounds/hour).
    (vii) Annual operating hours for each manufacturing line used to 
produce soda ash using liquid alkaline feedstock (hours).
    (11) Number of times missing data procedures were used and for 
which parameter as specified in this paragraph (b)(11):
    (i) Trona or soda ash (number of months).
    (ii) Inorganic carbon contents of trona or soda ash (weeks).
    (iii) Process vent flow rate from mine water stripper/evaporator 
(number of months).
    (iv) Stack gas volumetric flow rate during performance test (number 
of times).
    (v) Hourly CO2 concentration (number of times).
    (vi) Average vent process vent flow rate from mine stripper/
evaporator during performance test (number of times).


Sec.  98.297  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section 
for each soda ash manufacturing line.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart the records required for the Tier 4 
Calculation Methodology specified in subpart C of this part and the 
information listed in this paragraph (a):
    (1) Monthly production of soda ash (tons)
    (2) Monthly consumption of trona or liquid alkaline feedstock 
(tons)
    (3) Annual operating hours (hours).
    (b) If a CEMS is not used to measure emissions, then you must 
retain records for the information listed in this paragraph (b):
    (1) Records of all analyses and calculations conducted for 
determining all reported data as listed in Sec.  98.296(b).
    (2) If using Equation CC-1 or CC-2 of this subpart, weekly 
inorganic carbon content factor of trona or soda ash, depending on 
method chosen, as measured by the applicable method in Sec.  98.294(b) 
(percent by weight expressed as a decimal fraction).
    (3) Annual operating hours for each manufacturing line used to 
produce soda ash (hours).
    (4) You must document the procedures used to ensure the accuracy of 
the monthly trona consumption or soda ash production measurements 
including, but not limited to, calibration of weighing equipment and 
other measurement devices. The estimated accuracy of measurements made 
with these devices must also be recorded, and the technical basis for 
these estimates must be provided.
    (5) If you produce soda ash using the liquid alkaline feedstock 
process and use the site-specific emission factor method to estimate 
emissions (Sec.  98.293(b)(3)) then you must also retain the following 
relevant information:
    (i) Records of performance test results.
    (ii) You must document the procedures used to ensure the accuracy

[[Page 56471]]

of the annual average vent flow measurements including, but not limited 
to, calibration of flow rate meters and other measurement devices. The 
estimated accuracy of measurements made with these devices must also be 
recorded, and the technical basis for these estimates must be provided.


Sec.  98.298  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart DD--[Reserved]

Subpart EE--Titanium Dioxide Production


Sec.  98.310  Definition of the source category.

    The titanium dioxide production source category consists of 
facilities that use the chloride process to produce titanium dioxide.


Sec.  98.311  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a titanium dioxide production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (a)(2).


Sec.  98.312  GHGs to report.

    (a) You must report CO2 process emissions from each 
chloride process line as required in this subpart.
    (b) You must report CO2, CH4, and 
N2O emissions from each stationary combustion unit under 
subpart C of this part (General Stationary Fuel Combustion Sources) by 
following the requirements of subpart C.


Sec.  98.313  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions for each chloride process line using the procedures in either 
paragraph (a) or (b) of this section.
    (a) Calculate and report under this subpart the process 
CO2 emissions by operating and maintaining a CEMS according 
to the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4) 
and all associated requirements for Tier 4 in subpart C of this part 
(General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the annual process 
CO2 emissions for each chloride process line by determining 
the mass of calcined petroleum coke consumed in each line as specified 
in paragraphs (b)(1) through (b)(3) of this section. Use Equation EE-1 
of this section to calulate annual combined process CO2 
emissions from all process lines and use Equation EE-2 of this section 
to calculate annual process CO2 emissions for each process 
line. If your facility generates carbon-containing waste, use Equation 
EE-3 of this section to estimate the annual quantity of carbon-
containing waste generated and its carbon contents according to Sec.  
98.314(e) and (f):
    (1) You must calculate the annual CO2 process emissions 
from all process lines at the facility using Equation EE-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.123

Where:

CO2 = Annual CO2 emissions from titanium 
dioxide production facility (metric tons/year).
Ep = Annual CO2 emissions from chloride 
process line p (metric tons), determined using Equation EE-2 of this 
section.
p = Process line.
m = Number of separate chloride process lines located at the 
facility.

    (2) You must calculate the annual CO2 process emissions 
from each process lines at the facility using Equation EE-2 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.124


Where:

Ep = Annual CO2 mass emissions from chloride 
process line p (metric tons).
Cp,n = Calcined petroleum coke consumption for process 
line p in month n (tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion of tons to metric tons.
CCFn = Carbon content factor for petroleum coke consumed 
in month n from the supplier or as measured by the applicable method 
incorporated by reference in Sec.  98.7 according to Sec.  98.314(c) 
(percent by weight expressed as a decimal fraction).
n = Number of month.

    (3) If facility generates carbon-containing waste, you must 
calculate the total annual quantity of carbon-containing waste produced 
from all process lines using Equation EE-3 of this section and its 
carbon contents according to Sec.  98.314(e) and (f):
[GRAPHIC] [TIFF OMITTED] TR30OC09.125

Where:

TWC = Annual production of carbon-containing waste from titanium 
dioxide production facility (tons).
WCp,n = Production of carbon-containing waste in month n 
from chloride process line p (tons).
p = Process line.
m = Total number of process lines.
n = Number of month.

    (c) If GHG emissions from a chloride process line are vented 
through the same stack as any combustion unit or process equipment that 
reports CO2 emissions using a CEMS that complies with the 
Tier 4 Calculation Methodology in subpart C of this part (General 
Stationary Fuel Combustion Sources), then the calculation methodology 
in paragraph (b) of this section shall not be used to calculate process 
CO2 emissions. The owner or operator shall report under this 
subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.


Sec.  98.314  Monitoring and QA/QC requirements.

    (a) You must measure your consumption of calcined petroleum coke 
using plant instruments used for accounting purposes including direct 
measurement weighing the petroleum coke fed into your process (by belt 
scales or a similar device) or through the use of purchase records.
    (b) You must document the procedures used to ensure the accuracy of 
monthly calcined petroleum coke consumption measurements.
    (c) You must determine the carbon content of the calcined petroleum 
coke each month based on reports from the supplier. Alternatively, 
facilities can measure monthly carbon contents of the petroleum coke 
using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate 
Analysis of Coal and Coke (incorporated by reference, see Sec.  98.7) 
and ASTM D5373-08 Standard Test Methods for Instrumental Determination 
of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal 
(incorporated by reference, see Sec.  98.7).

[[Page 56472]]

    (d) For quality assurance and quality control of the supplier data, 
you must conduct an annual measurement of the carbon content from a 
representative sample of the petroleum coke consumed using ASTM D3176-
89 and ASTM D5373-08.
    (e) You must determine the quantity of carbon-containing waste 
generated from the each titanium production line dioxide using plant 
instruments used for accounting purposes including direct measurement 
weighing the carbon-containing waste not used during the process (by 
belt scales or a similar device) or through the use of sales records.
    (f) You must determine the carbon contents of the carbon-containing 
waste from each titanium production line on an annual basis by 
collecting and analyzing a representative sample of the material using 
ASTM D3176-89 and ASTM D5373-08.


Sec.  98.315  Procedures for estimating missing data.

    For the petroleum coke input procedure in Sec.  98.313(b), a 
complete record of all measured parameters used in the GHG emissions 
calculations is required (e.g., carbon content values, etc.). 
Therefore, whenever the monitoring and quality assurance procedures in 
Sec.  98.315 cannot be followed, a substitute data value for the 
missing parameter shall be used in the calculations as specified in the 
paragraphs (a) through (c) of this section. You must document and keep 
records of the procedures used for all such estimates.
    (a) For each missing value of the monthly carbon content of 
calcined petroleum coke the substitute data value shall be the 
arithmetic average of the quality-assured values of carbon contents for 
the month immediately preceding and the month immediately following the 
missing data incident. If no quality-assured data on carbon contents 
are available prior to the missing data incident, the substitute data 
value shall be the first quality-assured value for carbon contents 
obtained after the missing data period.
    (b) For each missing value of the monthly calcined petroleum coke 
consumption and/or carbon-containing waste, the substitute data value 
shall be the best available estimate of the monthly petroleum coke 
consumption based on all available process data or information used for 
accounting purposes (such as purchase records).
    (c) For each missing value of the carbon content of carbon-
containing waste, you must conduct a new analysis following the 
procedures in Sec.  98.314(f).


Sec.  98.316  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable for each titanium dioxide 
production line.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report the relevant information required under Sec.  
98.36(e)(2)(vi) for the Tier 4 Calculation Methodology and the 
following information in this paragraph (a).
    (1) Identification number of each process line.
    (2) Annual consumption of calcined petroleum coke (tons).
    (3) Annual production of titanium dioxide (tons).
    (4) Annual production capacity of titanium dioxide (tons).
    (5) Annual production of carbon-containing waste (tons), if 
applicable.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Identification number of each process line.
    (2) Annual CO2 emissions from each chloride process line 
(metric tons/year).
    (3) Annual consumption of calcined petroleum coke for each process 
line (tons).
    (4) Annual production of titanium dioxide for each process line 
(tons).
    (5) Annual production capacity of titanium dioxide for each process 
line (tons).
    (6) Calcined petroleum coke consumption for each process line for 
each month (tons).
    (7) Annual production of carbon-containing waste for each process 
line (tons), if applicable.
    (8) Monthly production of titanium dioxide for each process line 
(tons).
    (9) Monthly carbon content factor of petroleum coke from the 
supplier (percent by weight expressed as a decimal fraction).
    (10) Whether monthly carbon content of the petroleum coke is based 
on reports from the supplier or through self measurement using 
applicable ASTM standard methods.
    (11) Carbon content for carbon-containing waste (percent by weight 
expressed as a decimal fraction).
    (12) If carbon content of petroleum coke is based on self 
measurement, the ASTM standard methods used.
    (13) Sampling analysis results of carbon content of petroleum coke 
as determined for QA/QC of supplier data under Sec.  98.314(d) (percent 
by weight expressed as a decimal fraction).
    (14) Number of separate chloride process lines located at the 
facility.
    (15) The number of times in the reporting year that missing data 
procedures were followed to measure the carbon contents of petroleum 
coke (number of months); petroleum coke consumption (number of months); 
carbon-containing waste generated (number of months); and carbon 
contents of the carbon-containing waste (number of times during year).


Sec.  98.317  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) and (b) of this section 
for each titanium dioxide production facility.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must retain under this subpart required for the Tier 4 Calculation 
Methodology in Sec.  98.37 and the information listed in this paragraph 
(a):
    (1) Records of all calcined petroleum coke purchases.
    (2) Annual operating hours for each titanium dioxide process line.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must retain records for the information listed in this paraghraph:
    (1) Records of all calcined petroleum coke purchases (tons).
    (2) Records of all analyses and calculations conducted for all 
reported data as listed in Sec.  98.316(b).
    (3) Sampling analysis results for carbon content of consumed 
calcined petroleum coke (percent by weight expressed as a decimal 
fraction).
    (4) Sampling analysis results for the carbon content of carbon 
containing waste (percent by weight expressed as a decimal fraction), 
if applicable.
    (5) Monthly production of carbon-containing waste (tons).
    (6) You must document the procedures used to ensure the accuracy of 
the monthly petroleum coke consumption and quantity of carbon-
containing waste measurement including, but not limited to, calibration 
of weighing equipment and other measurement devices. The estimated 
accuracy of measurements made with these devices must also be recorded, 
and the technical basis for these estimates must be provided.
    (7) Annual operating hours for each titanium dioxide process line 
(hours).


Sec.  98.318  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[[Page 56473]]

Subpart FF--[Reserved]

Subpart GG--Zinc Production


Sec.  98.330  Definition of the source category.

    The zinc production source category consists of zinc smelters and 
secondary zinc recycling facilities.


Sec.  98.331  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a zinc production process and the facility meets the 
requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.332  GHGs to report.

    You must report:
    (a) CO2 process emissions from each Waelz kiln and 
electrothermic furnace used for zinc production.
    (b) CO2, CH4, and N2O combustion 
emissions from each Waelz kiln. You must calculate and report these 
emissions under subpart C of this part (General Stationary Fuel 
Combustion Sources) by following the requirements of subpart C.
    (c) CO2, CH4, and N2O emissions 
from each stationary combustion unit other than Waelz kilns. You must 
report these emissions under subpart C of this part (General Stationary 
Fuel Combustion Sources) by following the requirements of subpart C.


Sec.  98.333  Calculating GHG emissions.

    You must calculate and report the annual process CO2 
emissions using the procedures specified in either paragraph (a) or (b) 
of this section.
    (a) Calculate and report under this subpart the process or combined 
process and combustion CO2 emissions by operating and 
maintaining a CEMS according to the Tier 4 Calculation Methodology in 
Sec.  98.33(a)(4) and all associated requirements for Tier 4 in subpart 
C of this part (General Stationary Fuel Combustion Sources).
    (b) Calculate and report under this subpart the process 
CO2 emissions by following paragraphs (b)(1) and (b)(2) of 
this section.
    (1) For each Waelz kiln or electrothermic furnace at your facility 
used for zinc production, you must determine the mass of carbon in each 
carbon-containing material, other than fuel, that is fed, charged, or 
otherwise introduced into each Waelz kiln and electrothermic furnace at 
your facility for each year and calculate annual CO2 process 
emissions from each affected unit at your facility using Equation GG-1 
of this section. For electrothermic furnaces, carbon containing input 
materials include carbon eletrodes and carbonaceous reducing agents. 
For Waelz kilns, carbon containing input materials include carbonaceous 
reducing agents. If you document that a specific material contributes 
less than 1 percent of the total carbon into the process, you do not 
have to include the material in your calculation using Equation R-1 of 
Sec.  98.183.
[GRAPHIC] [TIFF OMITTED] TR30OC09.126

Where:

ECO2k = Annual CO2 process emissions from 
individual Waelz kiln or electrothermic furnace ``k'' (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion factor to convert tons to metric tons.
(Zinc)k = Annual mass of zinc bearing material charged to 
kiln or furnace ''k'' (tons).
(CZinc)k = Carbon content of the zinc bearing 
material, from the annual carbon analysis for kiln or furnace ``k'' 
(percent by weight, expressed as a decimal fraction).
(Flux)k = Annual mass of flux materials (e.g., limestone, 
dolomite) charged to kiln or furnace ``k'' (tons).
(CFlux)k = Carbon content of the flux 
materials charged to kiln or furnace ``k'', from the annual carbon 
analysis (percent by weight, expressed as a decimal fraction).
(Electrode)k = Annual mass of carbon electrode consumed 
in kiln or furnace ``k'' (tons).
(CElectrode)k = Carbon content of the carbon 
electrode consumed in kiln or furnace ``k'', from the annual carbon 
analysis (percent by weight, expressed as a decimal fraction).
(Carbon)k = Annual mass of carbonaceous materials (e.g., 
coal, coke) charged to the kiln or furnace ``k''(tons).
(CCarbon)k Carbon content of the carbonaceous 
materials charged to kiln or furnace, ``k'', from the annual carbon 
analysis (percent by weight, expressed as a decimal fraction).

    (2) You must determine the CO2 emissions from all of the 
Waelz kilns or electrothermic furnaces at your facility using Equation 
GG-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.127

Where:

CO2 = Annual combined CO2 emissions from all 
Waelz kilns or electrothermic furnaces (tons).
ECO2k = Annual CO2 emissions from each Waelz 
kiln or electrothermic furnace k calculated using Equation GG-1 of 
this section (tons).
n = Total number of Waelz kilns or electrothermic furnaces at 
facility used for the zinc production.

    (c) If GHG emissions from a Waelz kiln or electrothermic furnace 
are vented through the same stack as any combustion unit or process 
equipment that reports CO2 emissions using a CEMS that 
complies with the Tier 4 Calculation Methodology in subpart C of this 
part (General Stationary Fuel Combustion Sources), then the calculation 
methodology in paragraph (b) of this section shall not be used to 
calculate process emissions. The owner or operator shall report under 
this subpart the combined stack emissions according to the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4) and all associated 
requirements for Tier 4 in subpart C of this part.


Sec.  98.334  Monitoring and QA/QC requirements.

    If you determine CO2 emissions using the carbon input 
procedure in Sec.  98.333(b)(1) and (b)(2), you must meet the 
requirements specified in paragraphs (a) and (b) of this section.
    (a) Determine the mass of each solid carbon-containing input 
material consumed using facility instruments, procedures, or records 
used for accounting purposes including direct measurement weighing or 
through the use of purchase records same plant instruments or 
procedures that are used for accounting purposes (such as weigh 
hoppers, belt weigh feeders, weighed purchased quantities in shipments 
or containers, combination of bulk density and volume measurements, 
etc.). Record the total mass for the materials consumed each calendar 
month and sum the monthly mass to determine the annual mass for each 
input material.
    (b) For each input material identified in paragraph (a) of this 
section, you must determine the average carbon content of the material 
consumed or used in the calendar year using the methods specified in 
either paragraph (b)(1) or (b)(2) of this section.
    (1) Information provided by your material supplier.
    (2) Collecting and analyzing at least three representative samples 
of the material using the appropriate testing method. For each carbon-
containing

[[Page 56474]]

input material identified for which the carbon content is not provided 
by your material supplier, the carbon content of the material must be 
analyzed at least annually using the appropriate standard methods (and 
their QA/QC procedures), which are identified in paragraphs (b)(2)(i) 
through (b)(2)(iii) of this section, as applicable. If you document 
that a specific process input or output contributes less than one 
percent of the total mass of carbon into or out of the process, you do 
not have to determine the monthly mass or annual carbon content of that 
input or output.
    (i) Using ASTM E1941-04 Standard Test Method for Determination of 
Carbon in Refractory and Reactive Metals and Their Alloys (incorporated 
by reference, see Sec.  98.7), analyze zinc bearing materials.
    (ii) Using ASTM D5373-08 Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal (incorporated by reference, see Sec.  98.7), analyze 
carbonaceous reducing agents and carbon electrodes.
    (iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis 
of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, 
see Sec.  98.7), analyze flux materials such as limestone or dolomite.


Sec.  98.335  Procedures for estimating missing data.

    For the carbon input procedure in Sec.  98.333(b), a complete 
record of all measured parameters used in the GHG emissions 
calculations is required (e.g., raw materials carbon content values, 
etc.). Therefore, whenever a quality-assured value of a required 
parameter is unavailable, a substitute data value for the missing 
parameter shall be used in the calculations as specified in paragraphs 
(a) and (b) of this section. You must document and keep records of the 
procedures used for all such estimates.
    (a) For missing records of the carbon content of inputs for 
facilities that estimate emissions using the carbon input procedure in 
Sec.  98.333(b); 100 percent data availability is required. You must 
repeat the test for average carbon contents of inputs according to the 
procedures in Sec.  98.335(b) if data are missing.
    (b) For missing records of the annual mass of carbon-containing 
inputs using the carbon input procedure in Sec.  98.333(b), the 
substitute data value must be based on the best available estimate of 
the mass of the input material from all available process data or 
information used for accounting purposes, such as purchase records.


Sec.  98.336  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs (a) 
or (b) of this section, as applicable, for each Waelz kiln or 
electrothermic furnace.
    (a) If a CEMS is used to measure CO2 emissions, then you 
must report under this subpart the relevant information required for 
the Tier 4 Calculation Methodology in Sec.  98.37 and the information 
listed in this paragraph (a):
    (1) Annual zinc product production capacity (tons).
    (2) Annual production quantity for each zinc product (tons).
    (3) Annual facility production quantity for each zinc product 
(tons).
    (4) Number of Waelz kilns at each facility used for zinc 
production.
    (5) Number of electrothermic furnaces at each facility used for 
zinc production.
    (b) If a CEMS is not used to measure CO2 emissions, then 
you must report the information listed in this paragraph (b):
    (1) Kiln identification number and annual process CO2 
emissions from each individual Waelz kiln or electrothermic furnace 
(metric tons).
    (2) Annual zinc product production capacity (tons).
    (3) Annual production quantity for each zinc product (tons).
    (4) Number of Waelz kilns at each facility used for zinc 
production.
    (5) Number of electrothermic furnaces at each facility used for 
zinc production.
    (6) Annual mass of each carbon-containing input material charged to 
each kiln or furnace (including zinc bearing material, flux materials 
(e.g., limestone, dolomite), carbon electrode, and other carbonaceous 
materials (e.g., coal, coke)) (tons).
    (7) Carbon content of each carbon-containing input material charged 
to each kiln or furnace (including zinc bearing material, flux 
materials, and other carbonaceous materials) from the annual carbon 
analysis for each kiln or furnace (percent by weight, expressed as a 
decimal fraction).
    (8) Whether carbon content of each carbon-containing input material 
charged to each kiln or furnace is based on reports from the supplier 
or through self measurement using applicable ASTM standard method.
    (9) If carbon content of each carbon-containing input material 
charged to each kiln or furnace is based on self measurement, the ASTM 
Standard Test Method used.
    (10) Carbon content of the carbon electrode used in each furnace 
from the annual carbon analysis (percent by weight, expressed as a 
decimal fraction).
    (11) Whether carbon content of the carbon electrode used in each 
furnace is based on reports from the supplier or through self 
measurement using applicable ASTM standard method.
    (12) If carbon content of carbon electrode used in each furnace is 
based on self measurement, the ASTM standard method used.
    (13) If you use the missing data procedures in Sec.  98.335(b), you 
must report how the monthly mass of carbon-containing materials with 
missing data was determined and the number of months the missing data 
procedures were used.


Sec.  98.337  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the records specified in paragraphs (a) through (b) of this 
section for each zinc production facility.
    (a) If a CEMS is used to measure emissions, then you must retain 
under this subpart the records required for the Tier 4 Calculation 
Methodology in Sec.  98.37 and the information listed in this paragraph 
(a):
    (1) Monthly facility production quantity for each zinc product 
(tons).
    (2) Annual operating hours for all Waelz kilns and electrothermic 
furnaces used in zinc production.
    (b) If a CEMS is not used to measure emissions, you must also 
retain the records specified in paragraphs (b)(1) through (b)(7) of 
this section.
    (1) Records of all analyses and calculations conducted for data 
reported as listed in Sec.  98.336(b).
    (2) Annual operating hours for Waelz kilns and electrothermic 
furnaces used in zinc production.
    (3) Monthly production quantity for each zinc product (tons).
    (4) Monthly mass of zinc bearing materials, flux materials (e.g., 
limestone, dolomite), and carbonaceous materials (e.g., coal, coke) 
charged to the kiln or furnace (tons).
    (5) Sampling and analysis records for carbon content of zinc 
bearing materials, flux materials (e.g., limestone, dolomite), 
carbonaceous materials (e.g., coal, coke), charged to the kiln or 
furnace (percent by weight, expressed as a decimal fraction).
    (6) Monthly mass of carbon electrode consumed in for each 
electrothermic furnace (tons).
    (7) Sampling and analysis records for carbon content of electrode 
materials.
    (8) You must keep records that include a detailed explanation of 
how company records of measurements are used to estimate the carbon 
input to each Waelz kiln or electrothermic furnace, as applicable to 
your facility, including documentation of any materials excluded from 
Equation GG-

[[Page 56475]]

1 of this subpart that contribute less than 1 percent of the total 
carbon inputs to the process. You also must document the procedures 
used to ensure the accuracy of the measurements of materials fed, 
charged, or placed in an affected unit including, but not limited to, 
calibration of weighing equipment and other measurement devices. The 
estimated accuracy of measurements made with these devices must also be 
recorded, and the technical basis for these estimates must be provided.


Sec.  98.338  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart HH--Municipal Solid Waste Landfills


Sec.  98.340  Definition of the source category.

    (a) This source category applies to municipal solid waste (MSW) 
landfills that accepted waste on or after January 1, 1980.
    (b) This source category does not include hazardous waste 
landfills, construction and demolition landfills, or industrial 
landfills.
    (c) This source category consists of the following sources at 
municipal solid waste (MSW) landfills: Landfills, landfill gas 
collection systems, and landfill gas destruction devices (including 
flares).


Sec.  98.341  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a MSW landfill and the facility meets the requirements of 
Sec.  98.2(a)(1).


Sec.  98.342  GHGs to report.

    (a) You must report CH4 generation and CH4 
emissions from landfills.
    (b) You must report CH4 destruction resulting from 
landfill gas collection and combustion systems.
    (c) You must report under subpart C of this part (General 
Stationary Fuel Combustion Sources) the emissions of CO2, 
CH4, and N2O from each stationary combustion unit 
following the requirements of subpart C.


Sec.  98.343  Calculating GHG emissions.

    (a) For all landfills subject to the reporting requirements of this 
subpart, calculate annual modeled CH4 generation according 
to the applicable requirements in paragraphs (a)(1) through (a)(3) of 
this section.
    (1) Calculate annual modeled CH4 generation using 
Equation HH-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.128

Where:

GCH4 = Modeled methane generation rate in reporting year 
T (metric tons CH4).
X = Year in which waste was disposed.
S = Start year of calculation. Use the year 50 years prior to the 
year of the emissions estimate, or the opening year of the landfill, 
whichever is more recent.
T = Reporting year for which emissions are calculated.
Wx = Quantity of waste disposed in the landfill in year X 
from tipping fee receipts or other company records (metric tons, as 
received (wet weight)).
L0 = CH4 generation potential (metric tons 
CH4/metric ton waste) = MCF x DOC x DOCF x F x 
16/12.
MCF = Methane correction factor (fraction); default is 1.
DOC = Degradable organic carbon from Table HH-1 of this subpart or 
measurement data, if available [fraction (metric tons C/metric ton 
waste)].
DOCF = Fraction of DOC dissimilated (fraction); default 
is 0.5.
F = Fraction by volume of CH4 in landfill gas from 
measurement data, if available (fraction); default is 0.5.
k = Rate constant from Table HH-1 of this subpart or measurement 
data, if available (yr-1).

    (2) For years when material-specific waste quantity data are 
available, apply Equation HH-1 of this section for each waste quantity 
type and sum the CH4 generation rates for all waste types to 
calculate the total modeled CH4 generation rate for the 
landfill. Use the appropriate parameter values for k, DOC, MCF, 
DOCF, and F shown in Table HH-1 of this subpart. The annual 
quantity of each type of waste disposed must be calculated as the sum 
of the daily quantities of waste (of that type) disposed. You may use 
the bulk waste parameters for a portion of your waste materials when 
using the material-specific modeling approach for mixed waste streams 
that cannot be designated to a specific material type. For years when 
waste composition data are not available, use the bulk waste parameter 
values for k and L0 in Table HH-1 of this subpart for the 
total quantity of waste disposed in those years.
    (3) For years prior to reporting for which waste disposal 
quantities are not readily available, Wx shall be estimated 
using one of the applicable methods in paragraphs (a)(3)(i) through 
(a)(3)(iii) of this section. You must determine which method is most 
applicable to the conditions and disposal history of your facility and 
use that method to estimate waste disposal quantities.
    (i) Assume all prior year waste disposal quantities are the same as 
the waste quantity in the first reporting year.
    (ii) Use the estimated population served by the landfill in each 
year, the values for national average per capita waste generation, and 
fraction of generated waste disposed of in solid waste disposal sites 
found in Table HH-2 of this subpart, and calculate the waste quantity 
landfilled using Equation HH-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.129

Where:

Wx = Quantity of waste placed in the landfill in year x 
(metric tons, wet basis).
POPx = Population of served by the landfill in year x 
from city population, census data, or other estimates (capita).
WGR = Average per capita waste generation rate for year x from Table 
HH-2 of this subpart (metric tons per capita per year, wet basis; 
tons/cap/yr).
%SWDS = Percent of waste generated subsequently managed in solid 
waste disposal sites (i.e., landfills) for year x from Table HH-2 of 
this subpart.

    (iii) Use a constant average waste disposal quantity calculated 
using Equation HH-3 of this section for each year the landfill was in 
operation (i.e.,

[[Page 56476]]

from first accepting waste until the last year for which waste disposal 
data is unavailable, inclusive).
[GRAPHIC] [TIFF OMITTED] TR30OC09.130

Where:

WAR = Annual average waste acceptance rate (metric tons per year).
LFC = Landfill capacity or, for operating landfills, capacity of the 
landfill currently used from design drawings or engineering 
estimates (metric tons).
YrData = Year in which the landfill last received waste or, for 
operating landfills, the year prior to the first reporting year when 
waste disposal data is first available from company records, or best 
available data.
YrOpen = Year in which the landfill first received waste from 
company records or best available data. If no data are available for 
estimating YrOpen for a closed landfill, use 30 years as the default 
operating life of the landfill.

    (b) For landfills with gas collection systems, calculate the 
quantity of CH4 destroyed according to the requirements in 
paragraphs (b)(1) and (b)(2) of this section.
    (1) If you continuously monitor the flow rate, CH4 
concentration, temperature, pressure, and moisture content of the 
landfill gas that is collected and routed to a destruction device 
(before any treatment equipment) using a monitoring meter specifically 
for CH4 gas, as specified in Sec.  98.344, you must use this 
monitoring system and calculate the quantity of CH4 
recovered for destruction using Equation HH-4 of this section. A fully 
integrated system that directly reports CH4 content requires 
no other calculation than summing the results of all monitoring periods 
for a given year.
[GRAPHIC] [TIFF OMITTED] TR30OC09.131

Where:

R = Annual quantity of recovered CH4 (metric tons 
CH4).
N = Total number of measurement periods in a year. Use daily 
averaging periods for continuous monitoring system (N = 365). For 
weekly sampling, use N = 52.
n = Index for measurement period.
(V)n = Daily average volumetric flow rate for day n 
(acfm). If the flow rate meter automatically corrects for 
temperature and pressure, replace ``520 [deg]R/(T)n x 
(P)n/1 atm'' with ``1''. If the CH4 
concentration is determined on a dry basis and the flow rate meter 
automatically corrects for moisture/content, replace the term [1 - 
(fH20)n] with 1.
(fH2O)n = Daily average moisture 
content of landfill gas, volumetric basis (cubic feet water per 
cubic feet landfill gas).
(C)n = Daily average CH4 concentration of 
landfill gas for day n (volume %, dry basis). If the CH4 
concentration is determined on a wet basis, replace the term [1 - 
(fH20)n] with 1.
0.0423 = Density of CH4 lb/cf at 520 [deg]R or 60 [deg]F 
and 1 atm.
(T)n = Temperature at which flow is measured for day n 
([deg]R).
(P)n = Pressure at which flow is measured for day n 
(atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (2) If you do not continuously monitor according to paragraph 
(b)(1) of this section, you must determine the flow rate, 
CH4 concentration, temperature, pressure, and moisture 
content of the landfill gas that is collected and routed to a 
destruction device (before any treatment equipment) at least weekly 
according to the requirements in paragraphs (b)(2)(i) through 
(b)(2)(iii) of this section and calculate the quantity of 
CH4 recovered for destruction using Equation HH-4 of this 
section.
    (i) Continuously monitor gas flow rate and determine the cumulative 
volume of landfill gas each week and the cumulative volume of landfill 
gas each year that is collected and routed to a destruction device 
(before any treatment equipment). Under this option, the gas flow meter 
is not required to automatically correct for temperature, pressure, or, 
if necessary, moisture content. If the gas flow meter is not equipped 
with automatic correction for temperature, pressure, or, if necessary, 
moisture content, you must determine these parameters as specified in 
paragraph (b)(2)(iii) of this section.
    (ii) Determine the CH4 concentration in the landfill gas 
that is collected and routed to a destruction device (before any 
treatment equipment) in a location near or representative of the 
location of the gas flow meter no less than weekly.
    (iii) If the gas flow meter is not equipped with automatic 
correction for temperature, pressure, or, if necessary, moisture 
content:
    (A) Determine the temperature, pressure in the landfill gas that is 
collected and routed to a destruction device (before any treatment 
equipment) in a location near or representative of the location of the 
gas flow meter no less than weekly.
    (B) If the CH4 concentration is determined on a dry 
basis, determine the moisture content in the landfill gas that is 
collected and routed to a destruction device (before any treatment 
equipment) in a location near or representative of the location of the 
gas flow meter no less than weekly
    (c) Calculate CH4 generation (adjusted for oxidation in 
cover materials) and actual CH4 emissions (taking into 
account any CH4 recovery, and oxidation in cover materials) 
according to the applicable methods in paragraphs (c)(1) through (c)(3) 
of this section.
    (1) Calculate CH4 generation, adjusted for oxidation, 
from the modeled CH4 (GCH4 from Equation HH-1 of 
this section) using Equation HH-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.132

Where:

MG = Methane generation, adjusted for oxidation, from the landfill 
in the reporting year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year 
from Equation HH-1 of this section (metric tons CH4).
OX = Oxidation fraction. Use the default value of 0.1 (10%).

    (2) For landfills that do not have landfill gas collection systems, 
the CH4 emissions are equal to the CH4 generation 
(MG) calculated in Equation HH-5 of this section.
    (3) For landfills with landfill gas collection systems, calculate 
CH4 emissions using the methodologies specified in 
paragraphs (c)(3)(i) and (c)(3)(ii) of this section.

[[Page 56477]]

    (i) Calculate CH4 emissions from the modeled 
CH4 generation and measured CH4 recovery using 
Equation HH-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.133

Where:

Emissions = Methane emissions from the landfill in the reporting 
year (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year 
from Equation HH-1 of this section or the quantity of recovered 
CH4 from Equation HH-4 of this section, whichever is 
greater (metric tons CH4).
R = Quantity of recovered CH4 from Equation HH-4 of this 
section (metric tons).
OX = Oxidation fraction. Use the oxidation fraction default value of 
0.1 (10%).
DE = Destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99). If the gas is transported off-site 
for destruction, use DE = 1.
fDest = Fraction of hours the destruction device was 
operating (annual operating hours/8760 hours per year). If the gas 
is destroyed in a back-up flare (or simlar device) or if the gas is 
transported off-site for destruction, use fDest = 1.

    (ii) Calculate CH4 generation and CH4 
emissions using measured CH4 recovery and estimated gas 
collection efficiency and Equations HH-7 and HH-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.134

[GRAPHIC] [TIFF OMITTED] TR30OC09.135


Where:

MG = Methane generation, adjusted for oxidation, from the landfill 
in the reporting year (metric tons CH4).
Emissions = Methane emissions from the landfill in the reporting 
year (metric tons CH4).
R = Quantity of recovered CH4 from Equation HH-4 of this 
section (metric tons CH4).
CE = Collection efficiency estimated at landfill, taking into 
account system coverage, operation, and cover system materials from 
Table HH-3 of this subpart. If area by soil cover type information 
is not available, use default value of 0.75 (CE4 in table HH-3 of 
this subpart) for all areas under active influence of the collection 
system.
fRec = Fraction of hours the recovery system was 
operating (annual operating hours/8760 hours per year).
OX = Oxidation fraction. Use the oxidation fractions default value 
of 0.1 (10%).
DE = Destruction efficiency, (lesser of manufacturer's specified 
destruction efficiency and 0.99). If the gas is transported off-site 
for destruction, use DE = 1.
fDest = Fraction of hours the destruction device was 
operating (device operating hours/8760 hours per year). If the gas 
is destroyed in a back-up flare (or similar device) or if the gas is 
transported off-site for destruction, use fDest = 1.

Sec.  98.344  Monitoring and QA/QC requirements.

    (a) The quantity of waste landfilled must be determined using mass 
measurement equipment meeting the requirements for commercial weighing 
equipment as described in ``Specifications, Tolerances, and Other 
Technical Requirements For Weighing and Measuring Devices'' NIST 
Handbook 44 (2009)(incorporated by reference, see Sec.  98.7).
    (b) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas composition monitor capable of measuring 
the concentration of CH4 in the recovered landfill gas using one of the 
methods specified in paragraphs (b)(1) through (b)(6) of this section 
or as specified by the manufacturer. Gas composition monitors shall be 
calibrated prior to the first reporting year and recalibrated either 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent, or whenever the error in the midrange 
calibration check exceeds  10 percent.
    (1) Method 18 at 40 CFR part 60, appendix A-6.
    (2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas 
by Gas Chromatography (incorporated by reference, see Sec.  98.7).
    (3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography (incorporated by reference, see 
Sec.  98.7).
    (4) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography.
    (5) UOP539-97 Refinery Gas Analysis by Gas Chromatography 
(incorporated by reference, see Sec.  98.7).
    (6) As an alternative to the gas chromatography methods provided in 
paragraphs (b)(1) through (b)(5) of this section, you may use total 
gaseous organic concentration analyzers and calculate the methane 
concentration following the requirements in paragraphs (b)(6)(i) 
through (b)(6)(iii) of this section.
    (i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to 
determine total gaseous organic concentration. You must calibrate the 
instrument with methane and determine the total gaseous organic 
concentration as carbon (or as methane; K=1 in Equation 25A-1 of Method 
25A at 40 CFR part 60, appendix A-7).
    (ii) Determine a non-methane organic carbon correction factor no 
less frequently than once a reporting year following the requirements 
in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.
    (A) Take a minimum of three grab samples of the landfill gas that 
is collected and routed to a destruction device (before any treatment 
equipment) with a minimum of 20 minutes between samples and determine 
the methane composition of the landfill gas using one of the methods 
specificed in paragraphs (b)(1) through (b)(5) of this section.
    (B) As soon as practical after each grab sample is collected and 
prior to the collection of a subsequent grab sample, determine the 
total gaseous organic concentration of the landfilll gas that is

[[Page 56478]]

collected and routed to a destruction device (before any treatment 
equipment) using either Method 25A or 25B at 40 CFR part 60, appendix 
A-7 as specified in paragaph (b)(6)(i) of this section.
    (C) Determine the arithmetic average methane concentration and the 
arithmetic average total gaseous organic concentration of the samples 
analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of 
this section, respectively, and calculate the non-methane organic 
carbon correction factor as the ratio of the average methane 
concentration to the average total gaseous organic concentration. If 
the ratio exceeds 1, use 1 for the non-methane organic carbon 
correction factor.
    (iii) Calculate the methane concentration as specified in Equation 
HH-9 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.136


Where:

CCH4 = Methane concentration in the landfill 
gas (volume %).
fNMOC = Non-methane organic carbon correction factor from 
the most recent determination of the non-methane organic carbon 
correction factor as specified in paragraph (b)(6)(ii) of this 
section (unitless).
CTGOC = Total gaseous organic carbon concentration 
measured using Method 25A or 25B at 40 CFR part 60, appendix A-7 
during routine monitoring of the landfill gas (volume %).

    (c) For landfills with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate of the recovered landfill gas using one of the 
methods specified in paragraphs (c)(1) through (c)(8) of this section 
or as specified by the manufacturer. Each gas flow meter shall be 
calibrated prior to the first year of reporting and recalibrated either 
biennially (every 2 years) or at the minimum frequency specified by the 
manufacturer. Except as provided in Sec.  98.343(b)(2)(i), each gas 
flow meter must be capable of correcting for the temperature and 
pressure and, if the gas composition monitor determines CH4 
concentration on a dry basis, moisture content.
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of 
Coriolis Mass Flowmeters (incorporated by reference, see Sec.  98.7). 
The mass flow must be corrected to volumetric flow based on the 
measured temperature, pressure, and gas composition.
    (6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec.  98.7).
    (8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
    (d) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer.
    (e) The owner or operator shall document the procedures used to 
ensure the accuracy of the estimates of disposal quantities and, if 
applicable, gas flow rate, gas composition, temperature, and pressure 
measurements. These procedures include, but are not limited to, 
calibration of weighing equipment, fuel flow meters, and other 
measurement devices. The estimated accuracy of measurements made with 
these devices shall also be recorded, and the technical basis for these 
estimates shall be provided.


Sec.  98.345  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements in paragraphs (a) 
through (c) of this section.
    (a) For each missing value of the CH4 content, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately 
following the missing data incident. If the ``after'' value is not 
obtained by the end of the reporting year, you may use the ``before'' 
value for the missing data substitution. If, for a particular 
parameter, no quality-assured data are available prior to the missing 
data incident, the substitute data value shall be the first quality-
assured value obtained after the missing data period.
    (b) For missing gas flow rates, the substitute data value shall be 
the arithmetic average of the quality-assured values of that parameter 
immediately preceding and immediately following the missing data 
incident. If the ``after'' value is not obtained by the end of the 
reporting year, you may use the ``before'' value for the missing data 
substitution. If, for a particular parameter, no quality-assured data 
are available prior to the missing data incident, the substitute data 
value shall be the first quality-assured value obtained after the 
missing data period.
    (c) For missing daily waste disposal quantity data for disposal in 
reporting years, the substitute value shall be the average daily waste 
disposal quantity for that day of the week as measured on the week 
before and week after the missing daily data.


Sec.  98.346  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each landfill.
    (a) A classification of the landfill as ``open'' (actively received 
waste in the reporting year) or ``closed'' (no longer receiving waste), 
the year in which the landfill first started accepting waste for 
disposal, the last year the landfill accepted waste (for open 
landfills, enter the estimated year of landfill closure), the capacity 
(in metric tons) of the landfill, an indication of whether leachate 
recirculation is used, and the waste disposal quantity for each year of 
landfilling.
    (b) Method for estimating waste disposal quantity, and reason for 
its selection.
    (c) Waste composition for each year of landfilling, if available, 
in percentage categorized as:
    (1) Municipal.
    (2) Biosolids or biological sludges.
    (3) Other, or more refined categories, such as those for which k 
rates are available in Table HH-1 of this subpart, and the method or 
basis for estimating waste composition.
    (d) For each waste type used to calculate CH4 generation 
using Equation HH-1 of this subpart, you must report:
    (1) Degradable organic carbon (DOC) value used in the calculations.
    (2) Decay rate (k) value used in the calculations.
    (e) Fraction of CH4 in landfill gas (F) and an 
indication of whether the fraction of CH4 was determined 
based on measured values or the default value.
    (f) The surface area of the landfill containing waste (in square 
meters), the cover types applicable to the landfill, the surface area 
and oxidation fraction

[[Page 56479]]

for each cover type used to calculate the average oxidation fraction, 
and the average oxidation fraction used in the calculations.
    (g) The modeled annual methane generation rate for the reporting 
year (metric tons CH4) calculated using Equation HH-1 of 
this subpart.
    (h) For landfills without gas collection systems, the annual 
methane emissions (i.e., the methane generation, adjusted for 
oxidation, calculated using Equation HH-5 of this subpart), reported in 
metric tons CH4.
    (i) For landfills with gas collection systems, you must report:
    (1) Total volumetric flow of landfill gas collected for destruction 
(cubic feet at 520 [deg]R or 60 [deg]F and 1 atm).
    (2) CH4 concentration of landfill gas collected for 
destruction (percent by volume).
    (3) Monthly average temperature for each month at which flow is 
measured for landfill gas collected for destruction, or statement that 
temperature is incorporated into internal calculations run by the 
monitoring equipment.
    (4) Monthly average pressure for each month at which flow is 
measured for landfill gas collected for destruction, or statement that 
temperature is incorporated into internal calculations run by the 
monitoring equipment.
    (5) An indication of whether destruction occurs at the landfill 
facility or off-site. If destruction occurs at the landfill facility, 
also report an indication of whether a back-up destruction device is 
present at the landfill, the annual operating hours for the primary 
destruction device, the annual operating hours for the back-up 
destruction device (if present), and the destruction efficiency used 
(percent).
    (6) Annual quantity of recovered CH4 (metric tons 
CH4) calculated using Equation HH-4 of this subpart.
    (7) A description of the gas collection system (manufacture, 
capacity, number of wells, etc.), the surface area (square meters) and 
estimated waste depth (meters) for each area specified in Table HH-3 of 
this subpart, the estimated gas collection system efficiency for 
landfills with this gas collection system, and the annual operating 
hours of the gas collection system.
    (8) Methane generation corrected for oxidation calculated using 
Equation HH-5 of this subpart, reported in metric tons CH4.
    (9) Methane generation (GCH4) value used as an input to 
Equation HH-6 of this subpart. Specify whether the value is modeled 
(GCH4 from HH-1 of this subpart) or measured (R from 
Equation HH-4 of this subpart).
    (10) Methane generation corrected for oxidation calculated using 
Equation HH-7 of this subpart, reported in metric tons CH4.
    (11) Methane emissions calculated using Equation HH-6 of this 
subpart, reported in metric tons CH4.
    (12) Methane emissions calculated using Equation HH-8 of this 
subpart, reported in metric tons CH4.


Sec.  98.347  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.


Sec.  98.348  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

    Table HH-1 to Subpart HH of Part 98--Emissions Factors, Oxidation
                           Factors and Methods
------------------------------------------------------------------------
             Factor                  Default value           Units
------------------------------------------------------------------------
                     Waste model--bulk waste option
------------------------------------------------------------------------
k (precipitation <20 inches/year  0.02..............  yr-\1\
 and no leachate recirculation).
k (precipitation 20-40 inches/    0.038.............  yr-\1\
 year and no leachate
 recirculation).
k (precipitation >40 inches/year  0.057.............  yr-\1\
 or for landfill areas with
 leachate recirculation).
L0 (Equivalent to DOC = 0.2028    0.067.............  metric tons CH4/
 when MCF = 1, DOCF = 0.5, and F                       metric ton waste
 = 0.5).
------------------------------------------------------------------------
                     Waste model--All MSW landfills
------------------------------------------------------------------------
MCF.............................  1.................  ..................
DOCF............................  0.5...............  ..................
F...............................  0.5...............  ..................
------------------------------------------------------------------------
             Waste model--MSW using waste composition option
------------------------------------------------------------------------
DOC (food waste)................  0.15..............  Weight fraction,
                                                       wet basis
DOC (garden)....................  0.2...............   Weight fraction,
                                                       wet basis
DOC (paper).....................  0.4...............  Weight fraction,
                                                       wet basis
DOC (wood and straw)............  0.43..............  Weight fraction,
                                                       wet basis
DOC (textiles)..................  0.24..............  Weight fraction,
                                                       wet basis
DOC (diapers)...................  0.24..............  Weight fraction,
                                                       wet basis
DOC (sewage sludge).............  0.05..............  Weight fraction,
                                                       wet basis
DOC (bulk waste)................  0.20..............  Weight fraction,
                                                       wet basis
k (food waste)..................  0.06 to 0.185\a\..  yr-\1\
k (garden)......................  0.05 to 0.10 \a\..  yr-\1\
k (paper).......................  0.04 to 0.06 \a\..  yr-\1\
k (wood and straw)..............  0.02 to 0.03 \a\..  yr-\1\
k (textiles)....................  0.04 to 0.06 \a\..  yr-\1\
k (diapers).....................  0.05 to 0.10 \a\..  yr-\1\
k (sewage sludge)...............  0.06 to 0.185 \a\.  yr-\1\
------------------------------------------------------------------------
              Calculating methane generation and emissions
------------------------------------------------------------------------
OX..............................  0.1...............  ..................

[[Page 56480]]

 
DE..............................  0.99..............  ..................
------------------------------------------------------------------------
\a\ Use the lesser value when the potential evapotranspiration rate
  exceeds the mean annual precipitation rate and leachate recirculation
  is not used. Use the greater value when the potential
  evapotranspiration rate does not exceed the mean annual precipitation
  rate or when leachate recirculation is used.


   Table HH-2 to Subpart HH of Part 98--U.S. Per Capita Waste Disposal
                                  Rates
------------------------------------------------------------------------
                                             Waste per
                  Year                     capita  ton/      % to SWDS
                                              cap/yr
------------------------------------------------------------------------
1950....................................            0.63             100
1951....................................            0.63             100
1952....................................            0.63             100
1953....................................            0.63             100
1954....................................            0.63             100
1955....................................            0.63             100
1956....................................            0.63             100
1957....................................            0.63             100
1958....................................            0.63             100
1959....................................            0.63             100
1960....................................            0.63             100
1961....................................            0.64             100
1962....................................            0.64             100
1963....................................            0.65             100
1964....................................            0.65             100
1965....................................            0.66             100
1966....................................            0.66             100
1967....................................            0.67             100
1968....................................            0.68             100
1969....................................            0.68             100
1970....................................            0.69             100
1971....................................            0.69             100
1972....................................            0.70             100
1973....................................            0.71             100
1974....................................            0.71             100
1975....................................            0.72             100
1976....................................            0.73             100
1977....................................            0.73             100
1978....................................            0.74             100
1979....................................            0.75             100
1980....................................            0.75             100
1981....................................            0.76             100
1982....................................            0.77             100
1983....................................            0.77             100
1984....................................            0.78             100
1985....................................            0.79             100
1986....................................            0.79             100
1987....................................            0.80             100
1988....................................            0.80             100
1989....................................            0.85              84
1990....................................            0.84              77
1991....................................            0.78              76
1992....................................            0.76              72
1993....................................            0.78              71
1994....................................            0.77              67
1995....................................            0.72              63
1996....................................            0.71              62
1997....................................            0.72              61
1998....................................            0.78              61
1999....................................            0.78              60
2000....................................            0.84              61
2001....................................            0.95              63
2002....................................            1.06              66
2003....................................            1.06              65
2004....................................            1.06              64
2005....................................            1.06              64
2006....................................            1.06              64
------------------------------------------------------------------------


[[Page 56481]]


      Table HH-3 to Subpart HH of Part 98--Landfill Gas Collection
                              Efficiencies
------------------------------------------------------------------------
                                             Landfill Gas Collection
              Description                           Efficiency
------------------------------------------------------------------------
A1: Area with no waste in-place........  Not applicable; do not use this
                                          area in the calculation.
A2: Area without active gas collection,  CE2: 0%.
 regardless of cover type.
H2: Average depth of waste in area A2..
A3: Area with daily soil cover and       CE3: 60%.
 active gas collection.
H3: Average depth of waste in area A3..
A4: Area with an intermediate soil       CE4: 75%.
 cover and active gas collection.
H4: Average depth of waste in area A4..
A5: Area with a final soil and           CE5: 95%.
 geomembrane cover system and active
 gas collection.
H5: Average depth of waste in area A5..
Area weighted average collection         CEave1 = (A2*CE2 + A3*CE3 +
 efficiency for landfills.                A4*CE4 + A5*CE5)/
                                          (A2+A3+A4+A5).
------------------------------------------------------------------------

Subpart II--[Reserved]

Subpart JJ--Manure Management


Sec.  98.360  Definition of the source category.

    (a) This source category consists of livestock facilities with 
manure management systems that emit 25,000 metric tons CO2e 
or more per year.
    (1) Table JJ-1 presents the minimum average annual animal 
population by animal group that is estimated to emit 25,000 metric tons 
CO2e or more per year. Facilities with an average annual 
animal population, as described in Sec.  98.363(a)(1) and (2), below 
those listed in Table JJ-1 do not need to report under this rule. A 
facility with an annual animal population that exceeds those listed in 
Table JJ-1 should conduct a more thorough analysis to determine 
applicability.
    (2) (i) If a facility has more than one animal group present (e.g., 
swine and poultry), the facility must determine if they are required to 
report by calculating the combined animal group factor (CAGF) using 
equation JJ-1:
[GRAPHIC] [TIFF OMITTED] TR30OC09.137


Where:

CAGF = Combined Animal Group Factor
AAAPAG,Facility = Average annual animal population at the 
facility, by animal group
APTL AG = Animal population threshold level, as specified 
in Table JJ-1 of this section

    (ii) If the calculated CAGF for a facility is less than 1, the 
facility is not required to report under this rule. If the CAGF is 
equal to or greater than 1, the facility must use more detailed 
applicability tables and tools to determine if they are required to 
report under this rule.
    (b) A manure management system (MMS) is a system that stabilizes 
and/or stores livestock manure, litter, or manure wastewater in one or 
more of the following system components: Uncovered anaerobic lagoons, 
liquid/slurry systems with and without crust covers (including but not 
limited to ponds and tanks), storage pits, digesters, solid manure 
storage, dry lots (including feedlots), high-rise houses for poultry 
production (poultry without litter), poultry production with litter, 
deep bedding systems for cattle and swine, manure composting, and 
aerobic treatment.
    (c) This source category does not include system components at a 
livestock facility that are unrelated to the stabilization and/or 
storage of manure such as daily spread or pasture/range/paddock systems 
or land application activities or any method of manure utilization that 
is not listed in Sec.  98.360(b).
    (d) This source category does not include manure management 
activities located off site from a livestock facility or off-site 
manure composting operations.


Sec.  98.361  Reporting threshold.

    Livestock facilities must report GHG emissions under this subpart 
if the facility meets the reporting threshold as defined in 98.360(a) 
above, contains a manure management system as defined in 98.360(b) 
above, and meets the requirements of Sec.  98.2(a)(1).


Sec.  98.362  GHGs to report.

    (a) Livestock facilities must report annual aggregate 
CH4 and N2O emissions for the following MMS 
components at the facility:
    (1) Uncovered anaerobic lagoons.
    (2) Liquid/slurry systems (with and without crust covers, and 
including but not limited to ponds and tanks).
    (3) Storage pits.
    (4) Digesters, including covered anaerobic lagoons.
    (5) Solid manure storage.
    (6) Dry lots, including feedlots.
    (7) High-rise houses for poultry production (poultry without 
litter)
    (8) Poultry production with litter.
    (9) Deep bedding systems for cattle and swine.
    (10) Manure composting.
    (11) Aerobic treatment.
    (b) A livestock facility that is subject to this rule only because 
of emissions from manure management system components is not required 
to report emissions from subparts C through PP (other than subpart JJ) 
of this part.
    (c) A livestock facility that is subject to this part because of 
emissions from source categories described in subparts C through PP of 
this part is not required to report emissions under subpart JJ of this 
part unless emissions from manure management systems are 25,000 metric 
tons CO2e per year or more.


Sec.  98.363  Calculating GHG emissions.

    (a) For all manure management system components listed in 98.360(b) 
except digesters, estimate the annual CH4 emissions and sum 
for all the components to obtain total emissions from the manure 
management system for all animal types using Equation JJ-1.

[[Page 56482]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.138

Where:

MMSC = Manure management systems component.
TVSAT = Total volatile solids excreted by animal type, 
calculated using Equation JJ-3 of this section (kg/day).
VSMMSC = Fraction of the total manure for each animal 
type that is managed in MMS component MMSC, assumed to be equivalent 
to the fraction of VS in each MMS component.
VSss = Volatile solids removal through solid separation; 
if solid separation occurs prior to the MMS component, use a default 
value from Table JJ-4 of this section; if no solid separation 
occurs, this value is set to 0.
(B0)AT = Maximum CH4-producing 
capacity for each animal type, as specified in Table JJ-2 of this 
section (m\3\ CH4/kg VS).
MCFMMSC = CH4 conversion factor for the MMS 
component, as specified in Table JJ-5 of this section (decimal).
[GRAPHIC] [TIFF OMITTED] TR30OC09.139

Where:

TVSAT = Daily total volatile solids excreted per animal 
type (kg/day).
PopulationAT = Average annual animal population 
contributing manure to the manure management system by animal type 
(head) (see description in Sec.  98.363(a)(i) and (ii) below).
TAMAT = Typical animal mass for each animal type, using 
either default values in Table JJ-2 of this section or farm-specific 
data (kg/head).
VSAT = Volatile solids excretion rate for each animal 
type, using default values in Table JJ-2 or JJ-3 of this section (kg 
VS/day/1000 kg animal mass).

    (1) Average annual animal populations for static populations (e.g., 
dairy cows, breeding swine, layers) must be estimated by performing an 
animal inventory or review of facility records once each reporting 
year.
    (2) Average annual animal populations for growing populations (meat 
animals such as beef and veal cattle, market swine, broilers, and 
turkeys) must be estimated each year using the average number of days 
each animal is kept at the facility and the number of animals produced 
annually, and an equation similar or equal to Equation JJ-4 below, 
adapted from Equation 10.1 in 2006 IPCC Guidelines for National 
Greenhouse Gas Inventories, Volume 4, Chapter 10.
[GRAPHIC] [TIFF OMITTED] TR30OC09.140

Where:

PopulationAT = Average annual animal population (by 
animal type).
Days onsiteAT = Average number of days the animal is kept 
at the facility, by animal type.
NAPAAT = Number of animals produced annually, by animal 
type.

    (b) For each digester, calculate the total amount of CH4 
emissions, and then sum the emissions from all digesters, as shown in 
Equation JJ-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.141

Where:

CH4 EmissionsAD = CH4 emissions 
from anaerobic digestion (metric tons/yr).
AD = Number of anaerobic digesters at the manure management 
facility.
CH4C = CH4 flow to digester combustion device, 
calculated using Equation JJ-6 of this section (metric tons 
CH4/yr).
CH4D = CH4 destruction at digesters, 
calculated using Equation JJ-11 of this section (metric tons 
CH4/yr) .
CH4L = Leakage at digesters calculated using Equation JJ-
12 of this section (metric tons CH4/yr).

    (1) For each digester, calculate the annual CH4 flow to 
the combustion device (CH4C) using Equation JJ-6 of this 
section. A fully integrated system that directly reports the quantity 
of CH4 flow to the digester combustion device requires only 
summing the results of all monitoring periods for a given year to 
obtain CH4C.
[GRAPHIC] [TIFF OMITTED] TR30OC09.142

Where:

CH4C = CH4 flow to digester combustion device 
(metric tons CH4/yr).
V = Average annual volumetric flow rate, calculated in Equation JJ-7 
of this subsection (cubic feet CH4/yr).
C = Average annual CH4 concentration of digester gas, 
calculated in Equation JJ-8 of this section (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60 
[deg]F and 1 atm).

[[Page 56483]]

T = Average annual temperature at which flow is measured, calculated 
in Equation JJ-9 of this section ([deg]R).
P = Average annual pressure at which flow is measured, calculated in 
Equation JJ-10 of this section (atm).

    (2) For each digester, calculate the average annual volumetric flow 
rate, CH4 concentration of digester gas, temperature, and 
pressure at which flow are measured using Equations JJ-7 through JJ-10 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.143

Where:

V = Average annual volumetric flow rate (cubic feet CH4/
yr).
OD = Operating days, number of days per year that that the digester 
was operating (days/yr).
Vn = Daily average volumetric flow rate for day n, as 
determined from daily monitoring as specified in Sec.  98.364 
(acfm).
[GRAPHIC] [TIFF OMITTED] TR30OC09.144

Where:

C = Average annual CH4 concentration of digester gas (%, 
wet basis).
OD = Operating days, number of days per year that the digester was 
operating (days/yr).
Cn = Average daily CH4 concentration of 
digester gas for day n, as determined from daily monitoring as 
specified in Sec.  98.364 (%, wet basis).
[GRAPHIC] [TIFF OMITTED] TR30OC09.145

Where:

T = Average annual temperature at which flow is measured ([deg]R).
OD = Operating days, number of days per year that the digester was 
operating (days/yr).
Tn = Temperature at which flow is measured for day 
n([deg]R).
[GRAPHIC] [TIFF OMITTED] TR30OC09.146

Where:

P = Average annual pressure at which flow is measured (atm).
OD = Operating days, number of days per year that the digester was 
operating (days/yr).
Pn = Pressure at which flow is measured for day n (atm).

    (3) For each digester, calculate the CH4 destruction at 
the digester combustion device using Equation JJ-11 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.147

Where:

CH4D = CH4 destruction at digester combustion 
device (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester 
combustion device, as calculated in Equation JJ-6 of this section 
(metric tons CH4).
DE = CH4 destruction efficiency from flaring or burning 
in engine (lesser of manufacturer's specified destruction efficiency 
and 0.99). If the gas is transported off-site for destruction, use 
DE = 1.
OH = Number of hours combustion device is functioning in reporting 
year.
Hours = Hours in reporting year.

    (4) For each digester, calculate the CH4 leakage using 
Equation JJ-12 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.148

Where:

CH4L = Leakage at digesters (metric tons/yr).
CH4C = Annual quantity of CH4 flow to digester 
combustion device, as calculated in Equation JJ-6 of this section 
(metric tons CH4).
CE = CH4 collection efficiency of anaerobic digester, as 
specified in Table JJ-6 of this section (decimal).

    (c) For each MMS component, estimate the annual N2O 
emissions and sum for all MMS components to obtain total emissions from 
the manure management system for all animal types using Equation JJ-13 
of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.149

Where:

Nex AT = Daily total nitrogen excreted per animal type, 
calculated using Equation JJ-14 of this section (kg N/day).
Nex,MMSC = Fraction of the total manure for each animal 
type that is managed in MMS component MMSC, assumed to be equivalent 
to the fraction of Nex in each MMS component.
Nss = Nitrogen removal through solid separation; if solid 
separation occurs prior to the MMS component, use a default value 
from Table JJ-4 of this

[[Page 56484]]

section; if no solid separation occurs, this value is set to 0.
EFMMSC = Emission factor for MMS component, as specified 
in Table JJ-7 of this section (kg N2O-N/kg N).
[GRAPHIC] [TIFF OMITTED] TR30OC09.150

Where:

Nex AT = Total nitrogen excreted per animal type (kg/
day).
PopulationAT = Average annual animal population 
contributing manure to the manure management system by animal type 
(head) (see description in Sec.  98.363(a)(i) and (ii)).
TAMAT = Typical animal mass by animal type, using either 
default values in Table JJ-2 of this section or farm-specific data 
(kg/head).
NAT = Nitrogen excretion rate by animal type, using 
default values in Tables JJ-2 or JJ-3 of this section (kg N/day/1000 
kg animal mass).

    (d) Estimate the annual total facility emissions using Equation JJ-
15 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.151

Where:

CH4 emissionsMMS = From Equation JJ-2 of this 
section.
CH4 emissionsAD = From Equation JJ-5 of this 
section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = From Equation JJ-13 of this 
section.
310 = Global Warming Potential of N2O.

Sec.  98.364  Monitoring and QA/QC requirements.

    (a) Perform an annual animal inventory or review of facility 
records (for static populations) or population calculation (for growing 
populations) to determine the average annual animal population for each 
animal type (see description in Sec.  98.363(a)(1) and (2)).
    (b) Perform an analysis on your operation to determine the fraction 
of total manure by weight for each animal type that is managed in each 
on-site manure management system component. If your system changes from 
previous reporting periods, you must reevaluate the fraction of total 
manure managed in each system component.
    (c) The CH4 concentration of gas from digesters must be 
determined using ASTM D1946-90 (Reapproved 2006) Standard Practice for 
Analysis of Reformed Gas by Gas Chromatography (incorporated by 
reference see Sec.  98.7). All gas composition monitors shall be 
calibrated prior to the first reporting year for biogas methane and 
carbon dioxide content using ASTM D1946-90 (Reapproved 2006) Standard 
Practice for Analysis of Reformed Gas by Gas Chromatography 
(incorporated by reference see Sec.  98.7)and recalibrated either 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent, or whenever the error in the midrange 
calibration check exceeds  10 percent. All monitors shall 
be maintained as specified by the manufacturer.
    (d) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer. All 
equipment (temperature and pressure monitors) shall be maintained as 
specified by the manufacturer.
    (e) For digesters with gas collection systems, install, operate, 
maintain, and calibrate a gas flow meter capable of measuring the 
volumetric flow rate to provide data for the GHG emissions 
calculations, using the applicable methods specified in paragraphs 
(e)(1) through (e)(6) of this section or as specified by the 
manufacturer.
    (1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi (incorporated by reference, see Sec.  
98.7).
    (2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by 
Turbine Meters (incorporated by reference, see Sec.  98.7).
    (3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters (incorporated by reference, see Sec.  98.7).
    (4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles (incorporated by reference, see 
Sec.  98.7).
    (5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore 
Precision Orifice Meters (incorporated by reference, see Sec.  98.7).
    (6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area 
Meters (incorporated by reference, see Sec.  98.7).
    (f) If applicable, the owner or operator shall document the 
procedures used to ensure the accuracy of gas flow rate, gas 
composition, temperature, and pressure measurements. These procedures 
include, but are not limited to, calibration of fuel flow meters and 
other measurement devices. The estimated accuracy of measurements made 
with these devices shall also be recorded, and the technical basis for 
these estimates shall be provided.
    (g) Each gas flow meter shall be calibrated prior to the first 
reporting year and recalibrated either annually or at the minimum 
frequency specified by the manufacturer, whichever is more frequent. 
Each gas flow meter must have a rated accuracy of  5 
percent or lower and be capable of correcting for the temperature and 
pressure and, if the gas composition monitor determines CH4 
concentration on a dry basis, moisture content.


Sec.  98.365  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions during unit operation or if a required fuel sample is not 
taken), a substitute data value for the missing parameter shall be used 
in the calculations, according to the requirements in paragraph (b) of 
this section.
    (b) For missing gas flow rates or CH4 content data, the 
substitute data value shall be the arithmetic average of the quality-
assured values of that parameter immediately preceding and immediately 
following the missing data incident. If, for a particular parameter, no 
quality-assured data are available prior to the missing data incident, 
the substitute data value shall be the first quality-assured value 
obtained after the missing data period.


Sec.  98.366  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information:

[[Page 56485]]

    (1) List of manure management system components at the facility.
    (2) Fraction of manure from each animal type that is handled in 
each manure management system component.
    (3) Average annual animal population (for each animal type) for 
static populations or the results of Equation JJ-4 for growing 
populations.
    (4) Average number of days that growing animals are kept at the 
facility (for each animal type).
    (5) The number of animals produced annually for growing populations 
(for each animal type).
    (6) Typical animal mass (for each animal type).
    (7) Total facility emissions (results of Equation JJ-15).
    (8) CH4 emissions from manure management system 
components listed in Sec.  98.360(b), except digesters (results of 
Equation JJ-2).
    (9) VS value used (for each animal type).
    (10) B0 value used (for each animal type).
    (11) Methane conversion factor used for each MMS component.
    (12) Average ambient temperature used to select each methane 
conversion factor.
    (13) N2O emissions (results of Equation JJ-13).
    (14) N value used for each animal type.
    (15) N2O emission factor selected for each MMS 
component.
    (b) Facilities with anaerobic digesters must also report:
    (1) CH4 emissions from anaerobic digesters (results of 
Equation JJ-5).
    (2) CH4 flow to the digester combustion device for each 
digester (results of Equation JJ-6, or value from fully integrated 
monitoring system as described in 98.363(b)).
    (3) CH4 destruction for each digester (results of 
Equation JJ-11).
    (4) CH4 leakage for each digester (results of Equation 
JJ-12).
    (5) Total annual volumetric biogas flow for each digester (results 
of Equation JJ-7).
    (6) Average annual CH4 concentration for each digester 
(results of Equation JJ-8).
    (7) Average annual temperature at which gas flow is measured for 
each digester (results of Equation JJ-9).
    (8) Average annual gas flow pressure at which gas flow is measured 
for each digester (results of Equation JJ-10).
    (9) Destruction efficiency used for each digester.
    (10) Number of days per year that each digester was operating.
    (11) Collection efficiency used for each digester.


Sec.  98.367  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the calibration records for all monitoring equipment, including 
the method or manufacturer's specification used for calibration.


Sec.  98.368  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

 Table JJ-1 to Subpart JJ of Part 98--Animal Population Threshold Level
    Below Which Facilities Are Not Required To Report Emissions Under
                             Subpart JJ 1,2
------------------------------------------------------------------------
                                                          Average annual
                                                              animal
                      Animal group                          population
                                                            (Head) \3\
------------------------------------------------------------------------
Beef....................................................          29,300
Dairy...................................................           3,200
Swine...................................................          34,100
Poultry:
    Layers..............................................         723,600
    Broilers............................................      38,160,000
    Turkeys.............................................       7,710,000
------------------------------------------------------------------------
\1\ The threshold head populations in this table were calculated using
  the most conservative assumptions (high VS and N values, maximum
  ambient temperatures, and the application of an uncertainty factor) to
  ensure that facilities at or near the 25,000 metric ton CO2e threshold
  level were not excluded from reporting.
\2\ For facilities with more than one animal group present refer to Sec.
    98.360 (2) to estimate the combined animal group factor (CAGF),
  which is used to determine if a facility may be required to report.
\3\ For all animal groups except dairy, the average annual animal
  population represents the total number of animals present at the
  facility. For dairy facilities, the average annual animal population
  represents the number of mature dairy cows present at the facility
  (note that heifers and calves were included in the emission estimates
  for dairy facilities using the assumption that the average annual
  animal population of heifers and calves at dairy facilities are equal
  to 30 percent of the mature dairy cow average annual animal
  population, therefore the average annual population for dairy
  facilities should not include heifers and calves, only dairy cows).


                         Table JJ-2 to Subpart JJ of Part 98--Waste Characteristics Data
----------------------------------------------------------------------------------------------------------------
                                                                                                      Maximum
                                                       Volatile solids                                methane
                                    Typical animal   excretion rate  (kg     Nitrogen excretion     generation
            Animal type               mass  (kg)    VS/day/1000 kg animal   rate  (kg N/day/1000   potential, Bo
                                                            mass)             kg animal mass)      (m\3\ CH4/kg
                                                                                                     VS added)
----------------------------------------------------------------------------------------------------------------
Dairy Cows........................             604  See Table JJ-3.......  See Table JJ-3.......            0.24
Dairy Heifers.....................             476  See Table JJ-3.......  See Table JJ-3.......            0.17
Dairy Calves......................             118  6.41.................  0.30.................            0.17
Feedlot Steers....................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Feedlot heifers...................             420  See Table JJ-3.......  See Table JJ-3.......            0.33
Market Swine <60 lbs..............              16  8.80.................  0.60.................            0.48
Market Swine 60-119 lbs...........              41  5.40.................  0.42.................            0.48
Market Swine 120-179 lbs..........              68  5.40.................  0.42.................            0.48
Market Swine >180 lbs.............              91  5.40.................  0.42.................            0.48
Breeding Swine....................             198  2.60.................  0.24.................            0.48

[[Page 56486]]

 
Feedlot Sheep.....................              25  9.20.................  0.42.................            0.36
Goats.............................              64  9.50.................  0.45.................            0.17
Horses............................             450  10.00................  0.30.................            0.33
Hens >/= 1 yr.....................             1.8  10.09................  0.83.................            0.39
Pullets...........................             1.8  10.09................  0.62.................            0.39
Other Chickens....................             1.8  10.80................  0.83.................            0.39
Broilers..........................             0.9  15.00................  1.10.................            0.36
Turkeys...........................             6.8  9.70.................  0.74.................            0.36
----------------------------------------------------------------------------------------------------------------


                  Table JJ-3 to Subpart JJ of Part 98--State-Specific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                  Volatile solids excretion rate (kg VS/day/  Nitrogen excretion rate (kg VS/day/1000 kg
                                                                             1000 kg animal mass)                            animal mass)
                              State                              ---------------------------------------------------------------------------------------
                                                                    Dairy      Dairy     Feedlot    Feedlot     Dairy      Dairy     Feedlot    Feedlot
                                                                     cows     heifers     steer     heifers      cows     heifers     steer     heifers
--------------------------------------------------------------------------------------------------------------------------------------------------------
Alabama.........................................................       8.40       8.35       4.27       4.74       0.50       0.46       0.36       0.38
Alaska..........................................................       7.30       8.35       4.15       4.58       0.45       0.46       0.35       0.37
Arizona.........................................................      10.37       8.35       3.91       4.27       0.58       0.46       0.33       0.34
Arkansas........................................................       7.59       8.35       3.98       4.35       0.46       0.46       0.33       0.35
California......................................................      10.02       8.35       3.96       4.33       0.56       0.46       0.33       0.34
Colorado........................................................      10.25       8.35       3.97       4.34       0.58       0.46       0.33       0.35
Connecticut.....................................................       9.22       8.35       4.41       4.93       0.53       0.46       0.37       0.40
Delaware........................................................       8.63       8.35       4.19       4.64       0.51       0.46       0.35       0.37
Florida.........................................................       8.90       8.35       4.15       4.58       0.52       0.46       0.35       0.37
Georgia.........................................................       9.07       8.35       4.18       4.63       0.53       0.46       0.35       0.37
Hawaii..........................................................       7.00       8.35       4.15       4.58       0.44       0.46       0.35       0.37
Idaho...........................................................      10.11       8.35       4.03       4.42       0.57       0.46       0.34       0.35
Illinois........................................................       9.07       8.35       4.15       4.59       0.52       0.46       0.35       0.37
Indiana.........................................................       9.38       8.35       3.98       4.35       0.54       0.46       0.33       0.35
Iowa............................................................       9.46       8.35       3.93       4.28       0.54       0.46       0.33       0.34
Kansas..........................................................       9.63       8.35       3.97       4.35       0.55       0.46       0.33       0.35
Kentucky........................................................       7.89       8.35       4.20       4.65       0.48       0.46       0.35       0.37
Louisiana.......................................................       7.39       8.35       4.07       4.48       0.45       0.46       0.34       0.36
Maine...........................................................       8.99       8.35       4.07       4.47       0.52       0.46       0.34       0.36
Maryland........................................................       9.02       8.35       4.05       4.45       0.52       0.46       0.34       0.35
Massachusetts...................................................       8.63       8.35       4.15       4.58       0.51       0.46       0.35       0.37
Michigan........................................................      10.05       8.35       4.00       4.38       0.57       0.46       0.34       0.35
Minnesota.......................................................       9.17       8.35       3.89       4.24       0.53       0.46       0.33       0.34
Mississippi.....................................................       8.19       8.35       4.14       4.57       0.49       0.46       0.35       0.37
Missouri........................................................       8.02       8.35       4.08       4.49       0.48       0.46       0.34       0.36
Montana.........................................................       9.03       8.35       4.23       4.69       0.52       0.46       0.36       0.38
Nebraska........................................................       9.09       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Nevada..........................................................       9.65       8.35       4.07       4.48       0.55       0.46       0.34       0.36
New Hampshire...................................................       9.44       8.35       3.94       4.30       0.54       0.46       0.33       0.34
New Jersey......................................................       8.51       8.35       3.98       4.36       0.50       0.46       0.33       0.35
New Mexico......................................................      10.34       8.35       3.88       4.22       0.58       0.46       0.32       0.33
New York........................................................       9.42       8.35       3.75       4.05       0.54       0.46       0.31       0.32
North Carolina..................................................       9.38       8.35       4.20       4.65       0.55       0.46       0.35       0.37
North Dakota....................................................       8.40       8.35       3.88       4.22       0.50       0.46       0.32       0.34
Ohio............................................................       9.01       8.35       3.96       4.33       0.52       0.46       0.33       0.34
Oklahoma........................................................       8.58       8.35       3.98       4.35       0.50       0.46       0.33       0.35
Oregon..........................................................       9.40       8.35       4.06       4.46       0.54       0.46       0.34       0.36
Pennsylvania....................................................       9.26       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Rhode Island....................................................       8.94       8.35       4.36       4.87       0.52       0.46       0.37       0.39
South Carolina..................................................       9.05       8.35       4.15       4.58       0.53       0.46       0.35       0.37
South Dakota....................................................       9.45       8.35       4.01       4.39       0.54       0.46       0.34       0.35
Tennessee.......................................................       8.60       8.35       4.48       5.02       0.51       0.46       0.38       0.40
Texas...........................................................       9.51       8.35       3.95       4.32       0.54       0.46       0.33       0.34
Utah............................................................       9.70       8.35       3.88       4.22       0.55       0.46       0.32       0.34
Vermont.........................................................       9.03       8.35       4.10       4.52       0.52       0.46       0.34       0.36
Virginia........................................................       9.02       8.35       3.98       4.35       0.53       0.46       0.33       0.35
Washington......................................................      10.36       8.35       4.07       4.47       0.58       0.46       0.34       0.36
West Virginia...................................................       8.13       8.35       4.65       5.25       0.48       0.46       0.40       0.42
Wisconsin.......................................................       9.34       8.35       3.95       4.31       0.54       0.46       0.33       0.34

[[Page 56487]]

 
Wyoming.........................................................       9.29       8.35       4.17       4.61       0.53       0.46       0.35       0.37
--------------------------------------------------------------------------------------------------------------------------------------------------------


    Table JJ-4 to Subpart JJ of Part 98--Volatile Solids and Nitrogen
                    Removal through Solids Separation
------------------------------------------------------------------------
                                    Volatile solids    Nitrogen removal
    Type of solids separation      removal (decimal)       (decimal)
------------------------------------------------------------------------
Gravity.........................                0.60                0.60
Mechanical:
    Stationary Screen...........                0.20                0.10
    Vibrating Screen............                0.15                0.15
    Screw Press.................                0.25                0.15
    Centrifuge..................                0.50                0.25
    Roller drum.................                0.25                0.15
    Belt press/screen...........                0.50                0.30
------------------------------------------------------------------------

BILLING CODE 6560-50-P

[[Page 56488]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.192

BILLING CODE 6560-50-C

[[Page 56489]]



     Table JJ-6 to Subpart JJ of Part 98--Collection Efficiencies of
                           Anaerobic Digesters
------------------------------------------------------------------------
                                                              Methane
      Anaerobic digester type            Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon (biogas    Bank to bank,                  0.975
 capture).                           impermeable.
                                    Modular, impermeable            0.70
Complete mix, fixed film, or plug   Enclosed Vessel.....            0.99
 flow digester.
------------------------------------------------------------------------


 Table JJ-7 to Subpart JJ of Part 98--Nitrous Oxide Emission Factors (kg
                            N2O-N/kg Kjdl N)
------------------------------------------------------------------------
                                                                 N2O
             Manure management system component                emission
                                                                factor
------------------------------------------------------------------------
Uncovered anaerobic lagoon.................................            0
Liquid/Slurry (with crust cover)...........................        0.005
Liquid/Slurry (without crust cover)........................            0
Storage pits...............................................        0.002
Digesters..................................................            0
Solid manure storage.......................................        0.005
Dry lots (including feedlots)..............................         0.02
High-rise house for poultry (poultry without litter).......        0.001
Poultry production with litter.............................        0.001
Deep bedding for cattle and swine (active mix).............         0.07
Deep bedding for cattle and swine (no mix).................         0.01
Manure Composting (in vessel)..............................        0.006
Manure Composting (intensive)..............................          0.1
Manure Composting (passive)................................         0.01
Manure Composting (static).................................        0.006
Aerobic Treatment (forced aeration)........................        0.005
Aerobic Treatment (natural aeration).......................         0.01
------------------------------------------------------------------------

Subpart KK--[Reserved]

Subpart LL--Suppliers of Coal-based Liquid Fuels


Sec.  98.380  Definition of the source category.

    This source category consists of producers, importers, and 
exporters of products listed in Table MM-1 of subpart MM that are coal-
based (coal-to-liquid products).
    (a) A producer is the owner or operator of a coal-to-liquids 
facility. A coal-to-liquids facility is any facility engaged in 
converting coal into liquid products using a process involving 
conversion of coal into gas and then into liquids (e.g., Fischer-
Tropsch) or conversion of coal directly into liquids (i.e., direct 
liquefaction).
    (b) An importer or exporter shall have the same meaning given in 
Sec.  98.6.


Sec.  98.381  Reporting threshold.

    Any supplier of coal-to-liquid products who meets the requirements 
of Sec.  98.2(a)(4) must report GHG emissions.


Sec.  98.382  GHGs to report.

    You must report the CO2 emissions that would result from 
the complete combustion or oxidation of fossil-fuel products (besides 
coal or crude oil) that you produce, use as feedstock, import, or 
export during the calendar year. Additionally, producers must report 
CO2 emissions that would result from the complete combustion 
or oxidation of any biomass co-processed with fossil fuel-based 
feedstocks.


Sec.  98.383  Calculating GHG emissions.

    You must follow the calculation methodologies of Sec.  98.393 as if 
they applied to the appropriate coal-to-liquid product supplier (i.e., 
calculation methodologies for refiners apply to producers of coal-to-
liquid products and calculation methodologies for importers and 
exporters of petroleum products apply to importers and exporters of 
coal-to-liquid products).
    (a) In calculation methodologies in Sec.  98.393 for petroleum 
products or petroleum-based products, suppliers of coal-to-liquid 
products shall also include coal-to-liquid products.
    (b) In calculation methodologies in Sec.  98.393 for non-crude 
feedstocks or non-crude petroleum feedstocks, producers of coal-to-
liquid products shall also include coal-to-liquid products that enter 
the facility to be further processed or otherwise used on site.
    (c) In calculation methodologies in Sec.  98.393 for petroleum 
feedstocks, suppliers of coal-to-liquid products shall also include 
coal and coal-to-liquid products that enter the facility to be further 
processed or otherwise used on site.


Sec.  98.384  Monitoring and QA/QC requirements.

    You must follow the monitoring and QA/QC requirements in Sec.  
98.394 as if they applied to the appropriate coal-to-liquid product 
supplier. Any monitoring and QA/QC requirement for petroleum products 
in Sec.  98.394 also applies to coal-to-liquid products.


Sec.  98.385  Procedures for estimating missing data.

    You must follow the procedures for estimating missing data in Sec.  
98.395 as if they applied to the appropriate coal-to-liquid product 
supplier. Any procedure for estimating missing data for petroleum 
products in Sec.  98.395 also applies to coal-to-liquid products.


Sec.  98.386  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), the 
following requirements apply:
    (a) Producers shall report the following information for each coal-
to-liquid facility:
    (1) For each product listed in Table MM-1 of subpart MM of this 
part that enters the coal-to-liquid facility to be further processed or 
otherwise used on site, report the annual quantity in metric tons or 
barrels by each quantity measurement standard method or other industry 
standard practice used. For natural gas liquids, quantity shall reflect 
the individual components of the product.
    (2) For each product listed in Table MM-1 of subpart MM of this 
part that enters the coal-to-liquid facility to be further processed or 
otherwise used on site, report the total annual quantity in metric tons 
or barrels. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) that was 
produced by blending a fossil fuel-based product with a biomass-based 
product, report the percent of the volume reported in paragraph (a)(2) 
of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(1) of this section.
    (5) For each product (leaving the coal-to-liquid facility) listed 
in Table MM-1 of subpart MM of this part, report the annual quantity in 
metric tons or barrels by each quantity measurement standard method or 
other industry standard practice used. For natural gas liquids, 
quantity shall reflect the individual components of the product.
    (6) For each product (leaving the coal-to-liquid facility) listed 
in Table MM-1 of subpart MM of this part, report the total annual 
quantity in metric tons or barrels. For natural gas liquids, quantity 
shall reflect the individual components of the product.
    (7) For each product reported in paragraph (a)(6) of this section 
that was produced by blending a fossil fuel-based

[[Page 56490]]

product with a biomass-based product, report the percent of the volume 
reported in paragraph (a)(6) of this section that is fossil fuel-based.
    (8) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(5) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this 
section for which Calculation Methodology 2 of subpart MM of this part 
was used to determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of 
this section for which Calculation Methodology 2 of subpart MM of this 
part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every product reported in paragraph (a)(6) of this section 
for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor.
    (12) For every non-solid product reported in paragraph (a)(6) of 
this section for which Calculation Methodology 2 of subpart MM of this 
part was used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) For each specific type of biomass that enters the coal-to-
liquid facility to be co-processed with fossil fuel-based feedstock to 
produce a product reported in paragraph (a)(6) of this section, report 
the annual quantity in metric tons or barrels by each quantity 
measurement standard method or other industry standard practice used.
    (14) For each specific type of biomass that enters the coal-to-
liquid facility to be co-processed with fossil fuel-based feedstock to 
produce a product reported in paragraph (a)(6) of this section, report 
the total annual quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(3) of this section.
    (16) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each feedstock reported in 
paragraph (a)(2) of this section, calculated according to Sec.  
98.393(b) or (h).
    (17) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each product (leaving the 
coal-to-liquid facility) reported in paragraph (a)(6) of this section, 
calculated according to Sec.  98.393(a) or (h).
    (18) Annual CO2 emissions in metric tons that would 
result from the complete combustion or oxidation of each type of 
biomass feedstock co-processed with fossil fuel-based feedstocks 
reported in paragraph (a)(3) of this section, calculated according to 
Sec.  98.393(c).
    (19) Annual CO2 emissions that would result from the 
complete combustion or oxidation of all products, calculated according 
to Sec.  98.393(d).
    (20) Annual quantity of bulk NGLs in metric tons or barrels 
received for processing during the reporting year.
    (b) In addition to the information required by Sec.  98.3(c), each 
importer shall report all of the following information at the corporate 
level:
    (1) For each product listed in Table MM-1 of subpart MM of this 
part, report the annual quantity in metric tons or barrels by each 
quantity measurement standard method or other industry standard 
practice used. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (2) For each product listed in Table MM-1 of subpart MM of this 
part, report the total annual quantity in metric tons or barrels. For 
natural gas liquids, quantity shall reflect the individual components 
of the product as listed in Table MM-1 of subpart MM of this part.
    (3) For each product reported in paragraph (b)(2) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (b)(2) of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (b)(1) of this section.
    (5) For each product reported in paragraph (b)(2) of this section 
for which Calculation Methodology 2 of this subpart used was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (6) For each non-solid product reported in paragraph (b)(2) of this 
section for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons ber barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each imported product 
reported in paragraph (b)(2) of this section, calculated according to 
Sec.  98.393(a).
    (8) The total sum of CO2 emissions that would result 
from the complete combustion or oxidation of all imported products, 
calculated according to Sec.  98.393(e).
    (c) In addition to the information required by Sec.  98.3(c), each 
exporter shall report all of the following information at the corporate 
level:
    (1) For each product listed in Table MM-1 of subpart MM of this 
part, report the annual quantity in metric tons or barrels by each 
quantity measurement standard method or other industry standard 
practice used. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (2) For each product listed in table MM-1 of subpart MM of this 
part, report the total annual quantity in metric tons or barrels. For 
natural gas liquids, quantity shall reflect the individual components 
of the product.
    (3) For each product reported in paragraph (c)(2) of this section 
that was produced by blending a fossil fuel-based product with a 
biomass-based product, report the percent of the volume reported in 
paragraph (c)(2) of this section that is fossil fuel-based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (c)(1) of this section.
    (5) For each product reported in paragraph (c)(2) of this section 
for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).

[[Page 56491]]

    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (6) For each non-solid product reported in paragraph (c)(2) of this 
section for which Calculation Methodology 2 of this subpart used was 
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each exported product 
reported in paragraph (c)(2) of this section, calculated according to 
Sec.  98.393(a).
    (8) Total sum of CO2 emissions that would result from 
the complete combustion or oxidation of all exported products, 
calculated according to Sec.  98.393(e).


Sec.  98.387  Records that must be retained.

    You must retain records according to the requirements in Sec.  
98.397 as if they applied to the appropriate coal-to-liquid product 
supplier (e.g., retaining copies of all reports submitted to EPA under 
Sec.  98.386 and records to support information contained in those 
reports). Any records for petroleum products that are required to be 
retained in Sec.  98.397 are also required for coal-to-liquid products.


Sec.  98.388  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart MM--Suppliers of Petroleum Products


Sec.  98.390  Definition of the source category.

    This source category consists of petroleum refineries and importers 
and exporters of petroleum products and natural gas liquids as listed 
in Table MM-1 of this subpart.
    (a) A petroleum refinery for the purpose of this subpart is any 
facility engaged in producing petroleum products through the 
distillation of crude oil.
    (b) A refiner is the owner or operator of a petroleum refinery.
    (c) Importer has the same meaning given in Sec.  98.6 and includes 
any entity that imports petroleum products or natural gas liquids as 
listed in Table MM-1 of this subpart. Any blender or refiner of refined 
or semi-refined petroleum products shall be considered an importer if 
it otherwise satisfies the aforementioned definition.
    (d) Exporter has the same meaning given in Sec.  98.6 and includes 
any entity that exports petroleum products or natural gas liquids as 
listed in Table MM-1 of this subpart. Any blender or refiner of refined 
or semi-refined petroleum products shall be considered an exporter if 
it otherwise satisfies the aforementioned definition.


Sec.  98.391  Reporting threshold.

    Any supplier of petroleum products who meets the requirements of 
Sec.  98.2(a)(4) must report GHG emissions.


Sec.  98.392  GHGs To report.

    Suppliers of petroleum products must report the CO2 
emissions that would result from the complete combustion or oxidation 
of each petroleum product and natural gas liquid produced, used as 
feedstock, imported, or exported during the calendar year. 
Additionally, refiners must report CO2 emissions that would 
result from the complete combustion or oxidation of any biomass co-
processed with petroleum feedstocks.


Sec.  98.393  Calculating GHG emissions.

    (a) Calculation for individual products produced, imported, or 
exported.
    (1) Except as provided in paragraph (h) of this section, any 
refiner, importer, or exporter shall calculate CO2 emissions 
from each individual petroleum product and natural gas liquid using 
Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.152

Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each petroleum product 
or natural gas liquid ``i'' (metric tons).
Producti = Annual volume of product ``i'' produced, 
imported, or exported by the reporting party (barrels). For 
refiners, this volume only includes products ex refinery gate. For 
natural gas liquids, volumes shall reflect the individual components 
of the product as listed in Table MM-1 of this subpart.
EFi = Product-specific CO2 emission factor 
(metric tons CO2 per barrel).

    (2) In the event that an individual petroleum product is 
produced as a solid rather than liquid any refiner, importer, or 
exporter shall calculate CO2 emissions using Equation MM-
1 of this section.

Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each petroleum product 
``i'' (metric tons).
Producti = Annual mass of product ``i'' produced, 
imported, or exported by the reporting party (metric tons). For 
refiners, this mass only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor 
(metric tons CO2 per metric ton of product).

    (b) Calculation for individual products that enter a refinery as a 
non-crude feedstock.
    (1) Except as provided in paragraph (h) of this section, any 
refiner shall calculate CO2 emissions from each non-crude 
feedstock using Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.153


Where:

CO2j = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each non-crude 
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of a petroleum product or 
natural gas liquid ``j'' that enters the refinery to be further 
refined or otherwise used on site (barrels). For natural gas 
liquids, volumes shall reflect the individual components of the 
product as listed in table MM-1 of this subpart.
EFj = Feedstock-specific CO2 emission factor 
(metric tons CO2 per barrel).

    (2) In the event that a non-crude feedstock enters a refinery as a 
solid rather than liquid, the refiner shall calculate CO2 
emissions using Equation MM-2 of this section.

Where:

CO2j = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each non-crude 
feedstock ``j'' (metric tons).
Feedstockj = Annual mass of a petroleum product ``j'' 
that enters the refinery to be further refined or otherwise used on 
site (metric tons).
EFj = Feedstock-specific CO2 emission factor 
(metric tons CO2 per metric ton of feedstock).

    (c) Calculation for biomass co-processed with petroleum feedstocks.
    (1) Refiners shall calculate CO2 emissions from each 
type of biomass that enters a refinery and is co-processed with 
petroleum feedstocks using Equation MM-3 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.154

Where:

CO2m = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each type of biomass 
``m'' (metric tons).
Biomassm = Annual volume of a specific type of biomass 
that enters the refinery and is co-processed with petroleum 
feedstocks to produce a petroleum product reported under paragraph 
(a) of this section (barrels).

[[Page 56492]]

EFm = Biomass-specific CO2 emission factor 
(metric tons CO2 per barrel).

    (2) In the event that biomass enters a refinery as a solid rather 
than liquid and is co-processed with petroleum feedstocks, the refiner 
shall calculate CO2 emissions from each type of biomass 
using Equation MM-3 of this section.

Where:

CO2m = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each type of biomass 
``m'' (metric tons).
Biomassm = Total annual mass of a specific type of 
biomass that enters the refinery to be co-processed with petroleum 
feedstocks to produce a petroleum product reported under paragraph 
(a) of this section (metric tons).
EFm = Biomass-specific CO2 emission factor 
(metric tons CO2 per metric ton of biomass).

    (d) Summary calculation for refinery products. Refiners shall 
calculate annual CO2 emissions from all products using 
Equation MM-4 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.155


Where:

CO2r = Annual CO2 emissions that would result 
from the complete combustion or oxidation of all petroleum products 
and natural gas liquids (ex refinery gate) minus non-crude 
feedstocks and any biomass to be co-processed with petroleum 
feedstocks.
CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each petroleum product 
or natural gas liquid ``i'' (metric tons).
CO2j = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each non-crude 
feedstock ``j'' (metric tons).
CO2m = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each type of biomass 
``m'' (metric tons).

    (e) Summary calculation for importer and exporter products. 
Importers and exporters shall calculate annual CO2 emissions 
from all petroleum products and natural gas liquids imported or 
exported, respectively, using Equations MM-1 and MM-5 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.156


Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each petroleum product 
or natural gas liquid ``i'' (metric tons).
CO2x = Annual CO2 emissions that would result 
from the complete combustion or oxidation of all petroleum products 
and natural gas liquids.

    (f) Emission factors for petroleum products and natural gas 
liquids. The emission factor (EFi,j) for each petroleum 
product and natural gas liquid shall be determined using either of the 
calculation methods described in paragraphs (f)(1) or (f)(2) of this 
section. The same calculation method must be used for the entire 
quantity of the product for the reporting year. For refiners, the 
quantity of a product that enters a refinery (i.e., a non-crude 
feedstock) is considered separate from the quantity of a product ex 
refinery gate.
    (1) Calculation Method 1. For solid products, use the default 
carbon share factor (i.e., percent carbon by mass) in column B of Table 
MM-1 of this subpart for the appropriate product. For all other 
products, use the default CO2 emission factor listed in 
column C of Table MM-1 of this subpart for the appropriate product.
    (2) Calculation Method 2.
    (i) For solid products, develop emission factors according to 
Equation MM-6 of this section using a value of 1 for density and direct 
measurements of carbon share according to methods set forth in Sec.  
98.394(c). For all other products, develop emission factors according 
to Equation MM-6 of this section using direct measurements of density 
and carbon share according to methods set forth in Sec.  98.394(c).
[GRAPHIC] [TIFF OMITTED] TR30OC09.157


Where:

EFi,j = Emission factor of the petroleum product or 
natural gas liquid (metric tons CO2 per barrel or per 
metric ton of product).
Density = Density of the petroleum product or natural gas liquid 
(metric tons per barrel for non-solid products, 1 for solid 
products).
Carbon share = Percent of total mass that carbon represents in the 
petroleum product or natural gas liquid, expressed as a fraction 
(e.g., 75% would be expressed as 0.75 in the above equation).
44/12 = Conversion factor for carbon to carbon dioxide.

    (ii) If you use a standard method that involves gas chromatography 
to determine the percent mass of each component in a product, calculate 
the product's carbon share using Equation MM-7 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.158


Where:

Carbon Share = Percent of total mass that carbon represents in the 
petroleum product or natural gas liquid.
%Composition i* * *n = Percent of total mass that each molecular 
component in the petroleum product or natural gas liquid represents 
as determined by the procedures in the selected standard method.
%Massi* * *n = Percent of total mass that carbon 
represents in each molecular component of the petroleum product or 
natural gas liquid.

    (g) Emission factors for biomass co-processed with petroleum 
feedstocks. Refiners shall use the most appropriate default 
CO2 emission factor (EFm) for biomass in Table 
MM-2 of this subpart to calculate CO2 emissions in paragraph 
(c) of this section.
    (h) Special procedures for blended biomass-based fuels. In the 
event that some portion of a petroleum product is biomass-based and was 
not derived by co-processing biomass and petroleum feedstocks together 
(i.e., the petroleum product was produced by blending a

[[Page 56493]]

petroleum-based product with a biomass-based fuel), the reporting party 
shall calculate emissions for the petroleum product according to one of 
the methods in paragraphs (h)(1) through (h)(4) of this section, as 
appropriate.
    (1) A reporter using Calculation Methodology 1 to determine the 
emission factor of a petroleum product shall calculate the 
CO2 emissions associated with that product using Equation 
MM-8 of this section in place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.159

Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each petroleum product 
``i'' (metric tons).
Producti = Annual volume of each petroleum product ``i'' 
produced, imported, or exported by the reporting party (barrels). 
For refiners, this volume only includes products ex refinery gate.
EFi = Petroleum product-specific CO2 emission 
factor (metric tons CO2 per barrel) from Table MM-1 of 
this subpart.
%Voli = Percent volume of product ``i'' that is 
petroleum-based, including 2.5% of the volume of any ethanol product 
blended into a petroleum-based product to represent the denaturant 
in that ethanol product, expressed as a fraction (e.g., 75% would be 
expressed as 0.75 in the above equation).

    (2) A refinery using Calculation Methodology 1 of this subpart to 
determine the emission factor of a non-crude petroleum feedstock shall 
calculate the CO2 emissions associated with that feedstock 
using Equation MM-9 of this section in place of Equation MM-2 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.160

Where:

CO2j = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each non-crude 
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product 
``j'' that enters the refinery as a feedstock to be further refined 
or otherwise used on site (barrels).
EFj = Non-crude petroleum feedstock-specific 
CO2 emission factor (metric tons CO2 per 
barrel).
%Volj = Percent volume of feedstock ``j'' that is 
petroleum-based, including 2.5% of the volume of any ethanol product 
blended with the petroleum-based product to represent the denaturant 
in that ethanol product, expressed as a fraction (e.g., 75% would be 
expressed as 0.75 in the above equation).

    (3) A reporter using Calculation Methodology 2 of this subpart to 
determine the emission factor of a petroleum product must calculate the 
CO2 emissions associated with that product using Equation 
MM-10 of this section in place of Equation MM-1 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.161

Where:

CO2i = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each product ``i'' 
(metric tons).
Producti = Annual volume of each petroleum product ``i'' 
produced, imported, or exported by the reporting party (barrels). 
For refiners, this volume only includes products ex refinery gate.
EFi = Product-specific CO2 emission factor 
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table 
MM-2 of this subpart that most closely represents the component of 
product ``i'' that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is 
biomass-based, not including 2.5% of the volume of any ethanol 
product blended with the petroleum-based product, which represents 
the denaturant in that ethanol product, expressed as a fraction 
(e.g., 75% would be expressed as 0.75 in the above equation).

    (4) A refiner using Calculation Methodology 2 of this subpart to 
determine the emission factor of a non-crude petroleum feedstock must 
calculate the CO2 emissions associated with that feedstock 
using Equation MM-11 of this section in place of Equation MM-2 of this 
section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.162

Where:

CO2j = Annual CO2 emissions that would result 
from the complete combustion or oxidation of each non-crude 
feedstock ``j'' (metric tons).
Feedstockj = Annual volume of each petroleum product 
``j'' that enters the refinery to be further refined or otherwise 
used on site (barrels).
EFj = Feedstock-specific CO2 emission factor 
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table 
MM-2 of this subpart that most closely represents the component of 
petroleum product ``j'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that 
is biomass-based, not including 2.5% of the volume of any ethanol 
product blended with the petroleum-based product, which represents 
the denaturant in that ethanol product, expressed as a fraction 
(e.g., 75% would be expressed as 0.75 in the above equation).

Sec.  98.394  Monitoring and QA/QC requirements.

    (a) Determination of quantity.
    (1) The quantity of petroleum products, natural gas liquids, 
biomass, and crude oil shall be determined as follows:
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used. 
Consensus-based

[[Page 56494]]

standards organizations include, but are not limited to, the following: 
ASTM International, the American National Standards Institute (ANSI), 
the American Gas Association (AGA), the American Society of Mechanical 
Engineers (ASME), the American Petroleum Institute (API), and the North 
American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall 
be followed.
    (iii) For products that are liquid at 60 degrees Fahrenheit and one 
standard atmosphere, all measurements of quantity shall be temperature-
adjusted and pressure-adjusted to these conditions. For all other 
products, reporters shall use appropriate standard conditions specified 
in the standard method; if temperature and pressure conditions are not 
specified in the standard method or if a reporter uses an industry 
standard practice to determine quantity, the reporter shall use 
appropriate standard conditions according to established industry 
practices.
    (2) All measurement equipment (including, but not limited to, flow 
meters and tank gauges) used for compliance with this subpart shall be 
appropriate for the standard method or industry standard practice 
followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.
    (b) Equipment Calibration.
    (1) All measurement equipment shall be calibrated prior to its 
first use for reporting under this subpart, using an appropriate 
standard method published by a consensus based standards organization 
or according to the equipment manufacturer's directions.
    (2) Measurement equipment shall be recalibrated at the minimum 
frequency specified by the standard method used or by the equipment 
manufacturer's directions.
    (c) Procedures for Calculation Methodology 2 of this subpart.
    (1) Reporting parties shall collect one sample of each petroleum 
product or natural gas liquid on any day of each calendar month of the 
reporting year in which the quantity of that product was measured in 
accordance with the requirements of this subpart. For example, if a 
given product was measured as entering the refinery continuously 
throughout the reporting year, twelve samples of that product shall be 
collected over the reporting year, one on any day of each calendar 
month of that year. If a given product was only measured from April 15 
through June 10 of the reporting year, a refiner would collect three 
samples during that year, one during each of the calendar months of 
April, May and June on a day when the product was measured as either 
entering or exiting the refinery. Each sample shall be collected using 
an appropriate standard method published by a consensus-based standards 
organization.
    (2) Mixing and handling of samples shall be performed using an 
appropriate standard method published by a consensus-based standards 
organization.
    (3) Density measurement.
    (i) For all products that are not solid, reporters shall test for 
density using an appropriate standard method published by a consensus-
based standards organization.
    (ii) The density value for a given petroleum product shall be 
generated by either making a physical composite of all of the samples 
collected for the reporting year and testing that single sample or by 
measuring the individual samples throughout the year and defining the 
representative density value for the sample set by numerical means, 
i.e., a mathematical composite. If a physical composite is chosen as 
the option to obtain the density value, the reporter shall submit each 
of the individual samples collected during the reporting year to the 
laboratory responsible for generating the composite sample.
    (iii) For physical composites, the reporter shall handle the 
individual samples and the laboratory shall mix them in accordance with 
an appropriate standard method published by a consensus-based standards 
organization.
    (iv) All measurements of density shall be temperature-adjusted and 
pressure-adjusted to the conditions assumed for determining the 
quantities of the product reported under this subpart.
    (4) Carbon share measurement.
    (i) Reporters shall test for carbon share using an appropriate 
standard method published by a consensus-based standards organization.
    (ii) If a standard method that involves gas chromatography is used 
to determine the percent mass of each component in a product, the 
molecular formula for each component shall be obtained from the 
information provided in the standard method and the atomic mass of each 
element in a given molecular component shall be obtained from the 
periodic table of the elements.
    (iii) The carbon share value for a given petroleum product shall be 
generated by either making a physical composite of all of the samples 
collected for the reporting year and testing that single sample or by 
measuring the individual samples throughout the year and defining the 
representative carbon share value for the sample set by numerical 
means, i.e., a mathematical composite. If a physical composite is 
chosen as the option to obtain the carbon share value, the reporter 
shall submit each of the individual samples collected during the 
reporting year to the laboratory responsible for generating the 
composite sample.
    (iv) For physical composites, the reporter shall handle the 
individual samples and the laboratory shall mix them in accordance with 
an appropriate standard method published by a consensus-based standards 
organization.
    (d) Measurement of API gravity and sulfur content of crude oil.
    (1) Samples of each batch of crude oil shall be taken according to 
an appropriate standard method published by a consensus-based standards 
organization.
    (2) Samples shall be handled according to an appropriate standard 
method published by a consensus-based standards organization.
    (3) API gravity shall be measured using an appropriate standard 
method published by a consensus-based standards organization.
    (4) Sulfur content shall be measured using an appropriate standard 
method published by a consensus-based standards organization.
    (5) All measurements shall be temperature-adjusted and pressure-
adjusted to the conditions assumed for determining the quantities of 
crude oil reported under this subpart.


Sec.  98.395  Procedures for estimating missing data.

    (a) Determination of quantity. Whenever the quality assurance 
procedures in Sec.  98.394(a) cannot be followed to measure the 
quantity of one or more petroleum products, natural gas liquids, types 
of biomass, feedstocks, or crude oil batches during any period (e.g., 
if a meter malfunctions), the following missing data procedures shall 
be used:
    (1) For quantities of a product that are purchased or sold, a 
period of missing data shall be substituted using a reporter's 
established procedures for billing purposes in that period as agreed to 
by the party selling or purchasing the product.
    (2) For quantities of a product that are not purchased or sold but 
of which the custody is transferred, a period of missing data shall be 
substituted using a reporter's established procedures for tracking 
purposes in that period as agreed to by the party involved in custody 
transfer of the product.

[[Page 56495]]

    (b) Determination of emission factor. Whenever any of the 
procedures in Sec.  98.394(c) cannot be followed to develop an emission 
factor for any reason, Calculation Methodology 1 of this subpart must 
be used in place of Calculation Methodology 2 of this subpart for the 
entire reporting year.
    (c) Determination of API gravity and sulfur content of crude oil. 
For missing data on sulfur content or API gravity, the substitute data 
value shall be the arithmetic average of the quality-assured values of 
API gravity or sulfur content in the batch preceding and the batch 
immediately following the missing data incident. If no quality-assured 
data are available prior to the missing data incident, the substitute 
data value shall be the first quality-assured values for API gravity 
and sulfur content obtained from the batch after the missing data 
period.


Sec.  98.396  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), the 
following requirements apply:
    (a) Refiners shall report the following information for each 
facility:
    (1) For each petroleum product or natural gas liquid listed in 
table MM-1 of this subpart that enters the refinery to be further 
refined or otherwise used on site, report the annual quantity in metric 
tons or barrels by each quantity measurement standard method or other 
industry standard practice used. For natural gas liquids, quantity 
shall reflect the individual components of the product.
    (2) For each petroleum product or natural gas liquid listed in 
Table MM-1 of this subpart that enters the refinery to be further 
refined or otherwise used on site, report the annual quantity in metric 
tons or barrels. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (3) For each feedstock reported in paragraph (a)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(a)(2) of this section that is petroleum-based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(1) of this section.
    (5) For each petroleum product and natural gas liquid (ex refinery 
gate) listed in Table MM-1 of this subpart, report the annual quantity 
in metric tons or barrels by each quantity measurement standard method 
or other industry standard practice used. For natural gas liquids, 
quantity shall reflect the individual components of the product.
    (6) For each petroleum product and natural gas liquid (ex refinery 
gate) listed in Table MM-1 of this subpart, report the annual quantity 
in metric tons or barrels. For natural gas liquids, quantity shall 
reflect the individual components of the product.
    (7) For each product reported in paragraph (a)(6) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(a)(6) of this section that is petroleum-based.
    (8) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(5) of this section.
    (9) For every feedstock reported in paragraph (a)(2) of this 
section for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c)
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons.
    (10) For every non-solid feedstock reported in paragraph (a)(2) of 
this section for which Calculation Methodology 2 of this subpart was 
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (11) For every petroleum product and natural gas liquid reported in 
paragraph (a)(6) of this section for which Calculation Methodology 2 of 
this subpart was used to determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (12) For every non-solid petroleum product and natural gas liquid 
reported in paragraph (a)(6) for which Calculation Method 2 was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (13) For each specific type of biomass that enters the refinery to 
be co-processed with petroleum feedstocks to produce a petroleum 
product reported in paragraph (a)(6) of this section, report the annual 
quantity in metric tons or barrels by each quantity measurement 
standard method or other industry standard practice used.
    (14) For each specific type of biomass that enters the refinery to 
be co-processed with petroleum feedstocks to produce a petroleum 
product reported in paragraph (a)(6) of this section, report the annual 
quantity in metric tons or barrels.
    (15) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (a)(13) of this section.
    (16) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each petroleum product and 
natural gas liquid (ex refinery gate) reported in paragraph (a)(6) of 
this section, calculated according to Sec.  98.393(a) or (h).
    (17) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each feedstock reported in 
paragraph (a)(2) of this section, calculated according to Sec.  
98.393(b) or (h).
    (18) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each type of biomass 
feedstock co-processed with petroleum feedstocks reported in paragraph 
(a)(13) of this section, calculated according to Sec.  98.393(c).
    (19) The sum of CO2 emissions that would result from the 
complete combustion or oxidation of all products, calculated according 
to Sec.  98.393(d).
    (20) All of the following information for all crude oil feedstocks 
used at the refinery:
    (i) Batch volume in barrels.
    (ii) API gravity of the batch at the point of entry at the 
refinery.
    (iii) Sulfur content of the batch at the point of entry at the 
refinery.
    (iv) Country of origin of the batch, if known.
    (21) The quantity of bulk NGLs in metric tons or barrels received 
for processing during the reporting year.
    (b) In addition to the information required by Sec.  98.3(c), each 
importer shall report all of the following information at the corporate 
level:
    (1) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons 
or barrels by each quantity measurement standard method or other 
industry standard practice used. For natural gas liquids,

[[Page 56496]]

quantity shall reflect the individual components of the product.
    (2) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons 
or barrels. For natural gas liquids, quantity shall reflect the 
individual components of the product as listed in Table MM-1 of this 
subpart.
    (3) For each product reported in paragraph (b)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(b)(2) of this section that is petroleum-based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (b)(1) of this section.
    (5) For each product reported in paragraph (b)(2) of this section 
for which Calculation Methodology 2 of this subpart used was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percent mass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (b)(2) of this 
section for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of each imported petroleum 
product and natural gas liquid reported in paragraph (b)(2) of this 
section, calculated according to Sec.  98.393(a).
    (8) The sum of CO2 emissions that would result from the 
complete combustion oxidation of all imported products, calculated 
according to Sec.  98.393(e).
    (c) In addition to the information required by Sec.  98.3(c), each 
exporter shall report all of the following information at the corporate 
level:
    (1) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons 
or barrels by each quantity measurement standard method or other 
industry standard practice used. For natural gas liquids, quantity 
shall reflect the individual components of the product.
    (2) For each petroleum product and natural gas liquid listed in 
Table MM-1 of this subpart, report the annual quantity in metric tons 
or barrels. For natural gas liquids, quantity shall reflect the 
individual components of the product.
    (3) For each product reported in paragraph (c)(2) of this section 
that was produced by blending a petroleum-based product with a biomass-
based product, report the percent of the volume reported in paragraph 
(c)(2) of this section that is petroleum based.
    (4) Each standard method or other industry standard practice used 
to measure each quantity reported in paragraph (c)(1) of this section.
    (5) For each product reported in paragraph (c)(2) of this section 
for which Calculation Methodology 2 of this subpart was used to 
determine an emissions factor, report:
    (i) The number of samples collected according to Sec.  98.394(c).
    (ii) The sampling standard method used.
    (iii) The carbon share test results in percentmass.
    (iv) The standard method used to test carbon share.
    (v) The calculated CO2 emissions factor in metric tons 
CO2 per barrel or per metric ton of product.
    (6) For each non-solid product reported in paragraph (c)(2) of this 
section for which Calculation Methodology 2 of this subpart used was 
used to determine an emissions factor, report:
    (i) The density test results in metric tons per barrel.
    (ii) The standard method used to test density.
    (7) The CO2 emissions in metric tons that would result 
from the complete combustion or oxidation of for each exported 
petroleum product and natural gas liquid reported in paragraph (c)(2) 
of this section, calculated according to Sec.  98.393(a).
    (8) The sum of CO2 emissions that would result from the 
complete combustion or oxidation of all exported products, calculated 
according to Sec.  98.393(e).


Sec.  98.397  Records that must be retained.

    (a) All reporters shall retain copies of all reports submitted to 
EPA under Sec.  98.396. In addition, all reporters shall maintain 
sufficient records to support information contained in those reports, 
including but not limited to information on the characteristics of 
their feedstocks and products.
    (b) Reporters shall maintain records to support quantities that are 
reported under this subpart, including records documenting any 
estimations of missing data and the number of calendar days in the 
reporting year for which substitute data procedures were followed. For 
all quantities of petroleum products, natural gas liquids, biomass, and 
feedstocks, reporters shall maintain metering, guaging, and other 
records normally maintained in the course of business to document 
product and feedstock flows including the date of initial calibration 
and the frequency of recalibration for the measurement equipment used
    (c) Reporters shall retain laboratory reports, calculations and 
worksheets used to estimate the CO2 emissions of the 
quantities of petroleum products, natural gas liquids, biomass, and 
feedstocks reported under this subpart.
    (d) Reporters shall maintain laboratory reports, calculations and 
worksheets used in the measurement of density and carbon share for any 
petroleum product or natural gas liquid for which CO2 
emissions were calculated using Calculation Methodology 2.
    (e) Reporters shall maintain laboratory reports, calculations and 
worksheets used in the measurement of API gravity and sulfur content 
for every crude oil batch reported under this subpart.
    (f) Estimates of missing data shall be documented and records 
maintained showing the calculations.
    (g) Reporters described in this subpart shall also retain all 
records described in Sec.  98.3(g).


Sec.  98.398  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

[[Page 56497]]



   Table MM-1 to Subpart MM of Part 98--Default Factors for Petroleum
                  Products and Natural Gas Liquids 1 2
------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     emission
                                     density       carbon       factor
             Products                (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Finished Motor Gasoline
------------------------------------------------------------------------
Conventional--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
Conventional--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
Reformulated--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670
Reformulated--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Gasoline--Other..................       0.1185        86.61       0.3763
------------------------------------------------------------------------
Blendstocks
------------------------------------------------------------------------
CBOB--Summer
    Regular......................       0.1181        86.66       0.3753
    Midgrade.....................       0.1183        86.63       0.3758
    Premium......................       0.1185        86.61       0.3763
CBOB--Winter
    Regular......................       0.1155        86.50       0.3663
    Midgrade.....................       0.1161        86.55       0.3684
    Premium......................       0.1167        86.59       0.3705
RBOB--Summer
    Regular......................       0.1167        86.13       0.3686
    Midgrade.....................       0.1165        86.07       0.3677
    Premium......................       0.1164        86.00       0.3670
RBOB--Winter
    Regular......................       0.1165        86.05       0.3676
    Midgrade.....................       0.1165        86.06       0.3676
    Premium......................       0.1166        86.06       0.3679
Blendstocks--Other...............       0.1185        86.61       0.3763
------------------------------------------------------------------------
Oxygenates
------------------------------------------------------------------------
Methanol.........................       0.1268        37.48       0.1743
GTBA.............................       0.1257        64.82       0.2988
MTBE.............................       0.1181        68.13       0.2950
ETBE.............................       0.1182        70.53       0.3057
TAME.............................       0.1229        70.53       0.3178
DIPE.............................       0.1156        70.53       0.2990
------------------------------------------------------------------------
Distillate Fuel Oil
------------------------------------------------------------------------
Distillate No. 1
    Ultra Low Sulfur.............       0.1346        86.40       0.4264
    Low Sulfur...................       0.1346        86.40       0.4264
    High Sulfur..................       0.1346        86.40       0.4264
Distillate No. 2
    Ultra Low Sulfur.............       0.1342        87.30       0.4296
    Low Sulfur...................       0.1342        87.30       0.4296
    High Sulfur..................       0.1342        87.30       0.4296
Distillate Fuel Oil No. 4........       0.1452        86.47       0.4604
Residual Fuel Oil No. 5 (Navy           0.1365        85.67       0.4288
 Special)........................
Residual Fuel Oil No. 6 (a.k.a.         0.1528        84.67       0.4744
 Bunker C).......................
Kerosene-Type Jet Fuel...........       0.1294        86.30       0.4095
Kerosene.........................       0.1346        86.40       0.4264
Diesel--Other....................       0.1452        86.47       0.4604
------------------------------------------------------------------------
Petrochemical Feedstocks
------------------------------------------------------------------------

[[Page 56498]]

 
    Naphthas (< 401 [deg]F)......       0.1158        84.11       0.3571
    Other Oils (> 401 [deg]F)....       0.1390        87.30       0.4450
------------------------------------------------------------------------
Unfinished Oils
------------------------------------------------------------------------
Heavy Gas Oils...................       0.1476        85.80       0.4643
Residuum.........................       0.1622        85.70       0.5097
------------------------------------------------------------------------
Other Petroleum Products and Natural Gas Liquids
------------------------------------------------------------------------
Aviation Gasoline................       0.1120        85.00       0.3490
Special Naphthas.................       0.1222        84.76       0.3798
Lubricants.......................       0.1428        85.80       0.4492
Waxes............................       0.1285        85.30       0.4019
Petroleum Coke...................       0.1818        92.28       0.6151
Asphalt and Road Oil.............       0.1634        83.47       0.5001
Still Gas........................       0.1405        77.70       0.4003
Ethane...........................       0.0866        79.89       0.2537
Ethylene.........................       0.0903        85.63       0.2835
Propane..........................       0.0784        81.71       0.2349
Propylene........................       0.0803        85.63       0.2521
Butane...........................       0.0911        82.66       0.2761
Butylene.........................       0.0935        85.63       0.2936
Isobutane........................       0.0876        82.66       0.2655
Isobutylene......................       0.0936        85.63       0.2939
Pentanes Plus....................       0.1055        83.63       0.3235
Miscellaneous Products...........       0.1380        85.49       0.4326
------------------------------------------------------------------------
\1\ In the case of products blended with some portion of biomass-based
  fuel, the carbon share in Table MM-1 of this subpart represents only
  the petroleum-based components.
\2\ Products that are derived entirely from biomass should not be
  reported, but products that were derived from both biomass and a
  petroleum product (i.e., co-processed) should be reported as the
  petroleum product that it most closely represents.


 Table MM-2 to Subpart MM of Part 98--Default Factors for Biomass-Based
                            Fuels and Biomass
------------------------------------------------------------------------
                                                              Column C:
                                    Column A:    Column B:     Emission
                                     Density       Carbon       factor
  Biomass-based fuel and biomass     (metric    share (% of    (metric
                                    tons/bbl)      mass)      tons CO2/
                                                                 bbl)
------------------------------------------------------------------------
Ethanol (100%)...................       0.1267        52.14       0.2422
Biodiesel (100%, methyl ester)...       0.1396        77.30       0.3957
Rendered Animal Fat..............       0.1333        76.19       0.3724
Vegetable Oil....................       0.1460        76.77       0.4110
------------------------------------------------------------------------

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


Sec.  98.400  Definition of the source category.

    This supplier category consists of natural gas liquids 
fractionators and local natural gas distribution companies.
    (a) Natural gas liquids fractionators are installations that 
fractionate natural gas liquids (NGLs) into their consitutent liquid 
products (ethane, propane, normal butane, isobutane or pentanes plus) 
for supply to downstream facilities.
    (b) Local Distribution Companies (LDCs) are companies that own or 
operate distribution pipelines, not interstate pipelines or intrastate 
pipelines, that physically deliver natural gas to end users and that 
are regulated as separate operating companies by State public utility 
commissions or that operate as independent municipally-owned 
distribution systems.
    (c) This supply category does not consist of the following 
facilities:
    (1) Field gathering and boosting stations.
    (2) Natural gas processing plants that separate NGLs from natural 
gas and produce bulk or y-grade NGLs but do not fractionate these NGLs 
into their constituent products.
    (3) Facilities that meet the definition of refineries and report 
under subpart MM of this part.
    (4) Facilities that meet the definition of petrochemical plants and 
report under subpart X of this part.


Sec.  98.401  Reporting threshold.

    Any supplier of natural gas and natural gas liquids that meets the 
requirements of Sec.  98.2(a)(4) must report GHG emissions.


Sec.  98.402  GHGs to report.

    (a) NGL fractionators must report the CO2 emissions that 
would result from the complete combustion or oxidation of the annual 
quantity of ethane, propane, normal butane, isobutane, and pentanes

[[Page 56499]]

plus that is produced and sold or delivered to others.
    (b) LDCs must report the CO2 emissions that would result 
from the complete combustion or oxidation of the annual volumes of 
natural gas provided to end-users on their distribution systems.


Sec.  98.403  Calculating GHG emissions.

    (a) LDCs and fractionators shall, for each individual product 
reported under this part, calculate the estimated CO2 
emissions that would result from the complete combustion or oxidation 
of the products supplied using either of Calculation Methodology 1 or 2 
of this subpart:
    (1) Calculation Methodology 1. NGL fractionators shall estimate 
CO2 emissions that would result from the complete combustion 
or oxidation of the product(s) supplied using Equation NN-1 of this 
section. LDCs shall estimate CO2 emissions that would result 
from the complete combustion or oxidation of the product received at 
the city gate using Equation NN-1. For each product, use the default 
value for higher heating value and CO2 emission factor in 
Table NN-1 of this subpart. Alternatively, for each product, a 
reporter-specific higher heating value and CO2 emission 
factor may be used, in place of one or both defaults provided they are 
developed using methods outlined in Sec.  98.404. For each product, you 
must use the same volume unit throughout the equation.
[GRAPHIC] [TIFF OMITTED] TR30OC09.163

Where:

CO2i = Annual CO2 mass emissions that would 
result from the combustion or oxidation of each product ``h'' for 
redelivery to all recipients (metric tons).
Fuel = Total annual volume of product ``h'' supplied (volume per 
year, in Mscf for natural gas and bbl for NGLs).
HHV = Higher heating value of product ``h'' supplied (MMBtu/Mscf or 
MMBtu/bbl).
EFh = CO2 emission factor of product ``h'' (kg 
CO2/MMBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons (MT/kg).

    (2) Calculation Methodology 2. NGL fractionators shall estimate 
CO2 emissions that would result from the complete combustion 
or oxidation of the product(s) supplied using Equation NN-2 of this 
section. LDCs shall estimate CO2 emissions that would result 
from the complete combustion or oxidation of the product received at 
the city gate using Equation NN-2. For each product, use the default 
CO2 emission factor found in Table NN-2 of this subpart. 
Alternatively, for each product, a reporter-specific CO2 
emission factor may be used in place of the default factor, provided it 
is developed using methods outlined in Sec.  98.404. For each product, 
you must use the same volume unit throughout the equation.

[GRAPHIC] [TIFF OMITTED] TR30OC09.164

Where:

CO2i = Annual CO2 mass emissions that would 
result from the combustion or oxidation of each product ``h'' 
(metric tons)
Fuel = Total annual volume of product ``h'' supplied (bbl or Mscf 
per year)
EFh = CO2 emission factor of product ``h'' (MT 
CO2/bbl, or MT CO2/Mscf)

    (b) Each LDC shall follow the procedures below.
    (1) For natural gas that is received for redelivery to downstream 
gas transmission pipelines and other local distribution companies, use 
eEquation NN-3 of this section and the default values for the 
CO2 emission factors found in Table NN-2 of this subpart. 
Alternatively, reporter-specific CO2 emission factors may be 
used, provided they are developed using methods outlined in Sec.  
98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.165

Where:

CO2j = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas for 
redelivery to transmission pipelines or other LDCs (metric tons).
Fuel = Total annual volume of natural gas supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT 
CO2/Mscf).

    (2)(i) For natural gas delivered to each meter registering a supply 
equal to or greater than 460,000 Mscf per year, use Equation NN-4 of 
this section and the default values for the CO2 emission 
factors found in Table NN-2 of this subpart.
    (ii) Alternatively, reporter-specific CO2 emission 
factors may be used, provided they are developed using methods outlined 
in Sec.  98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.166

Where:

CO2k = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas received by 
end-users that receive a supply equal to or greater than 460,000 
Mscf per year (metric tons).
Fuel = Total annual volume of natural gas supplied (Mscf per year).
EF = Fuel-specific CO2 emission factor (MT 
CO2/Mscf).

    (3) For natural gas received by the LDC at the city gate that is 
injected into on-system storage, and/or liquefied and stored, use 
Equation NN-5 of this section and the default value for the 
CO2 emission factors found in Table NN-2 of this subpart. 
Alternatively, a reporter-specific CO2 emission factor may 
be used, provided it is developed using methods outlined in Sec.  
98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.167

Where:

CO2l = Annual CO2 mass emissions that would 
result from the combustion or oxidation of the net natural gas that 
is liquefied and/or stored and not used for deliveries by the LDC 
within the reported year (metric tons).
Fuel1 = Total annual volume of natural gas received by 
the LDC at the city gate and stored on-system or liquefied and 
stored in the reportng year (Mscf per year).
Fuel2 = Total annual volume of natural gas that is used 
for deliveries in the reporting year that was not otherwise 
accounted for in Equation NN-1 or NN-2 of this section (Mscf per 
year). This primarily includes natural gas previously stored on-
system or liquefied and stored that is removed from storage and used 
for deliveries to customers or other LDCs by the LDC within the 
reporting year. This also includes natural gas that bypassed the 
city gate and was delivered directly to LDC systems from producers 
or natural gas processing plants from local production.
EF = Fuel-specific CO2 emission factor (MT 
CO2/Mscf).


[[Page 56500]]


    (4) Calculate the total CO2 emissions that would result 
from the complete combustion or oxidation of the annual supply of 
natural gas to end-users using Equation NN-6 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.168

Where:

CO2 = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas delivered to 
LDC customers not covered in paragraph (b)(2) of this section 
(metric tons).
CO2i = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas received at 
the city gate as calculated in paragraph (a)(1) or (a)(2) of this 
section (metric tons).
CO2j = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas delivered to 
transmission pipelines or other LDCs as calculated in paragraph 
(b)(1) of this section (metric tons).
CO2k = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas received by 
end-users that receive a supply equal to or greater than 460,000 
Mscf per year as calculated in paragraph (b)(2) of this section 
(metric tons).
CO2l = Annual CO2 mass emissions that would 
result from the combustion or oxidation of natural gas received by 
the LDC and liquefied and/or stored but not used for deliveries 
within the reported year as calculated in paragraph (b)(3) of this 
section (metric tons).

    (c) Each NGL fractionator shall follow the following procedures.
    (1)(i) For fractionated NGLs received by the reporter from other 
NGL fractionators, you shall use Equation NN-7 of this section and the 
default values for the CO2 emission factors found in Table 
NN-2 of this subpart.
    (ii) Alternatively, reporter-specific CO2 emission 
factors may be used, provided they are developed using methods outlined 
in Sec.  98.404.
[GRAPHIC] [TIFF OMITTED] TR30OC09.169

Where:

CO2m = Annual CO2 mass emissions that would 
result from the combustion or oxidation of each fractionated NGL 
product ``g'' received from other fractionators (metric tons).
Fuelg = Total annual volume of each NGL product ``g'' 
received (bbls).
EF = Fuel-specific CO2 emission factor (MT 
CO2/bbl).

    (2) Calculate the total CO2 equivalent emissions that 
would result from the combustion or oxidation of fractionated NGLs 
supplied less the quantity received by other fractionators using 
Equation NN-8 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.170

Where:

CO2 = Annual CO2 mass emissions that would 
result from the combustion or oxidation of fractionated NGLs 
delivered to customers or on behalf of customers (metric tons).
CO2i = Annual CO2 mass emissions that would 
result from the combustion or oxidation of fractionated NGLs 
delivered to all customers as calculated in paragraph (a)(1) or 
(a)(2) of this section (metric tons).
CO2m = Annual CO2 mass emissions that would 
result from the combustion or oxidation of fractionated NGLs 
received from other fractionators and calculated in paragraph (c)(1) 
of this section (metric tons).

Sec.  98.404  Monitoring and QA/QC requirements.

    (a) Determination of quantity.
    (1) NGL fractionators and LDCs shall determine the quantity of NGLs 
and natural gas using methods in common use in the industry for billing 
purposes as audited under existing Sarbanes Oxley regulationn.
    (i) Where an appropriate standard method published by a consensus-
based standards organization exists, such a method shall be used. 
Consensus-based standards organizations include, but are not limited 
to, the following: ASTM International, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, industry standard practices shall 
be followed.
    (2) NGL fractionators and LDCs shall base the minimum frequency of 
the product quantity measurements, to be summed to the annual quantity 
reported, on the reporter's standard practices for commercial 
operations.
    (i) For NGL fractionators the minimum frequency of measurements 
shall be the measurements taken at custody transfers summed to the 
annual reportable volume.
    (ii) For natural gas the minimum frequency of measurement shall be 
based on the LDC's standard measurement schedules used for billing 
purposes and summed to the annual reportable volume.
    (3) NGL fractionators shall use measurement for NGLs at custody 
tranfer meters or at such meters that are used to determine the NGL 
product slate delivered from the fractionation facility.
    (4) If a NGL fractionator supplies a product not listed in Table 
NN-1 of this subpart that is a mixture or blend of two or more products 
listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator 
shall report the quantities of the constituents of the mixtures or 
blends separately.
    (5) For an LDC using Equation NN-1 or NN-2 of this subpart, the 
point(s) of measurement for the natural gas volume supplied shall be 
the LDC city gate meter(s).
    (i) If the LDC makes its own quantity measurements according to 
established business practices, its own measurements shall be used.
    (ii) If the LDC does not make its own quantity measurements 
according to established business practices, it shall use its 
delivering pipeline invoiced measurements for natural gas deliveries to 
the LDC city gate, used in determining daily system sendout.
    (6) An LDC using Equation NN-3 of this subpart shall measure 
natural gas at the custody transfer meters.
    (7) An LDC using Equation NN-4 of this subpart shall measure 
natural gas at the customer meters. The reporter shall consider the 
volume delivered through a single particluar meter at a single 
particular location as the volume delivered to an individual end-user.
    (8) An LDC using Equation NN-5 of this subpart shall measure 
natural gas as follows:

[[Page 56501]]

    (i) Fuel1 shall be measured at the on-system storage 
injection meters and/or at the meters measuring natural gas to be 
liquefied.
    (ii) Fuel2 shall be measured at the meters used for 
measuring on-system storage withdrawals and/or LNG vaporization 
injection. If Fuel2 is from a source other than storage, the 
appropriate meter shall be used to measure the quantity.
    (9) An LDC shall measure all natural gas under the following 
standard industry temperature and pressure conditions: Cubic foot of 
gas at a temperature of 60 degrees Fahrenheit and at an absolute 
pressure of fourteen and seventy-three hundredths (14.73) pounds per 
square inch.
    (b) Determination of higher heating values (HHV).
    (1) When a reporter uses the default HHV provided in this section 
to calculate Equation NN-1 of this subpart, the appropriate value shall 
be taken from Table NN-1 of this subpart.
    (2) When a reporter uses a reporter-specific HHV to calculate 
Equation NN-1 of this subpart, an appropriate standard test published 
by a consensus-based standards organization shall be used. Consensus-
based standards organizations include, but are not limited to, the 
following: AGA and GPA.
    (i) If an LDC makes its own HHV measurements according to 
established business practices, then its own measurements shall be 
used.
    (ii) If an LDC does not make its own measurements according to 
established business practices, it shall use its delivering pipeline 
measurements.
    (c) Determination of emission factor (EF).
    (1) When a reporter used the default EF provided in this section to 
calculate Equation NN-1 of this subpart, the appropriate value shall be 
taken from Table NN-1 of this subpart.
    (2) When a reporter used the default EF provided in this section to 
calculate Equation NN-2, NN-3, NN-4, NN-5, or NN-7 of this subpart, the 
appropriate value shall be taken from Table NN-2 of this subpart.
    (3) When a reporter uses a reporter-specific EF, the reporter shall 
use an appropriate standard method published by a consensus-based 
standards organization to conduct compositional analysis necessary to 
determine reporter-specific CO2 emission factors. Consensus-
based standards organizations include, but are not limited to, the 
following: AGA and GPA.
    (d) Equipment Calibration.
    (1) Equipment used to measure quantities in Equations NN-1, NN-2, 
and NN-5 of this subpart shall be calibrated prior to its first use for 
reporting under this subpart, using a suitable standard method 
published by a consensus based standards organization or according to 
the equipment manufacturer's directions.
    (2) Equipment used to measure quantities in Equations NN-1, NN-2, 
and NN-5 of this subpart shall be recalibrated at the frequency 
specified by the standard method used or by the manufacturer's 
directions.


Sec.  98.405  Procedures for estimating missing data.

    (a) Whenever a quality-assured value of the quantity of natural gas 
liquids or natural gas supplied during any period is unavailable (e.g., 
if a flow meter malfunctions), a substitute data value for the missing 
quantity measurement must be used in the calculations according to 
paragraphs (b) and (c) of this section.
    (b) Determination of quantity.
    (1) NGL fractionators shall substitute meter records provided by 
pipeline(s) for all pipeline receipts of NGLs; by manifests for 
deliveries made to trucks or rail cars; or metered quantities accepted 
by the entities purchasing the output from the fractionator whether by 
pipeline or by truck or rail car. In cases where the metered data from 
the receiving pipeline(s) or purchasing entities are not available, 
fractionators may substitute estimates based on contract quantities 
required to be delivered under purchase or delivery contracts with 
other parties.
    (2) LDCs shall either substitute their delivering pipeline metered 
deliveries at the city gate or substitute nominations and scheduled 
delivery quantities for the period when metered values of actual 
deliveries are not available.
    (c) Determination of HHV and EF.
    (1) Whenever an LDC that makes its own HHV measurements according 
to established business practices cannot follow the quality assurance 
procedures for developing a reporter-specific HHV, as specified in 
Sec.  98.404, during any period for any reason, the reporter shall use 
either its delivering pipeline measurements or the default HHV provided 
in Table NN-1 of this part for that period.
    (2) Whenever an LDC that does not make its own HHV measurements 
according to established business practices or an NGL fractionator 
cannot follow the quality assurance procedures for developing a 
reporter-specific HHV, as specified in Sec.  98.404, during any period 
for any reason, the reporter shall use the default HHV provided in 
Table NN-1 of this part for that period.
    (3) Whenever a NGL fractionator cannot follow the quality assurance 
procedures for developing a reporter-specific HHV, as specified in 
Sec.  98.404, during any period for any reason, the NGL fractionator 
shall use the default HHV provided in Table NN-1 of this part for that 
period.
    (4) Whenever a reporter cannot follow the quality assurance 
procedures for developing a reporter-specific EF, as specified in Sec.  
98.404, during any period for any reason, the reporter shall use the 
default EF provided in Sec.  98.408 for that period.


Sec.  98.406  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), the 
annual report for each NGL fractionator covered by this rule shall 
contain the following information.
    (1) Annual quantity (in barrels) of each NGL product supplied to 
downstream facilities in the following product categories: ethane, 
propane, normal butane, isobutane, and pentanes plus.
    (2) Annual quantity (in barrels) of each NGL product received from 
other NGL fractionators in the following product categories: ethane, 
propane, normal butane, isobutane, and pentanes plus.
    (3) Annual volumes in Mscf of natural gas received for processing.
    (4) Annual quantity (in barrels) of y-grade, bulk NGLs received 
from others for fractionation.
    (5) Annual quantity (in barrels) of propane that the NGL 
fractionator odorizes at the facility and delivers to others.
    (6) Annual CO2 emissions (metric tons) that would result 
from the complete combustion or oxidation of the quantities in 
paragraphs (b)(1) and (b)(2) of this section, calculated in accordance 
with Sec.  98.403(a) and (c)(1).
    (7) Annual CO2 mass emissions (metric tons) that would 
result from the combustion or oxidation of fractionated NGLs supplied 
less the quantity received by other fractionators, calculated in 
accordance with Sec.  98.403(c)(2).
    (8) The specific industry standard used to measure each quantity 
reported in paragraph (a)(1) of this section.
    (9) If the LNG fractionator developed reporter-specific EFs or 
HHVs, report the following:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to 
Sec.  98.404(b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).

[[Page 56502]]

    (b) In addition to the information required by Sec.  98.3(c), the 
annual report for each LDC shall contain the following information.
    (1) Annual volume in Mscf of natural gas received by the LDC at its 
city gate stations for redelivery on the LDC's distribution system, 
including for use by the LDC.
    (2) Annual volume in Mscf of natural gas placed into storage.
    (3) Annual volume in Mscf of vaporized liquefied natural gas (LNG) 
produced at on-system vaporization facilities for delivery on the 
distribution system that is not accounted for in paragraph (b)(1) of 
this section.
    (4) Annual volume in Mscf of natural gas withdrawn from on-system 
storage (that is not delivered to the city gate) for delivery on the 
distribution system.
    (5) Annual volume in Mscf of natural gas delivered directly to LDC 
systems from producers or natural gas processing plants from local 
production.
    (6) Annual volume in Mscf of natural gas delivered to downstream 
gas transmission pipelines and other local distribution companies.
    (7) Annual volume in Mscf of natural gas delivered by LDC to each 
meter registering supply equal to or greater than 460,000 Mcsf during 
the calendar year.
    (8) The total annual CO2 mass emissions (metric tons) 
associated with the volumes in paragraphs (b)(1) through (b)(7) of this 
section, calculated in accordance with Sec.  98.403(a) and (b)(1) 
through (b)(3).
    (9) Annual CO2 emissions (metric tons) that would result 
from the complete combustion or oxidation of the annual supply of 
natural gas to end-users registering less than 460,000 Mcsf, calculated 
in accordance with Sec.  98.403(b)(4).
    (10) The specific industry standard used to develop the volume 
reported in paragraph (b)(1) of this section.
    (11) If the LDC developed reporter-specific EFs or HHVs, report the 
following:
    (i) The specific industry standard(s) used to develop reporter-
specific higher heating value(s) and/or emission factor(s), pursuant to 
Sec.  98.404 (b)(2) and (c)(3).
    (ii) The developed HHV(s).
    (iii) The developed EF(s).
    (12) The customer name, address, and meter number of each meter 
reading used to report in paragraph (b)(7) of this section.
    (i) If known, report the EIA identification number of each LDC 
customer.
    (ii) [Reserved]
    (13) The annual volume in Mscf of natural gas delivered by the 
local distribution company to each of the following end-use categories. 
For definitions of these categories, refer to EIA Form 176 (Annual 
Report of Natural Gas and Supplemental Gas Supply & Disposition) and 
Instructions.
    (i) Residential consumers.
    (ii) Commercial consumers.
    (iii) Industrial consumers.
    (iv) Electricity generating facilities.
    (c) Each reporter shall report the number of days in the reporting 
year for which substitute data procedures were used for the following 
purpose:
    (1) To measure quantity.
    (2) To develop HHV(s).
    (3) To develop EF(s).


Sec.  98.407  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), each 
annual report must contain the following information:
    (a) Records of all daily meter readings and documentation to 
support volumes of natural gas and NGLs that are reported under this 
part.
    (b) Records documenting any estimates of missing metered data and 
showing the calculations of the values used for the missing data.
    (c) Calculations and worksheets used to estimate CO2 
emissions for the volumes reported under this part.
    (d) Records related to the large end-users identified in Sec.  
98.406(b)(6).
    (e) Records relating to measured Btu content or carbon content 
showing specific industry standards used to develop reporter-specific 
higher heating values and emission factors.
    (f) Records of such audits as required by Sarbanes Oxley 
regulations on the accuracy of measurements of volumes of natural gas 
and NGLs delivered to customers or on behalf of customers.


Sec.  98.408  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

  Table NN-1 to Subpart NN of Part 98--Default Factors for Calculation
                      Methodology 1 of This Subpart
------------------------------------------------------------------------
                                                             Default CO2
                                      Default high heating     emission
                Fuel                      value factor       factor  (kg
                                                              CO2/MMBtu)
------------------------------------------------------------------------
Natural Gas........................  1.027 MMBtu/Mscf......        53.02
Propane............................  3.836 MMBtu/bbl.......        63.02
Normal butane......................  4.326 MMBtu/bbl.......        64.93
Ethane.............................  3.082 MMBtu/bbl.......        59.58
Isobutane..........................  3.974 MMBtu/bbl.......        65.08
Pentanes plus......................  4.620 MMBtu/bbl.......        66.90
------------------------------------------------------------------------


     Table NN-2 to Subpart NN of Part 98--Lookup Default Values for
                Calculation Methodology 2 of This Subpart
------------------------------------------------------------------------
                                                             Default CO2
                                                               emission
                Fuel                          Unit            value  (MT
                                                              CO2/Unit)
------------------------------------------------------------------------
Natural Gas........................  Mscf..................     0.054452
Propane............................  Barrel................     0.241745
Normal butane......................  Barrel................     0.280887
Ethane.............................  Barrel................     0.183626
Isobutane..........................  Barrel................     0.258628

[[Page 56503]]

 
Pentanes plus......................  Barrel................     0.309078
------------------------------------------------------------------------

Subpart OO--Suppliers of Industrial Greenhouse Gases


Sec.  98.410  Definition of the source category.

    (a) The industrial gas supplier source category consists of any 
facility that produces a fluorinated GHG or nitrous oxide, any bulk 
importer of fluorinated GHGs or nitrous oxide, and any bulk exporter of 
fluorinated GHGs or nitrous oxide.
    (b) To produce a fluorinated GHG means to manufacture a fluorinated 
GHG from any raw material or feedstock chemical. Producing a 
fluorinated GHG includes the manufacture of a fluorinated GHG 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, or the creation of by-products that are released 
or destroyed at the production facility.
    (c) To produce nitrous oxide means to produce nitrous oxide by 
thermally decomposing ammonium nitrate (NH4NO3). 
Producing nitrous oxide does not include the reuse or recycling of 
nitrous oxide or the creation of by-products that are released or 
destroyed at the production facility.


Sec.  98.411  Reporting threshold.

    Any supplier of industrial greenhouse gases who meets the 
requirements of Sec.  98.2(a)(4) must report GHG emissions.


Sec.  98.412  GHGs to report.

    You must report the GHG emissions that would result from the 
release of the nitrous oxide and each fluorinated GHG that you produce, 
import, export, transform, or destroy during the calendar year.


Sec.  98.413  Calculating GHG emissions.

    (a) Calculate the total mass of each fluorinated GHG or nitrous 
oxide produced annually, except for amounts that are captured solely to 
be shipped off site for destruction, by using Equation OO-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.171


P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp = Mass of fluorinated GHG or nitrous oxide produced 
over the period ``p''.

    (b) Calculate the total mass of each fluorinated GHG or nitrous 
oxide produced over the period ``p'' by using Equation OO-2 of this 
section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.172


Where:

Pp = Mass of fluorinated GHG or nitrous oxide produced 
over the period ``p'' (metric tons).
Op = Mass of fluorinated GHG or nitrous oxide that is 
measured coming out of the production process over the period p 
(metric tons).
Up = Mass of used fluorinated GHG or nitrous oxide that 
is added to the production process upstream of the output 
measurement over the period ``p'' (metric tons).

    (c) Calculate the total mass of each fluorinated GHG or nitrous 
oxide transformed by using Equation OO-3 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.173


Where:

T = Mass of fluorinated GHG or nitrous oxide transformed annually 
(metric tons).

FT = Mass of fluorinated GHG fed into the transformation 
process annually (metric tons).
ET = The fraction of the fluorinated GHG or nitrous oxide 
fed into the transformation process that is transformed in the process 
(metric tons).

    (d) Calculate the total mass of each fluorinated GHG destroyed by 
using Equation OO-4 of this section:
[GRAPHIC] [TIFF OMITTED] TR30OC09.174

Where:

D = Mass of fluorinated GHG destroyed annually (metric tons).
FD = Mass of fluorinated GHG fed into the destruction 
device annually (metric tons).
DE = Destruction efficiency of the destruction device (fraction).


Sec.  98.414  Monitoring and QA/QC requirements.

    (a) The mass of fluorinated GHGs or nitrous oxide coming out of the 
production process shall be measured using flowmeters, weigh scales, or 
a combination of volumetric and density measurements with an accuracy 
and precision of one percent of full scale or better.
    (b) The mass of any used fluorinated GHGs or used nitrous oxide 
added back into the production process upstream of the output 
measurement in paragraph (a) of this section shall be measured using 
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 mass in paragraph (a) of this section is 
measured by weighing containers that include returned heels as well as 
newly produced fluorinated GHGs, the returned heels shall be considered 
used fluorinated GHGs for purposes of this paragraph (b) of this 
section and Sec.  98.413(b).
    (c) The mass of fluorinated GHGs or nitrous oxide fed into the 
transformation process shall be measured using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of one percent of full scale or better.
    (d) The fraction of the fluorinated GHGs or nitrous oxide fed into 
the transformation process that is actually transformed shall be 
estimated considering yield calculations or quantities of unreacted 
fluorinated GHGs or nitrous oxide permanently removed from the process 
and recovered, destroyed, or emitted.
    (e) The mass of fluorinated GHG or nitrous oxide sent to another 
facility for transformation shall be measured using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of one percent of full scale or better.

[[Page 56504]]

    (f) The mass of fluorinated GHG sent to another facility for 
destruction shall be measured using 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, the concentration of the fluorinated GHG shall be 
estimated considering current or previous representative concentration 
measurements and other relevant process information. This concentration 
(mass fraction) shall be multiplied by the mass measurement to obtain 
the mass of the fluorinated GHG sent to another facility for 
destruction.
    (g) You must estimate the share of the mass of fluorinated GHGs in 
paragraph (f) of this section that is comprised of fluorinated GHGs 
that are not included in the mass produced in Sec.  98.413(a) because 
they are removed from the production process as by-products or other 
wastes.
    (h) The mass of fluorinated GHGs fed into the destruction device 
shall be measured using 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, the concentrations of fluorinated GHG being destroyed 
shall be estimated considering current or previous representative 
concentration measurements and other relevant process information. This 
concentration (mass fraction) shall be multiplied by the mass 
measurement to obtain the mass of the fluorinated GHG destroyed.
    (i) Very small quantities of fluorinated GHGs that are difficult to 
measure because they are entrained in other media such as destroyed 
filters and destroyed sample containers are exempt from paragraphs (f) 
and (h) of this section.
    (j) You must estimate the share of the mass of fluorinated GHGs in 
paragraph (h) of this section that is comprised of fluorinated GHGs 
that are not included in the mass produced in Sec.  98.413(a) because 
they are removed from the production process as by-products or other 
wastes.
    (k) For purposes of Equation OO-4 of this subpart, the destruction 
efficiency can be equated to the destruction efficiency determined 
during a previous performance test of the destruction device or, if no 
performance test has been done, the destruction efficiency provided by 
the manufacturer of the destruction device.
    (l) In their estimates of the mass of fluorinated GHGs destroyed, 
fluorinated GHG production facilities that destroy fluorinated GHGs 
shall account for any temporary reductions in the destruction 
efficiency that result from any startups, shutdowns, or malfunctions of 
the destruction device, including departures from the operating 
conditions defined in state or local permitting requirements and/or 
oxidizer manufacturer specifications.
    (m) Calibrate all flow meters, weigh scales, and combinations of 
volumetric and density measures that are used to measure or calculate 
quantities that are to be reported under this subpart prior to the 
first year for which GHG emissions are reported under this part. 
Calibrations performed prior to the effective date of this rule satisfy 
this requirement. Recalibrate all flow meters, weigh scales, and 
combinations of volumetric and density measures at the minimum 
frequency specified by the manufacturer. Use NIST-traceable standards 
and suitable methods published by a consensus standards organization 
(e.g., ASTM, ASME, ISO, or others).


Sec.  98.415  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emissions calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable (e.g., if a meter 
malfunctions), a substitute data value for the missing parameter shall 
be used in the calculations, according to paragraph (b) of this 
section.
    (b) For each missing value of the mass produced, fed into the 
production process (for used material being reclaimed), fed into the 
transformation process, fed into destruction devices, sent to another 
facility for transformation, or sent to another facility for 
destruction, the substitute value of that parameter shall be a 
secondary mass measurement where such a measurement is available. For 
example, if the mass produced is usually measured with a flowmeter at 
the inlet to the day tank and that flowmeter fails to meet an accuracy 
or precision test, malfunctions, or is rendered inoperable, then the 
mass produced may be estimated by calculating the change in volume in 
the day tank and multiplying it by the density of the product. Where a 
secondary mass measurement is not available, the substitute value of 
the parameter shall be an estimate based on a related parameter. For 
example, if a flowmeter measuring the mass fed into a destruction 
device is rendered inoperable, then the mass fed into the destruction 
device may be estimated using the production rate and the previously 
observed relationship between the production rate and the mass flow 
rate into the destruction device.


Sec.  98.416  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information:
    (a) Each fluorinated GHG or nitrous oxide production facility shall 
report the following information:
    (1) Mass in metric tons of each fluorinated GHG or nitrous oxide 
produced at that facility by process, except for amounts that are 
captured solely to be shipped off site for destruction.
    (2) Mass in metric tons of each fluorinated GHG or nitrous oxide 
transformed at that facility, by process.
    (3) Mass in metric tons of each fluorinated GHG destroyed at that 
facility, except fluorinated GHGs not included in the calculation of 
mass produced in Sec.  98.413(a) because they are removed from the 
production process as by-products or other wastes. Quantities to be 
reported under this paragraph (a)(3) of this section could include, for 
example, quantities that are returned to the facility for reclamation 
but are found to be irretrievably contaminated and are therefore 
destroyed.
    (4) Mass in metric tons of each fluorinated GHG that is destroyed 
at that facility except GHGs not included in the calculation of mass 
produced in Sec.  98.413(a) because they are removed from the 
production process as byproducts or other wastes.
    (5) Total mass in metric tons of each fluorinated GHG or nitrous 
oxide sent to another facility for transformation.
    (6) Total mass in metric tons of each fluorinated GHG sent to 
another facility for destruction, except fluorinated GHGs that are not 
included in the mass produced in Sec.  98.413(a) because they are 
removed from the production process as by-products or other wastes. 
Quantities to be reported under this paragraph (a)(6) could include, 
for example, fluorinated GHGs that are returned to the facility for 
reclamation but are found to be irretrievably contaminated and are 
therefore sent to another facility for destruction.
    (7) Total mass in metric tons of each fluorinated GHG that is sent 
to another facility for destruction and that is not included in the 
mass produced in Sec.  98.413(a) because it is removed from

[[Page 56505]]

the production process as a byproduct or other waste.
    (8) Total mass in metric tons of each reactant fed into the F-GHG 
or nitrous oxide production process, by process.
    (9) Total mass in metric tons of the reactants, by-products, and 
other wastes permanently removed from the F-GHG or nitrous oxide 
production process, by process.
    (10) For transformation processes that do not produce an F-GHG or 
nitrous oxide, mass in metric tons of any fluorinated GHG or nitrous 
oxide fed into the transformation process, by process.
    (11) Mass in metric tons of each fluorinated GHG fed into the 
destruction device.
    (12) Mass in metric tons of each fluorinated GHG or nitrous oxide 
that is measured coming out of the production process, by process.
    (13) Mass in metric tons of each used fluorinated GHGs or nitrous 
oxide added back into the production process (e.g., for reclamation), 
including returned heels in containers that are weighed to measure the 
mass in Sec.  98.414(a), by process.
    (14) Names and addresses of facilities to which any nitrous oxide 
or fluorinated GHGs were sent for transformation, and the quantities 
(metric tons) of nitrous oxide and of each fluorinated GHG that were 
sent to each for transformation.
    (15) Names and addresses of facilities to which any fluorinated 
GHGs were sent for destruction, and the quantities (metric tons) of 
nitrous oxide and of each fluorinated GHG that were sent to each for 
destruction.
    (16) Where missing data have been estimated pursuant to Sec.  
98.415, the reason the data were missing, the length of time the data 
were missing, the method used to estimate the missing data, and the 
estimates of those data.
    (b) A fluorinated GHG production facility or importer that destroys 
fluorinated GHGs shall submit a one-time report containing the 
following information:
    (1) Destruction efficiency (DE) of each destruction unit.
    (2) Methods used to determine the destruction efficiency.
    (3) Methods used to record the mass of fluorinated GHG destroyed.
    (4) Chemical identity of the fluorinated GHG(s) used in the 
performance test conducted to determine DE.
    (5) Name of all applicable federal or state regulations that may 
apply to the destruction process.
    (6) If any process changes affect unit destruction efficiency or 
the methods used to record mass of fluorinated GHG destroyed, then a 
revised report must be submitted to reflect the changes. The revised 
report must be submitted to EPA within 60 days of the change.
    (c) A bulk importer of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes their imports at the corporate 
level, except for shipments including less than 250 metric tons of 
CO2e, 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.
    (2) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG imported in bulk and sold or transferred to persons other than the 
importer for use in processes resulting in the transformation or 
destruction of the chemical.
    (3) Date on which the fluorinated GHGs or nitrous oxide were 
imported.
    (4) Port of entry through which the fluorinated GHGs or nitrous 
oxide passed.
    (5) Country from which the imported fluorinated GHGs or nitrous 
oxide were imported.
    (6) Commodity code of the fluorinated GHGs or nitrous oxide 
shipped.
    (7) Importer number for the shipment.
    (8) Total mass in metric tons of each fluorinated GHG destroyed by 
the importer.
    (9) If applicable, the names and addresses of the persons and 
facilities to which the nitrous oxide or fluorinated GHGs were sold or 
transferred for transformation, and the quantities (metric tons) of 
nitrous oxide and of each fluorinated GHG that were sold or transferred 
to each facility for transformation.
    (10) If applicable, the names and addresses of the persons and 
facilities to which the nitrous oxide or fluorinated GHGs were sold or 
transferred for destruction, and the quantities (metric tons) of 
nitrous oxide and of each fluorinated GHG that were sold or transferred 
to each facility for destruction.
    (d) A bulk exporter of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes their exports at the corporate 
level, except for shipments including less than 250 metric tons of 
CO2e, transshipments, and heels. The report shall contain 
the following information for each export:
    (1) Total mass in metric tons of nitrous oxide and each fluorinated 
GHG exported in bulk.
    (2) Names and addresses of the exporter and the recipient of the 
exports.
    (3) Exporter's Employee Identification Number.
    (4) Commodity code of the fluorinated GHGs and nitrous oxide 
shipped.
    (5) Date on which, and the port from which, fluorinated GHGs and 
nitrous oxide were exported from the United States or its territories.
    (6) Country to which the fluorinated GHGs or nitrous oxide were 
exported.
    (e) By April 1, 2011, a fluorinated GHG production facility shall 
submit a one-time report describing the following information:
    (1) The method(s) by which the producer in practice measures the 
mass of fluorinated GHGs produced, including the instrumentation used 
(Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its 
accuracy and precision.
    (2) The method(s) by which the producer in practice estimates the 
mass of fluorinated GHGs fed into the transformation process, including 
the instrumentation used (Coriolis flowmeter, other flowmeter, weigh 
scale, etc.) and its accuracy and precision.
    (3) The method(s) by which the producer in practice estimates the 
fraction of fluorinated GHGs fed into the transformation process that 
is actually transformed, and the estimated precision and accuracy of 
this estimate.
    (4) The method(s) by which the producer in practice estimates the 
masses of fluorinated GHGs fed into the destruction device, including 
the method(s) used to estimate the concentration of the fluorinated 
GHGs in the destroyed material, and the estimated precision and 
accuracy of this estimate.
    (5) The estimated percent efficiency of each production process for 
the fluorinated GHG produced.


Sec.  98.417  Records that must be retained.

    (a) In addition to the data required by Sec.  98.3(g), the 
fluorinated GHG production facility shall retain the following records:
    (1) Dated records of the data used to estimate the data reported 
under Sec.  98.416.
    (2) Records documenting the initial and periodic calibration of the 
gas chromatographs, weigh scales, flowmeters, and volumetric and 
density measures used to measure the quantities reported under this 
subpart, including the industry standards or manufacturer directions 
used for calibration pursuant to Sec.  98.414(j) and (k).
    (b) In addition to the data required by paragraph (a) of this 
section, the

[[Page 56506]]

fluorinated GHG production facility that destroys fluorinated GHGs 
shall keep records of test reports and other information documenting 
the facility's one-time destruction efficiency report and annual 
destruction device outlet reports in Sec.  98.416(b) and (e).
    (c) In addition to the data required by Sec.  98.3(g), the bulk 
importer shall retain the following records substantiating each of the 
imports that they report:
    (1) A copy of the bill of lading for the import.
    (2) The invoice for the import.
    (3) The U.S. Customs entry form.
    (d) In addition to the data required by Sec.  98.3(g), the bulk 
exporter shall retain the following records substantiating each of the 
exports that they report:
    (1) A copy of the bill of lading for the export and
    (2) The invoice for the import.
    (e) Every person who imports a container with a heel that is not 
reported under Sec.  98.416(c) shall keep records of the amount brought 
into the United States that document that the residual amount in each 
shipment is less than 10 percent of the volume of the container and 
will:
    (1) Remain in the container and be included in a future shipment.
    (2) Be recovered and transformed.
    (3) Be recovered and destroyed.
    (4) Be recovered and included in a future shipment.


Sec.  98.418  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

Subpart PP--Suppliers of Carbon Dioxide


Sec.  98.420  Definition of the source category.

    (a) The carbon dioxide (CO2) supplier source category 
consists of the following:
    (1) Facilities with production process units that capture a 
CO2 stream for purposes of supplying CO2 for 
commercial applications or that capture and maintain custody of a 
CO2 stream in order to sequester or otherwise inject it 
underground. Capture refers to the initial separation and removal of 
CO2 from a manufacturing process or any other process.
    (2) Facilities with CO2 production wells that extract or 
produce a CO2 stream for purposes of supplying 
CO2 for commercial applications or that extract and maintain 
custody of a CO2 stream in order to sequester or otherwise 
inject it underground.
    (3) Importers or exporters of bulk CO2.
    (b) This source category is focused on upstream supply. It does not 
cover:
    (1) Storage of CO2 above ground or in geologic 
formations.
    (2) Use of CO2 in enhanced oil and gas recovery.
    (3) Transportation or distribution of CO2.
    (4) Purification, compression, or processing of CO2.
    (5) On-site use of CO2 captured on site.
    (c) This source category does not include CO2 imported 
or exported in equipment, such as fire extinguishers.


Sec.  98.421  Reporting threshold.

    Any supplier of CO2 who meets the requirements of Sec.  
98.2(a)(4) of subpart A of this part must report the mass of 
CO2 captured, extracted, imported, or exported.


Sec.  98.422  GHGs to report.

    (a) Mass of CO2 captured from each production process 
unit.
    (b) Mass of CO2 extracted from each CO2 
production wells.
    (c) Mass of CO2 imported.
    (d) Mass of CO2 exported.


Sec.  98.423  Calculating CO2 supply.

    (a) 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. If multiple flow meters are used, you shall calculate the 
annual mass of CO2 for all flow meters according to the 
procedures specified in paragraph (a)(3) of this section.
    (1) For each mass flow meter, you shall calculate quarterly the 
mass of CO2 in a CO2 stream in metric tons, prior 
to any subsequent purification, processing, or compressing, by 
multiplying the mass flow by the composition data, according to 
Equation PP-1 of this section. Mass flow and composition data 
measurements shall be made in accordance with Sec.  98.424 of this 
subpart.
[GRAPHIC] [TIFF OMITTED] TR30OC09.175

Where:

CO2,u = Annual mass of CO2 (metric tons) 
through flow meter u.
CCO2,p,u = Quarterly CO2 
concentration measurement in flow for flow meter u in quarter p (wt. 
%CO2).
Qp,u = Quarterly mass flow rate measurement for flow 
meter u in quarter p (metric tons).
p = Quarter of the year.
u = Flow meter.

    (2) For each volumetric flow meter, you shall calculate quarterly 
the mass of CO2 in a CO2 stream in metric tons, 
prior to any subsequent purification, processing, or compressing, by 
multiplying the volumetric flow by the concentration and density data, 
according to Equation PP-2 of this section. Volumetric flow, 
concentration and density data measurements shall be made in accordance 
with Sec.  98.424 of this section.
[GRAPHIC] [TIFF OMITTED] TR30OC09.176

Where:

CO2,u = Annual mass of CO2 (metric tons) 
through flow meter u.
CCO2,p = Quarterly CO2 
concentration measurement in flow for flow meter u in quarter p (wt. 
% CO2).
Qp = Quarterly volumetric flow rate measurement for flow 
meter u in quarter p (standard cubic meters).
Dp = Quarterly CO2 stream density measurement 
for flow meter u in quarter p (metric tons per standard cubic 
meter).
p = Quarter of the year.
u = Flow meter.

    (3) To aggregate data, sum the mass of CO2 for all flow 
meters in accordance with Equation PP-3 of this section.

[[Page 56507]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.177

Where:

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

    (b) Importers or exporters that import or export CO2 in 
containers shall calculate the total mass of CO2 imported or 
exported in metric tons, prior to any subsequent purification, 
processing, or compressing, 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] TR30OC09.178

Where:

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

Sec.  98.424  Monitoring and QA/QC requirements.

    (a) Determination of quantity.
    (1) Reporters that have a mass flow meter or volumetric flow meter 
installed to measure the flow of a CO2 stream shall base 
calculations in Sec.  98.423 of this subpart on the installed mass flow 
or volumetric flow meters.
    (2) Reporters that do not have a mass flow meter or volumetric flow 
meter installed to measure the flow of the CO2 stream 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.
    (3) Importers or exporters that import or export CO2 in 
containers shall measure the mass in each CO2 container 
using weigh bills, scales, or load cells and sum the mass in all 
containers imported or exported during the reporting year.
    (4) All flow meters, scales, and load cells used to measure 
quantities that are reported in Sec.  98.423 of this subpart shall be 
operated and calibrated according to the following procedure:
    (i) You shall use an appropriate standard 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, the American National Standards 
Institute (ANSI), the American Gas Association (AGA), the American 
Society of Mechanical Engineers (ASME), the American Petroleum 
Institute (API), and the North American Energy Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, you shall follow industry standard 
practices.
    (iii) You must ensure that any flow meter calibrations performed 
are NIST traceable.
    (5) Reporters using Equation PP-2 of this subpart shall measure the 
density of the CO2 stream on a quarterly basis in order to 
calculate the mass of the CO2 stream according to the 
following procedure:
    (i) You shall use an appropriate standard method published by a 
consensus-based standards organization to measure density if such a 
method exists. Consensus-based standards organizations include, but are 
not limited to, the following: ASTM International, the American 
National Standards Institute (ANSI), the American Gas Association 
(AGA), the American Society of Mechanical Engineers (ASME), the 
American Petroleum Institute (API), and the North American Energy 
Standards Board (NAESB).
    (ii) Where no appropriate standard method developed by a consensus-
based standards organization exists, you shall follow industry standard 
practices.
    (b) Determination of concentration.
    (1) Reporters using Equation PP-1 or PP-2 of this subpart shall 
sample the CO2 stream on a quarterly basis to determine the 
composition of the CO2 stream.
    (2) Methods to measure the composition of the CO2 stream 
must conform to applicable chemical analytical standards. Acceptable 
methods include U.S. Food and Drug Administration food-grade 
specifications for CO2 (see 21 CFR 184.1250) and ASTM 
standard E1747-95 (Reapproved 2005) Standard Guide for Purity of Carbon 
Dioxide Used in Supercritical Fluid Applications (incorporated by 
reference, see Sec.  98.7 of subpart A of this part).


Sec.  98.425  Procedures for estimating missing data.

    (a) Whenever the quality assurance procedures in Sec.  98.424(a) 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:
    (1) A quarterly CO2 mass flow or volumetric flow value 
that is missing may be substituted with a quarterly value measured 
during another quarter of the current reporting year.
    (2) A quarterly CO2 mass flow or volumetric flow value 
that is missing may be substituted with a quarterly value measured 
during the same quarter from the past reporting year.
    (3) If a mass or volumetric flow meter is installed to measure the 
CO2 stream, you may substitute data from a mass or 
volumetric flow meter measuring the CO2 stream transferred 
for any period during which the installed meter is inoperable.
    (4) The mass or volumetric flow used 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.
    (b) Whenever the quality assurance procedures in Sec.  98.424(b) of 
this subpart cannot be followed to determine concentration of the 
CO2 stream, the most appropriate of the following missing 
data procudures shall be followed:
    (1) A quarterly concentration value that is missing may be 
substituted with a quarterly value measured during another quarter of 
the current reporting year.
    (2) A quarterly concentration value that is missing may be 
substituted with a quarterly value measured during the same quarter 
from the previous reporting year.
    (3) The concentration used for purposes of product tracking and 
billing according to the reporter's established procedures may be 
substituted for any quarterly value.
    (c) Missing data on density of the CO2 stream shall be 
substituted with quarterly or annual average values from the previous 
calendar year.


Sec.  98.426  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c) of subpart 
A of this part, the annual report shall contain the following 
information, as applicable:
    (a) If you use Equation PP-1 of this subpart, report the following 
information for each mass flow meter:
    (1) Annual mass in metric tons of CO2.
    (2) Quarterly mass flow of CO2.
    (3) Quarterly concentration of the CO2 stream.
    (4) The standard used to measure CO2 concentration.
    (b) If you use Equation PP-2 of this subpart, report the following 
information for each volumetric flow meter:
    (1) Annual mass in metric tons of CO2.
    (2) Quarterly volumetric flow of CO2.
    (3) Quarterly concentration of the CO2 stream.
    (4) Quarterly density of the CO2 stream.

[[Page 56508]]

    (5) The method used to measure density.
    (6) The standard used to measure CO2 concentration.
    (c) If you use Equation PP-3 of this subpart, report the annual 
CO2 mass in metric tons from all flow meters.
    (d) If you use Equation PP-4 of this subpart, report at the 
corporate level the annual mass of CO2 in metric tons in all 
CO2 containers that are imported or exported.
    (e) Each reporter shall report the following information:
    (1) The type of equipment used to measure the total flow of the 
CO2 stream or the total mass in CO2 containers.
    (2) The standard used to operate and calibrate the equipment 
reported in (e)(1) of this section.
    (3) The number of days in the reporting year for which substitute 
data procedures were used for the following purpose:
    (i) To measure quantity.
    (ii) To measure concentration.
    (iii) To measure density.
    (f) Report the aggregated annual quantity of CO2 in 
metric tons that is transferred to each of the following end use 
applications, if known:
    (1) Food and beverage.
    (2) Industrial and municipal water/wastewater treatment.
    (3) Metal fabrication, including welding and cutting.
    (4) Greenhouse uses for plant growth.
    (5) Fumigants (e.g., grain storage) and herbicides.
    (6) Pulp and paper.
    (7) Cleaning and solvent use.
    (8) Fire fighting.
    (9) Transportation and storage of explosives.
    (10) Enhanced oil and natural gas recovery.
    (11) Long-term storage (sequestration).
    (12) Research and development.
    (13) Other.
    (g) Each production process unit that captures a CO2 
stream for purposes of supplying CO2 for commercial 
applications or in order to sequester or otherwise inject it 
underground when custody of the CO2 is maintained shall 
report the percentage of that stream, if any, that is biomass-based 
during the reporting year.


Sec.  98.427  Records that must be retained.

    In addition to the records required by Sec.  98.3(g) of subpart A 
of this part, you must retain the records specified in paragraphs (a) 
through (c) of this section, as applicable.
    (a) The owner or operator of a facility containing production 
process units must retain quarterly records of captured or transferred 
CO2 streams and composition.
    (b) The owner or operator of a CO2 production well 
facility must maintain quarterly records of the mass flow or volumetric 
flow of the extracted or transferred CO2 stream and 
concentration and density if volumetric flow meters are used.
    (c) Importers or exporters of CO2 must retain annual 
records of the mass flow, volumetric flow, and mass of CO2 
imported or exported.


Sec.  98.428  Definitions.

    All terms used in this subpart have the same meaning given in the 
Clean Air Act and subpart A of this part.

PART 1033--[AMENDED]

0
21. The authority citation for part 1033 continues to read as follows:

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

Subpart C--[Amended]

0
22. Section 1033.205 is amended by revising paragraph (d)(8) to read as 
follows:


Sec.  1033.205  Applying for a certificate of conformity.

* * * * *
    (d) * * *
    (8)(i) All test data you obtained for each test engine or 
locomotive. As described in Sec.  1033.235, we may allow you to 
demonstrate compliance based on results from previous emission tests, 
development tests, or other testing information. Include data for NOx, 
PM, HC, CO, and CO2.
    (ii) Report measured CO2, N2O, and 
CH4 as described in Sec.  1033.235. Small manufacturers/
remanufacturers may omit reporting N2O and CH4.
* * * * *

0
23. Section 1033.235 is amended by adding paragraph (i) to read as 
follows:


Sec.  1033.235  Emission testing required for certification.

* * * * *
    (i) Measure CO2 with each test. Measure CH4 
with each low-hour certification test using the procedures specified in 
40 CFR part 1065 starting in the 2012 model year. Also measure 
N2O with each low-hour certification test using the 
procedures specified in 40 CFR part 1065 for any engine family that 
depends on NOx aftertreatment to meet emission standards. Small 
manufacturers/remanufacturers may omit measurement of N2O 
and CH4. Use the same units and modal calculations as for 
your other results to report a single weighted value for 
CO2, N2O, and CH4. Round the final 
values as follows:
    (1) Round CO2 to the nearest 1 g/bhp-hr.
    (2) Round N2O to the nearest 0.001 g/bhp-hr.
    (3) Round CH4 to the nearest 0.001g/bhp-hr.

Subpart F--[Amended]

0
24. Section 1033.501 is amended by revising paragraph (a) introductory 
text to read as follows:


Sec.  1033.501  General provisions.

    (a) Except as specified in this subpart, use the equipment and 
procedures for compression-ignition engines in 40 CFR part 1065 to 
determine whether your locomotives meet the duty-cycle emission 
standards in Sec.  1033.101. Use the applicable duty cycles specified 
in this subpart. Measure emissions of all the pollutants we regulate in 
Sec.  1033.101 plus CO2. Measure N2O, and 
CH4 as described in Sec.  1033.235. The general test 
procedure is the procedure specified in 40 CFR part 1065 for steady-
state discrete-mode cycles. However, if you use the optional ramped 
modal cycle in Sec.  1033.520, follow the procedures for ramped modal 
testing in 40 CFR part 1065. The following exceptions from the 1065 
procedures apply:
* * * * *

Subpart J--[Amended]

0
25. Section 1033.905 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  1033.905  Symbols, acronyms, and abbreviations.

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

PART 1039--[AMENDED]

0
26. The authority citation for part 1039 continues to read as follows:

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

Subpart C--[Amended]

0
27. Section 1039.205 is amended by revising paragraph (r) to read as 
follows:


Sec.  1039.205  What must I include in my application?

* * * * *
    (r) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test

[[Page 56509]]

procedures of subpart F of this part. We may ask you to send other 
information to confirm that your tests were valid under the 
requirements of this part and 40 CFR part 1065.
    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1039.235. Small-volume engine 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
28. Section 1039.235 is amended by adding paragraph (g) to read as 
follows:


Sec.  1039.235  What emission testing must I perform for my application 
for a certificate of conformity?

* * * * *
    (g) Measure CO2 and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065 
in the 2011 and 2012 model years, respectively. Also measure 
N2O with each low-hour certification test using the 
procedures specified in 40 CFR part 1065 starting in the 2013 model 
year for any engine family that depends on NOx aftertreatment to meet 
emission standards. Small-volume engine manufacturers may omit 
measurement of N2O and CH4. These measurements 
are not required for NTE testing. Use the same units and modal 
calculations as for your other results to report a single weighted 
value for each constituent. Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001g/kW-hr.

Subpart F--[Amended]

0
29. Section 1039.501 is amended by revising paragraph (a) to read as 
follows:


Sec.  1039.501  How do I run a valid emission test?

    (a) Use the equipment and procedures for compression-ignition 
engines in 40 CFR part 1065 to determine whether engines meet the duty-
cycle emission standards in subpart B of this part. Measure the 
emissions of all the exhaust constituents subject to emissions 
standards as specified in 40 CFR part 1065. Measure CO2, 
N2O, and CH4 as described in Sec.  1039.235. Use 
the applicable duty cycles specified in Sec. Sec.  1039.505 and 
1039.510.
* * * * *

Subpart I--[Amended]

0
30. Section 1039.805 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  1039.805  What symbols, acronyms, and abbreviations does this 
part use?

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

PART 1042--[AMENDED]

0
31. The authority citation for part 1042 continues to read as follows:

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

Subpart C--[Amended]

0
32. Section 1042.205 is amended by revising paragraph (r) to read as 
follows:


Sec.  1042.205  Application requirements.

* * * * *
    (r) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test procedures of subpart F of this part. We may ask you to 
send other information to confirm that your tests were valid under the 
requirements of this part and 40 CFR part 1065.
    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1042.235. Small-volume engine 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
33. Section 1042.235 is amended by adding paragraph (g) to read as 
follows:


Sec.  1042.235  Emission testing required for a certificate of 
conformity.

* * * * *
    (g) Measure CO2 with each low-hour certification test 
using the procedures specified in 40 CFR part 1065 starting in the 2011 
model year. Also measure CH4 from Category 1 and Category 2 
engines with each low-hour certification test using the procedures 
specified in 40 CFR part 1065 starting in the 2012 model year. Measure 
N2O from Category 1 and Category 2 engines with each low-
hour certification test using the procedures specified in 40 CFR part 
1065 for any engine family that depends on NOx aftertreatment to meet 
emission standards. Small-volume engine manufacturers may omit 
measurement of N2O and CH4. These measurements 
are not required for NTE testing. Use the same units and modal 
calculations as for your other results to report a single weighted 
value for each constituent. Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001 g/kW-hr.

Subpart F--[Amended]

0
34. Section 1042.501 is amended by revising paragraph (a) to read as 
follows:


Sec.  1042.501  How do I run a valid emission test?

    (a) Use the equipment and procedures for compression-ignition 
engines in 40 CFR part 1065 to determine whether Category 1 and 
Category 2 engines meet the duty-cycle emission standards in Sec.  
1042.101(a). Measure the emissions of all exhaust constituents subject 
to emissions standards as specified in 40 CFR part 1065. Measure 
CO2, N2O, and CH4 as described in 
Sec.  1042.235. Use the applicable duty cycles specified in Sec.  
1042.505.
* * * * *

Subpart J--[Amended]

0
35. Section 1042.905 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  1042.905  Symbols, acronyms, and abbreviations.

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

PART 1045--[AMENDED]

0
36. The authority citation for part 1045 continues to read as follows:

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

Subpart C--[Amended]

0
37. Section 1045.205 is amended by revising paragraph (q) to read as 
follows:


Sec.  1045.205  What must I include in my application?

* * * * *
    (q) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test procedures of subpart F of this part. We may ask you to 
send other information to confirm that your tests were valid under the 
requirements of this part and 40 CFR parts 1060 and 1065.

[[Page 56510]]

    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1045.235. Small-volume engine 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
38. Section 1045.235 is amended by adding paragraph (g) to read as 
follows:


Sec.  1045.235  What emission testing must I perform for my application 
for a certificate of conformity?

* * * * *
    (g) Measure CO2 and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065 
starting in the 2011 and 2012 model years, respectively. Also measure 
N2O with each low-hour certification test using the 
procedures specified in 40 CFR part 1065 starting in the 2013 model 
year for any engine family that depends on NOX 
aftertreatment to meet emission standards. Small-volume engine 
manufacturers may omit measurement of N2O and 
CH4. These measurements are not required for NTE testing. 
Use the same units and modal calculations as for your other results to 
report a single weighted value for each constituent. Round the final 
values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001 g/kW-hr.

Subpart F--[Amended]

0
39. Section 1045.501 is amended by revising paragraph (b) to read as 
follows:


Sec.  1045.501  How do I run a valid emission test?

* * * * *
    (b) General requirements. Use the equipment and procedures for 
spark-ignition engines in 40 CFR part 1065 to determine whether engines 
meet the duty-cycle emission standards in Sec. Sec.  1045.103 and 
1045.105. Measure the emissions of all exhaust constituents subject to 
emissions standards as specified in 40 CFR part 1065. Measure 
CO2, N2O, and CH4 as described in 
Sec.  1045.235. Use the applicable duty cycles specified in Sec.  
1045.505. Section 1045.515 describes the supplemental procedures for 
evaluating whether engines meet the not-to-exceed emission standards in 
Sec.  1045.107.
* * * * *

PART 1048--[AMENDED]

0
40. The authority citation for part 1048 continues to read as follows:

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

Subpart C--[Amended]

0
41. Section 1048.205 is amended by revising paragraph (s) to read as 
follows:


Sec.  1048.205  What must I include in my application?

* * * * *
    (s) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test procedures of subpart F of this part. We may ask you to 
send other information to confirm that your tests were valid under the 
requirements of this part and 40 CFR part 1065.
    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1048.235. Small-volume engine 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
42. Section 1048.235 is amended by adding paragraph (g) to read as 
follows:


Sec.  1048.235  What emission testing must I perform for my application 
for a certificate of conformity?

* * * * *
    (g) Measure CO2 and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065 
starting in the 2011 and 2012 model years, respectively. Also measure 
N2O with each low-hour certification test using the 
procedures specified in 40 CFR part 1065 starting in the 2013 model 
year for any engine family that depends on NOx aftertreatment to meet 
emission standards. Small-volume engine manufacturers may omit 
measurement of N2O and CH4. These measurements 
are not required for measurements using field-testing procedures. Use 
the same units and modal calculations as for your other results to 
report a single weighted value for each constituent. Round the final 
values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001g/kW-hr.

Subpart F--[Amended]

0
43. Section 1048.501 is amended by revising paragraph (a) to read as 
follows:


Sec.  1048.501  How do I run a valid emission test?

    (a) Use the equipment and procedures for spark-ignition engines in 
40 CFR part 1065 to determine whether engines meet the duty-cycle 
emission standards in Sec.  1048.101(a) and (b). Measure the emissions 
of all the pollutants we regulate in Sec.  1048.101 using the sampling 
procedures specified in 40 CFR part 1065. Measure CO2, 
N2O, and CH4 as described in Sec.  1048.235. Use 
the applicable duty cycles specified in Sec. Sec.  1048.505 and 
1048.510.
* * * * *

Subpart I--[Amended]

0
44. Section 1048.805 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  1048.805  What symbols, acronyms, and abbreviations does this 
part use?

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

PART 1051--[AMENDED]

0
45. The authority citation for part 1051 continues to read as follows:

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

Subpart C--[Amended]

0
46. Section 1051.205 is amended by revising paragraph (p) to read as 
follows:


Sec.  1051.205  What must I include in my application?

* * * * *
    (p) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test procedures of subpart F of this part. We may ask you to 
send other information to confirm that your tests were valid under the 
requirements of this part and 40 CFR parts 86 and 1065.
    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1051.235. Small-volume 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
47. Section 1051.235 is amended by adding paragraph (i) to read as 
follows:


Sec.  1051.235  What emission testing must I perform for my application 
for a certificate of conformity?

* * * * *
    (i) Measure CO2 and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065 
starting in the 2011 and 2012

[[Page 56511]]

model years, respectively. Also measure N2O with each low-
hour certification test using the analytical equipment and procedures 
specified in 40 CFR part 1065 starting in the 2013 model year for any 
engine family that depends on NOx aftertreatment to meet emission 
standards. Small-volume manufacturers may omit measurement of 
N2O and CH4; other manufacturers may provide 
appropriate data and/or information and omit measurement of 
N2O and CH4 as described in 40 CFR 1065.5. Use 
the same units and modal calculations as for your other results to 
report a single weighted value for each constituent. Round the final 
values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr or 1 g/km, as 
appropriate.
    (2) Round N2O to the nearest 0.001 g/kW-hr or 0.001 g/
km, as appropriate.
    (3) Round CH4 to the nearest 0.001 g/kW-hr or 0.001 g/
km, as appropriate.

Subpart F--[Amended]

0
48. Section 1051.501 is amended by revising paragraphs (a) and (b) to 
read as follows:


Sec.  1051.501  What procedures must I use to test my vehicles or 
engines?

* * * * *
    (a) Snowmobiles. For snowmobiles, use the equipment and procedures 
for spark-ignition engines in 40 CFR part 1065 to determine whether 
your snowmobiles meet the duty-cycle emission standards in Sec.  
1051.103. Measure the emissions of all the pollutants we regulate in 
Sec.  1051.103. Measure CO2, N2O, and 
CH4 as described in Sec.  1051.235. Use the duty cycle 
specified in Sec.  1051.505.
    (b) Motorcycles and ATVs. For motorcycles and ATVs, use the 
equipment, procedures, and duty cycle in 40 CFR part 86, subpart F, to 
determine whether your vehicles meet the exhaust emission standards in 
Sec.  1051.105 or Sec.  1051.107. Measure the emissions of all the 
pollutants we regulate in Sec.  1051.105 or Sec.  1051.107. Measure 
CO2, N2O, and CH4 as described in 
Sec.  1051.235. If we allow you to certify ATVs based on engine 
testing, use the equipment, procedures, and duty cycle described or 
referenced in the section that allows engine testing. For motorcycles 
with engine displacement at or below 169 cc and all ATVs, use the 
driving schedule in paragraph (c) of appendix I to 40 CFR part 86. For 
all other motorcycles, use the driving schedule in paragraph (b) of 
Appendix I to part 86. With respect to vehicle-speed governors, test 
motorcycles and ATVs in their ungoverned configuration, unless we 
approve in advance testing in a governed configuration. We will only 
approve testing in a governed configuration if you can show that the 
governor is permanently installed on all production vehicles and is 
unlikely to be removed in use. With respect to engine-speed governors, 
test motorcycles and ATVs in their governed configuration. Run the test 
engine, with all emission-control systems operating, long enough to 
stabilize emission levels; you may consider emission levels stable 
without measurement if you accumulate 12 hours of operation.
* * * * *

Subpart I--[Amended]

0
49. Section 1051.805 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  1051.805  What symbols, acronyms, and abbreviations does this 
part use?

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *

PART 1054--[AMENDED]

0
50. The authority citation for part 1054 continues to read as follows:

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

Subpart C--[Amended]

0
51. Section 1054.205 is amended by revising paragraph (p) to read as 
follows:


Sec.  1054.205  What must I include in my application?

* * * * *
    (p) Report test results as follows:
    (1) Report all test results involving measurement of pollutants for 
which emission standards apply. Include test results from invalid tests 
or from any other tests, whether or not they were conducted according 
to the test procedures of subpart F of this part. We may ask you to 
send other information to confirm that your tests were valid under the 
requirements of this part and 40 CFR parts 1060 and 1065.
    (2) Report measured CO2, N2O, and 
CH4 as described in Sec.  1054.235. Small-volume engine 
manufacturers may omit reporting N2O and CH4.
* * * * *

0
52. Section 1054.235 is amended by adding paragraph (g) to read as 
follows:


Sec.  1054.235  What exhaust emission testing must I perform for my 
application for a certificate of conformity?

* * * * *
    (g) Measure CO2 and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065 
starting in the 2011 and 2012 model years, respectively. Also measure 
N2O with each low-hour certification test using the 
procedures specified in 40 CFR part 1065 starting in the 2013 model 
year for any engine family that depends on NOx aftertreatment to meet 
emission standards. Small-volume engine manufacturers may omit 
measurement of N2O and CH4. Use the same units 
and modal calculations as for your other results to report a single 
weighted value for each constituent. Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001 g/kW-hr.

Subpart F--[Amended]

0
53. Section 1054.501 is amended by revising paragraph (b)(1) to read as 
follows:


Sec.  1054.501  How do I run a valid emission test?

* * * * *
    (b) * * *
    (1) Measure the emissions of all exhaust constituents subject to 
emissions standards as specified in Sec.  1054.505 and 40 CFR part 
1065. Measure CO2, N2O, and CH4 as 
described in Sec.  1054.235. See Sec.  1054.650 for special provisions 
that apply for variable-speed engines (including engines shipped 
without governors).
* * * * *

PART 1065--[AMENDED]

0
54. The authority citation for part 1065 continues to read as follows:

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

Subpart A--[Amended]

0
55. Section 1065.5 is amended by revising paragraph (a)(3) to read as 
follows:


Sec.  1065.5  Overview of this part 1065 and its relationship to the 
standard-setting part.

    (a) * * *
    (3) Which exhaust constituents do I need to measure? Measure all 
exhaust constituents that are subject to emission standards, any other 
exhaust constituents needed for calculating emission rates, and any 
additional

[[Page 56512]]

exhaust constituents as specified in the standard-setting part. 
Alternatively, you may omit the measurement of N2O and 
CH4 for an engine, provided it is not subject to an 
N2O or CH4 emission standard. If you omit the 
measurement of N2O and CH4, you must provide 
other information and/or data that will give us a reasonable basis for 
estimating the engine's emission rates.
* * * * *

Subpart C--[Amended]

0
56. The center heading ``NOx Measurements'' preceding Sec.  
1065.270 is revised to read as follows:

NOX and N2O Measurements

0
57. A new Sec.  1065.275 is added under the center heading 
``NOx and N2O Measurements'' to read as follows:


Sec.  1065.275  N2O measurement devices.

    (a) General component requirements. We recommend that you use an 
analyzer that meets the specifications in Table 1 of Sec.  1065.205. 
Note that your system must meet the linearity verification in Sec.  
1065.307.
    (b) Instrument types. You may use any of the following analyzers to 
measure N2O:
    (1) Nondispersive infra-red (NDIR) analyzer. You may use an NDIR 
analyzer that has compensation algorithms that are functions of other 
gaseous measurements and the engine's known or assumed fuel properties. 
The target value for any compensation algorithm is 0.0% (that is, no 
bias high and no bias low), regardless of the uncompensated signal's 
bias.
    (2) Fourier transform infra-red (FTIR) analyzer. You may use an 
FTIR analyzer that has compensation algorithms that are functions of 
other gaseous measurements and the engine's known or assumed fuel 
properties. The target value for any compensation algorithm is 0.0% 
(that is, no bias high and no bias low), regardless of the 
uncompensated signal's bias. Use appropriate analytical procedures for 
interpretation of infrared spectra. For example, EPA Test Method 320 is 
considered a valid method for spectral interpretation (see http://www.epa.gov/ttn/emc/methods/method320.html).
    (3) Photoacoustic analyzer. You may use a photoacoustic analyzer 
that has compensation algorithms that are functions of other gaseous 
measurements. The target value for any compensation algorithm is 0.0% 
(that is, no bias high and no bias low), regardless of the 
uncompensated signal's bias. Use an optical wheel configuration that 
gives analytical priority to measurement of the least stable components 
in the sample. Select a sample integration time of at least 5 seconds. 
Take into account sample chamber and sample line volumes when 
determining flush times for your instrument.
    (4) Gas chromatograph analyzer. You may use a gas chromatograph 
with an electron-capture detector (GC-ECD) to measure N2O 
concentrations of diluted exhaust for batch sampling.
    (i) You may use a packed or porous layer open tubular (PLOT) column 
phase of suitable polarity and length to achieve adequate resolution of 
the N2O peak for analysis. Examples of acceptable columns 
are a PLOT column consisting of bonded polystyrene-divinylbenzene or a 
Porapack Q packed column. Take the column temperature profile and 
carrier gas selection into consideration when setting up your method to 
achieve adequate N2O peak resolution.
    (ii) Use good engineering judgment to zero your instrument and 
correct for drift. You do not need to follow the specific procedures in 
Sec.  1065.530 and Sec.  1065.550(b) that would otherwise apply. For 
example, you may perform a span gas measurement before and after sample 
analysis without zeroing. Use the average area counts of the pre-span 
and post-span measurements to generate a response factor (area counts/
span gas concentration), which you then multiply by the area counts 
from your sample to generate the sample concentration.
    (c) Interference validation. Perform interference validation for 
NDIR, FTIR, and photoacoustic analyzers using the procedures of Sec.  
1065.375. Interference validation is not required for GC-ECD. Certain 
interference gases can positively interfere with NDIR, FTIR, and 
photoacoustic analyzers by causing a response similar to 
N2O. When running the interference verification for these 
analyzers, use interference gases as follows:
    (1) The interference gases for NDIR analyzers are CO, 
CO2, H2O, CH4 and SO2. Note 
that interference species, with the exception of H2O, are 
dependent on the N2O infrared absorption band chosen by the 
instrument manufacturer and should be determined dently for each 
analyzer.
    (2) Use good engineering judgment to determine interference gases 
for FTIR. Note that interference species, with the exception of 
H2O, are dependent on the N2O infrared absorption 
band chosen by the instrument manufacturer and should be determined 
independently for each analyzer.
    (3) The interference gases for photoacoustic analyzers are CO, 
CO2, and H2O.

Subpart D--[Amended]

0
58. Section 1065.303 is revised to read as follows:


Sec.  1065.303  Summary of required calibration and verifications

    The following table summarizes the required and recommended 
calibrations and verifications described in this subpart and indicates 
when these have to be performed:

     Table 1 of Sec.   1065.303-Summary of Required Calibration and
                              Verifications
------------------------------------------------------------------------
 Type of calibration or verification         Minimum frequency \a\
------------------------------------------------------------------------
Sec.   1065.305: Accuracy,             Accuracy: Not required, but
 repeatability and noise.               recommended for initial
                                        installation.
                                       Repeatability: Not required, but
                                        recommended for initial
                                        installation.
                                       Noise: Not required, but
                                        recommended for initial
                                        installation.
Sec.   1065.307: Linearity...........  Speed: Upon initial installation,
                                        within 370 days before testing
                                        and after major maintenance.
                                       Torque: Upon initial
                                        installation, within 370 days
                                        before testing and after major
                                        maintenance.
                                       Electrical power: Upon initial
                                        installation, within 370 days
                                        before testing and after major
                                        maintenance.
                                       Clean gas and diluted exhaust
                                        flows: Upon initial
                                        installation, within 370 days
                                        before testing and after major
                                        maintenance, unless flow is
                                        verified by propane check or by
                                        carbon or oxygen balance.

[[Page 56513]]

 
                                       Raw exhaust flow: Upon initial
                                        installation, within 185 days
                                        before testing and after major
                                        maintenance, unless flow is
                                        verified by propane check or by
                                        carbon or oxygen balance.
                                       Gas analyzers: Upon initial
                                        installation, within 35 days
                                        before testing and after major
                                        maintenance.
                                       FTIR and photoacoustic analyzers:
                                        Upon initial installation,
                                        within 370 days before testing
                                        and after major maintenance.
                                       GC-ECD: Upon initial installation
                                        and after major maintenance.
                                       PM balance: Upon initial
                                        installation, within 370 days
                                        before testing and after major
                                        maintenance.
                                       Stand-alone pressure and
                                        temperature: Upon initial
                                        installation, within 370 days
                                        before testing and after major
                                        maintenance.
Sec.   1065.308: Continuous gas        Upon initial installation or
 analyzer system response and           after system modification that
 updating-recording verification--for   would effect response.
 gas analyzers not continuously
 compensated for other gas species.
Sec.   1065.309: Continuous gas        Upon initial installation or
 analyzer system-response and           after system modification that
 updating-recording verification--for   would effect response.
 gas analyzers continuously
 compensated for other gas species.
Sec.   1065.310: Torque..............  Upon initial installation and
                                        after major maintenance.
Sec.   1065.315: Pressure,             Upon initial installation and
 temperature, dewpoint.                 after major maintenance.
Sec.   1065.320: Fuel flow...........  Upon initial installation and
                                        after major maintenance.
Sec.   1065.325: Intake flow.........  Upon initial installation and
                                        after major maintenance.
Sec.   1065.330: Exhaust flow........  Upon initial installation and
                                        after major maintenance.
Sec.   1065.340: Diluted exhaust flow  Upon initial installation and
 (CVS).                                 after major maintenance.
Sec.   1065.341: CVS and batch         Upon initial installation, within
 sampler verification \b\.              35 days before testing, and
                                        after major maintenance.
Sec.   1065.345: Vacuum leak.........  Before each laboratory test
                                        according to subpart F of this
                                        part and before each field test
                                        according to subpart J of this
                                        part.
Sec.   1065.350: CO2 NDIR H2O          Upon initial installation and
 interference.                          after major maintenance.
Sec.   1065.355: CO NDIR CO2 and H2O   Upon initial installation and
 interference.                          after major maintenance.
Sec.   1065.360: FID calibration, THC  Calibrate all FID analyzers: upon
 FID optimization, and THC FID          initial installation and after
 verification..                         major maintenance.
                                       Optimize and determine CH4
                                        response for THC FID analyzers:
                                         upon initial installation and
                                          after major maintenance.
                                         Verify CH4 response for THC FID
                                          analyzers: upon initial
                                          installation, within 185 days
                                          before testing, and after
                                          major maintenance.
Sec.   1065.362: Raw exhaust FID O2    For all FID analyzers: upon
 interference.                          initial installation, and after
                                        major maintenance.
                                       For THC FID analyzers: upon
                                        initial installation, after
                                        major maintenance, and after FID
                                        optimization according to Sec.
                                        1065.360.
Sec.   1065.365: Nonmethane cutter     Upon initial installation, within
 penetration.                           185 days before testing, and
                                        after major maintenance.
Sec.   1065.370: CLD CO2 and H2O       Upon initial installation and
 quench.                                after major maintenance.
Sec.   1065.372: NDUV HC and H2O       Upon initial installation and
 interference.                          after major maintenance.
Sec.   1065.375: N2O analyzer          Upon initial installation and
 interference.                          after major maintenance.
Sec.   1065.376: Chiller NO2           Upon initial installation and
 penetration.                           after major maintenance.
Sec.   1065.378: NO2-to-NO converter   Upon initial installation, within
 conversion.                            35 days before testing, and
                                        after major maintenance.
Sec.   1065.390: PM balance and        Independent verification: upon
 weighing.                              initial installation, within 370
                                        days before testing, and after
                                        major maintenance.
                                       Zero, span, and reference sample
                                        verifications: within 12 hours
                                        of weighing, and after major
                                        maintenance.
Sec.   1065.395: Inertial PM balance   Independent verification: upon
 and weighing.                          initial installation, within 370
                                        days before testing, and after
                                        major maintenance.
                                       Other verifications: upon initial
                                        installation and after major
                                        maintenance.
------------------------------------------------------------------------
\a\ Perform calibrations and verifications more frequently, according to
  measurement system manufacturer instructions and good engineering
  judgment.
\b\ The CVS verification described in Sec.   1065.341 is not required
  for systems that agree within  2% based on a chemical
  balance of carbon or oxygen of the intake air, fuel, and diluted
  exhaust.

0
59. Section 1065.307 is amended by revising paragraph (c)(6) to read as 
follows:


Sec.  1065.307  Linearity verification.

* * * * *
    (c) * * *
    (6) For all measured quantities, use instrument manufacturer 
recommendations and good engineering judgment to select reference 
values, yrefi, that cover a range of values that you expect 
would prevent extrapolation beyond these values during emission 
testing. We recommend selecting a zero reference signal as one of the 
reference values of the linearity verification. For stand-alone 
pressure and temperature linearity verifications and for GC-ECD 
linearity verifications, we recommend at least three reference values. 
For all other linearity verifications select at least ten reference 
values.
* * * * *

0
60. Section 1065.365 is amended by revising paragraphs (d), (e), and 
(f) to read as follows:

[[Page 56514]]

Sec.  1065.365  Nonmethane cutter penetration fractions.

* * * * *
    (d) Procedure for a FID calibrated with the NMC. The method 
described in this paragraph (d) is recommended over the procedures 
specified in paragraphs (e) and (f) of this section. If your FID 
arrangement is such that a FID is always calibrated to measure 
CH4 with the NMC, then span that FID with the NMC using a 
CH4 span gas, set the product of that FID's CH4 
response factor and CH4 penetration fraction, 
RFPFCH4[NMC-FID], equal to 1.0 for all emission 
calculations, and determine its combined ethane 
(C2H6) response factor and penetration fraction, 
RFPFC2H6[NMC-FID] as follows:
    (1) Select CH4 and C2H6 analytical 
gas mixtures and ensure that both mixtures meet the specifications of 
Sec.  1065.750. Select a CH4 concentration that you would 
use for spanning the FID during emission testing and select a 
C2H6 concentration that is typical of the peak 
NMHC concentration expected at the hydrocarbon standard or equal to the 
THC analyzer's span value.
    (2) Start, operate, and optimize the nonmethane cutter according to 
the manufacturer's instructions, including any temperature 
optimization.
    (3) Confirm that the FID analyzer meets all the specifications of 
Sec.  1065.360.
    (4) Start and operate the FID analyzer according to the 
manufacturer's instructions.
    (5) Zero and span the FID with the nonmethane cutter as you would 
during emission testing. Span the FID through the cutter by using 
CH4 span gas.
    (6) Introduce the C2H6 analytical gas mixture 
upstream of the nonmethane cutter. Use good engineering judgment to 
address the effect of hydrocarbon contamination if your point of 
introduction is vastly different from the point of zero/span gas 
introduction.
    (7) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the nonmethane cutter and 
to account for the analyzer's response.
    (8) While the analyzer measures a stable concentration, record 30 
seconds of sampled data. Calculate the arithmetic mean of these data 
points.
    (9) Divide the mean C2H6 concentration by the 
reference concentration of C2H6, converted to a 
C1 basis. The result is the C2H6 
combined response factor and penetration fraction, 
RFPFC2H6[NMC-FID]. Use this combined response factor and 
penetration fraction and the product of the CH4 response 
factor and CH4 penetration fraction, 
RFPFCH4[NMC-FID], set to 1.0 in emission calculations 
according to Sec.  1065.660(b)(2)(i), Sec.  1065.660(c)(1)(i), or Sec.  
1065.665, as applicable.
    (e) Procedure for a FID calibrated with propane, bypassing the NMC. 
If you use a single FID for THC and CH4 determination with 
an NMC that is calibrated with propane, C3H8, by 
bypassing the NMC, determine its penetration fractions, 
PFC2H6[NMC-FID] and PFCH4[NMC-FID], as follows:
    (1) Select CH4 and C2H6 analytical 
gas mixtures and ensure that both mixtures meet the specifications of 
Sec.  1065.750. Select a CH4 concentration that you would 
use for spanning the FID during emission testing and select a 
C2H6 concentration that is typical of the peak 
NMHC concentration expected at the hydrocarbon standard or equal to the 
THC analyzer's span value.
    (2) Start and operate the nonmethane cutter according to the 
manufacturer's instructions, including any temperature optimization.
    (3) Confirm that the FID analyzer meets all the specifications of 
Sec.  1065.360.
    (4) Start and operate the FID analyzer according to the 
manufacturer's instructions.
    (5) Zero and span the FID as you would during emission testing. 
Span the FID by bypassing the cutter and by using 
C3H8 span gas.
    (6) Introduce the C2H6 analytical gas mixture 
upstream of the nonmethane cutter. Use good engineering judgment to 
address the effect of hydrocarbon contamination if your point of 
introduction is vastly different from the point of zero/span gas 
introduction.
    (7) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the nonmethane cutter and 
to account for the analyzer's response.
    (8) While the analyzer measures a stable concentration, record 30 
seconds of sampled data. Calculate the arithmetic mean of these data 
points.
    (9) Reroute the flow path to bypass the nonmethane cutter, 
introduce the C2H6 analytical gas mixture, and 
repeat the steps in paragraph (e)(7) through (e)(8) of this section.
    (10) Divide the mean C2H6 concentration 
measured through the nonmethane cutter by the mean 
C2H6 concentration measured after bypassing the 
nonmethane cutter. The result is the C2H6 
penetration fraction, PFC2H6[NMC-FID]. Use this penetration 
fraction according to Sec.  1065.660(b)(2)(ii), Sec.  
1065.660(c)(1)(ii), or Sec.  1065.665, as applicable.
    (11) Repeat the steps in paragraphs (e)(6) through (e)(10) of this 
section, but with the CH4 analytical gas mixture instead of 
C2H6. The result will be the CH4 
penetration fraction, PFCH4[NMC-FID]. Use this penetration 
fraction according to Sec.  1065.660(b)(2)(ii), Sec.  
1065.660(c)(1)(ii), or Sec.  1065.665, as applicable.
    (f) Procedure for a FID calibrated with methane, bypassing the NMC. 
If you use a FID with an NMC that is calibrated with methane, 
CH4, by bypassing the NMC, determine its combined ethane 
(C2H6) response factor and penetration fraction, 
RFPFC2H6[NMC-FID], as well as its CH4 penetration 
fraction, PFCH4[NMC-FID], as follows:
    (1) Select CH4 and C2H6 analytical 
gas mixtures and ensure that both mixtures meet the specifications of 
Sec.  1065.750. Select a CH4 concentration that you would 
use for spanning the FID during emission testing and select a 
C2H6 concentration that is typical of the peak 
NMHC concentration expected at the hydrocarbon standard or equal to the 
THC analyzer's span value.
    (2) Start and operate the nonmethane cutter according to the 
manufacturer's instructions, including any temperature optimization.
    (3) Confirm that the FID analyzer meets all the specifications of 
Sec.  1065.360.
    (4) Start and operate the FID analyzer according to the 
manufacturer's instructions.
    (5) Zero and span the FID as you would during emission testing. 
Span the FID by bypassing the cutter and by using CH4 span 
gas. Note that you must span the FID on a C1 basis. For 
example, if your span gas has a methane reference value of 100 [mu]mol/
mol, the correct FID response to that span gas is 100 [mu]mol/mol 
because there is one carbon atom per CH4 molecule.
    (6) Introduce the C2H6 analytical gas mixture 
upstream of the nonmethane cutter. Use good engineering judgment to 
address the effect of hydrocarbon contamination if your point of 
introduction is vastly different from the point of zero/span gas 
introduction.
    (7) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the nonmethane cutter and 
to account for the analyzer's response.
    (8) While the analyzer measures a stable concentration, record 30 
seconds of sampled data. Calculate the arithmetic mean of these data 
points.
    (9) Divide the mean C2H6 concentration by the 
reference concentration of C2H6, converted to a 
C1 basis. The result is the C2H6 
combined response factor and penetration fraction, 
RFPFC2H6[NMC-FID]. Use this combined response factor and 
penetration fraction according to Sec.  1065.660(b)(2)(iii),

[[Page 56515]]

Sec.  1065.660(c)(1)(iii), or Sec.  1065.665, as applicable.
    (10) Introduce the CH4 analytical gas mixture upstream 
of the nonmethane cutter. Use good engineering judgment to address the 
effect of hydrocarbon contamination if your point of introduction is 
vastly different from the point of zero/span gas introduction.
    (11) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the nonmethane cutter and 
to account for the analyzer's response.
    (12) While the analyzer measures a stable concentration, record 30 
seconds of sampled data. Calculate the arithmetic mean of these data 
points.
    (13) Reroute the flow path to bypass the nonmethane cutter, 
introduce the CH4 analytical gas mixture, and repeat the 
steps in paragraphs (e)(11) and (12) of this section.
    (14) Divide the mean CH4 concentration measured through 
the nonmethane cutter by the mean CH4 concentration measured 
after bypassing the nonmethane cutter. The result is the CH4 
penetration fraction, PFCH4[NMC-FID]. Use this penetration 
fraction according to Sec.  1065.660(b)(2)(iii), Sec.  
1065.660(c)(1)(iii), or Sec.  1065.665, as applicable.

0
61. The center heading ``NOX MEASUREMENTS'' preceding Sec.  
1065.370 is revised to read as follows:

NOX and N2O Measurements

0
62. A new Sec.  1065.375 is added under the center header 
``NOX and N2O Measurements'' to read as follows:


Sec.  1065.375  Interference verification for N2O analyzers.

    (a) Scope and frequency. See Sec.  1065.275 to determine whether 
you need to verify the amount of interference after initial analyzer 
installation and after major maintenance.
    (b) Measurement principles. Interference gasses can positively 
interfere with certain analyzers by causing a response similar to 
N2O. If the analyzer uses compensation algorithms that 
utilize measurements of other gases to meet this interference 
verification, simultaneously conduct these other measurements to test 
the compensation algorithms during the analyzer interference 
verification.
    (c) System requirements. Analyzers must have combined interference 
that is within (0.0  1.0) [mu]mol/mol. We strongly 
recommend a lower interference that is within (0.0  0.5) 
[mu]mol/mol.
    (d) Procedure. Perform the interference verification as follows:
    (1) Start, operate, zero, and span the N2O analyzer as 
you would before an emission test. If the sample is passed through a 
dryer during emission testing, you may run this verification test with 
the dryer if it meets the requirements of Sec.  1065.342. Operate the 
dryer at the same conditions as you will for an emission test. You may 
also run this verification test without the sample dryer.
    (2) Create a humidified test gas by bubbling a multi component span 
gas that incorporates the target interference species and meets the 
specifications in Sec.  1065.750 through distilled water in a sealed 
vessel. If the sample is not passed through a dryer during emission 
testing, control the vessel temperature to generate an H2O 
level at least as high as the maximum expected during emission testing. 
If the sample is passed through a dryer during emission testing, 
control the vessel temperature to generate an H2O level at 
least as high as the level determined in Sec.  1065.145(e)(2) for that 
dryer. Use interference span gas concentrations that are at least as 
high as the maximum expected during testing.
    (3) Introduce the humidified interference test gas into the sample 
system. You may introduce it downstream of any sample dryer, if one is 
used during testing.
    (4) If the sample is not passed through a dryer during this 
verification test, measure the water mole fraction, xH2O, of 
the humidified interference test gas as close as possible to the inlet 
of the analyzer. For example, measure dewpoint, Tdew, and 
absolute pressure, ptotal, to calculate xH2O. 
Verify that the water content meets the requirement in paragraph (d)(2) 
of this section. If the sample is passed through a dryer during this 
verification test, you must verify that the water content of the 
humidified test gas downstream of the vessel meets the requirement in 
paragraph (d)(2) of this section based on either direct measurement of 
the water content (e.g., dewpoint and pressure) or an estimate based on 
the vessel pressure and temperature. Use good engineering judgment to 
estimate the water content. For example, you may use previous direct 
measurements of water content to verify the vessel's level of 
saturation.
    (5) If a sample dryer is not used in this verification test, use 
good engineering judgment to prevent condensation in the transfer 
lines, fittings, or valves from the point where xH2O is 
measured to the analyzer. We recommend that you design your system so 
that the wall temperatures in the transfer lines, fittings, and valves 
from the point where  xH2O is measured to the analyzer are 
at least 5 [deg]C above the local sample gas dewpoint.
    (6) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the transfer line and to 
account for analyzer response.
    (7) While the analyzer measures the sample's concentration, record 
its output for 30 seconds. Calculate the arithmetic mean of this data.
    (8) The analyzer meets the interference verification if the result 
of paragraph (d)(7) of this section meets the tolerance in paragraph 
(c) of this section.
    (9) You may also run interference procedures separately for 
individual interference gases. If the interference gas levels used are 
higher than the maximum levels expected during testing, you may scale 
down each observed interference value by multiplying the observed 
interference by the ratio of the maximum expected concentration value 
to the actual value used during this procedure. You may run separate 
interference concentrations of H2O (down to 0.025 mol/mol 
H2O content) that are lower than the maximum levels expected 
during testing, but you must scale up the observed H2O 
interference by multiplying the observed interference by the ratio of 
the maximum expected H2O concentration value to the actual 
value used during this procedure. The sum of the scaled interference 
values must meet the tolerance specified in paragraph (c) of this 
section.

Subpart F--[Amended]

0
63. Section 1065.550 is amended by revising paragraphs (b) introductory 
text and (b)(1), adding and reserving paragraph (b)(3), and adding 
paragraph (b)(4) to read as follows:


Sec.  1065.550  Gas analyzer range validation, drift validation, and 
drift correction.

* * * * *
    (b) Drift validation and drift correction. Calculate two sets of 
brake-specific emission results for each test interval. Calculate one 
set using the data before drift correction and calculate the other set 
after correcting all the data for drift according to Sec.  1065.672. 
Use the two sets of brake-specific emission results to validate the 
duty cycle for drift as follows:
    (1) The duty cycle is validated for drift if you satisfy one of the 
following criteria:
    (i) For each test interval of the duty cycle and for each measured 
exhaust constituent, the difference between the uncorrected and the 
corrected brake-

[[Page 56516]]

specific emission values over the test interval is within 4% of the uncorrected value or applicable emission standard, 
whichever is greater. This requirement also applies for CO2, 
whether or not an emission standard applies for CO2. Where 
no emission standard applies for CO2, the difference must be 
within 4% of the uncorrected value. See paragraph (b)(4) of 
this section for exhaust constituents other than CO2 for 
which no emission standard applies.
    (ii) For the entire duty cycle and for each regulated pollutant, 
the difference between the uncorrected and corrected composite brake-
specific emission values over the entire duty cycle is within 4% of the uncorrected value or the applicable emission standard, 
whichever is greater. Note that for purposes of drift validation using 
composite brake-specific emission values over the entire duty cycle, 
leave unaltered any negative emission results over a given test 
interval (i.e., do not set them to zero). A third calculation of 
composite brake-specific emission values is required for final 
reporting. This calculation uses drift-corrected mass (or mass rate) 
values from each test interval and sets any negative mass (or mass 
rate) values to zero before calculating the composite brake-specific 
emission values over the entire duty cycle. This requirement also 
applies for CO2, whether or not an emission standard applies 
for CO2. Where no emission standard applies for 
CO2, the difference must be within 4% of the 
uncorrected value. See paragraph (b)(3) of this section for exhaust 
constituents other than CO2 for which no emission standard 
applies.
* * * * *
    (3) [Reserved]
    (4) The provisions of paragraph (b)(3) of this section apply for 
measurement of pollutants other than CO2 for which no 
emission standard applies. You may use measurements that do not meet 
the drift validation criteria specified in paragraph (b)(1) of this 
section. For example, this allowance may be appropriate for measuring 
and reporting very low concentrations of CH4 and 
N2O as long as no emission standard applies for these 
compounds.

Subpart G--[Amended]

0
64. Section 1065.601 is amended by revising paragraph (a)(1) to read as 
follows:


Sec.  1065.601  Overview.

    (a) * * *
    (1) Use the signals recorded before, during, and after an emission 
test to calculate brake-specific emissions of each measured exhaust 
constituent.
* * * * *

0
65. Section 1065.660 is amended by revising paragraphs (a), (b) 
introductory text, (b)(1), (b)(2), and (b)(3) introductory text, and 
adding paragraph (c) to read as follows:


Sec.  1065.660  THC, NMHC, and CH4 determination.

    (a) THC determination and THC/CH4 initial contamination 
corrections. (1) If we require you to determine THC emissions, 
calculate xTHC[THC-FID]cor using the initial THC 
contamination concentration xTHC[THC-FID]init from Sec.  
1065.520 as follows:
[GRAPHIC] [TIFF OMITTED] TR30OC09.179


Example:

xTHCuncor = 150.3 [micro]mol/mol
xTHCinit = 1.1 [micro]mol/mol
xTHCcor = 150.3-1.1
xTHCcor = 149.2 [micro]mol/mol

    (2) For the NMHC determination described in paragraph (b) of this 
section, correct xTHC[THC-FID] for initial HC contamination 
using Eq. 1065.660-1. You may correct xTHC[NMC-FID] for 
initial contamination of the CH4 sample train using Eq. 
1065.660-1, substituting in CH4 concentrations for THC.
    (3) For the CH4 determination described in paragraph (c) 
of this section, you may correct xTHC[NMC-FID] for initial 
contamination of the CH4 sample train using Eq. 1065.660-1, 
substituting in CH4 concentrations for THC.
    (b) NMHC determination. Use one of the following to determine NMHC 
concentration, xNMHC:
    (1) If you do not measure CH4, you may determine NMHC 
concentrations as described in Sec.  1065.650(c)(1)(vi).
    (2) For nonmethane cutters, calculate xNMHC using the 
nonmethane cutter's penetration fractions (PF) of CH4 and 
C2H6 from Sec.  1065.365, and using the HC 
contamination and dry-to-wet corrected THC concentration 
xTHC[THC-FID]cor as determined in paragraph (a) of this 
section.
    (i) Use the following equation for penetration fractions determined 
using an NMC configuration as outlined in Sec.  1065.365(d):
[GRAPHIC] [TIFF OMITTED] TR30OC09.180


Where:
xNMHC = concentration of NMHC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the NMC FID 
during sampling through the NMC.
RFCH4[THC-FID] = response factor of THC FID to 
CH4, according to Sec.  1065.360(d).
RFPFC2H6[NMC-FID] = nonmethane cutter combined ethane 
response factor and penetration fraction, according to Sec.  
1065.365(d).
Example:
xTHC[THC-FID]cor = 150.3 [mu]mol/mol
xTHC[NMC-FID]cor = 20.5 [mu]mol/mol
RFPFC2H6[NMC-FID] = 0.019
RFCH4[THC-FID] = 1.05
[GRAPHIC] [TIFF OMITTED] TR30OC09.181

xNMHC = 131.4 [mu]mol/mol

    (ii) For penetration fractions determined using an NMC 
configuration as outlined in section Sec.  1065.365(e), use the 
following equation:

[[Page 56517]]

[GRAPHIC] [TIFF OMITTED] TR30OC09.182


Where:
xNMHC = concentration of NMHC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
PFCH4[NMC-FID] = nonmethane cutter CH4 
penetration fraction, according to Sec.  1065.365(e).
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the THC FID 
during sampling through the NMC.
PFC2H6[NMC-FID] = nonmethane cutter ethane penetration 
fraction, according to Sec.  1065.365(e).

Example:
xTHC[THC-FID]cor = 150.3 [mu]mol/mol
PFCH4[NMC-FID] = 0.990
xTHC[NMC-FID]cor = 20.5 [mu]mol/mol
PFC2H6[NMC-FID] = 0.020
[GRAPHIC] [TIFF OMITTED] TR30OC09.183

xNMHC = 132.3 [mu]mol/mol

    (iii) For penetration fractions determined using an NMC 
configuration as outlined in Sec.  1065.365(f), use the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR30OC09.184


Where:
xNMHC = concentration of NMHC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
PFCH4[NMC-FID] = nonmethane cutter CH4 
penetration fraction, according to Sec.  1065.365(f).
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the THC FID 
during sampling through the NMC.
RFPFC2H6[NMC-FID] = nonmethane cutter CH4 
combined ethane response factor and penetration fraction, according 
to Sec.  1065.365(f).
RFCH4[THC-FID] = response factor of THC FID to 
CH4, according to Sec.  1065.360(d).
Example:
xTHC[THC-FID]cor = 150.3 [mu]mol/mol
PFCH4[NMC-FID] = 0.990
xTHC[NMC-FID]cor = 20.5 [mu]mol/mol
RFPFC2H6[NMC-FID] = 0.019
RFCH4[THC-FID] = 0.980
[GRAPHIC] [TIFF OMITTED] TR30OC09.185

xNMHC = 132.5 [mu]mol/mol

    (3) For a gas chromatograph, calculate xNMHC using 
the THC analyzer's response factor (RF) for CH4, from 
Sec.  1065.360, and the HC contamination and dry-to-wet corrected 
initial THC concentration xTHC[THC-FID]cor as determined 
in paragraph (a) of this section as follows:
* * * * *
    (c) CH4 determination. Use one of the following 
methods to determine CH4 concentration, xCH4:
    (1) For nonmethane cutters, calculate xCH4 using the 
nonmethane cutter's penetration fractions (PF) of CH4 and 
C2H6 from Sec.  1065.365, using the dry-to-wet 
corrected CH4 concentration xTHC[NMC-FID]cor 
as determined in paragraph (a) of this section and optionally using 
the CH4 contamination correction under paragraph (a) of 
this section.
    (i) Use the following equation for penetration fractions 
determined using an NMC configuration as outlined in Sec.  
1065.365(d):
[GRAPHIC] [TIFF OMITTED] TR30OC09.186


Where:
xCH4 = concentration of CH4.
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the NMC FID 
during sampling through the NMC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
RFPFC2H6[NMC-FID] = the combined ethane response factor 
and penetration fraction of the nonmethane cutter, according to 
Sec.  1065.365(d).
RFCH4[THC-FID] = response factor of THC FID to 
CH4, according to Sec.  1065.360(d).
Example:
xTHC[NMC-FID]cor = 10.4 [mu]mol/mol
xTHC[THC-FID]cor = 150.3 [mu]mol/mol
RFPFC2H6[NMC-FID] = 0.019
RFCH4[THC-FID] = 1.05
[GRAPHIC] [TIFF OMITTED] TR30OC09.187

xCH4 = 7.69 [mu]mol/mol

    (ii) For penetration fractions determined using an NMC 
configuration as outlined in Sec.  1065.365(e), use the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR30OC09.188


Where:
xCH4 = concentration of CH4.
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the NMC FID 
during sampling through the NMC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
PFC2H6[NMC-FID] = nonmethane cutter ethane penetration 
fraction, according to Sec.  1065.365(e).
RFCH4[THC-FID] = response factor of THC FID to 
CH4, according to Sec.  1065.360(d).
PFCH4[NMC-FID] = nonmethane cutter CH4 
penetration fraction, according to Sec.  1065.365(e).
Example:
xTHC[NMC-FID]cor = 10.4 [mu]mol/mol
xTHC[THC-FID]cor = 150.3 [mu]mol/mol
PFC2H6[NMC-FID] = 0.020
RFCH4[THC-FID] = 1.05

[[Page 56518]]

PFCH4[NMC-FID] = 0.990
[GRAPHIC] [TIFF OMITTED] TR30OC09.189

xCH4 = 7.25 [mu]mol/mol

    (iii) For penetration fractions determined using an NMC 
configuration as outlined in Sec.  1065.365(f), use the following 
equation:
[GRAPHIC] [TIFF OMITTED] TR30OC09.190

Where:
xCH4 = concentration of CH4.
xTHC[NMC-FID]cor = concentration of THC, HC contamination 
(optional) and dry-to-wet corrected, as measured by the NMC FID 
during sampling through the NMC.
xTHC[THC-FID]cor = concentration of THC, HC contamination 
and dry-to-wet corrected, as measured by the THC FID during sampling 
while bypassing the NMC.
RFPFC2H6[NMC-FID] = the combined ethane response factor 
and penetration fraction of the nonmethane cutter, according to 
Sec.  1065.365(f).
PFCH4[NMC-FID] = nonmethane cutter CH4 
penetration fraction, according to Sec.  1065.365(f).
RFCH4[THC-FID] = response factor of THC FID to 
CH4, according to Sec.  1065.360(d).
Example:

xTHC[NMC-FID]cor = 10.4 [micro]mol/mol
xTHC[THC-FID]cor = 150.3 [micro]mol/mol
RFPFC2H6[NMC-FID] = 0.019
PFCH4[NMC-FID] = 0.990
RFCH4[THC-FID] = 1.05
[GRAPHIC] [TIFF OMITTED] TR30OC09.191

xCH4 = 7.78 [micro]mol/mol

    (2) For a gas chromatograph, xCH4 is the actual dry-
to-wet corrected CH4 concentration as measured by the 
analyzer.

Subpart H--[Amended]

0
66. Section 1065.750 is amended by revising paragraph (a)(1)(ii) and 
adding paragraph (a)(3)(xi) to read as follows:


Sec.  1065.750  Analytical Gases.

* * * * *
    (a) * * *
    (1) * * *
    (ii) Contamination as specified in the following table:

 Table 1 of Sec.   1065.750--General specifications for purified gases.
------------------------------------------------------------------------
                                  Purified synthetic
           Constituent                  air \1\         Purified N2\1\
------------------------------------------------------------------------
THC (C1 equivalent).............  <= 0.05 [mu]mol/    <= 0.05 [mu]mol/
                                   mol.                mol.
CO..............................  <= 1 [mu]mol/mol..  <= 1 [mu]mol/mol.
CO2.............................  <= 10 [mu]mol/mol.  <= 10 [mu]mol/mol.
O2..............................  0.205 to 0.215 mol/ <= 2 [mu]mol/mol.
                                   mol.
NOX.............................  <= 0.02 [mu]mol/    <= 0.02 [mu]mol/
                                   mol.                mol.
N2O\2\..........................  <= 0.05 [mu]mol/    <= 0.05 [mu]mol/
                                   mol.                mol.
------------------------------------------------------------------------
\1\ We do not require these levels of purity to be NIST-traceable.
\2\ The N2O limit applies only if the standard-setting part requires you
  to report N2O.

* * * * *
    (3) * * *
    (xi) N2O, balance purified synthetic air.
* * * * *

0
67. Section 1065.1001 is amended by revising the definition for 
``Oxides of nitrogen'' to read as follows:


Sec.  1065.1001  Definitions.

* * * * *
    Oxides of nitrogen means NO and NO2 as measured by the 
procedures specified in Sec.  1065.270. Oxides of nitrogen are 
expressed quantitatively as if the NO is in the form of NO2, 
such that you use an effective molar mass for all oxides of nitrogen 
equivalent to that of NO2.
* * * * *

0
68. Section 1065.1005 is amended by revising paragraphs (b), (f)(2), 
and (g) to read as follows:


Sec.  1065.1005  Symbols, abbreviations, acronyms, and units of 
measure.

* * * * *
    (b) Symbols for chemical species. This part uses the following 
symbols for chemical species and exhaust constituents:

------------------------------------------------------------------------
                 Symbol                              Species
------------------------------------------------------------------------
Ar.....................................  argon.
C......................................  carbon.
CH4....................................  methane.
C2H6...................................  ethane.
C3H8...................................  propane.
C4H10..................................  butane.
C5H12..................................  pentane.
CO.....................................  carbon monoxide.
CO2....................................  carbon dioxide.
H......................................  atomic hydrogen.
H2.....................................  molecular hydrogen.
H2O....................................  water.
He.....................................  helium.
\85\Kr.................................  krypton 85.
N2.....................................  molecular nitrogen.
NMHC...................................  nonmethane hydrocarbon.
NMHCE..................................  nonmethane hydrocarbon
                                          equivalent.
NO.....................................  nitric oxide.
NO2....................................  nitrogen dioxide.
NOX....................................  oxides of nitrogen.
N2O....................................  nitrous oxide.
NOTHC..................................  nonoxygenated hydrocarbon.
O2.....................................  molecular oxygen.
OHC....................................  oxygenated hydrocarbon.
\210\Po................................  polonium 210.
PM.....................................  particulate mass.
S......................................  sulfur.
SO2....................................  sulfur dioxide.
THC....................................  total hydrocarbon.
ZrO2...................................  zirconium dioxide.
------------------------------------------------------------------------

* * * * *
    (f) * * *
    (2) This part uses the following molar masses or effective molar 
masses of chemical species:

[[Page 56519]]



------------------------------------------------------------------------
                                                              g/mol (10-
              Symbol                       Quantity          3.kg\.\mol-
                                                                  1)
------------------------------------------------------------------------
Mair.............................  molar mass of dry air...     28.96559
MAr..............................  molar mass of argon.....       39.948
MC...............................  molar mass of carbon....      12.0107
MCO..............................  molar mass of carbon          28.0101
                                    monoxide.
MCO2.............................  molar mass of carbon          44.0095
                                    dioxide.
MH...............................  molar mass of atomic          1.00794
                                    hydrogen.
MH2..............................  molar mass of molecular       2.01588
                                    hydrogen.
MH2O.............................  molar mass of water.....     18.01528
MHe..............................  molar mass of helium....     4.002602
MN...............................  molar mass of atomic          14.0067
                                    nitrogen.
MN2..............................  molar mass of molecular       28.0134
                                    nitrogen.
MNMHC............................  effective molar mass of     13.875389
                                    nonmethane hydrocarbon
                                    \2\.
MNMHCE...........................  effective molar mass of     13.875389
                                    nonmethane equivalent
                                    hydrocarbon \2\.
MNOx.............................  effective molar mass of       46.0055
                                    oxides of nitrogen \3\.
MN2O.............................  effective molar mass of       44.0128
                                    nitrous oxide.
MO...............................  molar mass of atomic          15.9994
                                    oxygen.
MO2..............................  molar mass of molecular       31.9988
                                    oxygen.
MC3H8............................  molar mass of propane...     44.09562
MS...............................  molar mass of sulfur....       32.065
MTHC.............................  effective molar mass of     13.875389
                                    total hydrocarbon \2\.
MTHCE............................  effective molar mass of     13.875389
                                    total hydrocarbon
                                    equivalent \2\.
------------------------------------------------------------------------
\1\ See paragraph (f)(1) of this section for the composition of dry air
\2\ The effective molar masses of THC, THCE, NMHC, and NMHCE are defined
  by an atomic hydrogen-to-carbon ratio, [alpha], of 1.85
\3\ The effective molar mass of NOx is defined by the molar mass of
  nitrogen dioxide, NO2

* * * * *
    (g) Other acronyms and abbreviations. This part uses the following 
additional abbreviations and acronyms:

ASTM American Society for Testing and Materials.
BMD bag mini-diluter.
BSFC brake-specific fuel consumption.
CARB California Air Resources Board.
CFR Code of Federal Regulations.
CFV critical-flow venturi.
CI compression-ignition.
CITT Curb Idle Transmission Torque.
CLD chemiluminescent detector.
CVS constant-volume sampler.
DF deterioration factor.
ECM electronic control module.
EFC electronic flow control.
EGR exhaust gas recirculation.
EPA Environmental Protection Agency.
FEL Family Emission Limit
FID flame-ionization detector.
GC gas chromatograph.
GC-ECD gas chromatograph with an electron-capture detector.
IBP initial boiling point.
ISO International Organization for Standardization.
LPG liquefied petroleum gas.
NDIR nondispersive infrared.
NDUV nondispersive ultraviolet.
NIST National Institute for Standards and Technology.
PDP positive-displacement pump.
PEMS portable emission measurement system.
PFD partial-flow dilution.
PMP Polymethylpentene.
pt. a single point at the mean value expected at the standard.
PTFE polytetrafluoroethylene (commonly known as TeflonTM).
RE rounding error.
RMC ramped-modal cycle.
RMS root-mean square.
RTD resistive temperature detector.
SSV subsonic venturi.
SI spark-ignition.
UCL upper confidence limit.
UFM ultrasonic flow meter.
U.S.C. United States Code.

[FR Doc. E9-23315 Filed 10-29-09; 8:45 am]
BILLING CODE 6560-50-P