[Federal Register Volume 74, Number 68 (Friday, April 10, 2009)]
[Proposed Rules]
[Pages 16448-16731]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: E9-5711]



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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; Proposed Rule

  Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / 
Proposed Rules  

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Parts 86, 87, 89, 90, 94, 98, 600, 1033, 1039, 1042, 1045, 
1048, 1051, 1054, and 1065

[EPA-HQ-OAR-2008-0508; FRL-8782-1]
RIN 2060-A079


Mandatory Reporting of Greenhouse Gases

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA is proposing a regulation to require reporting of 
greenhouse gas emissions from all sectors of the economy. The rule 
would apply to fossil fuel suppliers and industrial gas suppliers, as 
well as to direct greenhouse gas emitters. The proposed rule does not 
require control of greenhouse gases, rather it requires only that 
sources above certain threshold levels monitor and report emissions.

DATES: Comments must be received on or before June 9, 2009. There will 
be two public hearings. One hearing was held on April 6 and 7, 2009, in 
the Washington, DC, area (One Potomac Yard, 2777 S. Crystal Drive, 
Arlington, VA 22202). One hearing will be on April 16, 2009 in 
Sacramento, CA (Sacramento Convention Center, 1400 J Street, 
Sacramento, CA 95814). The April 16, 2009 hearing will begin at 9 a.m. 
local time.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-HQ-
OAR-2008-0508, by one of the following methods:
     Federal eRulemaking Portal: http://www.regulations.gov. 
Follow the online instructions for submitting comments.
     E-mail: [email protected].
     Fax: (202) 566-1741.
     Mail: Environmental Protection Agency, EPA Docket Center 
(EPA/DC), Mailcode 6102T, Attention Docket ID No. EPA-HQ-OAR-2008-0508, 
1200 Pennsylvania Avenue, NW., Washington, DC 20460.
     Hand Delivery: EPA Docket Center, Public Reading Room, EPA 
West Building, Room 3334, 1301 Constitution Avenue, NW., Washington, DC 
20004. Such deliveries are only accepted during the Docket's normal 
hours of operation, and special arrangements should be made for 
deliveries of boxed information.
    Instructions: Direct your comments to Docket ID No. EPA-HQ-OAR-
2008-0508. EPA's policy is that all comments received will be included 
in the public docket without change and may be made available online at 
http://www.regulations.gov, including any personal information 
provided, unless the comment includes information claimed to be CBI or 
other information whose disclosure is restricted by statute. Do not 
submit information that you consider to be CBI or otherwise protected 
through http://www.regulations.gov or e-mail. The http://www.regulations.gov Web site is an ``anonymous access'' system, which 
means EPA will not know your identity or contact information unless you 
provide it in the body of your comment. If you send an e-mail comment 
directly to EPA without going through http://www.regulations.gov your 
e-mail address will be automatically captured and included as part of 
the comment that is placed in the public docket and made available on 
the Internet. If you submit an electronic comment, EPA recommends that 
you include your name and other contact information in the body of your 
comment and with any disk or CD-ROM you submit. If EPA cannot read your 
comment due to technical difficulties and cannot contact you for 
clarification, EPA may not be able to consider your comment. Electronic 
files should avoid the use of special characters, any form of 
encryption, and be free of any defects or viruses.
    Docket: All documents in the docket are listed in the http://www.regulations.gov index. Although listed in the index, some 
information is not publicly available, e.g., CBI or other information 
whose disclosure is restricted by statute. Certain other material, such 
as copyrighted material, will be publicly available only in hard copy. 
Publicly available docket materials are available either electronically 
in http://www.regulations.gov or in hard copy at the Air Docket, EPA/
DC, EPA West, Room B102, 1301 Constitution Ave., NW., Washington, DC. 
This Docket Facility is open from 8:30 a.m. to 4:30 p.m., Monday 
through Friday, excluding legal holidays. The telephone number for the 
Public Reading Room is (202) 566-1744, and the telephone number for the 
Air Docket is (202) 566-1742.

FOR FURTHER INFORMATION CONTACT: Carole Cook, Climate Change Division, 
Office of Atmospheric Programs (MC-6207J), Environmental Protection 
Agency, 1200 Pennsylvania Ave., NW., Washington, DC 20460; telephone 
number: (202) 343-9263; fax number: (202) 343-2342; e-mail address: 
[email protected]. For technical information, contact the 
Greenhouse Gas Reporting Rule Hotline at telephone number: (877) 444-
1188; or e-mail: [email protected]. To obtain information about the public 
hearings or to register to speak at the hearings, please go to http://www.epa.gov/climatechange/emissions/ghgrulemaking.html. Alternatively, 
contact Carole Cook at 202-343-9263.

SUPPLEMENTARY INFORMATION: 
    Additional Information on Submitting Comments: To expedite review 
of your comments by Agency staff, you are encouraged to send a separate 
copy of your comments, in addition to the copy you submit to the 
official docket, to Carole Cook, U.S. EPA, Office of Atmospheric 
Programs, Climate Change Division, Mail Code 6207-J, Washington, DC, 
20460, telephone (202) 343-9263, e-mail [email protected].
    Regulated Entities. The Administrator determines that this action 
is subject to the provisions of 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.''). This is a proposed 
regulation. If finalized, these regulations would affect owners and 
operators of fuel and chemicals suppliers, direct emitters of GHGs and 
manufacturers of mobile sources and engines. Regulated categories and 
entities would 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.

[[Page 16449]]

 
                                  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  Owners and operators of
                                                  Portland Cement
                                                  manufacturing plants.
Electronics Manufacturing......          334111  Microcomputers
                                                  manufacturing
                                                  facilities.
                                         334413  Semiconductor,
                                                  photovoltaic (solid-
                                                  state) device
                                                  manufacturing
                                                  facilities.
                                         334419  LCD unit screens
                                                  manufacturing
                                                  facilities.
                                 ..............  MEMS manufacturing
                                                  facilities.
Ethanol Production.............          325193  Ethyl alcohol
                                                  manufacturing
                                                  facilities.
Ferroalloy Production..........          331112  Ferroalloys
                                                  manufacturing
                                                  facilities.
Fluorinated GHG Production.....          325120  Industrial gases
                                                  manufacturing
                                                  facilities.
Food Processing................          311611  Meat processing
                                                  facilities.
                                         311411  Frozen fruit, juice,
                                                  and vegetable
                                                  manufacturing
                                                  facilities.
                                         311421  Fruit and vegetable
                                                  canning 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.
Magnesium Production...........          331419  Primary refiners of
                                                  nonferrous metals by
                                                  electrolytic methods.
                                         331492  Secondary magnesium
                                                  processing plants.
Nitric Acid Production.........          325311  Nitric acid
                                                  manufacturing
                                                  facilities.
Oil and Natural Gas Systems....          486210  Pipeline transportation
                                                  of natural gas.
                                         221210  Natural gas
                                                  distribution
                                                  facilities.
                                         325212  Synthetic rubber
                                                  manufacturing
                                                  facilities.
Petrochemical Production.......           32511  Ethylene dichloride
                                                  manufacturing
                                                  facilities.
                                         325199  Acrylonitrile, ethylene
                                                  oxide, methanol
                                                  manufacturing
                                                  facilities.
                                         325110  Ethylene manufacturing
                                                  facilities.
                                         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.
Sulfur Hexafluoride (SF6) from           221121  Electric bulk power
 Electrical Equipment.                            transmission and
                                                  control facilities.
Titanium Dioxide Production....          325188  Titanium dioxide
                                                  manufacturing
                                                  facilities.
Underground Coal Mines.........          212113  Underground anthracite
                                                  coal mining
                                                  operations.
                                         212112  Underground bituminous
                                                  coal mining
                                                  operations.
Zinc Production................          331419  Primary zinc refining
                                                  facilities.
                                         331492  Zinc dust reclaiming
                                                  facilities, recovering
                                                  from scrap and/or
                                                  alloying purchased
                                                  metals.
Landfills......................          562212  Solid waste landfills.
                                         221320  Sewage treatment
                                                  facilities.
                                         322110  Pulp mills.
                                         322121  Paper mills.
                                         322122  Newsprint mills.
                                         322130  Paperboard mills.
                                         311611  Meat processing
                                                  facilities.
                                         311411  Frozen fruit, juice,
                                                  and vegetable
                                                  manufacturing
                                                  facilities.
                                         311421  Fruit and vegetable
                                                  canning facilities.
Wastewater Treatment...........          322110  Pulp mills.
                                         322121  Paper mills.
                                         322122  Newsprint mills.
                                         322130  Paperboard mills.

[[Page 16450]]

 
                                         311611  Meat processing
                                                  facilities.
                                         311411  Frozen fruit, juice,
                                                  and vegetable
                                                  manufacturing
                                                  facilities.
                                         311421  Fruit and vegetable
                                                  canning facilities.
                                         325193  Ethanol manufacturing
                                                  facilities.
                                         324110  Petroleum refineries.
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 and Coal-              212111  Bituminous, and lignite
 based Products.                                  coal surface mining
                                                  facilities.
                                         212113  Anthracite coal mining
                                                  facilities.
                                         212112  Underground bituminous
                                                  coal mining
                                                  facilities.
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.................          336112  Light-duty vehicles and
                                                  trucks manufacturing
                                                  facilities.
                                         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 
regulated by this action. Table 1 of this preamble lists the types of 
facilities that EPA is now aware could be potentially affected by this 
action. Other types of facilities not listed in the table could also be 
subject to reporting requirements. To determine whether your facility 
is affected by this action, you should carefully examine the 
applicability criteria found in proposed 40 CFR part 98, subpart A. 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 would be affected by the proposed 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 would 
be relevant for all reporters.

            Table 2--Source Categories and Relevant Subparts
------------------------------------------------------------------------
  Source category (and main applicable   Subparts recommended for review
                subpart)                    to determine applicability
------------------------------------------------------------------------
General Stationary Fuel Combustion       General Stationary Fuel
 Sources.                                 Combustion.
Electricity Generation.................  General Stationary Fuel
                                          Combustion, Electricity
                                          Generation, Suppliers of CO2,
                                          Electric Power Systems.
Adipic Acid Production.................  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.
Electronics Manufacturing..............  General Stationary Fuel
                                          Combustion.
Ethanol Production.....................  General Stationary Fuel
                                          Combustion, Landfills,
                                          Wastewater Treatment.
Ferroalloy Production..................  General Stationary Fuel
                                          Combustion.
Fluorinated GHG Production.............  General Stationary Fuel
                                          Combustion.
Food Processing........................  General Stationary Fuel
                                          Combustion, Landfills,
                                          Wastewater Treatment.
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.
Lead Production........................  General Stationary Fuel
                                          Combustion.
Lime Manufacturing.....................  General Stationary Fuel
                                          Combustion.

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Magnesium Production...................  General Stationary Fuel
                                          Combustion.
Nitric Acid Production.................  General Stationary Fuel
                                          Combustion, Adipic Acid.
Oil and Natural Gas Systems............  General Stationary Fuel
                                          Combustion, Petroleum
                                          Refineries, Suppliers of
                                          Petroleum Products, Suppliers
                                          of Natural Gas and NGL,
                                          Suppliers of CO2.
Petrochemical Production...............  General Stationary Fuel
                                          Combustion, Ammonia, Petroleum
                                          Refineries.
Petroleum Refineries...................  General Stationary Fuel
                                          Combustion, Hydrogen,
                                          Landfills, Wastewater
                                          Treatment, Suppliers of
                                          Petroleum Products.
Phosphoric Acid Production.............  General Stationary Fuel
                                          Combustion.
Pulp and Paper Manufacturing...........  General Stationary Fuel
                                          Combustion, Landfills,
                                          Wastewater Treatment.
Silicon Carbide Production.............  General Stationary Fuel
                                          Combustion.
Soda Ash Manufacturing.................  General Stationary Fuel
                                          Combustion.
Sulfur Hexafluoride (SF6) from           General Stationary Fuel
 Electrical Equipment.                    Combustion.
Titanium Dioxide Production............  General Stationary Fuel
                                          Combustion.
Underground Coal Mines.................  General Stationary Fuel
                                          Combustion, Suppliers of Coal.
Zinc Production........................  General Stationary Fuel
                                          Combustion.
Landfills..............................  General Stationary Fuel
                                          Combustion, Ethanol, Food
                                          Processing, Petroleum
                                          Refineries, Pulp and Paper.
Wastewater Treatment...................  General Stationary Fuel
                                          Combustion, Ethanol, Food
                                          Processing, Petroleum
                                          Refineries, Pulp and Paper.
Manure Management......................  General Stationary Fuel
                                          Combustion.
Suppliers of Coal......................  General Stationary Fuel
                                          Combustion, Underground Coal
                                          Mines.
Suppliers of Coal-based Liquid Fuels...  Suppliers of Coal, Suppliers of
                                          Petroleum Products.
Suppliers of Petroleum Products........  General Stationary Fuel
                                          Combustion, Oil and Natural
                                          Gas Systems.
Suppliers of Natural Gas and NGLs......  General Stationary Fuel
                                          Combustion, Oil and Natural
                                          Gas Systems, 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.
------------------------------------------------------------------------

    Acronyms and Abbreviations. The following acronyms and 
abbreviations are used in this document.

A/C air conditioning
AERR Air Emissions Reporting Rule
ANPR advance notice of proposed rulemaking
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
CARB California Air Resources Board
CBI confidential business information
CCAR California Climate Action Registry
CDX central data exchange
CEMS continuous emission monitoring system(s)
CERR Consolidated Emissions Reporting Rule
cf cubic feet
CFCs chlorofluorocarbons
CFR Code of Federal Regulations
CH4 methane
CHP combined heat and power
CO2 carbon dioxide
CO2e CO2-equivalent
COD chemical oxygen demand
DE destruction efficiency
DOD U.S. Department of Defense
DOE U.S. Department of Energy
DOT U.S. Department of Transportation
DE destruction efficiency
DRE destruction or removal efficiency
ECOS Environmental Council of the States
EGUs electrical generating units
EIA Energy Information Administration
EISA Energy Independence and Security Act of 2007
EO Executive Order
EOR enhanced oil recovery
EPA U.S. Environmental Protection Agency
EU European Union
FTP Federal Test Procedure
FY2008 fiscal year 2008
GHG greenhouse gas
GWP global warming potential
HCFC-22 chlorodifluoromethane (or CHClF2)
HCFCs hydrochlorofluorocarbons
HCl hydrogen chloride
HFC-23 trifluoromethane (or CHF3)
HFCs hydrofluorocarbons
HFEs hydrofluorinated ethers
HHV higher heating value
ICR information collection request
IPCC Intergovernmental Panel on Climate Change
ISO International Organization for Standardization
kg kilograms
LandGEM Landfill Gas Emissions Model
LCD liquid crystal display
LDCs local natural gas distribution companies
LEDs light emitting diodes
LNG liquified natural gas
LPG liquified petroleum gas
MEMS microelectricomechanical system
mmBtu/hr millions British thermal units per hour
MMTCO2e million metric tons carbon dioxide equivalent
MSHA Mine Safety and Health Administration
MSW municipal solid waste
MW megawatts
N2O nitrous oxide
NAAQS national ambient air quality standard
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
NIOSH National Institute for Occupational Safety and Health
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
POTWs publicly owned treatment works
PSD Prevention of Significant Deterioration
PV photovoltaic
QA quality assurance
QA/QC quality assurance/quality control
QAPP quality assurance performance plan
RFA Regulatory Flexibility Act
RFS Renewable Fuel Standard
RGGI Regional Greenhouse Gas Initiative

[[Page 16452]]

RIA regulatory impact analysis
SAE Society of Automotive Engineers
SAR IPCC Second Assessment Report
SBREFA Small Business Regulatory Enforcement Fairness Act
SF6 sulfur hexafluoride
SFTP Supplemental Federal Test Procedure
SI international system of units
SIP State Implementation Plan
SSM startup, shutdown, and malfunction
TCR The Climate Registry
TOC total organic carbon
TRI Toxic Release Inventory
TSCA Toxics Substances Control Act
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
USDA U.S. Department of Agriculture
USGS U.S. Geological Survey
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. What Are GHGs?
    B. What Is Climate Change?
    C. Statutory Authority
    D. Inventory of U.S. GHG Emissions and Sinks
    E. How does this proposal relate to U.S. government and other 
climate change efforts?
    F. How does this proposal relate to EPA's Climate Change ANPR?
    G. How was this proposed rule developed?
II. Summary of Existing Federal, State, and Regional Emission 
Reporting Programs
    A. Federal Voluntary GHG Programs
    B. Federal Mandatory Reporting Programs
    C. EPA Emissions Inventories
    D. Regional and State Voluntary Programs for GHG Emissions 
Reporting
    E. State and Regional Mandatory Programs for GHG Emissions 
Reporting and Reduction
    F. How the Proposed Mandatory GHG Reporting Program is Different 
From the Federal and State Programs EPA Reviewed
III. Summary of the General Requirements of the Proposed Rule
    A. Who must report?
    B. Schedule for Reporting
    C. What do I have to report?
    D. How do I submit the report?
    E. What records must I retain?
IV. Rationale for the General Reporting, Recordkeeping and 
Verification Requirements That Apply to All Source Categories
    A. Rationale for Selection of GHGs To Report
    B. Rationale for Selection of Source Categories To Report
    C. Rationale for Selection of Thresholds
    D. Rationale for Selection of Level of Reporting
    E. Rationale for Selecting the Reporting Year
    F. Rationale for Selecting the Frequency of Reporting
    G. Rationale for the Emissions Information to Report
    H. Rationale for Monitoring Requirements
    I. Rationale for Selecting the Recordkeeping Requirements
    J. Rationale for Verification Requirements
    K. Rationale for Selection of Duration of the Program
V. Rationale for the Reporting, Recordkeeping and Verification 
Requirements for Specific Source Categories
    A. Overview of Reporting for Specific Source Categories
    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. 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)
    QQ. Mobile Sources
VI. Collection, Management, and Dissemination of GHG Emissions Data
    A. Purpose
    B. Data Collection
    C. Data Management
    D. Data Dissemination
VII. Compliance and Enforcement
    A. Compliance Assistance
    B. Role of the States
    C. Enforcement
VIII. Economic Impacts of the Proposed Rule
    A. How are compliance costs estimated?
    B. What are the costs of this proposed rule?
    C. What are the economic impacts of the proposed rule?
    D. What are the impacts of the proposed rule on small entities?
    E. What are the benefits of the proposed rule for society?
IX. Statutory and Executive Order Reviews
    A. Executive Order 12866: Regulatory Planning and Review
    B. Paperwork Reduction Act
    C. Regulatory Flexibility Act (RFA)
    D. Unfunded Mandates Reform Act (UMRA)
    E. Executive Order 13132: Federalism
    F. Executive Order 13175: Consultation and Coordination With 
Indian Tribal Governments
    G. Executive Order 13045: Protection of Children From 
Environmental Health Risks and Safety Risks
    H. Executive Order 13211: Actions That Significantly Affect 
Energy Supply, Distribution, or Use
    I. National Technology Transfer and Advancement Act
    J. Executive Order 12898: Federal Actions To Address 
Environmental Justice in Minority Populations and Low-Income 
Populations

I. Background

    The proposed rule would require reporting of annual emissions of 
carbon dioxide (CO2), methane (CH4), nitrous 
oxide (N2O), sulfur hexafluoride (SF6), 
hydrofluorocarbons (HFCs), perfluorochemicals (PFCs), and other 
fluorinated gases (e.g., nitrogen trifluoride and hydrofluorinated 
ethers (HFEs)). The proposed rule would apply to certain downstream 
facilities that emit GHGs (primarily large facilities emitting 25,000 
tpy of CO2 equivalent GHG emissions or more) and to upstream 
suppliers of fossil fuels and industrial GHGs, as well as to 
manufacturers of vehicles and engines. Reporting would be at the 
facility level, except certain suppliers and vehicle and engine 
manufacturers would report at the corporate level.
    This preamble is broken into several large sections, as detailed 
above in the Table of Contents. Throughout the preamble we explicitly 
request comment on a variety of issues. The paragraph below describes 
the layout of the preamble and provides a brief summary of each 
section. We also highlight particular issues on which, as indicated 
later in the preamble, we would specifically be interested in receiving 
comments.
    The first section of this preamble contains the basic background 
information about greenhouse gases and climate change. It also 
describes the origin of this proposal, our legal authority and how this 
proposal relates to other efforts to address emissions of greenhouse 
gases. In this section we

[[Page 16453]]

would be particularly interested in receiving comment on the 
relationship between this proposal and other government efforts.
    The second section of this preamble describes existing Federal, 
State, Regional mandatory and voluntary GHG reporting programs and how 
they are similar and different to this proposal. Again, similar to the 
previous section, we would like comments on the interrelationship of 
this proposal and existing GHG reporting programs.
    The third section of this preamble provides an overview of the 
proposal itself, while the fourth section provides the rationale for 
each decision the Agency made in developing the proposal, including key 
design elements such as: (i) Source categories included, (ii) the level 
of reporting, (iii) applicability thresholds, (iv) reporting and 
monitoring methods, (v) verification, (vi) frequency and (vii) duration 
of reporting. Furthermore, in this section, EPA explains the 
distinction between upstream and downstream reporters, describes why it 
is necessary to collect data at multiple points, and provides 
information on how different data would be useful to inform different 
policies. As stated in the fourth section, we solicit comment on each 
design element of the proposal generally.
    The fifth section of this preamble looks at the same key design 
elements for each of the source categories covered by the proposal. 
Thus, for example, there is a specific discussion regarding appropriate 
applicability thresholds, reporting and monitoring methodologies and 
reporting and recordkeeping requirements for each source category. Each 
source category describes the proposed options for each design element, 
as well as the other options considered. In addition to the general 
solicitation for comment on each design element generally and for each 
source category, throughout the fifth section there are specific issues 
highlighted on which we solicit comment. Please refer to the specific 
source category of interest for more details.
    The sixth section of this preamble explains how EPA would collect, 
manage and disseminate the data, while the seventh section describes 
the approach to compliance and enforcement. In both sections the role 
of the States is discussed, as are requests for comment on that role.
    Finally, the eighth section provides the summary of the impacts and 
costs from the Regulatory Impact Analysis and the last section walks 
through the various statutory and executive order requirements 
applicable to rulemakings.

A. What Are GHGs?

    The proposed rule would cover the major GHGs that are directly 
emitted by human activities. These include CO2, 
CH4, N2O, HFCs, PFCs, SF6, and other 
specified fluorinated compounds (e.g., HFEs) used in boutique 
applications such as electronics and anesthetics. These gases influence 
the climate system by trapping in the atmosphere heat that would 
otherwise escape to space. The GHGs vary in their capacity to trap 
heat. The GHGs also vary in terms of how long they remain in the 
atmosphere after being emitted, with the shortest-lived GHG remaining 
in the atmosphere for roughly a decade and the longest-lived GHG 
remaining for up to 50,000 years. Because of these long atmospheric 
lifetimes, all of the major GHGs become well mixed throughout the 
global atmosphere regardless of emission origin.
    Global atmospheric CO2 concentration increased about 35 
percent from the pre-industrial era to 2005. The global atmospheric 
concentration of CH4 has increased by 148 percent from pre-
industrial levels, and the N2O concentration has increased 
18 percent. The observed increase in concentration of these gases can 
be attributed primarily to human activities. The atmospheric 
concentration of industrial fluorinated gases--HFCs, PFCs, 
SF6--and other fluorinated compounds are relatively low but 
are increasing rapidly; these gases are entirely anthropogenic in 
origin.
    Due to sheer quantity of emissions, CO2 is the largest 
contributor to GHG concentrations followed by CH4. 
Combustion of fossil fuels (e.g., coal, oil, gas) is the largest source 
of CO2 emissions in the U.S. The other GHGs are emitted from 
a variety of activities. These emissions are compiled by EPA in the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks (Inventory) and 
reported to the UNFCCC \1\ on an annual basis.\2\ A more detailed 
discussion of the Inventory is provided in Section I.D below.
---------------------------------------------------------------------------

    \1\ For more information about the UNFCCC, please refer to: 
http://www.unfccc.int. See Articles 4 and 12 of the UNFCCC treaty. 
Parties to the Convention, by ratifying, ``shall develop, 
periodically update, publish and make available * * * national 
inventories of anthropogenic emissions by sources and removals by 
sinks of all greenhouse gases not controlled by the Montreal 
Protocol, using comparable methodologies * * *''.
    \2\ The U.S. submits the Inventory of U.S. Greenhouse Gas 
Emissions and Sinks to the Secretariat of the UNFCCC as an annual 
reporting requirement. The UNFCCC treaty, ratified by the U.S. in 
1992, sets an overall framework for intergovernmental efforts to 
tackle the challenge posed by climate change. The U.S. has submitted 
the GHG inventory to the United Nations every year since 1993. The 
annual Inventory of U.S. Greenhouse Gas Emissions and Sinks is 
consistent with national inventory data submitted by other UNFCCC 
Parties, and uses internationally accepted methods for its emission 
estimates.
---------------------------------------------------------------------------

    Because GHGs have different heat trapping capacities, they are not 
directly comparable without translating them into common units. The 
GWP, a metric that incorporates both the heat-trapping ability and 
atmospheric lifetime of each GHG, can be used to develop comparable 
numbers by adjusting all GHGs relative to the GWP of CO2. 
When quantities of the different GHGs are multiplied by their GWPs, the 
different GHGs can be compared on a CO2e basis. The GWP of 
CO2 is 1.0, and the GWP of other GHGs are expressed relative 
to CO2. For example, CH4 has a GWP of 21, meaning 
each metric ton of CH4 emissions would have 21 times as much 
impact on global warming (over a 100-year time horizon) as a metric ton 
of CO2 emissions. The GWPs of the other gases are listed in 
the proposed rule, and range from the hundreds up to 23,900 for 
SF6.\3\ Aggregating all GHGs on a CO2e basis at 
the source level allows a comparison of the total emissions of all the 
gases from one source with emissions from other sources.
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    \3\ EPA has chosen to use GWPs published in the IPCC SAR 
(furthermore referenced as ``SAR GWP values''). The use of the SAR 
GWP values allows comparability of data collected in this proposed 
rule to the national GHG inventory that EPA compiles annually to 
meet U.S. commitments to the UNFCCC. To comply with international 
reporting standards under the UNFCCC, official emission estimates 
are to be reported by the U.S. and other countries using SAR GWP 
values. The UNFCCC reporting guidelines for national inventories 
were updated in 2002 but continue to require the use of GWPs from 
the SAR. The parties to the UNFCCC have also agreed to use GWPs 
based upon a 100-year time horizon although other time horizon 
values are available. For those fluorinated compounds included in 
this proposal that not listed in the SAR, EPA is using the most 
recent available GWPs, either the IPCC Third Assessment Report or 
Fourth Assessment Report. For more specific information about the 
GWP of specific GHGs, please see Table A-1 in the proposed 40 CFR 
part 98, subpart A.
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    For additional information about GHGs, climate change, climate 
science, etc. please see EPA's climate change Web site found at http://www.epa.gov/climatechange/.

B. What Is Climate Change?

    Climate change refers to any significant changes in measures of 
climate (such as temperature, precipitation, or wind) lasting for an 
extended period. Historically, natural factors such as volcanic 
eruptions and changes in the amount of energy released from the sun 
have affected the earth's climate. Beginning in the late 18th century, 
human activities associated with the industrial revolution

[[Page 16454]]

have also changed the composition of the earth's atmosphere and very 
likely are influencing the earth's climate.\4\ The heating effect 
caused by the buildup of GHGs in our atmosphere enhances the Earth's 
natural greenhouse effect and adds to global warming. As global 
temperatures increase other elements of the climate system, such as 
precipitation, snow and ice cover, sea levels, and weather events, 
change. The term ``climate change,'' which encompasses these broader 
effects, is often used instead of ``global warming.''
---------------------------------------------------------------------------

    \4\ IPCCC: Climate Change 2007: The Physical Science Basis, 
February 2, 2007 (http://www.ipcc.ch/).
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    According to the IPCC, warming of the climate system is 
``unequivocal,'' as is now evident from observations of increases in 
global average air and ocean temperatures, widespread melting of snow 
and ice, and rising global average sea level. Global mean surface 
temperatures have risen by 0.74 [deg]C (1.3 [deg]F) over the last 100 
years. Global mean surface temperature was higher during the last few 
decades of the 20th century than during any comparable period during 
the preceding four centuries. U.S. temperatures also warmed during the 
20th and into the 21st century; temperatures are now approximately 0.56 
[deg]C (1.0 [deg]F) warmer than at the start of the 20th century, with 
an increased rate of warming over the past 30 years. Most of the 
observed increase in global average temperatures since the mid-20th 
century is very likely due to the observed increase in anthropogenic 
GHG concentrations.
    According to different scenarios assessed by the IPCC, average 
global temperature by end of this century is projected to increase by 
1.8 to 4.0 [deg]C (3.2 to 7.2 [deg]F) compared to the average 
temperature in 1990. The uncertainty range of this estimate is 1.1 to 
6.4 [deg]C (2.0 to 11.5 [deg]F). Future projections show that, for most 
scenarios assuming no additional GHG emission reduction policies, 
atmospheric concentrations of GHGs are expected to continue climbing 
for most if not all of the remainder of this century, with associated 
increases in average temperature. Overall risk to human health, society 
and the environment increases with increases in both the rate and 
magnitude of climate change.
    For additional information about GHGs, climate change, climate 
science, etc. please see EPA's climate change Web site found at http://www.epa.gov/climatechange/.

C. Statutory Authority

    On December 26, 2007, President Bush signed the FY2008 Consolidated 
Appropriations Act which authorized funding for EPA to ``develop and 
publish a draft rule not later than 9 months after the date of 
enactment of this Act, and a final rule not later than 18 months after 
the date of enactment of this Act, to require mandatory reporting of 
GHG 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 has interpreted that language to confirm that it may 
be appropriate for the Agency to exercise its CAA authority to require 
reporting of the quantity of fuel or chemical that is produced or 
imported from upstream sources such as fuel suppliers, as well as 
reporting of emissions from facilities (downstream sources) that 
directly emit GHGs from their processes or from fuel combustion, as 
appropriate. 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'' 
under section 821 of the 1990 CAA Amendments.
    EPA is proposing this rule under its existing CAA authority. EPA 
also proposes that the rule require the reporting of the GHG emissions 
resulting from the quantity 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 from facilities (downstream sources) 
that directly emit GHGs from their processes or from fuel combustion, 
as appropriate. This proposed rule would also establish appropriate 
thresholds and frequency for reporting.
    Section 114(a)(1) of the CAA authorizes the Administrator to, inter 
alia, require certain persons (see below) on a one-time, periodic or 
continuous basis to keep records, make reports, undertake monitoring, 
sample emissions, or provide such other information as the 
Administrator may reasonably require. This information may be required 
of any person who (i) owns or operates an emission source, (ii) 
manufactures control or process equipment, (iii) the Administrator 
believes may have information necessary for the purposes set forth in 
this section, or (iv) is subject to any requirement of the Act (except 
for manufacturers subject to certain title II requirements). The 
information may be required for the purposes of developing an 
implementation plan, an emission standard under sections 111, 112 or 
129, determining if any person is in violation of any standard or 
requirement of an implementation plan or emissions standard, or 
``carrying out any provision'' of the Act (except for a provision of 
title II with respect to manufacturers of new motor vehicles or new 
motor vehicle engines).\5\ 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.
---------------------------------------------------------------------------

    \5\ Although there are exclusions in section 114(a)(1) regarding 
certain title II requirements applicable to manufacturers of new 
motor vehicle and motor vehicle engines, section 208 authorizes the 
gathering of information related to those areas.
---------------------------------------------------------------------------

    The scope of the persons potentially subject to a section 114(a)(1) 
information request (e.g., a person ``who the Administrator believes 
may have information necessary for the purposes set forth in'' section 
114(a)) and the reach of the phrase ``carrying out any provision'' of 
the Act are quite broad. EPA's authority to request information reaches 
to a source not subject to the CAA, and may be used for purposes 
relevant to any provision of the Act. Thus, for example, utilizing 
sections 114 and 208, EPA could gather information relevant to carrying 
out provisions involving research (e.g., section 103(g)); evaluating 
and setting standards (e.g., section 111); and endangerment 
determinations contained in specific provisions of the Act (e.g., 202); 
as well as other programs.
    Given the broad scope of sections 114 and 208 of the CAA, it is 
appropriate for EPA to gather the information required by this rule 
because such information is relevant to EPA's carrying out a wide 
variety of CAA provisions. For example, emissions from direct emitters 
should inform decisions about whether and how to use section 111 to 
establish NSPS for various source categories emitting GHGs, including 
whether there are any additional categories of sources that should be 
listed under section 111(b). Similarly, the information required of 
manufacturers of mobile

[[Page 16455]]

sources should support decisions regarding treatment of those sources 
under sections 202, 213 or 231 of the CAA. In addition, the information 
from fuel suppliers would be relevant in analyzing whether to proceed, 
and particular options for how to proceed, under section 211(c) 
regarding fuels, or to inform action concerning downstream sources 
under a variety of Title I or Title II provisions. For example, the 
geographic distribution, production volumes and characteristics of 
various fuel types and subtypes may also prove useful is setting NSPS 
or Best Available Control Technology limits for some combustion 
sources. Transportation distances from fuel sources to end users may be 
useful in evaluating cost effectiveness of various fuel choices, 
increases in transportation emissions that may be associated with 
various fuel choices, as well as the overall impact on energy usage and 
availability. The data overall also would inform EPA's implementation 
of section 103(g) of the CAA regarding improvements in nonregulatory 
strategies and technologies for preventing or reducing air pollutants. 
This section, which specifically mentions CO2, highlights 
energy conservation, end-use efficiency and fuel-switching as possible 
strategies for consideration and the type of information collected 
under this rule would be relevant. The above discussion is not a 
comprehensive listing of all the possible ways the information 
collected under this rule could assist EPA in carrying out any 
provision of the CAA. Rather it illustrates how the information request 
fits within the parameters of EPA's CAA authority.

D. Inventory of U.S. GHG Emissions and Sinks

    The Inventory of U.S. Greenhouse Gas Emissions and Sinks 
(Inventory), prepared by EPA's Office of Atmospheric Programs in 
coordination with the Office of Transportation and Air Quality, is an 
impartial, policy-neutral report that tracks annual GHG emissions. The 
annual report presents historical U.S. emissions of CO2, 
CH4, N2O, HFCs, PFCs, and SF6.
    The U.S. submits the Inventory to the Secretariat of the UNFCCC as 
an annual reporting requirement. The UNFCCC treaty, ratified by the 
U.S. in 1992, sets an overall framework for intergovernmental efforts 
to tackle the challenge posed by climate change. The U.S. has submitted 
the GHG inventory to the United Nations every year since 1993. The 
annual Inventory is consistent with national inventory data submitted 
by other UNFCCC Parties, and uses internationally accepted methods for 
its emission estimates.
    In preparing the annual Inventory, EPA leads an interagency team 
that includes DOE, USDA, DOT, DOD, the State Department, and others. 
EPA collaborates with hundreds of experts representing more than a 
dozen Federal agencies, academic institutions, industry associations, 
consultants, and environmental organizations. The Inventory is peer-
reviewed annually by domestic experts, undergoes a 30-day public 
comment period, and is also peer-reviewed annually by UNFCCC review 
teams.
    The most recent GHG inventory submitted to the UNFCCC, the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990-2006 (April 
2008), estimated that total U.S. GHG emissions were 7,054.2 million 
metric tons of CO2e in 2006. Overall emissions have grown by 
15 percent from 1990 to 2006. CO2 emissions have increased 
by 18 percent since 1990. CH4 emissions have decreased by 8 
percent since 1990, while N2O emissions have decreased by 4 
percent since 1990. Emissions of HFCs, PFCs, and SF6 have 
increased by 64 percent since 1990. The combustion of fossil fuels 
(i.e., petroleum, coal, and natural gas) was the largest source of GHG 
emissions in the U.S., and accounted for approximately 80 percent of 
total CO2e emissions.
    The Inventory is a comprehensive top-down national assessment of 
national GHG emissions, and it uses top-down national energy data and 
other national statistics (e.g., on agriculture). To achieve the goal 
of comprehensive national emissions coverage for reporting under the 
UNFCCC, most GHG emissions in the report are calculated via activity 
data from national-level databases, statistics, and surveys. The use of 
the aggregated national data means that the national emissions 
estimates are not broken-down at the geographic or facility level. In 
contrast, this reporting rule focuses on bottom-up data and individual 
sources above appropriate thresholds. Although it would provide more 
specific data, it would not provide full coverage of total annual U.S. 
GHG emissions, as is required in the development of the Inventory in 
reporting to the UNFCCC.
    The mandatory GHG reporting rule would help to improve the 
development of future national inventories for particular source 
categories or sectors by advancing the understanding of emission 
processes and monitoring methodologies. Facility, unit, and process 
level GHG emissions data for industrial sources would improve the 
accuracy of the Inventory by confirming the national statistics and 
emission estimation methodologies used to develop the top-down 
inventory. The results can indicate shortcomings in the national 
statistics and identify where adjustments may be needed.
    Therefore, although the data collected under this rule would not 
replace the system in place to produce the comprehensive annual 
national Inventory, it can serve as a useful tool to better improve the 
accuracy of future national-level inventories.
    At the same time, EPA solicits comment on whether the submission of 
the Inventory to the UNFCCC could be utilized to satisfy the 
requirements of the rule promulgated by EPA pursuant to the FY2008 
Consolidated Appropriations Act.
    For more information about the Inventory, please refer to the 
following Web site: http://www.epa.gov/climatechange/emissions/usinventoryreport.html.

E. How does this proposal relate to U.S. government and other climate 
change efforts?

    The proposed mandatory GHG reporting program would provide EPA, 
other government agencies, and outside stakeholders with economy-wide 
data on facility-level (and in some cases corporate-level) GHG 
emissions. Accurate and timely information on GHG emissions is 
essential for informing some future climate change policy decisions. 
Although additional data collection (e.g., for other source categories 
such as indirect emissions or offsets) may be required as the 
development of climate policies evolves, the data collected in this 
rule would provide useful information for a variety of policies. For 
example, through data collected under this rule, EPA would 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 would also improve our 
understanding of the factors that influence GHG emission rates and 
actions that facilities are already taking to reduce emissions. In 
addition, the data collected on some source categories such as 
landfills and manure management, which can be covered by the CAA, could 
also potentially help inform offset program design by providing 
fundamental data on current baseline emissions for these categories.
    Through this rulemaking, EPA would be able to track the trend of 
emissions from industries and facilities within

[[Page 16456]]

industries over time, particularly in response to policies and 
potential regulations. The data collected by this rule would also 
improve the U.S. government's ability to formulate a set of climate 
change policy options and to assess which industries would be affected, 
and how these industries would be affected by the options. 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 reduction opportunities and 
carry them out.
    The goal is to have this GHG reporting program supplement and 
complement, rather than duplicate, U.S. government and other GHG 
programs (e.g., State and Regional based programs). As discussed in 
Section I.D of this preamble, EPA anticipates that facility-level GHG 
emissions data would lead to improvements in the quality of the 
Inventory.
    As discussed in Section II of this preamble, 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). Because this mandatory reporting program would have much 
broader coverage than the voluntary programs, it would help EPA learn 
more about emissions from facilities not currently included in these 
programs and broaden coverage of these industries.
    Also discussed in Section II of this preamble, DOE EIA implements a 
voluntary GHG registry under section 1605(b) of the Energy Policy Act. 
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.\6\ EPA's proposed mandatory GHG program would have a much 
broader set of reporters included, primarily at the facility \7\ rather 
than entity-level, but this proposed rule is not designed with the 
specific intent of reporting of emission reductions, as is the 1605(b) 
program.
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    \6\ 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/)
    \7\ For the purposes of this proposal, 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.
---------------------------------------------------------------------------

    Again, in Section II, existing State and Regional GHG reporting and 
reduction programs are summarized. Many of those programs may be 
broader in scope and more aggressive in implementation. States 
collecting that additional information may have determined that types 
of data not collected by this proposal are necessary to implement a 
variety of climate efforts. While EPA's proposal was specifically 
developed in response to the Appropriations Act, we also acknowledge, 
similar to the States, there may be a need to collect additional data 
from sources subject to this rule as well as other sources depending on 
the types of policies the Agency is developing and implementing (e.g., 
indirect emissions and offsets). Addressing climate change may require 
a suite of policies and programs and this proposal for a mandatory 
reporting program is just one effort to collect information necessary 
to inform those policies. There may well be subsequent efforts 
depending on future policy direction and/or requests from Congress.

F. How does this proposal relate to EPA's Climate Change ANPR?

    On July 30, 2008, EPA published an ANPR on ``Regulating Greenhouse 
Gas Emissions under the Clean Air Act'' (73 FR 44354). The ANPR 
presented information relevant to, and solicited public comment on, 
issues regarding the potential regulation of GHGs under the CAA, 
including EPA's response to the U.S. Supreme Court's decision in 
Massachusetts v. EPA. 127 S.Ct. 1438 (2007). EPA's proposing the 
mandatory GHG reporting rule does not indicate that EPA has made any 
final decisions related to the questions identified in the ANPR. Any 
information collected under the mandatory GHG reporting program would 
assist EPA and others in developing future climate policy.\8\
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    \8\ At this time, a regulation requiring the reporting of GHG 
emissions and emissions-related data under CAA sections 114 and 208 
does not trigger the need for EPA to develop or revise regulations 
under any other section of the CAA, including the PSD program. See 
memorandum entitled ``EPA's Interpretation of Regulations that 
Determine Pollutants Covered By Federal Prevention of Significant 
Deterioration (PSD) Permit Program'' (Dec. 18, 2008). EPA is 
reconsidering this memorandum and will be seeking public comment on 
the issues raised in it. That proceeding, not this rulemaking, would 
be the appropriate venue for submitting comments on the issue of 
whether monitoring regulations under the CAA should trigger the PSD 
program.
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G. How was this proposed rule developed?

    In response to the FY2008 Consolidated Appropriations Amendment, 
EPA has developed this proposed rulemaking. The components of this 
development are explained in the following subsections.
1. Identifying the Goals of the GHG Reporting System
    The mandatory reporting program would provide comprehensive and 
accurate data which would inform future climate change policies. 
Potential future 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 we do not know at this time the specific 
policies that may be adopted, the data reported through the mandatory 
reporting system should be of sufficient quality to support a range of 
approaches. Also, consistent with the Appropriations Act, the reporting 
rule proposes to cover a broad range of sectors of the economy.
    To these ends, we identified the following goals of the mandatory 
reporting system:
     Obtain data that is of sufficient quality that it can be 
used to support a range of future climate change policies and 
regulations.
     Balance the rule coverage to maximize the amount of 
emissions reported while excluding small emitters.
     Create reporting requirements that are consistent with 
existing GHG reporting programs by using existing GHG emission 
estimation and reporting methodologies to reduce reporting burden, 
where feasible.
2. Developing the Proposed Rule
    In order to ensure a comprehensive consideration of GHG emissions, 
EPA organized the development of the proposal around seven categories 
of processes that emit GHGs: Downstream sources of emissions: (1) 
Fossil Fuel Combustion: Stationary, (2) Fossil Fuel Combustion: Mobile, 
(3) Industrial Processes, (4) Fossil Fuel Fugitive \9\ Emissions, (5) 
Biological Processes and Upstream sources of emissions: (6) Fuel

[[Page 16457]]

Suppliers, and (7) Industrial GHG Suppliers.
---------------------------------------------------------------------------

    \9\ The term ``fugitive'' often refers to emissions that cannot 
reasonably pass through a stack, chimney, vent or other functionally 
equivalent opening. This definition of fugitives is used throughout 
the preamble, except in Section W Oil and Natural Gas Systems, which 
uses a slightly modified definition based on the Intergovernmental 
Panel on Climate Change.
---------------------------------------------------------------------------

    For each category, EPA evaluated the requirements of existing GHG 
reporting programs, obtained input from stakeholders, analyzed 
reporting options, and developed the general reporting requirements and 
specific requirements for each of the GHG emitting processes.
3. Evaluation of Existing GHG Reporting Programs
    A number of State and regional GHG reporting systems currently are 
in place or under development. EPA's goal is to develop a reporting 
rule that, to the extent possible and appropriate, would rely on 
similar protocols and formats of the existing programs and, therefore, 
reduce the burden of reporting for all parties involved. Therefore, 
each of the work groups performed a comprehensive review of existing 
voluntary and mandatory GHG reporting programs, as well as guidance 
documents for quantifying GHG emissions from specific sources. These 
GHG reporting programs and guidance documents included the following:
     International programs, including the IPCC, the EU 
Emissions Trading System, and the Environment Canada reporting rule;
     U.S. national programs, such as the U.S. GHG inventory, 
the ARP, voluntary GHG partnership programs (e.g., Natural Gas STAR), 
and the DOE 1605(b) voluntary GHG registry;
     State and regional GHG reporting programs, such as TCR, 
RGGI, and programs in California, New Mexico, and New Jersey;
     Reporting protocols developed by nongovernmental 
organizations, such as WRI/WBCSD; and
     Programs from industrial trade organizations, such as the 
American Petroleum Institute's Compendium of GHG Estimation 
Methodologies for the Oil and Gas Industry and the Cement 
Sustainability Initiative's CO2 Accounting and Reporting 
Standard for the Cement Industry, developed by WBCSD.
    In reviewing these programs, we analyzed the sectors covered, 
thresholds for reporting, approach to indirect emissions reporting, the 
monitoring or emission estimating methods used, the measures to assure 
the quality of the reported data, the point of monitoring, data input 
needs, and information required to be reported and/or retained. We 
analyzed these provisions for suitability to a mandatory, Federal GHG 
reporting program, and compiled the information. The full review of 
existing GHG reporting programs and guidance may be found in the docket 
at EPA-HQ-OAR-2008-0508-054. Section II of this preamble summarizes the 
fundamental elements of these programs.
4. Stakeholder Outreach To Identify Reporting Issues
    Early in the development process, we conducted a proactive 
communications outreach program to inform the public about the rule 
development effort. We solicited input and maintained an open door 
policy for those interested in discussing the rulemaking. Since January 
2008, EPA staff held more than 100 meetings with over 250 stakeholders. 
These stakeholders included:
     Trade associations and firms in potentially affected 
industries/sectors;
     State, local, and Tribal environmental control agencies 
and regional air quality planning organizations;
     State and regional organizations already involved in GHG 
emissions reporting, such as TCR, CARB, and WCI;
     Environmental groups and other nongovernmental 
organizations.
     We also met with DOE and USDA which have programs relevant 
to GHG emissions.
    During the meetings, we shared information about the statutory 
requirements and timetable for developing a rule. Stakeholders were 
encouraged to provide input on key issues. Examples of topics discussed 
were, existing GHG monitoring and reporting programs and lessons 
learned, thresholds for reporting, schedule for reporting, scope of 
reporting, handling of confidential data, data verification, and the 
role of States in administering the program. As needed, the technical 
work groups followed up with these stakeholder groups on a variety of 
methodological, technical, and policy issues. EPA staff also provided 
information to Tribes through conference calls with different Indian 
working groups and organizations at EPA and through individual calls 
with Tribal board members of TCR.
    For a full list of organizations EPA met with during development of 
this proposal, see the memo found at EPA-HQ-OAR-2008-0508-055.

II. Summary of Existing Federal, State, and Regional Emission Reporting 
Programs

    A number of voluntary and mandatory GHG programs already exist or 
are being developed at the State, Regional, and Federal levels. These 
programs have different scopes and purposes. Many focus on GHG emission 
reduction, whereas others are purely reporting programs. In addition to 
the GHG programs, other Federal emission reporting programs and 
emission inventories are relevant to the proposed GHG reporting rule. 
Several of these programs are summarized in this section.
    In developing the proposed rule, we carefully reviewed the existing 
reporting programs, particularly with respect to emissions sources 
covered, thresholds, monitoring methods, frequency of reporting and 
verification. States may have, or intend to develop, reporting programs 
that are broader in scope or are more aggressive in implementation 
because those programs are either components of established reduction 
programs (e.g., cap and trade) or being used to design and inform 
specific complementary measures (e.g., energy efficiency). EPA has 
benefitted from the leadership the States have shown in developing 
these programs and their experiences. Discussions with States that have 
already implemented programs have been especially instructive. Where 
possible, we built upon concepts in existing Federal and State programs 
in developing the mandatory GHG reporting rule.

A. Federal Voluntary GHG Programs

    EPA and other Federal agencies operate a number of voluntary GHG 
reporting and reduction programs that EPA reviewed when developing this 
proposal, including Climate Leaders, several Non-CO2 
voluntary programs, the CHP partnership, the SmartWay Transport 
Partnership program, the National Environmental Performance Track 
Partnership, and the DOE 1605(b) voluntary GHG registry. There are 
several other Federal voluntary programs to encourage emissions 
reductions, clean energy, or energy efficiency, and this summary does 
not cover them all. This summary focuses on programs that include 
voluntary GHG emission inventories or reporting of GHG emission 
reduction activities for sectors covered by this proposed rulemaking.
    Climate Leaders.\10\ Climate Leaders is an EPA partnership program 
that works with companies to develop GHG reduction strategies. Over 250 
industry partners in a wide range of sectors have joined. Partner 
companies complete a corporate-wide inventory of GHG emissions and 
develop an inventory management plan using Climate Leaders protocols. 
Each company sets GHG reductions goals and submits to EPA an

[[Page 16458]]

annual GHG emissions inventory documenting their progress. The annual 
reporting form provides corporate-wide emissions by type of emissions 
source.
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    \10\ For more information about the Climate Leaders program 
please see: http://www.epa.gov/climateleaders/.
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    Non-CO2 Voluntary Partnership Programs.\11\ Since the 
1990s, EPA has operated a number of non-CO2 voluntary 
partnership programs aimed at reducing emissions from GHGs such as 
CH4, SF66, and PFCs. There are four 
sector-specific voluntary CH4 reduction programs: Natural 
Gas STAR, Landfill Methane Outreach Program, Coalbed Methane Outreach 
Program and AgSTAR. In addition, there are sector-specific voluntary 
emission reduction partnerships for high GWP gases. The Natural Gas 
STAR partnership encourages companies across the natural gas and oil 
industries to adopt practices that reduce CH4 emissions. The 
Landfill Methane Outreach Program and Coalbed Methane Outreach Program 
encourage voluntary capture and use of landfill and coal mine 
CH4, respectively, to generate electricity or other useful 
energy. These partnerships focus on achieving CH4 
reductions. Industry partners voluntarily provide technical information 
on projects they undertake to reduce CH4 emissions on an 
annual basis, but they do not submit CH4 emissions 
inventories. AgSTAR encourages beneficial use of agricultural 
CH4 but does not have partner reporting requirements.
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    \11\ For more information about the Non-CO2 Voluntary 
Partnership Programs please see: http://www.epa.gov/nonco2/voluntaryprograms.html.
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    There are two sector specific partnerships to reduce SF6 
emissions: The SF6 Emission Reduction Partnership for 
Electric Power Systems, with over 80 participating utilities, and an 
SF6 Emission Reduction Partnership for the Magnesium 
Industry. Partners in these programs implement practices to reduce 
SF6 emissions and prepare corporate-wide annual inventories 
of SF6 emissions using protocols and reporting tools 
developed by EPA. There are also two partnerships focused on PFCs. The 
Voluntary Aluminum Industrial Partnership promotes technically feasible 
and cost effective actions to reduce PFC emissions. Industry partners 
track and report PFC emissions reductions. Similarly, the Semiconductor 
Industry Association and EPA formed a partnership to reduce PFC 
emissions. A third party compiles data from participating semiconductor 
companies and submits an aggregate (not company-specific) annual PFC 
emissions report.
    CHP Partnership.\12\ The CHP Partnership is an EPA partnership that 
cuts across sectors. It encourages use of CHP technologies to generate 
electricity and heat from the same fuel source, thereby increasing 
energy efficiency and reducing GHG emissions from fuel combustion. 
Corporate and institutional partners provide data on existing and new 
CHP projects, but do not submit emissions inventories.
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    \12\ For more information about the CHP Partnership please see: 
http://www.epa.gov/chp/.
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    SmartWay Transport Partnership.\13\ The SmartWay Transport 
Partnership program is a voluntary partnership between freight industry 
stakeholders and EPA to promote fuel efficiency improvements and GHG 
emissions reductions. Over 900 companies have joined including freight 
carriers (railroads and trucking fleets) and shipping companies. 
Carrier and shipping companies commit to measuring and improving the 
efficiency of their freight operations using EPA-developed tools that 
quantify the benefits of a number of fuel-saving strategies. Companies 
report progress annually. The GHG data that carrier companies report to 
EPA is discussed further in Section V.QQ.4b of this preamble.
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    \13\ For more information about SmartWay please see: http://www.epa.gov/smartway/.
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    National Environmental Performance Track Partnership.\14\ The 
Performance Track Partnership is a voluntary partnership that 
recognizes and rewards private and public facilities that demonstrate 
strong environmental performance beyond current requirements. 
Performance Track is designed to augment the existing regulatory system 
by creating incentives for facilities to achieve environmental results 
beyond those required by law. To qualify, applicants must have 
implemented an independently-assessed environmental management system, 
have a record of sustained compliance with environmental laws and 
regulations, commit to achieving measurable environmental results that 
go beyond compliance, and provide information to the local community on 
their environmental activities. Members are subject to the same legal 
requirements as other regulated facilities. In some cases, EPA and 
states have reduced routine reporting or given some flexibility to 
program members in how they meet regulatory requirements. This approach 
is recognized by more than 20 states that have adopted similar 
performance-based leadership programs.
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    \14\ For more information about Performance Track please see: 
http://www.epa.gov/perftrac/index.htm.
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    1605(b) Voluntary Registry.\15\ The DOE EIA established a voluntary 
GHG registry under section 1605(b) of the Energy Policy Act of 1992. 
The program was recently enhanced and a final rule containing general 
reporting guidelines was published on April 21, 2006 (71 FR 20784). The 
rule is contained in 10 CFR part 300. Unlike EPA's proposal which 
requires of reporting of GHG emissions from facilities over a specific 
threshold, the DOE 1605(b) registry allows anyone (e.g., a public 
entity, private company, or an individual) to report on their emissions 
and their emission reduction projects to the registry. Large emitters 
(e.g., anyone that emits over 10,000 tons of CO2e per year) 
that wish to register emissions reductions must submit annual company-
wide GHG emissions inventories following technical guidelines published 
by DOE and must calculate and report net GHG emissions reductions. The 
program offers a range of reporting methodologies from stringent direct 
measurement to simplified calculations using default factors and allows 
the reporters to report using the methodological option they choose. In 
addition, as mentioned above, unlike EPA's proposal, sequestration and 
offset projects can also be reported under the 1605(b) program. There 
is additional flexibility offered to small sources who can choose to 
limit annual inventories and emission reduction reports to just a 
single type of activity rather than reporting company-wide GHG 
emissions, but must still follow the technical guidelines. Reported 
data are made available on the Web in a public use database.
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    \15\ For more information about DOE's 1605(b) programs please 
see: http://www.pi.energy.gov/enhancingGHGregistry/.
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    Summary. These voluntary programs are different in nature from the 
proposed mandatory GHG emissions reporting rule. Industry participation 
in the programs and reporting to the programs is entirely voluntary. A 
small number of sources report, compared to the number of facilities 
that would likely be affected by the proposed mandatory GHG reporting 
rule. Most of the EPA voluntary programs do not require reporting of 
annual emissions data, but are instead intended to encourage GHG 
reduction projects/activities and track partner's successes in 
implementing such projects. For the programs that do include annual 
emissions reporting (e.g., Climate Leaders, DOE 1605(b)) the scope and 
level of detail are different. For example, Climate Leaders annual 
reports are generally corporate-wide and do not contain the facility 
and process-

[[Page 16459]]

level details that would be needed by a mandatory program to verify the 
accuracy of the emissions reports.
    At the same time, aspects of the voluntary programs serve as useful 
starting points for the mandatory GHG reporting rules. GHG emission 
calculation principles and protocols have been developed for various 
types of emission sources by Climate Leaders, the DOE 1605(b) program, 
and some partnerships such as the SF6 reduction partnerships 
and SmartWay. Under these protocols, reporting companies monitor 
process or operating parameters to estimate GHG emissions, report 
annually, and retain records to document their GHG estimates. Through 
the voluntary programs, EPA, DOE, and participating companies have 
gained understanding of processes that emit GHGs and experience in 
developing and reviewing GHG emission inventories.

B. Federal Mandatory Reporting Programs

    Sulfur Dioxide (SO2) and Nitrogen Oxides (NOX) Trading Programs. 
The ARP and the NOX Budget Trading Program are cap-and-trade 
programs designed to reduce emissions of SO2 and 
NOX\16\. As a part of those programs facilities with EGUs 
that serve a generator larger than 25 MW are required to report 
emissions. The 40 CFR part 75 CEMS rule establishes monitoring and 
reporting requirements under these programs. The regulations in 40 CFR 
part 75 require continuous monitoring and quarterly and annual 
emissions reporting of CO2 mass emissions,\17\ 
SO2 mass emissions, NOX emission rate, and heat 
input. Part 75 contains specifications for the types of monitoring 
systems that may be used to determine CO2 emissions and sets 
forth operations, maintenance, and QA/QC requirement for each system. 
In some cases, EGUs are allowed to use simplified procedures other than 
CEMS (e.g., monitoring fuel feed rates and conducting periodic sampling 
and analyses of fuel carbon content) to determine CO2 
emissions. Under the regulations, affected EGUs must submit detailed 
quarterly and annual CO2 emissions reports using 
standardized electronic reporting formats. If CEMS are used, the 
quarterly reports include hourly CEMS data and other information used 
to calculate emissions (e.g., monitor downtime). If alternative 
monitoring programs are used, detailed data used to calculate 
CO2 emissions must be reported.
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    \16\ For more information about these cap and trade programs see 
http://www.epa.gov/airmarkt/.
    \17\ The requirements regarding CO2 emissions 
reporting apply only to ARP sources and are pursuant to section 821 
of the CAA Amendments of 1990, Public Law 101-549.
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    The joint explanatory statement accompanying the FY2008 
Consolidated Appropriations Amendment specified that EPA could use the 
existing reporting requirements for electric generating units under 
section 821 of the 1990 CAA Amendments.\18\ As described in Sections 
V.C. and V.D. of this preamble, because the part 75 regulations already 
require reporting of high quality CO2 data from EGUs, the 
GHG reporting rule proposes to use the same CO2 data rather 
than require additional reporting of CO2 from EGUs. They 
would, however, have to include reporting of the other GHG emissions, 
such as CH4 and N2O, at their facilities.
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    \18\ The joint explanatory statement refers to ``Section 821 of 
the Clean Air Act'' but section 821 was part of the 1990 CAA 
Amendments not codified into the CAA itself.
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    TRI. TRI requires facility-level reporting of annual mass emissions 
of approximately 650 toxic chemicals.\19\ If they are above established 
thresholds, facilities in a wide range of industries report including 
manufacturing industries, metal and coal mining, electric utilities, 
and other industrial sectors. Facilities must submit annual reports of 
total stack and fugitive emissions of the listed toxic chemicals using 
a standardized form which can be submitted electronically. No 
information is reported on the processes and emissions points included 
in the total emissions. The data reported to TRI are not directly 
useful for the GHG rule because TRI does not include GHG emissions and 
does not identify processes or emissions sources. However, the TRI 
program is similar to the proposed GHG reporting rule in that it 
requires direct emissions reporting from a large number of facilities 
(roughly 23,000) across all major industrial sectors. Therefore, EPA 
reviewed the TRI program for ideas regarding program structure and 
implementation.
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    \19\ For more information about TRI and what chemicals are on 
the list, please see: http://www.epa.gov/tri/.
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    Vehicle Reporting. EPA's existing criteria pollutant emissions 
certification regulations, as well as the fuel economy testing 
regulations which EPA administers as part of the CAFE program, require 
vehicle manufacturers to measure and report CO2 for 
essentially all of their light duty vehicles. In addition, many engine 
manufacturers currently measure CO2 as an integral part of 
calculating emissions of criteria pollutants, and some report 
CO2 emissions to EPA in some form.

C. EPA Emissions Inventories

    U.S. Inventory of Greenhouse Gas Emissions and Sinks. As discussed 
in Section I.D of this preamble, EPA prepares the U.S. Inventory of 
Greenhouse Gas Emissions and Sinks every year. The details of this 
Inventory, the methodologies used to calculate emissions and its 
relationship to this proposal are discussed in Section I.D of this 
preamble.
    NEI. \20\ EPA compiles the NEI, a database of air emissions 
information provided primarily by State and local air agencies and 
Tribes. The database contains information on stationary and mobile 
sources that emit criteria air pollutants and their precursors, as well 
as hazardous air pollutants. Stationary point source emissions that 
must be inventoried and reported are those that emit over a threshold 
amount of at least one criteria pollutant. Many States also inventory 
and report stationary sources that emit amounts below the thresholds 
for each pollutant. The NEI includes over 60,000 facilities. The 
information that is required consists of facility identification 
information; process information detailing the types of air pollution 
emission sources; air pollution emission estimates (including annual 
emissions); control devices in place; stack parameters; and location 
information. The NEI differs from the proposed GHG reporting rule in 
that the NEI contains no GHG data, and the data are reported primarily 
by State agencies rather than directly reported by industries.\21\ 
However, in developing the proposed rule, EPA used the NEI to help 
determine sources that might need to report under the GHG reporting 
rule. We considered the types of facility, process and activity data 
reported in NEI to support the emissions data as a possible model for 
the types of data to be reported under the GHG reporting rule. We also 
considered systems that could be used to link data reported under the 
GHG rule with data for the same facilities in the NEI.
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    \20\ For more information about the NEI please see: http://www.epa.gov/ttn/chief/net/.
    \21\ As discussed in section IV of the preamble, tropospheric 
ozone (O3) is a GHG. The precursors to tropospheric 
O3 (e.g., NOX, VOCs, etc) are reported to the NEI by 
States and then EPA models tropospheric O3 based on that 
precursor data.
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D. Regional and State Voluntary Programs for GHG Emissions Reporting

    A number of States have demonstrated leadership and developed 
corporate voluntary GHG reporting programs individually or joined with 
other States to develop GHG reporting programs as part of their 
approaches to addressing GHG emissions. EPA has

[[Page 16460]]

benefitted from this leadership and the States' experiences; 
discussions with those that have already implemented programs have been 
especially instructive. Section V of the preamble describes the 
proposed methods for each source category. The different options 
considered have been particularly informed by the States' expertise. 
This section of the preamble summarizes two prominent voluntary 
efforts. In developing the greenhouse rules, EPA reviewed the relevant 
protocols used by these programs as a starting point. We recognize that 
these programs may have additional monitoring and reporting 
requirements than those outlined in the proposed rule in order to 
provide distinct program benefits.
    CCAR.\22\ CCAR is a voluntary GHG registry already in use in 
California. CCAR has released several methodology documents including a 
general reporting protocol, general certification (verification) 
protocol, and several sector-specific protocols. Companies submit 
emissions reports using a standardized electronic system. Emission 
reports may be aggregated at the company level or reported at the 
facility level.
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    \22\ For more information about CCAR please see: http://www.climateregistry.org/.
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    TCR.\23\ TCR is a partnership formed by U.S. and Mexican States, 
Canadian provinces, and Tribes to develop standard GHG emissions 
measurement and verification protocols and a reporting system capable 
of supporting mandatory or voluntary GHG emission reporting rules and 
policies for its member States. TCR has released a General Reporting 
Protocol that contains procedures to measure and calculate GHG 
emissions from a wide range of source categories. They have also 
released a general verification protocol, and an electronic reporting 
system. Founding reporters (companies and other organizations that have 
agreed to voluntarily report their GHG emissions) implemented a pilot 
reporting program in 2008. Annual reports would be submitted covering 
six GHGs. Corporations must report facility-specific emissions, broken 
out by type of emission source (e.g., stationary combustion, 
electricity use, direct process emissions) within the facility.
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    \23\ For more information about TCR please see: http://www.theclimateregistry.org/.
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E. State and Regional Mandatory Programs for GHG Emissions Reporting 
and Reduction

    Several individual States and regional groups of States have 
demonstrated leadership and are developing or have developed mandatory 
GHG reporting programs and GHG emissions control programs. This section 
of the preamble summarizes two regional cap-and-trade programs and 
several State mandatory reporting rules. We recognize that, like the 
current voluntary regional and State programs, State and regional 
mandatory reporting programs may evolve or develop to include 
additional monitoring and reporting requirements than those included in 
the proposed rule. In fact, these programs may be broader in scope or 
more aggressive in implementation because the programs are either 
components of established reduction programs (e.g., cap and trade) or 
being used to design and inform specific complementary measures (e.g., 
energy efficiency).
    RGGI.\24\ RGGI is a regional cap-and-trade program that covers 
CO2 emissions from EGUs that serve a generator greater than 
25 MW in member States in the mid-Atlantic and Northeast. The program 
goal is to reduce CO2 emissions to 10 percent below 1990 
levels by the year 2020. RGGI will utilize the CO2 reported 
to and verified by EPA under 40 CFR part 75 to determine compliance of 
the EGUs in the cap-and-trade program. In addition, the EGUs in RGGI 
that are not currently reporting to EPA under the ARP and NOX Budget 
program (e.g., co-generation facilities) will start reporting their 
CO2 data to EPA for QA/QC, similar to the sources already 
reporting. Certain types of offset projects will be allowed, and GHG 
offset protocols have been developed. The States participating in RGGI 
have adopted State rules (based on the model rule) to implement RGGI in 
each State. The RGGI cap-and-trade program took effect on January 1, 
2009.
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    \24\ For more information about RGGI please see: http://www.rggi.org/.
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    WCI.\25\ WCI is another regional cap-and-trade program being 
developed by a group of Western States and Canadian provinces. The goal 
is to reduce GHG emissions to 15 percent below 2005 levels by the year 
2020. Draft options papers and program scope papers were released in 
early 2008, public comments were reviewed, and final program design 
recommendations were made in September 2008. Other elements of the 
program, such as reporting requirements, market operations, and offset 
program development continues. Several source categories are being 
considered for inclusion in the cap and trade framework. The program 
might be phased in, starting with a few source categories and adding 
others over time. Points of regulation for some source categories, 
calculation methodologies, and other reporting program elements are 
under development. The WCI is also analyzing alternative or 
complementary policies other than cap-and-trade that could help reach 
GHG reduction goals. Options for rule implementation and for 
coordination with other rules and programs such as TCR are being 
investigated.
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    \25\ For more information about WCI please see: http://www.westernclimateinitiative.org/.
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    A key difference between the Federal mandatory GHG reporting rule 
and the RGGI and WCI programs is that the Federal mandatory GHG rule is 
solely a reporting requirement. It does not in any way regulate GHG 
emissions or require any emissions reductions.
    State Mandatory GHG Reporting Rules. Seventeen States have 
developed, or are developing, mandatory GHG reporting rules.\26\ The 
docket contains a summary of these State mandatory rules (EPA-HQ-OAR-
2008-0508-056). Final rules have not yet been developed by some of the 
States, so details of some programs are unknown. Reporting requirements 
have taken effect in twelve States as of 2009; the rest start between 
2010 and 2012. Reporting is typically annual, although some States 
require quarterly reporting for EGUs, consistent with RGGI and the ARP.
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    \26\ These include: California, Colorado, Connecticut, Delaware, 
Hawaii, Iowa, Maine, Maryland, Massachusetts, New Jersey, New 
Mexico, North Carolina, Oregon, Virginia, Washington, West Virginia, 
and Wisconsin.
---------------------------------------------------------------------------

    State rules differ with regard to which facilities must report and 
which GHGs must be reported. Some States require all facilities that 
must obtain Title V permits to report GHG emissions. Others require 
reporting for particular sectors (e.g., large EGUs, cement plants, 
refineries). Some State rules apply to any facility with stationary 
combustion sources that emit a threshold level of CO2. Some 
apply to any facility, or to facilities within listed industries, if 
their emissions exceed a specified threshold level of CO2e. 
Many of the State rules apply to six GHGs (CO2, 
CH4, N2O, HFCs, PFCs, SF6); others 
apply only to CO2 or a subset of the six gases. Most require 
reporting at the facility level, or by unit or process within a 
facility.
    The level of specificity regarding GHG monitoring and calculation 
methods varies. Some of the States refer to use of protocols 
established by TCR or CCAR. Others look to industry-specific protocols 
(such as methods developed by the American Petroleum Institute), to 
accepted international methodologies such as IPCC, and/or to emission 
factors in EPA's Compilation of Air Pollutant

[[Page 16461]]

Emission Factors (known as AP-42 \27\) or other EPA guidance.
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    \27\ See Compilation of Air Pollutant Emission Factors, Fifth 
Edition: http://www.epa.gov/ttn/chief/ap42/index.html_ac/index.html.
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    California Mandatory GHG Reporting Rule.\28\ CARB's mandatory 
reporting rule is an example of a State rule that covers multiple 
source categories and contains relatively detailed requirements, 
similar to this proposal developed by EPA. According to the CARB 
proposed rule (originally proposed October 19, 2007, and revised on 
December 5, 2007), monitoring must start on January 1, 2009, and the 
first reports will be submitted in 2010. The rule requires facility-
level reporting of all GHGs, except PFCs, from cement manufacturing 
plants, electric power generation and retail, cogeneration plants, 
petroleum refineries, hydrogen plants, and facilities with stationary 
combustion sources emitting greater than 25,000 tons CO2 per 
year. California requires 40 CFR part 75 data for EGUs. The California 
rule contains specific GHG estimation methods that are largely 
consistent with CCAR protocols, and also rely on American Petroleum 
Institute protocols and IPCC/EU protocols for certain types of sources. 
California continues to participate in other national and regional 
efforts, such as TCR and WCI, to assist with developing consistent 
reporting tools and procedures on a national and regional basis.
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    \28\ For more information about CA mandatory reporting program 
please see: http://www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm.
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F. How the Proposed Mandatory GHG Reporting Program Is Different From 
the Federal and State Programs EPA Reviewed

    The various existing State and Federal programs EPA reviewed are 
diverse. They apply to different industries, have different thresholds, 
require different pollutants and different types of emissions sources 
to be reported, rely on different monitoring protocols, and require 
different types of data to be reported, depending on the purposes of 
each program. None of the existing programs require nationwide, 
mandatory GHG reporting by facilities in a large number of sectors, so 
EPA's proposed mandatory GHG rule development effort is unique in this 
regard.
    Although the mandatory GHG rule is unique, EPA carefully considered 
other Federal and State programs during development of the proposed 
rule. Documentation of our review of GHG monitoring protocols for each 
source category used by Federal, State, and international voluntary and 
mandatory GHG programs, and our review of State mandatory GHG rules can 
be found at EPA-HQ-OAR-2008-0508-056. The proposed monitoring and GHG 
calculation methodologies for many source categories are the same as, 
or similar to, the methodologies contained in State reporting programs 
such as TCR, CCAR, and State mandatory GHG reporting rules and similar 
to methodologies developed by EPA voluntary programs such as Climate 
Leaders. The reporting requirements set forth in 40 CFR part 75 are 
also being used for this proposed rule. Similarity in proposed methods 
would help maximize the ability of individual reporters to submit the 
emissions calculations to multiple programs, if desired. EPA also 
continues to work closely with States and State-based groups to ensure 
that the data management approach in this proposal would lead to 
efficient submission of data to multiple programs. Section V of this 
preamble includes further information on the selection of monitoring 
methods for each source category.
    The intent of this proposed rule is to collect accurate and 
consistent GHG emissions data that can be used to inform future 
decisions. One goal in developing the rule is to utilize and be 
consistent with the GHG protocols and requirements of other State and 
Federal programs, where appropriate, to make use of existing 
cooperative efforts and reduce the burden to facilities submitting 
reports to other programs. However, we also need to be sure the 
mandatory reporting rule collects facility-specific data of sufficient 
quality to achieve the Agency's objectives for this rule. Therefore, 
some reporting requirements of this proposed rule are different from 
the State programs. The remaining sections of this preamble further 
describe the proposed rule requirements and EPA's rationale for all of 
the requirements.
    EPA seeks comment on whether the conclusions drawn during its 
review of existing programs are accurate and invites data to 
demonstrate if, and if so how, the goals and objectives of this 
proposed mandatory reporting system could be met through existing 
programs. In particular, comments should address how existing programs 
meet the breadth of sources reporting, thresholds for reporting, 
consistency and stringency of methods for reporting, level of 
reporting, frequency of reporting and verification of reports included 
in this proposal.

III. Summary of the General Requirements of the Proposed Rule

    The proposed rule would require reporting of annual emissions of 
CO2, CH4, N2O, SF6, HFCs, 
PFCs, and other fluorinated gases (as defined in proposed 40 CFR part 
98, subpart A). The rule would apply to certain downstream facilities 
that emit GHGs, upstream suppliers of fossil fuels and industrial GHGs, 
and manufacturers of vehicles and engines.\29\ We are proposing that 
reporting be at the facility \30\ level, except that certain suppliers 
of fossil fuels and industrial gases and manufacturers of vehicles and 
engines would report at the corporate level.
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    \29\ We are proposing to incorporate the reporting requirements 
for manufacturers of motor vehicles and engines into the existing 
reporting requirements of 40 CFR parts 86, 89, 90, 91, 92, 94, 1033, 
1039, 1042, 1045, 1048, 1051, and 1054.
    \30\ For the purposes of this proposal, 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.
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A. Who must report?

    Owners and operators of the following facilities and supply 
operations would submit annual GHG emission reports under the proposal:

 A facility that contains any of the source categories listed 
below in any calendar year starting in 2010. For these facilities, the 
GHG emission report would cover all sources in any source category for 
which calculation methodologies are provided in proposed 40 CFR part 
98, subparts B through JJ.
    --Electricity generating facilities that are subject to the ARP, or 
that contain electric generating units that collectively emit 25,000 
metric tons of CO2e or more per year.\31\
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    \31\ This does not include portable equipment or generating 
units designated as emergency generators in a permit issued by a 
state or local air pollution control agency. As described in section 
V.C of the preamble we are taking comment on whether or not a permit 
should be required.
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    --Adipic acid production.
    --Aluminum production.
    --Ammonia manufacturing.
    --Cement production.
    --Electronics--Semiconductor, MEMS, and LCD (LCD) manufacturing 
facilities with an annual production capacity that exceeds any of the 
thresholds listed in this paragraph--Semiconductors:

[[Page 16462]]

1,080 m\2\ silicon, MEMS: 1,202 m\2\ silicon, LCD: 235,700 m\2\ LCD.
    --Electric power systems that include electrical equipment with a 
total nameplace capacity that exceeds 17,820 lbs (7,838 kg) of 
SF6 or PFCs.
    --HCFC-22 production.
    --HFC-23 destruction processes that are not colocated 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.
    --Phosphoric acid production.
    --Silicon carbide production.
    --Soda ash production.
    --Titanium dioxide production.
    --Underground coal mines that are subject to quarterly or more 
frequent sampling by MSHA of ventilation systems.
    --Municipal landfills that generate CH4 in amounts 
equivalent to 25,000 metric tons CO2e or more per year.
    --Manure management systems that emit CH4 and 
N2O in amounts equivalent to 25,000 metric tons 
CO2e or more per year.
 Any facility 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 below that are located at the facility in any calendar year 
starting in 2010. For these facilities, the GHG emission report would 
cover all source categories for which calculation methodologies are 
provided in proposed 40 CFR part 98, subparts B through JJ of the rule.
    --Electricity Generation \32\
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    \32\ This does not include portable equipment or generating 
units designated as emergency generators in a permit issued by a 
state or local air pollution control agency. As described in section 
V.C of the preamble we are taking comment on whether or not a permit 
should be required.
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    --Electronics--Photovoltaic Manufacturing
    --Ethanol Production
    --Ferroalloy Production
    --Fluorinated Greenhouse Gas Production
    --Food Processing
    --Glass Production
    --Hydrogen Production
    --Iron and Steel Production
    --Lead Production
    --Magnesium Production
    --Oil and Natural Gas Systems
    --Pulp and Paper Manufacturing
    --Zinc Production
    --Industrial Landfills
    --Wastewater
 Any facility that in any calendar year starting in 2010 meets 
all three of the conditions listed in this paragraph. For these 
facilities, the GHG emission report would cover emissions from 
stationary fuel combustion sources only. For 2010 only, the facilities 
can submit an abbreviated emissions report according to proposed 40 CFR 
98.3(d).
    --The facility does not contain any source in any source category 
designated in the above two paragraphs;
    --The aggregate maximum rated heat input capacity of the stationary 
fuel combustion units at the facility is 30 mmBtu/hr or greater; and
    --The facility emits 25,000 metric tons CO2e or more per 
year from all stationary fuel combustion sources.\33\
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    \33\ This does not include portable equipment or generating 
units designated as emergency generators in a permit issued by a 
state or local air pollution control agency. As described in section 
V. C of the preamble we are taking comment on whether or not a 
permit should be required.
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 Any supplier of any of the products listed below in any 
calendar year starting in 2010. For these suppliers, the GHG emissions 
report would cover all applicable products for which calculation 
methodologies are provided in proposed 40 CFR part 98, subparts KK 
through PP.
    --Coal.
    --Coal-based liquid fuels.
    --Petroleum products.
    --Natural gas and NGLs.
    --Industrial GHGs: All producers of industrial GHGs, importers and 
exporters of industrial GHGs with total bulk imports or total bulk 
exports that exceed 25,000 metric tons CO2e per year.
    --CO2: All producers of CO2, importers and 
exporters of CO2 or a combination of CO2 and 
other industrial GHGs with total bulk imports or total bulk exports 
that exceed 25,000 metric tons CO2e per year.
 Manufacturers of mobile sources and engines would be required 
to report emissions from the vehicles and engines they produce, 
generally in terms of an emission rate.\34\ These requirements would 
apply to emissions of CO2, CH4, N2O, 
and, where appropriate, HFCs. Manufacturers of the following vehicle 
and engine types would need to report: (1) Manufacturers of passenger 
cars, light trucks, and medium-duty passenger vehicles, (2) 
manufacturers of highway heavy-duty engines and complete vehicles, (3) 
manufacturers of nonroad diesel engines and nonroad large spark-
ignition engines, (4) manufacturers of nonroad small spark-ignition 
engines, marine spark-ignition engines, personal watercraft, highway 
motorcycles, and recreational engines and vehicles, (5) manufacturers 
of locomotive and marine diesel engines, and (6) manufacturers of jet 
and turboprop aircraft engines.
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    \34\ As discussed in Section V.QQ, manufacturers below a size 
threshold would be exempt.
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B. Schedule for Reporting

    Facilities and suppliers would begin collecting data on January 1, 
2010. The first emissions report would be due on March 31, 2011, for 
emissions during 2010.35 36 Reports would be submitted 
annually. Facilities with EGUs that are subject to the ARP would 
continue to report CO2 mass emissions quarterly, as required 
by the ARP, in addition to providing the annual GHG emissions reports 
under this rule. EPA is proposing that the rule require the submission 
of GHG emissions data on an ongoing, annual basis. The snapshot of 
information provided by a one-time information collection request would 
not provide the type of ongoing information which could inform the 
variety of potential policy options being evaluated for addressing 
climate change. EPA is taking comment on other possible options, 
including a commitment to review the continued need for the information 
at a specific later date, or a sunset provision. Once subject to this 
reporting rule, a facility or supply operation would continue to submit 
reports even if it falls below the reporting thresholds in future 
years.
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    \35\ Unless otherwise noted, years and dates in this notice 
refer to calendar years and dates.
    \36\ There is a discussion in section I.IV of this preamble that 
takes comment on alternative reporting schedules.
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C. What do I have to report?

    The report would include total annual GHG emissions in metric tons 
of CO2e aggregated for all the source categories and for all 
supply categories for which emission calculation methods are provided 
in part 98. The report would also separately present annual mass GHG 
emissions for each source category and supply category, by gas. 
Separate reporting requirements are provided for vehicle and engine 
manufacturers. These sources would be required to report emissions from 
the vehicles and engines they produce, generally in terms of an 
emission rate.
    Within a given source category, the report also would break out 
emissions at the level required by the respective subpart (e.g., 
reporting could be

[[Page 16463]]

required for each individual unit for some source categories and for 
each process line for other source categories).
    In addition to GHG emissions, you would report certain activity 
data (e.g., fuel use, feedstock inputs) that were used to generate the 
emissions data. The required activity data are specified in each 
subpart. For some source categories, additional data would be reported 
to support QA/QC and verification.
    EPA would 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 cannot be 
considered CBI.\37\
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    \37\ 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).
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D. How do I submit the report?

    The reports would be submitted electronically, in a format to be 
specified by the Administrator after publication of the final rule.\38\ 
To the extent practicable, we plan to adapt existing 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 reporting mechanisms.
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    \38\ For more information about the reporting format please see 
section VI of this preamble.
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    Each report would contain a signed certification by a Designated 
Representative of the facility. On behalf of the owner or operator, the 
Designated Representative would 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, based on a reasonable inquiry of individuals responsible for 
obtaining the information.

E. What records must I retain?

    Each facility or supplier would also have to retain and make 
available to EPA upon request the following records for five 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;
     Documentation of the process used to collect the necessary 
data for the GHG emissions calculations;
     The GHG emissions calculations and methods used;
     All emission factors used for the GHG emissions 
calculations;
     Any facility operating data or process information used 
for the GHG emissions calculations;
     Names and documentation of key facility personnel involved 
in calculating and reporting the GHG emissions;
     The annual GHG emissions reports;
     A log book documenting any procedural changes to the GHG 
emissions accounting methods and any changes to the instrumentation 
critical to GHG emissions calculations;
     Missing data computations;
     A written QAPP;
     Any other data specified in any applicable subpart of 
proposed 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.

IV. Rationale for the General Reporting, Recordkeeping and Verification 
Requirements That Apply to All Source Categories

    This section of the preamble explains the rationales for EPA's 
proposals for various aspects of the rule. This section applies to all 
of the source categories in the preamble (further discussed in Sections 
V.B through V.PP of this preamble) with the exception of mobile sources 
(discussed in Section V.QQ of this preamble). The proposals EPA is 
making with regard to mobile sources are extensions of existing EPA 
programs and therefore the rationales and decisions are discussed 
wholly within that section. With respect to the source categories B 
through PP, EPA is particularly interested in receiving comments on the 
following issues:
    (1) Reporting thresholds. EPA is interested in receiving data and 
analyses on thresholds. In particular, we solicit comment on whether 
the thresholds proposed are appropriate for each source category or 
whether other emissions or capacity based thresholds should be applied. 
If suggesting alternative thresholds, please discuss whether and how 
they would achieve broad emissions coverage and result in a reasonable 
number of reporters.
    (2) Methodologies. EPA is interested in receiving data, technical 
information and analyses relevant to the methodology approach. We 
solicit comment on whether the methodologies selected by EPA are 
appropriate for each source category or whether alternative approaches 
should be adopted. In particular, EPA would like information on the 
technical feasibility, costs, and relative improvement in accuracy of 
direct measurement at facilities. If suggesting an alternative 
methodology (e.g., using established industry default factors or 
allowing industry groups to propose an industry specific emission 
factor to EPA), please discuss whether and how it provides complete and 
accurate emissions data, comparable to other source categories, and 
also reflects broadly agreed upon calculation procedures for that 
source category.
    (3) Frequency and year of reporting. EPA is interested in receiving 
data and analyses regarding frequency of reporting and the schedule for 
reporting. In particular, we solicit information regarding whether the 
frequency of data collection and reporting selected by EPA is 
appropriate for each source category or whether alternative frequencies 
should be considered (e.g., quarterly or every few years). If 
suggesting an alternative frequency, please discuss whether and how it 
ensures that EPA and the public receive the data in a timely fashion 
that allow it to be relevant for future policy decisions. EPA is 
proposing 2010 data collection and 2011 reporting, however, we are 
interested in receiving comment on alternative schedules if we are 
unable to meet our goal.
    (4) Verification. EPA is interested in receiving data and analyses 
regarding verification options. We solicit input on whether the 
verification approach selected by EPA is appropriate for each source 
category or whether an alternative approach should be adopted. If 
suggesting an alternative verification approach, please discuss how it 
weighs the costs and burden to the reporter and EPA as well as the need 
to ensure the data are complete, accurate, and available in the timely 
fashion.
    (5) Duration of the program. EPA is interested in receiving data 
and analyses regarding options for the duration of the GHG emissions 
information collection program in this proposed rule. By duration, EPA 
means for how many years the program should require the submission of 
information. EPA solicits input on whether the duration selected by EPA 
is appropriate for each source category or whether an alternative 
approach should be adopted. If suggesting an alternative duration, 
please discuss how it impacts the need to ensure the data are 
sufficient to inform the variety of potential policy decisions 
regarding climate change under consideration.

[[Page 16464]]

A. Rationale for Selection of GHGs To Report

    The proposed rule would require reporting of CO2, 
CH4, N2O, HFCs, PFCs, SF6, and other 
fluorinated compounds (e.g., NF3 and HFEs) as defined in the 
rule \39\. These are the most abundantly emitted GHGs that result from 
human activity. They are not currently controlled by other mandatory 
Federal programs and, with the exception of the CO2 
emissions data reported by EGUs subject to the ARP \40\, GHG emissions 
data are also not reported under other mandatory Federal programs. 
CO2 is the largest contributor of GHGs directly emitted by 
human activities, and is a significant driver of climate change. The 
anthropogenic combined heating effect of CH4, 
N2O, HFCs, PFCs, SF6, and the other fluorinated 
compounds are also significant: About 40 percent as large as the 
CO2 heating effect according to the Fourth Assessment Report 
of the IPCC.
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    \39\ The GWPs for the GHGs to be reported are found in Table A-1 
of proposed 40 CFR part 98, subpart A.
    \40\ Pursuant to regulations established under section 821 of 
the CAA Amendments of 1990, hourly CO2 emissions are 
monitored and reported quarterly to EPA. EPA performs a series of 
QA/QC checks on the data and then makes it available on the Web site 
(http://epa.gov/camddataandmaps/) usually within 30 days after 
receipt.
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    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 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 the common focus of the climate change 
research community. The IPCC also included methods for accounting for 
emissions from several specified fluorinated gases in the 2006 IPCC 
Guidelines for National Greenhouse Gas Inventories.\41\ These gases 
include fluorinated ethers, which are used in electronics, anesthetics, 
and as heat transfer fluids. Like the other six GHGs for which 
emissions would be reported, these fluorinated compounds are long-lived 
in the atmosphere and have high GWP. In many cases these fluorinated 
gases are used in expanding industries (e.g., electronics) or as 
substitutes for HFCs. As such, EPA is proposing to include 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.
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    \41\ 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).
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    There are other GHGs and aerosols that have climatic warming 
effects that we are not proposing to include in this rule: Water vapor, 
CFCs, HCFCs, halons, tropospheric O3, and black carbon. 
There are a number of reasons why we are not proposing to require 
reporting of these gases and aerosols under this rule. For example, 
these GHGs and aerosols are not covered under any State or Federal 
voluntary or mandatory GHG program, the UNFCCC or the Inventory of U.S. 
Greenhouse Gas Emissions and Sinks. Nonetheless, we request comment on 
the selection of GHGs that are or are not included in the proposed 
rule; include data supporting your position on why a GHG should or 
should not be included. More detailed discussions for particular 
substances that we do not propose including in this rule follow.
    Water Vapor. Water vapor is the most abundant naturally occurring 
GHG and, therefore, makes up a significant share of the natural, 
background greenhouse effect. However, water vapor emissions from human 
activities have only a negligible effect on atmospheric concentrations 
of water vapor. Significant changes to global atmospheric 
concentrations of water vapor occur indirectly through human-induced 
global warming, which then increases the amount of water vapor in the 
atmosphere because a warmer atmosphere can hold more moisture. 
Therefore, changes in water vapor concentrations are not an initial 
driver of climate change, but rather an effect of climate change which 
then acts as a positive feedback that further enhances warming. For 
this reason, the IPCC does not list direct emissions of water vapor as 
an anthropogenic forcing agent of climate change, but does include this 
water vapor feedback mechanism in response to human-induced warming in 
all modeling scenarios of future climate change. Based on this 
recognition that anthropogenic emissions of water vapor are not a 
significant driver of anthropogenic climate change, EPA's annual 
Inventory of U.S. Greenhouse Gas Emissions and Sinks does not include 
water vapor, and GHG inventory reporting guidelines under the UNFCCC do 
not require data on water vapor emissions.
    ODS. The CFCs, HCFCs, and halons are all strong anthropogenic GHGs 
that are long-lived in the atmosphere and are adding to the global 
anthropogenic heating effect. Therefore, these gases share common 
climatic properties with the other GHGs discussed in this preamble. The 
production and consumption of these substances (and, hence, their 
anthropogenic emissions) are being controlled and phased out, not 
because of their effects on climate change, but because they deplete 
stratospheric O3, which protects against harmful ultraviolet 
B radiation. The control and phase-out of these substances in the U.S. 
and globally is occurring under the Montreal Protocol on Substances 
that Deplete the Ozone Layer, and in the U.S. under Title VI of the CAA 
as well.\42\ Therefore, the climate change research and policy 
community typically does not focus on these substances, precisely 
because they are essentially already being addressed with non-climate 
policy mechanisms. The UNFCCC does not cover these substances, and 
instead defers their treatment to the Montreal Protocol.
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    \42\ Under the Montreal Protocol, production and consumption of 
CFCs were phased out in developed countries in 1996 (with some 
essential use exemptions) and are scheduled for phase-out by 2010 in 
developing countries (with some essential use exemptions). For 
halons the schedule was 1994 for phase out in developed countries 
and 2010 for developing countries; HCFC production was frozen in 
2004 in developed countries, and in 2016 production will be frozen 
in developing countries; and HCFC consumption phase-out dates are 
2030 for developed countries and 2040 in developing countries.
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    Tropospheric Ozone. Increased concentrations of tropospheric 
O3 are causing a significant anthropogenic warming effect, 
but, unlike the long-lived GHGs, tropospheric O3 has a short 
atmospheric lifetime (hours to weeks), and therefore its concentrations 
are more variable over space and time. For these reasons, its global 
heating effect and relevance to climate change tends to entail greater 
uncertainty compared to the well-mixed, long-lived GHGs. Tropospheric 
O3 is not addressed under the UNFCCC. Moreover, tropospheric 
O3 is already listed as a NAAQS pollutant and its precursors 
are reported to States. Tropospheric O3 is subsequently 
modeled based on the precursor data reported to the NEI.
    Black Carbon. Black carbon is an aerosol particle that results from 
incomplete combustion of the carbon contained in fossil fuels, and it 
remains in the atmosphere for about a week. There is some evidence that 
black carbon emissions may contribute to climate warming by absorbing 
incoming and reflected sunlight in the atmosphere and by darkening 
clouds, snow and ice. While the net effect of anthropogenic aerosols 
has a cooling effect (CCSP 2009), there is considerable uncertainty

[[Page 16465]]

in quantifying the effects of black carbon on radiative forcing and 
whether black carbon specifically has direct or indirect warming 
effects. The National Academy of Sciences states ``Regulations 
targeting black carbon emissions or ozone precursors would have 
combined benefits for public health and climate'' \43\ while also 
indicating that the level of scientific understanding regarding the 
effect of black carbon on climate is ``very low.'' The direct and 
indirect radiative forcing properties of multiple aerosols, including 
sulphates, organic carbon, and black carbon, are not well understood. 
While mobile diesel engines have been the largest black carbon source 
in the U.S., these emissions are expected to be reduced significantly 
over the next several decades based on CDPFs for new vehicles.
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    \43\ National Academy of Sciences, ``Radiative Forcing of 
Climate Change: Expanding the Concept and Addressing 
Uncertainties,'' October 2005.
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B. Rationale for Selection of Source Categories To Report

    Section III of this preamble lists the source categories that would 
submit reports under the proposed rule. The source categories 
identified in this list were selected after considering the language of 
the Appropriations Act and the accompanying explanatory statement, 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.'' \44\ In developing the 
proposed list, we also used our significant experience in quantifying 
GHG emissions from source categories across the economy for the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks.
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    \44\ To read the full appropriations language please refer to 
the links on this Web site: http://www.epa.gov/climatechange/emissions/ghgrulemaking.html.
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    As a starting point, EPA first considered all anthropogenic sources 
of GHG emissions. The term ``anthropogenic'' refers to emissions that 
are produced as a result of human activities (e.g., combustion of coal 
in an electric utility or CH4 emissions from a landfill). 
This is in contrast to GHGs that are emitted to the atmosphere as a 
result of natural activities, such as volcanoes. Anthropogenic 
emissions may be of biogenic origin (manure lagoons) or non-biogenic 
origin (e.g., coal mines). Consistent with existing international, 
national, regional, and corporate-level GHG reporting programs, this 
proposal includes only anthropogenic sources.
    As a second step, EPA considered all of the source categories in 
the Inventory of U.S. Greenhouse Gas Emissions and Sinks because, as 
described in Section I.D of this preamble, it is a top-down assessment 
of anthropogenic sources of emissions in the U.S. Furthermore, the 
Inventory has been independently reviewed by national and international 
experts and is considered to be a comprehensive representation of 
national-level GHG emissions and source categories relevant for the 
U.S.
    As a third step, EPA also carefully reviewed the recently completed 
2006 IPCC Guidelines for National Greenhouse Gas Inventories for 
additional source categories that may be relevant for the U.S. These 
international guidelines are just beginning to be incorporated into 
national inventories. The 2006 IPCC Guidelines identified one 
additional source category for consideration (fugitive emissions from 
fluorinated GHG production).
    As a fourth step, once EPA had a complete list of source categories 
relevant to the U.S., the Agency systematically reviewed those source 
categories against the following criteria to develop the list to the 
source categories included in the proposal:
    (1) Include source categories that emit the most significant 
amounts of GHG emissions, while also minimizing the number of 
reporters, and
    (2) Include source categories that can be measured with an 
appropriate level of accuracy.
    To accomplish the first criterion, EPA set reporting thresholds, as 
described in Section IV.C of this preamble, that are designed to target 
large emitters. When the proposed thresholds are applied, the source 
categories included in this proposal meet the criterion of balancing 
the emissions coverage with a reasonable number of reporters. For more 
detailed information about the coverage of emissions and number of 
reporters see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and the RIA 
(EPA-HQ-OAR-2008-0508-002).
    The second criterion was to require reporting for only those 
sources for which measurement capabilities are sufficiently accurate 
and consistent. Under this criterion, EPA considered whether or not 
facility reporting would be as effective as other means of obtaining 
emissions data. For some sources, our understanding of emissions is 
limited by lack of knowledge of source-specific factors. In instances 
where facility-specific calculations are feasible and result in 
sufficiently accurate and consistent estimates, facility-level 
reporting would improve current inventory estimates and EPA's 
understanding of the types and levels of emissions coming from large 
facilities, particularly in the industrial sector. These source 
categories have been included in the proposal. For other source 
categories, uncertainty about emissions is related more to the 
unavailability of emission factors or simple models to estimate 
emissions accurately and at a reasonable cost at the facility-level. 
Under this criterion, we would require facility-level reporting only if 
reporting would provide more accurate estimates than can be obtained by 
other means, such as national or regional-level modeling. For an 
example, please refer to the discussion below on emissions from 
agricultural sources and other land uses.
    As the Agency completed its four step evaluation of source 
categories to include in the proposal, some source categories were 
excluded from consideration and some were added. The reasons for the 
additions and deletions are explained below. In general, the proposed 
reporting rule covers almost all of the source categories in the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks and the 2006 IPCC 
Guidelines for National Greenhouse Gas Inventories.
    Reporting by direct emitters. Consistent with the appropriations 
language regarding reporting of emissions from ``downstream sources,'' 
EPA is proposing reporting requirements from facilities that directly 
emit GHGs above a certain threshold as a result of combustion of fuel 
or processes. The majority of the direct emitters included in this 
proposal are large facilities in the electricity generation or 
industrial sectors. In addition, many of the electricity generation 
facilities are already reporting their CO2 emissions to EPA 
under existing regulations. As such, these facilities have only a 
minimal increase in the amount of data they have to provide EPA on 
their CH4 and N2O emissions. The typical 
industrial facilities that are required to report under this proposal 
have emissions that are substantially higher than the proposed 
thresholds and are already doing many of the measurements and 
quantifications of emissions required by this proposal through existing 
business practices, voluntary programs, or mandatory State-level GHG 
reporting programs.
    For more information about the thresholds included in this proposal 
please refer to Section IV.C of this

[[Page 16466]]

preamble and for more information about the requirements for specific 
sources refer to Section V of this preamble.
    Reporting by fuel and industrial GHG suppliers. \45\ Consistent 
with the appropriations language regarding reporting of emissions from 
``upstream production,'' EPA is proposing reporting requirements from 
upstream suppliers of fossil fuel and industrial GHGs. In the context 
of GHG reporting, ``upstream emissions'' refers to the GHG emissions 
potential of a quantity of industrial gas or fossil fuel supplied into 
the economy. For fossil fuels, the emissions potential is the amount of 
CO2 that would be produced from complete combustion or 
oxidation of the carbon in the fuel. 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, particularly in 
the commercial and residential sectors (e.g., HFCs emitted from home A/
C units or GHG emissions from individual motor vehicles).\46\ To cover 
these direct emissions would require reporting by hundreds or thousands 
of small facilities. To avoid this impact, the proposed rule does not 
include all of those emitters, but instead requires reporting by the 
suppliers of industrial gases and suppliers of fossil fuels. Because 
the GHGs in these products are almost always fully emitted during use, 
reporting these supply data would provide an accurate estimate of 
national emissions while substantially reducing the number of 
reporters.\47\ For this reason, the proposed rule requires reporting by 
suppliers of coal and coal-based products, petroleum products, natural 
gas and NGLs, CO2 gas, and other industrial GHGs. We are not 
proposing to require reporting by suppliers of biomass-based fuels, or 
renewable fuels, due to the fact that GHGs emitted upon combustion of 
these fuels are traditionally taken into account at the point of 
biomass production. However, we seek comment on this approach and note 
that producers of some biomass-based fuels (e.g., ethanol) would be 
subject to reporting requirements for their on-site emissions under 
this proposal, similar to other fuel producers. For more information 
about these source categories please see the source-specific 
discussions in Section V of this preamble.
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    \45\ In this context, suppliers include producers, importers, 
and exporters of fossil fuels and industrial GHGs.
    \46\ While EPA is not proposing any reporting requirements in 
this rule for operators of mobile source fleets, we are requesting 
comment in Section V.QQ.4.b of the Preamble.
    \47\ As an example of estimating the CO2 emissions 
that result from the combustion of fossil fuels, please see, 2006 
IPCC Guidelines for National Greenhouse Gas Inventories, Volume 2--
Energy, Chapter 1--Introduction (http://www.ipcc-nggip.iges.or.jp/public/2006gl/index.html).
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    There is inherent double-reporting of emissions in a program that 
includes both upstream and downstream sources. For example, coal mines 
would report CO2 emissions that would be produced from 
combustion of the coal supplied into the economy, and the receiving 
power plants are already reporting CO2 emissions to EPA from 
burning the coal to generate electricity. This double-reporting is 
nevertheless 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. EPA recognizes the double-reporting 
and as discussed in Section I.D of this preamble does not intend to use 
the upstream and downstream emissions data as a replacement for the 
national emissions estimates found in the Inventory.
    It is possible to construct a reporting system with no double-
reporting. For example, such a system could include fossil fuel 
combustion-related emissions upstream only, based on the fuel 
suppliers, supplemented by emissions reported downstream for industrial 
processes at select industries (e.g., CO2 process emissions 
from the production of cement); fugitive emissions from coal, oil, and 
gas operations; biological processes and mobile source manufacturers. 
Industrial GHG suppliers could be captured completely upstream, thereby 
removing reporting obligations from the use of the industrial gases by 
large downstream users (e.g., magnesium production and SF6 
in electric power systems). Under this option, the total number of 
facilities affected is approximately 32% lower than the proposed 
option, and the private sector costs are approximately 26% lower than 
the proposed option. The emissions coverage remains largely the same as 
the proposed option although it is important to note that some process 
related emissions may not be captured due to the fact that downstream 
combustion sources would not be covered under this option. A source 
with process emission plus combustion emissions would only have to 
report their process emission, thus the exclusion of downstream 
combustion could result in some sources being under the threshold. For 
more information about this analysis and the differences in the number 
of reporters and coverage of emissions, please see the RIA (EPA-HQ-OAR-
2008-0508-002).
    Emissions from agricultural sources and other land uses. The 
proposed rule does not require reporting of GHG emissions from enteric 
fermentation, rice cultivation, field burning of agricultural residues, 
composting (other than as part of a manure management system), 
agricultural soil management, or other land uses and land-use changes, 
such as emissions associated with deforestation, and carbon storage in 
living biomass or harvested wood products. As discussed in Section V of 
this preamble, the proposal does include reporting of emissions from 
manure management systems.
    EPA reports on the GHG emissions and sinks associated with 
agricultural and land-use sources in the Inventory of U.S. Greenhouse 
Gas Emissions and Sinks. In the agriculture sector, the U.S. GHG 
inventory report estimated that agricultural soil management, which 
includes fertilizer application (including synthetic and manure 
fertilizers, etc.), contributed N2O emissions of 265 million 
metric tons CO2e in 2006 and enteric fermentation 
contributed CH4 emissions of 126 million metric tons 
CO2e in 2006. These amounts reflect 3.8 percent and 1.8 
percent of total GHG emissions from anthropogenic sources in 2006. Rice 
cultivation, agricultural field burning, and composting (other than as 
part of a manure management system) contributed emissions of 5.9, 1.2, 
and 3.3 million metric tons CO2e, respectively in 2006. 
Total carbon fluxes, rather than specific emissions from deforestation, 
for U.S. forestlands and other land uses and land-use changes were also 
reported in the U.S. GHG inventory report.
    The challenges to including these direct emission source categories 
in the rule are that practical reporting methods to estimate facility-
level emissions for these sources can be difficult to implement and can 
yield uncertain results. For more information on uncertainty for these 
sources, please refer to the TSD for Biological Process Sources 
Excluded from this Rule (EPA-HQ-OAR-2008-0508-045). Furthermore, these 
sources are characterized by a large number of small emitters. In light 
of these challenges, we have determined that it is impractical to 
require reporting of emissions from these sources in the proposed rule 
at

[[Page 16467]]

this time for the reasons explained below.
    For these sources, currently, there are no direct greenhouse gas 
emission measurement methods available except for research methods that 
are prohibitively expensive and require sophisticated equipment. 
Instead, 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 using emission factor or carbon stock change 
approaches, it would be necessary for landowners to report on 
management practices, and a variety of data inputs. Activity data 
collection and emission factor development necessary for emissions 
calculations at the scale of individual reporters can be complex and 
costly.
    For example, for calculating emissions of N2O from 
agricultural soils, data on nitrogen inputs necessary for accurate 
emissions calculations include: Synthetic fertilizer, organic 
amendments (manure and sludge), waste from grazing animals, crop 
residues, and mineralization of soil organic matter. While some 
activity data can be collected with reasonable certainty, the emissions 
estimates could still have a high degree of uncertainty because the 
emission factors available for individual reporters do not reflect the 
variety of conditions (e.g., soil type, moisture) that need to be 
considered for accurate estimates.
    Without reasonably accurate facility-level emissions factors and 
the ability to accurately measure all facility-level calculation 
variables at a reasonable cost to reporters, facility-level emissions 
reporting would not improve our knowledge of GHG emissions relative to 
national or regional-level emissions models and data available from 
national databases. While a systematic measurement program of these 
sources could improve understanding of the environmental factors and 
management practices that influence emissions, this type of measurement 
program is technically difficult and expensive to implement, and would 
be better accomplished through an empirical research program that 
establishes and maintains rigorous measurements over time.
    Despite the issues associated with reporting by the agriculture and 
land use sectors, threshold analyses were conducted for several source 
categories within these sectors as part of their consideration for 
inclusion in this rule. For some agricultural source categories, the 
number of individual farms covered at various thresholds was estimated. 
The resulting analyses showed that for most of these sources no 
facilities would exceed any of the thresholds evaluated.
    Because facility-level reporting is impracticable, the proposed 
rule contains other provisions to improve our understanding of 
emissions from these source categories. For example, agricultural soil 
management is a significant source of N2O. Activity data, 
including synthetic nitrogen-based fertilizer applications, influence 
N2O emissions from this agricultural source category. To 
gain additional information on synthetic nitrogen-based fertilizers, 
EPA is proposing that the industrial facilities reporting under this 
rule include information on the production and nitrogen content of 
fertilizers as part of their annual reports to EPA. It is estimated 
that all of the synthetic nitrogen-based fertilizer produced in the 
U.S. is manufactured by industrial facilities that are covered under 
this rule due to onsite combustion-related and industrial process 
emissions (e.g., ammonia manufacturing facilities). The reporting 
requirements are contained in proposed 40 CFR part 98, subpart A.
    EPA is requesting comment on this approach. In particular, the 
Agency is looking for information on the usefulness of the fertilizer 
data for estimating N2O emissions from agricultural soils, 
and also on including other possible reporters of synthetic nitrogen-
based fertilizers, such as fertilizer wholesalers or distributors, or 
importers in order to develop a better understanding of the source of 
N2O emissions from fertilizer use.
    For additional background information on emissions from 
agricultural sources and other land use, please refer to the TSD for 
Biological Process Sources Excluded from this Rule (EPA-HQ-OAR-2008-
0508-045).

C. Rationale for Selection of Thresholds

    The proposed rule would establish reporting thresholds at the 
facility level.48 49 50 Only those facilities that exceed a 
threshold as specified in proposed 40 CFR part 98, subpart A would be 
required to submit annual GHG reports.
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    \48\ Facilities reporting under this rule will likely have more 
than one source category within their facility (e.g., a petroleum 
refinery would have to report on its refinery process, combustion, 
landfill and wastewater emissions).
    \49\ 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.
    \50\ A different threshold approach is proposed for vehicle and 
engine manufacturers (when reporting emissions from the vehicles and 
engines the produce). Here, EPA proposes to exempt small businesses 
from reporting requirements, instead of applying an emission-based 
threshold.
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    The thresholds are expressed in several ways (e.g., actual 
emissions or capacity). The use of these different types of thresholds 
is discussed later in this section, but most correspond to an annual 
facility-wide emission level of 25,000 metric tons of CO2e, 
and the thresholds result in covering approximately 85-90 percent of 
U.S. emissions. That level is largely consistent with many of the 
existing GHG reporting programs, including California, which also has a 
25,000 metric ton of CO2e threshold. Furthermore, many 
industry stakeholders that EPA met with expressed support for a 25,000 
metric ton of CO2e threshold because it sufficiently 
captures the majority of GHG emissions in the U.S., while excluding 
smaller facilities and sources.\51\ The three exceptions to the 25,000 
metric ton of CO2e threshold are electricity production at 
selected units subject to existing Federal programs, fugitive emissions 
from coal mining, and emissions from mobile sources. These thresholds 
were selected to be consistent with existing thresholds for reporting 
similar data to EPA and the MSHA. The proposed thresholds maximized the 
rule coverage with over 85 percent of U.S. emissions reported by 
approximately 13,000 reporters, while keeping reporting burden to a 
minimum and excluding small emitters.
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    \51\ To view a summary of EPA's outreach efforts please refer to 
EPA-HQ-OAR-2008-0508-055.
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    Consideration of alternative emissions thresholds. In selecting the 
proposed threshold level, we considered two lower emission threshold 
alternatives and one higher alternative. We collected available data on 
each industry and analyzed the implication of various thresholds in 
terms of number of facilities and level of emissions covered at both 
the industry level and the national level. We also performed a similar 
analysis for each proposed source category to determine if there were 
reasons to develop a different threshold in specific industry sectors. 
From these analyses, we concluded that a 25,000 metric ton threshold 
suited the needs of the reporting program by providing comprehensive 
coverage of

[[Page 16468]]

emissions with a reasonable number of reporters and that having a 
uniform threshold was an equitable approach. This conclusion took into 
account our finding that a threshold other than 25,000 metric tons of 
CO2e might appear to achieve an appropriate balance between 
number of facilities and emissions covered for a limited number of 
source categories. Our conclusions about the alternative thresholds are 
summarized below and in the Thresholds TSD (EPA-HQ-OAR-2008-0508-046), 
and the considerations for individual source categories are explained 
in Section V of this preamble.
    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. Both broaden national emissions coverage but 
do so by disproportionately increasing the number of affected 
facilities (e.g., increasing the number of reporters by an order of 
magnitude in the case of a 1,000 metric tons CO2e/yr 
threshold and doubling the number of reporters in the case of a 10,000 
metric tons CO2e/yr threshold). The majority of stakeholders 
were opposed to these lower thresholds for that reason--the gains in 
emissions coverage are not adequately balanced against the increased 
number of affected facilities.
    A 1,000 metric ton of CO2e per year threshold would 
increase the number of affected facilities by an order of magnitude 
over the proposed threshold. The effect of a 1,000 metric ton threshold 
would be to change the focus of the program from large to small 
emitters. This threshold would impose reporting costs on tens of 
thousands of small businesses that in total would amount to less than 
10 percent of national GHG emissions.
    A 10,000 metric ton of CO2e per year threshold 
approximately doubles the number of facilities affected compared to a 
25,000 metric ton threshold. The effect of a 10,000 metric ton 
threshold would only improve national emissions coverage by 
approximately 1 percent. The extra data that would result from a 10,000 
metric ton threshold would do little to further the objectives of the 
program. EPA believes the 25,000 metric ton threshold more effectively 
targets large industrial emitters, which are responsible for some 90 
percent of U.S. emissions. Similarly, California's mandatory GHG 
reporting program also based their selection of a 25,000 metric ton 
threshold on similar results at the State level.\52\
---------------------------------------------------------------------------

    \52\ For more information on CA analysis please see http://www.arb.ca.gov/regact/2007/ghg2007/isor.pdf.
---------------------------------------------------------------------------

    We also considered 100,000 metric tons of CO2e per year 
as an alternative threshold but concluded that it fails to satisfy two 
key objectives. First, it may exclude enough 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 several large industry sectors would be rather 
significantly fragmented, resulting in an incomplete picture of direct 
emissions from that sector. For example, at a 100,000 metric ton of 
CO2e threshold in ammonia manufacturing, approximately 22 
out of 24 facilities would have to report; in nitric acid production, 
approximately 40 out of 45 facilities would have to report; in lime 
manufacturing, 52 out of 89 facilities would have to report; and in 
pulp and paper, 410 out of 425 facilities would have to report. Several 
stakeholders we met with stressed this potential fragmentation as a 
concern and requested that EPA include all facilities in a particular 
sector to simplify compliance, even if there was some uncertainty about 
whether all facilities in an industry would technically meet a 
particular threshold. For more information about the impact of 
thresholds on different industries, please see the source-specific 
discussion in Section V of this preamble.
    The data collected by this rulemaking is intended to support 
analyses of future policy options. Those options may depend on 
harmonization with State or even international reporting programs. 
Several States and regional GHG programs are using thresholds that are 
comparable in scope to a 25,000 metric ton of CO2e per year 
threshold.\53\ As noted earlier, California specifically chose a 
threshold of 25,000 metric ton of CO2e after analyzing 
CO2 data from the air quality management districts because 
they concluded that level provided the correct balance of emissions 
coverage and number of reporters. Implementing a national reporting 
program using a 100,000, 10,000 or 1,000 metric ton of CO2e 
per year limit would result in a fragmentary dataset insufficient in 
detail or coverage, or a more burdensome reporting requirement, and 
these options would be inconsistent with what many other GHG programs 
are requiring today.
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    \53\ For more information about what different States are 
requiring, see section II of this preamble, the ``Summary of 
Existing State GHG Rules'' memorandum and ``Review of Existing 
Programs'' memorandum found at EPA-HQ-OAR-2008-0508-056 and 054.
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    In addition to the typical emissions thresholds associated with GHG 
reporting and reduction programs (e.g., 25,000 metric tons 
CO2e), under the CAA, there are (1) the Title V program that 
requires all major stationary sources, including all sources that emit 
or have the potential to emit over 100 tons per year of an air 
pollutant, to hold an operating permit \54\ and (2) the PSD/NSR program 
that requires new major sources and sources that are undergoing major 
modifications to obtain a permit. A major source for PSD is defined as 
any source that emits or has the potential to emit either 100 or 250 
tons per year of a regulated pollutant, dependent on the source 
category.\55\ In nonattainment areas, the major source threshold for 
NSR is at most 100 tons per year, and is less in some areas depending 
on the pollutant and the nonattainment classification of the area.
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    \54\ Other sources required to obtain Title V operating permits 
include all sources that are required to have PSD permits, 
``affected sources'' under the ARP, and sources subject to NSPS or 
NESHAP (although non-major sources under those programs can be 
exempted by rule).
    \55\ The 100 tons per year level is the level at which existing 
sources in 28 industry categories listed in the CAA are classified 
as major sources for the PSD program. The 250 tons per year level is 
the level at which existing sources in all other categories are 
classified as major sources for PSD purposes.
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    EPA performed some preliminary analyses to generally estimate the 
existing stock of major sources in order to then estimate the 
approximate number of new facilities that could be required to obtain 
NSR/PSD permits.\56\ For example, if the 100 and 250 tons per year 
thresholds were applied in the context of GHGs, the Agency estimates 
the number of PSD permits required to be issued each year would 
increase by more than a factor of 10 (i.e., more than 2,000 to 3,000 
permits per year). The additional permits would generally be issued to 
smaller industrial sources, as well as large office and residential 
buildings, hotels, large retail establishments, and similar facilities.
---------------------------------------------------------------------------

    \56\ For more information about the major source analysis please 
see docket number EPA-HQ-OAR-2008-0318.
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    For more information about the affect of thresholds considered for 
this rule on the number of reporters, emissions coverage and costs, 
please see Table VIII-2 in Section VIII of this preamble and Table IV-
47 of the RIA found at EPA-HQ-OAR-2008-0508-002.
    Determining applicability to the rule. The thresholds listed in 
proposed 40 CFR part 98, subpart A fall into three groups: Capacity, 
emissions, or ``all in.'' The thresholds developed are generally 
equivalent to a threshold of 25,000 metric tons of CO2e per 
year of actual emissions.
    EPA carefully examined thresholds and source categories that might 
be able

[[Page 16469]]

to report utilizing a capacity metric, for example, tons of product 
produced per year. A capacity-based threshold could be the least 
burdensome alternative for reporting because a facility would not have 
to estimate emissions to determine if the rule applies. However, EPA 
faced two key challenges in trying to develop capacity thresholds. 
First, in most cases we did not have sufficient data to determine an 
appropriate capacity threshold. Secondly, for some source categories 
defining the appropriate capacity metric was not feasible. For example, 
for some source categories, GHG emissions are not related to production 
capacity, but are more affected by design and operating factors.
    The scope of the proposed emission threshold is emissions from all 
applicable source categories located within the physical boundary of a 
facility. To determine emissions to compare to the threshold, a 
facility that directly emits GHGs would estimate total emissions from 
all source categories for which emission estimation methods are 
provided in proposed 40 CFR part 98, subparts C through JJ. The use of 
total emissions is necessary because some facilities are comprised of 
multiple process units or collocated source categories that 
individually may not be large emitters, but that emit significant 
levels of GHGs collectively. The calculation of total emissions for the 
purposes of determining whether a facility exceeds the threshold should 
not include biogenic CO2 emissions (e.g., those resulting 
from combustion of biofuels). Therefore, these emissions, while 
accounted for and reported separately, are not considered in a 
facility's emissions totals.
    In order to ensure that the reporting of GHG emissions from all 
source categories within a facility's boundaries is not unduly 
burdensome, EPA has proposed flexibility in two ways. First, a facility 
would only have to report on the source categories for which there are 
methods provided in this rule. EPA has proposed methods only for source 
categories that typically contribute a relatively significant amount to 
a facility's total GHG emissions (e.g., EPA has not provided a method 
for a facility to account for the CH4 emissions from coal 
piles). Second, for small facilities, EPA has proposed simplified 
emission estimation methods where feasible (e.g., stationary combustion 
equipment under a certain rating can use a simplified mass balance 
approach as opposed to more rigorous direct monitoring).
    The proposed emissions threshold is based on actual emissions, with 
a few exceptions described below. An actual emission metric accounts 
for actual operating practices at each facility. A threshold based on 
potential emissions would bring in far more facilities including many 
small emitters. For example, under a potential emissions threshold, a 
facility that operates one shift a day would have to estimate emissions 
assuming three shifts per day, and would have to assume continuous use 
of feedstocks or fuels that result in the highest rate of GHG emissions 
absent enforceable limitations. Such an approach would be inconsistent 
with the twin goals of collecting accurate data on actual GHG emissions 
to the atmosphere and excluding small emitters from the rule. However, 
we note that emissions thresholds in some CAA rules are based on actual 
or potential emissions. Moreover, although actual emissions may change 
year to year due to fluctuations in the market and other factors, 
potential emissions are less subject to yearly fluctuations. We solicit 
comment on how considerations of actual and potential emissions should 
be incorporated into the proposed threshold.
    There is one source category that has a proposed threshold based on 
GHG generation instead of emissions--municipal landfills. In this case, 
a GHG generation threshold is more appropriate because some landfills 
have installed CH4 gas recovery systems. A gas recovery 
system collects a percentage of the generated CH4, and 
destroys it, through flaring or use in energy recovery equipment. The 
use of a threshold based on GHG generation prior to recovery is 
proposed because it ensures reporting from landfills that have similar 
CH4 emission generating activities (e.g., ensures that 
landfills of similar size and management practices are reporting).
    As described in Section III of this preamble, in the case of 19 
source categories all of the facilities that have that particular 
source category within their boundaries would be subject to the 
proposed rule. For these facilities, our analysis indicated that all 
facilities with that source category emit more than 25,000 metric tons 
of CO2e per year or that only a few facilities emit 
marginally below this level. These source categories include large 
manufacturing operations such as petroleum refineries and cement 
production. This simplifies the applicability determination for 
facilities with these source categories.
    When determining if a facility passes a relevant applicability 
threshold, direct emissions from the source categories would be 
assessed separately from the emissions from the supplier categories. 
For example, a company that produces and supplies coal would be subject 
to reporting as a supplier of coal (40 CFR part 98, subpart KK), 
because coal suppliers is an ``all in'' supplier category. But the 
company would separately evaluate whether or not emissions from their 
underground coal mines (40 CFR part 98, subpart FF) would also be 
reported.
    In addition, the source categories listed in proposed 40 CFR 
98.2(a)(1) and (2) and the supply operations listed in proposed 40 CFR 
98.2(a)(4) represent EPA's best estimate of the large emitters of GHGs 
or large suppliers of fuel and industrial GHGs. In order to ensure that 
all large emitters are included in this reporting program, proposed 40 
CFR 98.2(a)(3) also covers any facility that emits more than 25,000 
metric tons of CO2e per year from stationary fuel combustion 
units at source categories that are not listed in proposed 40 CFR 
98.2(a)(2). To minimize the reporting burden, such facilities would be 
required to submit an annual report that covers stationary combustion 
emissions.
    Furthermore, we recognize that a potentially large number of 
facilities would need to calculate their emissions in order to 
determine whether or not they had to report under proposed 40 CFR 
98.2(a)(3). Therefore, to further minimize the burden on those 
facilities, we are proposing that any facility that has an aggregate 
maximum rated heat input capacity of the stationary fuel combustion 
units less than 30 mmBtu/hr may presume it has emissions below the 
threshold. According to our analysis, a facility with stationary 
combustion units that have a maximum rated heat input capacity of less 
that 30 mmBtu/hr, operating full time (e.g., 8,760 hours per year) with 
all types of fossil fuel would not exceed 25,000 metric tons 
CO2e/yr (EPA-HQ-OAR-2008-0508-049). Under this approach, we 
estimate that approximately 30,000 facilities would have to assess 
whether or not they had to report according to proposed 40 CFR 
98.2(a)(3).\57\ Of the 30,000, approximately 13,000 facilities would 
likely meet the threshold and have to report. Therefore, an additional 
17,000 facilities may have to assess their applicability but 
potentially not meet the threshold for reporting. We concluded that is 
a reasonable number of assessments in order to ensure all

[[Page 16470]]

large emitters in the U.S. are included in this reporting program. We 
are seeking comment on (1) whether the presumption for maximum rated 
heat input capacity of 30 mmBtu/hr is appropriate, (2) whether a 
different (lower or higher) mmBtu/hr capacity presumption should be set 
and (3) whether other capacity thresholds should be developed for 
different types of facilities. The comments should contain data and 
analysis to support the use of different thresholds.
---------------------------------------------------------------------------

    \57\ This estimate is based on the Energy and Environmental 
Analysis, ``Characterization of the U.S. Industrial/Commercial 
Boiler Population'' (2005) (EPA-HQ-OAR-2008-0508-050). We assumed 3 
boilers per manufacturing facility and 1 boiler per commercial 
facility. For additional information on the impact to these 30,000 
facilities, please see the ICR and RIA (EPA-HQ-OAR-2008-0508-002).
---------------------------------------------------------------------------

    We are proposing that once a facility is subject to this reporting 
rule, it would continue to submit annual reports even if it falls below 
the reporting thresholds in future years. (As discussed in section 
IV.K. of this preamble, EPA is proposing that this rule require the 
submission of data into the foreseeable future, although EPA is 
soliciting comment on other options.) The purpose of the thresholds is 
to exclude small sources from reporting. For sources that trigger the 
thresholds, it is important for the purpose of policy analysis to be 
able to track trends in emissions and understand factors that influence 
emission levels. The data would be most useful if the population of 
reporting sources is consistent, complete and not varying over time.
    The one exception to the proposed requirement to continue 
submitting reports even if a facility falls below the reporting 
threshold is active underground coal mines. When coal is no longer 
produced at a mine, the mine often becomes abandoned. As discussed in 
Section V.FF of this preamble, we are proposing to exclude abandoned 
coal mines from the proposed rule, and therefore methods are not 
proposed for this source category.
    We recognize that in some cases, this provision of ``once in, 
always in'' could potentially act as a disincentive for some facilities 
to reduce their emissions because under this proposal those facilities 
that did lower their emissions below the treshold would have to 
continue to report. To address this issue in California, CARB's 
mandatory reporting rule offers a facility that has emissions under the 
threshold for three consecutive years the opportunity to be exempt from 
the reporting program. We request comment on whether EPA should develop 
a similar process for this reporting program. Comments should include 
specifics on how the exemption process could work, e.g., the number of 
years a facility is under the threshold before they could be exempt, 
the quantity of emissions reductions required before a facility could 
be exempt, whether a facility should formally apply to EPA for an 
exemption or if it is automatic, etc.
    EPA requests comment on the need for developing simplified 
emissions calculation tools for certain source categories to assist 
potential reporters in determining applicability. These simplified 
calculation tools would provide conservatively high emission estimates 
as an aid in identifying facilities that could be subject to the rule. 
Actual facility applicability would be determined using the methods 
presented for each source category in the rule.
    For additional information about the threshold analysis EPA 
conducted see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046) and the 
individual source category discussions in Section V of this preamble. 
In addition, Section V.QQ of this preamble describes the threshold for 
vehicle and engine manufacturers, which is a different approach from 
what is described in this section.

D. Rationale for Selection of Level of Reporting

    EPA is proposing facility-level reporting for most source 
categories under this program. Specifically, the owner or operator of a 
facility would be required to report its GHG emissions from all source 
categories for which there are methods developed and listed in this 
proposal. For example, a petroleum refinery would have to report its 
emissions resulting from stationary combustion, production processes, 
and any fugitive or biological emissions. Facility-level reporting by 
owners or operators is consistent with other CAA or State-level 
regulatory programs that typically require facility or unit level data 
and compliance (e.g., ARP, NSPS, RGGI, and the California and New 
Mexico mandatory GHG reporting rules). This approach allows flexibility 
for firms to determine whether the owner or operator of the facility 
would report and avoid the challenges of establishing complex reporting 
rules based on equity or operational control.
    In addition to reporting emissions at the total facility level, the 
emissions would also be broken out by source category (e.g., a 
petroleum refinery would separately identify its emissions for refinery 
production processes, wastewater, onsite landfills, and any other 
source categories listed in proposed 40 CFR part 98, subpart A that are 
located onsite). This would enable EPA to understand what types of 
emission sources are being reported, determine that the facility is 
reporting for all required source categories, and use the source-
category specific estimates for future policy development. Within each 
source category, further breakout of emissions by process or unit may 
be specified. Information on process or unit-level reporting and 
associated rationale is contained in the source category sections 
within Section V of this preamble.
    Although many voluntary programs such as Climate Leaders or TCR 
have corporate-level reporting systems, EPA concluded that corporate-
level reporting is overly complex under a mandatory system involving 
many reporters and thus is not appropriate for this rule, except where 
discussed below. Complex ownership structures and the frequent changes 
in ownership structure make it difficult to establish accountability 
over time and ensure consistent and uniform data collection at the 
facility-level. Because the best technical knowledge of emitting 
processes and emission levels exists at the facility level, this is 
where responsibility for reporting should be placed. Furthermore, the 
ability to differentiate and track the level and type of emissions by 
facility, unit or process, is essential for development of certain 
types of future policy (e.g., NSPS).
    The only exception to facility level reporting is for some supplier 
source categories (e.g., importers of fuels and industrial GHGs or 
manufacturers of motor vehicles and engines). Importers are not 
individual facilities in the traditional sense of the word. The type of 
information reported by motor vehicle and engine manufacturers is an 
extension of long-standing existing reporting requirements (e.g., 
reporting of criteria emissions rates from vehicle and engine 
manufacturers) and as such does not necessitate a change in reporting 
level. The reporting level for these source categories is specified in 
Section V of this preamble.

E. Rationale for Selecting the Reporting Year

    EPA is proposing that the monitoring and reporting requirements 
would start on January 1, 2010.\58\ The first report to EPA would be 
submitted by March 31, 2011, and would cover calendar year 2010. The 
year 2011 is therefore referred to as the first reporting year, and 
includes 2010 data (there is a discussion later in this section that 
takes comment on alternative approaches to the reporting year). EPA is 
requesting comment on whether or not we should select an alternative 
reporting date that

[[Page 16471]]

corresponds with the requirements of an existing reporting system.
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    \58\ The exception is for vehicle and engine manufacturers when 
reporting emissions from the vehicles and engines they produce. For 
these sources, reporting requirements would apply beginning with the 
2011 model year.
---------------------------------------------------------------------------

    For existing facilities that meet the applicability criteria in 
proposed 40 CFR part 98, subpart A, monitoring would begin on January 
1, 2010. For new facilities that begin operation after January 1, 2010, 
monitoring would begin with the first month that the facility is 
operating and end on December 31 of that same calendar year in which 
they start operating. Each subsequent monitoring year would begin on 
January 1 and end on December 31 of each calendar year. EPA is 
proposing that new facilities monitor and report emissions for the 
first partial year after they begin operating so that EPA has as 
complete an inventory as possible of GHG emissions for each calendar 
year.
    Due to the comprehensive reporting and monitoring requirements in 
this proposal, the Agency has concluded that it is not appropriate to 
require reporting of historical emissions data for years before 2010. 
Compiling, submitting, and verifying historical data according to the 
methodologies specified in this rule would create additional burdens on 
both the affected facilities and the Agency, and much of the needed 
data might not be available. Because Federal policy for GHG emissions 
is still being developed, the Agency's focus is on collecting data of 
known quality that is generated on a consistent basis. Collecting 
historic emissions data would introduce data of unknown quality that 
would not be comparable to the data reported under the program for 
years 2011 and beyond.
    The first year of monitoring for existing facilities would begin on 
January 1, 2010. This schedule would give existing facilities lead time 
after the date the rule is promulgated to prepare for monitoring and 
reporting. Preparation would include studying the final rule, 
determining whether it applies to the facility, identifying the 
requirements with which the facility must comply, and preparing to 
monitor and collect the required data needed to calculate and report 
GHG emissions.
    A beginning date of January 1, 2010 would allow sufficient time to 
begin monitoring and collecting data because many of the parameters 
that would need to be monitored under the proposed rule are already 
monitored by facilities for process management and accounting reasons 
(e.g., feedstock input rates, production output, fuel purchases). In 
addition, the monitoring methods specified by the rule are already 
well-known and documented; and monitoring devices required by the rule 
are routinely available, in ready supply (e.g., flow meters, automatic 
data recorders), and in some cases already installed. These same 
monitoring devices are already required by other air quality programs 
with which many of these same facilities are already complying.
    It is reasonable for new sources that start operation after January 
1, 2010, to begin monitoring the first month of operation because new 
sources would be aware of the rule requirements when they design the 
facility and its processes and obtain permits. They can plan the data 
collection and reporting processes and install needed monitoring 
equipment as they build the facility and begin operating the monitoring 
equipment when they begin operating the facility.
    We recognize that although the Agency plans to issue the final rule 
in sufficient time to begin monitoring on January 1, 2010, we may be 
unable to meet that goal. Therefore, we are interested in receiving 
comments on alternative effective dates, including the following two 
options:
     Report 2010 data in 2011 using best available data: Under 
this scenario, the rule would be effective January 1, 2010, allowing 
affected facilities to use either the methods in proposed 40 CFR part 
98 or best available data. As in the current proposal, the report would 
be submitted on March 31, 2011, and then full data collection, using 
the methods in 40 CFR part 98 would begin in 2011, with that report 
sent to EPA on March 31, 2012. Under this approach, EPA solicits 
comment on the types of best available data and methods that should be 
allowed in 2010, by source category, (e.g., fuel consumption, emissions 
by process, default emissions factors, fuel receipts, etc.) as well as 
additional basic data that should be reported (e.g., facility name, 
location). This approach is similar to the CARB mandatory reporting 
rule, which allowed affected facilities to report 2009 emissions in 
2010 using best available data, and then requires 2010 data collection 
in 2011 using the methods in the rule. The advantages of this approach 
are that the dates of the proposal remain intact and EPA receives basic 
information, including emissions and fuel data from all affected 
facilities in 2011. Furthermore, this approach can ease facilities into 
the program by giving them potentially a full year to implement the 
required methods and install any necessary equipment. For example, this 
option encourages the use of the methods in 40 CFR part 98 but if that 
is not possible, it allows the use of best available data (e.g., if a 
facility does not have a required flow meter installed for 2010 they 
can substitute the data from their fuel receipts in the calculation). 
The disadvantage of this approach is that it delays full data 
collection using the methods in the rule by 1 year from what is 
proposed. Further, in some cases, this approach could lead to data that 
is of lesser quality than the data we would receive using the methods 
in 40 CFR part 98. In other cases, because sources are already 
following the methods in 40 CFR part 98 (e.g., stationary combustion 
units in the ARP), the quality of the data would remain unchanged under 
this option. Given the objective of this rule to collect comprehensive 
and accurate data to inform future policies and the interest in 
Congress in developing climate change legislation, any delay in 
receiving that data could adversely affect the ability to inform those 
policies. That said, the data we would receive in 2011 under this 
option would at least provide basic information about the types, 
locations, emissions and fuel consumption from facilities in the United 
States.
     Report 2011 data in 2012: Under this scenario, the rule 
would require that affected facilities begin collecting data January 1, 
2011 and submit the first reports to EPA on March 31, 2012. The methods 
in the proposed rule would remain unchanged and the only difference is 
that this option would delay implementation of the rule by one year. 
The advantages of this approach are that affected facilities would have 
a substantial amount of time to prepare for this reporting rule, 
including implementing the method and installing equipment. In 
addition, we would have even more time to conduct outreach and guidance 
to affected facilities. The disadvantages of this approach are that it 
delays implementation of this rule by a year and does not offer a 
mechanism for EPA to receive crucial data, even basic data, necessary 
to inform future policy and regulatory development. Furthermore, in 
some cases affected facilities are already implementing the methods 
required by proposed 40 CFR part 98 (e.g., stationary combustion units 
in the ARP) or are familiar with the methods, and have all of the 
necessary equipment or processes in place to monitor emissions 
consistent with the methods in 40 CFR part 98. Therefore, delaying 
implementation by a year not only deprives EPA of valuable data to 
support future policy development, but at the same time, does not 
provide any real advantage to these facilities.
    Proposed 40 CFR part 98, subpart A, specifies numerical reporting 
thresholds for different direct emitters or supply

[[Page 16472]]

operations. A facility or supply operation that exceeds any of these 
reporting thresholds in 2010 would submit a full emissions report in 
reporting year 2011, which contains calendar year 2010 data. The 
facilities and supply operations that contain many of the source 
categories that are listed in 40 CFR part 98, subpart A are larger 
facilities that have been participating in a variety of mandatory and 
voluntary GHG emissions programs. Therefore, those facilities and 
supply operations should be familiar with the methods and able to 
comply with the requirements and submit a full report without 
significant burden.
    As discussed earlier, if a facility does not have any of the source 
categories listed in proposed 40 CFR 98.2 (a)(1) or (2), but has 
stationary combustion onsite that exceeds the GHG reporting threshold 
in 2010, they would still be required to estimate GHG emissions in 2010 
and report in 2011. However, because those facilities would not contain 
any of the source categories specifically identified in proposed 40 CFR 
98.2 (a)(1) or (2) and tend to be smaller facilities in diverse 
industrial sectors, they may require some extra time to implement the 
requirements of this rule. As such, they would be allowed to use an 
abbreviated facility report using simplified emission estimation 
methods for the first year (i.e., for calendar year 2010) and would not 
be required to complete a full report until the second reporting year 
(i.e., 2012).
    The abbreviated report would allow the facility to use default 
fuel-specific CO2 emission factors. They would not be 
required to determine actual fuel carbon content or to use a CEMS to 
determine CO2 emissions, as they may otherwise be required 
to do with a full report. This provision for abbreviated reporting 
requirements has been proposed because there are potentially many 
facilities that are not in the listed industries, but are required to 
report solely due to stationary combustion sources at their facility. 
These include numerous and diverse sources in a wide variety of 
industries, some of which may not be as familiar with GHG monitoring 
and reporting. Such sources may often need more time to determine if 
they are above the threshold and subject to the rule and, if they are, 
to implement the full monitoring and reporting systems required. 
Therefore, the abbreviated report with simpler estimating methodologies 
is being proposed for these sources for the first year of monitoring 
and reporting.
    EPA proposes that the annual GHG emissions reports would be 
submitted no later than March 31 for the previous calendar year's 
reporting period. Three months is a reasonable time to compile and 
review the information needed for the annual GHG emissions report and 
to prepare and submit the report. The data needed to estimate emissions 
and compile the report would be collected by the facility on an ongoing 
basis throughout the year, so facilities could begin data summary 
during the year as the data are collected. For example, they could 
compile needed GHG calculation input data (e.g., fuel use or raw 
material consumption data) or emission data on a periodic basis (e.g., 
monthly or quarterly) throughout the year and then total it at the end 
of the year. Therefore, only the most recently collected information 
would need to be compiled and a final set of calculations would need to 
be performed before the final report is assembled. Given the nature of 
the methodologies contained in the rule, three months is sufficient 
time to calculate emissions, quality-assure, certify, and submit the 
data.

F. Rationale for Selecting the Frequency of Reporting

    EPA is proposing that all affected facilities would have to submit 
annual GHG emission 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. The annual CO2 
mass emissions from the ARP reports would simply be converted to metric 
tons and included in the GHG report. This approach should not impose a 
significant burden on ARP sources.
    We have determined that annual reporting is sufficient for policy 
development. It is consistent with other existing mandatory and 
voluntary GHG reporting programs at the State and Federal levels (e.g., 
TCR, several individual State mandatory GHG reporting rules, EPA 
voluntary partnership programs, the DOE voluntary GHG registry). 
However, as future policies develop it may be necessary to reconsider 
the reporting frequency and require more or less frequent reporting 
(e.g., quarterly or every few years). For example, under future 
programs or policy initiatives, particularly if regulatory in nature 
(e.g., a cap-and-trade program similar to the ARP) it may be more 
appropriate require quarterly reporting.

G. Rationale for the Emissions Information To Report

1. General Content of Reports
    Generally, we propose that facilities report emissions for all 
source categories at the facility for which methods have been defined 
in any subpart of proposed 40 CFR part 98. Facilities would report (1) 
total annual GHG emissions in metric tons CO2e and (2) 
separately present annual mass emissions of each individual GHG for 
each source category at the facility .\59\ 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 would be valuable for 
future policy development and help EPA quantify the relative 
contribution of each gas to a source category's emissions, while 
maintaining the transparency of reporting total mass of individual 
gases released by facility, unit, or process.
---------------------------------------------------------------------------

    \59\ Consistent with the IPCC, the CARB reporting rule and the 
EU Emission Trading System, the proposed rule requires units to 
separately report the biogenic portion of their total annual 
CO2 emissions.
---------------------------------------------------------------------------

    Emissions would be reported at the level (facility, process, unit) 
at which the emission calculation methods are specified in each 
applicable subpart. For example, if a pulp and paper mill has three 
boilers and a wastewater treatment operation, the facility would report 
emissions for each boiler (according to the methodologies presented in 
proposed 40 CFR part 98, subpart C), the wastewater treatment operation 
(according to proposed 40 CFR part 98, subpart II), and from chemical 
recovery units, lime kilns, and makeup chemicals (according to proposed 
40 CFR part 98, subpart AA). In addition, the report would include 
summary information on certain process operating data that influence 
the level of emissions and that are necessary to calculate GHG 
emissions and verify those calculations using the methodologies in the 
rule. Examples of these data include fuel type and amount, raw material 
inputs, or production output. The specific process information to 
report varies for each source category and is specified in each 
subpart.
    Furthermore, in addition to any specific requirements for reporting 
emissions from electricity generation in Sections V.C and V.D of this 
preamble, EPA is proposing that all facilities and supply operations 
affected by this rule would also report the quantity of electricity 
generated onsite. The generation of onsite electricity can

[[Page 16473]]

represent a relatively significant fraction of onsite fuel use. We seek 
comment on whether this information would be useful to support future 
climate policy development, given the other data related to GHG 
emissions from electricity generation already collected under other 
sections of this proposed rule. At this point, we do not propose 
separate reporting of the onsite electricity generation by generation 
source (e.g., combined heat and power or renewable or fossil-based) due 
to the burden on reporters, but we recognize the potential value of 
being able to discern the quantity of electricity being generated from 
renewable and non-renewable sources. We are seeking comment on the 
value of collecting this data; and if it is collected, whether there is 
a need to separately report the kilowatt-hours by type of generation 
source.
    We are also taking comment on, but not proposing at this time, 
requiring facilities and supply operations affected by the proposed 
rule to also report the quantity of electricity purchased. For many 
industrial facilities, purchased electricity represents a large part of 
onsite energy consumption, and their overall GHG emissions footprint 
when taking into account the indirect emissions from fossil fuel 
combusted for the electricity generated. Together, the reporting of 
electricity purchase data and onsite generation could provide a better 
understanding of how electricity is used in the economy and the major 
industry sectors.
    Many existing reporting programs require reporting of indirect 
emissions (e.g., Climate Leaders, CARB, TCR, DOE 1605(b) program). In 
general, the protocols for these programs follow the methods developed 
by WRI/WBCSD for the quantification and reporting of indirect emissions 
from the purchase of electricity. The WRI/WBCSD protocol outlines three 
scopes to help delineate direct and indirect emission sources, with the 
stated goal to improve transparency, and provide utility for different 
types of organizations and different types of climate policies and 
business goals. Scope 1 includes direct GHG emissions occurring from 
sources that are owned or controlled by the business. Scope 2 includes 
indirect GHG emissions resulting from the generation of purchased 
electricity, heat, and/or steam. Scope 3 is optional and includes other 
types of indirect emissions (e.g., from production of purchased 
materials, waste disposal or employee transportation).
    We are taking comment on, but not proposing at this time, an 
approach that would require the reporting of electricity purchase data, 
and not indirect emissions, because these data are more readily 
available to all facilities. Through the review of existing reporting 
programs that require the reporting of indirect emissions data it was 
determined that there are multiple ways proposed to calculate indirect 
emissions from electricity purchases. This reflects the challenge 
associated with determining the specific fossil fuel mix used to 
generate the electricity consumed by a facility, and thus the indirect 
emissions that should be attributed to the facility. Although indirect 
emissions data would not be directly reported under this approach, it 
would enable indirect emissions for facilities to be calculated. This 
option also would be the least burdensome to reporting facilities since 
the data would be easily available.
    The information that is proposed to be reported reflects the data 
that could support analyses of GHG emissions for future policy 
development and ensure the data are accurate and comparable across 
source categories. Besides total facility emissions, it benefits 
policymakers to understand: (1) The specific sources of the 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. This level of reporting should not be overly 
burdensome because many of these data already are routinely monitored 
and recorded by facilities for business reasons. The remainder of the 
reported data would need to be collected to determine GHG emissions.
    The report would contain a signed certification from a 
representative designated by the owner or operator of a facility 
affected by this rule. This ``Designated Representative'' would act as 
a legal representative between the source and the Agency. The use of 
the Designated Representative would simplify the administration of the 
program while ensuring the accountability of an owner or operator for 
emission reports and other requirements of the mandatory GHG reporting 
rule. The Designated Representative would certify that data submitted 
are complete, true, and accurate. The Designated Representative could 
appoint an alternate to act on their behalf, but the Designated 
Representative would maintain legal responsibility for the submission 
of complete, true, and accurate emissions data and supplemental data.
    Besides these general reporting requirements, the specific 
reporting requirements for each source category are described in the 
methodological discussions in Section V of this preamble.
2. De minimis Reporting for Minor Emission Points
    A number of existing GHG reporting programs contain ``de minimis'' 
provisions. The goal of a de minimis provision is to avoid imposing 
excessive reporting costs on minor emission points that can be 
burdensome or infeasible to monitor. Existing GHG reporting programs 
recognize that it may not be possible or efficient to specify the 
reporting methods for every source that must be reported and, 
therefore, have some type of provision to reduce the burden for smaller 
emissions sources. Depending on the program, the reporter is allowed to 
either not report a subset of emissions (e.g., 2 to 5 percent of 
facility-level emissions) or use simplified calculation methods for de 
minimis sources.
    We analyzed the de minimis provisions of existing reporting rules 
and concluded that there is no need to exclude a percentage of 
emissions from reporting under this proposal. EPA recognizes the 
potential burden of reporting emissions for smaller sources. The 
proposal addresses this concern in several ways. First, only those 
facilities over the established thresholds would be required to report. 
Smaller facilities would not be subject to the program. Second, for 
those facilities subject to the rule, only emissions from those source 
categories for which methods are provided would be reported. Methods 
are not proposed for what are typically smaller sources of emissions 
(e.g., coal piles on industrial sites). Third, because some facilities 
subject to the rule could still have some relatively small sources, the 
proposal includes simplified emissions estimation methods for smaller 
sources, where appropriate. For example, small stationary combustion 
units could use a default emission factor and heat rate to estimate 
emissions, and no fuel measurements would be required. Where simplified 
methods are proposed, they are described in the relevant discussions in 
Section V of this preamble.
    Our analysis showed that the GHG reporting programs with de minimis 
exclusions are structured differently than our proposed rule. For 
example, most rules with de minimis exclusions require corporate level 
reporting of all emission sources. Under these programs, some 
corporations must report emissions from numerous remote facilities and 
must report emissions from small onsite equipment (e.g., lawn mowers). 
For these programs, a de minimis exclusion avoids potentially

[[Page 16474]]

unreasonable reporting burdens. The recent trend in these programs, 
however, is to require full reporting of all required GHG emissions, 
but allow simplified calculation procedures for small sources. In 
contrast to these other reporting programs, today's proposed rule would 
affect only larger facilities, would require reporting of significant 
emission points only, and would contain simplified reporting where 
practicable. Accordingly, a de minimis exclusion is not necessary. EPA 
requests comment on whether this approach to smaller sources of 
emissions is appropriate or if we should include some type of de 
minimis provision.
    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-
2008-0508-048).
3. Recalculation and Missing Data
    Most voluntary and mandatory GHG reporting programs include 
provisions for operators to revise previously submitted data. For 
example, some voluntary programs require reporters to revise their base 
year emissions calculations if there is a significant change in the 
boundary of a reporter, a change in methodologies or input data, a 
calculation error, or a combination of the above that leads to a 
significant change in emissions. Recalculation procedures particularly 
appear to be central in voluntary GHG reporting programs that are also 
tracking emissions reductions.
    Moreover, some programs (e.g., ARP) have detailed provisions for 
filling in data gaps that are missing in the required report. For 
example, in ARP, these procedures apply when CEMS are not functioning 
and as a result several hours of the required hourly data are missing. 
Note, however, that merely filling in data gaps that are missing or 
correcting calculation errors does not relieve an operator from 
liability for failure to properly calculate, monitor and test as 
required.
    For this mandatory GHG reporting program, EPA concluded it was 
important to have missing data procedures in order to ensure there is a 
complete report of emissions from a particular facility. However, 
because this program requires annual reporting rather than quarterly 
reporting of hourly data as in ARP, the missing data provision often 
require the facility to redo the test or calculation of emissions. 
Section V of the preamble details the missing data procedures for 
facilities reporting to this program. EPA is seeking comment on whether 
to include a provision to require a minimum standard for reported data 
(e.g., only 10 percent of the data reported can be generated using 
missing data procedures).
    In addition to establishing procedures for missing data, there may 
be benefit in requiring previously submitted data to be recalculated in 
order to ensure that the GHG emissions reported by a facility are as 
accurate as possible. The proposed California mandatory GHG reporting 
program, for example, allows reporters to revise submitted emissions 
data if errors are identified, subject to approval by the program.
    EPA is considering whether or not to include provisions to require 
facilities to correct previously submitted data under certain 
circumstances. However, these benefits must also be weighed against the 
additional costs associated with requiring reporters to recalculate and 
resubmit previous data, and the magnitude of the emissions changes 
expected from such recalculations. Moreover, even if EPA were to allow 
recalculation of submitted data or accept data submitted using missing 
data procedures, that would not relieve the reporter of their 
obligation to report data that are complete, accurate and in accordance 
with the requirements of this rule. Although submitting recalculated 
data or data using missing data procedures would correct the data that 
are wrong, that resubmission or missing data procedures does not 
necessarily reverse the potential rule violation and would not relieve 
the reporter of any penalties associated with that violation. EPA is 
seeking comment on whether the mandatory GHG reporting program should 
include provisions to require reporters to submit recalculated data and 
under what circumstances such recalculations should be required.

H. Rationale for Monitoring Requirements

    In selecting the monitoring requirements for the proposed rule, 
EPA's goal is to collect data of sufficient accuracy and quality to be 
used to inform future climate policy development and support a range of 
possible policies and regulations. Future policies and regulations 
could range from research and development initiatives to regulatory 
programs (e.g. , cap-and-trade programs). Accurate and timely 
information is critical to making policy decisions and developing 
programs. However, EPA recognizes that methods that provide the most 
accurate data may also entail higher data collection costs. In 
selecting a general monitoring approach, EPA considered the relative 
accuracy and costs of different approaches, the monitoring methods 
already in use within the regulated industries, and consistency with 
the monitoring approaches required by various Federal and State 
mandatory and voluntary GHG reporting programs. Measurement methods can 
range from continuous direct emissions measurements to simple 
calculation methods that rely on default factors and assumptions. EPA 
considered four broad monitoring approaches for the mandatory GHG rule. 
These general approaches (options 1 through 4) and the rationale for 
the selected approach are described in this section. After a general 
approach was selected, EPA developed the specific proposed monitoring 
methods for each source category as described in Section V of this 
preamble.
    Option 1. Direct Emission Measurement. Option 1 would require 
direct measurement of GHGs for all source categories where direct 
measurement is feasible. It would require installation of CEMS for 
CO2 in the stacks from stationary combustion units and 
industrial processes. The approach would be similar to 40 CFR part 75 
that require coal-fired EGUs to install, operate, and maintain CEMs for 
SO2 and NOX emissions and report hourly emissions 
data (although some lower-emitting units have the option to use fuel 
sampling and fuel flow rate metering to determine emissions). Like 40 
CFR part 75, the direct measurement approach would have detailed 
requirements for the CEMS including stringent QA/QC requirements to 
monitor accuracy and precision.
    Direct measurement is not technically feasible in all cases. For 
example, CEMS are not available for many of the GHGs that must be 
reported. Direct measurement is also infeasible for emissions that are 
not captured and emitted through a stack, such as CH4 
emissions from the surface of landfills or fugitive emissions from 
selected oil and natural gas operations. For sources where direct 
measurement is not technically feasible, this option would require the 
use of rigorous methods with a comparable level of accuracy to CEMS.
    The direct measurement option has the highest degree of certainty 
of the data reported. It is also the most costly because all facilities 
where direct measurement is feasible would need to install, operate, 
and maintain emission monitors. Most facilities currently do not have 
CEMS to measure GHG emissions.
    Option 2. Combination of Direct Emission Measurement and Facility-
Specific Calculations. This option

[[Page 16475]]

would require direct measurement of emissions from units at facilities 
that already are required to collect and report data using CEMS under 
other Federally enforceable programs (e.g., ARP, NSPS, NESHAP, SIPs). 
In some cases, this may require upgrading existing CEMS that currently 
monitor criteria pollutants to also monitor CO2.
    Facilities that do not have units that have CEMS installed would 
have the choice to either directly measure emissions or to use 
facility-specific GHG calculation methods. The measurement and 
calculation methods for each source category would be specified in each 
subpart. Depending on the source category, methods could include mass 
balance; measurement of the facility's use of fuels, raw materials, or 
additives combined with site-specific measured carbon content of these 
materials; or other procedures that rely on facility-specific data. For 
the supplier source categories (e.g., those that supply fuels or 
industrial GHGs), this option would require reporting of production, 
import, and export data. The supplier companies already closely track 
these data for financial and other reasons.
    This option provides a relatively high degree of certainty and 
takes advantage of existing practices at facilities. This option is 
less costly than option 1 because most facilities are not required to 
install CEMS and can, in many cases, make use of data they are already 
collecting for other reasons.
    Option 3. Simplified Calculation Methods. Under option 3, 
facilities would calculate emissions using simple inputs (e.g., total 
annual production) that are usually already measured for other reasons, 
and EPA-supplied default emission factors (many of which have been 
developed by industry consortiums, such as the World Resources 
Institute/World Business Council for Sustainable Development (WRI/
WBCSD) (Cement Sustainability Initiative) Protocol). The default 
emission factors would represent national average factors. These 
methods and emission factors would not take into account facility-
specific differences in processes or in the composition of raw 
materials, fuels, or products.
    Under this option, the only facilities that would have to use more 
rigorous monitoring or site-specific calculations methods are 
facilities that are already required to report emissions under 40 CFR 
part 75. These facilities would continue to follow the CO2 
monitoring and reporting requirements of 40 CFR part 75.
    Data collected under this option would have a lower degree of 
certainty than options 1 or 2. Furthermore, many facilities are already 
calculating GHG emissions to a higher degree of certainty for business 
reasons or for other mandatory or voluntary reporting programs, and 
option 3 would not make use of such available data. However, the cost 
to facilities is lower than under options 1 and 2.
    Option 4. Reporter's Choice of Methods. Under this approach, 
reporters would have flexibility to select any measurement or 
calculation method and any emission factors for determining emissions. 
The rule would not prescribe any methods or present any specific 
options for determining emissions.
    Data collected under this option would not be comparable across a 
given industry and across reporters subject to the program, thereby 
minimizing the usefulness of the data to support future policymaking. 
Although some facilities might choose to use direct measurement because 
CEMS are already installed at the facility, other facilities would 
select default calculations. This option would be the lowest cost to 
reporters.
    Proposed Option. For the proposed rule, EPA selected option 2 
(combination of direct measurement and facility-specific calculations) 
as the general monitoring approach. This option results in relatively 
high quality data for use in developing climate policies and supporting 
a wide range of potential future policy options. Because we do not yet 
know which specific policy options the data may ultimately be used to 
support, the reported GHG emission estimates should have a sufficient 
degree of certainty such that they could be used to help develop a 
potential variety of programs.
    Option 2 strikes a 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., TCR, California programs, Climate 
Leaders). Because this option specifies methods for each source 
category, it should result in data that are comparable across 
facilities.
    Option 1 (direct emission measurement) was not chosen because the 
cost to the reporters if all facilities had to install continuous 
emission monitoring systems would be unreasonably high in the absence 
of a defined policy that would require this type of monitoring. 
However, under the selected option, facilities that already use CEMS 
would still be required to use them for purposes of the GHG reporting 
rule.
    Option 3 (simplified calculation methods) was not chosen because 
the data would be less accurate than option 2 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. 
Option 3 would also be inconsistent with several other GHG reporting 
programs such as TCR and California programs that contain more site-
specific calculation methods for several of the source categories.
    Option 4 (reporter's choice of methods) was not proposed because 
the accuracy and reliability of the reported data would be unknown and 
would vary from one reporter to the next. Because consistent methods 
would not be used under this option, the reported data would not be 
comparable across similar facilities. The lack of comparability would 
undermine the use of the data to support policy decisions.
    EPA requests comments on the selected monitoring approach and on 
other potential options and their advantages and disadvantages.

I. Rationale for Selecting the Recordkeeping Requirements

    EPA is proposing that each facility that would be required to 
submit an annual GHG report would also keep the following records, in 
addition to any records prescribed in each applicable subpart:
     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;
     Documentation of the process used to collect the necessary 
data for the GHG emissions calculations;
     The GHG emissions calculations and methods used;
     All emission factors used for the GHG emissions 
calculations;
     Any facility operating data or process information used 
for the GHG emissions calculations;
     Names and documentation of key facility personnel involved 
in calculating and reporting the GHG emissions;
     The annual GHG emissions reports;
     A log book documenting any procedural changes to the GHG 
emissions accounting methods and any changes to the instrumentation 
critical to GHG emissions calculations;
     Missing data computations;
     A written QAPP;
     Any other data specified in any applicable subpart of 
proposed 40 CFR part 98. Examples of such data could

[[Page 16476]]

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.
    These data are needed to verify the accuracy of reported GHG 
emission calculations and, if needed, to reproduce GHG emission 
estimates using the methods prescribed in the proposed rule. Since the 
above information must be collected in order to calculate GHG 
emissions, the added burden of maintaining records of that information 
should be minimal.
    Each facility would be required to retain all required records for 
at least 5 years. Records would be maintained for this period so that a 
history of compliance could be demonstrated and questions about past 
emission estimates could be resolved, if needed.
    The records would be required to be kept in an electronic or hard-
copy format (as appropriate) that is readily accessible within a 
reasonable time for onsite inspection and auditing. They would be 
recorded in a form that can be easily inspected and reviewed. The 
allowance of a variety of electronic and hard copy formats for records 
allows flexibility for facilities to use a system that meets their 
needs and is consistent with other facility records maintenance 
practices, thereby minimizing the recordkeeping burden.

J. Rationale for Verification Requirements

1. General Approach to Verification Proposed in This Rule
    GHG emissions reported under this rule would be verified to ensure 
accuracy and completeness so that EPA and the public could be confident 
in using the data for developing climate policies and potential future 
regulations. To ensure the completeness and quality of data reported to 
the program, the Agency proposes self-certification with EPA 
verification. Under this approach, all reporters subject to this rule 
would certify that the information they submit to EPA is truthful, 
accurate and complete. EPA would then review the emissions data and 
supporting data submitted by reporters to verify that the GHG emission 
reports are complete, accurate, and meet the reporting requirements of 
this rule.
    Given the scope of this rulemaking, this approach is consistent 
with many EPA regulatory programs. That said, this proposal does not 
preclude that in the future, as climate policies evolve, EPA may 
consider third party verification for other programs (e.g., offsets). 
Furthermore, many programs in the States and Regions may be broader in 
scope and the use of third party verifiers may be appropriate to meet 
the needs of those programs.
    In addition, under the authorities of CAA sections 114 and 208, EPA 
has the authority to independently conduct site visits to observe 
monitoring procedures, review records, and verify compliance with this 
rule (see Section VII of this preamble for further information on 
compliance and enforcement). For vehicle and engine manufacturers, EPA 
is not proposing additional verification requirements beyond the 
current emissions testing and certification procedures. These 
procedures include well-established methods for assuring the 
completeness and quality of reported emission test data and EPA is 
proposing to include the new GHG reporting requirements as part of 
these methods.
2. Options Considered
    In selecting this proposed approach to verification, the Agency 
reviewed verification requirements and procedures under a number of 
existing EPA regulatory programs, as well as existing domestic and 
international GHG reporting programs. Additional information on this 
review and the verification approaches can be found in a technical 
memorandum (``Review of Verification Systems in Environmental Reporting 
Programs,'' EPA-HQ-OAR-2008-0508-047). Based on this review, EPA 
considered three alternative approaches to verification: (1) Self-
certification without independent verification, (2) self-certification 
with third-party verification, and (3) self-certification with EPA 
verification.
    Option 1. Self-certification without independent verification. 
Under this option, the Designated Representative of the reporting 
facility would be required to sign and submit a certification statement 
as part of each annual emissions report. The certification would affirm 
that the report has been prepared in accordance with the requirements 
of the GHG reporting rule, and that the emissions data and other 
information reported is true and accurate to the best knowledge and 
belief of the certifying official. The reasons for requiring self-
certification are contained in Section IV.G of this preamble. Under 
option 1, EPA would not independently verify the accuracy and 
consistency of the reported data. Furthermore, because this approach 
does not include independent verification by EPA or a third party, the 
facility would not have to submit the detailed data needed to verify 
emissions estimates. Such information would be retained at the 
facility. For example, facilities would not be required to submit 
detailed monitoring data, activity data (e.g., fuel use, raw material 
consumption, production rates), carbon content measurements, or 
emission factor data used to calculate emissions.
    Option 1 is a low burden option for reporters submitting data for 
this rule. Reporters under this option would not have to pay for third-
party verifiers and would not necessarily have to submit the additional 
data required under the other options. In addition, EPA would not incur 
the expense of conducting verification of the reported data or 
certifying independent verifiers to conduct verification activities. 
The major disadvantages of this approach are the greater potential for 
inconsistent and inaccurate data in the absence of independent 
verification and the lower level of confidence that the public, 
stakeholders and EPA may have in the data.
    Option 2. Self-certification with third-party verification. Under 
this approach, reporters would submit the same self-certification 
statements as under option 1. In addition, reporters would be required 
to hire independent third-party verifiers. The third-party verifiers 
would review the emissions report and the underlying monitoring system 
records, activity data collection, calculation procedures, and 
documentation, and submit a verification statement that the reported 
emissions are accurate and free of material misstatement. Under this 
approach, records supporting the GHG emissions calculations would be 
retained at the facility for compliance purposes and provided to the 
verifiers, but not submitted to EPA. In addition, as discussed below, 
EPA would have to establish a system to certify the independent 
verifiers.
    Self-certification with third-party verification provides greater 
assurance of accuracy and impartiality than self-certification without 
verification. While this option is consistent with some existing 
domestic and international GHG reporting programs such as TCR, the 
California mandatory reporting rule, CCAR, and the EU Emission Trading 
System, the majority of industry stakeholders that met with EPA are 
opposed to this approach for this rulemaking, primarily due to the 
additional cost. Compared to option 1, the third-party verification 
approach places two additional costs on reporters: (1) Reporters would 
need to hire and pay verifiers, at a cost of thousands of dollars per 
reporting facility, and (2) reporters would incur costs to assemble

[[Page 16477]]

and provide to verifiers detailed supporting data for the emission 
estimates.
    To ensure consistency and quality of the third-party verifications, 
EPA would need to develop verification protocols, establish a system to 
qualify and accredit the third-party verifiers, and conduct ongoing 
oversight and auditing of verifications to be sure that third-party 
verifications continue to be conducted in a consistent and high quality 
manner.
    As mentioned above, as climate policy evolves, it may be 
appropriate for EPA to consider the use of third party verification in 
other circumstances (e.g., offsets).
    Option 3. Self-certification with EPA verification. Under this 
option, reporters would submit the same self-certification as under 
option 1. Reporters also would assemble data to support their emissions 
estimates, similar to option 2 but submit it to EPA in their annual 
emission reports, rather than to a third party verifier. EPA would 
review the emissions estimates and the supporting data contained in the 
reports, and perform other activities (e.g., comparison of data across 
similar facilities, site visits) to verify that the reported emissions 
data are accurate and complete.
    EPA verification provides greater assurance of accuracy and 
impartiality than self-reporting without verification. Compared to a 
third-party verification system, there would be a consistent approach 
to verification from one centralized verifier rather than a variety of 
separate verifiers although this option would require EPA to ensure 
consistency if it chose to use its own contractors to support its 
verification activities. In addition, a centralized verification system 
would provide greater ability to the government to identify trends and 
outliers in data and thus assist with targeted enforcement planning. 
Finally, an EPA verification approach is consistent with other EPA 
emissions reporting programs including EPA's ARP.\60\ The cost to the 
reporter is intermediate between options 1 and 2. Although this 
approach would not subject reporters to the cost of paying for third-
party verifiers, reporters would have to assemble and submit detailed 
supporting data to ensure proper verification by EPA. An EPA 
verification program would result in greater costs to the Agency than 
options 1 and 2, but due to economies of scale may result in lower 
overall costs.
---------------------------------------------------------------------------

    \60\ For a description of how verification is conducted in ARP 
please see, ``Fundamentals of Successful Monitoring, Reporting, and 
Verification under a Cap-and-Trade Program.'' John Schakenbach, 
Robert Vollaro, and Reynaldo Forte, U.S. EPA/OAP. Journal of the Air 
and Waste Management Association 56:1576-1583. November 2006. (EPA-
HQ-OAR-2008-0508-051.)
---------------------------------------------------------------------------

3. Selection of Self-Certification With EPA Verification as the 
Proposed Approach
    EPA is proposing self-certification with EPA verification (option 
3) because it ensures that data reported under this rule are 
consistent, accurate, and complete. In addition, we are seeking comment 
on requiring third-party verification for suppliers of petroleum 
products, many of whom currently report to EPA under the Office of 
Transportation and Air Quality's fuels programs. Third-party 
verification could be reasonable in these instances because this rule, 
to some extent, would build on existing transportation fuels programs 
that already require audits of records maintained by these suppliers by 
independent certified public accountants or certified internal 
auditors. For more information about the approach to fuel suppliers 
please refer to Section V of this preamble.
    EPA is successfully using self certification with EPA verification 
in a number of other emissions reporting programs. EPA verification 
option provides greater assurance of the accuracy, completeness, and 
consistency of the reported data than option 1 (no independent 
verification) and consistent with feedback from industry stakeholders, 
does not require reporters to hire third-party verifiers (option 2). In 
addition, EPA verification option does not require the establishment of 
an accreditation and approval program for third-party verifiers 
although it would require EPA to ensure consistency if it chose to use 
its own contractors to support its verification activities.
    EPA judged that option 1 (no independent verification) does not 
ensure sufficient quality data for the possible future uses of the 
data. The potential inconsistency, inaccuracy, and increased 
uncertainty of the data collected under option 1 would make the data 
less useful for informing decisions on climate policy and supporting 
the development of a wide range of potential future policies and 
regulations.
    We selected EPA verification (option 3) instead of third-party 
verification (option 2) because EPA verification is consistent with 
other EPA programs, has lower costs to reporters than option 2, and 
would result in a consistent verification approach applied to all 
submitted data. Even with a verifier accreditation and approval 
process, the third-party verification approach could entail a risk of 
inconsistent verifications because verification responsibilities are 
spread amongst numerous verifiers. Given the potential diversity of 
verifiers, the quality and thoroughness of verifications may be 
inconsistent and EPA audit and enforcement oversight would become the 
predominant factor in ensuring uniformity. Under option 2, EPA would 
also need to develop and administer a process to ensure that verifiers 
hired by the 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. Finally, EPA verification would likely avoid any 
delays that may be introduced by third-party verification and better 
ensure the timely reporting and use of the reported data. Some 
reporting programs provide four to six months after the annual 
emissions report is submitted for third-party verification. That said, 
as mentioned above, depending on the scope or type of program (e.g., 
offsets), EPA may consider the use of third party verification in the 
future as policy options evolve.
    The Agency recognizes that, in some instances, data submitted by 
reporters under this rule may have been independently verified as the 
result of other mandatory or voluntary GHG reporting programs or by 
other Federal, State or local regulations. Whether or not data have 
been independently verified outside of the requirements of this 
proposed GHG reporting rule, EPA has concluded for the purposes of this 
proposal it is important to apply the same verification requirements to 
all affected facilities in order to ensure equity across all reporters 
and consistent data collection for policy analysis and public 
information.

K. Rationale for Selection of Duration of the Program

    EPA is proposing that the rule require the reporting of GHG 
emissions data on an ongoing, annual basis. Other approaches that EPA 
considered include a one-time collection of information and collection 
of a limited duration (e.g., a three-year data collection effort).
    EPA does not believe that a one-time data collection effort is 
consistent with the legislative history of the FY 2008 Consolidated 
Appropriations Act, which instructed EPA to develop a rule to require 
the reporting of GHG emissions. Typically, a rule is not required to 
undertake a one-time information collection request. Moreover, the 
President's FY 2010

[[Page 16478]]

Budget, as well as initial Congressional budgets for the remainder of 
FY 2009 indicate that policy makers anticipate that the information 
will be collected for multiple years.
    For example, on February 6, 2009, Senators Feinstein, Boxer, Snowe 
and Klobuchar sent a letter to EPA's Administrator Lisa Jackson and 
OMB's Director Peter Orszag stating that this program allowed EPA to 
``gather critical baseline data on greenhouse gas emissions, which is 
essential information that policymakers need to craft an effective 
climate change approach.'' In addition, in recent testimony from John 
Stephenson, Director of Natural Resources and Environment at the 
Government Accountability Office,\61\ stated that when setting 
baselines for past regulatory policies, averaging data ``across several 
years also helped to ensure that the baseline reflected changes in 
emissions that can result in a given year due to economic and other 
conditions.'' The testimony further noted the because EPA's ARP was 
able to average several years worth of data when setting the baseline 
for SO2 reductions, the program ``achieved greater 
assurances that it reduced emissions from historical levels'' as 
opposed to the EU who did not have enough data to set accurate 
baselines for the first phase of the EU Emissions Trading System. 
Furthermore, EPA's experience with certain CAA programs show that a 
one-time snapshot of information is not always representative of normal 
operations, and hence emissions, of a facility. See, e.g., Final New 
Source Review (NSR) Reform Rules, 68 FR 80186, 80199 (2002). Finally, 
as discussed earlier, a multi-year reporting program allows EPA to 
track trends in emissions and understand factors that influence 
emissions levels.
---------------------------------------------------------------------------

    \61\ High Quality Greenhouse Gas Emissions Data are a 
Cornerstone of Programs to Address Climate Change, Statement of John 
Stephenson, Director, Natural Resources and Environment, Government 
Accountability Office, February 24, 2009.
---------------------------------------------------------------------------

    EPA also considered a multi-year program that would sunset at a 
date certain in the future (e.g., three years) absent subsequent 
regulatory action by EPA to extend it. EPA decided against this 
approach because it would unnecessarily limit the debate about 
potential policy options to address climate change. At this time, it 
would be premature to guess at what point in the future this 
information may be less relevant to decision-making. Rather, a more 
prudent approach is to maintain the program until such time in the 
future when it is determined that the information for one or more 
source categories is no longer relevant to decision-making, or is 
adequately provided in the context of regulatory program (e.g., CAA 
NSPS). Notably, EPA crafted the requirements in this rule with the 
potential monitoring, recordkeeping and reporting requirements for any 
future regulations addressing GHG emissions in mind. EPA solicits 
comment on all of these possible approaches, including whether EPA 
should commit to revisit the continued necessity of the reporting 
program at a future date.

V. Rationale for the Reporting, Recordkeeping and Verification 
Requirements for Specific Source Categories

    Section V of this preamble discusses the source categories covered 
by the proposed rule. Each section presents a description of a source 
category and the proposed threshold, monitoring methods, missing data 
procedures, and reporting and recordkeeping requirements.

A. Overview of Reporting for Specific Source Categories

    Once you have determined that your facility exceeds any reporting 
threshold specified in 40 CFR 98.2(a), you would have to calculate and 
report GHG emissions, or alternate information as required (e.g., 
production and imports for industrial GHG suppliers) for all source 
categories at your facility for which there are measurement methods 
provided. The threshold determination is separately assessed for 
suppliers (fossil fuel suppliers and industrial GHG suppliers) and 
downstream source categories.
    Facilities, or corporations, where relevant, that trigger only the 
threshold for upstream fossil fuel or industrial GHG supply (proposed 
40 CFR part 98, subparts KK through PP) need only follow the methods in 
those respective sections. Facilities (or corporations) that contain 
source categories that also have downstream sources of emissions (e.g., 
proposed 40 CFR part 98, subparts B through JJ), or facilities that are 
exclusively downstream sources of emissions may have to monitor and 
report GHG emissions using methods presented in multiple sections. For 
example, a food processing facility should review Section V.C (General 
Stationary Fuel Combustion), Section V.HH (Landfills) and Section V.II 
(Wastewater Treatment) in addition to Section V.M (Food Processing) of 
this preamble. Table 2 of this preamble (in the SUPPLEMENTARY 
INFORMATION section of this preamble) provides a cross walk to aid 
facilities 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 V 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 would be relevant 
to all reporters. The remainder of this overview summarizes the general 
approach to calculating and reporting these downstream sources of 
emissions.
    Consistent with the requirements in the proposed 40 CFR part 98, 
subpart A, facilities would have to report GHG emissions from all 
source categories located at their facility--stationary combustion, 
process (e.g., iron and steel), fugitive (e.g., oil and gas) or 
biologic (e.g., landfills) sources of GHG emissions. The methods 
presented typically account for normal operating conditions, as well as 
SSM, where significant (e.g., HCFC-22 production and oil and gas 
systems). Although SSM is not specifically addressed for many source 
categories, emissions estimation methodologies relying on CEMS or mass 
balance approaches would capture these different operating conditions.
    For many facilities, calculating facility-wide emissions would 
simply involve adding GHG emissions calculated under Section V.C of 
this preamble (General Stationary Fuel Combustion Sources) and 
emissions calculated under the source-specific subpart. For other 
facilities, particularly selected sources in Sections V.E through V.JJ 
of this preamble that rely on mass balance approaches or the use of 
CEMS, the proposed methods would (depending on the operating conditions 
and configuration of the plant) capture both combustion and process-
related emissions and there is no need to separately quantify 
combustion-related emissions using the methods presented in Section V.C 
of this preamble.
    Generally, the proposed method depends on the equipment you 
currently have installed at the facility.
    Sources with CEMS. If you have CEMS that meet the requirements in 
proposed 40 CFR part 98, subpart C you would be required to quantify 
and report the CO2 emissions that can be monitored using the 
existing CEMS. Non-CO2 combustion-related emissions would be 
estimated consistent with proposed 40 CFR part 98, subpart C, and other 
non-CO2 emissions would be estimated using the source-
specific methods provided.

[[Page 16479]]

    (1) Where the CEMS capture both combustion- and process-related 
emissions you would be required to follow the calculation procedures, 
monitoring and QA/QC methods, missing data procedures, reporting 
requirements, and recordkeeping requirements of proposed 40 CFR part 
98, subpart C to estimate emissions from the industrial source. In this 
case, use of the additional methods provided in the source-specific 
discussions would not be required.
    (2) Where the CEMS do not capture both combustion and process-
related emissions, you should refer to the source-specific sections 
that provide methods for calculating process emissions. You would also 
be required to follow the calculation procedures, monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of proposed 40 CFR part 98, subpart C to 
estimate any stationary fuel combustion emissions from the industrial 
source.
    Sources without CEMS. If you do not have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, you would 
be required to carry out facility-specific calculations to estimate 
process emissions. You would also be required to follow the calculation 
procedures, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements of proposed 40 
CFR part 98, subpart C to estimate any stationary fuel combustion 
emissions from the industrial source.

B. Electricity Purchases

    At this time, we are not proposing that facilities report 
information to us regarding their electricity purchases or indirect 
emissions from electricity consumption. However, we carefully 
considered proposing that all facilities that report to us also report 
their total purchases of electricity. This section describes our 
deliberations and outlines potential methods for monitoring and 
reporting electricity purchases. We generally seek comment on the value 
of collecting information on electricity purchases. Further, we are 
specifically interested in receiving feedback on the approach outlined 
below.
1. Definition of the Source Category
    The electric utility sector is the largest emitter of GHG emissions 
in the U.S. The level of GHG emissions associated with electricity use 
is determined not just by the fuel and combustion technology onsite at 
the power plant, but also by customer demand for electricity. 
Accordingly, electricity use and the efficiency of this use indirectly 
affect the emissions of CO2, CH4 and 
N2O from the combustion of fossil fuel at electric 
generating stations.
    For many facilities, purchased electricity represents a large part 
of onsite energy consumption, and their overall GHG emissions footprint 
when taking into account the indirect emissions from fossil fuel 
combusted for the electricity generated. Therefore, the reporting of 
electricity purchase data from facilities could provide a better 
understanding of how electricity is used in the economy and the major 
sectors. We would propose not to provide for adjustments to take into 
account the purchases of renewable energy credits or other mechanisms.
    If included, this source category would include electricity 
purchases, but not include electricity generated onsite (i.e., 
facility-operated power plants, emergency back-up generators, or any 
portable, temporary, or other process internal combustion engines). 
General requirements for all reporters subject to the proposed rule to 
report on total kilowatt hours of electricity generated onsite is 
discussed in Section IV.G of the preamble. Calculating emissions from 
onsite electricity generation is addressed in Sections V.C and V.D of 
this preamble.
    For additional background information on indirect emissions from 
electricity purchases, please refer to the Electricity Purchases TSD 
(EPA-HQ-OAR-2008-0508-003).
2. Selection of Reporting Threshold
    Three options for reporting thresholds could be considered for the 
reporting of indirect emissions from purchased electricity (i.e., GHG 
emissions from the production of purchased electricity). These options 
would be as follows:
    Option 1: Do not require any reporting on electricity purchases or 
associated indirect emissions from electricity purchases as part of 
this rule.
    Option 2: Require reporting on 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 
emissions threshold (including indirect emissions from the purchased 
electricity). Reporting for this option could be proposed either in 
terms of electricity purchases or calculated indirect CO2e 
emissions based on purchased electricity. This option would require an 
additional number of reporters, based on their annual electricity 
purchases, to report indirect emissions.
    No additional facilities to those already reporting their emissions 
data under this rule would be affected by the first or second options. 
The number of additional facilities affected by the third proposed 
threshold is estimated to be approximately: 250 facilities at a 100,000 
metric tons CO2e threshold; 5,000 total facilities at a 
25,000 metric tons CO2e threshold; 15,000 total facilities 
at a 10,000 metric tons CO2e threshold; and 185,000 total 
facilities at a 1,000 metric tons CO2e threshold.
    Under all threshold options, reporting of information related to 
electricity purchases would apply to entities reporting at the facility 
level. This provision would not apply to source categories that we 
propose report at the corporate level (e.g., importers and exporters of 
industrial GHGs, local distribution companies, etc.). These companies 
in many cases may own large facilities such as refineries which already 
have a reporting obligation for direct emissions and electricity 
purchases.
    Given the above considerations, our preferred option would be 
option 2. Purchased electricity is considered to be a significant 
portion of the GHG emissions of most industrial facilities, therefore 
the collection of indirect emissions from purchased electricity could 
be seen as an important component of the GHG mandatory reporting rule. 
Although such a reporting requirement would not provide EPA with 
emissions information, it could provide the necessary underlying data 
to develop emissions estimates in the future if this were necessary.
    The reporting of electricity purchase data directly instead of 
calculated indirect emissions would be preferred due to the 
difficulties in identifying the appropriate electrical grid or 
electrical plant emission factor for converting a facility's 
electricity purchases to GHG emissions. EPA does not have data to 
evaluate the uncertainty of applying national, regional or State 
emission factors to electricity consumption at a given facility, versus 
undertaking detailed studies to determine the actual emissions from 
electricity purchases.
    Under Option 2, all facilities that are already required to report 
their GHG emissions under this rule would also have to quantify and 
report their annual electricity purchases. The total purchased 
electricity would include electricity purchased from all sources (i.e., 
fossil fuel power plants, green power generating facilities, etc.). It 
should be noted that under this approach, data from large sources of 
indirect emissions due to electricity

[[Page 16480]]

usage (e.g., non-industrial commercial buildings) would be not be 
collected.
3. Selection of Proposed Monitoring Methods
    Purchased electricity could be quantified through the use of 
purchase receipts or similar records provided by the electricity 
provider. The facility could choose to use data from facility 
maintained electric meters in addition to or in lieu of data from an 
electricity provider (e.g., electricity purchase receipts, etc.), 
provided that this data could be demonstrated to accurately reflect 
facility electricity purchases. However, purchase receipts or 
electricity provider data would be the preferred method of quantifying 
a facility's electricity purchases. Because facilities would be 
expected to retain these data as part of routine financial records, the 
only additional burden of collecting this information would be to 
retain the records in a readily available manner.
    In identifying the options outlined above, we reviewed five 
reporting programs and guidelines: (1) EPA Climate Leaders Program, (2) 
the CARB Mandatory Greenhouse Gas Emissions Program, (3) TRI, (4) the 
DOE 1605(b) program, and (5) the GHG Protocol developed jointly by WRI 
and WBCSD. In general, these protocols follow the methods presented in 
WRI/WBCSD for the quantification and reporting of indirect emissions 
from the purchase of electricity.
    See the Electricity Purchases TSD (EPA-HQ-OAR-2008-0508-003) for 
more information.
4. Selection of Procedures for Estimating Missing Data
    If we were to collect information on electricity purchases, we 
would propose that a facility be required to make all attempts to 
collect electricity records from their electricity provider. In the 
event that there were missing electricity purchase records, the 
facility would estimate its electricity purchases for the missing data 
period based on historical data (i.e., previous electricity purchase 
records). Any historical data used to estimate missing data should 
represent similar circumstances to the period over which data are 
missing (e.g., seasonal). If a facility were using electric meter data 
and had a missing data period, the facility could use a substitute data 
value developed by averaging the quality-assured values metered values 
for kilowatt-hours of electricity use immediately before and 
immediately after the missing data period.
5. Selection of Data Reporting Requirements
    If we were to collect information on electricity purchases, we 
would propose that a facility report total annual purchased electricity 
in kilowatt-hours for the entire facility.
6. Selection of Records That Must Be Retained
    If we were to collect information on electricity purchases, we 
would propose that the owner or operator maintain monthly electricity 
purchase records for all operations and buildings. If electric meter 
data were used, then monthly logs of the electric meter readings would 
also be proposed to be maintained.

C. General Stationary Fuel Combustion Sources

1. Definition of the Source Category
    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, combustion turbines, 
engines, incinerators, and process heaters. The combustion process may 
be used to: (a) Generate steam or produce useful heat or energy for 
industrial, commercial, or institutional use; (b) produce electricity; 
or (c) reduce the volume of waste by removing combustible matter. As 
discussed in Section III of this preamble and proposed 40 CFR part 98, 
subpart A, this section applies to facilities with stationary fuel 
combustion sources that (a) have emissions greater than or equal to 
25,000 metric tons CO2e/yr; or (b) are referred to this 
section by other source categories listed in proposed 40 CFR 98.2(a)(1) 
or (2).
    Combustion of fossil fuels in the U.S. is the largest source of GHG 
emissions in the nation, producing three principal greenhouse gases: 
CO2, CH4 and N2O. For the purposes of 
this rule, CO2, CH4, and N2O would be 
reported by stationary fuel combustion sources. The emission rate of 
CO2 is directly proportional to the carbon content of the 
fuel, and virtually all of the carbon is oxidized to CO2. 
The emission rates of CH4 and N2O are much less 
predictable, as these gases are by-products of incomplete or 
inefficient combustion, and depend on many factors such as combustion 
technology and other considerations. The CO2 emissions 
generated by fuel combustion far exceed the CH4 and 
N2O emissions (CH4 and N2O contribute 
less than 1 percent of combined U.S. GHG emissions from stationary 
combustion, on a CO2e basis), however, under this proposed 
rule, CO2, CH4, and N2O would all be 
reported by stationary fuel combustion sources. EPA is proposing to not 
require reporting of emissions from portable equipment or generating 
units designated as emergency generators in a permit issued by a state 
or local air pollution control agency. We request comment on whether or 
not a permit should be required for these emergency generators.
    A wide and diverse segment of the U.S. economy engages in 
stationary combustion, principally the combustion of fossil fuels. 
According to the ``Inventory of U.S. Greenhouse Gas Emissions and 
Sinks: 1990-2006'', the nationwide GHG emissions from stationary fossil 
fuel combustion are approximately 3.75 billion metric tons 
CO2e per year. This estimate includes both large and small 
stationary sources and represents more than 50 percent of total GHG 
emissions in the U.S.
    EPA's proposed rule presents methods for calculating GHG emissions 
from stationary combustion, both at unspecified facilities as well as 
facilities in source categories listed in proposed 40 CFR 98.2(a)(1) 
and (2), which are based on the fuel combusted and the size of the 
stationary equipment (e.g., the maximum heat input capacity in mmBtu/
hr). EPA already collects CO2 emissions data from 
electricity generating units in the ARP,\62\ which combust the vast 
majority of coal consumed in the U.S. annually. So, while detailed 
requirements are provided for facilities that combust solid fuels, 
these methods are likely to affect only a small percentage of 
facilities reporting under proposed 40 CFR part 98 (as separate 
methods, in proposed 40 CFR 98.40, would be used by electricity 
generating units already reporting under the requirements of ARP). In 
presenting methodologies in the following sections, EPA further notes 
that the majority of reporters under proposed 40 CFR part 98, subpart C 
would use the methods prescribed for stationary combustion equipment 
combusting natural gas.
---------------------------------------------------------------------------

    \62\ It should be noted, as discussed in section V.D, EPA 
already collects over 90% of total CO2 emissions from 
U.S. coal combustion through the 40 CFR part 75 requirements of ARP.
---------------------------------------------------------------------------

    Table C-1 of this preamble illustrates the methods for calculating 
CO2 emissions for different types of reporters based on the 
fuel being combusted at the facility and the size of the stationary 
combustion equipment. The

[[Page 16481]]

calculations for CH4 and N2O that are presented 
in subsequent subsections are to be applied to all fuel types and are 
not contingent upon the stationary cobustion equipment size.

   Table C-1. Four-Tiered Approach for Calculating CO2 Emissions From
                      Stationary Combustion Sources
------------------------------------------------------------------------
                                                         Methodological
     Combustion unit size             Additional          tier required
                                    requirement(s)             \a\
------------------------------------------------------------------------
                     Solid Fossil Fuel (e.g., Coal)
------------------------------------------------------------------------
> 250 mmBtu/hour..............  --Unit has operated                    4
                                 more than 1,000 hours
                                 a year \b\.
                                --Unit has existing,
                                 certified gas
                                 monitors or stack gas
                                 volumetric flow rate
                                 monitor (or both);
                                 and
                                --Facility has an
                                 established
                                 monitoring
                                 infrastructure and
                                 meets specific QA/QC
                                 requirements.
                                --Unit does not meet                   3
                                 conditions above.
<= 250 mmBtu/hr...............  --Unit operates more                   4
                                 than 1,000 hours a
                                 year \b\.
                                --Unit has existing,
                                 certified CO2 or O2
                                 concentration monitor
                                 and stack gas
                                 volumetric flow rate
                                 monitor; and
                                --Facility has an
                                 established
                                 monitoring
                                 infrastructure and
                                 meets specific QA/QC
                                 requirements.
                                --Unit does not meet                   2
                                 conditions above.
                                --Monthly measured HHV
                                 is available.
                                --Unit does not meet                   1
                                 conditions above.
                                --Monthly measured HHV
                                 is not available.
------------------------------------------------------------------------
                 Gaseous Fossil Fuel (e.g., Natural Gas)
------------------------------------------------------------------------
> 250 mmBtu/hr................  None..................                 3
<= 250 mmBtu/hr...............  --Monthly measured HHV                 2
                                 is available.
                                --Monthly measured HHV                 1
                                 is not available.
------------------------------------------------------------------------
                    Fossil Liquid Fuel (e.g., Diesel)
------------------------------------------------------------------------
> 250 mmBtu/hr................  None..................                 3
<= 250 mmBtu/hr...............  --Monthly measured HHV                 2
                                 is available.
                                --Monthly measured HHV                 1
                                 is not available.
------------------------------------------------------------------------
              Biomass or Biomass-Derived Fuels (e.g., wood)
------------------------------------------------------------------------
All Sizes.....................  --EPA has provided a                   1
                                 default CO2 emission
                                 factor and a default
                                 heating value for the
                                 fuel.
All Sizes.....................  --EPA has provided a                   2
                                 default CO2 emission
                                 factor for specific
                                 fuel to be used with
                                 that fuel's measured
                                 heating value.
All Sizes.....................  --EPA has not provided                 3
                                 a default CO2
                                 emission factor for
                                 specific fuel to be
                                 used with that fuel's
                                 measured heating
                                 value.
------------------------------------------------------------------------
                                   MSW
------------------------------------------------------------------------
> 250 tons MSW/day............  --Unit has operated                    4
                                 more than 1,000 hours
                                 a year \b\.
                                --Unit has existing,
                                 certified gas
                                 monitors or stack gas
                                 volumetric flow rate
                                 monitor (or both);
                                 and
                                --Facility has an
                                 established
                                 monitoring
                                 infrastructure and
                                 meets specific QA/QC
                                 requirements.
                                --Unit does not meet                   2
                                 conditions above.
<= 250 tons MSW/day...........  --Unit operates more                   4
                                 than 1,000 hours a
                                 year \b\.
                                --Unit has existing,
                                 certified CO2
                                 concentration monitor
                                 and stack gas
                                 volumetric flow rate
                                 monitor; and
                                --Facility has an
                                 established
                                 monitoring
                                 infrastructure and
                                 meets specific QA/QC
                                 requirements.
                                --Unit does not meet                  2
                                 conditions above.
------------------------------------------------------------------------
\a\ Minimum tier level to be used by reporters. Reporters required to
  use Tier 1, 2, or 3 have the option to use a higher tier methodology.
\b\ Hours of operation in any year since 2005.
Note: Facilities with units reporting CO2 data to ARP should refer to
  Section V.D of this preamble (Electricity Generation).

2. Selection of Reporting Threshold
    In developing the threshold for facilities with stationary 
combustion equipment, EPA considered an emissions-based threshold of 
1,000, 10,000, 25,000, and 100,000 metric tons CO2e. Table 
C-2 of this preamble illustrates the emissions covered and the number 
of facilities that would be covered under these various thresholds. It 
should be noted that Table C-2 of this preamble only includes 
facilities with stationary combustion equipment that are not covered in 
other subparts of the proposed rule. For this reason, the total 
emissions presented in Table C-2 of this preamble appear as a lower 
total than presented previously (the general discussion in Section C.1 
of this preamble), where emissions from all

[[Page 16482]]

stationary combustion equipment are being discussed.

               Table C-2. Threshold Analysis for Unspecified Industrial Stationary Fuel Combustion
----------------------------------------------------------------------------------------------------------------
                                          Total                      Emissions covered      Facilities covered
                                        national                 -----------------------------------------------
                                        emissions   Total number    Million
 Threshold level metric tons CO2e/yr    (million         of         metric
                                       metric tons   facilities   tons CO2e/    Percent     Number      Percent
                                          CO2e)                       yr
----------------------------------------------------------------------------------------------------------------
1,000                                          410       350,000         250          61      32,000         9.1
10,000                                         410       350,000         230          56       8,000         2.3
25,000                                         410       350,000         220          54       3,000         0.9
100,000                                        410       350,000         170          41       1,000         0.3
----------------------------------------------------------------------------------------------------------------

    In calculating emissions for this analysis, and for the proposed 
threshold, only CO2 from the combustion of fossil fuels, in 
combination with all CH4 and N2O emissions, are 
considered. CO2 emissions from biomass are not considered as 
part of the determination of the threshold level. This treatment of 
biomass fuels is consistent with the IPCC Guidelines and the annual 
Inventory of U.S. Greenhouse Gas Emissions and Sinks, which account for 
the release of these CO2 emissions in accounting for carbon 
stock changes from agriculture, forestry, and other land-use. 
CH4 and N2O emissions from combustion of biomass 
are counted as part of stationary combustion within the IPCC and 
national U.S. GHG inventory frameworks.
    The purpose of the general stationary combustion source category is 
to capture significant emitters of stationary combustion GHG emissions 
that are not covered by the specific source categories described 
elsewhere in this preamble. Therefore, EPA is proposing a threshold for 
reporting emissions from stationary combustion at 25,000 metric tons 
CO2e.\63\ EPA selected the proposed 25,000 metric tons 
CO2e threshold as it appears to strike the best balance 
between covering a high percentage of nationwide GHG emissions and 
keeping the number of affected facilities manageable. As illustrated in 
Table C-2 of this preamble, selecting a 25,000 metric tons 
CO2e threshold achieves the greatest incremental gain in 
coverage with the lowest increase in the number of covered sources.
---------------------------------------------------------------------------

    \63\ As described previously, the threshold only includes 
CO2 from the combustion of fossil fuels and 
CH4 and N2O emissions from all fuel 
combustion. CO2 emissions from biomass are not considered 
as part of the determination of the threshold level.
---------------------------------------------------------------------------

    The 100,000 metric tons CO2e threshold was not proposed 
because EPA believes it would exclude too many significant emitters of 
GHG emissions that are not required to report pursuant to the other 
provisions of this rule. EPA believes that most of the population of 
facilities over a 100,000 metric tons CO2e threshold is 
known either through source category studies or existing EPA reporting 
programs.
    The 10,000 metric tons CO2e threshold showed a smaller 
incremental gain in emissions coverage from a higher threshold than the 
25,000 metric tons CO2e threshold, while greatly increasing 
the incremental number of reporters (as illustrated in Table C-2 of 
this preamble). The 1,000 metric tons CO2e threshold greatly 
increases the total number of reporters for this rule and places an 
unnecessary administrative burden on EPA, while not greatly increasing 
nationwide emissions coverage of stationary combustion sources.
    In addition, although there is considerable uncertainty as to the 
number of facilities under a 25,000 metric tons CO2e 
threshold, there is evidence to indicate that moving the threshold from 
25,000 to 10,000 metric tons CO2e would have a 
disproportionate impact on the commercial sector. It should also be 
noted that this concern is even more applicable to the 1,000 metric 
tons CO2e threshold.
    EPA concluded that a 25,000 metric tons CO2e threshold 
would better achieve a comprehensive economy wide coverage of emissions 
while focusing reporting efforts on large industrial emitters. In 
particular, it would address the considerable uncertainties in the 
25,000 to 100,000 metric tons CO2e emissions range, both as 
to the number of reporters and the magnitude of emissions. EPA believes 
that a 25,000 metric tons CO2e threshold would help in 
gathering data from a reasonable number of reporters for which little 
information is currently known without imposing undue administrative 
burden.
    EPA also considered including GHG emissions from the combustion of 
biomass fuels in the emission threshold calculations. Therefore, the 
proposed rule states that GHG emissions from biomass fuel combustion 
are to be excluded when evaluating a facility's status with respect to 
the 25,000 metric tons CO2e reporting threshold. This is 
similar to the approach taken by the IPCC and various other GHG 
emission inventories.
    Finally, EPA considered a heat input capacity-based threshold (such 
as all facilities with stationary combustion equipment rated over 100 
mmBtu/hr maximum heat input capacity). A complete, reliable set of heat 
input capacity data was unavailable for all facilities that might be 
subject to this rule, thus this type of threshold could not be 
thoroughly evaluated.
    For a full discussion of the threshold analysis and for background 
information on this threshold determination, please refer to the 
Thresholds TSD (EPA-HQ-OAR-2008-0508-046). For specific information on 
costs, including unamortized first year capital expenditures, please 
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    EPA's proposed methods for calculating GHG emissions from 
stationary fuel combustion sources is consistent with existing domestic 
and international protocols, as well as monitoring programs currently 
implemented by EPA. Those protocols and programs generally utilize 
either a direct measurement approach based on concentrations of 
combustion exhaust gases through a stack, or a direct measurement 
approach based on the quantity of fuel combusted and the 
characteristics of the fuel (e.g., heat content, carbon content, etc.). 
As the magnitude of CO2 emissions released by stationary 
combustion sources relative to CH4 and N2O is 
greater (even on a CO2e basis), more guidance is provided on 
the application of specific monitoring and calculation methods for 
CO2. EPA is proposing simpler calculation methods for 
CH4 and N2O.

[[Page 16483]]

    For facilities which have EGUs subject to the ARP reporting 
requirements under 40 CFR part 75, refer to Section V.D of this 
preamble regarding those units. For other units located at that 
facility (i.e., units that are not reporting to the ARP), the facility 
would use the calculation methods presented below.
    The discussions which follow in this subsection will focus on 
methods for: (a) The calculation of CO2 emissions from fuel 
combustion; (b) the calculation for the separate reporting of biogenic 
CO2 emissions; (c) reporting biogenic CO2 
emissions from MSW; (d) the calculation of CH4 and 
N2O emissions; and (e) the calculation of additional 
CO2 emissions from the sorbent in combustion control 
technology systems.
a. CO2 Emissions From Fuel Combustion
    To monitor and calculate CO2 emissions from stationary 
combustion sources, EPA is proposing a four-tiered approach, which 
would be applied either at the unit or facility level. The most 
stringent emissions calculation methods would apply to large stationary 
combustion units that are fired with solid fuels and that have existing 
CEMS equipment. This is due to the complexity of monitoring solid fuel 
consumption and the heterogeneous nature of solid fuels. Furthermore, 
because of the significant mass of CO2 emissions that are 
released by these large units, combining stringent methods and existing 
monitoring equipment is justified.
    The next level of methodological stringency applies to large 
stationary combustion units that are fired with liquid or gaseous 
fuels. The stringency of the methods reflects the homogenous nature of 
these fuels and the ability to monitor fuel consumption more precisely. 
However, in cases where there is greater heterogeneity in the fuels 
(e.g., refinery fuel gas) more frequent analyses of liquid and gaseous 
fuels is required.
    For smaller combustion units, EPA is proposing to allow the use of 
more simplified emissions calculation methods that rely on 
relationships between the heat content of the fuel (a generally known 
parameter) and the CO2 emission factor associated with the 
fuel's characteristics.
    The following subsections present EPA's proposed four-tiered 
approach in order from the most rigorous to the least stringent, and 
describe how it must be used by affected facilities. The applicability 
of the four measurement tiers, based on unit size and fuel type, is 
summarized in Table C-1 of this preamble. These CO2 emission 
calculation methods would, in some cases, be applied at the unit level, 
and in other cases at the facility level (for further discussion, see 
``Selection of Data Reporting Requirements'' below). Affected 
facilities would have the flexibility to use higher-tier methods (i.e., 
more stringent methods) than the ones required by this rule.
    Tier 4. The Tier 4 methodology would require the use of certified 
CEMS to quantify CO2 mass emissions, where existing CEMS 
equipment is installed. The existing installed CEMS must include a gas 
monitor of any kind or a flow monitor (or both). Generally, a 
CO2 monitor and a stack gas volumetric flow rate monitor 
would be required to calculate CO2 emissions, although in 
some cases, in lieu of a CO2 concentration monitor, data 
from a certified oxygen (O2) concentration monitor and fuel-
specific F-factors could be used to calculate hourly CO2 
concentrations. An appropriate upgrade of the existing CEMS would be 
required: (1) If the gas monitor is neither a CO2 
concentration monitor nor an O2 concentration monitor and 
(2) if a flow monitor is not already installed.
    Any CEMS that would be used to quantify CO2 emissions 
would also have to be certified and undergo on-going quality-assurance 
testing according to the procedures specified in either: (1) 40 CFR 
part 75; or (2) 40 CFR part 60, Appendix B; or (3) a State monitoring 
program.
    The Tier 4 method, and the use of CEMS (with any required monitor 
upgrades), is required for solid fossil fuel-fired units with a maximum 
heat input capacity greater than 250 mmBtu/hr (and for units with a 
capacity to combust greater than 250 tons per day of MSW). The use of 
an O2 monitor to determine CO2 concentrations 
would not be allowed for units combusting MSW. EPA is unaware of 
carbon-based F-factors for MSW that would be appropriate for converting 
O2 readings to CO2 concentrations for this rule. 
Therefore, units combusting MSW would need to use a CO2 
monitor to calculate CO2 emissions.
    For smaller solid fossil fuel-fired units (i.e., less than or equal 
to 250 mmBtu/hr or 250 tons per day of MSW), EPA would require the use 
of Tier 4 if all the monitors needed to calculate CO2 mass 
emissions (i.e., CO2 gas monitor and flow monitor) are 
already installed, and certified and quality assured as described 
above.
    In addition, in order to be subject to the Tier 4 requirements, the 
unit must have been operated for 1,000 hours or more in any calendar 
year since 2005.
    The incremental cost of adding a diluent gas (CO2 or 
O2) monitor or a flow monitor, or both, to meet Tier 4 
monitoring requirements would likely not be unduly burdensome for a 
large unit that combusts solid fossil fuels or MSW, operates 
frequently, and is already required to install, certify, maintain, and 
operate CEMS and to perform on-going QA testing of the existing 
monitors. The cost of compliance with the proposed rule would be even 
less for units that already have all of the necessary monitors in 
place. Cost estimates are provided in the RIA (EPA-HQ-OAR-2008-0508-
002). In addition, EPA is allowing provisions to monitor common stack 
configurations. Please refer to Section V.C.5 of this preamble, on data 
reporting requirements, for further information on reporting where 
there are common stack configurations.
    Reporters would follow the reporting requirements stated in 
proposed 40 CFR part 98, subpart A. However, EPA is allowing a January 
1, 2011 compliance date to install CEMS to meet the Tier 4 
requirements, if either a diluent gas monitor, flow monitor, or both, 
must be added. The January 1, 2011 deadline would allow sufficient time 
to purchase, install, and certify any additional monitor(s) needed to 
quantify CO2 mass emissions. Until that time, affected units 
subject to that deadline would be allowed to use the Tier 3 methodology 
in 2010.
    Tier 3. The Tier 3 calculation methodology would require periodic 
determination of the carbon content of the fuel, using consensus 
standards listed in the proposed 40 CFR part 98 (e.g., ASTM methods) 
and direct measurement of the amount of fuel combusted. This 
methodology is required for liquid and gaseous fossil fuel-fired units 
with a maximum heat input capacity greater than 250 mmBtu/hr, and is 
required for solid fossil fuel-fired units that are not subject to the 
Tier 4 provisions. In addition, EPA is proposing that a facility may 
use the Tier 3 calculation methodology to calculate facility-wide 
CO2 emissions (rather than unit-by-unit emissions) when the 
same liquid or gaseous fuel is used across the facility and a common 
direct measurement of fuel consumed is available (e.g., a natural gas 
meter at the facility gate). This flexibility is consistent with 
existing protocols and methodologies allowed by EPA in existing 
programs. Please refer to the subsequent subsection on data reporting 
requirements for further information on the use of fuel data from 
common supply lines.

[[Page 16484]]

    The required frequency for carbon content determinations for the 
Tier 3 calculation methodology would be monthly for natural gas, liquid 
fuels, and solid fuels (monthly molecular weight determinations are 
also required for gaseous fuels). Daily determinations for other 
gaseous fuels (e.g., refinery gas, process gas, etc.) would be 
required. The daily fuel sampling requirement for units that combust 
``other'' gaseous fuels would likely not be overly burdensome, because 
the types of facilities that burn these fuels are likely to have 
equipment in place (e.g., on-line gas chromatographs) to continuously 
monitor the fuels' characteristics in order to optimize process 
operation. Solid fuel samples would be taken weekly and composited, but 
would only be analyzed once a month. Also, fuel sampling and analysis 
would be required only for those days or months when fuel is combusted 
in the unit.
    For liquid and gaseous fuels, Tier 3 would require direct 
measurement of the amount of fuel combusted, using calibrated fuel flow 
meters. Alternatively, for fuel oil, tank drop measurements could be 
used. Solid fuel consumption would be quantified using company records. 
For quality-assurance purposes, EPA proposes that all oil and gas flow 
meters would have to be calibrated prior to the first reporting year. 
EPA recommends the use of the fuel flow meter calibration methods in 40 
CFR part 75, but, alternatively, the manufacturer's recommended 
procedure could be used. Tank drop measurements and carbon content 
determinations would be made using the appropriate methods incorporated 
by reference.
    Tier 2. The Tier 2 calculation methodology would require that the 
HHVs of each fuel combusted would be measured monthly. EPA is proposing 
that the Tier 2 method be used by units with heat input capacities of 
250 mmBtu/hr or less, combusting fuels for which EPA has provided 
default CO2 emission factors in the proposed rule. Fuel 
consumption would be based on company records. Please refer to the 
subsequent subsection on data reporting requirements for further 
information on the aggregation of units.
    Tier 1. Under Tier 1, the annual CO2 mass emissions 
would be calculated using the quantity of each type of fuel combusted 
during the year, in conjunction with fuel-specific default 
CO2 emission factors and default HHVs. The amount of fuel 
combusted would be determined from company records. The default 
CO2 emission factors and HHVs are national-level default 
factors. The Tier 1 method may be used by any small unit if EPA has 
provided the fuel-specific HHV and emission factors in proposed 40 CFR 
part 98, subpart C. However, if the owner or operator routinely 
performs fuel sampling and analysis on a monthly (or more frequent) 
basis to determine the HHV and other properties of the fuel, or if 
monthly HHV data are provided by the fuel supplier, Tier 1 could not be 
used but instead Tier 2 (or a higher tier) would have to be used.
    EPA considered several alternative CO2 emission 
calculation methods of varying stringency for stationary combustion 
units. The most stringent method would have required all combustion 
units at the affected facilities to use 40 CFR part 75 monitoring 
methodologies. However, this option was not pursued because it would 
have likely imposed an undue cost burden, particularly on smaller 
entities. For homogenous fuels, this additional cost burden would 
probably not lead to significant increases in accuracy compared with 
Tiers 1-3.
    For coal combustion, EPA evaluated a number of calculation methods 
used in other mandatory and voluntary GHG emissions reporting programs. 
In general, these methods require relatively infrequent fuel sampling, 
do not take into account the heat input capacity of stationary 
combustion equipment, and use company records to estimate fuel 
consumption. Given the heterogeneous characteristics of coal, EPA 
determined that the procedures used in these other programs are not 
rigorous enough for this proposed rule and would introduce significant 
uncertainty into the CO2 emissions estimates, especially for 
larger combustion units.
    EPA considered allowing the use of default emission factors, 
default HHVs, and company records to quantify annual fuel consumption 
for all stationary combustion units, regardless of size or the type of 
fuel combusted. The Agency decided to limit the use of this type of 
calculation methodology to smaller combustion units. The proposed rule 
reflects this, by allowing use of the Tier 1 and Tier 2 calculation 
methodologies at units with a maximum heat input capacity of 250 mmBtu/
hr or less.
    For gaseous fuel combustion, EPA considered calculation 
methodologies based on an assumption that all gaseous fuels are 
homogeneous. However, the Agency decided against this approach because 
the characteristics of certain gaseous fuels can be quite variable, and 
mixtures of gaseous fuels are often heterogeneous in composition. 
Therefore, the proposed rule requires daily sampling for all gaseous 
fuels except for natural gas.
    Finally, EPA considered allowing affected facilities to rely 
exclusively on the results of fuel sampling and analysis provided by 
fuel suppliers, rather than performing periodic on-site sampling for 
all variables. The Agency decided not to propose this because in most 
instances, only the fuel heating value, not the carbon content, is 
routinely provided by fuel suppliers. Therefore, EPA proposes to allow 
fuel suppliers to provide fuel HHVs for the Tier 2 calculation method. 
However, EPA is requesting comment on integrating the fuel supplier 
requirements of this proposed rule with both the Tier 1 and Tier 2 
calculation methodologies.
b. CO2 Emissions From Biomass Fuel Combustion
    Today's proposed rule requires affected facilities with units that 
combust biomass fuels to report the annual biogenic CO2 mass 
emissions separately. As previously described, this is consistent with 
the approach taken in the IPCC and national U.S. GHG inventory 
frameworks. EPA is proposing distinct methods to determine the biogenic 
CO2 emissions from a stationary combustion source combusting 
a biomass or biomass-derived fuel depending upon which tier is used for 
reporting other fuel combustion CO2 emissions.
    Where Tier 4 is not required, EPA is allowing the Tier 1 method to 
be used to calculate biogenic CO2 emissions for fuels in 
which EPA has provided default CO2 emission factors and a 
default HHV in the proposed rule. If default values are not provided by 
EPA, the facility would use the Tier 2 or Tier 3 method, as 
appropriate, to calculate the biogenic CO2 emissions.
    For units required to use Tier 4, total CO2 emissions 
are directly measured using CEMS. Except when MSW is combusted, EPA 
proposes that facilities perform a supplemental calculation to 
determine the biogenic CO2 and non-biogenic CO2 
portions of the measured CO2 emissions. The facility would 
use company records on annual fossil fuel combusted to calculate the 
annual volume of CO2 emitted from that fossil fuel 
combustion. This value would then be subtracted from the total volume 
of CO2 emissions measured to obtain the volume of biogenic 
CO2 emissions. The volume ratio of biogenic CO2 
emissions to total CO2 emissions would then be applied to 
the measured total CO2 emissions to determine the biogenic 
CO2 emissions.
c. CO2 Emissions From MSW
    EPA is proposing a separate calculation method for a unit that

[[Page 16485]]

combusts MSW, which can include biomass components. For units subject 
to Tier 4, as described above, an additional analysis would be required 
to separately report any biogenic CO2 emissions. The 
reporter would be required to use ASTM methods listed in the rule to 
sample and analyze the CO2 in the flue gas once each 
quarter, in order to determine the relative percentages of fossil fuel-
based carbon (e.g., petroleum-based plastics) and biomass carbon (e.g., 
newsprint) in the effluent when MSW is combusted in the unit. The 
measured ratio of biogenic to fossil CO2 concentrations is 
then applied to the measured or calculated total CO2 
emissions to determine biogenic CO2 emissions.
    The GHG emission calculation methods for units combusting MSW would 
be used in conjunction with EPA's proposed calculation method for the 
annual unit heat input, based on steam production and the design 
characteristics of the combustion unit.
    For units that combust MSW, EPA considered allowing a manual 
sorting approach to be used to determine the biomass and non-biomass 
fractions of the fuel, based on defined and traceable input streams. 
However, this approach is not considered practical, given the highly 
variable composition of MSW. To eliminate this uncertainty, EPA 
believes that more rigorous and standardized ASTM methods should be 
used to determine the biogenic percentage of the CO2 
emissions when MSW is combusted.
d. CH4 and N2O Emissions From All Fuel Combustion
    As described previously, EPA is allowing simplified emissions 
calculation methods for CH4 and N2O. The annual 
CH4 and N2O emissions would be estimated using 
EPA-provided default emission factors and annual heat input values. The 
calculation would either be done at the unit level or the facility 
level, depending upon the tier required for estimating CO2 
emissions (and using the same heat input value reported from the 
CO2 calculation method).
    A CEMS methodology was not selected for measuring N2O 
primarily because the cost impacts of requiring the installation of 
CEMS is high in comparison to the relatively low amount of 
N2O emissions (even on a CO2e basis) that would 
be emitted from stationary combustion equipment.
    EPA considered requiring periodic stack testing to derive site-
specific emission factors for CH4 and N2O. This 
approach has the advantage of ensuring a higher level of accuracy and 
consistency among reporters. However, it was decided that this option 
was too costly for the small improvement in data quality that it might 
achieve. The CH4 and N2O emissions from 
stationary combustion are relatively low compared to the CO2 
emissions. The proposed approach, i.e., using fuel-specific default 
emission factors to calculate CH4 and N2O 
emissions, is in accordance with methods used in other programs and 
provides data of sufficient accuracy. However, given the unit-level 
approach for calculating CO2 emissions, EPA is requesting 
comments on the use of more technology-specific CH4 and 
N2O emission factors that could be applied in unit-level 
calculations.
e. CO2 Emissions From Sorbent
    For fluidized bed boilers and for units equipped with flue gas 
desulfurization systems or other acid gas emission controls with 
sorbent injection, CO2 emissions would be accounted for and 
reported using simplified methods. These methods are based on the 
quantity of limestone or other sorbent material used during the year, 
if not accounted for using the Tier 4 calculation methodology.
    In summary, EPA is proposing to allow facilities flexibility in 
measuring and monitoring stationary fuel combustion sources by: (1) 
Allowing most smaller combustion units (depending upon facility-level 
considerations described above) to use the Tier 1 and Tier 2 
calculation methods; (2) allowing Tier 3 to be widely used, with few 
restrictions; (3) limiting the requirement to use Tier 4 to certain 
solid fuel-fired combustion units located at facilities where there is 
an established monitoring infrastructure; and (4) allowing simplified 
methodologies to calculate CH4 and N2O emissions. 
In addition, EPA is using a maximum heat input capacity determination 
of 250 mmBtu/hr to distinguish between large and small units. This 
approach is common to many existing EPA programs.
    EPA believes that the proposed default CO2 emission 
factors and high heat values used in Tiers 1 and 2 and the ASTM methods 
incorporated by reference for the carbon content determinations 
required by Tier 3 are well-established and minimize uncertainty.
    In proposing this tiered approach, EPA acknowledges that, in the 
case of solid fuels, a simple, standardized way of measuring the amount 
of solid fuel combusted in a unit is not proposed. In view of this, the 
proposed rule would require the owner or operator to keep detailed 
records explaining how company records are used to quantify solid fuel 
usage. These records would describe the procedures used to calibrate 
weighing equipment and other measurement devices, and would include 
scientifically-based estimates of the accuracy of these devices. EPA 
therefore solicits comment on ways to ensure that the feed rate of 
solid fuel to a combustion device is accurately measured.
4. Selection of Procedures for Estimating Missing Data
    The proposed rule requires the use of substitute data whenever a 
quality-assured value of a parameter that is used to calculate GHG 
emissions is unavailable, commonly referred to as ``missing data.'' For 
units using the CO2 calculation methodologies in Tiers 2 and 
3, when HHV, fuel carbon content, or fuel molecular weight data are 
missing, the substitute data value would be the average of the quality-
assured values of the parameter immediately before and immediately 
after the missing data period. When Tier 3 or Tier 4 is used and fuel 
flow rate or stack gas flow rate data is missing, the substitute data 
values would be the best available estimates of these parameters, based 
on process and operating data (e.g., production rate, load, unit 
operating time, etc.). This same substitute data approach would be used 
when fuel usage data and sorbent usage data are missing. The proposed 
rule provides that the reporter would be required to document and keep 
record of the procedures used to determine the appropriate substitute 
data values.
    EPA considered more conservative missing data procedures for the 
proposed rule, such as requiring higher substitute data values for 
longer missing data periods, but decided against proposing these 
procedures out of concern that GHG emissions might be significantly 
overestimated.
5. Selection of Data Reporting Requirements
    In addition to the facility-level information that would be 
reported under proposed 40 CFR part 98, subpart A, the proposed rule 
would require the reporter to submit certain unit-level data for the 
stationary combustion units at each affected facility. This additional 
information would require reporting of the unit type, its maximum rated 
heat input, the type of fuel combusted in the unit during the report 
year, the methodology used to calculate CO2 emissions for 
each type of fuel combusted, and the total annual GHG emissions from 
the unit.

[[Page 16486]]

    To reduce the reporting burden, the proposed rule would allow 
reporting of the combined GHG emissions from multiple units at the 
facility instead of requiring emissions reporting for each individual 
unit, in certain instances. Three types of emissions aggregation would 
be allowed. First, the combined GHG emissions from a group (or groups) 
of small units at a facility could be reported, provided that the 
combined maximum rated heat input of the units in the group does not 
exceed 250 mmBtu/hr. Second, the combined GHG emissions from units in a 
common stack configuration could be reported, if CEMS are used to 
continuously monitor the CO2 emissions at the common stack. 
Third, if a facility combusts the same type of homogeneous oil or 
gaseous fuel through a common supply line, and the total amount of fuel 
consumed through that supply line is accurately measured using a 
calibrated fuel flow meter, the combined GHG emissions from the 
facility could be reported.
    Different levels of verification data are required depending upon 
which tier is used for reporting. For Tier 1, only the total quantity 
of each type of fuel combusted during the report year would be 
reported. For Tier 2, the quantity of each type of fuel combusted 
during each measurement period would be reported, along with all high 
heat values used in the emissions calculations, the methods used to 
determine the HHVs, and information indicating which HHVs (if any) are 
substitute data values.
    For Tier 3, the quantity of each type of fuel combusted during each 
measurement period (day or month) would be reported, along with all 
carbon content values and, if applicable, molecular weight measurements 
used in the emissions calculations, with information indicating which 
ones (if any) are substitute data values. In addition, the results of 
all fuel flow meter calibrations would be reported along with 
information indicating which analytical methods were used for the 
carbon content determinations, flow meter calibrations and (if 
applicable) oil tank drop measurements.
    For Tier 4, the number of unit operating days and hours would be 
reported, along with daily CO2 mass emission totals, the 
number of hours of substitute data used in the annual emissions 
calculations, the results of the initial CEMS certification tests and 
the major ongoing QA tests.
    If MSW is combusted in the unit, the owner or operator would be 
required to report the results of the quarterly sample analyses used to 
determine the biogenic percentage of CO2 emissions in the 
effluent. If combinations of fossil and biomass fuels are combusted and 
CEMS are used to measure CO2 emissions, the annual volumes 
of biogenic and fossil CO2 would be reported, along with the 
F-factors and fuel gross calorific values used in the calculations, and 
the biogenic percentage of the annual CO2 emissions.
    Finally, for units that use acid gas scrubbing with sorbent 
injection but are not equipped with CEMS, the owner or operator would 
be required to report information on the type and amount of sorbent 
used.
6. Selection of Records That Must Be Retained
    In addition to meeting the general recordkeeping requirements in 
proposed 40 CFR part 98, subpart A, whenever company records are used 
to estimate fuel consumption (e.g., when the Tier 1 or 2 emissions 
calculation methodology is used) and sorbent consumption, EPA proposes 
to require the owner or operator to keep on file a detailed explanation 
of how fuel usage is quantified, including a description of the QA 
procedures that are used to ensure measurement accuracy (e.g., 
calibration of weighing devices and other instrumentation).
    As discussed in Section IV of this preamble and proposed 40 CFR 
part 98, subpart A, there are a number of facilities that are not part 
of a source category listed in 40 CFR 98.2(1)(a) or (2) but have 
stationary combustion equipment emitting GHG emissions. In 2010, those 
facilities would have to determine whether or not they are subject to 
the requirements of this rule (i.e., if their emissions are 25,000 
metric tons CO2e/yr or higher). In order to reduce the 
burden on those facilities, we are proposing that facilities with an 
aggregate maximum heat input capacity of less than 30 mmBtu/hr from 
stationary combustion units are automatically exempt from the proposed 
40 CFR part 98. Based on our assessment of the maximum amount of GHG 
emissions likely from units of that size that burn fossil fuels (e.g, 
coal, oil or gas) and operate continuously through the year, such a 
facility would still be below the 25,000 metric tons CO2e 
threshold. The purpose for having this provision is to exempt small 
facilities from having to estimate emissions to determine if they are 
subject to the rule, and re-estimate whenever there are process 
changes.

D. Electricity Generation

1. Definition of the Source Category
    This section of the preamble addresses GHG emissions reporting for 
facilities with EGUs that are in the ARP, and are subject to the 
CO2 emissions reporting requirements of Section 821 of the 
CAA Amendments of 1990. All other facilities using stationary fuel 
combustion equipment to generate electricity should refer to Section 
V.C of this preamble (General Stationary Fuel Combustion Sources) to 
understand EPA's proposed approach for GHG emissions reporting.
    Electricity generating units in the ARP reported CO2 
emissions of 2,262 million metric tons CO2e in 2006. This 
represents almost one third of total U.S. GHG emissions and over 90 
percent of CO2 emissions from electricity generation. EPA 
has been receiving these CO2 data since 1995.\64\
---------------------------------------------------------------------------

    \64\ This data can be accessed at: http://epa.gov/camdataandmaps.
---------------------------------------------------------------------------

2. Selection of Reporting Threshold
    If a facility includes within its boundaries at least one EGU that 
is subject to the ARP, the facility would be subject to the mandatory 
GHG emissions reporting of proposed 40 CFR part 98, subpart D. 
Facilities with EGUs in the ARP would not be expected to report any new 
CO2 data. Therefore, EPA expects that the GHG emissions 
reporting requirements of this rule would not be overly burdensome for 
facilities already reporting to the ARP.
    For specific information on costs, including unamortized first year 
capital expenditures, please refer to section 4 of the RIA and the RIA 
cost appendix.
3. Selection of Proposed Monitoring Methods
    For ARP units, the CO2 mass emissions data already 
reported to EPA under 40 CFR part 75 would be used in the annual GHG 
emissions reports required under this proposed rule. The annual 
CO2 mass emissions (i.e., English short tons) reported for 
an ARP unit would simply be converted to metric tons and then included 
in the GHG emissions report for the facility.
    As CH4 and N2O emissions are not required to 
be reported under 40 CFR part 75, the facility would consult the 
proposed methods in proposed 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources) for calculating CH4 and 
N2O from the ARP units.
    The additional units at an affected facility that are not in the 
ARP would use the GHG calculation methods specified and required in 
proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources).

[[Page 16487]]

4. Selection of Procedures for Estimating Missing Data
    The proposed missing data substitution procedures for 
CH4 and N2O emissions from ARP units and all GHG 
emissions from units at the facility not in ARP are discussed in 
Section V.C.4 of this preamble, under General Stationary Fuel 
Combustion Sources.
5. Selection of Data Reporting Requirements
    The proposed data reporting requirements are discussed in Section 
V.C.5 of this preamble, under General Stationary Fuel Combustion 
Sources.
6. Selection of Records That Must Be Retained
    The records that must be retained regarding CH4 and 
N2O emissions from ARP units and all GHG emissions from 
units at the facility not in the ARP are discussed in Section V.C.6 of 
this preamble, under General Stationary Fuel Combustion Sources.

E. Adipic Acid Production

1. Definition of the Source Category
    Adipic acid is a white crystalline solid used in the manufacture of 
synthetic fibers, plastics, coatings, urethane foams, elastomers, and 
synthetic lubricants. Commercially, it is the most important of the 
aliphatic dicarboxylic acids, which are used to manufacture polyesters. 
Adipic acid is also used in food applications.
    Adipic acid is produced through a two-stage process. The first 
stage usually involves the oxidation of cyclohexane to form a 
cyclohexanone/cyclohexanol mixture. The second stage involves oxidizing 
this mixture with nitric acid to produce adipic acid.
    National emissions from adipic acid production were estimated to be 
9.3 million metric tons CO2e (less than 0.1 percent of U.S. 
GHG emissions) in 2006. These emissions include both process-related 
emissions (N2O) and on-site stationary combustion emissions 
(CO2, CH4, and N2O). The main GHG 
emitted from adipic acid production is N2O, which is 
generated as a by-product of the nitric acid oxidation stage of the 
manufacturing process, and it is emitted in the waste gas stream. 
Process N2O emissions alone were estimated at 5.9 million 
metric tons CO2e, or 64 percent of the total GHG emissions 
in 2006, while on-site stationary combustion emissions account for the 
remaining 3.4 million metric tons CO2e, or 36 percent of the 
total.
    Process emissions from the production of adipic acid vary with the 
types of technologies and level of emission controls employed by a 
facility. DE for N2O emissions can vary from 90 to 98 
percent using abatement technologies such as nonselective catalytic 
reduction. In 1998, the three major adipic acid production facilities 
in the U.S. had control systems in place. Only one small facility, 
representing approximately two percent of adipic acid production, does 
not control for N2O.
    As part of this proposed rule, stationary combustion emissions 
would be estimated and reported according to the applicable procedures 
in proposed 40 CFR part 98, subpart C. For additional background 
information on adipic acid production, please refer to the Adipic Acid 
Production TSD (EPA-HQ-OAR-2008-0508-005).
2. Selection of Reporting Threshold
    In developing the threshold for adipic acid production, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e. Table E-1 of 
this preamble illustrates that the various thresholds do not affect the 
amount of emissions or number of facilities that would be covered.

                            Table E-1. Threshold Analysis for Adipic Acid Production
----------------------------------------------------------------------------------------------------------------
                                                               Emissions covered          Facilities covered
 Threshold level metric tons      Total     Total number -------------------------------------------------------
           CO2e/yr              national         of        Metric tons
                                emissions    facilities      CO2e/yr       Percent       Number        Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................     9,300,000             4     9,300,000           100             4           100
10,000......................     9,300,000             4     9,300,000           100             4           100
25,000......................     9,300,000             4     9,300,000           100             4           100
100,000.....................     9,300,000             4     9,300,000           100             4           100
----------------------------------------------------------------------------------------------------------------

    Facility-level emissions estimates based on known facility 
capacities for the four known adipic acid facilities suggests that each 
of the facilities would be at least five times over the 100,000 metric 
tons CO2e threshold based on just process-related emissions. 
Because all adipic acid production facilities would have to report 
under any of the emission thresholds that were examined, we propose 
that all adipic acid production facilities be required to report. This 
would simplify rule applicability and avoid any burden for the source 
to perform unnecessary calculations.
    For a full discussion of the threshold analysis, please refer to 
the Adipic Acid Production TSD (EPA-HQ-OAR-2008-0508-005). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating adipic acid production 
process emissions (e.g., 2006 IPCC Guidelines, U.S. Inventory, DOE 
1605(b), and TRI). These methodologies coalesce around the four options 
discussed below.
    Option 1. Default emission factors would be applied to total 
facility production of adipic acid. The emissions would be calculated 
using the total production of adipic acid and the highest international 
default emission factor available in the 2006 IPCC Guidelines. This 
option assumes no abatement of N2O emissions. This approach 
is consistent with IPCC Tier 1 and the DOE 1605(b) ``C'' rated 
estimation method.
    Option 2. Default emission factors would be applied on a site-
specific basis using the specific type of abatement technology used and 
the adipic acid production activity. The amount of N2O 
emissions would be determined by multiplying the technology-specific 
emission factor by the production level of adipic acid. This approach 
is consistent with 1605(b) ``B'' rated estimation method, IPCC Tier 2, 
and TCR's ``B'' rated estimation method.
    Option 3. Periodic direct emission measurement of N2O 
emissions would be used to determine the relationship between adipic 
acid production and the amount of N2O emissions; i.e., to 
develop a facility-specific emissions

[[Page 16488]]

factor. The facility-specific emissions factor and production rate 
(activity level) would be used to calculate the emissions. The 
facility-specific emission factor would be developed from a single 
annual test. Production rate is most likely already measured at 
facilities. Existing procedures would be followed to measure the 
production rate during the performance test and on a quarterly basis 
thereafter. After the initial test, annual testing of N2O 
emissions would be required each year to estimate the emission factor 
and applied to production to estimate emissions. The yearly testing 
would assist in verifying the emission factor. Testing would also be 
required whenever the production rate is changed by more than 10 
percent from the production rate measured during the most recent 
performance test. Option 3 and the following Option 4 are approaches 
consistent with IPCC Tier 3, DOE 1605(b) ``A'' and TCR's ``A2'' rated 
estimation methods.
    Option 4. CEMS would be used to directly measure the N2O 
process emissions. CEMS would be used to directly measure 
N2O concentration and flow rate to directly determine 
N2O emissions. Measuring N2O emissions directly 
with CEMS is feasible, but adipic acid production facilities are 
currently only using NOX CEMS to comply with State programs 
(e.g. Texas). Half of the adipic acid production facilities are located 
in Texas where NOX CEMS are required in O3 
nonattainment areas under Control of Air Pollution from Nitrogen 
Compounds (TX Chap 117 (Reg 7)).
    Proposed option: We propose Option 3 to quantify process emissions 
from all adipic acid facilities. In addition, you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C to 
estimate emissions of CO2, CH4 and N2O 
from stationary combustion.
    We identified Options 3 and 4 as the approaches providing the 
lowest uncertainty and the best site-specific estimates based on 
differences in process operation and abatement technologies. Option 3 
requires annual monitoring of N2O emissions and the 
establishment of a facility-specific emissions factor that relates 
N2O emissions with adipic acid production rate.
    Option 4 was not chosen as the required method because, while 
N2O CEMS are available, there is no existing EPA method for 
certifying N2O CEMS, and the cost impact of requiring the 
installation of CEMS is high in comparison to the relatively low amount 
of emissions that would be quantified from the adipic acid production 
sector. NOX CEMS only capture emissions of NO and 
NO2 and not N2O. Although the amount of 
NOX and N2O emissions from adipic acid production 
may be directly related, direct measurement of NOX does not 
automatically correlate to the amount of N2O in the same 
exhaust stream. Periodic testing of N2O emissions (Option 3) 
would not indicate changes in emissions over short periods of time, but 
it does offer direct measurement of GHGs.
    We request comment on the advantages and disadvantages of using 
Options 3 and 4. After consideration of public comments, we may 
promulgate one or more of these options or a combination based on the 
additional information that is provided.
    We decided against Options 1 and 2 because facility-specific 
emission factors are more appropriate for reflecting differences in 
process design and operation. According to IPCC, the default emission 
factors for adipic acid are relatively certain because they are derived 
from the stoichiometry of the chemical reaction employed to oxidize 
nitric acid. However, there is still uncertainty in the amount of 
N2O that is generated. This variability is a result of 
differences in the composition of cyclohexanone and cyclohexanol 
feedstock. Variability also arises if adipic acid is produced from use 
of other feedstocks, such as phenol or hydrogen peroxide. Facility-
specific emission factors would be based on actual feedstock 
composition rather than an assumed composition.
    The various approaches to monitoring GHG emissions are elaborated 
in the Adipic Acid Production TSD (EPA-HQ-OAR-2008-0508-005).
4. Selection of Procedures for Estimating Missing Data
    For process sources that use Option 3 (facility-specific emission 
factor), no missing data procedures would apply because the facility-
specific emission factor is derived from an annual performance test and 
used in each calculation. The emission factor would be multiplied by 
the production rate, which is readily available. If the test data are 
missing or lost, the test would have to be repeated. Therefore, 100 
percent data availability would be required.
5. Selection of Data Reporting Requirements
    We propose that facilities submit their total annual N2O 
emissions from adipic acid production, as well as any stationary fuel 
combustion emissions. In addition we propose that facilities submit the 
following data, which are the basis of the calculations and are needed 
to understand the emissions data and verify the reasonableness of the 
reported emissions. The data submitted on an annual basis should 
include annual adipic acid production capacity, total adipic acid 
production, facility-specific emission rate factor used, abatement 
technology used, abatement technology efficiency, abatement utilization 
factor, and number of facility operating hours in calendar year.
    Capacity, actual production, and operating hours support 
verification of the emissions data provided by the facility. The 
production rate can be determined through sales records or by direct 
measurement using flow meters or weigh scales. This industry generally 
measures the production rate as part of normal operating procedures.
    A list of abatement technologies would be helpful in assessing the 
widespread use of abatement in the adipic acid source category, 
cataloging any new technologies that are being used, and documenting 
the amount of time that the abatement technologies are being used.
    A full list of data to be reported is included in the proposed 40 
CFR part 98, subparts A and E.
6. Selection of Records That Must Be Retained
    We propose that facilities maintain records of annual testing of 
N2O emissions, calculation of the facility-specific emission 
rate factor, hours of operation, annual adipic acid production, adipic 
acid production capacity, and N2O emissions. These records 
hold values directly used to calculate the emissions that are reported 
and are necessary to allow determination of whether the GHG emissions 
monitoring calculations were done correctly. A full list of records 
that must be retained on site is included in the proposed 40 CFR part 
98, subparts A and E.

F. Aluminum Production

1. Definition of the Source Category
    This source category includes primary aluminum production 
facilities. Secondary aluminum production facilities would not be 
required to report emissions under Subpart F. Aluminum is a light-
weight, malleable, and corrosion-resistant metal that is used in 
manufactured products in many sectors including transportation, 
packaging, building and construction. As of 2005, the U.S. was the 
fourth largest producer of primary aluminum, with approximately eight 
percent of the world total (Aluminum Production TSD

[[Page 16489]]

(EPA-HQ-OAR-2008-0508-006)). The production of primary aluminum--in 
addition to consuming large quantities of electricity--results in 
process-related emissions of CO2 and two PFCs: 
perfluoromethane (CF4) and perfluoroethane 
(C2F6). Only these process-related emissions are 
discussed here. Stationary fuel combustion source emissions must be 
monitored and reported according to proposed 40 CFR part 98, subpart C 
(General Stationary Fuel Combustion Sources), which is discussed in 
Section V.C of this preamble.
    CO2 is emitted during the primary aluminum smelting 
process when alumina (aluminum oxide, Al2O3) is 
reduced to aluminum using the Hall-H[eacute]roult reduction process. 
The reduction of the alumina occurs through electrolysis in a molten 
bath of natural or synthetic cryolite (Na3AlF6). 
The reduction cells contain a carbon lining that serves as the cathode. 
Carbon is also contained in the anode, which can be a carbon mass of 
paste, coke briquettes, or prebaked carbon blocks from petroleum coke. 
During reduction, most of the carbon in the anode is oxidized and 
released to the atmosphere as CO2. In addition, a smaller 
amount of CO2 is released during the baking of anodes for 
use in smelters using prebake technologies.
    In addition to CO2 emissions, the primary aluminum 
production industry is also a source of PFC emissions. During the 
smelting process, if the alumina ore content of the electrolytic bath 
falls below critical levels required for electrolysis, rapid voltage 
increases occur, which are termed ``anode effects.'' These anode 
effects cause carbon from the anode and fluorine from the dissociated 
molten cryolite bath to combine, thereby producing emissions of 
CF4 and C2F6. For any particular 
individual smelter, the magnitude of emissions for a given level of 
production depends on the frequency and duration of these anode 
effects. As the frequency and duration of the anode effects increase, 
emissions increase. In addition, even at constant levels of production 
and anode effect minutes, emissions vary among smelter technologies 
(e.g., Center-Work Prebake vs. Side-Work Prebake) and among individual 
smelters using the same smelter technology due to differing operational 
practices.
    Total U.S. Emissions. According to the U.S. GHG Inventory total 
process-related GHG emissions from primary aluminum production in the 
U.S. are estimated to be 6.4 million metric tons CO2e in 
2006. Process emissions of CO2 from the 14 aluminum smelters 
in the U.S. were estimated to be 3.9 million metric tons 
CO2e in 2006. Process emissions of CF4 and 
C2F6 from aluminum smelters were estimated to be 
2.5 million metric tons CO2e in 2006. In 2006, 13 of the 14 
primary aluminum smelters in the U.S. accounted for the vast majority 
of primary aluminum emissions. The remaining smelter was idle through 
most of 2006, restarting at the end of the year.
    Emissions to be reported. We propose to require reporting of the 
following types of emissions from primary aluminum production: Process 
emissions of PFCs, process emissions of CO2 from consumption 
of the anode during electrolysis (for both Prebake and S[oslash]derberg 
cells), and process emissions of CO2 from the anode baking 
process (for Prebake cells only).
    Another potential source of process CO2 emissions is 
coke calcining. We request comment on whether any U.S. smelters operate 
calcining furnaces and the extent of these process emissions.
2. Selection of Reporting Threshold
    We propose to require all owners or operators of primary aluminum 
facilities to report the total quantities of PFC and CO2 
process emissions. In 2006, 5 companies operated 14 primary aluminum 
for at least part of the year. (One of these smelters operated only 
briefly at the end of the year.) All primary aluminum smelters that 
operated throughout 2006 would be covered at all capacity and 
emissions-based thresholds considered in this analysis.
    In developing the threshold for primary aluminum, we considered the 
emissions thresholds 1,000, 10,000, 25,000, and 100,000 metric tons 
CO2e per year (metric tons CO2e/yr). These 
emissions thresholds translate to 64, 640, 1,594, and 6,378 metric tons 
primary aluminum produced, respectively, based on use of the 2006 IPCC 
default emission factors and assuming side-worked prebake cells and 100 
percent capacity utilization as shown in Table F-1 of this preamble.

                     Table F-1. Threshold Analysis for Aluminum Production Based on 2006 Emissions and Facility Production Capacity
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Emissions covered               Facilities covered
                                                         Total national   Total number  ----------------------------------------------------------------
      Emission threshold level metric tons CO2e/yr          emissions     of facilities    Metric tons
                                                                                             CO2e/yr         Percent          Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000..................................................       6,402,000              14       6,402,000            100                14             100
10,000.................................................       6,402,000              14       6,397,000             99.9              13              93
25,000.................................................       6,402,000              14       6,397,000             99.9              13              93
100,000................................................       6,402,000              14       6,397,000             99.9              13              93
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                    Production Capacity Threshold metric tons Al/year
--------------------------------------------------------------------------------------------------------------------------------------------------------
64.....................................................       6,402,000              14       6,402,000            100                14             100
640....................................................       6,402,000              14       6,402,000            100                14             100
1,594..................................................       6,402,000              14       6,402,000            100                14             100
6,378..................................................       6,402,000              14       6,402,000            100                14             100
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We propose that all primary aluminum facilities be subject to 
reporting. All smelters that operated in 2006 would be required to 
report if a 10,000, 25,000, or 100,000 metric tons CO2e per 
year threshold were used. Requiring all facilities to report would 
simplify the rule, avoid the need for facilities to estimate emissions 
to determine applicability, and ensure complete coverage of emissions 
from this source category. It results in little extra burden for the 
industry since few if any additional facilities would be required to 
report (compared to the thresholds considered). Significant 
fluctuations in capacity utilization do occur; aluminum smelters 
sometimes shut down for long periods. Under the proposed rule, 
facilities that did not operate at all during the previous year

[[Page 16490]]

would still have to submit a report; however, reporting would be 
minimal. (Zero production implies zero emissions.)
    For a full discussion of the threshold analysis, please refer to 
the Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    This section of this preamble provides monitoring methods for 
calculating and reporting process CO2 and PFC emissions 
only. If a facility has stationary fuel combustion it would need to 
also refer to proposed 40 CFR part 98, subpart C for methods for 
CO2, CH4 and N2O and would be required 
to follow the calculation procedures, monitoring and QA/QC methods, 
recordkeeping requirements as described.
    Protocols and guidance reviewed for this analysis include the 2006 
IPCC Guidelines, EPA's Voluntary Aluminum Industrial Partnership, the 
Inventory of U.S. Greenhouse Gas Emissions and Sinks, the International 
Aluminum Institute's Aluminum Sector Greenhouse Gas Protocol, the 
Technical Guidelines for the Voluntary Reporting of Greenhouse Gases 
(1605(b)) Program, EPA's Climate Leaders Program, and TRI.
    The methods described in these protocols and guidance coalesce 
around the methods described by the International Aluminum Institute's 
Aluminum Sector Greenhouse Gas Protocol and the 2006 IPCC Guidelines. 
These methods range from Tier 1 approaches based on aluminum production 
to Tier 3 approaches based primarily on smelter-specific data. The IPCC 
Tier 3 and International Aluminum Institute methods are essentially the 
same.
    Proposed Method for Monitoring PFC Emissions. The proposed method 
for monitoring PFC emissions from aluminum processing is similar to the 
Tier 3 approach in the 2006 IPCC Guidelines for primary aluminum 
production. The proposed method requires smelter-specific data on 
aluminum production, anode effect minutes per cell day (anode effect-
mins/cell-day), and recently measured slope coefficients. The slope 
coefficient represents kg of CF4/metric ton of aluminum 
produced divided by anode effect minutes per cell-day. The cell-day is 
the number of cells operating multiplied by the number of days of 
operation, per the 2006 IPCC Guidelines. The following describes how to 
calculate CF4 and C2F6 emissions based 
on the slope method. CF4 emissions equal the slope 
coefficient for CF4 (kg CF4/metric ton Al)/anode 
effect-Mins/cell-day) times metal production (metric tons Al). Annual 
anode effect calculations and records should be the sum of anode effect 
minutes per cell day and production by month. 
C2F6 emissions equal emissions of CF4 
times the weight fraction of C2F6/CF4 
(kg C2F6/kg CF4).
    Both the IPCC Tier 3 method and the less accurate IPCC Tier 2 
method are based on these equations and parameters. The critical 
distinction between the two methods is that the Tier 3 method requires 
smelter-specific slope coefficients while the Tier 2 method relies on 
default, technology-specific slope coefficients. Of the currently 
operating U.S. smelters, all but one has measured a smelter-specific 
coefficient at least once. However, as discussed below, some smelters 
may need to update these measurements if they occurred more than 3 
years ago.
    Use of the Tier 3 approach significantly improves the precision of 
a smelter's PFC emissions estimate. For individual facilities using the 
most common smelter technology in the U.S., the uncertainty (95 percent 
confidence interval) of estimates developed using the Tier 2 approach 
is 50 percent,\65\ while the uncertainty of estimates 
developed using the Tier 3 approach is approximately 15 
percent (Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006)). For a 
typical U.S. smelter emitting 175,000 metric tons CO2e in 
PFCs, these errors result in absolute uncertainties of 88,000 metric tons CO2e and 26,000 metric 
tons CO2e, respectively. The reduction in uncertainty 
associated with moving from the Tier 2 to the Tier 3 approach, 62,000 
metric tons CO2e, is as large as the emissions from many of 
the sources that would be subject to the rule. We concluded the extra 
burden to facilities of measuring the smelter-specific slope 
coefficients is justified by the considerable improvement in the 
precision of the reported emissions.
---------------------------------------------------------------------------

    \65\ The most common smelter technology in the U.S. is the 
center-worked prebake technology. The 2006 IPCC Guidelines provide a 
95 percent confidence interval of 6 percent for the 
center-worked prebake technology default slope coefficient. However, 
this range is not the range within which the slope coefficient from 
a single center-worked prebake technology has a 95 percent chance of 
falling. Instead, it is the range within which the true mean of all 
center-worked prebake technology slope factors has a 95 percent 
chance of falling. This appears to depart from the usual convention 
for expressing the uncertainties related to the use of default 
coefficients in the Guidelines.
---------------------------------------------------------------------------

    Measurement of Slope Coefficients. We propose that slope 
coefficients be measured using a method similar to the USEPA/
International Aluminum Institute Protocol for Measurement of 
Tetrafluoromethane and Hexafluoroethane from Primary Aluminum 
Production. The protocol 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). These guidelines include recommendations for 
documenting the frequency and duration of anode effects, measuring 
aluminum production, sampling design, measurement instruments and 
methods, calculations, QA/QC, and measurement frequency.
    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.\66\ 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.
---------------------------------------------------------------------------

    \66\ Aluminum Production TSD (EPA-HQ-OAR-2008-0508-006).
---------------------------------------------------------------------------

    We understand that two smelting companies in the U.S., Rio Tinto 
Alcan and Alcoa, have the necessary equipment and teams in-house to 
measure smelter-specific slope factors. These two companies account for 
11 out of 15 of the operating smelters in the U.S. The remaining 
facilities would need to hire a consultant to conduct a measurement 
study once every three years to accurately determine their slope 
coefficients. The cost of hiring a consultant to conduct the 
measurement study is probably significantly lower than the capital, 
labor and O&M costs of the equipment, training, and maintenance 
required to conduct the measurements in-house. While the cost to 
implement a Tier 3 approach is significantly greater than the cost to 
implement a Tier 2 approach, the benefit of reduced uncertainty is 
considerable (approximately 40 percent), as noted above.
    We request comment on the proposal that all smelters be required to 
measure their smelter-specific slope coefficients at least once every 
three years. We considered, but are not proposing, to exempt ``high 
performing'' smelters, as defined by the 2006 IPCC Guidelines, from the 
requirement to measure their smelter-specific slope coefficients more

[[Page 16491]]

than once. The Guidelines define ``high-performing'' smelters as those 
that operate with less than 0.2 anode effect minutes per cell day or 
less than 1.4 millivolt overvoltage. The Guidelines state, ``no 
significant improvement can be expected in the overall facility GHG 
inventory by using the Tier 3 method rather than the Tier 2 method.'' 
(IPCC, page 4.53, footnote 1). However, EPA believes there is benefit 
to EPA and to industry of periodic evaluation of the correlation of the 
smelter-specific slope coefficient and actual emissions, even in 
situations of low anode effect minutes per cell day or overvoltage.
    The Overvoltage Method. Another Tier 3 method included in the IPCC 
Guidelines is the Overvoltage Method. This 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. We request 
comment on whether any U.S. smelters are using the Pechiney technology 
and, if so, on whether these smelters should be permitted to use the 
Overvoltage Method.
    Proposed Method for Monitoring Process CO2 Emissions. If 
you are required to use an existing CEMS to meet the requirements 
outlined in proposed 40 CFR part 98, subpart C, you would be required 
to use CEMS to estimate stationary fuel combustion CO2 
emissions. Where the CEMS capture all combustion- and process-related 
CO2 emissions you would be required to follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
proposed 40 CFR part 98, subpart C to estimate process and stationary 
fuel combustion CO2 emissions from the industrial source. 
Also, refer to proposed 40 CR part 98, subpart C to estimate 
combustion-related CH4 and N2O.
    If your facility does not have stationary combustion, or if you do 
not currently have CEMS that meet the requirements outlined in proposed 
40 CR part 98, subpart C, or where the CEMS would not adequately 
account for process CO2 emissions, the proposed monitoring 
method for process CO2 emissions is similar to the IPCC Tier 
2 approach, which relies on industry defaults rather than smelter-
specific values for concentrations of minor anode components.
    CO2 emitted during electrolysis. We propose to require 
that CO2 emitted during electrolysis be calculated based on 
metal production and net anode consumption using a mass balance 
approach that assumes all carbon from net anode consumption is 
ultimately emitted as CO2. Since the concentrations of the 
non-carbon components are small (typically less than one percent to 
five percent), facility-specific data on them is not as critical to the 
precision of emission estimates as is facility-specific data on net 
anode consumption. Tier 3 improves the accuracy of the results but the 
improvement in accuracy is not expected to exceed 5 percent per the 
2006 IPCC Guidelines. Although we do not propose to require the use of 
the Tier 3 approach, we would allow and encourage smelter operators to 
use facility-specific data on anode non-carbon components when that 
data were available.
    For prebake cells, CO2 emissions are equal to net 
prebaked anode consumption per metric ton aluminum times total metal 
production times the percent weight of sulfur and ash content in the 
baked anode times the molecular mass of CO2.
    CO2 emissions from S[oslash]derberg cells are a function 
of total metal production, paste consumption, emissions of cyclohexane 
soluble matter, percent binder and sulfur content in paste, percent ash 
and hydrogen content in pitch, percent weight of sulfur and ash content 
in calcined coke, carbon in skimmed dust from S[oslash]derberg cells, 
and the carbon atomic mass ratio.
    The data reported by companies participating in EPA's Voluntary 
Aluminum Industrial Partnership has generally not included smelter-
specific values for each of these variables. However, most participants 
in the Voluntary Aluminum Industrial Partnership have used either data 
on paste consumption (for S[oslash]derberg cells) or on net anode 
consumption (for Prebake cells), along with some smelter-specific data 
on impurities, to develop a hybrid IPCC Tier 2/3 estimate (i.e., 
combination of smelter-specific and default factors).
    CO2 emitted during anode baking. We propose that 
CO2 emitted during anode baking be calculated based on a 
mass balance approach involving chemical contents of the anodes and 
packing materials. No anode baking emissions occur when using 
S[oslash]derberg cells, since these cells are not baked before aluminum 
smelting, but rather, bake in the electrolysis cell during smelting.
    CO2 emissions from pitch volatiles combustion equal the 
initial weight from green anode minus hydrogen content minus baked 
anode production minus waste tar collected times the molecular weight 
of CO2. CO2 emissions from bake furnace packing 
material are a function of packing coke consumption times baked anode 
production times the percent weight sulfur and ash content in packing 
coke.
    As is the case for CO2 emitted during electrolysis, the 
IPCC Tier 2 approach for anode baking relies on industry-wide defaults 
for minor anode components, requiring smelter-specific data only for 
the initial weight of green anodes and for baked anode production. The 
IPCC Tier 3 approach requires smelter-specific values for all 
parameters. Again, the concentrations of minor components are small, 
limiting their impact on the estimate of CO2 emissions from 
anode baking. In addition, anode baking emissions account for 
approximately 10 percent of total CO2 process emissions, so 
reducing the uncertainty in this estimate would have only a minor 
impact on the overall CO2 process estimate. For EPA's 
Voluntary Aluminum Industrial Partnership program, many smelters report 
only some smelter-specific values for the concentrations of minor anode 
components. In light of these considerations, we propose to require the 
Tier 2 method for estimating CO2 emissions from anode 
baking, with the option to use facility-specific data on impurity 
concentrations when that data is available.
    Other Options Considered. We are not proposing IPCC's Tier 1 
methodology for calculating PFC emissions. Although this methodology is 
simple, the default emission factors for PFCs have large uncertainties 
due to the variability in anode effect frequency and duration. Since 
1990, all U.S. smelters have sharply reduced their anode effect 
frequency and duration; through 2006, average anode minutes per cell 
day have declined by approximately 85 percent, lowering U.S. smelter 
emission rates well below those of the IPCC Tier 1 defaults. 
Consequently, as discussed above, the Tier 3 methodology has been 
proposed.
    For CO2, we are not proposing IPCC's Tier 1 methodology 
for calculating emissions. The difference in uncertainty between 
emission estimates developed using IPCC Tier 1 and Tier 2/3 approaches 
for U.S. smelters is notably lower than the difference for the PFC 
estimates. However, as part of typical operations, facilities regularly 
monitor inputs to higher Tier methods (e.g., consumption of anodes); 
consequently, the incremental cost to use the IPCC Tier 2 or a Tier 2/3 
hybrid estimate are small.

[[Page 16492]]

4. Selection of Procedures for Estimating Missing Data
    Where anode effect minutes per cell day data points are missing, 
the average anode effect minutes per cell day of the remaining 
measurements within the same reporting period may be applied. These 
parameters are typically logged by the process control system as part 
of the operations of nearly all aluminium production facilities and the 
uncertainties in these data are low.
    It is likely that aluminum production levels would be well known, 
since businesses rely on accurate monitoring and reporting of 
production levels. The 2006 IPCC Guidelines specify an uncertainty of 
less than 1 percent in the data for the annual production of aluminum. 
The likelihood for missing data is low.
    For CO2 emissions, the uncertainty in recording anode 
consumption as baked anode consumption or coke consumption is estimated 
to be only slightly higher than for aluminium production, less than 2 
percent per the 2006 IPCC Guidelines. This is also an important 
parameter in smelter operations and is routinely/continuously 
monitored. Again, the likelihood for missing data is low.
5. Selection of Data Reporting Requirements
    In addition to annual GHG emissions data, facilities would be 
required to submit annual aluminum production and smelter technology 
used. The following PFC-specific information would also be required to 
be reported on an annual basis: Anode effect minutes per cell-day, and 
anode effect frequency and duration. Smelters would also be required to 
submit smelter-specific slope coefficient; the last date when smelter-
specific slope coefficient was measured; certification that 
measurements of slope coefficients were conducted in accordance with 
the method identified in proposed 40 CFR part 98, subpart F; and the 
parameters used by the smelter to measure the frequency and duration of 
anode effects.
    The following CO2-specific information would be reported 
on an annual basis: Anode consumption for pre-bake cells, paste 
consumption for S[oslash]derberg cells, and smelter-specific inputs to 
the CO2 process equations (e.g., levels of impurities) that 
were used in the calculation. Exact data elements required would vary 
depending on smelter technology.
    These records consist of values that are used to calculate the 
emissions and are necessary to enable verification that the GHG 
emissions monitoring and calculations were done correctly.
6. Selection of Records That Must Be Retained
    In addition to the data reported, we propose that facilities 
maintain records on monthly production by smelter, anode effect minutes 
per cell-day or anode effect overvoltage by month, facility specific 
emission coefficient linked to anode effect performance, and net anode 
consumption for Prebake cells or paste consumption for S[oslash]derberg 
cells.
    These records consist of data that would be used to calculate the 
GHG emissions and are necessary to verify that the emissions monitoring 
and calculations are done correctly.

G. Ammonia Manufacturing

1. Definition of the Source Category
    Ammonia is a major industrial chemical that is mainly used as 
fertilizer, directly applied as anhydrous ammonia, or further processed 
into urea, ammonium nitrates, ammonium phosphates, and other nitrogen 
compounds. Ammonia also is used to produce plastics, synthetic fibers 
and resins, and explosives.
    Ammonia can be produced through three processes: Steam reforming, 
solid fuel gasification, and brine electrolysis. The production of 
ammonia typically uses conventional steam reforming or solid fuel 
gasification and generates both combustion and process-related 
greenhouse gas emissions. The production of ammonia through the brine 
electrolysis process does not produce process GHG emissions, although 
it releases GHGs from combustion of fuels to support the electrolysis 
process. We have not identified any facilities in the U.S. producing 
ammonia through the brine electrolysis process.
    Catalytic steam reforming of ammonia generates process-related 
CO2, primarily through the use of natural gas as a 
feedstock. One plant located in Kansas is manufacturing ammonia from 
petroleum coke feedstock. This and other natural gas-based and 
petroleum coke-based feedstock processes produce CO2 and 
hydrogen, the latter of which is used in the manufacture of ammonia.
    Not all of the CO2 produced in the manufacture of 
ammonia is emitted directly to the atmosphere. Both ammonia and 
CO2 are used as raw materials in the production of urea 
(CO(NH2)2), which is another type of nitrogenous 
fertilizer that contains carbon (C) and nitrogen (N). The carbon from 
ammonia production that is used to manufacture urea is assumed to be 
released into the environment as CO2 during urea use. 
Therefore, the majority of CO2 emissions associated with 
urea consumption are those that result from its use as a fertilizer. 
For CO2 collected and used onsite or transferred offsite, 
you must follow the methodology provided in proposed 40 CFR part 98, 
subpart PP (Suppliers of CO2).
    Some facilities produce for sale a combination of ammonia, 
methanol, and hydrogen. We propose that facilities report their 
process-related GHG emissions in the source category corresponding to 
the primary NAICS code for the facility. For example, a facility that 
primarily produces ammonia but also produces methanol would report in 
the ammonia manufacturing source category. Since CO2 is used 
to produce methanol, it does not get emitted directly into the 
atmosphere. These facilities would account for the CO2 used 
to produce methanol through the methodology provided in proposed 40 CFR 
part 98, subpart G (Ammonia Manufacturing).
    National emissions from ammonia manufacturing were estimated to be 
14.6 million metric tons CO2 equivalent (<0.25 percent of 
U.S. GHG emissions in 2006). These emissions include both process 
related CO2 emissions and on-site stationary combustion emissions 
(CO2, CH4, and N2O) from 24 
manufacturing facilities across the U.S. Process-related emissions 
account for 7.6 million metric tons CO2, or 52 percent of 
the total, while on-site stationary combustion emissions account for 
the remaining 7.0 million metric tons CO2 equivalent 
emissions.
    For additional background information on ammonia manufacturing, 
please refer to the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-
007).
2. Selection of Reporting Threshold
    In developing the reporting threshold for ammonia manufacturing, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e. Table G-1 of 
this preamble illustrates the emissions and facilities that would be 
covered under these various thresholds.

[[Page 16493]]



                             Table G-1. Threshold Analysis for Ammonia Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                                     Emissions covered      Facilities covered
                                          Total     Total number -----------------------------------------------
 Threshold level metric tons CO2e/yr    national         of         Metric
                                        emissions    facilities   tons CO2e/    Percent     Number      Percent
                                                                      yr
----------------------------------------------------------------------------------------------------------------
1,000...............................    14,543,007            24  14,543,007         100          24         100
10,000..............................    14,543,007            24  14,543,007         100          24         100
5,000...............................    14,543,007            24  14,543,007         100          24         100
100,000.............................    14,543,007            24  14,449,519          99          22          92
----------------------------------------------------------------------------------------------------------------

    Facility-level emissions estimates based on known plant capacities 
suggest that all known facilities, except two, exceed the 100,000 
metric tons CO2e threshold. Where information was available, 
emission estimates were adjusted to account for CO2 
consumption during urea production, and this was taken into account in 
the threshold analysis. In order to simplify the proposed rule and 
avoid the need for the source to calculate and report whether the 
facility exceeds the threshold value, we propose that all ammonia 
manufacturing facilities are required to report.
    For a full discussion of the threshold analysis, please refer to 
the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international monitoring guidelines and protocols 
include methodologies for estimating both combustion and process-
related emissions from ammonia manufacturing (e.g., 2006 IPCC 
Guidelines, U.S. Inventory, DOE 1605(b), and TCR). These methodologies 
coalesce around the following four options which we considered for 
quantifying emissions from ammonia manufacture:
    Option 1. The first method found in existing protocols estimates 
emissions by applying a default emission factor to total ammonia 
produced. This approach estimates only process-related emissions. This 
approach is consistent with IPCC Tier 1 and DOE 1605(b) ``C'' rated 
estimation methods.
    Option 2. A second method consists of performing a mass balance 
calculation using default carbon content values for feedstock (from the 
U.S. DOE). Using default carbon content for fuel would not provide the 
same level of accuracy as using facility-specific carbon contents. This 
approach is consistent with IPCC Tier 2, DOE 1605(b) and TCR's ``B'' 
rated estimation methods.
    Option 3. The third option is based on the IPCC Tier 3 method for 
determining CO2 emissions from ammonia manufacture. This 
method calculates emissions based on the monthly measurements of the 
total feedstock consumed (quantity of natural gas or other feedstock) 
and the monthly carbon content of the feedstock. All carbon in the 
feedstock is assumed to be oxidized to CO2. The accuracy and 
certainty of this approach is directly related to the accuracy of the 
feedstock usage and the carbon content of the feedstock. If the 
measurements or readings are made and verified according to established 
QA/QC methods, the resulting emission calculations are as accurate as 
possible. For CO2 collected and used onsite or transferred 
offsite, you must follow the methodology provided in proposed 40 CFR 
part 98, subpart PP of this part (Suppliers of CO2). This 
approach is also consistent with DOE's 1605(b) ``A'' rated method and 
TCR's ``A2'' rated estimation methods.
    Option 4. The fourth option is using CEMS to directly measure 
CO2 emissions. While this method does tend to provide the 
most accurate emissions measurements, it is likely the costliest of all 
the monitoring methods.
    Proposed Option. Under the proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C and the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2 emissions from the industrial source.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
the CEMS does not measure CO2 process emissions, the 
proposed monitoring method is Option 3. You would be required to follow 
the requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2, CH4 and N2O emissions from 
stationary combustion.
    The proposed monitoring method is Option 3. Options 3 and 4 provide 
the most accurate estimates from site-specific conditions. Option 3 is 
consistent with current feedstock monitoring practices at facilities 
within this industry, thereby minimizing costs. For CO2 collected and 
used onsite or transferred offsite, you must follow the methodology 
provided in proposed 40 CFR part 98, subpart PP (Suppliers of CO2).
    In general, we decided against existing methodologies that relied 
on default emission factors or default values for carbon content of 
materials because the differences among facilities could not be 
discerned, and such default approaches are inherently inaccurate for 
site-specific determinations. 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.
    The various approaches to monitoring GHG emissions are elaborated 
in the Ammonia Manufacturing TSD (EPA-HQ-OAR-2008-0508-007).
4. Selection of Procedures for Estimating Missing Data
    The proposed rule requires the use of substitute data whenever a 
quality-assured value of a parameter that is used to calculate GHG 
emissions is unavailable, or ``missing.'' For missing feedstock supply 
rates, use the lesser of the maximum supply rate that the unit is 
capable of processing or the maximum supply rate that the meter can 
measure. There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are 
determined to be invalid.
5. Selection of Data Reporting Requirements
    We propose that facilities that estimate their process CO2 
emissions under proposed 40 CFR part 98, subpart G, submit their 
process CO2 emissions data and the following additional data on an 
annual basis. These data are the basis for calculations and are needed 
for us to understand the emissions data and verify the reasonableness 
of the reported emissions. We propose facilities submit

[[Page 16494]]

the following data on an annual basis for each process unit: The total 
quantity of feedstock consumed for ammonia manufacturing, the monthly 
analyses of carbon content for each feedstock used in ammonia 
manufacturing. A full list of data to be reported is included in 
proposed 40 CFR part 98, subparts A and G.
6. Selection of Records That Must Be Retained
    We propose that each ammonia manufacturing facility maintain 
records of monthly carbon content analyses, and the method used to 
determine the quantity of feedstock used. These records consist of 
values that are directly used to calculate the emissions that are 
reported and are necessary to enable verification that the GHG 
emissions monitoring and calculations were done correctly.

H. Cement Production

1. Definition of the Source Category
    Hydraulic Portland cement, the primary product of the cement 
industry, is a fine gray or white powder produced by heating a mixture 
of limestone, clay, and other ingredients at high temperature. 
Limestone is the single largest ingredient required in the cement-
making process, and most cement plants are located near large limestone 
deposits. CO2 from the chemical process of cement production is the 
second largest source of industrial CO2 emissions in the U.S.
    During the cement production process, calcium carbonate (CaCO3) 
(usually from limestone and chalk) is combined with silica-containing 
materials (such as sand and shale) and is heated in a cement kiln at a 
temperature of about 1,450 [deg]C (2,400 [deg]F). The CaCO3 forms 
calcium oxide (or CaO) and CO2 in a process known as calcination or 
calcining. Very small amounts of carbonates other than CaCO3, such as 
magnesium carbonates and non-carbonate organic carbon may also be 
present in the raw materials, both of which contribute to generation of 
additional CO2. The product from the cement kiln is clinker, an 
intermediate product, and the CO2 generated as a by-product. The CO2 is 
released to the atmosphere.
    Additional CO2 emissions are generated with the formation of 
partially calcinated cement kiln dust. During clinker production, some 
of the clinker precursor materials (instead of forming clinker) are 
entrained in the flue gases exiting the kiln as non-calcinated, 
partially calcinated, or fully calcinated cement kiln dust \67\. Cement 
Kiln Dust is collected from the flue gas in dust collection equipment 
and can either be recycled back to the kiln or be sent offsite for 
disposal, depending on its quality. Organic carbon in raw materials is 
also emitted as CO2 as raw material is heated.
---------------------------------------------------------------------------

    \67\ Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
---------------------------------------------------------------------------

    National GHG emissions from cement production were estimated to be 
86.83 million metric tons CO2e in 2006. These emissions include both 
process-related emissions (CO2) and on-site stationary combustion 
emissions (CO2, CH4, and N2O) from 107 cement production facilities. 
Process-related emissions account for over half of emissions (45.7 
million metric tons CO2), while on-site stationary combustion emissions 
account for the remaining 41.1 million metric tons CO2e emissions.
    For additional background information on cement production, please 
refer to the Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
2. Selection of Reporting Threshold
    In developing the threshold for cement manufacturing, we considered 
emissions-based thresholds of 1,000 metric tons CO2e, 10,000 metric 
tons CO2e, 25,000 metric tons CO2e, and 100,000 metric tons CO2e. Table 
H-1 of this preamble illustrates the emissions and facilities that 
would be covered under these thresholds.

                             Table H-1. Threshold Analysis for Cement Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                                  Emissions Covered        Facilities Covered
                                    Total                    ---------------------------------------------------
  Threshold level metric tons      national    Total number     Million
            CO2e/yr               emissions    of facilities  metric tons    Percent       Number      Percent
                                  (MMTCO2e)                     CO2e/yr
----------------------------------------------------------------------------------------------------------------
1,000..........................        86.83             107        86.83          100          107          100
10,000.........................        86.83             107        86.83          100          107          100
25,000.........................        86.83             107        86.83          100          107          100
100,000........................        86.83             107        86.74         99.9          106         99.9
----------------------------------------------------------------------------------------------------------------

    All emissions thresholds examined covered over 99.9 percent of CO2e 
emissions from cement facilities. Only one plant out of 107 in the 
dataset would be excluded by a 100,000 metric tons CO2e threshold. All 
facilities would be included under a 25,000 metric tons CO2e threshold. 
Therefore, EPA is proposing that all cement production facilities are 
required to report. Having no threshold covers all of the cement 
production process emissions without increasing the number of 
facilities that must report and simplifies the rule.
    For a full discussion of the threshold analysis, please refer to 
the Cement Production TSD (EPA-HQ-OAR-2008-0508-008). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from cement manufacturing (e.g., the 2006 IPCC Guidelines, 
U.S. Inventory, DOE 1605(b), CARB mandatory GHG emissions reporting 
program, EPA's Climate Leaders, the EU Emissions Trading System, and 
the Cement Sustainability Initiative Protocol). These

[[Page 16495]]

methodologies coalesce around four different options.
    Option 1. Apply a default emission factor to the total quantity of 
clinker produced at the facility. The quantity of clinker produced 
could be directly measured, or a clinker fraction could be applied to 
the total quantity of cement produced.
    Option 2. Apply site-specific emission factors to the quantity of 
clinker produced.
    Option 3. Measure the carbonate inputs to the furnace. Under this 
``kiln input'' approach, emissions are calculated by weighing the mass 
of individual carbonate species sent to the kiln, multiplying by the 
emissions factor (relating CO2 emissions to carbonate content in the 
kiln feed), and subtracting for uncalcined cement kiln dust.
    Option 4. Direct measurement of emissions using CEMS.
    Proposed Option. Based on the agency's review of the above 
approaches, we propose two different methods for quantifying GHG 
emissions from cement manufacturing, depending on current emissions 
monitoring at the facility.
    CEMS Method. Under the proposed rule, if you are required to use an 
existing CEMS to meet the requirements outlined in proposed 40 CFR part 
98, subpart C, you would be required to use CEMS to estimate CO2 
emissions. Where the CEMS capture all combustion- and process-related 
CO2 emissions you would be required to follow the requirements of 
proposed 40 CFR part 98, subpart C to estimate all CO2 emissions from 
the industrial source. Also, refer to proposed 40 CFR part 98, subpart 
C (discussed in Section V.C of this preamble) to estimate combustion-
related CH4 and N2O.
    Calculation Method (Option 2). For facilities that do not currently 
have CEMS that meet the requirements outlined in proposed 40 CFR part 
98, subpart C, or where the CEMS would not adequately account for 
process emissions, we propose that these facilities calculate emissions 
following Option 2 outlined below. You would be required to follow the 
requirements of proposed 40 CFR part 98, subpart C to estimate 
emissions of CO2, CH4 and N2O from stationary combustion. The cement 
production section provides only those procedures for calculating and 
reporting process-related emissions.
    Under Option 2, we propose that facilities develop facility-
specific emission factors relating CO2 emissions to clinker production 
for each individual kiln. The emission factor relating CO2 emissions to 
clinker production would be based on the percent of measured carbonate 
content in the clinker (measured on a monthly basis) and the fraction 
of calcination achieved. The clinker emission factor is then multiplied 
by the monthly clinker production to estimate monthly process-related 
CO2 emissions from cement production. Annual emissions are calculated 
by summing CO2 emissions over 12 months across all kilns at the 
facility.
    Most current protocols propose this method, but allow facilities to 
apply a national default emission factor. We propose the development of 
a facility-specific emission factor based on the understanding that 
facilities analyze the carbonate contents of their raw materials to the 
kiln on a frequent basis, either on a daily basis or every time there 
is a change in the raw material mix.
    Cement Kiln Dust. The CO2 emissions attributable to calcined 
material in the cement kiln dust not recycled back to the kiln must be 
added to the estimate of CO2 emissions from clinker production. To 
establish a cement kiln dust adjustment factor, we propose that 
facilities conduct a chemical analysis on a quarterly basis to estimate 
the plant-specific fraction of uncalcined carbonate in the cement kiln 
dust from each kiln, that is not recycled to the kiln each quarter. 
Again, this method provides reasonable accuracy and is highly 
consistent with the prevailing methods presented in existing protocols.
    TOC Content in Raw Materials. The CO2 emissions attributable to the 
TOC content in raw material must be added to the estimate of CO2 
emissions from clinker production and cement kiln dust. We propose that 
facilities conduct an annual chemical analysis to determine the organic 
content of the raw material on an annual basis. The emissions are 
calculated from the TOC content by multiplying the organic content by 
the amount of raw material consumed annually.
    Other Options Considered. We considered three alternative options 
to estimate process-related emissions from cement production. The first 
method considered was to apply default emission factors to clinker 
production (either based on measurement of clinker, or by applying a 
clinker fraction to cement production). Applying default emission 
factors to clinker production is one of the most common approaches in 
existing protocols. However, 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.
    In some protocols, this method requires correcting for purchases 
and sales of clinker, such that a facility is only accounting for 
emissions from the clinker that is manufactured on site. This approach 
provides better emissions data than protocols where the method does not 
correct for clinker purchases and sales. In some protocols, the method 
requires reporters to start with cement production, estimate the 
clinker fraction, and then estimate the carbonate input used to produce 
the clinker. Conceptually, this might not be any different than the 
kiln input approach as the facility would ultimately have to identify 
and quantify the carbonate inputs to the kiln.
    The kiln input approach was considered, but not proposed, because 
it would not lead to significantly reduced uncertainty in the emissions 
estimate over the clinker based approach, where a site-specific 
emission factor is developed using periodic sampling of the carbonate 
mix into the kiln. The primary difference is the proposed clinker-based 
approach requires a monthly analysis of the degree of calcination 
achieved in the clinker in order to develop the facility-specific 
emissions factor, whereas the kiln input approach would require monthly 
monitoring of the inputs and outputs of the kiln. We concluded that 
although the kiln input does not improve certainty estimates 
significantly, it could potentially be more costly depending on the 
carbonate input sampling frequency.
    Early domestic and international guidance documents for estimating 
process CO2 emissions from cement production offered the option of 
applying a default emission factor to cement production (e.g. IPCC Tier 
1, DOE 1605(b) ``C'' rated approach). This is no longer considered an 
acceptable method in national inventories therefore we did not consider 
it further for developing a mandatory GHG reporting rule.
    The various approaches to monitoring GHG emissions are elaborated 
in the Cement Production TSD (EPA-HQ-OAR-2008-0508-008).
4. Selection of Procedures for Estimating Missing Data
    For facilities with CEMs, we propose that facilities follow the 
missing data procedures in proposed 40 CFR part 98, subpart C, which 
are also discussed in Section V.C of this preamble.
    For facilities without CEMs, we propose that no missing data 
procedures would apply because the emission

[[Page 16496]]

factors used to estimate CO2 emissions from clinker and cement kiln 
dust production are derived from routine tests of carbonate contents. 
In the event data on carbonate content analysis is missing we propose 
that the facility undertake a new analysis of carbonate contents. We 
are not proposing any missing data allowance for clinker and cement 
kiln dust production data. The likelihood for missing input, clinker 
and cement kiln dust production data is low, as businesses closely 
track their purchase of production inputs, quantity of clinker 
produced, and quantity of cement kiln dust discarded.
5. Selection of Data Reporting Requirements
    We propose that facilities submit annual CO2 emissions 
from cement production, as well as any stationary fuel combustion 
emissions. In addition, facilities using CEMS would be required to 
follow the data reporting requirements in proposed 40 CFR part 98, 
subpart C. Facilities using the clinker-based approach would be 
required to report annual clinker production, annual cement kiln dust 
production, number of kilns, site-specific clinker emission factor, the 
total annual fraction of cement kiln dust recycled to the kiln, and the 
quantity of CO2 captured for use and the end use, if known. 
In addition, we propose that facilities submit their annual analysis of 
carbonate composition, the total annual fraction of calcination 
achieved (for each carbonate), organic carbon content of the raw 
material, and the amount of raw material consumed annually. These data, 
used as the basis of the calculations, are needed for EPA to understand 
the emissions data and verify reasonableness of the reported emissions. 
A full list of data to be reported is included in proposed 40 CFR part 
98, subparts A and H.
6. Selection of Records That Must Be Retained
    In addition to the data reported, we propose that facilities using 
the clinker-based approach to calculate emissions keep records of 
monthly carbonate consumption, monthly cement production, monthly 
clinker production, results from monthly chemical analysis of 
carbonates, documentation of calculated site specific clinker emission 
factor, quarterly cement kiln dust production, total annual fraction 
calcination achieved, organic carbon content of the raw material, and 
the amount of raw material consumed annually. These records include 
values directly used to calculate the reported emissions; and these 
records are necessary to verify the estimated GHG emissions. A full 
list of records that must be retained onsite is included in proposed 40 
CFR part 98, subparts A and H.

I. Electronics Manufacturing

1. Definition of the Source Category
    The electronics industry uses multiple long-lived fluorinated GHGs 
such as PFCs, HFCs, SF6, and NF3 during 
manufacturing of semiconductors, liquid crystal displays (LCDs), 
microelectrical mechanical systems (MEMs), and photovoltaic cells (PV). 
We are also seeking comment below on the inclusion of light-emitting 
diodes (LEDs), disk readers and other products as part of the 
electronics manufacturing source category.
    The fluorinated gases (at room temperature) are used for plasma 
etching of silicon materials and cleaning deposition tool chambers. 
Additionally, semiconductor manufacturing employs fluorinated GHGs 
(typically liquids at room temperature) as heat transfer fluids. The 
most common fluorinated GHGs in use are HFC-23, CF4, 
C2F6, NF3 and SF6, although 
other compounds such as perfluoropropane (C3F8) 
and perfluorocyclobutane (c-C4F8) are also used 
(EPA, 2008a).
    Electronics manufacturers may also use N2O as the oxygen source for 
chemical vapor deposition of silicon oxynitride or silicon dioxide. 
Besides dielectric film etching and chamber cleaning, much smaller 
quantities of fluorinated gases are used to etch polysilicon films and 
refractory metal films like tungsten. Table I-1 of this preamble 
presents the fluorinated GHGs typically used during manufacture of each 
of these electronics devices.

      Table I-1. Fluorinated GHGs Used by the Electronics Industry
------------------------------------------------------------------------
                                          Fluorinated GHGs used during
             Product type                         manufacture
------------------------------------------------------------------------
Electronics (e.g., Semiconductor,      CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
 MEMS, LCD, PV).                        C4F6, C5F8, CHF3, CH2F2, NF3,
                                        SF6, and Heat Transfer Fluids
                                        (CF3-(O-CF(CF3)-CF2)n-(O-CF2)m-O
                                        -CF3, CnF2n+2, CnF2n+1(O)
                                        CmF2m+1, CnF2nO, (CnF2n+1)3N)a.
------------------------------------------------------------------------
a IPCC Guidelines do not specify the fluorinated GHGs used by the MEMs
  industry. Literature reviews revealed that CF4, SF6, and the Bosch
  process (consisting of alternating steps of SF6 and c-C4F8) are used
  to manufacture MEMs. For further information, see the Electronics
  Manufacturing TSD (EPA-HQ-OAR-2008-0508-009).

    The etching process uses plasma-generated fluorine atoms, which 
chemically react with exposed dielectric film to selectively remove the 
desired portions of the film. The material removed as well as 
undissociated fluorinated gases flow into waste streams and, unless 
emission control systems are employed, into the atmosphere.
    Chambers used for depositing dielectric films are cleaned 
periodically using fluorinated and other gases. During the cleaning 
cycle the gas is converted to fluorine atoms in plasma, which etches 
away residual material from chamber walls, electrodes, and chamber 
hardware. Undissociated fluorinated gases and other products pass from 
the chamber to waste streams and, unless emission control systems are 
employed, into the atmosphere.
    In addition to emissions of unreacted gases, some fluorinated 
compounds can also be transformed in the plasma processes into 
different fluorinated GHGs which are then exhausted, unless abated, 
into the atmosphere. For example, when C2F6 is 
used in cleaning or etching, CF4 is generated and emitted as a process 
by-product.
    Fluorinated GHG liquids (at room temperature) such as fully 
fluorinated linear, branched or cyclic alkanes, ethers, tertiary amines 
and aminoethers, and mixtures thereof are used as heat transfer fluids 
at several semiconductor facilities to cool process equipment, control 
temperature during device testing, and solder semiconductor devices to 
circuit boards. The fluorinated heat transfer fluid's high vapor 
pressures can lead to evaporative losses during use.\68\ We are seeking 
comment on the extent of use and

[[Page 16497]]

annual replacement quantities of fluorinated liquids as heat transfer 
fluids in other electronics sectors, such as their use for cooling or 
cleaning during LCD manufacture.
---------------------------------------------------------------------------

    \68\ Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009); 
2006 IPCC Guidelines.
---------------------------------------------------------------------------

    Total U.S. Emissions. Emissions of fluorinated GHGs from an 
estimated 216 electronics facilities were estimated to be 6.1 million 
metric tons CO2e in 2006. Below is a breakdown of emissions 
by electronics product type.
    Semiconductors. Emissions of fluorinated GHGs, including heat 
transfer fluids, from 175 semiconductor facilities were estimated to be 
5.9 million metric tons CO2e in 2006. Of the total estimated 
semiconductor emissions, 5.4 million metric tons CO2e are 
from etching/chamber cleaning and 0.5 million metric tons 
CO2e are from heat transfer fluid usage. Partners of the PFC 
Reduction/Climate Partnership for Semiconductors comprise approximately 
80 percent of U.S. semiconductor production capacity. These partners 
have committed to reduce their emissions (exclusive of heat transfer 
fluid emissions) to 10 percent below their 1995 levels by 2010, and 
their emissions have been on a general decline toward attainment of 
this goal since 1999.
    MEMs. Emissions of fluorinated GHGs from 12 facilities were 
estimated to be 0.03 million metric tons CO2e in 2006.
    LCDs. Emissions of fluorinated GHGs from 9 facilities were 
estimated to be 0.02 million metric tons CO2e in 2006.
    PVs. Emissions of fluorinated GHGs from 20 PV facilities were 
estimated to be 0.07 million metric tons CO2e in 2006. We 
request comment on the number and capacity of thin film (i.e., 
amorphous silicon) and other PV manufacturing facilities in the U.S. 
using fluorinated GHGs.
    Emissions To Be Reported. This section details our proposed 
requirements for reporting fluorinated GHG and N2O emissions 
from the following processes and activities:
    (1) Plasma etching;
    (2) Chamber cleaning;
    (3) Chemical vapor deposition using N2O as the oxygen source; and
    (4) Heat transfer fluid use.
    Our understanding is that only semiconductor facilities use heat 
transfer fluids; we request comment on this assumption.
    For additional background information on the electronics industry, 
refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009).
2. Selection of Reporting Threshold
    For manufacture of semiconductors, LCDs, and MEMs, we are proposing 
capacity-based thresholds equivalent to an annual emissions threshold 
of 25,000 metric tons CO2e. For manufacture of PVs for which 
we have less information on use and emissions of fluorinated GHGs, we 
are proposing an emissions threshold of 25,000 metric tons of 
CO2e.
    We are seeking comment on the inclusion of LEDs, disk readers and 
other products in the electronics manufacturing source category. Given 
that the manufacturing process for these devices is similar to other 
electronics, we are specifically interested in seeking feedback on the 
level of emissions from their manufacturer and whether subjecting these 
products to an emissions threshold of 25,000 metric ton CO2e 
would be appropriate.
    In our analysis, we considered emission thresholds of 1,000 metric 
tons CO2e, 10,000 metric tons CO2e, 25,000 metric 
tons CO2e, and 100,000 metric tons CO2e per year. 
Table I-2 of this preamble shows emissions and facilities that would be 
captured by the respective emissions thresholds.

                                                 Table I-2. Threshold Analysis for Electronics Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                Emissions covered               Facilities covered
                                                         Total national   Total number  ----------------------------------------------------------------
      Emission threshold level metric tons CO2e/yr          emissions     of facilities    Metric tons
                                                                                             CO2e/yr         Percent        Facilities        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000..................................................       5,984,462             216       5,972,909             99.8             173              80
10,000.................................................       5,984,462             216       5,840,411             98               118              55
25,000.................................................       5,984,462             216       5,708,283             95                96              44
100,000................................................       5,984,462             216       4,708,283             79                54              25
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We selected the 25,000 metric tons CO2e per year 
threshold because this threshold maximizes emissions reporting, while 
excluding small facilities that do not contribute significantly to the 
overall GHG emissions.
    We propose to use a production-based threshold based on the rated 
capacities of facilities, as opposed to an emissions-based threshold, 
where possible, because it simplifies the applicability determination. 
Therefore, we derived production capacity thresholds that are 
approximately equivalent to metric tons CO2e using IPCC Tier 
1 default emissions factors and assuming 100 percent capacity 
utilization. Where IPCC Tier 1 default factors were unavailable (i.e., 
MEMs), the emissions factor was estimated based on those of 
semiconductors for the relevant fluorinated GHGs. The proposed 
capacity-based thresholds are 1,000 m2 silicon for 
semiconductors; 4,000 m2 silicon for MEMs; and 236,000 m2 
LCD for LCDs. Table I-3 of this preamble shows the estimated emissions 
and number of facilities that would report for each source under the 
proposed capacity-based thresholds. PV is not shown in the table 
because we are proposing an emissions threshold due to lack of 
information.

                                  Table I-3. Summary of Rule Applicability Under the Proposed Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                               Total             Emissions covered              Facilities covered
                                       Capacity-based     Total national   emissions  of ---------------------------------------------------------------
         Emissions source                 threshold         facilities    source (metric    Metric tons
                                                                            tons CO2e)        CO2e/yr         Percent       Facilities        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
Semi-conductors...................  1,080 silicon m2....             175       5,741,676       5,492,066              96              91              52
MEMs..............................  1,020 silicon m2....              12         146,115          96,164              66               2              17
LCD...............................  235,700 LCD m2......               9          23,632               0               0               0               0
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 16498]]

    The proposed capacity-based thresholds are estimated to cover about 
50 percent of semiconductor facilities and between 0 percent and 20 
percent of the facilities manufacturing MEMs and LCDs. At the same 
time, the thresholds are expected to cover nearly 96 percent of 
fluorinated GHG emissions from semiconductor facilities, and 0 percent 
and 66 percent of fluorinated GHG emissions from facilities 
manufacturing LCDs and MEMs, respectively. Combined these emissions are 
estimated to account for close to 94 percent of fluorinated GHG 
emissions from electronics as a whole.
    We are proposing capacity-based thresholds for the electronics 
industry, where possible, because electronics manufacturers may employ 
emissions control equipment (e.g., thermal oxidizers, fluorinated GHG 
capture recycle systems) to lower their fluorinated GHG emissions. In 
addition, capacity-based thresholds would permit facilities to quickly 
determine whether or not they must report under this rule.
    When abatement equipment is used, electronics manufacturers often 
estimate their emissions using the manufacturer-published DRE for the 
equipment. However, abatement equipment may fail to achieve its rated 
DRE either because it is not being properly operated and maintained or 
because the DRE itself was incorrectly measured due to a failure to 
account for the effects of dilution. (For example, CF4 can 
be off by as much as a factor of 20 to 50 and 
C2F6 can be off by a factor of up to 10 because 
of failure to properly account for dilution.) In either event, the 
actual emissions from facilities employing abatement equipment may 
exceed estimates based on the rated DREs of this equipment and may 
therefore exceed the 25,000 metric tons CO2e threshold 
without the knowledge of the facility operators. Measuring and 
reporting emission control device performance is therefore important 
for developing an accurate estimate of emissions. As discussed below, 
we propose an emission estimation method that would account for 
destruction by abatement equipment only if facilities verified the 
performance of their abatement equipment using one of two methods. If 
facilities choose not to verify the performance of their abatement 
equipment, the estimation method would not account for any destruction 
by the abatement device.
    For additional background information on the threshold analysis, 
refer to the Electronics Manufacturing TSD (EPA-HQ-OAR-2008-0508-009). 
For specific information on costs, including unamortized first year 
capital expenditures, please refer to section 4 of the RIA and the RIA 
cost appendix.
3. Selection of Proposed Monitoring Methods
a. Etching and Cleaning Emissions
    Fluorinated GHG Emissions. Under the proposed rule, large 
semiconductor facilities (defined as facilities with annual capacities 
of greater than 10,500 m\2\ silicon) would be required to estimate 
their fluorinated GHG emissions from etching and cleaning using an 
approach based on the IPCC Tier 3 method, and all other facilities 
would be required to use an approach based on the IPCC Tier 2b method. 
We have determined that large semiconductor facilities are already 
using Tier 3 methods and/or have the necessary data readily available 
either in-house or from suppliers to apply the highest tier method. The 
difference between the proposed approaches and the IPCC methods is that 
the proposed approaches include stricter requirements for quantifying 
the gas destroyed by abatement equipment, as described below. None of 
the IPCC methods require a standard protocol to estimate DREs of 
abatement equipment. Given that the actual DRE of the abatement 
equipment can be significantly smaller (by up to a factor of 50) 
compared to the manufacturer rated DRE, we are proposing verification 
of the DREs using a standard reporting protocol (Burton, 2007).
    Under the proposed rule, we estimate that 17 percent of all 
semiconductor manufacturing facilities would be required to report 
using an IPCC Tier 3 approach (equivalent to 29 facilities out of 175 
total facilities) and that 56 percent of total semiconductor emissions 
(equivalent 3.4 million metric tons CO2e out of a total 5.9 
million metric tons CO2e emissions) would be reported using 
the IPCC Tier 3 approach.
    Method for Large Facilities. The IPCC Tier 3 approach uses company-
specific data on (1) gas consumption, (2) gas utilization, (3) by-
product formation, and (4) DRE for all emission abatement processes at 
the facility.
    Information on gas consumption by process is often gathered as 
business as usual,\69\ and information on gas utilization, by-product 
formation, and DRE for each process is readily available from tool 
manufacturers and can also be experimentally measured on-site at the 
facility. We propose that the DRE for abatement equipment be 
experimentally measured using the protocol described below.
---------------------------------------------------------------------------

    \69\ In the RIA for this rulemaking, we have conservatively 
included the costs of gathering, consolidating, and checking 
process-specific gas consumption information. However, we believe 
that this information is already gathered in many cases for purposes 
of internal process control and/or emissions reporting under EPA's 
voluntary PFC Reduction Program for the Semiconductor Industry.
---------------------------------------------------------------------------

    The guidance prepared by International SEMATECH Technology Transfer 
0612485A-ENG (December 2006) must be followed when preparing 
gas utilization and by-product formation measurements. We have 
determined that electronics manufacturers commonly track fluorinated 
GHG consumption using flow metering systems calibrated to 1 
percent or better accuracy. Thus the equation for estimating emissions 
does not account for cylinder heels. However, a facility may choose to 
estimate consumption by weighing fluorinated GHG cylinders when placed 
into and taken out of service, as is common practice by the magnesium 
industry.
    The use of the IPCC Tier 3 method and standard site-specific DRE 
measurement would provide the most certain and practical emission 
estimates for large facilities. The uncertainty associated with an IPCC 
Tier 3 approach is lower than any of the other IPCC approaches, and is 
on the order of 30 percent at the 95 percent confidence 
interval. We estimate that the Tier 3 approach would not impose a 
significant burden on facilities because large semiconductor facilities 
are already using Tier 3 methods and/or have the necessary data to do 
so readily available, as noted above.
    Method for Other Semiconductor, LCD, MEMS, and PV Facilities. The 
IPCC Tier 2b approach is based on gas consumption by process type 
(i.e., etch or chamber clean) multiplied by default factors for 
utilization, by-product formation, and destruction. We are proposing 
that site-specific DRE measurements be used for quantifying the amount 
of gas destroyed. The DRE measurements would be determined using the 
protocol described below.
    The Tier 2b approach does not account for variation among 
individual processes or tools and, therefore, the estimated emissions 
have an uncertainty about twice as high as that of IPCC Tier 3 
estimates. However, we have concluded that the IPCC Tier 3 method would 
be unduly burdensome to the estimated 146 facilities with annual 
production less than 10,500 m\2\ silicon. We estimate that the IPCC 
Tier 2b approach would not impose a significant burden on facilities 
because it requires only minimal fluorinated gas usage tracking by 
major production process type. These production input

[[Page 16499]]

data are readily available at all U.S. manufacturing facilities.
    N2O Emissions. We are proposing that electronics manufacturers use 
a simple mass-balance approach to estimate emissions of N2O 
during etching and chamber cleaning. This methodology assumes 
N2O is not converted or destroyed during etching or chamber 
cleaning, due to lack of N2O utilization data. We request 
comment on utilization factors for N2O during etching and 
chamber cleaning, and any data on N2O by-product formation.
    Verification of DRE. For facilities that employ abatement devices 
and wish to reflect the emission reductions due to these devices in 
their emissions estimates, two methods are proposed for verifying the 
DRE of the equipment. Either method may be followed.
    The first method would require facilities (or their equipment 
suppliers) to test the DRE of the equipment using an industry standard 
protocol, such as the one under development by EPA as part of the PFC 
Reduction/Climate Partnership for Semiconductors (not yet published). 
This draft protocol requires facilities to experimentally determine the 
effective dilution through the abatement device and to measure 
abatement DRE during actual or simulated process conditions. The second 
method would require facilities to buy equipment that has been tested 
by an independent third party (e.g., UL) using an industry standard 
protocol such as the one under development by EPA. Under this approach, 
manufacturers would pay the third party to select random samples of 
each model and test them. Because testing would not need to be obtained 
for every piece of equipment sold, this approach would probably be less 
expensive than in-house testing by electronics manufacturers, but it 
may not capture the full range of conditions under which the abatement 
equipment would actually be used.
    We believe that the proposed DRE measurement method is generally 
robust, but we are requesting comment on one aspect of that method. We 
are concerned that the DREs measured and calculated for CF4 
may vary depending on the mix of input gases used in the electronics 
manufacturing process. The calculated DRE for CF4 may be 
influenced by the formation of CF4 from other PFCs during 
the destruction process itself, and different input gases have 
different CF4 byproduct formation rates. This means that a 
DRE for CF4 calculated using one set of input gases might 
over- or under-estimate CF4 emissions when applied to 
another set of input gases (or even the original set in different 
proportions). We request comment on the likelihood and potential 
severity of such errors and on how they might be avoided.
    Facilities pursuing either DRE verification method would also be 
required to use the equipment within the manufacturer's specified 
equipment lifetime, operate the equipment within manufacturer specified 
limits for the gas mix and exhaust flow rate intended for fluorinated 
GHG destruction, and maintain the equipment according to the 
manufacturer's guidelines. We request comment on these proposed 
requirements.
b. Emissions of Heat Transfer Fluids
    We propose that electronics manufacturers use the IPCC Tier 2 
approach, which is a mass-balance approach, to estimate the emissions 
of each fluorinated heat transfer fluid. The IPCC Tier 2 approach uses 
company-specific data and accounts for differences among facilities' 
heat transfer fluids (which vary in their GWPs), leak rates, and 
service practices. It has an uncertainty on the order of 20 
percent at the 95 percent confidence interval according to the 2006 
IPCC Guidelines. The Tier 2 approach is preferable to the IPCC Tier 1 
approach, which relies on a default emissions factor to estimate heat 
transfer fluid emissions and has relatively high uncertainty compared 
to the Tier 2 approach.
c. Review of Existing Reporting Programs and Methodologies
    We reviewed the PFC Reduction/Climate Partnership for the 
Semiconductor Industry, U.S. GHG Inventory, 1605(b), EPA Climate 
Leaders, WRI, TRI, and the World Semiconductor Council methods for 
estimating etching and cleaning emissions. All of the methods draw from 
both the 2000 and 2006 IPCC Guidelines.
    Etching and Cleaning. For etching and cleaning emissions, we 
considered the 2006 IPCC Tier 1 and Tier 2a methods, as well as a Tier 
2b/3 hybrid which would apply Tier 3 to the most heavily used 
fluorinated GHGs in all facilities.
    The Tier 1 approach is based on the surface area of substrate 
(e.g., silicon, LCD or PV-cell) produced during manufacture multiplied 
by a default gas-specific emission factor. The advantages of the Tier 1 
approach lie in its simplicity. However, this method does not account 
for the differences among process types (i.e., etching versus 
cleaning), individual processes, or tools, leading to uncertainties in 
the default emission factors of up to 200 percent at the 95 percent 
confidence interval.\70\ Facilities routinely monitor gas consumption 
as part of business as usual, making it technically feasible to employ 
a method of at least IPCC Tier 2a complexity or higher without 
additional data collection efforts.
---------------------------------------------------------------------------

    \70\ This uncertainty refers only to semiconductors and LCDs. 
Tier 1 emission factor uncertainty for PV was not estimated in the 
2006 IPCC Guidelines.
---------------------------------------------------------------------------

    The Tier 2a approach is based on the gas consumption multiplied by 
default factors for utilization, by-product formation, and destruction. 
The Tier 2a approach is relatively simple, given that gas consumption 
data is collected as part of business as usual. However, due to 
variation in gas utilization between etching and cleaning processes, 
the estimated emissions using Tier 2a have greater uncertainty than 
Tier 2b estimated emissions.
    Tier 2b/3 hybrid approach involves requiring Tier 3 reporting for 
all facilities, but only for the top three gases emitted at each 
facility. For all other gases, the Tier 2b approach would be required. 
The top three gases emitted, based on data in the Inventory of U.S. GHG 
Emissions and Sinks, are C2F6, CF4, 
and SF6 (EPA, 2008a). These top three gases accounted for 
approximately 80 percent of total fluorinated GHG emissions from 
semiconductor manufacturing during etching and chamber cleaning in 
2006. The uncertainty associated with the Tier 2b/3 hybrid approach has 
not been determined, but is estimated to be between the uncertainty for 
a Tier 2b and Tier 3 approach.
    We did not select the Tier 1 and Tier 2a methods due to the greater 
uncertainty inherent in these approaches. Although the Tier 2b/3 hybrid 
approach would provide more accurate emissions estimates for small 
facilities, we concluded that the Tier 2b method with site-specific DRE 
measurements would provide sufficient accuracy without the additional 
monitoring and recordkeeping requirements of the Tier 3 method.
    We propose collecting emissions data from MEMS manufacturers 
meeting the threshold criterion although no IPCC default emission 
factors exist for MEMs and the IPCC emission factors for semiconductor 
and LCD manufacturing may not be reliable for MEMs. Therefore, we are 
seeking information on emissions and emission factors for both MEMs and 
LCD manufacturing.
    Heat Transfer Fluids. For heat transfer fluid emissions, we 
reviewed both the IPCC Tier 1 and IPCC Tier 2 approaches. The Tier 1 
approach for heat transfer fluid emissions is based on the

[[Page 16500]]

utilization capacity of the semiconductor facility multiplied by a 
default emission factor. Although the Tier 1 approach has the 
advantages of simplicity, it is less accurate than the Tier 2 approach 
according to the 2006 IPCC Guidelines.
4. Selection of Procedures for Estimating Missing Data
    Where facility-specific process gas utilization rates and by-
product gas formation rates are missing, facilities can estimate 
etching/cleaning emissions by applying defaults from the next lower 
Tier (e.g., IPCC Tier 2b or Tier 2a) to estimate missing data. However, 
facilities must limit their use of defaults from the next lower Tier to 
less than 5 percent of their emissions estimate.
    Default values for estimating DRE would not be permitted. DRE 
values must be estimated as zero in the absence of facility-specific 
DREs that have been measured using a standard protocol. Gas consumption 
is collected as business as usual and is not expected to be missing; 
therefore, it would not be permitted to revert to the Tier 1 approach 
for estimating emissions. When estimating heat transfer fluid emissions 
during semiconductor manufacture, the use of the mass-balance approach 
requires correct records for all inputs. Should the facility be missing 
records for a given input, it may be possible that the heat transfer 
fluid supplier has information in their records for the facility.
5. Selection of Data Reporting Requirements
    Owners and operators would be required to report GHG emissions for 
the facility, for all plasma etching processes, all chamber cleaning, 
all chemical vapor deposition processes, and all heat tranfer fluid 
use. Along with their emissions, facilities would be required to report 
the following: Method used (i.e., 2b or 3), mass of each gas fed into 
each process type, production capacity in terms of substrate surface 
area (e.g., silicon, PV-cell, LCD), factors used for gas utilization, 
by-product formation and their sources/uncertainties, emission control 
technology DREs and their uncertainties, fraction of gas fed into each 
process type with emissions, control technologies, description of 
abatement controls, inputs in the mass-balance equation (for heat 
transfer fluid emissions), example calculation, and emissions 
uncertainty estimate.
    These data form the basis of the calculations and are needed for us 
to understand the emissions data and verify the reasonableness of the 
reported emissions.
6. Selection of Records That Must Be Retained
    We propose that facilities keep records of the following: Data 
actually used to estimate emissions, records supporting values used to 
estimate emissions, the initial and any subsequent tests of the DRE of 
oxidizers, the initial and any subsequent tests to determine emission 
factors for process, and abatement device calibration/maintenance 
records.
    These records consist of values that are directly used to calculate 
the emissions that are reported and are necessary to enable 
verification that the GHG emissions monitoring and calculations are 
done correctly.

J. Ethanol Production

1. Definition of the Source Category
    Ethanol is produced primarily for use as a fuel component, but is 
also used in industrial applications and in the manufacture of beverage 
alcohol. Ethanol can be produced from the fermentation of sugar, 
starch, grain, and cellulosic biomass feedstocks, or produced 
synthetically from ethylene or hydrogen and carbon monoxide.
    The sources of GHG emissions at ethanol production facilities that 
must be reported under the proposed rule are stationary fuel 
combustion, onsite landfills, and onsite wastewater treatment.
    Proposed requirements for stationary fuel combustion emissions are 
set forth in proposed 40 CFR part 98, subpart C.
    Proposed requirements for landfill emissions are set forth in 
Section V.HH of this preamble. Data is unavailable on landfilling at 
ethanol facilities, but it is our understanding that some of these 
facilities may have landfills with significant CH4 
emissions. For more information on landfills at industrial facilities, 
please refer to the Ethanol Production TSD (EPA-HQ-OAR-2008-0508-010). 
EPA is seeking comment on available data sources for landfilling 
practices at ethanol production facilities.
    The wastewater generated at ethanol production facilities is 
handled in a variety of ways, with dry milling and wet milling 
facilities generally treating wastewaters differently. In 2006, 
CH4 emissions from wastewater treatment at ethanol 
production facilities were 68,200 metric tons CO2e. Proposed 
requirements for GHG emissions form wastewater treatment are set forth 
in Section V.II of this preamble. For more information on wastewater 
treatment at ethanol production facilities, please refer to the Ethanol 
Production TSD (EPA-HQ-OAR-2008-0508-010).
    As noted in Section IV.B of this preamble under the heading 
``Reporting by fuel and industrial gas suppliers'', ethanol producers 
and other suppliers of biomass-based fuel are not required to report 
GHG emissions from their products under this proposal, and we seek 
comment on this approach.
2. Selection of Reporting Threshold
    The proposed threshold for reporting emissions from ethanol 
production facilities is 25,000 metric tons CO2e total 
emissions from stationary fuel combustion, landfills, and onsite 
wastewater treatment. Table J-1 of this preamble illustrates the 
emissions and facilities that would be covered under various 
thresholds.

                                                  Table J-1. Threshold Analysis for Ethanol Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Emissions covered                   Facilities covered
           Threshold level                National emissions      Total number  ------------------------------------------------------------------------
                                                mtCO2e            of facilities         mtCO2e/year                Percent            Number    Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 mtCO2e.........................  Not estimated...........             140  Not estimated...........  Not estimated..........       >101        >72
10,000 mtCO2e........................  Not estimated...........             140  Not estimated...........  Not estimated..........        >94        >67
25,000 mtCO2e........................  Not estimated...........             140  Not estimated...........  Not estimated..........        >86        >61
100,000 mtCO2e.......................  Not estimated...........             140  Not estimated...........  Not estimated..........        >43        >31
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Data were unavailable to estimate emissions from landfills at 
ethanol refineries, or to estimate the combined wastewater treatment 
and stationary fuel combustion emissions at facilities. Data on 
stationary fuel combustion were used to estimate the minimum number of 
facilities that would meet each of the facility-level thresholds 
examined. The

[[Page 16501]]

25,000 metric tons CO2e threshold results in a reasonable 
number of reporters, and is consistent with thresholds for other source 
categories.
    For more information on this analysis, please refer to the Ethanol 
Production TSD (EPA-HQ-OAR-2008-0508-010). EPA is seeking comment on 
the analysis and on alternative data sources for stationary combustion 
at ethanol production facilities. For specific information on costs, 
including unamortized first year capital expenditures, please refer to 
section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
monitoring methods for general stationary fuel combustion sources, 
landfills, and wastewater treatment occurring on-site at ethanol 
production facilities.
4. Selection of Procedures for Estimating Missing Data
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
procedures for estimating missing data for general stationary fuel 
combustion sources, landfills, and industrial wastewater treatment 
occurring on-site at ethanol production facilities.
5. Selection of Data Reporting Requirements
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
reporting requirements for general stationary fuel combustion sources, 
landfills, and industrial wastewater treatment occurring on-site at 
ethanol production facilities. In addition, you would be required to 
report the quantity of CO2e captured for use (if applicable) 
and the end use, if known. For more information on reporting 
requirements for CO2e capture, please refer to Section V.PP 
of this preamble.
6. Selection of Records That Must Be Maintained
    Refer to Sections V.C, V.HH, and V.GG of this preamble for 
recordkeeping requirements for stationary fuel combustion, landfills, 
and industrial wastewater treatment occurring on-site at ethanol 
production facilities.

K. Ferroalloy Production

1. Definition of the Source Category
    A ferroalloy is an alloy of iron with at least one other metal such 
as chromium, silicon, molybdenum, manganese, or titanium. For this 
proposed rule, we are defining the ferroalloy production source 
category to consist 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. Ferroalloys are used extensively in the iron and steel 
industry to impart distinctive qualities to stainless and other 
specialty steels, and serve important functions during iron and steel 
production cycles. Silicon metal is included in the ferroalloy metals 
category due to the similarities between its production process and 
that of ferrosilicon. Silicon metal is used in alloys of aluminum and 
in the chemical industry as a raw material in silicon-based chemical 
manufacturing.
    The basic process used at U.S. ferroalloy production facilities is 
a batch process in which a measured mixture of metals, carbonaceous 
reducing agents, and slag forming materials are melted and reduced in 
an electric arc furnace. The carbonaceous reducing agents typically 
used are coke or coal. Molten alloy tapped from the electric arc 
furnace is casted into solid alloy slabs which are further mechanically 
processed for sale as product or disposed in landfills.
    Ferroalloy production results in both combustion and process-
related GHG emissions. The major source of GHG emissions from a 
ferroalloy production facility are the process-related emissions from 
the electric arc furnace operations. These emissions, which consist 
primarily of CO2e with smaller amounts of CH4, 
result from the reduction of the metallic oxides and the consumption of 
the graphite (carbon) electrodes during the batch process.
    Total nationwide GHG emissions from ferroalloy production 
facilities operating in the U.S. were estimated to be approximately 2.3 
million metric tons CO2e for the year 2006. Process-related 
GHG emissions were 2.0 million metric tons CO2e (86 percent 
of the total emissions). The remaining 0.3 million metric tons 
CO2e (14 percent of the total emissions) were combustion GHG 
emissions.
    Additional background information about GHG emissions from the 
ferroalloy production source category is available in the Ferroalloy 
Production TSD (EPA-HQ-OAR-2008-0508-011).
2. Selection of Reporting Threshold
    Ferroalloy production facilities in the U.S. vary in the specific 
types of alloy products produced. In developing the threshold for 
ferroalloy production facilities, we considered using annual GHG 
emissions-based threshold levels of 1,000 metric tons CO2e, 
10,000 metric tons CO2e, 25,000 metric tons CO2e 
and 100,000 metric tons CO2e. Table K-1 of this preamble 
presents the estimated emissions and number of facilities that would be 
subject to GHG emissions reporting, based upon emission estimates using 
production capacity data for the nine U.S. facilities that produce 
either ferrosilicon, silicon metal, ferrochromium, ferromanganese, or 
silicomanganese alloys. We were unable to obtain production data for an 
estimated five additional facilities that produce ferromolybdenum and 
ferrotitanium alloys.

                                           Table K-1. Threshold Analysis for Ferroalloy Production Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                             Total national                         Emissions covered             Facilities covered
                                                                emissions     Total number  ------------------------------------------------------------
           Threshold level (metric tons CO2e/yr)              (metric tons    of facilities    Metric tons
                                                                CO2e/yr)                         CO2e/yr         Percent         Number        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000......................................................       2,343,990               9       2,343,990             100               9          100
10,000.....................................................       2,343,990               9       2,343,990             100               9          100
25,000.....................................................       2,343,990               9       2,343,990             100               9          100
100,000....................................................       2,343,990               9       2,276,639              97               8           89
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Table K-1 of this preamble shows that all nine of the facilities 
would be required to report emissions at all thresholds except 100,000 
metric tons CO2e, when considering combustion and process-
related emissions. The rule could be simplified for these facilities by 
making the rule applicable to all ferroalloy production facilities.

[[Page 16502]]

However, because the threshold analysis did not include all of the 
facilities in the ferroalloy source category that potentially could be 
subject to the rule, we have decided that it is appropriate to include 
a reporting threshold level. The proposed threshold selected for 
reporting emissions from ferroalloy production facilities is 25,000 
metric tons CO2e per year consistent with the threshold 
level being proposed for other source categories. This threshold level 
would avoid placing a reporting burden on any small specialty 
ferroalloy production facility which may operate as a small business 
while still requiring the reporting of GHG emissions from the 
ferroalloy production facilities releasing most of the GHG emissions in 
the source category. A full discussion of the threshold selection 
analysis is available in the Ferroalloy Production TSD (EPA-HQ-OAR-
2008-0508-011). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    We reviewed 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. In general, the methodologies 
used for estimating process related GHG emissions at the facility level 
coalesce around the following four options.
    Option 1. Apply a default emission factor to ferroalloy production. 
This is a simplified emission calculation method using only default 
emission factors to estimate process-related CO2 and 
CH4 emissions. The method requires multiplying the amount of 
each ferroalloy product type produced by the appropriate default 
emission factors from the 2006 IPCC Guidelines.
    Option 2. Perform a monthly carbon balance using measurements of 
the carbon content of specific process inputs and process outputs and 
the amounts of these materials consumed or produced during a specified 
reporting period. This option is applicable to estimating only 
CO2 emissions from an electric arc furnace, and is the IPCC 
Tier 3 approach and the higher order methods in the Canadian and 
Australian reporting programs. Implementation of this method requires 
you to determine the carbon contents of carbonaceous material inputs to 
and outputs from the electric arc furnaces. Facilities determine carbon 
contents through analysis of representative samples of the material or 
from information provided by the material suppliers. In addition, the 
quantities of these materials consumed and produced during production 
would be measured and recorded. To obtain the CO2 emissions 
estimate, the average carbon content of each input and output material 
is multiplied by the corresponding mass consumed and a conversion of 
carbon to CO2. The difference between the calculated total 
carbon input and the total carbon output is the estimated 
CO2 emissions to the atmosphere. This method assumes that 
all of the carbon is converted during the process. For estimating the 
CH4 emissions from the electric arc furnace, selection of 
this option for estimating CO2 emissions would still require 
using the Option 1 approach of applying default emission factors to 
estimate CH4 emissions.
    Option 3. Use CO2 emissions data from a stack test 
performed using U.S. EPA test methods to develop a site-specific 
process emissions factor which is then applied to quantity measurement 
data of feed material or product for the specified reporting period. 
This monitoring method is applicable to electric arc furnace 
configurations for which the GHG emissions are contained within a stack 
or vent. Using site-specific emissions factors based on short-term 
stack testing is appropriate for those facilities where process inputs 
(e.g., feed materials, carbonaceous reducing agents) and process 
operating parameters remain relatively consistent over time.
    Option 4. Use direct emission testing of CO2 emissions. 
For electric arc furnace configurations in which the process off-gases 
are contained within a stack or vent, direct measurement of the 
CO2 emissions can be made by continuously measuring the off-
gas stream CO2 concentration and flow rate using a CEMS. 
Using a CEMS, the total CO2 emissions tabulated from the 
recorded emissions measurement data would be reported annually. If a 
ferroalloy production facility uses an open or semi-open electric arc 
furnace for which the CO2 emissions are not fully captured 
and contained within a stack or vent (i.e., a significant portion of 
the CO2 emissions escape capture by the hood and are release 
directly to the atmosphere), then another GHG emission estimation 
method other than direct measurement would be more appropriate.
    Proposed Option. Under the proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C, to 
estimate CO2 emissions from the industrial source. Also, 
refer to proposed 40 CFR part 98, subpart C to estimate combustion-
related CH4 and N2O.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
CEMS would not adequately account for process emissions, the proposed 
monitoring method is Option 2. You would be required to follow the 
requirements of proposed 40 CFR part 98, subpart C to estimate 
emissions of CO2, CH4 and N2O from 
stationary combustion. This section of the preamble provides procedures 
only for calculating and reporting process-related emissions.
    Given the variability of the alloy products produced and 
carbonaceous reducing agents used at U.S. ferroalloy production 
facilities, we concluded that using facility-specific information under 
Option 2 is preferred for estimating CO2 emissions from 
electric arc furnaces. This method is consistent with IPCC Tier 3 
methods and the preferred approaches for estimating emissions in the 
Canadian and Australian mandatory reporting programs. We consider the 
additional burden of the material measurements required for the carbon 
balance small in relation to the increased accuracy expected from using 
this site-specific information to calculate CO2 emissions.
    Emissions data collected under Option 3 would have the lowest 
uncertainty, expected to be less than 5 percent. For Option 2, the 
material-specific emission factors would be expected to be within 10 
percent, which would provide less uncertainty overall than for Option 
1, which may have uncertainty of 25 to 50 percent. The use of the 
default CO2 emission factors under Option 1 would be more 
appropriate for GHG estimates from aggregated process information on a 
sector-wide or nationwide basis than for determining GHG emissions from 
specific facilities.
    In comparison to the CO2 emissions levels from an 
electric arc furnace, the CH4 emissions compose a small 
fraction of the total GHG emissions from electric arc furnace 
operations at a ferroalloy production facility. The proposed Option 2 
above doesn't account for CH4. Considering the amount that 
CH4 emissions contribute to the total GHG emissions and the 
absence of facility-specific methods in other reporting systems, we are 
proposing that facilities

[[Page 16503]]

use Option 1 and the IPCC default emission factors to estimate 
CH4 emissions from electric arc furnaces at ferroalloy 
production facilities. This method provides reasonable estimates of the 
magnitude of the CH4 emissions from the units without the 
need for owners or operator to conduct on-site CH4 emissions 
measurements.
    We also decided against Option 3 because of the potential for 
significant variations at ferroalloy production facilities in the 
characteristics and quantities of the electric arc furnace inputs 
(e.g., metal ores, carbonaceous reducing agents) and process operating 
parameters. A method using periodic, short-term stack testing would not 
be practical or appropriate for those ferroalloy production facilities 
where the electric arc furnace inputs and operating parameters do not 
remain relatively consistent over the reporting period.
    The various approaches to monitoring GHG emissions are elaborated 
in the Ferroalloy Production TSD (EPA-HQ-OAR-2008-0508-011).
4. Selection of Procedures for Estimating Missing Data
    In cases when an owner or operator calculates CO2 and 
CH4 emissions using a carbon balance or an emission factor, 
the proposed rule would require the use of substitute data whenever a 
quality-assured value of a parameter that is used to calculate GHG 
emissions is unavailable, or ``missing.'' If the carbon content 
analysis of carbon inputs or outputs is missing or lost, the substitute 
data value would be the average of the quality-assured values of the 
parameter immediately before and immediately after the missing data 
period. The likelihood for missing process input and output data is 
low, as businesses closely track their purchase of production inputs. 
In those cases when an owner or operator uses direct measurement by a 
CO2 CEMS, the missing data procedures would be the same as 
the Tier 4 requirements described for general stationary combustion 
sources in Section V.C of this preamble.
5. Selection of Data Reporting Requirements
    The proposed rule would require reporting of the total annual 
CO2 and CH4 emissions for each electric arc 
furnace at a ferroalloy production facility, as well as any stationary 
fuel combustion emissions. In addition we propose that additional 
information which forms the basis of the emissions estimates also be 
reported so that we can understand and verify the reported emissions. 
This additional information includes the total number of electric arc 
furnaces operated at the facility, the facility ferroalloy product 
production capacity, the annual facility production quantity for each 
ferroalloy product, the number of facility operating hours in calendar 
year, and quantities of carbon inputs and outputs if applicable. A 
complete list of data to be reported is included in the proposed 40 CFR 
part 98, subparts A and K.
6. Selection of Records That Must Be Retained
    Maintaining records of the information used to determine the 
reported GHG emissions are necessary to enable us to verify that the 
GHG emissions monitoring and calculations were done correctly. We 
propose that all affected facilities maintain records of product 
production quantities, and number of facility operating hours each 
month. If you use the carbon balance procedure, you would record for 
each carbon-containing input material consumed or used and output 
material produced the monthly material quantity, monthly average carbon 
content determined for material, and records of the supplier provided 
information or analyses used for the determination. If you use the CEMS 
procedure, you would maintain the CEMS measurement records.

L. Fluorinated GHG Production

1. Definition of the Source Category
    This source category covers emissions of fluorinated GHGs that 
occur during the production of HFCs, PFCs, SF6, 
NF3, and other fluorinated GHGs such as fluorinated ethers. 
Specifically, it covers emissions that are never counted as ``mass 
produced'' under the proposed requirements for suppliers of industrial 
GHGs discussed in Section OO of this preamble. These emissions include 
fluorinated GHG products that are emitted upstream of the production 
measurement and fluorinated GHG byproducts that are generated and 
emitted either without or despite recapture or destruction.\71\ These 
emissions exclude generation and emissions of HFC-23 during the 
production of HCFC-22, which are discussed in Section O of this 
preamble.
---------------------------------------------------------------------------

    \71\ Byproducts that are emitted or destroyed at the production 
facility are excluded from the proposed definition of ``produce a 
fluorinated GHG.'' Any HFC-23 generated during the production of 
HCFC-22 is also excluded from this definition, even if the HFC-23 is 
recaptured. However, other fluorinated GHG byproducts that are 
recaptured for any reason would be considered to be ``produced.''
---------------------------------------------------------------------------

    Emissions can occur from leaks at flanges and connections in the 
production line, during separation of byproducts and products, during 
occasional service work on the production equipment, and during the 
filling of tanks or other containers that are distributed by the 
producer (e.g., on trucks and railcars). Fluorinated GHG emissions from 
U.S. facilities producing fluorinated GHGs are estimated to range from 
0.8 percent to 2 percent of the amount of fluorinated GHGs produced, 
depending on the facility.
    In 2006, 12 U.S. facilities produced over 350 million metric tons 
CO2e of HFCs, PFCs, SF6, and NF3. 
These facilities are estimated to have emitted approximately 5.3 
million metric tons CO2e of HFCs, PFCs, SF6, and 
NF3, based on an emission rate of 1.5 percent. We estimate 
that an additional 6 facilities produced approximately 1 million metric 
tons CO2e of fluorinated anesthetics. At an emission rate of 
1.5 percent, these facilities would emit approximately 15,000 metric 
tons CO2e of these anesthetics.
    The production of fluorinated gases causes both combustion and 
fluorinated GHG emissions. Fluorinated GHG production facilities would 
be required to follow the requirements of proposed 40 CFR part 98, 
subpart C to estimate emissions of CO2, CH4 and 
N2O from stationary fuel combustion. In addition, these 
facilities would be required to report their production of industrial 
GHGs under proposed 40 CFR part 98, subpart OO. This section of the 
preamble discusses only the procedures for calculating and reporting 
emissions of fluorinated GHGs.
2. Selection of Reporting Threshold
    We propose that owners and operators of facilities estimate and 
report fluorinated GHG and combustion emissions if those emissions 
together exceed 25,000 metric tons CO2e.
    In developing the threshold, we considered emissions thresholds of 
1,000 metric tons CO2e, 10,000 metric tons CO2e, 
25,000 metric tons CO2e and 100,000 metric tons 
CO2e and their capacity equivalents. Facility-specific 
emissions were estimated by multiplying an emission factor of 1.5 
percent by the estimated production at each facility. The capacity 
thresholds were developed based on emissions of fluorinated GHGs, 
assuming full capacity utilization and an emission rate of 2 percent of 
production. Because EPA had little information on combustion-related 
emissions at fluorinated GHG production facilities, these emissions 
were not incorporated into the capacity thresholds or the threshold 
analysis. Table L-1 of this preamble illustrates the HFC, PFC, 
SF6, and NF3 emissions

[[Page 16504]]

and facilities that would be covered under these various thresholds.

                         Table L-1. Threshold Analysis for Fluorinated GHG Emissions From Production of HFCs, PFCs, SF6, and NF3
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Total                             Emissions covered              Facilities covered
                                                             national                    ---------------------------------------------------------------
          Threshold level (metric tons CO2e/r)               emissions       Number of
                                                           (metric tons     facilities      Metric tons       Percent         Number          Percent
                                                               CO2e)                           CO2e
--------------------------------------------------------------------------------------------------------------------------------------------------------
Emission-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................       5,300,000              12       5,300,000             100              12             100
10,000..................................................       5,300,000              12       5,300,000             100              12             100
25,000..................................................       5,300,000              12       5,300,000             100              12             100
100,000.................................................       5,300,000              12       5,100,000              97               9              75
--------------------------------------------------------------------------------------------------------------------------------------------------------
Production Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
50,000..................................................       5,300,000              12       5,300,000             100              12             100
500,000.................................................       5,300,000              12       5,300,000             100              12             100
1,250,000...............................................       5,300,000              12       5,300,000             100              12             100
5,000,000...............................................       5,300,000              12       5,200,000              98              10              83
--------------------------------------------------------------------------------------------------------------------------------------------------------

    As can be seen from the tables, most HFC, PFC, SF6, and 
NF3 production facilities would be covered by all emission- 
and capacity-based thresholds. Although we do not have facility-
specific production information for producers of fluorinated 
anesthetics, we believe that few or none of these facilities are likely 
to have emissions above the proposed threshold.
    EPA requests comment on whether it should adopt a capacity-based 
threshold for this sector, and if so, what fluorinated GHG and 
combustion-related emission rates should be used to develop this 
threshold. Where EPA has reasonably good information on the 
relationship between production capacity and emissions, and where this 
relationship does not vary excessively from facility to facility, EPA 
is generally proposing capacity-based thresholds to make it easy for 
facilities to determine whether or not they must report. In this case, 
however, EPA has little data on combustion emissions and their likely 
magnitude compared to fluorinated GHG emissions from this source.
    As noted above, the capacity thresholds in Table L-1 of this 
preamble were developed based on a fluorinated GHG emission rate of 2 
percent of production. While EPA believes that this emission rate is an 
upper-bound for fluorinated GHGs, neither the rate nor the thresholds 
account for combustion-related emissions. Thus, it is possible that the 
production capacities listed in Table L-1 of this preamble are 
inappropriately high.
    In the event that a capacity-based threshold were adopted, 
facilities would be required to multiply the production capacity of 
each production line by the GWP of the fluorinated GHG produced on that 
line. Facilities would then be required to sum the resulting 
CO2e capacities across all lines. Where more than one 
fluorinated GHG could be produced by a production line, yielding more 
than one possible production capacity for that line in CO2e 
terms, facilities would be required to use the highest possible 
production capacity (in CO2e terms) in their threshold 
calculations.
    A full discussion of the threshold selection analysis is available 
in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    In developing this proposed rule, we reviewed a number of protocols 
for estimating fluorinated GHG emissions from fluorocarbon production, 
such as the 2006 IPCC Guidelines. In general, these protocols present 
three methods. In the first approach, a default emission factor is 
applied to the total production of the plant. In the second approach, 
fluorinated GHG emissions are equated to the difference between the 
mass of reactants fed into the process and the sum of the masses of the 
main product and those of any by-products and/or wastes. In the third 
approach, the composition and mass flow rate of the gas streams 
actually vented to the atmosphere are monitored either continuously or 
during a period long enough to establish an emission factor.
    If you produce fluorinated GHGs, we are proposing that you monitor 
fluorinated GHG emissions using the second approach, known as the mass-
balance or yield approach. There are two variants of the mass-balance 
approach. In the first variant, only some of the reactants and 
products, including the fluorinated GHG product, are considered. In the 
second variant, all of the reactants, products, and by-products are 
considered. Both variants are discussed in more detail in the 
Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).
    We are proposing that you monitor emissions using the first 
variant. In this approach, you would calculate the difference between 
the expected production of each fluorinated GHG based on the 
consumption of reactants and the measured production of that 
fluorinated GHG, accounting for yield losses related to byproducts 
(including intermediates permanently removed from the process) and 
wastes. Yield losses that could not be accounted for would be 
attributed to emissions of the fluorinated GHG product. This 
calculation would be performed for each reactant, and estimated 
emissions of the fluorinated GHG product would be equated to the 
average of the results obtained for each reactant. If fluorinated GHG 
byproducts were produced and were not completely recaptured or 
completely destroyed, you would also estimate emissions of each 
fluorinated GHG byproduct.
    To carry out this approach, you would daily weigh or meter each 
reactant fed into the process, the primary fluorinated GHG produced by 
the process, any reactants permanently removed from the

[[Page 16505]]

process (i.e., sent to the thermal oxidizer or other equipment, not 
immediately recycled back into the process), any byproducts generated, 
and any streams that contain the product or byproducts and that are 
recaptured or destroyed. For these measurements you would be required 
to use scales and/or flowmeters with an accuracy and precision of 0.2 
percent of full scale. If monitored process streams included more than 
one component (product, byproducts, or other materials) in more than 
trace concentrations,\72\ you would be required to monitor 
concentrations of products and byproducts in these streams at least 
daily 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. Finally, you would be required to perform daily 
mass balance calculations for each product produced.
---------------------------------------------------------------------------

    \72\ EPA is proposing to define ``trace concentration'' as any 
concentration less than 0.1 percent by mass of the process stream.
---------------------------------------------------------------------------

    In general, we understand that production facilities already 
perform these measurements and calculations to the proposed level of 
accuracy and precision in order to monitor their processes and yields. 
However, we request comment on this issue. We specifically request 
comment on the proposed scope and frequency of process stream 
concentration measurements. As noted above, concentration measurements 
would be triggered when products or byproducts occur in more than trace 
concentrations with other components in process streams (which include 
waste streams). However, it is possible that products or byproducts 
could occur in more than trace concentrations but still result in 
negligible yield losses (e.g., less than 0.2 percent). In this case, 
ignoring these losses may not significantly affect the accuracy of the 
overall GHG emission estimate. (This issue is discussed in more detail 
in the Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).) 
Similarly, decreasing the frequency of stream sampling may not have a 
significant impact on accuracy or precision if previous monitoring has 
shown that the concentrations of products and byproducts in process 
streams are stable or vary in a predictable and quantifiable way (e.g., 
seasonally due to differences in condenser cooling water temperature).
    EPA recognizes that the proposed mass-balance approach would assume 
that all yield losses that are not accounted for are attributable to 
emissions of the fluorinated GHG product. In some cases, the losses may 
be untracked emissions or other losses of reactants or fluorinated by-
products. In general, EPA understands that reactant flows are measured 
at the inlet to the reactor; thus, any losses of reactant that occur 
between the point of measurement and the reactor are likely to be 
small. However, reactants that are recovered from the process, whether 
they are recycled back into it or removed permanently, may experience 
some losses that the proposed method does not account for. EPA requests 
comment on the extent to which such losses occur, and how these might 
be measured.
    Fluorocarbon by-products, according to the IPCC Guidelines, 
generally have ``radiative forcing properties similar to those of the 
desired fluorochemical.'' If this is always the case (with the 
exception of HFC-23 generated during production of HCFC-22, which is 
addressed in Section V.O of this preamble), then assuming by-product 
emissions are product emissions would not lead to large errors in 
estimating overall fluorinated GHG emissions. If the GWPs of emitted 
fluorinated by-products are sometimes significantly different from 
those of the fluorinated GHG product, and if the quantity of by-product 
emitted can be estimated (e.g., based on periodic or past sampling of 
process streams), then the quantity of emitted product could be 
adjusted to reflect this. EPA requests comment on whether it is 
necessary or practical to distinguish between emissions of fluorinated 
GHG products and emissions of fluorinated by-products, and if so, on 
the best approach for doing so.
    We also request comment on the proposed accuracy and precision 
requirements for flowmeters and scales. If a waste or by-product stream 
is significantly smaller than the reactant and product streams, a less 
precise measurement of this stream (e.g., 0.5 percent) may not have a 
large impact on the precision of the fluorinated GHG emission estimate 
and may therefore be acceptable. Similarly, if a measurement is 
repeated multiple times over the course of the reporting period, the 
precision of individual measurements could be relaxed without seriously 
compromising the precision of the monthly or annual estimates. One way 
of adding flexibility to the precision requirements would be to require 
that the error of the fluorinated GHG emissions estimate be no greater 
than some fraction of the yield, e.g., 0.3 percent, on a monthly basis. 
Facilities could achieve this level of precision however they chose. We 
request comment on this issue and on the accuracy, precision, and cost 
of the proposed approach as a whole.
    Analysis of Alternative Methods. EPA is not proposing the approach 
using the default emission factor. While this approach is simple, it is 
also highly imprecise; emissions in U.S. plants are estimated to vary 
from 0.8 percent to 2 percent of production, more than a factor of 
two.\73\ Thus, applying a default factor (1.5 percent, for example) is 
likely to significantly overestimate emissions at some plants while 
significantly underestimating them at others.
---------------------------------------------------------------------------

    \73\ Fluorinated GHG Production TSD (EPA-HQ-OAR-2008-0508-012).
---------------------------------------------------------------------------

    EPA is not proposing the second variant of the mass-balance 
approach. This variant is implemented by comparing the total mass of 
reactants to the total mass of monitored products and byproducts, 
without regard for chemical identity. The drawbacks of this variant are 
that it is not the method currently used by facilities to track their 
production, and it would count losses of non-GHG products (e.g., HCl) 
as GHG emissions. EPA requests comment on this understanding and on the 
potential usefulness and accuracy of the second variant of the mass-
balance approach for estimating fluorinated GHG emissions.
    EPA is not proposing the third approach because it is our 
understanding that facilities do not routinely monitor their process 
vents, and therefore such monitoring is likely to be more expensive 
than the proposed mass-balance approach. However, the cost of 
monitoring may not be prohibitive, particularly if it is performed for 
a relatively short period of time for the purpose of developing an 
emission factor, similar to the approach for estimating smelter-
specific slope coefficients for aluminum production.\74\ Moreover, if 
the vent monitoring approach reduces the uncertainty of the emissions 
measurement by even 10 percent relative to the mass-balance approach, 
this would reduce the absolute uncertainty at the typical production 
facility by 40,000 metric tons CO2e. (The extent to which 
uncertainty would be reduced would depend in part on the sensitivity 
and

[[Page 16506]]

precision of the vent concentration measurements.)
---------------------------------------------------------------------------

    \74\ Conversations with representatives of fluorocarbon 
producers indicate that robust emission factors could often be 
developed by monitoring emissions (and a related parameter, such as 
production) for one month under representative operating conditions. 
Where emissions vary seasonally (e.g., due to changes in condenser 
cooling water temperature), two separate monitoring periods of one 
month each would often suffice. However, the length and frequency of 
monitoring would depend on the variability of the process.
---------------------------------------------------------------------------

    For completeness, monitoring of process vents would need to be 
supplemented by monitoring of equipment leaks, whose emissions would 
not occur through process vents. To capture emissions from equipment 
leaks, we could require use of EPA Method 21 and the Protocol for 
Equipment Leak Estimates (EPA-453/R-95-017). The Protocol includes four 
methods for estimating equipment leaks. These are, from least to most 
accurate, the Average Emission Factor Approach, the Screening Ranges 
Approach, EPA Correlation Approach, and the Unit-Specific Correlation 
Approach. Most recent EPA leak detection and repair regulations require 
use of one of the Correlation Approaches in the Protocol. To use any 
approach other than the Average Emission Factor Approach, you would 
need to have (or develop) Response Factors relating concentrations of 
the target fluorinated GHG to concentrations of the gas with which the 
leak detector was calibrated. We understand that at least two 
fluorocarbon producers currently use methods in the Protocol to 
quantify their emissions of fluorinated GHGs with different levels of 
accuracy and precision.\75\
---------------------------------------------------------------------------

    \75\ One producer estimates HFC and other fluorocarbon emissions 
by using the Average Emission Factor Approach. This approach simply 
assigns an average emission factor to each component without any 
evaluation of whether or how much that component is actually 
leaking. The second producer estimates emissions using the Screening 
Ranges Approach, which assigns different emission factors to 
components based on whether the concentrations of the target 
chemical are above or below 10,000 ppmv. This producer has developed 
a Response Factor for HCFC-22, which is present in the same streams 
as the HFC-23 whose leaks are being estimated. (HFC-23 emissions are 
discussed in Section O of this preamble.)
---------------------------------------------------------------------------

    We request comment on the accuracies and costs of the approaches in 
the Protocol as they would be applied to fluorinated GHG production. We 
also request comment on the significance of equipment leaks compared to 
process vents as a source of fluorinated GHG emissions.
    In addition, we request comment on whether we should require the 
vent monitoring approach, what sensitivity and precision would be 
appropriate for the vent concentration measurements, and on the 
increase in cost and improvements in accuracy and precision that would 
be associated with this approach relative to the proposed approach.
    Emissions from Evacuation of Returned Containers. We request 
comment on whether you should be required to measure and report 
fluorinated GHG emissions associated with the evacuation of cylinders 
or other containers that are returned to the facility containing either 
residual GHGs (heels) or GHGs that would be reclaimed or destroyed. We 
are not proposing to require reporting of these emissions because they 
are not associated with new production; instead, they are downstream 
emissions associated with earlier production.\76\ Requiring reporting 
of these emissions could therefore lead to double-counting.\77\
---------------------------------------------------------------------------

    \76\ Emissions from the filling or refilling of containers with 
new product may or may not be covered by proposed 40 CFR part 98, 
subpart L, depending on where production is measured. If production 
is measured upstream of filling, then the emissions would not be 
covered by proposed 40 CFR part 98, subpart L. If production is 
measured downstream of filling, then the emissions would be covered 
by subpart L.
    \77\ However, this double-counting could be avoided if the 
emissions from returned cylinders were clearly distinguished from 
other production facility emissions in the emissions report.
---------------------------------------------------------------------------

    Nevertheless, according to the 2006 IPCC Guidelines, the overall 
emission rate of a production facility can increase by nearly an order 
of magnitude (up to 8 percent) if the residual GHG remaining in the 
cylinders is vented to the atmosphere. One method of tracking such 
emissions would be to subtract the quantities of GHG reclaimed 
(purified) and sold or otherwise sent back to users from the quantities 
of residual and used GHGs returned to the facility in cylinders by 
users. This approach would be similar to the mass-balance approach 
proposed for estimating SF6 emissions from users and 
manufacturers of electrical equipment.
    Emissions of Fluorinated GHGs Associated with Production of ODS. We 
request comment on whether you should be required to report emissions 
of fluorinated GHGs associated with production of ODS (other than 
emissions of HFC-23 associated with production of HCFC-22, which are 
discussed in Section O of this preamble). These emissions would be by-
product emissions, for example of HFCs, since the definition of 
fluorinated GHGs excludes ODS. We specifically request comment on the 
likely magnitude of these emissions, both in absolute terms and 
relative to fluorinated GHG emissions from fluorinated GHG production. 
We believe that these emissions may occur due to the chemical 
similarities between HFCs, HCFCs, and CFCs and the common use of 
halogen replacement chemistry to produce them. Although production of 
HCFCs and CFCs is limited under the regulations implementing Title VI 
of the CAA, production of these substances for use as feedstocks is 
permitted to continue indefinitely.
4. Selection of Procedures for Estimating Missing Data
    In the event that a scale or flowmeter normally used to measure 
reactants, products, by-products, or wastes fails to meet an accuracy 
or precision test, malfunctions, or is rendered inoperable, we are 
proposing that facilities be required to estimate these quantities 
using other measurements where these data are available. For example, 
facilities that ordinarily measure production by metering the flow into 
the day tank could use the weight of product charged into shipping 
containers for sale and distribution as a substitute. It is our 
understanding that the types of flowmeters and scales used to measure 
fluorocarbon production (e.g., Coriolis meters) are generally quite 
reliable, and therefore that it should rarely be necessary to rely 
solely on secondary production measurements. In general, production 
facilities rely on accurate monitoring and reporting of the inputs and 
outputs of the production process.
    If concentration measurements are unavailable for some period, we 
are proposing that the facility use the average of the concentration 
measurements from just before and just after the period of missing 
data.
    There is one proposed exception to these requirements: If either 
method would result in a significant under- or overestimate of the 
missing parameter, then the facility would be required to develop an 
alternative estimate of the parameter and explain why and how it 
developed that estimate.
    We request comment on these proposed methods for estimating missing 
data.
5. Selection of Data Reporting Requirements
    Under the proposed rule, owners and operators of facilities 
producing fluorinated GHGs would be required to report both their 
fluorinated GHG emissions and the quantities used to estimate them, 
including the masses of the reactants, products, by-products, and 
wastes, and, if applicable, the quantities of any product in the by-
products and/or wastes (if that product is emitted at the facility). We 
are proposing that owners and operators report annual totals of these 
quantities.
    Where fluorinated GHG production facilities have estimated missing 
data, you would be required to report the reason the data were missing, 
the length of time the data were missing, the method used to estimate 
the missing

[[Page 16507]]

data, and the estimates of those data. Where the missing data was 
estimated by a method other than one of those specified, the owner or 
operator would be required to report why the specified method would 
lead to a significant under- or overestimate of the parameter(s) and 
the rationale for the methods used to estimate the missing data.
    We propose that facilities report these data because the data are 
necessary to verify facilities' calculations of fluorinated GHG 
emissions. We request comment on these proposed reporting requirements.
6. Selection of Records That Must Be Retained
    Under the proposed rule, owners and operators of facilities 
producing fluorinated GHGs would be required to retain records 
documenting the data reported, including records of daily and monthly 
mass-balance calculations and calibration records for flowmeters, 
scales, and gas chromatographs. These records are necessary to verify 
that the GHG emissions monitoring and calculations were performed 
correctly.

M. Food Processing

1. Definition of the Source Category
    Food processing facilities prepare raw ingredients for consumption 
by animals or humans. Many facilities in the meat and poultry, and 
fruit, vegetable, and juice processing industries have on-site 
wastewater treatment. This can include the use of anaerobic and aerobic 
lagoons, screening, fat traps and dissolved air flotation. These 
facilities can also include onsite landfills for waste disposal. In 
2006, CH4 emissions from wastewater treatment at food 
processing facilities were 3.7 million metric tons CO2e, and 
CH4 emissions from onsite landfills were 7.2 million metric 
tons CO2e. Data are not available to estimate stationary 
fuel combustion-related GHG emissions at food processing facilities.
    Proposed requirements for stationary fuel combustion emissions are 
set forth in proposed 40 CFR part 98, subpart C.
    Wastewater GHG emissions are described and considered in Section 
V.II of this preamble. For more information on wastewater treatment at 
food processing facilities, please refer to the Food Processing TSD 
(EPA-HQ-OAR-2008-0508-013).
    Landfill GHG emissions are described and considered in Section V.HH 
of this preamble. For more information on landfills at food processing 
facilities, please refer to the Landfills TSD (EPA-HQ-OAR-2008-0508-
034).
    The sources of GHG emissions at food processing facilities that 
must be reported under the proposed rule are stationary fuel 
combustion, onsite landfills and onsite wastewater treatment.
2. Selection of Reporting Threshold
    We considered using annual GHG emissions-based threshold levels of 
1,000 metric tons CO2e, 10,000 metric tons CO2e, 
25,000 metric tons CO2e and 100,000 metric tons 
CO2e for food processing facilities. The proposed threshold 
for reporting emissions from food processing facilities is 25,000 
metric tons CO2e total emissions from combined stationary 
fuel combustion, on-site landfills, and on-site wastewater treatment. 
Table M-1 of this preamble illustrates the emissions and facilities 
that would be covered under these various thresholds.

                                              Table M-1. Threshold Analysis for Food Processing Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Emissions covered              Facilities covered
                                                                                         ---------------------------------------------------------------
                        Threshold                            National          Total        Metric tons
                                                                                             CO2e/year        Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 mtCO2e............................................              NE           5,719              NE              NE             802            14.0
10,000 mtCO2e...........................................              NE           5,719              NE              NE             170             3.0
25,000 mtCO2e...........................................              NE           5,719              NE              NE             100             1.7
100,000 mtCO2e..........................................              NE           5,719              NE              NE              10            0.2
--------------------------------------------------------------------------------------------------------------------------------------------------------
NE = Not Estimated.

    Data were unavailable at the time of this analysis to estimate 
stationary combustion emissions onsite, or the co-location of landfills 
and wastewater treatment at food processing faculties. Facility 
coverage based on onsite wastewater GHG emissions and landfill GHG 
emissions was estimated as described in the Wastewater Treatment TSD 
and Landfills TSD (EPA-HQ-OAR-2008-0508-035) and (EPA-HQ-OAR-2008-0508-
034). We estimate that at the 25,000 metric tons CO2e 
threshold, a small percentage of facilities are covered by this rule, 
resulting in potentially a large percentage of emissions data reporting 
from this significant emissions source but avoiding small facilities.
    For specific information on costs, including unamortized first year 
capital expenditures, please refer to section 4 of the RIA and the RIA 
cost appendix.
3. Selection of Proposed Monitoring Methods
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
monitoring methods for general stationary fuel combustion sources, 
landfills, and wastewater treatment, respectively, occurring on-site at 
food production facilities.
4. Selection of Procedures for Estimating Missing Data
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
procedures for estimating missing data for general stationary fuel 
combustion sources, landfills, and wastewater treatment, respectively, 
occurring on-site at food processing facilities.
5. Selection of Data Reporting Requirements
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
reporting requirements for general stationary fuel combustion, 
landfills, and wastewater treatment, respectively, occurring on-site at 
food processing facilities. In addition, you would be required to 
report the quantity of CO2 captured for use (if applicable) 
and the end use, if known.
6. Selection of Records That Must Be Maintained
    Refer to Sections V.C, V.HH, and V.II of this preamble for 
recordkeeping requirements for general stationary fuel combustion 
sources, landfills, and wastewater treatment, respectively, occurring 
on-site at food processing facilities.

N. Glass Production

1. Definition of the Source Category
    Glass is a common commercial item that is produced by melting a 
mixture of

[[Page 16508]]

minerals and other substances, then cooling the molten materials in a 
manner that prevents crystallization. Glass is typically classified as 
container glass, flat (or window) glass, or pressed and blown glass. 
Pressed and blown glass includes textile fiberglass, which is used 
primarily as a reinforcement material in a variety of products, as well 
as other types of glass. Wool fiberglass, which is commonly used for 
insulation, is generally classified separately from textile fiberglass 
and other pressed and blown glass. However, for the purposes of GHG 
reporting, wool fiberglass production is included in the glass 
manufacturing source category.
    Glass can be produced using a variety of raw material formulations. 
Most commercial glass is made using a soda-lime glass formulation, 
which consists of silica (SiO2), soda (Na2O), and 
lime (CaO), with small amounts of alumina 
(Al2O3), magnesia (MgO), and other minor 
ingredients. Several specialty glasses, including fiberglass, are made 
using borosilicate or aluminoborosilicate recipes, which can consist 
primarily of silica and boric oxides, along with varying amounts of 
soda, lime, alumina, and other minor ingredients. Other formulations 
used in the production of specialty glasses include aluminosilicate and 
lead silicate formulations.
    Major carbonates used in the production of glass are limestone 
(CaCO3), dolomite (CaMg(CO3)2), and 
soda ash (Na2CO3). The use of these carbonates in 
the furnace during glass manufacturing results in a complex high-
temperature reaction that leads to process-related GHG emissions. Glass 
manufacturers may also use recycled scrap glass (cullet) in the 
production of glass, thereby reducing the carbonate input to the 
process and resulting GHG emissions.
    National emissions from glass manufacturing were estimated to be 
4.43 million metric tons CO2e (0.1 percent of U.S. GHG 
emissions) in 2005. These emissions include both process-related 
emissions (CO2) and on-site stationary combustion emissions 
(CO2, CH4, and N2O) from 374 glass 
manufacturing facilities across the U.S. and Puerto Rico. Process-
related emissions account for 1.65 million metric tons CO2, 
or 37 percent of the total, while on-site stationary combustion sources 
account for the remaining 2.78 million metric tons CO2e 
emissions.
    For additional background information on glass manufacturing, refer 
to the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014).
2. Selection of Reporting Threshold
    In developing the threshold for glass manufacturing, we considered 
an emissions-based threshold of 1,000 metric tons CO2e, 
10,000 metric tons CO2e, 25,000 metric tons CO2e, 
and 100,000 metric tons CO2e. Table N-1 of this preamble 
summarizes the emissions and number of facilities that would be covered 
under these various thresholds.

                                                  Table N-1. Threshold Analysis for Glass Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
          Threshold level  metric tons CO2e/yr              metric tons    of facilities    Metric tons
                                                              CO2e/yr                         CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................       4,425,269             374       4,336,892              98             217              58
10,000..................................................       4,425,269             374       4,012,319              91             158              42
25,000..................................................       4,425,269             374       2,243,583              51              55              15
100,000.................................................       4,425,269             374         207,535               5               1             0.3
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The glass manufacturing industry is heterogeneous in terms of the 
types of facilities. There are some relatively large, emissions-
intensive facilities, but small artisan shops are common as well. For 
example, at a 1,000 metric tons CO2e threshold, 98 percent 
of emissions would be covered, with only 58 percent of facilities being 
required to report.
    The proposed threshold for reporting emissions from glass 
manufacturing is 25,000 metric tons CO2e. We are proposing a 
25,000 metric tons CO2e threshold to reduce the compliance 
burden on small businesses, while still including half of the GHG 
emissions from the industry. In comparison to the 100,000 metric tons 
CO2e threshold, the 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 number of reporters. We consider this 
a significant coverage of the emissions, while impacting a relatively 
small portion of the industry.
    For a full discussion of the threshold analysis, please refer to 
the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many of the domestic and international GHG monitoring guidelines 
and protocols include methodologies for estimating process-related 
CO2 emissions from glass manufacturing (e.g., the 2006 IPCC 
Guidelines, U.S. Inventory, the Technical Guidelines for the DOE 
1605(b), and the EU Emissions Trading System). These methodologies 
coalesce around four different options. Two options are output-based 
(production-based): One applies appropriate emission factors to the 
type of glass produced, and the other applies a default emission factor 
to total glass production. A third option is based on measuring the 
carbonate input to the furnace. The final option uses direct 
measurement to estimate emissions.
    Option 1. The first production-based option we considered applies a 
default emission factor to the total quantity of all glass produced, 
correcting for the amount of cullet supplied to the process.
    Option 2. The second production-based approach we considered 
applies default emission factors to each of the types of glass produced 
at the facility (e.g., container, flat, pressed and blown, and 
fiberglass).
    Option 3. The carbonate-input approach calculates emissions based 
on actual input data and the mass fractions of the carbonates that are 
volatilized and emitted as CO2. More specifically, this 
option considers the type, quantity, and mass fraction of carbonate 
inputs to the furnace and develops a facility-specific emission factor.
    Option 4. This approach directly measures emissions using a CEMS. 
CEMS can be used to measure both combustion-related and process-related 
CO2 emissions from glass melting

[[Page 16509]]

furnaces. These emissions generally are exhausted through a common 
furnace stack. Therefore, separate CEMS would not be needed to quantify 
both types of emissions from glass melting furnaces.
    Proposed Option. Under the proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions, you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C to 
estimate CO2 emissions from the industrial source.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
the CEMS would not adequately account for process emissions, the 
proposed monitoring method would require estimating combustion 
emissions and process emissions separately. For combustion emissions, 
you would be required to follow the requirements of proposed 40 CFR 
part 98, subpart C to estimate emissions of CO2, 
CH4 and N2O from stationary combustion. For 
process emissions, the carbonate input approach (Option 3) is proposed. 
This section of the preamble provides only those procedures for 
calculating and reporting process-related emissions.
    To estimate process CO2 emissions from glass melting 
furnaces, we propose that facilities measure the type, quantity, and 
mass fraction of carbonate inputs to each furnace and apply the 
appropriate emission factors for the carbonates consumed. This method 
for determining process emissions is consistent with the IPCC Tier 3 
method.
    The proposed rule distinguishes between carbonate-based minerals 
and carbonate-based raw materials used in glass production. Carbonate-
based raw materials are fired in the furnace during glass 
manufacturing. These raw materials are typically limestone, which is 
primarily CaCO3; dolomite, which is primarily 
CaMg(CO3)CO2; and soda ash, which is primarily 
NaCO2CO3. Because it is the calcination of the 
mineral fraction of the raw material (e.g., CaCO3 fraction 
in limestone) that leads to CO2 emissions, the purity of the 
limestone or other carbonate input is important for emissions 
estimation.
    In order to assess the composition of the carbonate input, we 
propose that facilities use data from the raw material supplier to 
determine the carbonate-based mineral mass fraction of the carbonate-
based raw materials charged to an affected glass melting furnace. As an 
alternative to using data provided by the supplier, facilities can 
assume a value of 1.0 for the mass fraction of the carbonate-based 
mineral in the carbonate-based raw material. We also propose that 
emissions are estimated under the assumption that 100 percent of the 
carbon in the carbonate-based raw materials is volatilized and released 
from the furnace as CO2. Using the carbonate-based mineral 
mass fractions, the carbonate-based raw material feed rates, and the 
emission factors, the mass emissions of CO2 emitted from a 
glass melting furnace can be determined.
    Using values of 1.0 for the carbonate-based mineral mass fractions 
is based on the assumption that the raw materials consist of 100 
percent of the respective carbonate-based mineral (i.e., the limestone 
charged to the furnace consists of 100 percent CaCO3, the 
dolomite charged consists of 100 percent 
CaMg(CO3)2, and the soda ash consists of 100 
percent Na3CO3). Using this assumption generally 
overestimates CO2 emissions. However, given the relative 
purity of the raw materials used to produce glass, this method provides 
accurate estimates of process CO2 emissions from glass 
melting furnaces, while avoiding the costs associated with sampling and 
analysis of the raw materials.
    We have concluded that the carbonate input method specified in the 
proposed option is more certain as it involves measuring the 
consumption of each carbonate material charged to a glass melting 
furnace. According to the 2006 IPCC Guidelines, the uncertainty 
involved in the proposed carbonate input approach is 1 to 3 percent; in 
contrast, the uncertainty with using the default emission factor and 
cullet ratio for the production-based approach is 60 percent.
    We considered use of a CO2 CEMS which does tend to 
provide the most accurate CO2 emissions measurements and can 
measure both the combustion- and process-related CO2 
emissions. However, given the limited variability in the process inputs 
and outputs contributing to emissions from glass production, 
installation of CEMS would require significant additional burden to 
facilities given that few glass facilities currently have 
CO2 CEMS.
    We also considered, but decided not to propose, the production-
based default emission factor-based approach referenced above for 
quantifying process-related CO2 emissions based on the 
quantity of glass produced. In general, the default emission factor 
method results in less certainty because the method involves 
multiplying production data by emission factors that are based on 
default assumptions regarding carbonate-based mineral content and 
degree of calcination.
    As part of normal business practices, glass manufacturing plants 
maintain the records that would be needed to calculate emissions under 
the proposed option. Given the greater accuracy associated with the 
input method and the minimal additional burden, we have determined that 
this requirement would not add additional burden to current practices 
at the facility, while providing accurate estimates of process-based 
CO2 emissions.
    The various approaches to monitoring GHG emissions are elaborated 
in the Glass Manufacturing TSD (EPA-HQ-OAR-2008-0508-014).
4. Selection of Procedures for Estimating Missing Data
    To estimate process emissions of CO2 based on carbonate 
input, data are needed on the carbonate chemical analysis of the 
carbonate-based raw materials and the carbonate-based raw material 
input rate (process feed rate). Glass manufacturing facilities must 
monitor raw material feed rate carefully in order to maintain product 
quality. Therefore, we do not expect missing data on raw material input 
to be an issue. However, if these data were missing, we propose 
requiring facilities to use average data from the previous and 
following months for the mass of carbonate-based raw materials charged 
to the furnace. Given that glass furnaces generally operate 
continuously at a relatively constant production rate, we do not expect 
much variation in the amounts of carbonates charged to the furnace from 
month to month. Furthermore, it would be unusual for a glass 
manufacturing plant to change its glass formulation. Therefore, we 
believe using average data from the previous and following months would 
provide a reliable estimate of raw materials charged.
    For missing data on carbonate-based mineral mass fractions, we 
propose requiring facilities to assume that the mass fraction of each 
carbonate-based mineral in the carbonate-based raw materials is 1.0. 
This assumption may result in a slight overestimate of emissions, but 
should still provide a reasonably accurate estimate of emissions for 
the period with missing data.
5. Selection of Data Reporting Requirements
    We propose that facilities report total annual emissions of 
CO2 from each affected continuous glass melting furnace, as 
well as any stationary fuel combustion emissions. The proposed

[[Page 16510]]

rule would also require facilities to report the quantity of each 
carbonate-based raw material charged to each continuous glass melting 
furnace in tons per year, and the quantity of glass produced by each 
continuous glass melting furnace. For facilities that calculate process 
emissions of CO2 based on the mass fractions of carbonate-
based minerals, the proposed rule would require facilities to report 
those values. These data are requested because they provide the basis 
for calculating process-based CO2 emissions and are needed 
for us to understand the emissions data and verify the reasonableness 
of the reported emissions. The data on raw material composition and 
charge rates are needed to verify process-based emissions of 
CO2. The data on glass production are needed to verify that 
the reported quantities of raw materials charged to continuous furnaces 
are reasonable. The production data also can be used to identify 
potential outliers.
    A full list of data to be reported is included in proposed 40 CFR 
part 98, subparts A and N.
6. Selection of Records That Must Be Retained
    In addition to the data to be reported, we propose that facilities 
retain monthly records of the data used to calculate GHG emissions. 
This would include records of the amounts of each carbonate-based raw 
material charged to a continuous glass melting furnace and glass 
production (by type). This requirement would be consistent with current 
business practices and the reporting requirements for emissions of 
other pollutants for the glass manufacturing industry.
    The proposed rule also would require facilities to retain the 
results of all tests used to determine carbonate-based mineral mass 
fractions, as well as any other supporting information used in the 
calculation of GHG emissions. These data are directly used to calculate 
emissions that are reported and are necessary to enable verification 
that the GHG emissions monitoring and calculations were performed 
correctly.
    A full list of records that must be retained on site is included in 
proposed 40 CFR part 98, subparts A and N.

O. HCFC-22 Production and HFC-23 Destruction

1. Definition of the Source Category
    This source category includes the generation, emissions, sales, and 
destruction of HFC-23. The source category includes facilities that 
produce HCFC-22, generating HFC-23 in the process. This source category 
also includes facilities that destroy HFC-23, which are sometimes, but 
not always, also facilities that produce HCFC-22.
    HFC-23 is generated during the production of HCFC-22. HCFC-22 is 
primarily employed in refrigeration and A/C systems and as a chemical 
feedstock for manufacturing synthetic polymers. Because HCFC-22 
depletes stratospheric O3, its production for non-feedstock 
uses is scheduled to be phased out by 2020 under the CAA. Feedstock 
production, however, is permitted to continue indefinitely.
    HCFC-22 is produced by the reaction of chloroform 
(CHCl3) and hydrogen fluoride (HF) in the presence of a 
catalyst, SbClB5. In the reaction, the chlorine in the 
chloroform is replaced with fluorine, creating HCFC-22. Some of the 
HCFC-22 is over-fluorinated, producing HFC-23. Once separated from the 
HCFC-22, the HFC-23 may be vented to the atmosphere as an unwanted by-
product, captured for use in a limited number of applications, or 
destroyed.
    2006 U.S. emissions of HFC-23 from HCFC-22 production were 
estimated to be 13.8 million metric tons CO2e. This quantity 
represents a 13 percent decline from 2005 emissions and a 62 percent 
decline from 1990 emissions despite an 11 percent increase in HCFC-22 
production since 1990. Both declines are primarily due to decreases in 
the HFC-23 emission rate. The ratio of HFC-23 emissions to HCFC-22 
production has decreased from 0.022 to 0.0077 since 1990, a reduction 
of 66 percent. These decreases have occurred because an increasing 
fraction of U.S. HCFC-22 production capacity has adopted controls to 
reduce HFC-23 emissions. Three HCFC-22 production facilities operated 
in the U.S. in 2006, two of which used recapture and/or thermal 
oxidation to significantly lower their HFC-23 emissions. All three 
plants are part of a voluntary agreement to report and reduce their 
collective HFC-23 emissions.
    The production of HCFC-22 and destruction of HFC-23 causes both 
combustion and HFC-23 emissions. HCFC-22 production and HFC-23 
destruction facilities are required to follow the requirements of 
proposed 40 CFR part 98, subpart C to estimate emissions of 
CO2, CH4 and N2O from stationary fuel 
combustion. This section of the preamble provides only those procedures 
for calculating and reporting generation, emissions, sales, and 
destruction of HFC-23.
    For additional background information on HCFC-22 production, please 
refer to the HCFC-22 Production and HFC-23 Destruction TSD (EPA-HQ-OAR-
2008-0508-015).
2. Selection of Reporting Threshold
    We propose that all facilities producing HCFC-22 be required to 
report under this rule. Facilities destroying HFC-23 but not producing 
HCFC-22 would be required to report if they destroyed more than 25,000 
metric tons CO2e of HFC-23.
    For HCFC-22 production facilities, 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 and capacity-based thresholds equivalent to these. 
The capacity-based thresholds are shown in Table O-1 of this preamble, 
and are based on full utilization of HCFC-22 capacity and the emission 
rate given for older plants in the 2006 IPCC Guidelines. (One plant is 
relatively new, but the emission rate for older plants was used to be 
consistent and somewhat conservative.)

                                                          Table O-1. Capacity-Based Thresholds
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions    Total national ---------------------------------------------------------------
       Threshold level (HCFC-22 capacity in tons)          (metric tons     facilities      Metric tons
                                                               CO2e)                          CO2e/yr         Percent       Facilities        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
2.......................................................      13,848,483               3      13,848,483             100               3             100
21......................................................      13,848,483               3      13,848,483             100               3             100
53......................................................      13,848,483               3      13,848,483             100               3             100
214.....................................................      13,848,483               3      13,848,483             100               3             100
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 16511]]

    Our analysis showed that all of the facilities, which have 
capacities ranging from 18,000 to 100,000 metric tons of HCFC-22, 
exceeded all of the capacity-based thresholds by wide margins. The 
smallest plant exceeded the largest capacity-based threshold by a 
factor of 85.
    We are not presenting a table for emission-based thresholds because 
we do not have facility-specific emissions information. (Under the 
voluntary emission reduction agreement, total emissions from the three 
facilities are aggregated by a third party, who submits only the total 
to us.) Since two of the three facilities destroy or capture most or 
all of their HFC-23 by-product, one or both of them probably have 
emissions below at least some of the emission-based thresholds 
discussed above. However, if the thermal oxidizers malfunctioned, were 
not operated properly, or were unused for some other reason, emissions 
of HFC-23 from each of the plants could easily exceed all thresholds. 
Reporting is therefore important both for tracking the considerable 
emissions of facilities that do not use thermal oxidation and for 
verifying the performance of thermal oxidation where it is used. For 
this reason, we propose that all HCFC-22 manufacturers report their 
HFC-23 emissions.
    We are aware of one facility that destroys HFC-23 but does not 
produce HCFC-22. Although we do not know the precise quantity of HFC-23 
destroyed by this facility, the Agency has concluded that the facility 
destroys a substantial share of the HFC-23 generated by the largest 
HCFC-22 production facility in the U.S. If the destruction facility 
destroys even one percent of this HFC-23, it is likely to destroy 
considerably more than the proposed threshold of 25,000 metric tons 
CO2e.
    For additional background information on the threshold analysis for 
HCFC-22 production, please refer to the HCFC-22 Production and HFC-23 
Destruction TSD (EPA-HQ-OAR-2008-0508-015). For specific information on 
costs, including unamortized first year capital expenditures, please 
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
a. Review of Monitoring Methods
    In developing these proposed requirements, we reviewed several 
protocols and guidance documents, including the 2006 IPCC Guidelines, 
guidance developed under our voluntary program for HCFC-22 
manufacturers, the WRI/WBCSD protocols, the TRI, the TSCA Inventory 
Update Rule, The DOE 1605(b) Voluntary Reporting Program, EPA Climate 
Leaders, and TRI.
    We also considered the findings and conclusions of a recent report 
that closely reviewed the methods that facilities use to estimate and 
assure the quality of their estimates of HCFC-22 production and HFC-23 
emissions. As noted above, the production facilities currently estimate 
and report these quantities to us (across all three plants) under a 
voluntary agreement. The report, by RTI International, is entitled 
``Verification of Emission Estimates of HFC-23 from the Production of 
HCFC-22: Emissions from 1990 through 2006'' and is available in the 
docket for this rulemaking.
    The 2008 Verification Report found that the estimation methods used 
by the three HCFC-22 facilities currently operating in the U.S. were 
all equivalent to IPCC Tier 3 methods. Under the Tier 3 methodology, 
facility-specific emissions are estimated based on direct measurement 
of the HFC-23 concentration and the flow rate of the streams, 
accounting for the use of emissions abatement devices (thermal 
oxidizers) where they are used. In general, Tier 3 methods for this 
source category yield far more accurate estimates than Tier 2 or Tier 1 
methods. Even at the Tier 3 level, however, the emissions estimation 
methods used by the three facilities differed significantly in their 
levels of absolute uncertainty. The uncertainty of the one facility 
that does not thermally destroy its HFC-23 emissions dominates the 
uncertainty for the national emissions from this source category.
    In general, the methods proposed in this rule are very similar to 
the procedures already being undertaken by the facilities to estimate 
HFC-23 emissions and to assure the quality of these estimates. The 
differences (and the rationale for them) are discussed in the HCFC-22 
Production and HFC-23 Destruction TSD (EPA-HQ-OAR-2008-0508-015).
b. Proposed Monitoring Methods
    This section of the preamble includes two proposed monitoring 
methods for HCFC-22 production facilities and one for HFC-23 
destruction facilities. The proposed monitoring methods differ for 
HCFC-22 facilities that do and do not use a thermal oxidizer connected 
to the HCFC-22 production equipment. All the monitoring methods rely on 
measurements of HFC-23 concentrations in process or emission streams 
and on measurements of the flow rates of those streams, although the 
proposed frequency of these measurements varies.
    Proposed Methods for Estimating HFC-23 Emissions from Facilities 
that Do Not Use a Thermal Oxidizer or Facilities that Use a Thermal 
Oxidizer that is Not Directly Connected to the HCFC-22 Production 
Equipment. Under the proposed rule, you would be required to:
    (1) Monitor the concentration of HFC-23 in the reaction product 
stream containing the HFC-23 (which could be either the HCFC-22 or the 
HCl product stream) on at least a daily basis. This proposed 
requirement is intended to account for day-to-day fluctuations in the 
rate at which HFC-23 is generated; this rate can vary depending on 
process conditions.
    (2) Monitor the mass flow of the product stream containing the HFC-
23 either directly or by weighing the other reaction product. The other 
product could be either HCFC-22 or HCl. Plants would be required to 
make or sum these measurements on at least a daily basis. If the HCFC-
22 or HCl product were measured significantly downstream of the reactor 
(e.g., at storage tanks or the shipping dock), facilities would be 
required to add a factor that accounted for losses to the measurement. 
This factor would be 1.5 percent or another factor that could be 
demonstrated, to the satisfaction of the Administrator, to account for 
losses. This adjustment is intended to account for upstream product 
losses, which are estimated to range from one to two percent. Without 
the adjustment, HCFC-22 production and therefore HFC-23 generation at 
affected facilities would be systematically underestimated (negatively 
biased). A one-to two-percent underestimate could translate into an 
underestimate of HFC-23 emissions of 100,000 metric tons 
CO2e or more for each affected facility.
    We request comment on this proposed approach for compensating for 
the negative bias caused by HCFC-22 emissions. We specifically request 
comment on the 1.5 percent factor, which is the midpoint of the one-to-
two-percent range of product loss rates cited by the affected facility. 
We also request comment on what methods and data would be required to 
verify a loss rate other than 1.5 percent, if a facility wished to 
demonstrate a lower loss rate. One option would be a mass-balance 
approach using measurements with very fine precisions (e.g., 0.2 
percent or better).
    (3) Facilities that do not use a thermal oxidizer connected to the 
HCFC-22

[[Page 16512]]

production equipment would also be required to estimate the mass of 
HFC-23 produced either by multiplying the HFC-23 concentration 
measurement by the mass flow of the stream containing both the HFC-23 
and the other product or by multiplying the ratio of the concentrations 
of HFC-23 and of the other product by the mass of the other product.
    (4) Facilities would also be required to measure the masses of HFC-
23 sold or sent to other facilities for destruction. This step would 
ensure that any losses of HFC-23 during filling of containers were 
included in the HFC-23 emission estimates for facilities that capture 
HFC-23 for use as a product or for transfer to a destruction facility.
    (5) Facilities would also be required to estimate the HFC-23 
emitted by subtracting the masses of HFC-23 sold or sent for 
destruction from the mass of HFC-23 generated.
    This calculation assumes that all production that is not sold or 
sent to another facility for destruction is emitted. Such emissions may 
be the result of the packaging process; additional emissions can be 
attributed to the number of flanges in a line and other on-site 
equipment that is specific to each facility.
    Proposed Methods for Estimating HFC-23 Emissions from Plants that 
Use a Thermal Oxidizer Connected to the HCFC-22 Production Equipment. 
Under the proposed rule, you would be required to estimate HFC-23 
emissions from equipment leaks, process vents, and the thermal 
oxidizer. To estimate emissions from leaks, you would be required to 
estimate the number of leaks using EPA Method 21 of 40 CFR part 60, 
Appendix A-7 and a leak definition of 10,000 ppmv. Leaks registering 
above and below 10,000 ppmv would be assigned different default 
emission rates, depending on the component and service (gas or light 
liquid). These leak rates would be drawn from Table 2-5 from the 
Protocol for Equipment Leak Estimates (EPA-453/R-95-017) and data on 
the concentration of HFC-23 in the process stream.\78\ (The relevant 
portions of Table 2-5 are included in the proposed regulatory text for 
this rule.) To estimate emissions from process vents, you would be 
required to use the results of annual emissions tests at process vents, 
adjusting for changes in HCFC-22 production rates since the 
measurements occurred. Tests would have to be conducted in accordance 
with EPA Method 18 of 40 CFR part 60, Appendix A-6, Measurement of 
Gaseous Organic Compounds by Gas Chromatography. Although HFC-23 
emissions from process vents are believed to be quite low, this 
monitoring would ensure that any year-to-year variability in the 
emission rate was captured by the reporting. Finally, to estimate 
emissions from the thermal oxidizer, you would be required to apply the 
DE of the oxidizer to the mass of HFC-23 fed into the oxidizer.
---------------------------------------------------------------------------

    \78\ Although EPA recognizes that the proposed method for 
estimating emissions from equipment leaks is rather uncertain, EPA 
believes that the level of precision is not unreasonable given the 
small size of the HFC-23 emissions that would be estimated using the 
method. These emissions are estimated to account for a fraction of a 
percent of U.S. HFC-23 emissions from this source.
---------------------------------------------------------------------------

    Destruction. Under the proposed rule, if you use thermal oxidation 
to destroy HFC-23 you would be required to measure the quantities of 
HFC-23 fed into the oxidizer. You would also be required to account for 
any decreases in the DE of the oxidizer that occurred when the oxidizer 
was not operating properly (as defined in State or local permitting 
requirements and/or oxidizer manufacturer specifications). Finally, you 
would be required to perform annual HFC-23 concentration measurements 
by gas chromatography to confirm that emissions from the oxidizer were 
as low as expected based on the rated DE of the device. If emissions 
were found to be higher, then facilities would have the option of using 
the DE implied by the most recent measurements or of conducting more 
extensive measurements of the DE of the device.
    As discussed in the HCFC-22 Production and HFC-23 Destruction TSD 
(EPA-HQ-OAR-2008-0508-015), the initial testing and parametric 
monitoring that facilities currently perform on their oxidizers 
provides general assurance that the oxidizer is performing correctly. 
However, the proposed requirement to measure HFC-23 concentrations at 
the oxidizer outlet would provide additional assurance at relatively 
low cost. Even a one- or two-percent decline in the DE of the oxidizer 
could lead to emissions of over 100,000 metric tons CO2e, 
making this a particularly important factor to monitor accurately.
    Startups, shutdowns, and malfunctions. Under the proposed rule, if 
you produce HCFC-22 you would be required to account for HFC-23 
production and emissions that occur as a result of startups, shutdowns, 
and malfunctions. This would be done either by recording HFC-23 
production and emissions during these events, or documenting that these 
events do not result in significant HFC-23 production and/or emissions. 
Depending on the circumstances, startups, shutdowns, and malfunctions 
(including both the process equipment and any thermal oxidation 
equipment) can be significant sources of emissions, and the Agency 
believes that emissions during these process disturbances should 
therefore be tracked.
    Precision and Accuracy Requirements. We are proposing to require 
that HCFC-22 production facilities and HFC-23 destruction facilities 
monitor the masses that would be reported under this rule 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. Our understanding is that some HCFC-22 production 
facilities currently use devices with this level of accuracy and 
precision. However, flowmeters with considerably better precisions are 
available, e.g., 0.2 percent. We request comment on the option of 
requiring plants to use flowmeters or scales with an accuracy and 
precision of 0.2 percent or some other precision better than 1 percent. 
Given the large quantities of HFC-23 generated by each plant, this 
higher precision may be appropriate.
    We are also proposing to require that HCFC-22 production facilities 
and HFC-23 destruction facilities measure concentrations using 
equipment and methods with an accuracy and precision of 5 percent or 
better at the concentrations of the samples.
    Calibration Requirements. Under the proposed rule, if you produce 
HCFC-22 or destroy HFC-23 you would be required to perform the 
following activities to assure the quality of their measurements and 
estimates:
    (1) Calibrate gas chromatographs used to determine the 
concentration of HFC-23 by analyzing, on a monthly basis, certified 
standards with known HFC-23 concentrations that are in the same range 
(percent levels) as the process samples. This proposed requirement is 
intended to verify the accuracy and precision of gas chromatographs at 
the concentrations of interest; calibration at other concentrations 
does not verify this accuracy with the same level of assurance. The 
proposed requirement is similar to requirements in protocols for the 
use of gas chromatography, such as EPA Method 18, Measurement of 
Gaseous Organic Compound Emissions by Gas Chromatography.
    (2) Initially verify each weigh scale, flow meter, and combination 
of volumetric and density measurements used to measure quantities that 
are to be reported under this rule, and calibrate it thereafter at 
least every year. We request comment on these proposed requirements.

[[Page 16513]]

4. Selection of Procedures for Estimating Missing Data
    We are proposing that in the cases when an upstream flow meter 
(i.e., near reactor outlet) is ordinarily used but is not available for 
some period, the facility can compensate by using downstream production 
measures (e.g., quantity shipped) and adding 1.5 percent to account for 
product losses. If HFC-23 concentration measurements are unavailable 
for some period, we propose that the facility use the average of the 
concentration measurements from just before and just after the period 
of missing data.
    There is one proposed exception to these requirements: If either 
method would result in a significant under- or overestimate of the 
missing parameter (e.g., because the monitoring failure was linked to a 
process disturbance that is likely to have significantly increased the 
HFC-23 generation rate), then the facility would be required to develop 
an alternative estimate of the parameter and explain why and how it 
developed that estimate.
    We request comment on these methods for estimating missing data. We 
also request comment on the option of estimating missing production 
data based on consumption of reactants, assuming complete 
stoichiometric conversion.
5. Selection of Data Reporting Requirements
    If you produce HCFC-22 and do not use a thermal oxidizer connected 
to the HCFC-22 production equipment, you would be required to report 
the total mass of the HFC-23 generated in metric tons, the mass of any 
HFC-23 packaged for sale in metric tons, the mass of any HFC-23 sent 
off site for destruction in metric tons, and the mass of HFC-23 emitted 
in metric tons. If you produce HCFC-22 and destroy HFC-23 using a 
thermal oxidizer connected to the HCFC-22 production equipment, you 
would be required to report the mass of HFC-23 emitted from the thermal 
oxidizer, the mass of HFC-23 emitted from process vents, and the mass 
of HFC-23 emitted from equipment leaks, in metric tons.
    In addition, if you produce HCFC-22 you would also be required to 
submit the following supplemental data, as applicable, for QA purposes: 
Annual HCFC-22 production, annual consumption of reactants (including 
factors to account for quantities that typically remain unreacted), by 
reactant, annual mass of materials other than HCFC-22 and HFC-23 (i.e., 
unreacted reactants, HCl and other byproducts) that are permanently 
removed from the process, and the method for tracking startups, 
shutdowns, and malfunctions and HFC-23 generation/emissions during 
these events. You would also be required to report the names and 
addresses of facilities to which any HFC-23 was sent for destruction, 
and the quantities sent to each.
    Where HCFC-22 production facilities have estimated missing data, 
you would be required to report 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. Where the missing data 
was estimated by a method other than one of those specified, the owner 
or operator would be required to report why the specified method would 
lead to a significant under- or overestimate of the parameter(s) and 
the rationale for the methods used to estimate the missing data.
    If you destroy HFC-23, you would be required to report the mass of 
HFC-23 fed into the thermal oxidizer, the mass of HFC-23 destroyed, and 
the mass of HFC-23 emitted from the thermal oxidizer. You would also be 
required to submit the results of your annual HFC-23 concentration 
measurements at the outlet of the oxidizer. In addition, you would be 
required to submit a one-time report similar to that required under 
EPA's stratospheric protection regulations at 40 CFR 82.13(j).
    We propose that facilities report these data either because the 
data are necessary to verify facilities' calculations of HFC-23 
generation, emissions, or destruction or because the data allow us to 
implement other QA checks (e.g., calculation of an HFC-23/HCFC-22 
generation factor that can be compared across facilities and over 
time). We request comment on these proposed reporting requirements.
6. Selection of Records That Must Be Retained
    If you produce HCFC-22, you would be required to keep records of 
the data used to estimate emissions and records documenting the initial 
and periodic calibration of the gas chromatographs, scales, and 
flowmeters used to measure the quantities reported under this rule.
    If you destroy HFC-23, you would be required to keep records of 
information documenting your one-time and annual reports.
    These records are necessary to enable verification that the GHG 
emissions monitoring and calculations were performed correctly.

P. Hydrogen Production

1. Definition of the Source Category
    Approximately nine million metric tons of hydrogen are produced in 
the U.S. annually. Hydrogen is used for industrial applications such as 
petrochemical production, metallurgy, and food processing. Some of the 
largest users of hydrogen are ammonia production facilities, petroleum 
refineries, and methanol production facilities.
    About 95 percent of all hydrogen produced in the U.S. today is made 
from natural gas via steam methane reforming. This process consists of 
two basic chemical reactions: (1) Reformation of the CH4 
feedstock with high temperature steam supplied by burning natural gas 
to obtain a synthesis gas (CH4 + H2O = CO + 
3H2); and (2) Using a water-gas shift reaction to form 
hydrogen and CO2 from the carbon monoxide produced in the 
first step (CO + H2O = CO2 + H22).
    Other processes used for hydrogen production include steam naptha 
reforming, coal or biomass gasification, partial oxidation of coal or 
hydrocarbons, autothermal reforming, electrolysis of water, recovery of 
byproduct hydrogen from electrolytic cells used to produce chlorine and 
other products, and dissociation of ammonia.
    Hydrogen is produced in large quantities at approximately 77 
merchant hydrogen production facilities (which produce hydrogen to 
sell) and 145 captive hydrogen production facilities (which consume 
hydrogen at the site where it is produced, e.g. petroleum refineries, 
ammonia, and methanol facilities). Hydrogen is also produced in small 
quantities at numerous other locations.
    National emissions from hydrogen production were estimated to be 
approximately 60 million metric tons CO2 (1 percent of U.S. 
GHG emissions) annually.
    The source category covered by the hydrogen production subpart of 
the proposed rule is merchant hydrogen production. CO2 
emissions from captive hydrogen production facilities at ammonia 
facilities, petrochemical facilities, and petroleum refineries are 
covered in proposed 40 CFR part 98, subparts G, X, and Y, respectively.
    For additional background information on hydrogen production, 
please refer to the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016).
2. Selection of Reporting Threshold
    In developing the threshold for hydrogen production, we considered 
emissions-based thresholds of 1,000

[[Page 16514]]

metric tons CO2e, 10,000 metric tons CO2e, 25,000 
metric tons CO2e and 100,000 metric tons CO2e. 
This threshold is based on combined combustion and process 
CO2 emissions at the hydrogen production facility.
    In selecting a threshold, we considered emissions data from 
merchant hydrogen facilities only, which together account for an 
estimated 15.2 million metric tons CO2e in 2006.
    Table P-1 of this preamble illustrates the emissions and facilities 
that would be covered under these various thresholds.

                              Table P-1. Threshold Analysis for Hydrogen Production
----------------------------------------------------------------------------------------------------------------
                                   H2 Production         Emissions covered              Facilities covered
CO2 Threshold level (metric tons  capacity (tons ---------------------------------------------------------------
           CO2e/year)                H2/year)     Tons CO2e/year      Percent         Number          Percent
----------------------------------------------------------------------------------------------------------------
No threshold....................               0      15,226,620           100.0              77             100
1,000...........................             116      15,225,220           100.0              73              95
10,000..........................           1,160      15,130,255            99.4              51              66
25,000..........................           2,900      14,984,365            98.4              41              53
100,000.........................          11,600      14,251,265            93.6              30              39
----------------------------------------------------------------------------------------------------------------

    The hydrogen production industry is heterogeneous in terms of the 
types of facilities. There are some relatively large, emissions 
intensive facilities, but small facilities are common as well. At a 
25,000 ton threshold, although 98.4 percent of emissions would be 
covered, only 53 percent of facilities would be required to report.
    The proposed threshold for reporting emissions from hydrogen 
production is 25,000 metric tons CO2e. We are proposing a 
25,000 metric tons CO2e threshold to reduce the compliance 
burden on small businesses, while still including a majority of GHG 
emissions from the industry.
    For a full discussion of the threshold analysis, please refer to 
the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Several domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from hydrogen production (e.g., the American Petroleum 
Institute Compendium, the DOE 1605(b), and the CARB Mandatory GHG 
Emissions Reporting Program). These methods coalesce around variants of 
two methods for merchant hydrogen production facilities: Direct 
measurement of CO2 emissions by CEMS, and the feedstock 
material balance method.
    Option 1. Direct measurement. The CEMS would capture both 
combustion and process-related CO2 emissions from a hydrogen 
facility. Facilities that do not currently employ a CEMS could 
voluntarily elect to install CEMS for reporting under this subpart. 
This approach is consistent with DOE's 1605(b) ``A'' rated method and 
the CARB Mandatory GHG Emissions Reporting Program.
    Option 2. Feedstock material balance method. This method accounts 
for the difference between the quantity and carbon content of all 
feedstock delivered to the facility and of all products leaving the 
facility. This approach is consistent with IPCC Tier 3 methods for 
similar processes (i.e., steam reformation in ammonia production), the 
DOE 1605(b) ``A'' rated method, and the CARB Mandatory GHG Emissions 
Reporting Program.
    Based on our review of the above approaches, we propose both 
methods for quantifying GHG emissions from hydrogen production, to be 
implemented depending on current circumstances at your facility. If you 
are required to use an existing CEMS to meet the requirements outlined 
in proposed 40 CFR part 98, subpart C, you would be required to use 
CEMS to estimate CO2 emissions. Where the CEMS capture 
combustion- and process-related CO2 emissions you would be 
required to follow the calculation procedures, monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of proposed 40 CFR part 98, subpart C to 
estimate CO2 emissions from the industrial source. Also, 
refer to proposed 40 CFR part 98, subpart C to estimate combustion-
related emissions from fuels not captured in the CEMS, as well as 
CH4 and N2O.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
the CEMS does not measure process emissions, the proposed monitoring 
method is Option 2. You would be required to follow the calculation 
procedures, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements of proposed 40 
CFR part 98, subpart C to estimate combustion-related emissions from 
each hydrogen production unit and any other stationary combustion 
units. This section of the preamble provides only those procedures for 
calculating and reporting process-related CO2 emissions. For 
CO2 collected and used onsite or transferred offsite, you 
must follow the methodology provided in proposed 40 CFR part 98, 
subpart PP of this part (Suppliers of CO2).
    The feedstock material balance method entails measurements of the 
quantity and carbon content of all feedstock delivered to the facility 
and of all products leaving the facility, with the assumption that all 
the carbon entering the facility in the feedstock that is not captured 
and sold outside the facility is converted to CO2 and 
emitted. The quantity of feedstock consumed must be measured 
continuously using a flowmeter. The carbon fraction in the feedstock 
may be provided as part of an ultimate analysis performed by the 
supplier (e.g., the local gas utility in the case of natural gas 
feedstock). If the feedstock supplier does not provide the gas 
composition or ultimate analysis data, the facility would be required 
to analyze the carbon content of the feedstock on a monthly basis using 
the appropriate test method in proposed 40 CFR 98.7.
    We also considered three other methods for quantifying process-
related emissions. The first method requires direct measurement of 
emissions by CEMS from all reporting facilities. The second method 
applies a constant proportionality factor, based on the facility's 
historical data on natural gas consumption, to the facility's hydrogen 
production rate. The third method we

[[Page 16515]]

considered applies a national default emission factor to the natural 
gas consumption rate at a facility.
    The first method would generally increase accuracy of reported 
data. We invite comment on the practicality of adopting the first 
method. In general, the latter two methods are less certain, as they 
involve multiplying production and feedstock consumption data by 
default emission factors based on purity assumptions.
    In contrast, the feedstock material balance method is more certain 
as it involves measuring the consumption and carbon content of the 
feedstock input. Because 95 percent of hydrogen is produced using steam 
methane reforming, and the carbon content of natural gas is always 
within 1 percent of the ratio: One mole of carbon per mole of natural 
gas, the local utility QA/QC requirements should be more than adequate.
    Given the increase in accuracy of the direct measurement and 
feedstock material balance methods coupled with the minimal additional 
burden for facilities that already employ CEMS, we propose that 
facilities utilize the direct measurement method where currently 
employed, and the feedstock material balance method for all facilities 
that do not employ CEMS. We have concluded that this requirement does 
not add additional burden to current practices at the facilities, 
thereby minimizing costs. The primary additional burden for facilities 
associated with this method would be in conducting a gas composition 
analysis of the feedstock on a monthly basis, in cases where this 
information is not provided by the supplier.
    The various approaches to monitoring GHG emissions are elaborated 
in the Hydrogen Production TSD (EPA-HQ-OAR-2008-0508-016).
4. Selection of Procedures for Estimating Missing Data
    Sources using CEMS to comply with this rule would be required to 
comply with the missing data requirements of proposed 40 CFR part 98, 
subpart C.
    In the event that a facility lacks feedstock supply rates for a 
certain time period, we propose that facilities use the lesser of the 
maximum supply rate that the unit is capable of processing or the 
maximum supply rate that the meter can measure. In the event that a 
monthly value for carbon content is determined to be invalid, an 
additional sample must be collected and tested. The likelihood for 
missing data is small, since the fuel meter and carbon content data are 
needed for financial accounting purposes.
5. Selection of Data Reporting Requirements
    We propose that facilities submit their annual CO2, and 
N2O emissions data. Facilities that use CEMS must comply 
with the procedures specified in proposed 40 CFR 98.36(d)(iv). In 
addition, we propose that facilities submit the following data on an 
annual basis for each process unit. These data are needed for us to 
understand the emissions data and verify the reasonableness of the 
reported emissions, and are the basis of the feedstock material balance 
calculation.
    The data should include the total quantity of feedstock consumed 
for hydrogen production, the quantity of CO2 captured for 
use and the end use, if known, the monthly analyses of carbon content 
for each feedstock used in hydrogen production, the annual quantity of 
hydrogen produced, and the annual ammonia produced, if applicable.
    A full list of data to be reported is included in proposed 40 CFR 
part 98, subparts A and P.
6. Selection of Records That Must Be Retained
    We propose that each hydrogen production facility comply with the 
applicable recordkeeping requirements for stationary combustion units 
in proposed 40 CFR part 98, subpart C, which are also discussed in 
Section V.C of this preamble.
    Also, we propose that each hydrogen production facility maintain 
records of feedstock consumption and the method used to determine the 
quantity of feedstock consumption, QA/QC records (including calibration 
records and any records required by the QAPP), monthly carbon content 
analyses, and the method used to determine the carbon content. A full 
list of records that must be retained onsite is included in proposed 40 
CFR part 98, subparts A and P. These records consist of values that are 
directly used to calculate the emissions that are reported and are 
necessary to enable verification that the GHG emissions monitoring and 
calculations were done correctly.

Q. Iron and Steel Production

1. Definition of the Source Category
    The iron and steel industry in the U.S. is the third largest in the 
world, accounting for about 8 percent of the world's raw iron and steel 
production and supplying several industrial sectors, such as 
construction (building and bridge skeletons and supports), vehicle 
bodies, appliances, tools, and heavy equipment. In this proposed rule, 
we are defining the iron and steel production source category to be 
taconite iron ore processing facilities, integrated iron and 
steelmaking facilities, electric arc furnace steelmaking facilities 
that are not located at integrated iron and steel facilities, and 
cokemaking facilities that are not located at integrated iron and steel 
facilities. Coke, sinter, and electric arc furnace steel production 
operations at integrated iron and steel facilities are part of 
integrated iron and steel facilities. Direct reduced iron furnaces are 
located at and are part of electric arc furnace steelmaking facilities.
    Currently, there are 18 integrated iron and steel steelmaking 
facilities that make iron from iron ore and coke in a blast furnace and 
refine the molten iron (and some ferrous scrap) in a basic oxygen 
furnace to make steel. In addition, there are over 90 electric arc 
furnace steelmaking facilities that produce steel primarily from 
recycled ferrous scrap. There are also eight taconite iron ore (pellet) 
processing facilities, 18 cokemaking facilities, seven of which are co-
located at integrated iron and steel facilities, and one direct reduced 
iron furnace located at an electric arc furnace steelmaking facility.
    The primary operation units that emit GHG emissions are blast 
furnace stoves (24 million metric tons CO2e/yr), taconite 
indurating furnaces, basic oxygen furnaces, electric arc furnaces 
(about 5 million metric tons CO2e/yr each), coke oven 
battery combustion stacks (6 million metric tons CO2e/yr), 
and sinter plants (3 million metric tons CO2e/yr). Smaller 
amounts of GHG emissions are produced by coke pushing (160,000 metric 
tons CO2e/yr) and direct reduced iron furnaces (140,000 
metric tons CO2e/yr).
    Based on production in 2007, GHG emissions from the source category 
are estimated at about 85 million metric tons CO2e/yr or 
just over 1 percent of total U.S. GHG emissions. Emissions from both 
process units (47 million metric tons CO2e/yr) and 
miscellaneous combustion units (38 million metric tons CO2e/
yr) are significant. Small amounts of N2O and CH4 
are also emitted during the combustion of different types of fuels.
    Although by-product recovery coke batteries and blast furnaces 
operations produce coke and pig iron, respectively, we are proposing 
that their emissions be reported as required for combustion units in 
proposed 40 CFR part 98, subpart C because the majority of their GHG 
emissions originate from fuel combustion. Emissions from the blast 
furnace operation occur primarily from the combustion of blast furnace 
gas and

[[Page 16516]]

natural gas in the blast furnace stoves. Emissions from by-product 
recovery coke batteries are generated from the combustion of coke oven 
gas in the coke battery's underfiring system. In addition to the blast 
furnace stoves and by-product coke battery underfiring systems, the 
other combustion units where fuel is the only source of GHG emissions 
include boilers, process heaters, reheat and annealing furnaces, 
flares, flame suppression systems, ladle reheaters, and other 
miscellaneous sources. Emissions from these other combustion sources in 
2007 are estimated at 16.8 million metric tons CO2e/yr for 
integrated iron and steel facilities, 18.6 million metric tons 
CO2e/yr for electric arc furnace steelmaking facilities, and 
2.7 million metric tons CO2e/yr for coke facilities not 
located at integrated iron and steel facilities. As noted, the proposed 
requirements for combustion units in proposed 40 CFR part 98, subpart C 
would apply for estimating the CO2, CH4, and 
N2O emissions from the following combustion units:
     By-product recovery coke oven battery combustion stacks.
     Blast furnace stoves.
     Boilers.
     Process heaters.
     Reheat furnaces.
     Annealing furnaces.
     Flares.
     Ladle reheaters.
     Other miscellaneous combustion sources.
    Emissions from the remaining operation units are generated from the 
carbon in process inputs and in some cases, from fuel combustion in the 
process. The process-related CO2, CH4 and 
N2O emissions from the operation units listed below except 
for coke pushing would be reported according to the proposed 
requirements in this section:
     Taconite indurating furnaces.
     Nonrecovery coke oven battery combustion stacks.
     Coke pushing.
     Basic oxygen furnaces.
     Electric arc furnaces.
     Direct reduced iron furnaces.
     Sinter plants.
    Emissions from nonrecovery coke batteries do not result from the 
combustion of a fuel input. In the nonrecovery battery, the volatiles 
that evolve as the coal is heated are ignited in the crown above the 
coal mass and in flues used to heat the oven. All of the combustible 
compounds distilled from the coal are burned, and the exhaust gases 
containing CO2 are emitted through the battery's combustion 
stack. For all types of coke batteries, a small amount of 
CO2 is formed when the incandescent coke is pushed from the 
oven, and prior to quenching with water, some of the coke burns. The 
CO2 emissions from taconite plants come primarily from the 
indurating furnaces where coal and/or natural gas are burned in the 
pelletizing process, and carbon in the process feed materials (iron 
ore, limestone, bentonite) is converted to CO2. The 
CO2 emissions from direct reduced iron furnaces result from 
the combustion of natural gas in the furnace and from the process 
inputs, primarily from the carbonaceous materials (such as coal or 
coke) that is mixed with iron ore. During steelmaking in the basic 
oxygen furnace, most of the GHGs result from blowing oxygen into the 
molten iron to produce steel by removing carbon, primarily as 
CO2. CO2 emissions also result from the addition 
of fluxing materials and other process inputs that may contain carbon. 
Emissions from electric arc furnaces are produced by the same 
mechanisms as for basic oxygen furnaces, and in addition, the 
consumption of carbon electrodes during the melting and refining stages 
contribute to CO2 emissions.
    Emissions of CH4 and N2O occur from the 
combustion of fuels in both combustion units and process units. For 
fuels that contain CH4, combustion of CH4 is not 
complete, and a small amount of CH4 is not burned and is 
emitted. In addition, a small amount of N2O can be formed as 
a by-product of combustion from the air (nitrogen and oxygen) that is 
required for combustion.
    Additional background information about GHG emissions from the iron 
and steel production source category is available in the Iron and Steel 
Production TSD (EPA-HQ-OAR-2008-0508-017).
2. Selection of Reporting Threshold
    In evaluating potential thresholds for iron and steel production, 
we considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e per year. This 
threshold is based on combined combustion and process CO2 
emissions at an iron and steel production facility.
    Table Q-1 of this preamble illustrates that the various thresholds 
do not have a significant effect on the amount of emissions that would 
be covered. To avoid placing a reporting burden on the smaller 
specialty stainless steel producers which may operate as small 
businesses while still requiring the reporting of GHG emissions from 
those facilities releasing most of the GHG emissions in this source 
category, we are proposing a threshold of 25,000 metric tons 
CO2e per year for reporting of emissions. This threshold 
level is consistent with the threshold level being proposed for other 
source categories with similar facility size characteristics. We are 
proposing that facilities emitting greater than 25,000 in the iron and 
steel production source category would be subject to the proposed rule 
because of the magnitude of their emissions. All integrated iron and 
steel facilities and taconite facilities exceed the highest emissions 
threshold considered. Most electric arc furnace facilities (with the 
possible exception of about 9 facilities) exceed the 25,000 metric tons 
CO2e emissions threshold. Requiring facilities that emit 
25,000 metric tons CO2e a year or more to report would 
capture nearly 100 percent of the emissions without significantly 
increasing the number of affected facilities.
    For a full discussion of the threshold analysis, refer to the Iron 
and Steel Production TSD (EPA-HQ-OAR-2008-0508-017). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.

                                               Table Q-1. Threshold Analysis for Iron and Steel Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
            Threshold level metric tons CO2e               (metric tons    of facilities    Metric tons
                                                               CO2e)                          CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
all in..................................................      85,150,877             130      85,150,877             100             130             100
1,000...................................................      85,150,877             130      85,150,877             100             130             100
10,000..................................................      85,150,877             130      85,141,500             100             128              98
25,000..................................................      85,150,877             130      85,013,059             100             121              93

[[Page 16517]]

 
100,000.................................................      85,150,877             130      84,468,696            99.2             111              85
--------------------------------------------------------------------------------------------------------------------------------------------------------

3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating emissions from process 
and combustion sources (e.g. 2006 IPCC Guidelines, U.S. Inventory, the 
WBCSD/WRI GHG protocol, DOE 1605(b), TCR, EU Emissions Trading System, 
the American Iron and Steel Institute Protocol, International Iron and 
Steel Institute Protocol, and Environment Canada's mandatory reporting 
guidelines). We considered these methodologies for measuring or 
estimating GHG emissions from the iron and steel source category. The 
following five options were considered for reporting process-related 
CO2 emissions from these sources.
    Option 1. Apply a default emission factor based on the type of 
process and an annual activity rate (e.g. quantity of raw steel, 
sinter, or direct reduced iron produced). This option is the same as 
the IPCC Tier 1 approach.
    Option 2. Perform a carbon balance of all inputs and outputs using 
default or typical values for the carbon content of the inputs and 
outputs. Facility production and other records would be used to 
determine the annual quantity of process inputs and outputs. 
CO2 emissions from the difference of carbon-in minus carbon-
out, assuming all is converted to CO2, would be calculated. 
This option is the same as the IPCC Tier 2 approach, the WRI default 
approach, and the DOE 1605(b) approach that is rated ``B.'' It is 
similar to the approach recommended by American Iron and Steel 
Institute except that the carbon balance for Option 2 is based on the 
individual processes rather than the entire plant.
    Option 3. Perform a monthly carbon balance of all inputs and 
outputs using measurements of the carbon content of specific process 
inputs and process outputs and measure the mass rate of process inputs 
and process outputs. Calculate CO2 emissions from the 
difference of carbon-in minus carbon-out assuming all is converted to 
CO2. This is consistent with an IPCC Tier 3 approach (if 
direct measurements are not available), the WRI/WBCSD preferred 
approach, the approach used in the EU Emissions Trading System, and the 
DOE 1605(b) approach that is rated ``A.''
    Option 4. Develop a site-specific emission factor based on 
simultaneous and accurate measurements of CO2 emissions and 
production rate or process input rate during representative operating 
conditions. Multiply the site-specific factor by the annual production 
rate or appropriate periodic production rate (or process input rate, as 
appropriate). This approach is included in Environment Canada's 
methodologies and might be considered a form of direct measurement 
consistent with the IPCC's Tier 3 approach.
    Option 5. Direct and continuous measurement of CO2 
emissions using CEMS for CO2 concentration and stack gas 
volumetric flow rate based on the requirements in 40 CFR part 75. This 
is the IPCC Tier 3 approach (direct measurement).
    Proposed option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C to 
estimate CO2 emissions from the industrial source. Also, you 
would use proposed 40 CFR part 98, subpart C to estimate combustion-
related CH4 and N2O.
    If you do not currently have CEMS that meet the requirements 
outlined in proposed 40 CFR part 98, subpart C, or where the CEMS would 
not adequately account for process emissions, we propose that Options 
3, 4 or 5 could be implemented. You would be required to follow the 
requirements of proposed 40 CFR part 98, subpart C to estimate 
emissions of CO2, CH4 and N2O from 
stationary combustion. This section of the preamble provides procedures 
only for calculating and reporting process-related emissions.
    We identified Options 3, 4, and 5 as the approaches that have 
acceptable uncertainty for facility-specific estimates. All of these 
options would provide insight into different levels of emissions caused 
by facility-specific differences in feedstock or process operation. 
Options 3, 4, and 5 are forms of the IPCC's highest tier methodology 
(Tier 3), therefore, we propose these options as equal options. After 
consideration of public comments, we may promulgate one or more of the 
options or a combination based on the additional information that is 
provided.
    We considered but decided against Options 1 and 2 because the use 
of default values and lack of direct measurements results in a very 
high level of uncertainty in the emission estimates. These default 
approaches would not provide site-specific estimates of emissions that 
would reflect differences in feedstocks, operating conditions, fuel 
combustion efficiency, variability in fuels and other differences among 
facilities. In general, we decided against proposing existing 
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, and such default 
approaches are inherently inaccurate for site-specific determinations. 
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. According to the IPCC's 
2006 guidelines, the uncertainty associated with default emission 
factors for Options 1 and 2 is 25 percent, and the 
uncertainty in the production data used with the default emission 
factor is 10 percent, which results in a combined overall 
uncertainty greater than 25 percent. If process-specific 
carbon contents and actual mass rate data for the process inputs and 
outputs are used (i.e., Option 3) or if direct measurements are used 
(i.e., Options 4 and 5), the guidelines state that the uncertainty 
associated with the emission estimates would be reduced.
    For Option 3, we are proposing that facilities may estimate process 
emissions based on a carbon balance that uses facility-specific 
information on the carbon content of process inputs and outputs and 
measurements of the mass rate of process inputs and outputs. Monthly 
determinations of the mass of process inputs and outputs other than

[[Page 16518]]

fuels would be required. These data are readily available for almost 
all process inputs and outputs on a monthly basis from purchasing, 
accounting, and production records that are routinely maintained by 
each facility. The mass rates of fuels would be measured according to 
the procedures for fuels in combustion units in proposed 40 CFR part 
98, subpart C. The carbon content of each process input and output 
other than fuels would also be measured each month. A sample would be 
taken each week, composited for the monthly analysis, and sent to an 
independent laboratory for analysis of carbon content using the test 
methods in proposed 40 CFR part 98, subpart A. The carbon content of 
fuels would be determined using the procedures for fuels in combustion 
units in proposed 40 CFR part 98, subpart C. The CO2 
emissions would be estimated each month using the carbon balance 
equations in the proposed rule and then summed to provide the totals 
for the quarter and for the year.
    While this proposed approach is consistent with how iron and steel 
production facilities are currently developing facility level GHG 
inventories, there are three components of this approach for which the 
Agency is requesting comment and supporting information. One issue is 
the ability to obtain accurate measurements of the process inputs and 
outputs, especially materials that are bulk solids and molten metal and 
slag. A second issue is the ability to obtain representative samples of 
the process inputs and outputs to determine the carbon content, 
especially for non-homogenous materials such as iron and steel scrap. 
The third issue is the level of uncertainty in the emission estimates 
for processes where there is a significant amount of carbon leaving the 
process with product (such as coke plants). These and other factors may 
result in an unacceptable level of uncertainty, especially for certain 
processes, when using the carbon balance approach to estimate 
emissions.
    While we are proposing that emissions from blast furnace stoves and 
coke battery combustion stacks be reported as would be required for 
combustion sources under proposed 40 CFR part 98, subpart C, we are 
also requesting comment on how the carbon balance approach (Option 3) 
could be implemented as an alternative monitoring option for the entire 
blast furnace operation and the entire coke plant operation at 
integrated iron and steel facilities. Comments should address the 
advantages, disadvantages, types and frequency of measurements that 
should be required, and whether (and if so, how) the emissions can be 
determined with reasonable certainty. Comments must demonstrate that 
the procedures produce results that are reproducible and clearly 
specify the sampling methods and QA procedures that would ensure 
accurate results.
    For the site-specific emission factor approach (Option 4), the 
owner or operator may conduct a performance test and determine 
CO2 emissions from all exhaust stacks for the process using 
EPA reference methods to continuously measure the CO2 
concentration and stack gas volumetric flow rate during the test. In 
addition, either the feed rate of materials into the process or the 
production rate during the test would be measured. The performance test 
would be conducted under normal process operating conditions and at a 
production rate no less than 90 percent of the process rated capacity. 
For continuous processes (taconite indurating furnaces, non-recovery 
coke batteries, and sinter plants), the testing would cover at least 
nine hours of continuous operation. For batch or cyclic processes 
(basic oxygen furnaces, electric arc furnaces, and direct reduction 
furnaces), the testing would cover at least nine complete production 
cycles that start when the furnace is being charged and end after steel 
or iron and slag have been tapped. We are proposing testing for nine 
hours or nine production cycles, as applicable, because nine tests 
should provide a reasonable measure of variability (i.e., the standard 
deviation for nine production cycles or nine 1-hour runs). If an 
electric arc furnace is used to produce both carbon steel and low 
carbon steel (including stainless or specialty steel), separate 
emission factors would be developed for carbon steel and low carbon 
steel.
    The site-specific emission factor for the process would be 
calculated in metric tons CO2 per metric ton of feed or 
production, as applicable, by dividing the CO2 emission rate 
by the feed or production rate. The CO2 emissions for the 
process would be calculated by multiplying the emission factor by the 
total amount of feed or production, as applicable. A new performance 
test would be required each year to develop a new site-specific 
emission factor. Whenever there is a significant change in fuel type or 
mix, change in the process in a manner that affects energy efficiency 
by more than 10 percent, or a change in the process feed materials in a 
manner that changes the carbon content of the feed or fuel by more than 
10 percent, a new performance test would be conducted and a new site-
specific emission factor calculated.
    We are also requesting comment on the advantages and disadvantages 
of Option 4, along with supporting documentation. We have concluded 
that there may be situations in which the site-specific emission factor 
approach may result in an uncertainty lower than that associated with 
the carbon balance approach and provide more reasonable emission 
estimates. An example is nonrecovery coke plants, where a carbon 
balance approach may result in an unacceptably high level of 
uncertainty from subtracting two very large numbers (carbon in with 
coal and carbon out with coke) to estimate emissions that could instead 
be accurately and directly measured at the combustion stack.
    The primary sources of variability that affect CO2 
emissions from process sources in general are the carbon content of the 
process inputs and fuel and any changes to the process that alter 
energy efficiency. For most processes, the carbon content of process 
inputs and fuels is consistent and stable, and if a process change 
alters energy efficiency, a re-test could be performed to develop a new 
emission factor that reflected the change. We are requesting comment 
and supporting information on the minimum time or number of production 
cycles needed for testing to develop a representative emission factor, 
and how often periodic re-testing should be required (e.g., annually, 
quarterly, or only when there is a process change). We are also 
requesting that any comments on Option 4 address how changes in process 
inputs, fuels, or process energy efficiency should be accounted for, 
such as requiring a re-test if the carbon content of inputs change by 
more than some specified percent, if the type or mix of fuel is 
changed, or if there is a significant change in fuel consumption due to 
a process change.
    We are also proposing that you may use direct measurements, noting 
that CEMS (Option 5) provide the lowest uncertainty of the three 
options. This approach overcomes many of the limitations associated 
with other options considered such as accounting for the variability in 
emissions due to changes in the process, feed materials, or fuel over 
time. It would be applied to stacks that are already equipped with 
sampling ports and access platforms; consequently, it is technically 
feasible and cost effective. For those emission sources already 
equipped with CEMS, we are proposing that they be modified (if 
necessary) and used to determine CO2 emissions for that 
emission source. We are proposing this requirement

[[Page 16519]]

because it provides direct emission measurements that have low 
uncertainty with only a minimal additional cost burden. We also request 
comment, along with supporting documentation, on the advantages and 
disadvantages of Option 5.
    We are also proposing that CH4 and N2O 
emissions from the combustion of fuels in both combustion units and 
process units be determined and reported. All of the fuels used at iron 
and steel production processes are included in the methodologies in 
proposed 40 CFR part 98, subpart C for N2O and 
CH4. Consequently, EPA is proposing to use the same 
methodology as in proposed 40 CFR part 98, subpart C for determining 
and reporting emissions of N2O and CH4 from both 
stationary combustion units and process units.
    Miscellaneous Emissions Sources. Emissions may also occur when the 
incandescent coke is pushed from the coke oven and transported to the 
quench tower where it is cooled (quenched) with water. A small portion 
of the coke burns during this process prior to quenching. We updated 
the coke oven section of the AP-42 \79\ compilation of emission factors 
in May 2008, and the update included an emission factor for 
CO2 emissions developed from 26 tests for particulate matter 
from pushing operations. The emissions factor (0.008 metric tons 
CO2e per metric ton of coal charged) was derived to account 
for emissions from the pushing emission control device and those 
escaping the capture system. We are proposing that coke facilities use 
the AP-42 emission factor to estimate CO2 emissions from 
coke pushing operations.
---------------------------------------------------------------------------

    \79\ See Compilation of Air Pollutant Emission Factors, Fifth 
Edition: http://www.epa.gov/ttn/chief/ap42/ch12/final/c12s02_may08.pdf.
---------------------------------------------------------------------------

    There are dozens of emission points and various types of fugitive 
emissions, not collected for emission through a stack, from the 
production processes and materials handling and transfer activities at 
integrated iron and steel facilities. These emissions from iron and 
steel plants have been of environmental interest primarily because of 
the particulate matter in the emissions. Examples include ladle 
metallurgy operations, desulfurization, hot metal transfer, sinter 
coolers, and the charging and tapping of furnaces. The information we 
have examined to date indicates that these emissions contribute very 
little to the overall GHG emissions from the iron and steel sector 
(probably on the order of one percent or less). For example, emissions 
of blast furnace gas may be emitted during infrequent process upsets 
(called ``slips'') when gas is vented for a short period or from leaks 
in the ductwork that handles the gas. However, the mass of GHG 
emissions is expected to be small because most of the carbon in blast 
furnace gas is from carbon monoxide, which is not a GHG. Fugitive 
emissions and emissions from control device stacks may also occur from 
blast furnace tapping, the charging and tapping of basic oxygen 
furnaces and electric arc furnaces, ladle metallurgy, desulfurization, 
etc. However, we have no information that indicates CO2 is 
generated from these operations, and a review of test reports from 
systems that capture these emissions show that CO2 
concentrations are very low (at ambient air levels). Fugitive emissions 
containing CH4 may occur from leaks of raw coke oven gas 
from the coke oven battery during the coking cycle. However, the mass 
of these emissions is expected to be small based on the small number of 
leaks that are now allowed under existing Federal and State standards 
that regulate these emissions. In addition, since these emissions are 
not captured in a conveyance, there is no practical way to measure 
them. Consequently, we are not proposing that fugitive emissions be 
reported because we believe their GHG content is negligible and because 
there is no practical way of measuring them. However, we welcome public 
comment, along with supporting data and documentation, on whether 
fugitive emissions should be included, and if so, how these emissions 
can be estimated.
4. Selection of Procedures for Estimating Missing Data
    For process sources that use Option 3 (carbon balance) or Option 4 
(site-specific emission factor), no missing data procedures would apply 
because 100 percent data availability would be required. For process 
sources that use Option 5 (direct measurement by CEMS), the missing 
data procedures would be the same as for units using Tier 4 in the 
general stationary fuel combustion source category in proposed 40 CFR 
part 98, subpart C.
5. Selection of Data Reporting Requirements
    We are proposing that facilities submit annual emission estimates 
for CO2 presented by calendar quarters for coke oven battery 
combustion stacks, coke pushing, blast furnace stoves, taconite 
indurating furnaces, electric arc furnaces, argon-oxygen 
decarburization vessel, direct reduced iron furnaces, and sinter 
plants.
    In addition we propose that facilities submit the following data to 
assist in checks for reasonableness and for other data quality 
considerations: Total mass for all process inputs and outputs when the 
carbon balance is used for specific processes by calendar quarters, 
site-specific emission factor for all processes for which the site-
specific emission factor approach is used, annual production quantity 
for taconite pellets, coke, sinter, iron, raw steel by calendar 
quarters, annual production capacity for taconite pellets, coke, 
sinter, iron, raw steel, annual operating hours for taconite furnaces, 
coke oven batteries, sinter production, blast furnaces, direct reduced 
iron furnaces, and electric arc furnaces, and the quantity of 
CO2 captured for use and the end use, if known.
    A full list of data that would be reported is included in proposed 
40 CFR part 98, subparts A and Q.
6. Selection of Records That Must Be Retained
    In addition to the recordkeeping requirements for general 
stationary fuel combustion sources, we propose that the following 
additional records be kept to assist in QA/QC and verification 
purposes: GHG emission estimates from the iron and steel production 
process by calendar quarter, monthly total for all process inputs and 
outputs when the carbon balance is used for specific processes, 
documentation of calculation of site-specific emission factor for all 
processes for which the site-specific emission factor approach is used, 
monthly analyses of carbon content, and monthly production quantity for 
taconite pellets, coke, sinter, iron, and raw steel.

R. Lead Production

1. Definition of the Source Category
    Lead is a metal used to produce various products such as batteries, 
ammunition, construction materials, electrical components and 
accessories, and vehicle parts. For this proposed rule, we are defining 
the lead production source category to consist of primary lead smelters 
and secondary lead smelters. A primary lead smelter produces lead metal 
from lead sulfide ore concentrates through the use of pyrometallurgical 
processes. A secondary lead smelter produces lead and lead alloys from 
lead-bearing scrap metal.
    For the primary lead smelting process used in the U.S., lead 
sulfide ore concentrate is first fed to a sintering process to burn 
sulfur from the lead ore. The sinter is smelted with a

[[Page 16520]]

carbonaceous reducing agent in a blast furnace to produce molten lead 
bullion. From the furnace, the bullion is transferred to dross kettle 
furnaces to remove primarily copper and other metal impurities. 
Following further refining steps, the lead is cast into ingots or alloy 
products.
    The predominate feed materials processed at U.S. secondary lead 
smelters are used automobile batteries, but these smelters can also 
process other lead-bearing scrap materials including wheel balance 
weights, pipe, solder, drosses, and lead sheathing. These incoming lead 
scrap materials are first pre-treated to partially remove metal and 
nonmetal contaminants. The resulting lead scrap is smelted (U.S. 
secondary lead smelters typically use either a blast furnace or 
reverberatory furnace). The molten lead from the smelting furnace is 
refined in kettle furnaces, and then cast into ingots or alloy 
products.
    Lead production results in both combustion and process-related GHG 
emissions. Combustion-related CO2, CH4, and 
N2O emissions are generated from metallurgical process 
equipment used at primary and secondary lead smelters when natural gas 
or another fuel is burned in the unit to produce heat for drying, 
roasting, sintering, calcining, melting, or casting operations. 
Process-related CO2 emissions are released from the lead 
smelting process due to the addition of a carbonaceous reducing agent 
such as metallurgical coke or coal to the smelting furnace. The 
reduction of lead oxide to lead metal during the process produces the 
CO2 emissions.
    Currently there is one primary lead smelter operating in the U.S. 
There are 26 secondary lead smelters in the U.S. with widely varying 
annual lead production capacities ranging from approximately 1,000 
metric tons to more than 100,000 metric tons. Total national GHG 
emissions from lead production in the U.S. were estimated to be 
approximately 0.9 million metric tons CO2e in 2006. These 
emissions include both on-site stationary combustion emissions 
(CO2, CH4, and N2O) and process-
related emissions (CO2). The majority of these emissions 
were from the combustion of carbon-based fuels. Combustion GHG 
emissions were 0.6 million metric tons CO2e emissions (69 
percent of the total emissions). The remaining 0.3 million metric tons 
CO2e (31 percent of the total emissions) were process-
related GHG emissions.
    Additional background information about GHG emissions from the lead 
production source category is available in the Lead Production TSD 
(EPA-HQ-OAR-2008-0508-018).
2. Selection of Reporting Threshold
    In developing the threshold for lead production facilities, we 
considered using annual GHG emissions-based threshold levels of 1,000 
metric tons CO2e, 10,000 metric tons CO2e, 25,000 
metric tons CO2e and 100,000 metric tons CO2e. 
This threshold is based on combined combustion and process 
CO2 emissions at the lead production facility. Table R-1 of 
this preamble presents the estimated emissions and number of facilities 
that would be subject to GHG emissions reporting, based on existing 
facility lead production capacities, under these various threshold 
levels.

                                                     Table R-1. Threshold Analysis for Lead Smelters
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                 Emissions covered              Facilities covered
                                                               Total        Nationwide   ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              nationwide       number of      metric tons                      Facility
                                                             emissions      facilities        CO2e/yr         Percent         number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................         866,000              27         859,000              99              17              63
10,000..................................................         866,000              27         853,000              98              16              59
25,000..................................................         866,000              27         798,000              92              13              48
100,000.................................................         866,000              27               0               0               0               0
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Secondary lead smelters in the U.S. vary greatly in production 
capacity and include 10 small facilities with production capacities 
less than 4,000 tons per year. Table R-1 of this preamble shows 
approximately 92 percent of the GHG emissions that result from lead 
production are released from the one primary smelter and 12 secondary 
smelters that emit more than 25,000 metric tons CO2e 
annually. Of the facilities with annual GHG emissions below 25,000 
metric tons CO2e, 10 secondary smelters are estimated to 
emit less than 1,000 metric tons CO2e annually.
    To avoid placing a reporting burden on the smaller secondary lead 
smelters which may operate as small businesses while still requiring 
the reporting of GHG emissions from those facilities releasing most of 
the GHG emissions in this source category, we are proposing a threshold 
of 25,000 metric tons CO2e per year for reporting of 
emissions. This threshold level is consistent with the threshold level 
being proposed for other source categories with similar facility size 
characteristics. More discussion of the threshold selection analysis is 
available in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    We reviewed existing domestic and international GHG monitoring 
guidelines and protocols including the 2006 IPCC Guidelines for 
National Greenhouse Gas Inventories, U.S. GHG Inventory, the EU 
Emissions Trading System, the Canadian Mandatory Greenhouse Gas 
Reporting Program, and the Australian National Greenhouse Gas Reporting 
Program. These methods coalesce around the following four options for 
estimating process-related CO2 emissions from lead 
production facilities. A full summary of methods reviewed is available 
in the Lead Production TSD (EPA-HQ-OAR-2008-0508-018).
    Option 1. Apply a default emission factor for the process-related 
emissions to the facility's lead production rate. This is a simplified 
emission calculation method using only default emission factors to 
estimate process-related CO2 emissions. The method requires 
multiplying the amount of lead produced by the appropriate default 
emission factors from the 2006 IPCC Guidelines. This method is 
consistent with the IPCC Tier 1 method.
    Option 2. Perform monthly measurements of the carbon content of 
specific process inputs and measure the mass rate of these inputs. This 
is the IPCC Tier 3 approach and the higher order methods in the 
Canadian and Australian reporting programs. Implementation of this 
method requires owners and operators of affected lead smelters to 
determine the carbon

[[Page 16521]]

contents of materials added to the smelting furnace by analysis of 
representative samples collected of the material or from information 
provided by the material suppliers. In addition, you must measure and 
record the quantities of these input materials consumed during 
production. To obtain the process-related CO2 emission 
estimate, the material carbon content would be multiplied by the 
corresponding mass of the carbon-containing input material consumed and 
a conversion factor of carbon to CO2. This method assumes 
that all of the carbon is converted to CO2 during the 
reduction process. The facility owner or operator would determine the 
average carbon content of the material for each calendar month using 
information provided by the material supplier or by collecting a 
composite sample of material and sending it to an independent 
laboratory for chemical analysis.
    Option 3. Use CO2 emissions data from a stack test 
performed using EPA reference test methods to develop a site-specific 
process emissions factor which is then applied to quantity measurement 
data of feed material or product for the specified reporting period. 
This monitoring method is applicable to furnace configurations for 
which the GHG emissions are contained within a stack or vent. Using 
site-specific emissions factors based on short-term stack testing is 
appropriate for those facilities where process inputs (e.g., feed 
materials, carbonaceous reducing agents) and process operating 
parameters remain relatively consistent over time.
    Option 4. Use direct emission measurement of CO2 
emissions. For furnace configurations in which the process off-gases 
are contained within a stack or vent, direct measurement of the 
CO2 emissions can be made by continuously measuring the off-
gas stream CO2 concentration and flow rate using a CEMS. For 
a smelting furnace used for lead production where both combustion and 
process-related emissions are released by a source (e.g. blast furnace) 
emissions reported by using a CEMS would be total CO2 
emissions including both combustion and process-related CO2 
emissions.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2 emissions. Also, refer to proposed 40 CFR part 98, 
subpart C to estimate combustion-related CH4 and 
N2O.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
CEMS would not adequately account for combustion and process related 
CO2 emissions, the proposed monitoring method for process-
related CO2 from lead production is Option 2. You would be 
required to follow the calculation procedures, monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of proposed 40 CFR part 98, subpart C to 
estimate emissions of CO2, CH4 and N2O 
from stationary combustion. This section of the preamble provides 
procedures only for calculating and reporting process-related 
emissions.
    We propose Option 2, due to the operating variations between the 
individual U.S. lead production facilities, including differences in 
equipment configurations, mix of lead feedstocks charged, and types of 
carbon materials used. Further, Option 2 would result in lower 
uncertainty as compared to applying a default emissions factor based 
approach to these units.
    Although we are not proposing to require you to directly measure 
process emissions, unless you meet the requirements of proposed 40 CFR 
part 98, subpart C and the CEMS account for both combustion and 
process-relate emissions, you could opt to use direct measurement of 
CO2 emissions as an alternative GHG emissions estimation 
method because it would best reflect actual operating practices at your 
facility, and therefore, reduce uncertainty. While we recognize that 
the costs for conducting direct measurements may be higher than other 
methods, we are proposing to include this alternative because it 
provides GHG emissions data that have low uncertainty. The additional 
cost burden may be acceptable to owners and operators with site-
specific reasons for choosing this alternative.
    We decided not to propose the use of the default CO2 
emission factors (Option 1) because their application is more 
appropriate for GHG estimates from aggregated process information on a 
sector-wide or nationwide basis than for determining GHG emissions from 
specific facilities. We considered the additional burden of the 
material measurements required for the carbon calculations under Option 
2 small in relation to the increased accuracy expected from using this 
site-specific information to calculate the process-related 
CO2 emissions.
    We also decided not to propose Option 3 because of the potential 
for significant variations at lead smelters in the characteristics and 
quantities of the furnace inputs (e.g., lead scrap materials, 
carbonaceous reducing agents) and process operating parameters. A 
method using periodic, short-term stack testing would not be practical 
or appropriate for those lead smelters where the furnace inputs and 
operating parameters do not remain relatively consistent over the 
reporting period.
    Further details about the selection of the monitoring methods for 
GHG emissions is available in the Lead Production TSD (EPA-HQ-OAR-2008-
0508-018).
4. Selection of Procedures for Estimating Missing Data
    For smelting furnaces for which the owner or operator calculates 
process GHG emissions using site-specific carbonaceous input material 
data, the proposed rule requires the use of substitute data whenever a 
quality-assured value of a parameter that is used to calculate GHG 
emissions is unavailable, or ``missing.'' If the carbon content 
analysis of carbon inputs is missing or lost the substitute data value 
would be the average of the quality-assured values of the parameter 
immediately before and immediately after the missing data period. In 
those cases when an owner or operator uses direct measurement by a 
CO2 CEMS, the missing data procedures would be the same as 
the Tier 4 requirements described for general stationary fuel 
combustion sources in proposed 40 CFR part 98, subpart C. The 
likelihood for missing data is low, as businesses closely track their 
purchase of production inputs.
5. Selection of Data Reporting Requirements
    The proposed rule would require annual reporting of the total 
annual CO2 process-related emissions from each smelting 
furnace at lead production facilities, as well as any stationary fuel 
combustion emissions. In addition, we are proposing that additional 
information that forms the basis of the emissions estimates also be 
reported so that we can understand and verify the reported emissions. 
This addition information includes the total number of smelting 
furnaces operated at the facility, the facility lead product production 
capacity, the annual facility production quantity, annual quantity and 
type of carbon-containing input

[[Page 16522]]

materials consumed or used, annual weighted average carbon contents by 
material type, and the number of facility operating hours in the 
calendar year. A complete list of data to be reported is included in 
proposed 40 CFR part 98, subparts A and R.
6. Selection of Records That Must Be Retained
    Maintaining records of the information used to determine the 
reported GHG emissions is necessary to enable us to verify that the GHG 
emissions monitoring and calculations were done correctly. In addition 
to the information reported as described in Section V.R.5 of this 
preamble, we propose that all facilities estimating emissions according 
to the carbon input method maintain records of each carbon-containing 
input material consumed or used (other than fuel) the monthly material 
quantity, monthly average carbon content determined for material, and 
records of the supplier provided information or analyses used for the 
determination. If you use the CEMS procedure, you would maintain the 
CEMS measurement records according to the procedures in proposed 40 CFR 
part 98, subpart C. These records would be required to be maintained 
onsite for 5 years. A complete list of records to be retained is 
included in the proposed rule.

S. Lime Manufacturing

1. Definition of the Source Category
    Lime is an important manufactured product with many industrial, 
chemical, and environmental applications. Its major uses are in steel 
making, flue gas desulfurization systems at coal-fired electric power 
plants, construction, and water purification. Lime is used for the 
following purposes: Metallurgical uses (36 percent), environmental uses 
(29 percent), chemical and industrial uses (21 percent), construction 
uses (13 percent), and to make dolomite refractories (1 percent).
    For U.S. operations, the term ``lime'' actually refers to a variety 
of chemical compounds. These compounds include calcium oxide (CaO), or 
high-calcium quicklime; calcium hydroxide (Ca(OH)2), or 
hydrated lime; dolomitic quicklime ((CaO[bul]MgO)); and dolomitic 
hydrate ((Ca(OH)2[bul]MgO) or 
(Ca(OH)2[bul]Mg(OH)2)). Lime manufacturing 
involves three main processes: Stone preparation, calcination, and 
hydration. During the calcination process, the carbonate in limestone 
is sufficiently heated and reduced to CO2 gas. In certain 
applications, lime reabsorbs CO2 during use thereby reducing 
onsite GHG emissions.
    National emissions from the lime industry were estimated to be 25.4 
million metric tons CO2e in 2004 (or <0.4 percent of 
national emissions). These emissions include both process-related 
emissions and on-site stationary combustion emissions from 89 lime 
manufacturing facilities across the U.S. and Puerto Rico. Process-
related emissions account for 14.3 million metric tons CO2e, 
or 56 percent of the total, while on-site stationary combustion 
emissions account for the remaining 11.1 million metric tons 
CO2e.
    For additional background information on lime manufacturing, please 
refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019).
2. Selection of Reporting Threshold
    In developing the proposed reporting threshold for the lime 
manufacturing source category, we considered emissions-based thresholds 
of 1,000 metric tons CO2e, 10,000 metric tons 
CO2e, 25,000 metric tons CO2e and 100,000 metric 
tons CO2e. This threshold is based on combined combustion 
and process CO2 emissions at a lime production facility. 
Table S-1 of this preamble illustrates the emissions and facilities 
that would be covered under various thresholds.

                                                  Table S-1. Threshold Analysis for Lime Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              metric tons    of facilities    metric tons
                                                              CO2e/yr                         CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................      25,421,043              89      25,421,043             100              89             100
10,000..................................................      25,421,043              89      25,396,036            99.9              86              97
25,000..................................................      25,421,043              89      25,371,254            99.8              85              96
100,000.................................................      25,421,043              89      23,833,273              94              52              58
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The lime manufacturing sector consists primarily of large 
facilities and a few smaller facilities. All facilities, except four, 
exceed the 25,000 metric tons CO2e threshold.
    Consistent with National Lime Association recommendations, and in 
order to simplify the proposed rule and avoid the need to calculate and 
report whether the threshold value has been exceeded, we are proposing 
that all lime manufacturing facilities report GHG emissions. This 
captures 100 percent of emissions without significantly increasing the 
number of facilities that would have reported at 1,000, 10,000, or 
25,000 metric ton thresholds. For a full discussion of the threshold 
analysis, please refer to the Lime Manufacturing TSD (EPA-HQ-OAR-2008-
0508-019). For specific information on costs, including unamortized 
first year capital expenditures, please refer to section 4 of the RIA 
and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from lime manufacturing (e.g., the 2006 IPCC Guidelines, U.S. 
Inventory, DOE 1605(b), National Lime Association CO2 
Protocol, and the EU Emissions Trading System). These methodologies can 
be summarized by the following two overall approaches to estimating 
emissions, based on measuring either the carbonate inputs to the kiln 
or production outputs of the lime manufacturing process.
    Input-based Options. We considered the IPCC Tier 3 method which 
requires facilities to estimate process emissions by measuring the 
quantity of carbonate inputs to the kiln(s) and applying the 
appropriate emission factors and calcination fractions to the 
carbonates consumed. In order to assess the composition of carbonate 
inputs, facilities would send samples of their inputs and lime kiln 
dust produced to an off-site laboratory for analysis on a monthly basis 
using ASTM C25-06, ``Standard Test Methods for Chemical Analysis of 
Limestone, Quicklime, and Hydrated Lime'' (incorporated by reference, 
see proposed 40 CFR 98.7). For greater accuracy, facilities would

[[Page 16523]]

also estimate the calcination fraction of each carbonate consumed on a 
monthly basis. However, it is generally accepted that the calcination 
fraction of carbonates during lime production is 100 percent or very 
close to it.
    Output-based Options. We also considered three output-based methods 
for quantifying process-related emissions based on the quantity of lime 
produced. IPCC's Tier 1 method applies default emission factors to each 
of the three types of lime produced (high calcium lime, dolomitic lime, 
or hydraulic lime). The IPCC Tier 2 method applies a default emissions 
factor based on lime type to the corresponding quantity of all lime 
produced (by type), correcting for the amount of calcined byproduct/
waste product (such as lime kiln dust) produced in the process.
    The third output method, developed by the National Lime 
Association, improves upon the IPCC Tier 2 procedure. In this method, 
facilities multiply the amount of lime produced at each kiln and the 
amount of calcined byproducts/wastes at the kiln by an emission factor. 
The emission factor is derived based on facility specific chemical 
analysis of the CaO and magnesium oxide (MgO) content of the lime 
produced at the kiln. To assess the composition of the lime and 
calcined byproduct/waste product, facilities would send samples to an 
off-site laboratory for analysis on a monthly basis following the 
procedures described in the National Lime Association's method 
protocol, along with the procedures in ASTM C25-06, ``Standard Test 
Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated 
Lime'' (incorporated by reference, see proposed 40 CFR 98.7). This 
third output approach is also consistent with 1605(b)'s ``A'' rated 
approach and EU Emission Trading System's calculation B method.
    We compared the various methods for estimating process-related 
CO2 emissions. In general, the IPCC output methods are less 
certain, as they involve multiplying production data by emission and 
correction factors for lime kiln dust that are likely default values 
based on purity assumptions (i.e. the total CaO and MgO content of the 
lime products). In contrast, the input method is more certain as it 
involves measuring the consumption of each carbonate input and 
calculating purity fractions. According to the 2006 IPCC Guidelines, 
the uncertainty involved in the carbonate input approach for the IPCC 
Tier 3 method is 1 to 3 percent and the uncertainty involved in using 
the default emission factor and lime kiln dust correction factor for 
the Tier 1 and Tier 2 production-based approaches is 15 percent. 
However, IPCC states that the major source of uncertainty in the above 
approaches is the CaO content of the lime produced.
    Proposed Option. Under this proposed rule, if you are using an 
existing CEMS that meets the requirements outlined in proposed 40 CFR 
part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C to 
estimate both combustion and process CO2 emissions. Also, 
you would refer to proposed 40 CFR part 98, subpart C to estimate 
combustion-related CH4 and N2O emissions.
    Under this proposed rule, if you do not have CEMS that meet the 
conditions outlined in proposed 40 CFR part 98, subpart C, you would 
use the National Lime Association method in this section of the 
preamble to calculate process-related CO2 emissions. Refer 
to proposed 40 CFR part 98, subpart C specifically for procedures to 
estimate combustion-related CO2, CH4 and 
N2O emissions.
    We are proposing the National Lime Association's output-based 
procedure because this method is already in use by U.S. facilities and 
the improvement in accuracy compared to default approaches can be 
achieved at minimal additional cost. The measurement of production 
quantities is common practice in the industry and is usually measured 
through the use of scales or weigh belts so additional costs to the 
industry are not anticipated. The primary additional burden for 
facilities would include conducting a CaO and MgO analysis of each lime 
product on a monthly basis (to be averaged on an annual basis). 
However, approximately two thirds of the lime manufacturing facilities 
in the U.S. are already undertaking sampling efforts to meet reporting 
goals set forth by the National Lime Association.
    We request comment on the advantages and disadvantages of the IPCC 
Tier 3 method and supporting documentation. After consideration of 
public comments, we may promulgate the IPCC Tier 3 input-based 
procedure, the National Lime Association output-based procedure, or a 
combination based on additional information that is provided.
    The various approaches to monitoring GHG emissions are elaborated 
in the Lime Manufacturing TSD (EPA-HQ-OAR-2008-0508-019).
4. Selection of Procedures for Estimating Missing Data
    It is assumed that a facility would be able to supply facility-
specific production data. Since the likelihood for missing data is low 
because businesses closely track production, 100 percent data 
availability is required for lime production (by type) in the proposed 
rule. If analysis for the CaO and MgO content of the lime product are 
unavailable or ``missing'', facility owners or operators would 
substitute a data value that is the average of the quality-assured 
values of the parameter immediately before and immediately after the 
missing data period.
5. Selection of Data Reporting Requirements
    We propose that in addition to stationary fuel combustion GHG 
emissions, you report annual CO2 emissions for each kiln. In 
addition, for each kiln we are proposing that facilities report the 
following data used as the basis of the calculations to assist in 
verification of estimates, checks for reasonableness, and other data 
quality considerations for process emissions: Annual lime production 
and production capacity, emission factor by lime type, and number of 
operating hours in the calendar year. A full list of data to be 
reported is included in proposed 40 CFR part 98, subparts A and S.
6. Selection of Records That Must be Retained
    Maintaining records of the information used to determine the 
reported GHG emissions are necessary to enable us to verify that the 
GHG emissions monitoring and calculations were done correctly. In 
addition to the data to be reported, we are proposing that the 
facilities maintain records of the calculation of emission factors, 
results of the monthly chemical composition analyses, total lime 
production for each kiln by month and type, total annual calcined 
byproducts/wastes produced by each kiln averaged from monthly data, and 
correction factor for byproducts/waste products for each kiln. A full 
list of records that must be retained onsite is included in proposed 40 
CFR part 98, subparts A and S.

T. Magnesium Production

1. Definition of the Source Category
    Magnesium is a high-strength and light-weight metal that is 
important for the manufacture of a wide range of products and 
materials, such as portable electronics, automobiles, and other 
machinery. The U.S. accounts for less than 10 percent of world primary

[[Page 16524]]

magnesium production but is a significant importer of magnesium and 
producer of cast parts. The production and processing of magnesium 
metal under common practice results in emissions of SF6. For 
further information, see the Magnesium Production TSD (EPA-HQ-OAR-2008-
0508-020).
    The magnesium metal production (primary and secondary) and casting 
industry typically uses SF6 as a cover gas to prevent the 
rapid oxidation and burning of molten magnesium in the presence of air. 
A dilute gaseous mixture of SF6 with dry air and/or 
CO2 is blown over molten magnesium metal to induce and 
stabilize the formation of a protective crust. A small portion of the 
SF6 reacts with the magnesium to form a thin molecular film 
of mostly magnesium oxide and magnesium fluoride. The amount of 
SF6 reacting in magnesium production and processing is under 
study but is presently assumed to be negligible. Thus, all 
SF6 used is presently assumed to be emitted into the 
atmosphere.
    Cover gas systems are typically used to protect the surface of a 
crucible of molten magnesium that is the source for a casting operation 
and to protect the casting operation itself (e.g., ingot casting). 
SF6 has been used in this application in most parts of the 
world for the last twenty years. Due to increasing awareness of the GWP 
of SF6, the magnesium industry has begun exploring climate-
friendly alternative melt protection technologies. At this time the 
leading alternatives include HFC-134a, a fluorinated ketone (FK 5-1-12, 
C3F7C(O)C2F5), and dilute 
sulfur dioxide (SO2). The application of the fluorinated 
alternatives mentioned here may generate byproduct emissions of concern 
including PFCs. We are proposing that magnesium production and 
processing facilities report process emissions of SF6, HFC-
134a, FK 5-1-12, and CO2.
    Total U.S. emissions of SF6 from magnesium production 
and processing in the U.S. were estimated to be 3.2 metric tons 
CO2e in 2006. Primary and secondary production activities at 
3 facilities accounted for about 64 percent of total emissions, or 2 
metric tons CO2e. Approximately 20 magnesium die casting 
facilities in the U.S. accounted for more than 30 percent, or more than 
0.9 metric tons CO2e of total magnesium-related 
SF6 emissions. Other smaller casting activities such as sand 
and permanent mold casting accounted for the remaining magnesium-
related emissions of SF6. The term ``metal processed'' used 
here is defined as the mass of magnesium melted to cast or create 
parts. This should not be confused with the mass of finished magnesium 
parts because varying amounts of the metal may be lost as scrap when 
performing casting operations.
2. Selection of Reporting Threshold
    We considered emissions thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e as well as 
capacity based thresholds as shown in Tables T-1 and T-2 of this 
preamble.

                                           Table T-1. Threshold Analysis for Mg Production Based On Emissions
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Total                             Emissions covered              Facilities covered
                                                            nationwide      Nationwide   ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr               emissions       number of
                                                            metric tons     facilities      Metric tons       Percent       Facilities        Percent
                                                              CO2e/Yr                         CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................       3,200,000              13       2,954,559              92              13             100
10,000..................................................       3,200,000              13       2,939,741              92              11              85
25,000..................................................       3,200,000              13       2,939,741              92              11              85
100,000.................................................       3,200,000              13       2,872,982              90               9              69
--------------------------------------------------------------------------------------------------------------------------------------------------------
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
  production levels.


                                     Table T-2. Threshold Analysis for Mg Production Based On Mg Production Capacity
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Total                             Emissions covered              Facilities Covered
                                                            nationwide                   ---------------------------------------------------------------
             Capacity threshold level Mg/yr                  emissions       Number of
                                                            metric tons     facilities      Metric tons       Percent       Facilities        Percent
                                                              CO2e/Yr                         CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
26......................................................       3,200,000              13       2,954,559              92              13             100
262.....................................................       3,200,000              13       2,949,732              92              12              92
656.....................................................       3,200,000              13       2,949,732              92              12              92
2,622...................................................       3,200,000              13       2,780,717              87               9              69
--------------------------------------------------------------------------------------------------------------------------------------------------------
We believe that there are additional facilities than the 13 listed above, however, we do not have sufficient information to estimate emissions or
  production levels.

    Under the proposed rule, magnesium metal production and parts 
casting facilities would have to report their total GHG emissions if 
those emissions exceeded 25,000 metric tons CO2e. This 
threshold covers all currently identified operating U.S. primary and 
secondary magnesium producers and most die casters, accounting for over 
99 percent of emissions from these source categories.
    The proposed emissions threshold of 25,000 metric tons 
CO2e is equal to emissions of 1,046 kg of SF6; 
19,231 kg of HFC-134a; or 25,000,000 kg of CO2 or FK 5-1-2. 
Other emission threshold options that we considered were 1,000 metric 
tons CO2e, 10,000 metric tons CO2e, and 100,000 
metric tons CO2e. The 10,000 metric tons CO2e 
emission threshold yielded results identical to those of the proposed 
option.
    We also considered capacity-based thresholds of 26, 262, 656, and 
2,622 metric tons, based on 100 percent capacity utilization and an 
SF6 emission rate of 1.6 kg SF6 per metric ton of 
magnesium produced or processed. This emission factor represents the 
sum of (1) the average of the emission factors reported for secondary 
production and die casting through our magnesium Partnership (excluding 
outliers), and (2)

[[Page 16525]]

the standard deviation of those emission factors. The 1.6 kg-per-ton 
factor is higher than most, though not all, of the emission factors 
reported, which ranged from 0.7 to 7 kg/ton Mg in 2006. The resulting 
capacity thresholds yielded results very similar to those of the 
emission-based thresholds.
    The emissions based threshold was selected over the capacity based 
threshold for several reasons. The emissions based threshold is simple 
to evaluate because magnesium production and processing facilities can 
use readily available data regarding consumption of SF6 and 
would also possess similar data for alternatives such as HFC-134a as 
these are phased-in over time. To determine whether they exceeded the 
thresholds, magnesium facilities would multiply the total consumption 
of each of these gases by a GWP-unit conversion factor that could be 
compared to the 25,000 metric ton threshold. The equation for this 
calculation is provided in the proposed regulatory text.
    The emissions-based threshold of 25,000 metric tons CO2e 
also takes into account the variability in cover gas identities, usage 
rates, and process conditions. Alternatives to SF6 have 
considerably lower GWPs than SF6. In facilities where 
SF6 is used, the usage rate can vary by an order of 
magnitude depending on the casting process and operating conditions. 
Therefore, cover gas emissions are not well predicted by production 
capacity. Because emissions of each cover gas are assumed to equal use, 
and facilities are expected to track gas use in the ordinary course of 
business, facilities should have little difficulty determining whether 
or not they must report under this rule. For a full discussion of the 
threshold analysis, please refer to the Magnesium Production TSD (EPA-
HQ-OAR-2008-0508-020). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    We reviewed a wide range of protocols and guidance in developing 
this proposal, including the 2006 IPCC Guidelines, EPA's SF6 
Emission Reduction Partnership for the Magnesium Industry, the U.S. GHG 
Inventory, DOE 1605(b), EPA's Climate Leaders Program, and TCR.
    The methods described in these protocols and guidance were similar 
to the methods described by the IPCC Guidelines and the U.S. GHG 
Inventory methodology. These methods range from a Tier 1 approach, 
based on default consumption factors per unit Mg produced or processed, 
to a Tier 3 approach based on facility-specific measured emissions 
data.
    Under this proposed rule, if you are required to use an existing 
CEMS to meet the requirements outlined in proposed 40 CFR part 98, 
subpart C, you would be required to use CEMS to estimate CO2 
emissions. Where the CEMS capture all combustion- and process-related 
CO2 emissions you would be required to follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
proposed 40 CFR part 98, subpart C to estimate CO2 
emissions. Also, refer to proposed 40 CFR part 98, subpart C to 
estimate combustion-related CH4 and N2O 
emissions.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
the CEMS would not adequately account for process emissions, you would 
be required to follow the proposed monitoring method discussed below. 
The proposed method outlined below accounts for process-related 
SF6, HFC-134a, FK 5-1-12, and CO2 emissions. 
Refer to proposed 40 CFR part 98, subpart C specifically for procedures 
to estimate combustion-related CO2, CH4 and 
N2O emissions.
    The proposed method for monitoring SF6, HFC-134a, FK 5-
1-12, and CO2 cover gas emissions from magnesium production 
and processing is similar to the Tier 2 approach in the 2006 IPCC 
Guidelines for magnesium production. This approach is based on 
facility-specific information on cover gas consumption and assumes that 
all gases consumed are emitted. This methodology applies to any cover 
gas that is a GHG, including SF6, CO2, HFC-134a 
and FK 5-1-12.
    We propose three options for measuring gas consumption:
    1. Weighing gas cylinders as they are brought into and out of 
service allowing a facility to accurately track the actual mass of gas 
used.
    2. Using a mass flow meter to continuously measure the mass of 
global warming gases used.
    3. Performing a facility level mass balance for all global warming 
gases used at least once annually. Using this approach, a facility 
would review its gas purchase records and inventory to determine actual 
mass of gas used and subtract a 10 percent default heel factor to 
account for residual gas in cylinders returned to the gas suppliers.
    When weighing cylinders to determine cover gas consumption, 
facilities would weigh all gas cylinders that are returned to the gas 
supplier, or have the gas supplier weigh the cylinders, to determine 
the residual gas still in the cylinder. The weight of residual gas 
would be subtracted from the weight of gas delivered to determine gas 
consumption. Gas suppliers can provide detailed monthly spreadsheets 
with exact residual gas amounts returned.
    Facilities would be required to follow several procedures to ensure 
the quality of the consumption data. These procedures could be readily 
adopted, or would be based on information that is already collected for 
other reasons. Facilities would be required to track specific cylinders 
leaving and entering storage with check-out and weigh-in sheets and 
procedures. Scales used for weighing cylinders and mass flow meters 
would need to be accurate to within 1 percent of true mass, and would 
be periodically calibrated. Facilities would calculate the facility 
usage rate, compare it to known default emission rates and historical 
data for the facility, and investigate any anomalies in the facility 
usage rate. Finally, facilities would need to have procedures to ensure 
that all production lines have provided information to the manager 
compiling the emissions report, if this is not already handled through 
an electronic inventory system.
    We are not proposing IPCC's Tier 1 or 3 methodologies for 
calculating emissions. Although the Tier 1 methodology is 
straightforward, the default consumption factor for the SF6 
usage rate is significantly uncertain due to the variability in 
production processes and operating conditions. The Tier 3 methodology 
of conducting facility-specific measurements of emissions to account 
for potential cover gas destruction and byproduct formation is the most 
accurate, but also poses significant economic challenges for 
implementation because of the cost of direct emission measurements.
4. Selection of Procedures for Estimating Missing Data
    In general, it is unlikely that cover gas consumption data would be 
missing. Facilities are expected to know the quantities of cover gas 
that they consume because facility operations rely on accurate 
monitoring and tracking of costs. Facilities would possess invoices 
from gas suppliers during a given year and many facilities currently 
track the weight of SF6 consumed by weighing individual 
cylinders prior to replacement.
    However, where cover gas consumption information is missing, we

[[Page 16526]]

propose that facilities estimate emissions by multiplying production by 
the average cover gas usage rate (kg gas per ton of magnesium produced 
or processed) from the most recent period when operating conditions 
were similar to those for the period for which the data are missing, 
i.e., using the same cover gas concentrations and flow rates and, if 
applicable, casting parts of a similar size.
5. Selection of Data Reporting Requirements
    Facilities would be required to report total facility GHG emissions 
and emissions by process type: Primary production, secondary 
production, die casting, or other type of casting. For total facility 
and process emissions, emissions would be reported in metric tons of 
SF6, HFC-134a, FK 5-1-12, and CO2 (used as a 
carrier gas).
    Along with their total emissions from cover gas use, facilities 
would be required to submit supplemental data (as well as the 
supplemental data required in the combustion and calcination sections) 
including the type of production processes (e.g., primary, secondary, 
die casting), mass of magnesium produced or processed in metric tons 
for each process type, cover gas flow rate and composition, and mass of 
any CO2 used as a carrier gas during reporting period.
    If data were missing, facilities would be required to report the 
length of time the data were missing, the method used to estimate 
emissions in their absence, and the quantity of emissions thereby 
estimated. Facilities would also submit an explanation for any 
significant change in emission rate. Examples could include 
installation of new melt protection technology that would account for 
reduced emissions in any given year, or occurrence or repair of leaks 
in the cover gas delivery system.
    These non-emissions data need to be reported because they are 
needed to understand the nature of the facilities for which data are 
being reported and for verifying the reasonableness of the reported 
data.
6. Selection of Records That Must Be Retained
    We are proposing that magnesium producers and processors be 
required to keep records documenting adherence to the QA/QC 
requirements specified in the proposed rule. These records would 
include: Check-out and weigh-in sheets and procedures for cylinders; 
accuracy certifications and calibration records for scales; residual 
gas amounts in cylinders sent back to suppliers; and invoices for gas 
purchases and sales.
    These records are being specified because they are the values that 
are used to calculate the GHG emissions that are reported. They are 
necessary to verify that the GHG emissions monitoring and calculations 
were done correctly and accurately.

U. Miscellaneous Uses of Carbonates

1. Definition of the Source Category
    Limestone (CaCO3), dolomite 
(CaMg(CO3)2) and other carbonates are inputs used 
in a number of industries. The most common applications of limestone 
are used as a construction aggregate (78 percent of specified national 
consumption in 2006), the chemical and metallurgy industries (18 
percent), and other specialized applications (three percent). The 
breakdown of reported specified dolomite national consumption was 
similar to that of limestone, with the majority being used as a 
construction aggregate, and a lesser but still significant percent used 
in chemical and metallurgical applications.
    For some of these applications, the carbonates undergo a 
calcination process in which the carbonate is sufficiently heated, 
generating CO2 as a by-product. Examples of such emissive 
applications include limestone used as a flux or purifier in 
metallurgical furnaces, as a sorbent in flue gas desulfurization 
systems for utility and industrial plants, and as a raw material in the 
production of mineral wool or magnesium. Non-emissive applications 
include limestone used in producing poultry grit and asphalt filler.
    The use of limestone, dolomite and other carbonates is purely an 
industrial process source of emissions. Emissions from the use of 
carbonates in the manufacture of cement, ferroalloys, glass, iron and 
steel, lead, lime, pulp and paper, and zinc are elaborated in proposed 
40 CFR part 98, subparts H, K, N, Q, R, S, AA and GG, since they are 
relatively significant emitters. Facilities that include only these 
source categories would not need to follow the methods presented in 
this section to estimate emissions from the miscellaneous use of 
carbonates. The methods presented in this section should be used by 
facilities that use carbonates in source categories other than those 
listed above, but which are covered by the proposed rule.
    As estimated in the U.S. GHG Inventory, national process emissions 
from other limestone and dolomite uses (i.e., excluding cement, lime, 
and glass manufacturing) were 7.9 million metric tons CO2e 
in 2006 (0.1 percent of U.S. emissions). CH4 and 
N2O are not released from the calcination of carbonates.
    For additional background information on the use of limestone, 
dolomite and other carbonates, please refer to the Miscellaneous Uses 
of Carbonates TSD (EPA-HQ-OAR-2008-0508-021).
2. Selection of Reporting Threshold
    A separate threshold analysis is not proposed for uses of 
limestone, dolomite and other carbonates as these emissions occur in a 
large number of facilities across a range of industries. We propose 
that facilities with source categories identified in proposed 40 CFR 
98.2(a)(1) or (a)(2) consuming limestone, dolomite and other carbonates 
calculate the relevant emissions from their facility, including 
emissions from calcination of carbonates, to determine whether they 
surpass the proposed threshold for that industry. Data were not 
available to quantify emissions from the calcination of carbonates 
across all industries; therefore, these emissions were considered where 
appropriate in the thresholds analysis for the respective industries.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from the use of limestone, dolomite and other carbonates 
(e.g., the 2006 IPCC Guidelines, U.S. Inventory, DOE 1605(b), the EU 
Emissions Trading System, and the Australian National Greenhouse Gas 
Reporting Program). These methodologies all rely on measuring the 
consumption of carbonate inputs, but differ in their use of default 
values. The range of default values reflect differing assumptions of 
the carbonate weight fraction in process inputs; for example, the 2006 
IPCC Guidelines Tier 1 and 2 assume that carbonate inputs are 95 
percent pure (i.e., 95 percent of the mass consumed is carbonate), 
whereas the Australian Program assumes a default purity of 90 percent 
for limestone, 95 percent for dolomite, and 100 percent for magnesium 
carbonate.
    We propose that facilities estimate process emissions by measuring 
the type and quantity of carbonate input to a kiln or furnace and 
applying the appropriate emissions factors for the carbonates consumed. 
In order to assess the composition of the carbonate input, we propose 
that facilities send samples of each carbonate consumed to an off-site 
laboratory for a chemical analysis of

[[Page 16527]]

the carbonate weight fraction on an annual basis. Emission factors are 
based on stoichiometry and are presented in Table U-1 of this preamble. 
You would also be required to determine the calcination fraction for 
each of the carbonate-based minerals consumed, using an appropriate 
test method. The calcination fraction is the fraction of carbonate that 
is volatilized in the process. A calcination fraction of 1.0 could over 
estimate CO2 emissions. You would refer to proposed 40 CFR 
part 98, subpart C specifically for procedures to estimate combustion-
related CO2, CH4 and N2O emissions.

          Table U-1. CO2 Emission Factors for Common Carbonates
------------------------------------------------------------------------
                                                           CO2 emission
                                                              factor
                                                           (metric tons
                 Mineral name--carbonate                  ons CO2/metric
                                                              tons on
                                                            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............................       * 0.44197
Rhodochrosite--MnCO3....................................         0.38286
Sodium Carbonate/Soda Ash--Na2CO3.......................         0.41492
------------------------------------------------------------------------
* This is an average of the range provided by the 2006 IPCC Guidelines.

    We also considered but decided not to propose simplified methods 
(similar to IPCC Tier 1 and 2) for quantifying process-related 
emissions from this source, which assumes that limestone and dolomite 
are the only carbonates consumed, and allow for the use of default 
fractions of the two carbonates (85 percent for limestone and 15 
percent for dolomite). Default factors do not account for variability 
in relative carbonate consumption by other sources and therefore 
inaccurately estimate emissions.
    The various approaches to monitoring GHG emissions are elaborated 
in the Miscellaneous Uses of Carbonates TSD (EPA-HQ-OAR-2008-0508-021).
4. Selection of Procedures for Estimating Missing Data
    We propose that 100 percent data availability is required. If 
chemical analysis on the fraction calcination of carbonates consumed 
were lost or missing, the analysis would have to be repeated. It is 
assumed that a facility would be able to supply facility-specific 
carbonate consumption data. The likelihood for missing data is low, as 
businesses closely track production inputs.
5. Selection of Data Reporting Requirements
    We propose that facilities report annual CO2 emissions 
from carbonate consumption. In addition, we are proposing that 
facilities submit the following data which are the basis of the 
emission calculation and are needed for us to understand the emissions 
data and assess the reasonableness of the reported emissions: annual 
carbonate consumption (in metric tons, by carbonate) and the total 
fraction of calcination achieved (for each carbonate). A full list of 
data to be reported is included in proposed 40 CFR part 98, subparts A 
and U.
6. Selection of Records That Must Be Retained
    We propose that facilities retain records on monthly carbonate 
consumption (by type), annual records on the fraction of calcination 
achieved (by carbonate type), and results of the annual chemical 
analysis. These records provide values that are directly used to 
calculate the emissions that are reported and are necessary to allow 
determination of whether the GHG emissions monitoring and calculations 
were done correctly. A full list of records that must be retained 
onsite is included in proposed 40 CFR part 98, subparts A and U.

V. Nitric Acid Production

1. Definition of the Source Category
    Nitric acid is an inorganic chemical that is used in the 
manufacture of nitrogen-based fertilizers, adipic acid, and explosives. 
Nitric acid is also used for metal etching and processing of ferrous 
metals. A nitric acid production facility uses oxidation, condensation, 
and absorption to produce a weak nitric acid (30 to 70 percent in 
strength). The production process begins with the stepwise catalytic 
oxidation of ammonia (NH3) through nitric oxide (NO) to 
nitrogen dioxide (NO2) at high temperatures. Then the 
NO2 is absorbed in and reacted with water (H2O) 
to form nitric acid (HNO3).
    According to a facility-level inventory for 2006, there are 45 
nitric acid production facilities operating in 25 States with a total 
of 65 process lines. These facilities represent the best available data 
at the time of this rulemaking. Using the facility-level inventory, 
production levels for 2006 have been estimated at 6.6 million metric 
tons of nitric acid and indicate an estimated 17.7 million metric tons 
CO2e of process-related emissions (this represents the 
CO2 equivalent of N2O emissions, which is the 
primary process-related GHG). Nitric Acid process emissions were 
estimated in the U.S. GHG Inventory at 15.4 million metric tons 
CO2e in 2006 or 0.2 percent of total U.S. GHG emissions. The 
main reason for the difference in estimates is that the methodology of 
the U.S. Inventory assumed 20 percent of the nitric acid facilities 
were using nonselective catalytic reduction as an N2O 
abatement technology. The facility-level analysis showed that only five 
percent of the nitric acid facilities are using nonselective catalytic 
reduction.
    Stationary combustion emissions were not estimated at the source 
category level in the U.S. GHG Inventory. Stationary combustion 
emissions at nitric acid facilities may be associated with other 
chemical production processes as well (such as adipic acid production, 
phosphoric acid production, or ammonia manufacturing).
    For additional background information on nitric acid production, 
please refer to the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-
022).
2. Selection of Reporting Threshold
    In developing the proposed threshold for nitric acid production, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e. Table V-1 of 
this preamble illustrates the emissions and facilities that would be 
covered under these various thresholds.

                            Table V-1. Threshold Analysis for Nitric Acid Production
----------------------------------------------------------------------------------------------------------------
                                                  Process N2O emissions covered        Facilities  covered
                                                      (metric tons CO2e/yr)     --------------------------------
   N2O emission threshold (metric tons CO2e)    --------------------------------
                                                     Number          Percent         Number          Percent
----------------------------------------------------------------------------------------------------------------
1,000..........................................      17,731,650             100              45            100
10,000.........................................      17,723,576            99.9              44             97.8

[[Page 16528]]

 
25,000.........................................      17,706,259            99.9              43             95.6
100,000........................................      17,511,444            98.8              40             88.9
----------------------------------------------------------------------------------------------------------------

    We are proposing all nitric acid facilities report in order to 
simplify the rule and avoid the need for each facility to calculate and 
report whether it exceeds the threshold value. Facility-level emissions 
estimates based on plant production suggests that all known facilities, 
except two, exceed the 25,000 metric tons CO2e threshold. 
When facility-level production data were not known, capacity data were 
used along with a utilization factor of 70 percent. The utilization 
factor is based on total 2006 nitric acid production from the U.S. 
Census Bureau and capacity estimates from publicly available sources.
    This analysis, however, only took into account process-related 
emissions, as combustion-related emissions were not available. Had 
combustion-related emissions been included, it is probable that 
additional facilities would have been covered at each threshold. An 
``all in'' threshold captures 100 percent of emissions without 
significantly increasing the number of facilities required to report. 
Finally, the cost of reporting using the proposed monitoring method 
does not vary significantly between the four different emissions based 
thresholds.
    For a full discussion of the threshold analysis, please refer to 
the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating these emissions (e.g. 
2006 IPCC Guidelines, U.S. GHG Inventory, DOE 1605(b), TCR, and EPA 
NSPS). These methodologies coalesce around the five options discussed 
below.
    Option 1. Apply default emission factors to total facility 
production of nitric acid using the Tier 1 approach established by the 
IPCC. The emissions are calculated using the total production of nitric 
acid and the highest international default emission factor available in 
the 2006 IPCC Guidelines, based on technology type. It also assumes no 
abatement of N2O emissions.
    Option 2. Apply default emission factors on a site-specific basis 
using the Tier 2 approach established by the IPCC. This approach is 
also consistent with the DOE 1605(b) ``B'' rated approach. These 
emission factors are dependent on the type of nitric acid process used, 
the type of abatement technology used, and the production activity. The 
process-related N2O emissions are then estimated by 
multiplying the emission factor by the production level of nitric acid 
(on a 100 percent acid basis).
    Option 3. Follow the Tier 3 approach established by IPCC using 
periodic direct monitoring of N2O emissions to determine the 
relationship between nitric acid production and the amount of 
N2O emissions; i.e., develop a site-specific emissions 
factor. The site-specific emission factor would be determined from an 
annual measurement or a single annual stack test. The site-specific 
emissions factor developed from this test and production rate (activity 
level) is used to calculate N2O emissions. After the initial 
test, annual testing of N2O emissions would be required each 
year to estimate the emission factor and applied to production to 
estimate emissions. The yearly testing would assist in verifying the 
emission factor. Testing would also be required whenever the production 
rate is changed by more than 10 percent from the production rate 
measured during the most recent performance test.
    Option 4. Follow the approach used by the Nitric Acid NSPS (40 CFR 
part 60, subpart G). This option would require monitoring 
NOX emissions on a continuous basis and measuring 
N2O emissions to establish a site-specific emission factor 
that relates NOX emissions to N2O emissions. The 
emission factor would then be used to estimate N2O emissions 
based on continuous reading of NOX emissions. Periodic 
measurement would also be required to verify the emission factor over 
time. Testing would also be required whenever the production rate is 
changed by more than 10 percent from the production rate measured 
during the most recent performance test.
    Option 5. Follow the Tier 3 approach established by IPCC using 
continuous monitoring. Use CEMS to directly measure N2O 
concentration and flow rate to directly determine N2O 
emissions. CEMS that measure N2O emissions directly are 
available, but the nitric acid industry is currently using only 
NOX CEMS.
    Proposed Option. We are proposing Option 3 to quantify 
N2O process emissions from all nitric acid facilities. You 
would be required to follow the requirements in proposed 40 CFR part 
98, subpart C to estimate emissions of CO2, CH4 
and N2O from stationary combustion. We identified Options 3, 
4, and 5 as the approaches providing the highest certainty and the best 
site-specific estimates. These three options span the range of types of 
methodologies currently used that do not apply default values. These 
options all use site-specific approaches that would provide insight 
into different levels of emissions caused by site-specific differences 
in process operation and abatement technologies. Option 3 requires an 
annual test of N2O emissions and the establishment of a 
site-specific emissions factor that relates N2O emissions 
with the nitric acid production rate.
    Options 4 and 5 are similar in that both use continuous monitoring 
to calculate N2O emissions. Option 5 directly measures the 
N2O emissions. Option 4 uses continuous measurement of 
NOX emissions to estimate a site-specific emission factor 
that relates NOX emissions to N2O emissions. The 
emission factor is then used to estimate N2O emissions based 
on continuous readings of NOX emissions.
    Option 5 would provide the highest certainty of the three options 
and capture the smallest changes in N2O emissions over time, 
but N2O CEMS are not currently in use in the industry and 
there is no existing EPA method for certifying N2O CEMS. 
Option 3 and Option 4 use site-specific emission factors so the margin 
of error is much lower than using default emission factors. Option 4 
would require the use of NOX CEMS that are already in use by

[[Page 16529]]

many nitric acid facilities to automatically capture and record any 
changes in NOX emissions over time. However, NOX 
CEMS only capture emissions of NO and NO2 and not 
N2O. Therefore they would not be useful in the estimation of 
N2O emissions from nitric acid production facilities. 
Although the amount of NOX and N2O emissions from 
nitric acid production may be directly related, direct measurement of 
NOX does not automatically correlate to the amount of 
N2O in the same exhaust stream. Periodic testing of 
N2O emissions (Option 3) would not indicate changes in 
emissions over short periods of time, but does offer direct measurement 
of the GHG.
    We request comment, along with supporting documentation, on the 
advantages and disadvantages of using Options 3, 4 and 5. After 
consideration of public comments, EPA may promulgate one or more of 
these options or a combination based on the additional information that 
is provided.
    We decided not to propose Options 1 and 2 because the use of 
default values and lack of direct measurements results in a high level 
of uncertainty. Although different default emissions factors have been 
developed for different processes (e.g., low pressure, high pressure) 
and abatement techniques, the use of these default values is more 
appropriate for sector wide or national total estimates than for 
determining emissions from a specific facility. Site-specific emission 
factors are more appropriate for reflecting differences in process 
design and operation.
    The various approaches to monitoring GHG emissions are elaborated 
in the Nitric Acid Production TSD (EPA-HQ-OAR-2008-0508-022).
4. Selection of Procedures for Estimating Missing Data
    For process sources that use a site-specific emission factor, no 
missing data procedures would apply because the site-specific emission 
factor is derived from an annual performance test and used in each 
calculation. The emission factor would be multiplied by the production 
rate, which is readily available. If the test data is missing or lost, 
the test would have to be repeated. Therefore, 100 percent data 
availability would be required.
5. Selection of Data Reporting Requirements
    We propose that facilities report annual N2O emissions 
(in metric tons) from each nitric acid production line. In addition, we 
propose that facilities submit the following data to understand the 
emissions data and verify the reasonableness of the reported emissions. 
The data should include annual nitric acid production capacity, annual 
nitric acid production, type of nitric acid production process used, 
number of operating hours in the calendar year, the emission rate 
factor used, abatement technology used (if applicable), abatement 
technology efficiency, and abatement utilization factor.
    Capacity, actual production, and operating hours would be helpful 
in determining the potential for growth in the nitric acid industry. 
The production rate can be determined through sales records or by 
direct measurement using flow meters or weigh scales. This industry 
generally measures the production rate as part of normal operating 
procedures.
    A list of abatement technologies would be helpful in assessing how 
widespread the use of abatement is in the nitric acid source category, 
cataloging any new technologies that are being used, and documenting 
the amount of time that the abatement technologies are being used.
    A full list of data to be reported is included in proposed 40 CFR 
part 98, subparts A and V.
6. Selection of Records That Must Be Retained
    We propose that facilities maintain records of significant changes 
to process, N2O abatement technology used, abatement 
technology efficiency, abatement utilization factor (percent of time 
that abatement system is operating), annual testing of N2O 
emissions, calculation of the site-specific emission rate factor, and 
annual production of nitric acid.
    A full list of records that must be retained onsite is included in 
proposed 40 CFR part 98, subparts A and V.

W. Oil and Natural Gas Systems

1. Definition of the Source Category
    The U.S. petroleum and natural gas industry encompasses hundreds of 
thousands of wells, hundreds of processing facilities, and over a 
million miles of transmission and distribution pipelines. This section 
of the preamble identifies relevant facilities and outlines methods and 
procedures for calculating and reporting fugitive emissions (as defined 
in this section) of CH4 and CO2 from the 
petroleum and natural gas industry. Methods and reporting procedures 
for emissions resulting from natural gas or crude oil combustion in 
prime movers such as compressors are covered under Section V.C of this 
preamble.
    The natural gas segment involves production, processing, 
transmission and storage, and distribution of natural gas. The U.S. 
also receives, stores, and processes imported liquefied natural gas 
(LNG) at LNG import terminals. The petroleum segment involves crude oil 
production, transportation and refining.
    The relevant facilities covered in this section are offshore 
petroleum and natural gas production facilities, onshore natural gas 
processing facilities (including gathering/boosting stations), onshore 
natural gas transmission compression facilities, onshore natural gas 
storage facilities, LNG storage facilities, and LNG import facilities. 
Fugitive emissions from petroleum refineries are proposed for inclusion 
in the rulemaking, but these emissions are addressed in the petroleum 
refinery section (Section V.Y) of this preamble. Under this section of 
the preamble, we seek comment on methods for reporting fugitive 
emissions data from: On-shore petroleum and natural gas production and 
natural gas distribution facilities.
    For this rulemaking, fugitive emissions from the petroleum and 
natural gas industry are defined as unintentional equipment emissions 
and intentional or designed releases of CH4-and/or 
CO2-containing natural gas or hydrocarbon gas (not including 
combustion flue gas) from emissions sources including, but not limited 
to, open ended lines, equipment connections or seals to the atmosphere. 
In the context of this rule, fugitive emissions also mean 
CO2 emissions resulting from combustion of natural gas in 
flares. These emissions are hereafter collectively referred to as 
``fugitive emissions'' or ``emissions''. We seek comment on the 
proposed definition of fugitives, which is derived from the definition 
of fugitive emissions outlined in the 2006 IPCC Guidelines for National 
GHG Inventories, and is often used in the development of GHG 
inventories. We acknowledge that there are multiple definitions for 
fugitives, for example, defining the term fugitives to include ``those 
emissions which could not reasonably pass through a stack, chimney, 
vent, or other functionally-equivalent opening''. According to the 2008 
U.S. Inventory, total fugitive emissions of CH4 and 
CO2 from the natural gas and petroleum industry were 160 
metric tons CO2e in 2006. The breakdown of these fugitive 
emissions is shown in Table W-1 of this preamble.

[[Page 16530]]



  Table W-1. Fugitive Emissions From Petroleum and Natural Gas Systems
                                 (2006)
------------------------------------------------------------------------
                                                  Fugitive     Fugitive
                    Sector                          CH4          CO2
                                                 (MMTCO2e)    (MMTCO2e)
------------------------------------------------------------------------
Natural Gas Systems\1\........................        102.4         28.5
Petroleum Systems.............................         28.4          0.3
------------------------------------------------------------------------
\1\ Emissions account for Natural Gas STAR Partner Reported Reductions.

    Natural gas system fugitive CH4 emissions resulted from 
onshore and offshore natural gas production facilities (27 percent); 
onshore natural gas processing facilities (12 percent); natural gas 
transmission and underground natural gas storage, including LNG import 
and LNG storage facilities (37 percent); and natural gas distribution 
facilities (24 percent). Natural gas segment fugitive CO2 
emissions were primarily from onshore natural gas processing facilities 
(74 percent), followed by onshore and offshore natural gas production 
facilities (25 percent), and less than 1 percent each from natural gas 
transmission and underground natural gas storage and distribution 
facilities.\80\
---------------------------------------------------------------------------

    \80\ The distribution of CO2 emissions is slightly 
misleading due to current U.S. Inventory convention which assumes 
that all CO2 from natural gas processing facilities is 
emitted. In fact, approximately 7,000 metric tons CO2e is 
captured and used for EOR.
---------------------------------------------------------------------------

    Petroleum segment fugitive CH4 emissions are primarily 
associated with onshore and offshore crude oil production facilities 
(>97 percent of emissions) and petroleum refineries (2 percent) and are 
negligible in crude oil transportation facilities (<0.5 percent). 
Petroleum segment fugitive CO2 emissions are only estimated 
for onshore and offshore production facilities.
    With over 160 different sources of fugitive CH4 and 
CO2 emissions in the petroleum and natural gas industry, 
identifying those sources most relevant for a reporting program was a 
challenge. We developed a decision tree analysis and undertook a 
systematic review of each emissions source category included in the 
Inventory of U.S. GHG Emissions and Sinks. In determining the most 
relevant fugitive emissions sources for inclusion in this reporting 
program, we applied the following criteria: the coverage of fugitive 
emissions for the source category as a whole, the coverage of fugitive 
emissions per unit of the source category, feasibility of a viable 
monitoring method, including direct measurement and engineering 
estimations, and an administratively manageable number of reporting 
facilities.
    Another factor we considered in assessing the applicability of 
certain petroleum and natural gas industry fugitive emissions in a 
mandatory reporting program is the definition of a facility. In other 
words, what physically constitutes a facility? This definition is 
important to determine who the reporting entity would be, and to ensure 
that delineation is clear and double counting of fugitive emissions is 
minimized. For some segments of the industry, identifying the facility 
is clear since there are physical boundaries and ownership structures 
that lend themselves to identifying scope of reporting and responsible 
reporting entities (e.g., onshore natural gas processing facilities, 
natural gas transmission compression facilities, and offshore petroleum 
and natural gas facilities). In other segments of the industry, such as 
the pipelines between compressor stations, and more particularly 
onshore petroleum and natural gas production, such distinctions are not 
straightforward. In defining a facility, we reviewed current 
definitions used in the CAA and ISO definitions, consulted with 
industry, and reviewed current regulations relevant to the industry. 
The full results of our assessment can be found in the Oil and Natural 
Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).
    Following is a brief discussion of the proposed selected and 
excluded sources based on our analysis. Additional information can be 
found in the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-
023). This section of the preamble addresses only fugitive emissions. 
Combustion-related emissions are discussed in Section V.C of this 
preamble.
    Offshore Petroleum and Natural Gas Production Facilities. Offshore 
petroleum and natural gas production includes both shallow and deep 
water wells in both U.S. State and Federal waters. These offshore 
facilities house equipment to extract hydrocarbons from the ocean floor 
and transport it to storage or transport vessels or onshore. Fugitive 
emissions result from sources housed on the platforms.
    In 2006, offshore petroleum and natural gas production fugitive 
CO2 and CH4 emissions accounted for 5.6 million 
metric tons CO2e. The primary sources of fugitive emissions 
from offshore petroleum and natural gas production are from valves, 
flanges, open-ended lines, compressor seals, platform vent stacks, and 
other source components. Flare stacks account for the majority of 
fugitive CO2 emissions.
    Offshore petroleum and natural gas production facilities are 
proposed for inclusion due to the fact that this represents 
approximately 4 percent of emissions from the petroleum and natural gas 
industry, ``facilities'' are clearly defined, and major fugitive 
emissions sources can be characterized by direct measurement or 
engineering estimation.
    Onshore Natural Gas Processing Facilities. Natural gas processing 
includes gathering/ boosting stations that dehydrate and compress 
natural gas to be sent to natural gas processing facilities, and 
natural gas processing facilities that remove NGLs and various other 
constituents from the raw natural gas. The resulting ``pipeline 
quality'' natural gas is injected into transmission pipelines. 
Compressors are used within gathering/ boosting stations and also 
natural gas processing facilities to adequately pressurize the natural 
gas so that it can pass through all of the processes into the 
transmission pipeline.
    Fugitive CH4 emissions from reciprocating and 
centrifugal compressors, including centrifugal compressor wet and dry 
seals, reciprocating compressor rod packing, and all other compressor 
fugitive emissions, are the primary CH4 emission source from 
this segment. The majority of fugitive CO2 emissions come 
from acid gas removal vent stacks, which are designed to remove 
CO2 and hydrogen sulfide, when present, from natural gas. 
While these are the major fugitive emissions sources in natural gas 
processing facilities, if other potential fugitive sources such as 
flanges, open-ended lines and threaded fittings are present at your 
facility you would need to account for them if reporting under proposed 
40 CFR part 98, subpart W. For this subpart you would assume no capture 
of CO2 because capture and

[[Page 16531]]

transfer of CO2 offsite would be calculated in accordance 
with Section V.PP of this preamble and reported separately.
    Onshore natural gas processing facilities are proposed for 
inclusion due to the fact that these operations represent a significant 
emissions source, approximately 25 percent of emissions from the 
natural gas segment. ``Facilities'' are easily defined and major 
fugitive emissions sources can be characterized by direct measurement 
or engineering estimation.
    Onshore Natural Gas Transmission Compression Facilities and 
Underground Natural Gas Storage Facilities. Natural gas transmission 
compression facilities move natural gas throughout the U.S. natural gas 
transmission system. Natural gas is also injected and stored in 
underground formations during periods of low demand (e.g., spring or 
fall) and withdrawn, processed, and distributed during periods of high 
demand (e.g., winter or summer). Storage compressor stations are 
dedicated to gas injection and extraction at underground natural gas 
storage facilities.
    Fugitive CH4 emissions from reciprocating and 
centrifugal compressors, including centrifugal compressor wet and dry 
seals, reciprocating compressor rod packing, and all other compressor 
fugitive emissions, are the primary CH4 emission source from 
natural gas transmission compression stations and underground natural 
gas storage facilities. Dehydrators are also a significant source of 
fugitive CH4 emissions from underground natural gas storage 
facilities. While these are the major fugitive emissions sources in 
natural gas transmission, other potential fugitive sources include, but 
are not limited to, condensate tanks, open-ended lines and valve seals.
    Transmission compression facilities and underground natural gas 
storage facilities are proposed for inclusion due to the fact that 
these operations represent a significant emissions source, 
approximately 24 percent of emissions from the natural gas segment; 
``facilities'' are easily defined, and major fugitive sources can be 
characterized by direct measurement or engineering estimation.
    LNG Import and LNG Storage Facilities. The U.S. imports natural gas 
in the form of LNG, which is received, stored, and, when needed, 
processed and compressed at LNG import terminals. LNG storage 
facilities liquefy and store natural gas from transmission pipelines 
during periods of low demand (e.g., spring or fall) and vaporize for 
send out during periods of high demand (e.g., summer and winter)
    Fugitive CH4 and CO2 emissions from 
reciprocating and centrifugal compressors, including centrifugal 
compressor wet and dry seals, reciprocating compressor rod packing, and 
all other compressor fugitive emissions, are the primary CH4 
and CO2 emission source from LNG storage facilities and LNG 
import facilities. Process units at these facilities can include 
compressors to liquefy natural gas (at LNG storage facilities), re-
condensers, vaporization units, tanker unloading equipment (at LNG 
import terminals), transportation pipelines, and/or pumps.
    LNG storage facilities and LNG import facilities are proposed for 
inclusion due to the fact that fugitive emissions from these operations 
represent approximately 1 percent of emissions from natural gas 
systems. LNG storage ``facilities'' are defined as facilities that 
store liquefied natural gas in above ground storage tanks. LNG import 
terminal ``facilities'' are defined as facilities that receive imported 
LNG, store it in storage tanks, and release re-gasified natural gas for 
transportation.
    Onshore Petroleum and Natural Gas Production. Similar to offshore 
petroleum and natural gas production, the onshore petroleum and natural 
gas production segment uses wells to draw raw natural gas, crude oil, 
and associated gas from underground formations. The most dominant 
sources of fugitive CH4 and CO2 emissions 
include, but are not limited to, natural gas driven pneumatic valve and 
pump devices, field crude oil and condensate storage tanks, chemical 
injection pumps, releases and flaring during well completion and 
workovers, and releases and flaring of associated gas.
    We considered proposing the reporting of fugitive CH4 
and CO2 emissions from onshore petroleum and natural gas 
production in the rule. Onshore petroleum and natural gas production is 
responsible for the largest share of fugitive CH4 and 
CO2 emissions from petroleum and natural gas industry (27 
percent of total emissions). However, this segment is not proposed for 
inclusion primarily due to the unique difficulty in defining a 
``facility'' in this sector and correspondingly determining who would 
be responsible for reporting.
    Given the significance of fugitive emissions from the onshore 
petroleum and natural gas production, we would like to take comment on 
whether we should consider inclusion of this source category in the 
future. Specifically, we would like to take comment on viable ways to 
define a facility for onshore oil and gas production and to determine 
the responsible reporter. In addition, the Agency also requests comment 
on the merits and/or concerns with the corporate basin level reporting 
approach under consideration for onshore oil and gas production, as 
outlined below.
    One approach we are considering for including onshore petroleum and 
natural gas production fugitive emissions in this reporting rule is to 
require corporations to report emissions from all onshore petroleum and 
natural gas production assets at the basin level. In such a case, all 
operators in a basin would have to report their fugitive emissions from 
their operations at the basin-level. For such a basin-level facility 
definition, we may propose reporting of only the major fugitive 
emissions sources; i.e., natural gas driven pneumatic valve and pump 
devices, well completion releases and flaring, well blowdowns, well 
workovers, crude oil and condensate storage tanks, dehydrator vent 
stacks, and reciprocating compressor rod packing. Under this scenario, 
we might suggest that all operators would be subject to reporting, 
perhaps exempting small businesses, as defined by the Small Business 
Administration.
    This approach could substantially reduce the reporting complexity 
and require individual companies that produce crude oil and/or natural 
gas in each basin to be responsible for reporting emissions from all of 
their onshore petroleum and natural production operations in that 
basin, including from rented sources, such as compressors. In cases 
where hydrocarbons or emissions sources are jointly owned by more than 
one company, each company would report emissions equivalent to its 
portion of ownership.
    We considered other options in defining a facility such as 
individual wellheads or aggregating all emissions sources prior to 
compression as a facility. However, such definitions result in complex 
reporting requirements and are difficult to implement.
    We are seeking comments on reporting of the major fugitive 
emissions sources by corporations at the basin level for onshore 
petroleum and natural gas production.
    Petroleum and Natural Gas Pipeline Segments. Natural gas 
transmission involves high pressure, large diameter pipelines that 
transport gas long distances from field production and natural gas 
processing facilities to natural gas distribution pipelines or large 
volume customers such as power

[[Page 16532]]

plants or chemical plants. Crude oil transportation involves pump 
stations to move crude oil through pipelines and loading and unloading 
crude oil tanks, marine vessels, and rails.
    The majority of fugitive emissions from the transportation of 
natural gas occur at the compressor stations, which are already 
proposed for inclusion in the rule and discussed above. We do not 
propose to include reporting of fugitive emissions from natural gas 
pipeline segments between compressor stations, or crude oil pipelines 
in the rulemaking due to the dispersed nature of the fugitive 
emissions, the difficulty in defining pipelines as a facility, and the 
fact that once fugitives are found, they are generally fixed quickly, 
not allowing time for monitoring and direct measurement of the 
fugitives.
    Natural Gas Distribution. In the natural gas distribution segment, 
high-pressure gas from natural gas transmission pipelines enter ``city 
gate'' stations, which reduce the pressure and distribute the gas 
through primarily underground mains and service lines to individual end 
users. Distribution system CH4 and CO2 emissions 
result mainly from fugitive emissions from gate stations (metering and 
regulating stations) and vaults (regulator stations), and fugitive 
emissions from underground pipelines. At gate stations and vaults, 
fugitive CH4 emissions primarily come from valves, open-
ended lines, connectors, and natural gas driven pneumatic valve 
devices.
    Although fugitive emissions from a single vault, gate station or 
segment of pipeline in the natural gas distribution segment may not be 
significant, collectively these fugitive emissions sources contribute a 
significant share of fugitive emissions from natural gas systems.
    We do not propose to include the natural gas distribution segment 
of the natural gas industry in this rulemaking due to the dispersed 
nature of the fugitive emissions and difficulty in defining a facility 
such that there would be an administratively manageable number of 
reporters.
    One approach to address the concern with defining a facility for 
distribution would be to require corporate-level reporting of fugitive 
emissions from major sources by distribution companies. We seek comment 
on this and other ways of reporting fugitive emissions from the 
distribution sector.
    Crude Oil Transportation. Crude oil is commonly transported by 
barge, tanker, rail, truck, and pipeline from production operations and 
import terminals to petroleum refineries or export terminals. Typical 
equipment associated with these operations are storage tanks and 
pumping stations. The major sources of CH4 and 
CO2 fugitive emissions include releases from tanks and 
marine vessel loading operations.
    We do not propose to include the crude oil transportation segment 
of the petroleum and natural gas industry in this rulemaking due to its 
small contribution to total petroleum and natural gas fugitive 
emissions, accounting for much less than 1 percent, and the difficulty 
in defining a facility.
2. Selection of Reporting Threshold
    We propose that facilities with emissions greater than 25,000 
metric tons CO2e per year be subject to reporting. This 
threshold is applicable to all oil and natural gas system facilities 
covered by this subpart: Offshore petroleum and natural gas production 
facilities, onshore natural gas processing facilities, including 
gathering/boosting stations; natural gas transmission compression 
facilities, underground natural gas storage facilities; LNG storage 
facilities; and LNG import facilities.
    To identify the most appropriate threshold level for reporting of 
fugitive emissions, we conducted analyses to determine fugitive 
emissions reporting coverage and facility reporting coverage at four 
different levels of threshold; 1,000 metric tons CO2e per 
year, 10,000 metric tons CO2e per year, 25,000 metric tons 
CO2e per year, and 100,000 metric tons CO2e per 
year. Table W-2 of this preamble provides coverage of emissions and 
number of facilities reporting at each threshold level for all the 
industry segments under consideration for this rule.

                            Table W-2. Threshold Analysis for Fugitive Emissions From the Petroleum and Natural Gas Industry
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Total                                   Total emissions covered     Facilities covered
                                                              national                                    by thresholds \s\    -------------------------
                                                             emissions    Total number    Threshold  --------------------------
                      Source category                        #a (metric   of facilities     level       (metric
                                                             tons CO2e                                 tons CO2e     Percent       Number      Percent
                                                             per year)                                 per year)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Offshore Petroleum & Gas Production Facilities............   10,162,179           2,525        1,000    9,783,496           96        1,021           40
                                                                                              10,000    6,773,885           67          156            6
                                                                                              25,000    5,138,076           51           50            2
                                                                                             100,000    3,136,185           31            4          0.5
Natural Gas Processing Facilities.........................   50,211,548             566        1,000   50,211,548          100          566          100
                                                                                              10,000   49,207,852           98          394           70
                                                                                              25,000   47,499,976           95          287           51
                                                                                             100,000   39,041,555           78          125           22
Natural Gas Transmission Compression Facilities...........   73,198,355           1,944        1,000   73,177,039          100        1,659           85
                                                                                              10,000   71,359,167           97         1311           67
                                                                                              25,000   63,835,288           87          874           45
                                                                                             100,000   30,200,243           41          216           11
Underground Natural Gas Storage Facilities................   11,719,044             398        1,000   11,702,256          100          346           87
                                                                                              10,000   10,975,728           94          197           49
                                                                                              25,000    9,879,247           84          131           33
                                                                                             100,000    5,265,948           45           35            9
LNG Storage Facilities....................................    1,956,435             157        1,000    1,940,203           99           54           34
                                                                                              10,000    1,860,314           95           39           25
                                                                                              25,000    1,670,427           85           29           18
                                                                                             100,000      637,477           33            3            2
LNG Import Facilities.....................................    1,896,626               5        1,000    1,896,626          100            5          100

[[Page 16533]]

 
                                                                                              10,000    1,895,153         99.9            4           80
                                                                                              25,000    1,895,153         99.9            4           80
                                                                                             100,000    1,895,153         99.9            4           80
--------------------------------------------------------------------------------------------------------------------------------------------------------
\a\ The emissions include fugitive CH4 and CO2 and combusted CO2, N2O, and CH4 gases. The emissions for each industry segment do not match the 2008 U.S.
  Inventory either because of added details in the estimation methodology or use of a different methodology than the U.S. Inventory. For additional
  discussion, refer to the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).

    A proposed threshold of 25,000 metric tons CO2e applied 
to only those emissions sources listed in Table W-2 of this preamble 
captures approximately 81 percent of fugitive CH4 and 
CO2 emissions from the entire oil and natural gas industry, 
while capturing only a small fraction of total facilities. For 
additional information, please refer to the Oil and Natural Gas Systems 
TSD (EPA-HQ-OAR-2008-0508-023). For specific information on costs, 
including unamortized first year capital expenditures, please refer to 
section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating fugitive emissions from 
oil and natural gas operations, including the 2006 IPCC Guidelines, 
U.S. GHG Inventory, DOE 1605(b), and corporate industry protocols 
developed by the American Petroleum Institute, the Interstate Natural 
Gas Association of America, and the American Gas Association. The 
methodologies proposed vary by the emissions source, for example 
fugitive emissions versus vented emissions, versus emissions from 
flares (all of which are considered ``fugitive'' emissions in this 
rulemaking). Generally, approaches range from direct measurement (e.g., 
high volume samplers), to engineering equations (where applicable), to 
simple emission factor approaches based on national default factors.
    Proposed Option. We propose that facilities would be required to 
detect fugitive emissions from the identified emissions sources 
proposed in this rulemaking, and then quantify emissions using either 
engineering equations or direct measurement.
    Fugitive emissions from all affected emissions sources at the 
facility, whether in operating condition or on standby, would have to 
be monitored on an annual basis. The proposed monitoring method would 
depend on the fugitive emissions sources in the facility to be 
monitored. Each fugitive emissions source would be required to be 
monitored using one of the two monitoring methods: (1) Direct 
measurement or (2) engineering estimation. Table W-3 of this preamble 
provides the proposed fugitive emissions source and corresponding 
monitoring methods. General guidance on the monitoring methods is given 
below.

       Table W-3. Source Specific Monitoring Methods and Emissions
                             Quantification
------------------------------------------------------------------------
                                                          Emissions
       Emission source          Monitoring method      quantification
                                      type                 methods
------------------------------------------------------------------------
Acid Gas Removal Vent Stacks  Engineering           Simulation software.
                               estimation.
Blowdown Vent Stacks........  Engineering           Gas law and
                               estimation.           temperature,
                                                     pressure, and
                                                     volume between
                                                     isolation valves.
Centrifugal Compressor Dry    Direct measurement..  (1) High volume
 Seals.                                              sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Centrifugal Compressor Wet    Direct measurement..  (1) High volume
 Seals.                                              sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Compressor Fugitive           Direct measurement..  (1) High volume
 Emissions.                                          sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Dehydrator Vent Stacks......  Engineering           Simulation software.
                               estimation.
Flare Stacks................  Engineering           Velocity meter and
                               estimation and        mass/volume
                               direct measurement.   equations.
Natural Gas Driven Pneumatic  (1) Engineering       (1) Manufacturer
 Pumps.                        estimation, or (2)    data, equipment
                               Direct measurement.   counts, and amount
                                                     of chemical pumped,
                                                     or (2) Calibrated
                                                     bag.
Natural Gas Driven Pneumatic  (1) Engineering       (1) Manufacturer
 Manual Valve Actuator         estimation, or (2)    data and actuation
 Devices.                      Direct measurement.   logs, or (2)
                                                     Calibrated bag.
Natural Gas Driven Pneumatic  (1) Engineering       (1) Manufacturer
 Valve Bleed Devices.          estimation, or (2)    data and equipment
                               Direct measurement.   counts, or (2) High
                                                     volume sampler, or
                                                     (3) Calibrated bag,
                                                     or (4) Meter.
Non-pneumatic Pumps.........  Direct measurement..  High volume sampler.
Offshore Platform Pipeline    Direct measurement..  High volume sampler.
 Fugitive Emissions.
Open-ended Lines............  Direct measurement..  (1) High volume
                                                     sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Pump Seals..................  Direct measurement..  (1) High volume
                                                     sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Facility Fugitive Emissions.  Direct measurement..  High volume sampler.

[[Page 16534]]

 
Reciprocating Compressor Rod  Direct measurement..  (1) High volume
 Packing.                                            sampler, or (2)
                                                     Calibrated bag, or
                                                     (3) Meter.
Storage Tanks...............  (1) Engineering       (1) Meter, or (2)
                               estimation and        Simulation
                               direct measurement,   software, or (3)
                               or (2) Engineering    Vasquez-Beggs
                               estimation.           Equation.
------------------------------------------------------------------------

a. Direct Measurement
    Fugitive emissions detection and measurement are both required in 
cases where direct measurement is being proposed. Infrared fugitive 
emissions detection instruments are capable of detecting fugitive 
CH4 emissions, or Toxic Vapor Analyzers or Organic Vapor 
Analyzers can be used by the operator to detect fugitive natural gas 
emissions. These instruments detect the presence of hydrocarbons in the 
natural gas fugitive emissions stream. They do not detect any pure 
CO2 fugitive emissions. However, because all the sources 
proposed for monitoring have natural gas fugitive emissions that have 
CH4 as one of its constituents, there is no need for a 
separate detection instrument for separately detecting CO2 
fugitive emissions. The only exception to this is fugitive emissions 
from acid gas removal vent stacks where the predominant constituent of 
the fugitive emissions is CO2. Engineering estimation is 
proposed for this source, and therefore there is no need for detection 
of fugitive emissions from acid gas removal vent stacks.
    In the Oil and Natural Gas Systems TSD (EPA-HQ-OAR-2008-0508-023), 
we describe a particular method based on practicality of application. 
For example, using Toxic Vapor Analyzers or Organic Vapor Analyzers on 
very large facilities is not as cost effective as infrared fugitive 
emissions detection instruments. We propose that irrespective of the 
method used for fugitive natural gas emissions detection, the survey 
for detection must be comprehensive. This means that, on an annual 
basis, the entire population of emissions sources proposed for fugitive 
emissions reporting has to be surveyed at least once. When selecting 
the appropriate emissions detection instrument, it is important to note 
that certain instruments are best suited for particular applications 
and circumstances. For example, some optical infrared fugitive 
emissions detection instruments may not perform well in certain weather 
conditions or with certain colored backgrounds.
    Infrared fugitive emissions detection instruments are able to scan 
hundreds of source components at once, allowing for efficient detection 
of emissions at large facilities; however, infrared fugitive emissions 
detection instruments are typically much more expensive than other 
options. Organic Vapor Analyzers and Toxic Vapor Analyzers are not able 
to detect fugitive emissions from many components as quickly; however, 
for small facilities this may provide a less costly alternative to 
infrared fugitive emissions detection without requiring overly 
burdensome labor to perform a comprehensive fugitive emissions survey. 
We propose that operators choose the instrument from the choices 
provided in the proposed rule that is best suited for their 
circumstance. Further information is contained in the Oil and Natural 
Gas Systems TSD (EPA-HQ-OAR-2008-0508-023).
    For direct measurement, we have proposed that high volume samplers, 
meters (such as rotameters, turbine meters, hot wire anemometers, and 
others), and/or calibrated bags be designated for use. However, if 
fugitive emissions exceed the maximum range of the proposed monitoring 
instrument, you would be required to use a different instrument option 
that can measure larger magnitude emissions levels. For example, if a 
high volume sampler is pegged by a fugitive emissions source, then 
fugitive emissions would be required to be directly measured using 
either calibrated bagging or a meter. In the Oil and Natural Gas 
Systems TSD (EPA-HQ-OAR-2008-0508-023), we discuss multiple options for 
measurement where the range of emissions measurement instruments is 
seen as an issue. CH4 and CO2 fugitive emissions 
from the natural gas fugitive emissions stream can be calculated using 
the composition of natural gas.
b. Engineering Estimation
    Engineering estimation has been proposed for calculating 
CH4 and CO2 fugitive emissions from sources where 
the variable in the emissions magnitude on an annual basis is the 
number of times the source releases fugitive CH4 and 
CO2 emissions to the atmosphere. For example, when a 
compressor is taken offline for maintenance, the volume of fugitive 
CH4 and CO2 emissions that are released is the 
same during each release and the only variable is the number of times 
the compressor is taken offline. Also, engineering estimates have been 
proposed where safety concerns prohibit the use of direct measurement 
methods. For example, sometimes the temperature of the fugitive 
emissions stream for glycol dehydrator vent stacks is too high for 
operators to safely measure fugitive emissions. Based on these 
principles, we propose that direct measurement is mandatory unless 
there is a demonstrated and documented safety concern or frequency of 
fugitive emission releases is the only variable in emissions, at which 
time engineering estimates can be applied.
c. Alternative Monitoring Methods Considered
    Before proposing the monitoring methods discussed above, we 
considered four additional measurement methods. The use of Method 21 or 
the use of activity and emission factors were considered for fugitive 
emissions detection and measurement. Although Toxic Vapor Analyzers and 
Organic Vapor Analyzers were considered but not proposed for fugitive 
emissions direct measurement they are acceptable for fugitive emissions 
detection.
    Method 21. This is the reference method for equipment leak 
detection and repair regulations for volatile organic carbon (VOC) 
emissions under several 40 CFR part 60 emission standards. Method 21 of 
40 CFR part 60 Appendix A-7 determines a concentration at a point or 
points of emissions expressed in parts per million concentration of 
combustible hydrocarbon in the air stream of the instrument probe. This 
concentration is then compared to the ``action level'' in the 
referenced 40 CFR part 60 regulation to determine if a leak is present. 
Although Method 21 was not developed for this purpose, it may allow for 
better emission estimation than the overall average emission factors 
that have been published for equipment leaks. Quantification of air 
emissions from equipment leaks is generally done using EPA published 
guidelines which correlate the measured concentration to a VOC mass 
emission rate based on extensive measurements of air emissions from 
leaking equipment. The

[[Page 16535]]

correlations are statistically determined for a very large population 
of similar components, but not very accurate for single leaks or small 
populations. Therefore, Method 21 was not found suitable for fugitive 
emissions measurement under this reporting rule. However, we are 
seeking comments on this conclusion, and whether Method 21 should be 
permitted as a viable alternative method to estimate emissions for 
sources where it is currently required for VOC emissions.
    Activity Factor and Emissions Factor for All Sources. Fugitive 
CH4 emissions factors for all of the fugitive emissions 
sources proposed for inclusion in the rule are available in a study 
that was conducted in 1992.81 82 There have been no 
subsequent comparable studies published to replace or revise the 
fugitive emissions estimates available from this study. However, some 
petroleum and natural gas industry operations have changed 
significantly with the introduction of new technologies and improved 
operating and maintenance practices to mitigate fugitive emissions. 
These are not reflected in the fugitive emissions factors available. 
Also, in many cases the fugitive emissions factors are not 
representative of emission levels for individual sources or are not 
relevant to certain operations because the estimates were based on 
limited or no field data. Hence, they are not representative of the 
entire country or specific petroleum and natural gas facilities and 
fugitive emissions sources such as tanks and wells. Therefore, we did 
not propose this method for estimation of the fugitive emissions for 
reporting.
---------------------------------------------------------------------------

    \81\ EPA/GRI (1996) Methane Emissions from the Natural Gas 
Industry. Harrison, M., T. Shires, J. Wessels, and R. Cowgill, 
(eds.). Radian International LLC for National Risk Management 
Research Laboratory, Air Pollution Prevention and Control Division, 
Research Triangle Park, NC. EPA-600/R-96-080a.
    \82\ EPA (1999) Estimates of Methane Emissions from the U.S. Oil 
Industry (Draft Report). Prepared by ICF International. Office of 
Air and Radiation, U.S. Environmental Protection Agency. October 
1999.
---------------------------------------------------------------------------

    Default fugitive CO2 emissions factors are available 
only for whole segments of the industry (e.g., natural gas processing), 
and are not available for individual sources. Further, these are 
international default factors, which have a high uncertainty associated 
with them and are not appropriate for facility-level reporting.
    Mass Balance for Quantification. We considered, but decided not to 
propose, the use of a mass balance approach for quantifying emissions. 
This approach would take into account the volume of gas entering a 
facility and the amount exiting the facility, with the difference 
assumed to be emitted to the atmosphere. This is most often discussed 
for emissions estimation from the transportation segment of the 
industry. For transportation, the mass balance is often not recommended 
because of the uncertainties surrounding meter readings and the large 
volumes of throughput relative to fugitive emissions. We are seeking 
feedback on the use of a mass balance approach and the applicability to 
each sector of the oil and gas industry (production, processing, 
transmission, and distribution) as a potential alternative to component 
level leak detection and quantification.
    Toxic Vapor Analyzers and Organic Vapor Analyzers for Emissions 
Measurement. Toxic Vapor Analyzer and Organic Vapor Analyzer 
instruments quantify the concentration of combustible hydrocarbon from 
the fugitive emission in the air stream, but do not directly quantify 
the volumetric or mass emissions. The instrument probe rarely ingests 
all of the natural gas from a fugitive emissions source. Therefore, 
these instruments are used primarily for fugitive emissions leak 
detection. For the proposed rule, fugitive CH4 emissions 
detection by more cost-effective detection technologies such as 
infrared fugitive emissions detection instruments in conjunction with 
direct measurement methodologies such as the high volume sampler, 
meters and calibrated bags is deemed a better overall approach to 
fugitive emissions quantification than the labor intensive Organic 
Vapor Analyzers and Toxic Vapor Analyzers, which do not quantify 
volumetric or mass fugitive emissions.
d. Outstanding Issues on Which We Seek Comments
    The proposed rule does not indicate a particular threshold for 
detection above which emissions measurement is required. This is 
because the different emissions detection instruments proposed have 
different levels and types of detection capabilities. Hence the 
magnitude of actual emissions can only be determined after measurement. 
This, however, does not serve the purpose of this rule in limiting 
burden on emissions reporting. A facility can have hundreds of small 
emissions (as low as 3 grams per hour) and it might not be practical to 
measure all such small emissions for reporting.
    To address this issue we intend to incorporate one of the following 
two approaches in the final rule.
    The first approach would provide performance standards for fugitive 
emissions detection instruments and usage such that all instruments 
follow a common minimum detection threshold. We may propose the use of 
the Alternate Work Practice to Detect Leaks from Equipment standards 
for infrared fugitive emissions detection instruments being developed 
by EPA. In such a case all detected emissions from components subject 
to this rule would require measurement and reporting.
    The second approach would provide an emissions threshold above 
which the source would be identified as an ``emitter'' for emissions 
detection using Organic Vapor Analyzers or Toxic Vapor Analyzers. When 
using infrared fugitive emissions detection instruments all sources 
subject to this rule that have emissions detected would require 
emissions quantification. Alternatively, the operator would be given a 
choice of first detecting emissions sources using the infrared 
detection instrument and then verifying for measurement status using 
the emissions definition for Organic Vapor Analyzers or Toxic Vapor 
Analyzers.
    We are seeking comments on using the two options discussed above 
for determining emission sources requiring measurement of emissions.
    Some fugitive emissions by nature occur randomly within the 
facility. Therefore, there is no way of knowing when a particular 
source started emitting. This proposed rule requires annual fugitive 
emissions detection and measurement. The emissions detected and 
measured would be assumed to continue throughout the reporting year, 
unless no emissions detection is recorded at an earlier and/or later 
point in the reporting period. We recognize that this may not 
necessarily be true in all cases and that emissions reported would be 
higher than actual. Therefore, we are seeking comments on how this 
issue can be resolved without resulting in additional reporting burden 
to the facilities.
    The petroleum and natural gas industry is already implementing 
voluntary fugitive emissions detection and repair programs. Such 
voluntary programs are useful, but pose an accounting challenge with 
respect to emissions reporting for this rule. The proposed rule 
requires annual detection and measurement of fugitive emissions. This 
approach does not preclude any facility from performing emissions 
detection and repair prior to the official detection, measurement, and 
reporting of emissions for this rule. We are seeking comments on how to 
avoid under-reporting of emissions as a result of a preliminary, ``un-
official'' emissions

[[Page 16536]]

survey and repair exercise ahead of the ``official'' annual survey.
    Fugitive emissions from a compressor are a function of the mode in 
which the compressor is operating. Typically, a compressor station 
consists of several compressors with one (or more) of them on standby 
based on system redundancy requirements and peak delivery capacity. 
Fugitive emissions at compressors in standby mode are significantly 
different than those from compressors that are operating. The rule 
proposes annual direct measurement of fugitive emissions. This may not 
adequately account for the different modes in which a particular 
compressor is operating through the reporting period. We are soliciting 
input on a method to measure emissions from each mode in which the 
compressor is operating, and the period of time operated in that mode, 
that would minimize reporting burden. Specifically, given the 
variability of these measured emissions, EPA requests comment on 
whether engineering estimates or other alternative methods that account 
for total emissions from compressors, including open ended lines, could 
address this issue of operating versus standby mode.
    The fugitive emissions measurement instruments (i.e. high volume 
sampler, calibrated bags, and meters) proposed for this rule measure 
natural gas emissions. CH4 and CO2 emissions are 
required to be estimated from the natural gas mass emissions using 
natural gas composition appropriate for each facility. For this 
purpose, the proposed rule requires that facilities use existing gas 
composition estimates to determine CH4 and CO2 
components of the natural gas emissions (flare stack and storage tank 
fugitive emissions are an exception to this general rule). We have 
determined that these gas composition estimates are available from 
facilities reporting to this rule. We are seeking comments on whether 
this is a practical assumption. In the absence of gas composition, an 
alternative proposal would be to require the periodic measurement of 
the required gas composition for speciation of the natural gas mass 
emissions into CH4 and CO2 mass emissions.
4. Selection of Procedures for Estimating Missing Data
    The proposal requires data collection for a single source a minimum 
of once a year. If data are lost or an error occurs during fugitive 
emissions direct measurement, the operator should carry out the direct 
measurement a second time to obtain the relevant data point(s). 
Similarly, engineering estimates must account for relevant source 
counts and frequency of fugitive emissions releases throughout the 
year. There should not be any missing data for estimating fugitive 
emissions from petroleum and natural gas systems.
5. Selection of Data Reporting Requirements
    We propose that fugitive emissions from the petroleum and natural 
gas industry be reported on an annual basis. The reporting should be at 
a facility level with fugitive emissions being reported at the source 
type level. Fugitive emissions from each source type could be reported 
at an aggregated level. In other words, process unit-level reporting 
would not be required. For example, a facility with multiple 
reciprocating compressors could report fugitive emissions from all 
reciprocating compressors as an aggregate number. Since the proposed 
monitoring method is fugitive emissions detection and measurement at 
the source level, we determined that reporting at an aggregate source 
type level is feasible.
    Fugitive emissions from all sources proposed for monitoring, 
whether in operating condition or on standby, would have to be 
reported. Any fugitive emissions resulting from standby sources would 
be separately identified from the aggregate fugitive emissions.
    The reporting facility would be required to report the following 
information to us as a part of the annual fugitive emissions reporting: 
fugitive emissions monitored at an aggregate source level for each 
reporting facility, assuming no carbon capture and transfer offsite; 
the quantity of CO2 captured for use and the end use, if 
known; fugitive emissions from standby sources; and activity data for 
each aggregate source type level.
    Additional data are proposed to be reported to support 
verification: Engineering estimate of total component count; total 
number of compressors and average operating hours per year for 
compressors, if applicable; minimum, maximum and average throughput per 
year; specification of the type of any control device used, including 
flares; and detection and measurement instruments used. For offshore 
petroleum and natural gas production facilities, the number of 
connected wells, and whether they are producing oil, gas, or both is 
proposed to be reported. For compressors specifically, we proposed that 
the total number of compressors and average operating hours per year be 
reported.
    A full list of data to be reported is included in proposed 40 CFR 
part 98, subparts A and W.
6. Selection of Records That Must Be Retained
    The reporting facility shall retain relevant information associated 
with the monitoring and reporting of fugitive emissions to us, as 
follows; throughput of the facility when the fugitive emissions direct 
measurement was conducted, date(s) of measurement, detection and 
measurement instruments used, if any, results of the leak detection 
survey, and inputs and outputs to calculations or simulation software 
runs where the proposed monitoring method requires engineering 
estimation.
    A full list of records to be retained is included inproposed 40 CFR 
part 98, subparts A and W.

X. Petrochemical Production

1. Definition of the Source Category
    The petrochemical industry consists of numerous processes that use 
fossil fuel or petroleum refinery products as feedstocks. For this 
proposed GHG reporting rule, the reporting of process-related emissions 
in the petrochemical industry is limited to the production of 
acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene 
oxide, and methanol. The petrochemicals source category includes 
production of all forms of carbon black (e.g., furnace black, thermal 
black, acetylene black, and lamp black) because these processes use 
petrochemical feedstocks; bone black is not considered to be a form of 
carbon black because it is not produced from petrochemical feedstocks. 
The rule focuses on these six processes because production of GHGs from 
these processes has been recognized by the IPCC to be significant 
compared to other petrochemical processes. Facilities producing other 
types of petrochemicals are not subject to proposed 40 CFR part 98, 
subpart X of this reporting rule but may be subject to 40 CFR part 98, 
subpart C, General Stationary Fuel Combustion Sources, or other 
subparts.
    There are 88 facilities operating petrochemical processes in the 
U.S., and 9 of these operate either two or three types of petrochemical 
processes (e.g., ethylene and ethylene oxide). We estimate 
petrochemical production accounts for approximately 55 million metric 
tons CO2e.
    Total GHG emissions relevant to the petrochemical industry 
primarily include process-based emissions and emissions from combustion 
sources. Process-based emissions may be released to the atmosphere from 
process vents, equipment leaks, aerobic biological treatment systems, 
and in some cases, combustion source vents. CH4 may also be 
a process-based

[[Page 16537]]

emission from processes where CH4 is a feedstock (e.g., when 
methanol is produced from synthesis gas that is derived from reforming 
natural gas, some CH4 passes through the process without 
being converted and is emitted).
    Emissions from the burning of process off-gas to supply energy to 
the process are also process-based emissions because the organic 
compounds being burned are derived from the feedstock chemical. These 
emissions are included with other process-based emissions if the mass 
balance monitoring method (described in Section V.X.3 of this preamble) 
is used to estimate process-based emissions, but they are included with 
combustion source emissions if CEMS are used to measure emissions from 
all stacks. Combustion source emissions include CO2, 
CH4, and N2O emissions from combustion of either 
supplemental fuel alone (under the mass balance option) or combustion 
of both supplemental fuels and process off-gas (under the CEMS option). 
This difference in approach for emissions from the combustion of off-
gas is necessary to avoid either double counting or not counting these 
emissions, particularly if off-gas and supplemental fuel are mixed in a 
fuel gas system.
    CH4 emissions from onsite wastewater treatment systems 
(if anaerobic) are another possible source of GHG emissions from the 
petrochemical industry, but these emissions are expected to be small 
because anaerobic wastewater treatment is not common at petrochemical 
facilities. CH4 emissions from onsite wastewater treatment 
systems would be estimated and reported according to the proposed 
procedures in proposed 40 CFR part 98, subpart II.
    The ratio of process-based emissions to supplemental fuel 
combustion emissions varies among the various petrochemical processes. 
For example, process-based emissions dominate for acrylonitrile, 
ethylene, and ethylene oxide processes. Both process-based and 
supplemental fuel combustion emissions are important for carbon black 
and methanol processes. Emissions from supplemental fuel combustion 
predominate for ethylene dichloride processes. Equipment leak and 
wastewater emissions are both estimated to be less than 1 percent of 
the total emissions from petrochemical production.
    For further discussion see the Petrochemical Production TSD (EPA-
HQ-OAR-2008-0508-024).
2. Selection of Reporting Threshold
    We propose that every facility which includes within its boundaries 
methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, 
or carbon black production be subject to the requirements of this 
proposed rule.
    In developing the proposed threshold for petrochemical facilities, 
we considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e. Table X-1 of 
this preamble illustrates the emissions and number of facilities that 
would be covered under the four threshold options.

                                               Table X-1. Threshold Analysis for Petrochemical Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total National                         Emissions covered              Facilities covered
                                                            Emissions,     Total number  ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              metric tons   of  facilities    Metric tons                      Number of
                                                              CO2e/yr                         CO2e/yr         Percent       facilities        Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................      54,830,000              88      54,830,000             100              88             100
10,000..................................................      54,830,000              88      54,820,000           99.98              87            98.9
25,000..................................................      54,830,000              88      54,820,000           99.98              87            98.9
100,000.................................................      54,830,000              88      54,440,000            99.7              84            95.5
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The emissions presented in Table X-1 of this preamble are the total 
emissions associated solely with the production of methanol, 
acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, or carbon 
black, not the total emissions from petrochemical facilities. An 
estimate of the total emissions was difficult to develop because many 
of these facilities contain multiple source categories. For example, 
some petrochemical operations occur at petroleum refineries. Other 
petrochemical manufacturing facilities produce chemicals such as 
ammonia or hydrogen that are also subject to reporting. In addition, 
numerous chemical manufacturing facilities produce other chemicals in 
addition to one or more of the petrochemicals; these facilities may 
have combustion sources associated with these other chemical 
manufacturing processes that are separate from the combustion sources 
for petrochemical processes.
    Based on this analysis, 87 of the 88 petrochemical facilities have 
estimated combustion and process-based GHG emissions that exceed the 
25,000 metric tons CO2e/yr threshold, and 1 facility has 
estimated GHG emissions less than 10,000 metric tons CO2e/
yr. The facility with estimated GHG emissions less than 10,000 metric 
tons CO2e/yr is a carbon black facility. Considering that 
the threshold analysis did not include all types of emissions occurring 
at petrochemical facilities, and the large percentage of facilities 
that were above the various thresholds even when these emissions were 
excluded, EPA proposes that all facilities producing at least one of 
the petrochemicals report. This would simplify the rule and likely 
achieve the same result as having a 25,000 metric tons CO2e 
threshold.
    For a full discussion of the threshold analysis, please refer to 
the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    We reviewed existing domestic and international GHG monitoring 
guidelines and protocols including the 2006 IPCC Guidelines and DOE 
1605(b). Protocols included methods for both CO2 and 
CH4. From this review, we developed the following three 
options that share a number of features with the three Tiers presented 
by IPCC:
    Option 1. Apply default emission factors based on the type of 
process and site-specific activity data (e.g., measured or estimated 
annual production rate). This option is the same as the IPCC Tier 1 
approach.
    Option 2. Perform a carbon balance to estimate CO2 
emissions derived from carbon in feedstocks. Inputs to the carbon 
balance would be the flow and carbon content of each feedstock, and 
outputs would be the flow and carbon content of each product/byproduct. 
Organic liquid wastes that are collected for shipment offsite would 
also be considered an output in the carbon

[[Page 16538]]

balance. The difference between carbon inputs and outputs is assumed to 
be CO2 emissions. This includes all unconverted 
CH4 feedstock that is emitted. In addition, all 
CO2 that is recovered for sale or other use is considered an 
emission for the purposes of reporting for petrochemical processes. 
However, the volume of CO2 would be accounted for separately 
using the procedures in proposed 40 CFR part 98, subpart PP.
    This option would require continuous monitoring of liquid and 
gaseous flows using flow meters, measurement of solid feedstock and 
product flows using scales or other weighing devices, and determination 
of the carbon content of each feedstock and product/byproduct at least 
once per week. Supplemental fuel is not considered to be a feedstock 
because these fuels do not mix with process fluids (except in the 
furnace of a carbon black process) and would be calculated consistent 
with the monitoring methods in proposed 40 CFR part 98, subpart C.
    In addition to using the carbon balance to estimate process-based 
CO2 emissions, this option would require the petrochemical 
facility owner to estimate CO2, CH4, and 
N2O emissions from the combustion of supplemental fuels 
using the monitoring methods in proposed 40 CFR part 98, subpart C, and 
to estimate CH4 emissions from onsite wastewater treatment 
using the monitoring methods in proposed 40 CFR part 98, subpart II.
    Option 3. Direct and continuous measurement of CO2 
emissions from each stack (process vent or combustion source) using a 
CEMS for CO2 concentration and a stack gas volumetric flow 
rate monitor.
    This option also would require the petrochemical facility owner to 
use engineering analyses to estimate flow and carbon content of gases 
discharged to flares using the same procedures described in Section 
V.Y.3 of this preamble for petroleum refineries. Just as at petroleum 
refineries, flares at petrochemical facilities are used to control a 
variety of emissions releases. In addition, the flow and composition of 
gas flared can change significantly. Therefore, the Agency is proposing 
the same methodology for petrochemical flares as for flares at 
petroleum refineries. Please refer to the petroleum refineries section 
(Section V.Y.3 of this preamble) for a discussion of the rationale for 
these procedures.
    We request comment on this approach as well as on descriptions of 
differences in operating conditions for flares at petrochemical 
facilities and refineries that would warrant specification of different 
methodologies for estimating emissions.
    In addition to measuring CO2 emissions from process 
vents and estimating CO2 emissions from flares, this option 
would require the petrochemical facility owner to calculate 
CH4 and N2O emissions from combustion sources 
using the monitoring methods in proposed 40 CFR part 98, subpart C, and 
to calculate CH4 emissions from onsite wastewater treatment 
systems using the monitoring methods in proposed 40 CFR part 98, 
subpart II.
    Proposed Options. Under this proposed rule, if you operate and 
maintain an existing CEMS that measures total CO2 from 
process vents and combustion sources, you would be required to follow 
requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2 emissions from your facility. In such a circumstance, 
you also would be required to estimate CO2, CH4 
and N2O emissions from flares.
    If you do not operate and maintain an existing CEMS that measures 
total CO2 from process vents and combustion sources for your 
facility, the proposed rule permits the use of either Options 2 or 3 
since they account for process-based emissions, combustion source 
emissions, and wastewater treatment system emissions. Process-based 
CO2 emissions are estimated using procedures in proposed 40 
CFR part 98, subpart X; combustion emissions (CO2, 
CH4, and N2O) and wastewater emissions 
(CH4) are calculated using methods in proposed 40 CFR part 
98, subparts C and II, respectively. As discussed earlier, emissions 
from combustion of process off-gas are calculated with other process-
based emissions (only CO2 emissions) under Option 2, but 
they are estimated using methods for combustion sources under Option 3 
(CO2, CH4, and N2O emissions). Option 
2 offers greater flexibility and a lower cost of compliance than Option 
3. However it also has a higher measurement uncertainty.
    Option 3 is expected to have the lowest measurement uncertainty. 
However, using CEMS to monitor all emissions at petrochemical 
facilities would be relatively costly. For emissions estimates produced 
using Option 2, the uncertainty in these estimates is expected to be 
relatively low for most petrochemical processes. For ethylene 
dichloride and ethylene processes, the uncertainty of the carbon 
balance approach may be higher since it is influenced by the 
measurements of inputs and outputs at the facility and the percentage 
of carbon in the final product. Uncertainty may be high where the 
percentage of carbon in the product is close to 100 percent (since 
subtracting one large number for process output from another large 
number for process input results in relatively large uncertainty in the 
difference, even if the uncertainty in the two large numbers is low). 
For the petrochemical processes, we have decided that Option 2 is 
reasonable for purposes of this proposed rulemaking. However, direct 
measurement may provide improved emissions estimates.
    Option 1 was not proposed because the use of default values and 
lack of direct measurement results in a high level of uncertainty. 
These default approaches would not provide site-specific estimates of 
emissions that would reflect differences in feedstocks, operating 
conditions, catalyst selectivity, thermal/energy efficiencies, and 
other differences among plants. 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 request comment on how to improve the emission estimates 
developed using the carbon balance approach (Option 2), including 
whether the uncertainty in the estimated emissions can be reduced (and 
if so, by how much), the advantages, disadvantages, types and frequency 
of other measurements that could be required, costs of alternatives, 
how the uncertainty of alternatives is estimated, and the QA procedures 
that should be followed to assure accurate measurement. For further 
discussion of our assumptions on the uncertainty of emissions estimates 
see the Petrochemical Production TSD (EPA-HQ-OAR-2008-0508-024).
    Additional Issues and Requests for Comments. EPA is interested in 
public comment on four additional issues.
    Fugitive emissions from petrochemical production facilities have 
been of environmental interest primarily because of the VOC emissions. 
As noted above, we have concluded that fugitive CO2 and 
CH4 emissions contribute very little to the overall GHG 
emissions from the petrochemical production sector, and non-
CH4 hydrocarbon losses assumed to be CO2 
emissions overstate the emissions only slightly. Consequently, the 
Agency is not proposing that fugitive emissions be reported.
    Second, Option 2 assumes all carbon entering the process is 
released as CO2 and does not account for potential 
CH4 emissions, nor are N2O emissions estimated in 
this approach. EPA

[[Page 16539]]

believes CH4 and N2O emissions are small.
    Third, EPA is aware that a limited number of petrochemical 
facilities may produce petrochemicals as well as one or more other 
chemicals that are part of another source category (e.g.production of 
hydrogen for sale and the petrochemical methanol from synthesis gas 
created by steam reforming of CH4). We consider these 
``integrated processes'' and request comment on whether the procedures 
for the affected source categories are clear and adequate for 
addressing emissions from integrated facilities.
    Fourth, we are proposing several methods for measuring the volume, 
carbon content and composition of feedstocks and products. There may be 
additional peer-reviewed and published measurement methodologies.
    Public comment on each of these four issues is welcomed. Where 
applicable, supporting data and documentation on how emissions should 
be included, and if so, how these emissions can be estimated, including 
the advantages, disadvantages, types and frequency of measurements that 
could be required, costs of alternatives, how the uncertainty of 
alternatives is estimated, and the QA procedures that should be 
followed to assure accurate measurement.
4. Selection of Procedures for Estimating Missing Data
    The missing data procedures in proposed 40 CFR part 98, subpart C 
for combustion units are proposed for facilities that use CEMS to 
estimate emissions from both combustion sources and process vents. 
Similarly, if the mass balance option is used, the same procedures that 
apply to missing data for fuel measurements in proposed 40 CFR part 98, 
subpart C would also apply to missing flow and carbon content 
measurements of feedstocks and products. Specifically, the substitute 
data value for missing carbon content, CO2 concentration, or 
stack gas moisture content values would be the average of the quality-
assured values of the parameter immediately before and immediately 
after the missing data period. The substitute data value for missing 
feedstock, product, or stack gas flows would be the best available 
estimate based on all available process data.
5. Selection of Data Reporting Requirements
    Where CEMS are used, the reporting requirements specified in 
proposed 40 CFR part 98, subpart C would apply. Where the carbon 
balance method is used, we propose that the following information be 
reported: Identification of the process, annual CO2 
emissions for each type of petrochemical produced and each process 
unit, the methods used to determine flows and carbon contents, the 
emissions calculation methodology, quantity of feedstocks consumed, 
quantity of each product and byproduct produced, carbon contents of 
each feedstock and product, information on the number of actual versus 
substitute data points, and the quantity of CO2 captured for 
use. In addition, owners and operators would report information related 
to all equipment calibrations; measurements, calculations, and other 
data; certifications; and any other QA procedures used to assess the 
uncertainty in emissions estimates.
    The data to be reported under the proposed rule form the basis of 
the emissions calculations and are needed for us to understand the 
emissions data and verify reasonableness of the reported emissions. The 
Agency requests comment on the types of QA procedures that are most 
commonly conducted or recommended and the information that would be 
most useful in assessing uncertainty of the emissions estimates.
6. Selection of Records That Must Be Retained
    Petrochemical production facilities would be required to keep 
records of the information specified in proposed 40 CFR 98.3, as 
applicable. Under the carbon balance option, a facility also would be 
required to keep records of all feedstock and product flows and carbon 
content determinations. If a petrochemical production facility complies 
with the CEMS option, the additional records for CEMS listed in 
proposed 40 CFR 98.37 would also be required for all CEMS, including 
CEMS on process stacks that are not associated with combustion sources. 
These records document values that are directly used to calculate the 
emissions that are reported and are necessary to enable verification 
that the GHG emissions monitoring and calculations were done correctly.

Y. Petroleum Refineries

1. Definition of the Source Category
    Petroleum refineries are facilities engaged in producing gasoline, 
kerosene, distillate fuel oils, residual fuel oils, lubricants, asphalt 
(bitumen), or other products through distillation of petroleum or 
through redistillation, cracking, or reforming of unfinished petroleum 
derivatives. There are 150 operating petroleum refineries in the U.S. 
and its territories. Emissions from petroleum refineries account for 
approximately 205 million metric tons CO2e, representing 
approximately 3 percent of the U.S. nationwide GHG emissions. Most of 
these emissions are CO2 emissions from fossil fuel 
combustion. While the U.S. GHG Inventory does not separately report 
onsite fuel consumption at petroleum refineries, it estimates that 
approximately 0.6 million metric tons CO2e of CH4 
are emitted as fugitives per year from petroleum refineries in the U.S. 
Most CO2 emissions at a refinery are combustion-related, 
accounting for approximately 67 percent of CO2 emissions at 
a refinery.
    The combustion of catalyst coke in catalyst cracking units is also 
a significant contributor to the CO2 emissions 
(approximately 25 percent) from petroleum refineries. Combustion of 
excess or waste fuel gas in flares contributes approximately 2 percent 
of the refinery's overall CO2 emissions. As such, the Agency 
proposes that the emissions from these sources must be reported.
    Process emissions of CO2 also occur from the sulfur 
recovery plant, because the amine solutions used to remove hydrogen 
sulfide (H2S) from the refinery's fuel gas adsorb 
CO2. The stripped sour gas from the amine adsorbers is fed 
to the sulfur recovery plant; the CO2 contained in this 
stream is subsequently released to the atmosphere. Most refineries have 
on-site sulfur recovery plants; however, a few refineries send their 
sour gas to neighboring sulfur recovery or sulfuric acid production 
facilities. The quantity of CO2 contained in the sour gas 
sent for off-site sulfur recovery operations is considered an emission 
under this regulation.
    There are a variety of GHG emission sources at the refinery, which 
include: Asphalt blowing, delayed coking unit depressurization and coke 
cutting, coke calcining, blowdown systems, process vents, process 
equipment leaks, storage tanks, loading operations, land disposal, 
wastewater treatment, and waste disposal. To fully account for the 
refinery's GHG emissions, we propose that the emissions from these 
sources must also be reported.
    Based on the emission sources at petroleum refineries, GHGs to 
report under proposed 40 CFR part 98, subpart Y are limited to 
CO2, CH4, and N2O. Table Y-1 of this 
preamble summarizes the GHGs to be reported by emission source at the 
refinery.

[[Page 16540]]



        Table Y-1. GHGs to Report Under 40 CFR Part 98, Subpart Y
------------------------------------------------------------------------
                                                          Subpart of
                                                        proposed 40 CFR
                                                         part 98 where
         Emission source            GHGs to report         emissions
                                                           reporting
                                                         methodologies
                                                           addressed
------------------------------------------------------------------------
Stationary combustion sources...  CO2, CH4, and N2O.  Subpart C.
Coke burn-off emissions from      CO2, CH4, and N2O.  Subpart Y.
 catalytic cracking units, fluid
 coking units, catalytic
 reforming units, and coke
 calcining units.
Flares..........................  CO2, CH4, and N2O.  Subpart Y.
Hydrogen plant vent.............  CO2 and CH4.......  Subpart P.
Petrochemical processes.........  CO2 and CH4.......  Subpart X.
Sulfur recovery plant, on-site    CO2...............  Subpart Y.
 and off-site.
On-site wastewater treatment      CO2 and CH4.......  Subpart II.
 system.
On-site land disposal unit......  CH4...............  Subpart HH.
Fugitive Emissions..............  CO2, CH4, and N2O.  Subpart Y.
Delayed coking units............  CH4...............  Subpart Y.
------------------------------------------------------------------------

2. Selection of Reporting Threshold
    Four options were considered as reporting thresholds for petroleum 
refineries. Table Y-2 of this preamble illustrates the emissions and 
number of facilities that would be covered under the four options.

                              Table Y-2. Threshold Analysis for Petroleum Refining
----------------------------------------------------------------------------------------------------------------
                                                                Emissions covered          Facilities covered
                                                           -----------------------------------------------------
                  Option/threshold level                      Million
                                                            metric tons     Percent       Number       Percent
                                                             CO2e/year
----------------------------------------------------------------------------------------------------------------
1,000 metric tons CO2e....................................       204.75       100              150         100
10,000 metric tons CO2e...................................       204.74        99.995          149          99.3
25,000 metric tons CO2e...................................       204.69        99.97           146          97.3
100,000 metric tons CO2e..................................       203.75        99.51           128          85.3
----------------------------------------------------------------------------------------------------------------

    We are proposing that all petroleum refineries should report. This 
approach would ensure full reporting of emissions, affect an 
insignificant number of additional sources compared to the 25,000 
metric tons CO2e threshold, and would add minimal additional 
burden to the reporting facilities. All U.S. refineries must report 
their fuel consumption to the EIA, so there is limited additional 
burden to estimate their GHG emissions. Furthermore, due to the 
importance of the petroleum refining industry to our nation's energy 
needs as well as the overall U.S. GHG inventory, it is important to 
obtain the best information available for this source category. We 
estimate that 4 refineries did not exceed a reporting threshold of 
25,000 metric tons CO2e in 2006 and invite public comment on 
this matter.
    For a full discussion of the threshold analysis, please refer to 
the Petroleum Refineries TSD (EPA-HQ-OAR-2008-0508-025). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    We considered monitoring methods that are used or recommended for 
use from several sources including international groups, U.S. agencies, 
State agencies, and petroleum refinery trade organizations. For most 
emission sources, three general levels of monitoring options were 
evaluated: (1) Use of engineering calculations and/or default factors; 
(2) monitoring of process parameters (such as fuel consumption 
quantities and carbon content); and (3) direct emission measurement 
using CEMS for all emissions sources at a refinery.
    Under this proposed rule, if you are required to use an existing 
CEMS to meet the requirements outlined in proposed 40 CFR part 98, 
subpart C, you would be required to use CEMS to estimate CO2 
emissions. Where the CEMS capture all combustion- and process-related 
CO2 emissions you would be required to follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
proposed 40 CFR part 98, subpart C to estimate CO2 
emissions. Also, refer to proposed 40 CFR part 98, subpart C to 
estimate combustion-related CH4 and N2O 
emissions.
    For facilities that do not currently have CEMS that meet the 
requirements outlined in proposed 40 CFR part 98, subpart C, or where 
the CEMS would not adequately account for process emissions, the 
proposed monitoring method is Option 2. Option 2 accounts for process-
related CO2 emissions. Simplified methods for estimating 
fugitive CH4 emissions are provided below. Refer to proposed 
40 CFR part 98, subpart C specifically for procedures to estimate 
combustion-related CH4 and N2O emissions.
    You would be required to follow the calculation procedures, 
monitoring and QA/QC methods, missing data procedures, reporting 
requirements, and recordkeeping requirements of proposed 40 CFR part 
98, subpart HH to estimate emissions from landfills, proposed 40 CFR 
part 98, subpart II to estimate emissions from wastewater and proposed 
40 CFR part 98, subpart P to estimate emissions from hydrogen 
production (non-merchant hydrogen plants only).
    Specifically, for fluid catalytic cracking units and fluid coking 
units that already have CEMS in place, we

[[Page 16541]]

propose to require refineries to report CO2 emissions using 
these CEMS. For the sources that contribute significantly to the 
overall GHG emissions from the refinery, as defined below, we propose 
monitoring of process parameters (Option 2). The Agency requests 
comment on the feasibility of allowing smaller emission sources at the 
refinery to employ less certain (Option 1) methods as a way to reduce 
the costs and burden of measurement and verification under this 
proposed rule. Providing this flexibility would result in lower costs 
but greater uncertainty around some portions of a facility's emissions 
estimates.
    The selected monitoring methods for this proposed rule generally 
follow those used in other reporting rules as well as those recommended 
in the American Petroleum Institute's Compendium of Greenhouse Gas 
Emissions Estimation Methodologies for the Oil and Gas Industry 
(hereafter referred to as ``the API Compendium''). More detail 
regarding the selection of the proposed monitoring options for specific 
emission sources follows.
    Coke burn-off. The proposed methods for estimating GHG emissions 
from coke burn-off in the catalytic cracking unit, fluid coking unit, 
and catalytic reforming unit generally follow the methods presented in 
the API Compendium for coke burn-off. Fluid catalytic cracking units 
and fluid coking units are large CO2 emission sources, 
accounting for over 25 percent of the GHG emissions from petroleum 
refineries. Most of these units are expected to monitor gas composition 
for process control or for compliance with applicable monitoring 
provisions under 40 CFR part 60, subparts J and Ja and under 40 CFR 
part 63, subpart UUU. Given the magnitude of the GHG emissions from 
catalytic cracking units and fluid coking units, direct monitoring for 
CO2 emissions (i.e., continuous monitoring of CO2 
concentration and flow rate at the final exhaust stack) is believed to 
provide greater certainty in the emission estimate. However, 
compositional analysis monitoring in the regenerator or fluid coking 
burner exhaust vent prior to the combustion of other fuels (such as 
auxiliary fuel fired to a CO boiler) may be used when direct monitoring 
for CO2 emissions is not already employed. An equation is 
provided in the rule for calculating the vent stream flow rate based on 
the compositional analysis data rather than requiring a continuous flow 
monitor; this equation is allowed in other petroleum refinery rules (40 
CFR part 60, subparts J and Ja; 40 CFR part 63, subpart UUU) as an 
alternative to continuous flow monitoring.
    An engineering approach for estimating coke burn-off rates and 
calculating CO2 emissions using default carbon content for 
petroleum coke was considered. However, as most catalytic cracking 
units already must have the compositional monitors in-place due to 
other petroleum refinery rules and because catalytic cracking unit coke 
burn-off is a significant contributor to the overall GHG emissions from 
petroleum refineries, we are not proposing an engineering calculation 
for the catalytic cracking units. However, comment is requested on the 
engineering methods available to estimate coke burn-off rates, the 
uncertainty of the methods, and the measurements or parameters and 
enhanced QA that can be used to verify the engineering emission 
estimates and their certainty.
    The amount of coke burned in catalytic reforming units is estimated 
to be about 1 percent of the amount of coke burned in catalytic 
cracking units or fluid coking units; therefore, a simplified method is 
provided for estimating coke burn-off emissions for catalytic reforming 
units that do not monitor gas composition in the coke burn-off exhaust 
vent.
    Flares. Specific monitoring provisions are provided for flares. As 
the composition of gas flared can change significantly, we considered 
proposing continuous flow and composition monitors (or heating value 
monitors) on all flares. For example, in California, both the South 
Coast and Bay Area Air Quality Management Districts require these 
monitors for refineries located in their districts. However, a 
significant fraction of flares is not expected to have these monitoring 
systems installed. Further, since flares are projected to contribute 
only about 2 percent of a typical refinery's CO2 emissions, 
it would be costly to improve the monitoring systems for flare emission 
estimates. The use of the default CO2 emission factor for 
refinery fuel gas was also considered. The default emission factor is 
expected to be reasonable during normal refinery operations, but is 
highly uncertain during periods of start-up, shutdown, or malfunction. 
Consequently, a hybrid method is proposed that allows the use of a 
default CO2 emission factor for refinery fuel gas during 
periods of normal refinery operations and specific engineering analysis 
of GHG emissions during periods of high flare volumes associated with 
start-up, shutdown, or malfunction. As with stationary combustion 
sources, default emission factors for refinery gas are proposed to 
calculate CH4 and N2O emissions from flares.
    Sulfur Recovery Plants. For sulfur recovery plants at the petroleum 
refinery and for instances where sour gas is sent off-site for sulfur 
recovery, direct carbon content measurement in the sour gas feed to the 
sulfur recovery plant is the preferred monitoring approach. However, a 
site-specific or default carbon content method is also provided. It is 
anticipated that monitoring systems would be in place at most 
refineries, as monitoring of the sour gas feed is important in the 
operation of the sulfur recovery plant. The monitoring data for carbon 
content and flow rate must be used if they are available. The 
alternative default carbon content method is provided because the 
emissions from this source are relatively small, 1 to 2 percent for a 
given facility, and because only small, non-Claus sulfur recovery 
plants are not expected to monitor the flow and composition of the sour 
gas. We are proposing that only CO2 emissions would need to 
be reported for the sulfur recovery plant process-related emissions.
    Coke Calcining. For coke calcining units at the petroleum refinery, 
direct CO2 measurement is the preferred monitoring approach. 
However, a carbon balance approach is proposed similar to the approach 
included in The Aluminum Sector Greenhouse Gas Protocol \83\ for units 
that do not have CEMS. This is because coke calcining is a small source 
of GHG emissions, less than 1 percent for a given facility. 
CH4 and N2O emissions are calculated from the 
coke calcining CO2 process emissions using the default 
emission factors for petroleum coke combustion (the same equations as 
proposed for calculating CH4 and N2O emissions 
from coke burn-off).
---------------------------------------------------------------------------

    \83\ International Aluminum Institute. 2006. The Aluminum Sector 
Greenhouse Gas Protocol (Addendum to the WRI/WBCSD Greenhouse Gas 
Protocol). pp. 31-32. Available at: http://www.world-aluminium.org/Downloads/Publications/Download.
---------------------------------------------------------------------------

    Process Vents not Otherwise Specified. For process vents other than 
those discussed elsewhere in this section of the preamble, either 
process knowledge or measurement data can be used to calculate the GHG 
emissions. Due to other regulations affecting petroleum refineries, 
only a few, small process vents are expected to be present at most 
refineries. As such, these small vents do not warrant requiring the use 
of CEMS to quantify emissions. Process vent emissions are expected to 
be predominately CO2 or CH4, but N2O

[[Page 16542]]

emissions, if present, are also to be reported.
    Other Sources. Due to the small (less than 1 percent) contribution 
of other emissions sources at the refinery that make up the total GHG 
emissions from the facility, very simple methods are proposed to 
estimate these other emissions sources. Alternative methods are 
provided so that facilities can provide more detailed estimates if 
desired. For example, a refinery may estimate CH4 emissions 
from individual tanks using EPA's TANKS model, if desired, or apply a 
default emission factor to the facility's overall throughput. Simple 
emission factor approaches are provided for asphalt blowing, delayed 
coking unit depressurization and coke cutting, blowdown systems, 
process equipment leaks, storage tanks, and loading operations.
    For further discussion of this source category and monitoring of 
its emissions, see the Petroleum Refineries TSD (EPA-HQ-OAR-2008-0508-
025).
4. Selection of Procedures for Estimating Missing Data
    In those cases where you use direct measurement by a CO2 
CEMS, the missing data procedures would be the same as the Tier 4 
requirements described for general stationary fuel combustion sources 
in proposed 40 CFR part 98, subpart C. Missing data procedures are also 
specified, consistent with proposed 40 CFR part 98, subpart C, for heat 
content, carbon content, fuel molecular weight, gas and liquid fuel 
flow rates, stack gas flow rates, and compositional analysis data 
(CO2, CO, O2, CH4, N2O, and 
stack gas moisture content, as applicable). Generally, the average of 
the data measurements before and after the missing data period would be 
used to calculate the emissions during the missing data period.
5. Selection of Data Reporting Requirements
    The reporting requirements for combustion sources other than those 
associated with coke burn-off directly refer to those in proposed 40 
CFR part 98, subpart C, General Stationary Fuel Combustion Sources. For 
other sources, we propose to report the identification of the source, 
throughput of the source (if applicable), the calculation methodology 
used, the total GHG emissions for the source, and the quantity of 
CO2 captured for use and the end use, if known. A list of 
the specific GHG emissions reportable for each emission source is 
provided in Table Y-1 of this preamble.
    The reporting requirements consist of actual GHG emission values as 
well as values that are directly used to calculate the emissions and 
are necessary in order to verify that the GHG emissions monitoring and 
calculations were done correctly. As there are high uncertainties 
associated with many of the ancillary emission sources at the refinery, 
separate reporting of the emissions for these separate sources is 
needed to fully understand the importance and variability of these 
ancillary emission sources. A complete list of information to report is 
contained in proposed 40 CFR 98.256.
6. Selection of Records That Must Be Retained
    The recordkeeping requirements in the general provisions of 
proposed 40 CFR part 98 apply for petroleum refineries. Specifically, 
refineries would be required to keep all records specified in proposed 
40 CFR part 98, subpart A and summarized in Section III.E of this 
preamble. In addition, records of the data required to be monitored and 
reported under proposed 40 CFR part 98, subpart Y would be retained. If 
CEMS are used to quantify the GHG emissions, you would be required to 
keep additional records specified in proposed 40 CFR part 98, subparts 
A and Y. These records consist of values that are directly used to 
calculate the emissions and are necessary to enable verification that 
the GHG emissions monitoring and calculations were done correctly.

Z. Phosphoric Acid Production

1. Definition of the Source Category
    Phosphoric acid is a common industrial product used to manufacture 
phosphate fertilizers. Phosphoric acid is a product of the reaction 
between phosphate rock and, typically, sulfuric acid 
(H2SO4). A byproduct called calcium sulfate 
(CaSO4), or gypsum, is formed when calcium from the 
phosphate rock reacts with sulfate. Most companies in the U.S. use a 
dihydrate process in which two molecules of water (H2O) are 
produced per molecule of gypsum (CaSO4 [middot] 2 
H2O or calcium sulfate dihydrate).
    Additionally, a second reaction occurs in which the limestone 
(CaCO3) present in the phosphate rock reacts with sulfuric 
acid (H2SO4) releasing CO2. The amount 
of carbon in the phosphate rock feedstock varies depending on the 
region in which it was mined.
    National emissions from phosphoric acid production facilities were 
estimated to be 3.8 million metric tons CO2e in 2006. These 
emissions include both process-related emissions (CO2) and 
on-site stationary combustion emissions (CO2, CH4 
and N2O) from 14 phosphoric acid production facilities 
across the U.S. Process-related emissions account for 1.2 million 
metric tons CO2e, or 30 percent of the total, while on-site 
stationary combustion emissions account for the remaining 2.7 million 
metric tons CO2e emissions.
    The phosphoric acid production industry has many production sites 
that are integrated with mines; notably, three facilities import 
phosphate rock from Morocco.
    For additional background information on phosphoric acid 
production, please refer to the Phosphoric Acid Production TSD (EPA-HQ-
OAR-2008-0508-026).
2. Selection of Reporting Threshold
    In developing the threshold for phosphoric acid production, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e per year. Table 
Z-1 of this preamble illustrates the emissions and number of facilities 
would not be impacted under these various applicability thresholds.

                                              Table Z-1. Threshold Analysis for Phosphoric Acid Production
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              metric tons    of facilities    Metric tons
                                                              CO2e/yr                         CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................       3,838,036              14       3,838,036             100              14             100
10,000..................................................       3,838,036              14       3,838,036             100              14             100
25,000..................................................       3,838,036              14       3,838,036             100              14             100
100,000.................................................       3,838,036              14       3,838,036             100              14             100
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 16543]]

    There is no proposed threshold for reporting emissions from 
phosphoric acid production. Even at a 100,000 metric tons 
CO2e threshold, all emissions would be covered, and all 
facilities would be required to report. Having no threshold would 
simplify the rule and avoid any burden for unnecessary calculations to 
determine if a threshold is exceeded. Therefore, we propose that all 
phosphoric acid production facilities report.
    For a full discussion of the threshold analysis, please refer to 
the Phosphoric Acid Production TSD (EPA-HQ-OAR-2008-0508-026). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    The methodology for estimating process-related emissions from 
phosphoric acid production is based on the U.S. GHG Inventory method 
discussed further in the Phosphoric Acid Production TSD (EPA-HQ-OAR-
2008-0508-026). Most domestic and international GHG monitoring 
guidelines and protocols, such as the 2006 IPCC Guidelines do not 
provide estimation methodologies for process-related emissions from 
phosphoric acid production.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow the requirements of proposed 40 CFR part 98, subpart C to 
estimate CO2 emissions. Also, refer to proposed 40 CFR part 
98, subpart C to estimate combustion-related CH4 and 
N2O emissions.
    If you do not have CEMS that meet the conditions outlined in 
proposed 40 CFR part 98, subpart C, we propose that facilities estimate 
process-related CO2 emissions by determining the amount of 
inorganic carbon input to the process through measurement of the 
inorganic carbon content of the phosphate rock and multiplying by the 
amount (mass) of phosphate rock used to manufacture phosphoric acid. 
Refer to proposed 40 CFR part 98, subpart C specifically for procedures 
to estimate combustion-related CH4 and N2O 
emissions.
    In order to assess the composition of the inorganic carbon input, 
we assume that vertically integrated phosphoric acid production 
facilities already have the necessary equipment on-site for conducting 
chemical analyses of the inorganic carbon weight fraction of the 
phosphate rock and that this analysis is conducted on a routine basis 
at facilities. Facilities importing rock from Morocco would send rock 
samples off-site for composition analysis. The inorganic carbon content 
would be determined on a per-batch basis. Multiplying the inorganic 
carbon content by the amount (mass) of phosphate rock processed and by 
the molecular weight ratio of CO2 to inorganic carbon (44/
12) yields the estimate of CO2 emissions. This calculated 
value should be recorded monthly based on the most recent batch of 
phosphate rock received. The monthly emissions for each phosphoric acid 
process line are then summed to obtain the annual emissions to be 
included in the report.
    The various approaches to monitoring GHG emissions are elaborated 
in the Phosphoric Acid Production TSD (EPA-HQ-OAR-2008-0508-026).
4. Selection of Procedures for Estimating Missing Data
    The likelihood for missing data is low, as businesses closely track 
their purchase of production inputs. The Phosphoric Acid NSPS (40 CFR 
part 60, subpart T) requires continuous monitoring of phosphorus-
bearing material (rock) to process. This requirement, along with the 
fact that the facility would closely monitor production inputs, results 
in low likelihood of missing data. Additionally, only 3 facilities 
within the U.S. are not vertically integrated with mines and may lack 
the necessary equipment to measure the inorganic carbon weight percent 
of the rock. Therefore, no missing data procedures would apply to 
CO2 emission estimates from wet-process phosphoric acid 
production facilities because inorganic carbon test results and monthly 
production data should be readily available. Therefore, 100 percent 
data availability would be required.
5. Selection of Data Reporting Requirements
    We propose that facilities report total annual CO2 
emissions from each wet-process phosphoric acid productionline, as well 
as any stationary fuel combustion emissions. In addition, we propose 
that facilities report their annual average phosphate rock consumption, 
percent of inorganic carbon in the phosphate rock consumed, annual 
phosphoric acid production and concentration and annual phosphoric acid 
capacity. These data are used to calculate emissions. They are needed 
for us to understand the emissions data and assess the reasonableness 
of the reported emissions. A full list of data to be reported is 
included in proposed40 CFR part 98, subparts A and Z.
6. Selection of Records That Must Be Retained
    In addition to the data reported, we propose that facilities 
maintain records of inorganic carbon content chemical analyses on each 
batch of phosphate rock and monthly phosphate rock consumption (by the 
origin of the phosphate rock). These records provide values that are 
directly used to calculate the emissions that are reported and are 
necessary to allow determination of whether the GHG emissions 
monitoring and calculations were done correctly.
    A full list of records that must be retained on-site is included in 
proposed 40 CFR part 98, subparts A and Z.

AA. Pulp and Paper Manufacturing

1. Definition of the Source Category
    The pulp and paper source category consists of over 5,000 
facilities engaged in the manufacture of pulp, paper, and/or paperboard 
products primarily from wood material. However, less than 10 percent of 
these facilities are expected to meet the applicability thresholds of 
this proposed rule. The approximately 425 facilities that the proposed 
rule is expected to cover mainly consist of facilities that include 
pulp, paper and paperboard facilities that operate fossil fuel-fired 
boilers in addition to operating other sources of GHG emissions (e.g., 
biomass boilers, lime kilns, onsite landfills, and onsite wastewater 
treatment systems).\84\
---------------------------------------------------------------------------

    \84\ This estimate is based on a survey of pulp and paper mills 
conducted by the National Council for Air and Stream Improvement 
that operated stationary combustion units in 2005. See: National 
Council of Air and Stream Improvement Special Report No. 06-07. 
December 2006.
---------------------------------------------------------------------------

    Greenhouse gas emissions from the pulp and paper source category 
are predominantly CO2 with smaller amounts of CH4 
and N2O. The pulp and paper GHG emissions include biomass-
derived CO2 emissions from using the biomass generated on 
site as a byproduct (e.g., bark, other wood waste, spent pulping 
liquor). For example, kraft pulp and paper facilities are likely to 
generate byproduct biomass fuel while the majority of the onsite energy 
for non-integrated paper facilities and 100 percent recycled paper 
facilities is likely to be generated from fossil fuel-fired boilers 
because these facilities do not generate byproduct biomass fuel.
    Table AA-1 of this preamble lists the GHG emission sources that may 
be

[[Page 16544]]

found at pulp and paper facilities, the type of GHG emissions that are 
required to be reported, and where the reporting methodologies are 
found in proposed 40 CFR part 98.

     Table AA-1. GHG Emission Sources at Pulp, Paper, and Paperboard
                               Facilities
------------------------------------------------------------------------
                                                       Subpart of 40 CFR
                                                         part 98 where
                                                           emissions
        Emissions source             GHG emissions         reporting
                                                         methodologies
                                                           addressed
------------------------------------------------------------------------
General Stationary Fuel           CO2, CH4, N2O,      Subpart C.
 Combustion.                       biomass-CO2.
Makeup Chemicals (CaCO3, Na2CO3)  CO2...............  Subpart AA.
Onsite industrial landfills.....  CH4...............  Subpart HH.
Wastewater treatment............  CH4...............  Subpart II.
------------------------------------------------------------------------

    The method presented in this section of the preamble is to account 
for the use of make-up chemicals (e.g., sodium sulfate, calcium 
carbonate, sodium carbonate) that are added into the recovery loop 
(e.g., with the spent pulping liquor) at a pulp and paper facility to 
replace the small amounts of sodium and calcium that are lost from the 
recovery cycle at kraft and soda facilities. When carbonates are added, 
the carbon in these make-up chemicals, which can be derived from 
biomass or mineral sources, is emitted as CO2 from recovery 
furnaces and lime kilns. In cases where the carbon is mineral-based, 
emissions of CO2 would contribute to GHG emissions.
    Affected facilities would be required to report total GHG emissions 
on a facility-wide basis for all source categories for which methods 
are presented in proposed 40 CFR part 98.
2. Selection of Reporting Threshold
    For the pulp and paper source category, the Agency proposes a GHG 
reporting threshold of 25,000 metric tons CO2e, which would 
include the vast majority of GHG emissions from the pulp and paper 
source category.\85\
---------------------------------------------------------------------------

    \85\ The American Forest and Paper Association estimates that 
the 25,000 metric tons CO2e would include approximately 
99 percent of GHG emissions from the pulp and paper source category.
---------------------------------------------------------------------------

    As described in proposed 40 CFR part 98, subpart A, biomass-derived 
CO2 emissions should not be taken into consideration when 
determining whether a facility exceeds the 25,000 metric tons 
CO2e threshold.
    In evaluating potential thresholds for the pulp and paper source 
category, we considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e. The threshold 
analysis focuses on the most significant sources of GHG emissions in 
the pulp and paper industry, specifically facilities that make pulp, 
paper and paperboard and operate fossil fuel-fired boilers. Therefore, 
of the 5,000 facilities associated with this industry, only 425 were 
included in the analysis. Table AA-2 of this preamble illustrates that 
the various thresholds do not have a significant effect on the amount 
of emissions that would be covered.
    For a full discussion of the threshold analysis, please refer to 
the Pulp and Paper Manufacturing TSD (EPA-HQ-OAR-2008-0508-027). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.

                           Table AA-2. Reporting Thresholds for Pulp and Paper Sector
----------------------------------------------------------------------------------------------------------------
                              Total national     Total          Emissions covered          Facilities covered
 Threshold level metric tons     emissions     number of  ------------------------------------------------------
            CO2e               (metric tons       U.S.       Metric tons
                                   CO2e)       facilities      CO2e/yr       Percent       Number      Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................      57,700,000          425      57,700,000          100          425          100
10,000......................      57,700,000          425      57,700,000          100          425          100
25,000......................      57,700,000          425      57,700,000          100          425          100
100,000.....................      57,700,000          425      57,527,000         99.7          410           96
----------------------------------------------------------------------------------------------------------------

3. Selection of Proposed Monitoring Methods
a. Calculation Methods Selected
    Refer to proposed 40 CFR part 98, subparts C, HH, and II for 
monitoring methods for general stationary fuel combustion sources, 
landfills, and industrial wastewater treatment occurring on-site at 
pulp and paper facilities. This section of the preamble includes 
monitoring methods for calculating and reporting makeup chemicals at 
pulp and paper facilities. Additional details on the proposed 
monitoring options are elaborated in the Pulp and Paper Manufacturing 
TSD (EPA-HQ-OAR-2008-0508-027).
    The proposed method for monitoring emissions from carbonate-based 
make-up chemicals used at chemical pulp facilities includes calculating 
the CO2 emissions from the added CaCO3 and 
Na2CO3 using emissions factors provided in the 
rule. The calculation assumes that the carbonate based make-up 
chemicals added (e.g., limestone) are pure carbonate minerals, and that 
all of the carbon is released to the atmosphere. If you believe that 
these assumptions do not represent circumstances at your facility, you 
may send samples of each carbonate consumed to an off-site laboratory 
for a chemical analysis of the carbonate weight fraction on a quarterly 
basis, consistent with proposed 40 CFR part 98, subpart U. You could 
also determine the calcination fraction for each of the carbonate-based 
minerals consumed, using an appropriate test method. Make-up chemical 
usage would be required to be determined by direct measurement of the 
quantity of chemical added. The chemical usage should be quantified 
separately for each chemical used, and

[[Page 16545]]

the estimate should be in terms of pure CaCO3 and/or 
Na2CO3. We have proposed direct measurement for 
quantifying the amount of makeup chemicals, consistent with the 
estimation of emissions from carbonates in the rest of proposed 40 CFR 
part 98.
    For the monitoring methods detailed in proposed 40 CFR part 98, 
subpart C for general stationary combustion, it should be noted that 
biogenic CO2 emissions from the combustion of biomass fuels 
are to be reported separately. Furthermore, in referring to proposed 40 
CFR part 98, subpart C on general stationary combustion, we would 
expand upon particular details unique to a pulp and paper facility, 
because of the unique uses of biomass fuels. For the pulp and paper 
source category, biomass fuels include, but may not be limited to: (1) 
Unadulterated wood, wood residue, and wood products (e.g., trees, tree 
stumps, tree limbs, bark, lumber, sawdust, sanderdust, chips, scraps, 
slabs, millings, wood shavings, paper pellets, and corrugated container 
rejects); (2) pulp and paper facility wastewater treatment system 
sludge; (3) vegetative agricultural and silvicultural materials, such 
as logging residues and bagasse; and (4) liquid biomass-based fuels 
such as biomass-based turpentine and tall oil. Such fuels could be 
combusted at a pulp and paper facility in stationary combustion units 
including, but not limited to, boilers, chemical recovery furnaces, and 
lime kilns. Proposed 40 CFR part 98, subpart C provides details on the 
separate reporting of the biogenic CO2 emissions from these 
biomass-based fuels, and the calculation methodologies for any fossil 
fuels combusted, including when co-fired with biomass.
    Where biomass is co-fired with fossil fuel, the appropriate 
methodology as required in proposed 40 CFR part 98, subpart C should be 
used. However, to minimize the burden on owners and operators of 
biomass-fired stationary combustion equipment, this proposed rule 
allows biogenic CO2 emissions to be calculated using default 
emission factors and default HHVs used in the Tier 1 methodology.
    Where available, like in the case of spent pulping liquor, we would 
require direct analysis of the HHV, rather than allowing the use of a 
default HHV. This is due to the variability in the HHV of spent pulping 
liquor across the industry and because a number of facilities already 
perform this analysis on a monthly basis. However, the proposed rule 
does not propose the use of default GHG emissions factors for spent 
pulping liquor at kraft pulp facilities. For sulfite and semichemical 
chemical recovery combustion units, we propose that sources conduct a 
monthly carbon content analysis of the spent pulping liquor for use in 
calculating the biomass CO2 emissions because no default 
emissions factors are known to exist for these sources.
    We are requesting comment on the appropriateness of today's 
proposed requirements for monthly measurement of spent pulping liquor 
HHV (kraft recovery furnaces) and monthly carbon content analysis of 
spent pulping liquor (sulfite and semichemical chemical recovery 
combustion units). We welcome data and documentation regarding the use 
of potential alternative methods or default emissions factors.
    In addition, regarding the monitoring methods in proposed 40 CFR 
part 98, subpart C for general stationary combustion, the majority of 
biomass fuel consumed at pulp and paper mills is generated onsite, and 
thus, as required in proposed 40 CFR part 98, subpart C, the use of 
purchasing records might not be an option for these mills. As such, we 
are taking comment on appropriate details to be reported on volume or 
mass of biogenic fuel fed into stationary combustion units.
b. Other Monitoring Methods Considered
    Lime kilns and calciners used in the pulp and paper source category 
are unique and are defined separately from lime kilns used in the 
commercial lime manufacturing industry because the source of the carbon 
in the calcium carbonate entering the kraft lime kiln is biogenic. The 
CO2 emitted from lime kilns at kraft pulp facilities 
originates from two sources: (1) Fossil fuels burned in the kiln, and 
(2) conversion of calcium carbonate (or ``lime mud'') to calcium oxide 
during the chemical recovery process.
    Although CO2 is also liberated from the CaCO3 
burned in the kiln or calciner, the carbon released from 
CaCO3 is biomass carbon that originates in wood and is 
included in the biogenic CO2 emissions factor for the 
recovery furnace as discussed previously. The reporting of the 
CO2 emissions associated with the conversion of the calcium 
carbonate to lime as biogenic CO2 is consistent with the 
reporting requirements in other accepted protocols such as DOE 1605(b) 
and guidance developed for the International Council of the Forest and 
Paper Association. This approach has been widely accepted by the 
domestic and international community, including WRI/WBCSD. The IPCC 
does not directly state how CO2 emissions from kraft 
facility lime kilns should be addressed. As biogenic process 
CO2 emissions (i.e., any biogenic CO2 emissions 
not associated with the combustion of biomass fuels) are not being 
reported in this rule, we are taking comment on whether an exception 
should be made for this unique case, consistent with other existing 
protocols as noted above.
4. Selection of Procedures for Estimating Missing Data
    Refer to proposed 40 CFR part 98, subparts C, HH, and II for 
procedures for estimating missing data for stationary combustion, 
landfills, and industrial wastewater treatment occurring on-site at 
pulp and paper facilities.
    Proposed 40 CFR part 98, subpart AA contains missing data 
procedures for process emissions. 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 monthly 
measurements are determined to be invalid. For missing spent pulping 
liquor flow rates, the lesser value of either the maximum fuel flow 
rate for the combustion unit, or the maximum flow rate that the fuel 
flowmeter can measure would be used. 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).
5. Selection of Data Reporting Requirements
    Refer to proposed 40 CFR part 98, subparts C, HH, and II for 
reporting requirements for stationary combustion, landfills, and 
industrial wastewater treatment occurring on-site at pulp and paper 
facilities.
    We propose that some additional data be reported to assist in 
verification of estimates, checks for reasonableness, and other data 
quality considerations, including: Annual emission estimates presented 
by calendar quarters (including biogenic CO2), total 
consumption of all biomass fuels and spent pulping liquor by calendar 
quarters, and total annual quantities of makeup chemicals (carbonates) 
used and by carbonate.
6. Selection of Records That Must Be Retained
    Refer to proposed 40 CFR part 98, subparts C, HH, and II for 
recordkeeping requirements for stationary combustion, landfills, and 
industrial wastewater treatment occurring on-site at pulp and paper 
facilities.

[[Page 16546]]

    In addition to the recordkeeping requirements for general 
stationary fuel combustion sources in proposed 40 CFR part 98, subpart 
C, we propose that the following additional records be kept to assist 
in QA/QC, including: GHG emission estimates by calendar quarter by unit 
and facility, monthly consumption total of all biomass fuels and spent 
pulping liquor by unit and facility, monthly analyses of spent pulping 
liquor HHV or carbon content, monthly and annual steam production for 
each biomass unit, and monthly quantities of makeup chemicals 
(carbonates) used.

BB. Silicon Carbide Production

1. Definition of the Source Category
    Silicon carbide (SiC) is primarily an industrial abrasive 
manufactured from silica sand or quartz and petroleum coke. Other uses 
of silicon carbide include semiconductors, body armor, and the 
manufacture of Moissanite, a diamond substitute. The silicon carbide 
source category is limited to the production of silicon carbide for 
abrasive purposes.
    CO2 and CH4 are emitted during the production 
of silicon carbide. Petroleum coke is utilized as a carbon source 
during silicon carbide production and approximately 35 percent of the 
carbon is retained within the silicon carbide product; the remaining 
carbon is converted to CO2 and CH4.
    Silicon carbide process emissions totaled 109,271 metric tons 
CO2e in 2006 (less than 0.002 percent of the total national 
GHG emissions). Of the total, process-related CO2 emissions 
accounted for 91 percent (91,700 metric tons CO2e), 
CH4 emissions accounted for 9 percent (8,526 metric tons 
CO2e), and on-site stationary combustion emissions accounted 
for less than 1 percent (9,045 metric tons CO2e).
    For additional background information on silicon carbide 
production, please refer to the Silicon Carbide Production TSD (EPA-HQ-
OAR-2008-0508-028).
2. Selection of Reporting Threshold
    In developing the reporting threshold for silicon carbide 
production, we considered emissions-based thresholds of 1,000 metric 
tons CO2e, 10,000 metric tons CO2e, 25,000 metric 
tons CO2e and 100,000 metric tons CO2e. Requiring 
all facilities to report (no threshold) was also considered. Table BB-1 
of this preamble illustrates the emissions and facilities that would be 
covered under these various thresholds.

                          Table BB-1. Threshold Analysis for Silicon Carbide Production
----------------------------------------------------------------------------------------------------------------
                                   Total                        Emissions covered          Facilities covered
                                 national        Total    ------------------------------------------------------
 Threshold level metric tons     emissions     number of
           CO2e/yr             (metric tons    facilities    Metric tons     Percent       Number      Percent
                                 CO2e/yr)                      CO2e/yr
----------------------------------------------------------------------------------------------------------------
1,000.......................         109,271            1         109,271          100            1          100
10,000......................         109,271            1         109,271          100            1          100
25,000......................         109,271            1         109,271          100            1          100
100,000.....................         109,271            1         109,271          100            1          100
----------------------------------------------------------------------------------------------------------------

    There is no proposed threshold reporting level for GHG emissions 
from silicon carbide production facilities. The current estimate of 
emissions from the known facility just exceeds the highest threshold 
considered. Therefore, in order to simplify the rule and avoid the need 
for the facility to calculate and report whether the facility exceeds 
the threshold value, we propose that all facilities report in this 
source category. Requiring all facilities to report captures 100 
percent of emissions, and small temporary changes to the facility would 
not affect reporting requirements.
    For a full discussion of the threshold analysis, please refer to 
the Silicon Carbide Production TSD (EPA-HQ-OAR-2008-0508-028). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Monitoring of process emissions from silicon carbide production is 
addressed in both domestic and international GHG monitoring guidelines 
and protocols (the 2006 IPCC Guidelines and U.S. GHG Inventory). These 
methodologies can be summarized in two different options based on 
measuring either inputs or output of the production process. In 
general, the output or production-based method is less certain, as it 
involves multiplying production data by emission and correction factors 
that are likely default values based on carbon content (i.e., 
percentage of petroleum coke input that is carbon) assumptions. In 
contrast, the input method is more certain as it generally involves 
measuring the consumption of reducing agents and calculating the carbon 
contents of those reducing agents, specifically petroleum coke inputs.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS that meets the requirements outlined in proposed 
40 CFR part 98, subpart C, then you would be required to use CEMS to 
estimate CO2 emissions. Where the CEMS capture all 
combustion- and process-related CO2 emissions you would be 
required to follow the requirements of proposed 40 CFR part 98, subpart 
C to estimate CO2 emissions from the industrial source. 
Also, refer to proposed 40 CFR part 98, subpart C to estimate 
combustion-related CH4 and N2O emissions.
    Under this proposed rule, if you do not have CEMS that meet the 
conditions outlined in proposed 40 CFR part 98, subpart C or where the 
CEMS would not adequately account for process emissions, we propose 
that facilities use an input based method to estimate process-related 
CO2 emissions by measuring the facility-level petroleum coke 
consumed and applying a facility-specific emission factor derived from 
analysis of the carbon content in the coke. In addition, we propose 
that facilities use default emission factors to estimate process-
related CH4 emissions. Refer to proposed 40 CFR part 98, 
subpart C for procedures to estimate combustion-related CO2, 
CH4 and N2O emissions.
    We propose that facilities use an input-based method to estimate 
process-related CO2 emissions by measuring the facility-
level petroleum coke consumed and applying a facility-specific emission 
factor derived from analysis of the carbon content in the coke. Using 
the emission factor, facilities would calculate CO2 
emissions quarterly and aggregate for an annual estimate. In order to 
estimate carbon content, we

[[Page 16547]]

propose that facilities request reports of the carbon content of the 
petroleum coke directly from the supplier or send petroleum coke 
samples out to a certified laboratory for chemical analysis on a 
quarterly basis. Any changes in the measured values would be reflected 
in a revised emission factor.
    We assume that data on petroleum coke consumption is readily 
available to facilities. The measurement of production quantities is 
common practice in the industry and is usually measured through the use 
of scales or weigh belts so additional costs to the industry are not 
anticipated. The primary additional burden for facilities associated 
with this method is modifying their petroleum coke supplier contract to 
include an analysis of the carbon content of each delivery of petroleum 
coke. Alternatively, a facility can send the coke to an off-site 
laboratory for analysis of the carbon content by the applicable method 
incorporated by reference in proposed 40 CFR 98.7. We consider the 
additional burden of determining the carbon content of the coke raw 
material minimal compared to the increases in accuracy expected from 
the site specific emission factors.
    We also considered a second method of estimating process-related 
CO2 emissions that involves application of default emission 
factors based on the quantity of coke consumed or total silicon carbide 
produced. According to the 2006 IPCC Guidelines, the default 
CO2 emission factors for silicon carbide production are 
relatively uncertain because industry scale carbide production 
processes differ from the stoichiometry of theoretical chemical 
reactions. Given the relative uncertainty of defaults, we decided not 
to propose existing methodologies that relied on default emission 
factors or default values for carbon content of materials because 
default approaches are inherently inaccurate for site-specific 
determinations. The use of default values is more appropriate for 
sector wide or national total estimates from aggregated activity data 
than for determining emissions from specific facilities.
    We propose that facilities estimate process-related CH4 
emissions by using a default emission factor of 10.2 kg CH4 
per metric ton of petroleum coke consumed during silicon carbide 
production. This method coincides with the IPCC Tier 1 method. Direct 
measurement of a CH4 emission factor was considered, but the 
cost of performing testing to determine this factor is too burdensome, 
considering that the amount of CH4 emissions originating 
from silicon carbide production is less than 0.5 percent of the overall 
GHG emissions from this source category.
    The various approaches to monitoring GHG emissions are elaborated 
in the Silicon Carbide Production TSD (EPA-HQ-OAR-2008-0508-028).
4. Selection of Procedures for Estimating Missing Data
    It is assumed that a facility would be readily able to supply data 
on annual petroleum coke consumption and its carbon contents. 
Therefore, 100 percent data availability is required.
5. Selection of Data Reporting Requirements
    We propose that facilities report the combined annual 
CO2 and CH4 emissions from the silicon carbide 
production processes. In addition, we propose that the following data 
be reported to assist in verification of calculations and estimates, 
checks for reasonableness, and other data quality considerations: 
Annual silicon carbide production, annual silicon carbide production 
capacity, facility-specific CO2 emission factor, and annual 
operating hours. A full list of data to be reported is included in 
proposed 40 CFR part 98, subparts A and BB.
6. Selection of Records That Must Be Retained
    In addition to the data reported, we propose that facilities 
maintain records of quarterly analyses of carbon content for consumed 
coke (averaged to an annual basis), annual consumption of petroleum 
coke, and calculations of emission factors. These records hold values 
directly used to calculate reported emissions and are necessary for 
future verification that GHG emissions monitoring and calculations were 
done correctly. A full list of records that must be maintained onsite 
is included in proposed 40 CFR part 98, subparts A and BB.

CC. Soda Ash Manufacturing

1. Definition of the Source Category
    Soda ash (sodium carbonate, Na2CO3) is a raw 
material utilized in numerous industries including glass production, 
pulp and paper production, and soap production. According to the USGS, 
the majority of the 11 million metric tons of soda ash produced is used 
for glass production. In the U.S., trona (the raw material from which 
most American soda ash is produced) is mined exclusively in Wyoming, 
where five of the seven U.S. soda ash manufacturing facilities are 
located. Total soda ash production in 2006 was 11 million metric tons, 
an amount consistent with 2005 and 500,000 metric tons more than was 
produced in 2002. Due to a surplus of soda ash in the market, 
approximately 17 percent of the soda ash industry's nameplate capacity 
was idled in 2006.
    Trona-based production methods are collectively referred to as 
``natural production'' methods. ``Natural production'' emits 
CO2 by calcining trona. Calcining involves placing crushed 
trona into a kiln to convert sodium bicarbonate into crude sodium 
carbonate that would later be filtered into pure soda ash.
    National emissions from natural soda ash manufacturing were 
estimated to be 3.1 million metric tons CO2e in 2006 or less 
than 0.04 percent of total emissions. These emissions include both 
process-related emissions (CO2) and on-site stationary 
combustion emissions (CO2, CH4, N2O) 
from six production facilities across the U.S. and Puerto Rico. 
Process-related emissions account for 1.6 million metric tons 
CO2e, or 52 percent of the total, while on-site stationary 
combustion emissions account for the remaining 1.5 million metric tons 
CO2e emissions. Soda ash consumption in the U.S. generated 
2.5 million metric tons CO2e in 2006.
    Emissions from consumption of soda ash are not addressed in this 
proposed rule as they do not occur at the soda ash manufacturing 
source. Emissions from the use of soda ash would be reported by the 
glass manufacturing industry, which consumes the soda ash.
    For additional background information on soda ash manufacturing, 
please refer to the Soda Ash Manufacturing TSD (EPA-HQ-OAR-2008-0508-
029).
2. Selection of Reporting Threshold
    In developing the threshold for soda ash manufacturing, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e per year. 
Table CC-1 of this preamble illustrates the emissions and facilities 
that would be covered under these various thresholds.

[[Page 16548]]



                            Table CC-1. Threshold Analysis for Soda Ash Manufacturing
----------------------------------------------------------------------------------------------------------------
                              Total national                    Emissions covered          Facilities covered
 Threshold level metric tons     emissions       Total    ------------------------------------------------------
           CO2e/yr              metric tons    number of     Metric tons
                                  CO2e/yr      facilities      CO2e/yr       Percent       Number      Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................       3,121,438            5       3,121,438          100            5          100
10,000......................       3,121,438            5       3,121,438          100            5          100
25,000......................       3,121,438            5       3,121,438          100            5          100
100,000.....................       3,121,438            5       3,121,438          100            5          100
----------------------------------------------------------------------------------------------------------------

    Facility-level emissions estimates based on known plant capacities 
suggest that all known facilities exceed the highest (100,000 metric 
tons CO2e) threshold examined. Two facilities were excluded 
from this analysis based on available information (one has not been 
operating since 2004 and the second recycles or utilizes CO2 
emissions as part of the process, resulting in limited fugitive 
emissions). Even if sources are not operating at full capacity, all or 
most of them would still be expected to exceed the 25,000 metric ton 
threshold. We propose that all facilities report. Requiring all 
facilities to report would simplify the proposed rule, and ensure that 
100 percent of the emissions from this industry are reported.
    For a full discussion of the threshold analysis, please refer to 
the Soda Ash Manufacturing TSD (EPA-HQ-OAR-2008-0508-029). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from soda ash manufacturing (e.g., the 2006 IPCC Guidelines, 
DOE 1605(b)). These methodologies coalesce around three different 
options:
    Option 1: Default emission factors would be applied to the amount 
of trona consumed or soda ash produced. This method would also involve 
applying an adjustment factor to the default emission factor to account 
for fractional purity of the trona consumed or soda ash produced. A 
default adjustment factor of 0.9 could be applied if country specific 
or plant specific information is not available. This option is 
consistent with IPCC Tier 2 methods and 1605(b)'s ``A'' rated approach.
    Option 2: Develop a site-specific emission factor (determined by an 
annual stack test). This method would account for the fractional purity 
of the trona consumed or soda ash produced. This approach is consistent 
with IPCC's Tier 2 method and consistent with the DOE 1605(b) ``A'' 
rated approach.
    Option 3: Direct measurement of emissions using CEMS.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions, you would be required to 
follow requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2 emissions. Also, refer to proposed 40 CFR part 98, 
subpart C to estimate combustion-related CH4 and 
N2O emissions.
    Under this proposed rule, if you do not have CEMS that meet the 
conditions outlined in proposed 40 CFR part 98, subpart C, or where the 
CEMS would not adequately account for process emissions, we propose 
that facilities estimate process-related CO2 emissions using 
a modified Option 1. Refer to proposed 40 CFR part 98, subpart C for 
procedures to estimate combustion-related CO2, 
CH4 and N2O emissions.
    The proposed monitoring method requires facilities to use default 
stoichiometric emission factors (either 0.097 for trona consumed (ratio 
of ton of CO2 emitted for each ton of trona) or 0.138 for 
soda ash produced (ratio of ton of CO2 emitted for each ton 
of natural soda ash produced)) and to measure the fractional purity of 
the trona or soda ash. These factors are then applied to the estimated 
quantity of raw material input or the amount of soda ash output. Raw 
material input and output quantities are assumed to be readily 
available to facilities. In order to assess the fractional purity of 
trona or soda ash (as determined by the level of the inorganic carbon 
present), we propose that facilities test samples of trona using in-
house TOC analyzers or test samples of soda ash for inorganic carbon 
expressed as total alkalinity using applicable test methods. We are 
assuming that soda ash facilities are conducting daily tests of 
fractional purity and can develop monthly averages from daily tests. 
This methodology was chosen because it would be more accurate than 
methods using default factors for fractional purity.
    We decided against applying a default emission factor and a default 
adjustment factor of 0.9 to either the total amount of trona consumed 
or soda ash produced. According to IPCC, the stoichiometric ratio used 
in the default emission factor equation is an exact number and assumes 
100 percent purity of the input or output and the uncertainty of the 
default emission factor is negligible. However, simple application of 
default emission and adjustment factors would not take into account the 
actual fractional purities of either the trona input or soda ash 
output.
    We also decided against proposing the second option to determine an 
annual site-specific emission factor. The stack from the calciner 
(kiln) emits CO2 emissions from both combustion- and 
process-related sources. An annual stack test would not capture the 
variability in stationary combustion emissions associated with 
consumption of various types of fuels, so would not significantly 
reduce the uncertainty for developing annual estimates of 
CO2 emissions. While not improving emissions estimates 
significantly, annual stack testing would be burdensome to industry. We 
have concluded that measuring fractional purity, as described in the 
proposed modified Option 1 approach, would improve emissions estimates, 
with a minimal cost burden.
    The third option we considered, but did not select as the proposed 
option, was continuous direct measurement of emissions from soda ash 
manufacturing. This option is consistent with the 2006 IPCC Guidelines 
Tier 3 method. Use of a CO2 CEMS would eliminate the need 
for further periodic review because this method would account for the 
variability in GHG emissions due to changes in the process or operation 
over time. While this method does tend to provide the most accurate 
CO2 emissions measurements and can

[[Page 16549]]

measure both the combustion- and process-related CO2 
emissions, it is likely the costliest of all the monitoring methods. 
Installation of CEMS would require significant additional burden to 
facilities given that few soda ash facilities currently have 
CO2 CEMS.
    The various options of monitoring GHG emissions, as well as the 
domestic and international GHG monitoring guidelines and protocols 
researched, are elaborated in the Soda Ash Manufacturing TSD (EPA-HQ-
OAR-2008-0508-029).
4. Selection of Procedures for Estimating Missing Data
    We propose that no missing data procedures would apply to 
estimating CO2 process emissions because the calculations 
are based on production, or trona consumption, which are closely 
tracked production inputs and outputs. Given that the fractional purity 
would have to be tested on a daily basis, if a value is missing the 
test should be repeated. Therefore, 100 percent data availability would 
be required.
5. Selection of Data Reporting Requirements
    We propose that reported data include annual CO2 process 
emissions from each soda ash manufacturing line, and the number of soda 
ash manufacturing lines, as well as any stationary fuel combustion 
emissions. In addition, we propose that facilities report the following 
data for each soda ash manufacturing line: Annual soda ash production, 
annual soda ash production capacity, annual trona quantity consumed, 
fractional purity (i.e., inorganic carbon content) of the trona or soda 
ash, and number of operating hours in the calendar year. These 
additional data, most of which are used as a basis for calculating 
emissions, are needed to understand the emissions data, verify the 
reasonableness of the reported emissions, and identify outliers. A full 
list of data that would be reported is included in proposed 40 CFR part 
98, subparts A and CC.
6. Selection of Records That Must Be Retained
    We propose that facilities keep information on monthly production 
of soda ash (metric tons), monthly consumption of trona (metric tons), 
and daily fractional purity (i.e., inorganic carbon content) of the 
trona or soda ash. A full list of records that must be retained onsite 
is included in the proposed rule.

DD. Sulfur Hexafluoride (SF6) From Electrical Equipment

1. Definition of the Source Category
    The largest use of SF6, both in the U.S. and 
internationally, is as an electrical insulator and interrupter in 
equipment that transmits and distributes electricity. The gas has been 
employed by the electric power industry in the U.S. since the 1950s 
because of its dielectric strength and arc-quenching characteristics. 
It is used in gas-insulated substations, circuit breakers, other 
switchgear, and gas-insulated lines. SF6 has replaced 
flammable insulating oils in many applications and allows for more 
compact substations in dense urban areas. Currently, there are no 
available substitutes for SF6 in this application. For 
further information, see the SF6 from Electrical Equipment 
TSD (EPA-HQ-OAR-2008-0508-030).
    Fugitive emissions of SF6 can escape from gas-insulated 
substations and switch gear through seals, especially from older 
equipment. The gas can also be released during equipment manufacturing, 
installation, servicing, and disposal.
    PFCs are sometimes used as dielectrics and heat transfer fluids in 
power transformers. PFCs are also used for retrofitting CFC-113 cooled 
transformers. One PFC used in this application is perfluorohexane 
(C6F14). In terms of both absolute and carbon-
weighted emissions, PFC emissions from electrical equipment are 
generally believed to be much smaller than SF6 emissions 
from electrical equipment; however, there may be some exceptions to 
this pattern, according to the 2006 IPCC Guidelines.
    According to the 2008 U.S. Inventory, total U.S. estimated 
emissions of SF6 from an estimated 1,364 electric power 
system utilities \86\ were 12.4 million metric tons CO2e in 
2006. We do not have an estimate of PFC emissions.
---------------------------------------------------------------------------

    \86\ The estimated total number of electric power system (EPS) 
utilities includes all companies participating in the SF6 
Emission Reduction Partnership for Electric Power Systems and the 
number includes non-partner utilities with non-zero transmission 
miles. The estimated total number of EPS utilities that emit 
SF6 likely underestimates the population, as some 
utilities may own high-voltage equipment yet not own transmission 
miles. However, the estimated number is consistent with the U.S. 
inventory methodology, in which only non-partner utilities with non-
zero transmission miles and partner utilities are assumed to emit 
SF6.
---------------------------------------------------------------------------

    This source category comprises electric power transmission and 
distribution systems that operate gas-insulated substations, circuit 
breakers, and other switchgear, or power transformers containing 
sulfur-hexafluoride (SF6) or PFCs.
2. Selection of Reporting Threshold
    We propose to require electric power systems to report their 
SF6 and PFC emissions if the total nameplate capacity of 
their SF6-containing equipment exceeds 17,820 lbs of 
SF6. This threshold is equivalent to an emissions threshold 
of 25,000 metric tons CO2e, and was developed using 
historical (1999) data from utilities that participate in EPA's 
SF6 Emission Reduction Partnership for Electric Power 
Systems (Partnership).
    In addition, we considered emission-based threshold options of 
1,000 metric tons CO2e; 10,000 metric tons CO2e; 
and 100,000 metric tons CO2e. Nameplate capacity thresholds 
of 713; 7,128; and 71,280 lbs of SF6 for all utilities were 
also considered, corresponding to the emission threshold options of 
1,000; 10,000; and 100,000 metric tons CO2e, respectively. 
Summaries of the threshold options (capacity-based and emissions-based) 
and the number of utilities and emissions falling above each threshold 
are presented in Tables DD-1 and DD-2 of this preamble.

                                      Table DD-1. Options for Capacity-Based Thresholds for Electric Power Systems
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
  Nameplate capacity threshold for all  utilities  (lbs      emissions     Total number  ---------------------------------------------------------------
                          SF6)                              MMTCO2e/yr    of  facilities    MMTCO2e/yr        Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
713.....................................................            12.4           1,364           12.19              98             578              42
7,128...................................................            12.4           1,364           10.96              88             183              13
17,820..................................................            12.4           1,364           10.32              83             141              10
71,280..................................................            12.4           1,364            5.95              48              35               3
--------------------------------------------------------------------------------------------------------------------------------------------------------


[[Page 16550]]


                                      Table DD-2. Options for Emissions-Based Thresholds for Electric Power Systems
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
           Threshold level metric tons CO2e/yr               emissions     Total number  ---------------------------------------------------------------
                                                            MMTCO2e/yr    of  facilities    MMTCO2e/yr        Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................            12.4           1,364           12.20              98             564              41
10,000..................................................            12.4           1,364           10.87              88             158              12
25,000..................................................            12.4           1,364           10.11              82             111               8
100,000.................................................            12.4           1,364            5.84              47              27               2
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We selected a nameplate capacity threshold equivalent to the 25,000 
metric tons CO2e emissions threshold level. A capacity-based 
threshold was selected because it permits utilities to quickly 
determine whether they are covered. There have been many mergers and 
acquisitions in the electric power industry and nameplate capacity is 
generally a known variable as a result of these transactions.
    The proposed threshold is consistent with the threshold for other 
source categories. Based on information from the Partnership and from 
the Universal Database Interface Directory of Electric Power Producers 
and Distributors, we estimate that the nameplate capacity threshold 
covers only a small percentage of total utilities (10 percent or 141 
utilities), while covering the majority of annual emissions 
(approximately 83 percent).
    Other Options Considered. We considered setting a threshold based 
on the length of the transmission lines, defined as the miles of lines 
carrying voltages above 34.5 kV, owned by electric power systems. The 
transmission-mile threshold equivalent to 25,000 metric tons 
CO2e is 1,186 miles. The fractions of utilities and 
emissions covered by this threshold would be almost identical to those 
covered by the nameplate-capacity threshold.
    We decided not to propose the transmission-mile threshold because 
the relationship between emissions and transmission miles, while 
strong, is not as strong as that between emissions and nameplate 
capacity. On the one hand, some utilities have far larger nameplate 
capacities and emissions than would be expected based on their 
transmission miles. This is the case for some urban utilities that have 
large volumes of SF6 in gas-insulated switchgear. On the 
other hand, some utilities have lower nameplate capacities and 
emissions than would be expected based on their transmission miles, 
because most of their transmission lines use lower voltages than 
average and therefore typically use less SF6 than average as 
well.
    Additional information supporting the selection of the threshold 
can be found in the SF6 from Electrical Equipment TSD (EPA-
HQ-OAR-2008-0508-030). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    In developing the proposed approach, we reviewed the 2006 IPCC 
Guidelines, the SF6 Emissions Reduction Partnership for 
Electric Power Systems, the U.S. GHG Inventory, DOE 1605(b), EPA's 
Climate Leaders Program, and TCR. In the IPCC Guidelines, Tiers 1 and 2 
are based on default SF6 and PFC emission factors, but Tier 
3 is based on using utility-specific information to estimate emissions 
of both SF6 and PFC using a mass-balance analysis.
    The proposed monitoring methods for calculating SF6 and 
PFC emissions from electric power systems are similar to the 
methodologies described in EPA's SF6 Emission Reduction 
Partnership for Electric Power Systems (Partnership) Inventory 
Reporting Protocol and Form and the 2006 IPCC Guidelines Tier 3 methods 
for emissions from electrical equipment. In general, these protocols 
and guidance all support using a mass-balance approach as the most 
accurate alternative to estimate emissions.
    We propose that you report all SF6 and PFC emissions, 
including those from equipment installation, equipment use, and 
equipment decommissioning and disposal. This requirement would apply 
only to systems where the total nameplate capacity of their 
SF6-containing equipment exceeds 17,820 lbs of 
SF6. The Tier 3 approach is being proposed because it is the 
most accurate and it is feasible for all systems to conduct the mass 
balance analysis for SF6 and PFC using readily available 
information.
    The mass-balance approach works by tracking and systematically 
accounting for all facility uses of SF6 and PFC during the 
reporting year. The quantities of SF6 and PFC that cannot be 
accounted for are assumed to have been emitted to the atmosphere. The 
emissions of SF6 and PFC would be estimated and reported 
separately.
    The following equation describes the proposed utility-level mass-
balance approach:
    User Emissions = Decrease in SF6 Inventory + 
Acquisitions of SF6-Disbursements of SF6-Net 
Increase in Total Nameplate Capacity of Equipment

Where:

    Decrease in SF6 Inventory is SF6 stored in containers 
(but not in equipment) at the beginning of the year minus 
SF6 stored in containers (but not in equipment) at the 
end of the year.
    Acquisitions of SF6 is SF6 purchased from 
chemical producers or distributors in bulk + SF6 
purchased from equipment manufacturers or distributors with or 
inside of equipment + SF6 returned to site after off-site 
recycling.
    Disbursements of SF 6 is SF6 in bulk and contained in 
equipment that is sold to other entities + SF6 returned 
to suppliers + SF6 sent off-site for recycling + 
SF6 sent to destruction facilities.
    Net Increase in Total Nameplate Capacity of Equipment is the 
Nameplate capacity of new equipment minus Nameplate capacity of 
retiring equipment. (Note that Nameplate capacity refers to the full 
and proper charge of equipment rather than to the actual charge, 
which may reflect leakage.)

    The same method is being proposed to estimate emissions of PFCs 
from power transformers.
    Other Options Considered. We also considered the IPCC Tier 1 and 
the IPCC Tier 2 methods for calculating and reporting SF6 
and PFC emissions, but did not choose them for several reasons. 
Although the IPCC Tier 1 method is simpler, the default emission 
factors have large uncertainty due to variability associated with 
handling and management practices, age of equipment, mix of equipment, 
and other similar factors. Utilities participating in EPA's Partnership 
have reduced their emission factors to less than Tier 1 default values. 
Less than 10 percent of U.S. utilities participate in this program; 
however, these utilities represent close to 40 percent of the U.S. 
grid, so the IPCC Tier 1 emission factors are not

[[Page 16551]]

accurate for a large percentage of the U.S. source category.
    IPCC Tier 2 methods use country-specific emission factors, but the 
Partner utilities have demonstrated by calculating their own utility-
level emission rates that large variability exists in utility-level 
emission rates across the nation (i.e., emission rates range from less 
than one percent of a utility's SF6 inventory to greater 
than 35 percent). As a result, we are not proposing the IPCC Tier 2 
method.
4. Selection of Procedures for Estimating Missing Data
    It is expected that utilities should have 100 percent of the data 
needed to perform the mass balance calculations for both SF6 
and PFCs. Partner utilities missing inputs to the mass-balance approach 
have estimated emissions using other methods, such as assuming that all 
purchased SF6 is emitted. However, this method over-
estimates emissions, and we do not recommend this method of estimation 
in the absence of more complete data. The use of the mass-balance 
approach requires correct records for all inputs.
5. Selection of Data Reporting Requirements
    We propose annual reporting for facilities in the electric power 
systems industry. Each facility would report all SF6 and PFC 
emissions, including those from equipment installation, equipment use, 
and equipment decommissioning and disposal. However, the emissions 
would not need to be broken down and reported separately for 
installation, use or disposal. Along with their emissions, utilities 
would be required to submit the following supplemental data, nameplate 
capacity (existing as of the beginning of the year, new during the 
year, and retired during the year), transmission miles, SF6 
and PFC sales and purchases, SF6 and PFC sent off-site for 
destruction or to be recycled, SF6 and PFC returned from 
offsite after recycling, SF6 and PFC stored in containers at 
the beginning and end of the year, SF6 and PFC with or 
inside new equipment purchased in the year, SF6 and PFC with 
or inside equipment sold to other entities and SF6 and PFC 
returned to suppliers.
    These data would be submitted because they are the minimum data 
that are needed to understand and reproduce the emission calculations 
that are the basis of the reported emissions. Transmission miles would 
be included in the reported data so that the reasonableness of the 
reported emissions could be quickly checked using default emission 
factors.
6. Selection of Records That Must Be Retained
    We propose that electric power systems be required to keep records 
documenting (1) their adherence to the QA/QC requirements specified in 
the proposed rule, and (2) the data that would be included in their 
emission reports, as specified above. The QA/QC requirements records 
include check-out sheets and weigh-in procedures for cylinders, 
residual gas amounts in cylinders sent back to suppliers, invoices for 
gas and equipment purchases or sales, and records of equipment 
nameplate capacity. The records that are being proposed are the minimum 
needed to reproduce and confirm emission calculations.

EE. Titanium Dioxide Production

1. Definition of the Source Category
    Titanium dioxide is a metal oxide commonly used as a white pigment 
in paint manufacturing, paper, plastics, rubber, ceramics, fabrics, 
floor covering, printing ink, and other applications. The majority of 
TiO2 production is for the manufacturing of white paint. 
National production of TiO2 in 2006 was approximately 
1,400,000 metric tons.
    Titanium dioxide is produced through two processes: The chloride 
process and the sulfate process. According to USGS, most facilities in 
the U.S. employ the chloride process. Total U.S. production of titanium 
dioxide pigment through the chloride process was approximately 1.4 
metric tons in 2006, a 7 percent increase compared to 2005. The 
chloride process emits process-related CO2 through the use 
of petroleum coke and chlorine as raw materials, while the sulfate 
process does not emit any significant process-related GHGs.
    The chloride process is based on two chemical reactions. Petroleum 
coke (C) is oxidized as the reducing agent in the first reaction in the 
presence of chlorine and crystallized iron titanium oxide 
(FeTiO3) to form and emit CO2. A special grade of 
petroleum coke, known as calcined petroleum coke, is a highly 
electrically conductive carbon (fixed carbon content >98 percent) and 
is used in several manufacturing processes including titanium dioxide 
(in the chloride process), aluminum, graphite, steel, and other carbon 
consuming industries. For the purposes of this rulemaking effort EPA is 
assuming the carbon content factor for calcined petroleum coke is 100 
percent or a multiplier of 1. Therefore, no site-specific factor needs 
to be determined. The titanium tetrachloride (TiCl4) 
produced through this first reaction is oxidized with oxygen at about 
1,000 [deg]C, and calcinated in a second reaction to remove residual 
chlorine and any hydrochloric acid that may have formed in the reaction 
producing titanium dioxide (TiO2).
    National emissions from titanium dioxide production were estimated 
to be 3.6 million metric tons CO2e in 2006. These emissions 
include process-related (CO2) and on-site stationary 
combustion emissions (CO2, CH4, and 
N2O) from eight production facilities. Process-related 
emissions from titanium dioxide production were 1.87 million metric 
tons CO2e or 47 percent of the total, while on-site 
combustion emissions account for the remaining 1.8 million metric tons 
CO2e emissions in 2006.
    For additional background information on titanium dioxide 
production, please refer to the Titanium Dioxide Production TSD (EPA-
HQ-OAR-2008-0508-031).
2. Selection of Reporting Threshold
    In developing the threshold for titanium dioxide production, we 
considered an emissions-based threshold of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e. Table EE-1 of 
this preamble illustrates the emissions and facilities that would be 
covered under these various thresholds.

                         Table EE-1. Threshold Analysis for Titanium Dioxide Production
----------------------------------------------------------------------------------------------------------------
                                                                Emissions covered          Facilities covered
 Threshold level metric tons  Total national     Total    ------------------------------------------------------
           CO2e/yr               emissions     number of     Metric tons
                                               facilities      CO2e/yr       Percent       Number      Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................       3,685,777            8       3,685,777          100            8          100
10,000......................       3,685,777            8       3,685,777          100            8          100
25,000......................       3,685,777            8       3,685,777          100            8          100

[[Page 16552]]

 
100,000.....................       3,685,777            8       3,628,054           98            7           88
----------------------------------------------------------------------------------------------------------------

    At the threshold levels of 1,000 metric tons CO2e, 
10,000 metric tons CO2e, and 25,000 metric tons 
CO2e, all facilities exceed the threshold, therefore 
covering 100 percent of total emissions. At the 100,000 metric tons 
CO2e level, one facility would not exceed the threshold and 
98 percent of emissions would be covered. In order to simplify the 
rule, and avoid the need for the source to calculate and report whether 
the facility exceeds threshold value, we are proposing that all 
titanium dioxide production facilities report. Including all facilities 
simplifies the rule and ensures 100 percent coverage without 
significantly increasing the number of affected facilities expected to 
report relative to the 25,000 metric ton threshold.
    For a full discussion of the threshold analysis, please refer to 
the Titanium Dioxide Production TSD (EPA-HQ-OAR-2008-0508-031). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating process-related 
emissions from titanium dioxide production (e.g., the 2006 IPCC 
Guidelines, U.S. GHG Inventory, Australian Government's National 
Greenhouse and Energy Reporting System). These methods coalesce around 
two different options.
    Option 1. CO2 emissions are estimated by applying a 
default emission factor to annual facility level titanium dioxide 
production.
    Option 2. CO2 emissions are estimated based on the 
facility-specific quantity of reducing agents or calcined petroleum 
coke consumed.
    Option 3. Direct measurement of emissions using CEMS.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Where the CEMS capture all combustion- and 
process-related CO2 emissions you would be required to 
follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of proposed 40 CFR part 98, subpart C to estimate 
CO2 emissions. Also, refer to proposed 40 CFR part 98, 
subpart C to estimate combustion-related CH4 and 
N2O emissions.
    Under this proposed rule, if you do not have CEMS that meet the 
conditions outlined in proposed 40 CFR part 98, subpart C, we propose 
that facilities use the second option discussed above to estimate 
process-related CO2 emissions. Refer to proposed 40 CFR part 
98, subpart C specifically for procedures to estimate combustion-
related CO2, CH4 and N2O emissions.
    Under this approach the total amount of calcined petroleum coke 
consumed would be assumed to be directly converted into CO2 
emissions. The amount of calcined petroleum coke can be obtained from 
facility records, as that data would be readily available. The carbon 
oxidation factor for the calcined petroleum coke is assumed to be 100 
percent, because any amount that is not oxidized is an insignificant 
amount. For the purposes of this rulemaking effort EPA is assuming the 
carbon oxidation factor for calcined petroleum coke, is equal to 100/
100 or 1. Therefore, no site-specific factor needs to be determined.
    We decided not to propose the option to use continuous direct 
measurement because it would not lead to significantly reduced 
uncertainty in the emissions estimate over the proposed option. 
Furthermore, the cost impact of requiring the installation of CEMS is 
high in comparison to the relatively low amount of emissions that would 
be quantified from the titanium production sector.
    We decided not to propose the option to apply default emission 
factors to titanium dioxide production to quantify process-related 
emissions. Although default emissions factors have been developed for 
quantifying process-related emissions from titanium dioxide production, 
the use of these default values is more appropriate for sector wide or 
national total estimates than for determining emissions from a specific 
plant. Estimates based on site-specific consumption of reducing agents 
are more appropriate for reflecting differences in process design and 
operation. According to the 2006 IPCC Guidelines, the uncertainty 
associated with the proposed approach is much lower given that 
facilities closely track consumption of the calcined petroleum coke 
(accurate within 2 percent), whereas the uncertainty associated with 
the default emission factor is approximately 15 percent.
    The various approaches to monitoring GHG emissions are elaborated 
in the Titanium Dioxide Production TSD (EPA-HQ-OAR-2008-0508-031).
4. Selection of Procedures for Estimating Missing Data
    It is assumed that a facility would be able to supply data on 
annual calcined petroleum coke consumption data. Therefore, 100 percent 
data availability is required for all parameters.
5. Selection of Data Reporting Requirements
    We propose that facilities submit process-related CO2 
emissions on an annual basis, as well as any stationary fuel combustion 
emissions. In addition we propose that facilities report the following 
additional data used as the basis of the calculations to assist in 
verification of estimates, checks for reasonableness, and other data 
quality considerations. The data includes: annual production of 
titanium dioxide, annual amount of calcined petroleum coke consumed, 
and number of operating hours in the calendar year. Facilities are not 
required to submit carbon oxidation factor for calcined petroleum coke; 
this value is assumed to be 100 percent, as any amount that is not 
oxidized is assumed to be an insignificant amount. A full list of data 
to be reported is included in proposed 40 CFR part 98, subparts A and 
EE.
6. Selection of Records That Must Be Retained
    In addition to the data reported, we propose that facilities 
maintain records of monthly production of titanium dioxide and monthly 
amounts of calcined petroleum coke consumed. These records hold values 
that are directly used to calculate the emissions

[[Page 16553]]

that are reported and are necessary to allow determination of whether 
GHG emissions monitoring and calculations were done correctly. They 
also are needed to understand the emissions data and verify the 
reasonableness of the reported emissions and identify potential 
outliers.
    A full list of records that must be retained onsite is included in 
proposed 40 CFR part 98, subparts A and EE.

FF. Underground Coal Mines

1. Definition of the Source Category
    Coal mining can produce significant amounts of CH4 from 
the following areas and activities: Active underground coal mines, 
surface coal mines, post-coal mining activities and abandoned 
underground coal mines.
    An active underground coal mine is a mine at which coal is produced 
by tunneling into the earth to a subsurface coal seam, which is then 
mined with equipment such as cutting machines, extracted and 
transported to the surface. In underground mines, CH4 is 
released from the coal and surrounding rock strata due to mining 
activities, and can create an explosive hazard. Ventilation systems 
dilute in-mine concentrations to within safe limits, and exhaust 
CH4 to the atmosphere.
    Mines that produce large amounts of CH4 also rely on 
degasification (or ``drainage'') systems to remove CH4 from 
the coal seam in advance of, during, or after mining, producing high-
concentration CH4 gas.
    CH4 from degasification and ventilation systems can be 
liberated to the atmosphere or destroyed. Destroyed CH4 
includes, but is not limited to, CH4 combusted by flaring, 
CH4 destroyed by thermal oxidation, CH4 combusted 
for use in onsite energy or heat production technologies, 
CH4 that is conveyed through pipelines (including natural 
gas pipelines) for offsite combustion, and CH4 that is 
collected for any other onsite or offsite use as a fuel.
    At surface mines, CH4 in the coal seams is directly 
exposed to the atmosphere.
    Post coal mining activities release emissions as coal continues to 
emit CH4 as it is stored in piles, processed, and 
transported.
    At abandoned (closed) underground coal mines, CH4 from 
the coal seam and mined-out area may vent to the atmosphere through 
fissures in rock strata or through incompletely sealed boreholes. It is 
possible to recover and use the CH4 stored in abandoned coal 
mines.
    Total U.S. CH4 emissions from active mining operations 
in 2006 were estimated to be 58.5 million metric tons CO2e 
from these sources. Of this, active underground mines accounted for 61 
percent of emissions, or 35.9 million metric tons CO2e, 
surface mines accounted for 24 percent of emissions, or 14.0 million 
metric tons CO2e, and post-mining emissions accounted for 15 
percent, or 8.6 million metric tons CO2e. CH4 
emissions from abandoned (closed) underground coal mines were estimated 
to contribute another 5.4 million metric tons CO2e. On-site 
stationary fuel combustion emissions at coal mining operations 
accounted for an estimated 9.0 million metric tons CO2e 
emissions in 2006. Proposed requirements for stationary fuel combustion 
emissions are set forth in proposed 40 CFR part 98, subpart C.
    We propose to require reporting of emissions from ventilation and 
degasification systems at active underground mines in this rule. This 
includes the fugitive CH4 from these systems and also 
CO2 emissions from destruction of coal mine gas 
CH4, where the gas is not a fuel input for energy generation 
or use. Due to difficulties associated with obtaining accurate 
measurements from surface mines, post-mining activities, and abandoned 
(closed) mines, and in some cases, difficulties in identifying owners 
of these sources, we propose to exclude fugitive CH4 
emissions from these sources from this rule. These sources could still 
surpass the threshold for stationary fuel combustion activities and 
therefore be required to report stationary fuel combustion-related 
emissions.
    Although fugitive CO2 may be emitted from coal seams, it 
is not typically a significant source of emissions from U.S. coal seams 
compared to CH4. Furthermore, methodologies are not widely 
available to measure these emissions, and therefore they are not 
proposed for inclusion in this rule.
    For additional background information on coal mining, please refer 
to the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
2. Selection of Reporting Threshold
    In developing the threshold for active underground coal mines, we 
considered emissions-based thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e for total 
onsite emissions from stationary fuel combustion, ventilation, and 
degasification. We also considered requiring all coal mines for which 
CH4 emissions from the ventilation system are sampled 
quarterly by the MSHA to report under this proposal. Table FF-1 of this 
preamble illustrates the emissions and facilities that would be covered 
under these various thresholds.

                                     Table FF-1. Threshold Analysis for Coal Mining at Active Underground Coal Mines
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                            Total national                         Emissions covered              Facilities covered
                                               emissions     Total number  ---------------------------------------------------------------
    Threshold level metric tons CO2e/yr      (metric tons    of facilities    Metric tons
                                                 CO2e)                          CO2e/yr         Percent       Facilities        Percent
------------------------------------------------------------------------------------------------------------------------------------------
MSHA reporting............................      39,520,000             612      33,945,956              86             128              21
1,000.....................................      39,520,000             612      33,945,446              86             125              20
10,000....................................      39,520,000             612      33,926,526              86             122              20
25,000....................................      39,520,000             612      33,536,385              85             100              16
100,000...................................      39,520,000             612      31,054,856              79              53               9
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We propose that all active underground coal mines for which 
CH4 from the ventilation system is sampled quarterly by MSHA 
(or on a more frequent basis), are required to report under this rule. 
MSHA conducts quarterly testing of CH4 concentration and 
flow at mines emitting more than 100,000 cf CH4 per day. We 
selected this threshold because subjecting underground mine operators 
to a new emissions-based threshold is unnecessarily burdensome, as many 
of these mines are already subject to MSHA regulations. The MSHA 
threshold for reporting of 100,000 cf CH4 per day covers 
approximately 94 percent of the CH4 emitted from underground 
coal mine ventilation systems and about 86 percent of total emissions 
from underground mining

[[Page 16554]]

(including stationary fuel combustion emissions at mine sites, as shown 
in Table FF-1 of this preamble).
    For additional background information on the thresholds for coal 
mining, please refer to the Underground Coal Mines TSD (EPA-HQ-OAR-
2008-0508-032). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating CH4 emissions 
from coal mining (e.g., the 2006 IPCC Guidelines, U.S. GHG Inventory, 
DOE 1605(b), and Australia's National Greenhouse Gas and Energy 
Reporting System). These methodologies coalesce into three different 
approaches.
    Option 1. Engineering approaches, whereby default emission factors 
would be applied to total annual coal production (for ventilation 
systems), or emission factors associated with the system type (for 
degasification systems) to estimate fugitive emissions.
    Option 2. Periodic sampling of CH4. Quarterly or more 
frequent samples could be taken in order to develop a site-specific 
emission factor.
    Option 3. Use of CEMS.
    Proposed Option for Liberated Ventilation CH4. We propose Option 2, 
quarterly sampling of ventilation air for monitoring ventilation 
CH4 liberated from coal mines.
    Under this option, coal mine operators are required to either (a) 
independently collect quarterly samples of CH4 released from 
the ventilation system(s), using MSHA procedures, have these samples 
analyzed for CH4 composition, and report the results to us, 
or (b) to obtain the results from the quarterly testing that MSHA 
already conducts, and report those to EPA.
    MSHA inspectors currently perform quarterly mine safety inspections 
on mines emitting 100,000 cf CH4 or more per day, and as 
part of these inspections, the inspectors test CH4 emissions 
rates and ventilation shaft flow, using MSHA-approved sampling 
procedures and devices. The sample bottles are sent to the MSHA lab for 
analysis and the results are provided back to the MSHA district offices 
for inclusion in the inspection report. Currently, the results of these 
quarterly measurements are generally not provided back to the mine.
    We would like to take comment on whether relying on MSHA sampling 
procedures,\87\ which were developed to ensure adherence to safety 
standards, is appropriate and sufficiently accurate for a GHG emissions 
reporting program. Further, we are interested in viewpoints on whether 
quarterly sampling is sufficient to account for potential fluctuations 
in emissions over smaller time increments (e.g., daily) from the mine. 
For more information on the MSHA sampling procedures, please refer to 
the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
---------------------------------------------------------------------------

    \87\ NIOSH, Handbook for Methane Control in Mining, CDC 
Information Circular 9486, June 2006.
---------------------------------------------------------------------------

    For all ventilation systems with CH4 destruction, 
CH4 destruction would be monitored through direct 
measurement of CH4 flow to combustion devices with 
continuous flow monitoring systems. The resulting CO2 
emissions would be calculated from these monitored values. If 
CH4 from ventilation systems is destroyed, such a system 
would have sufficient continuous monitoring devices associated with it 
that such required monitoring would not propose any additional burden.
    We considered requiring mines to monitor ventilation CH4 
concentrations by daily sampling, in place of quarterly sampling, for 
this rule. Many mines sample CH4 daily from ventilation 
systems using handheld CH4 analyzers. The primary advantages 
of this option are that many mines already take these measurements and 
this would therefore not impose an additional monitoring burden, and 
that daily measurements of CH4 concentration and ventilation 
shaft flowrates could allow for more accurate annual estimates than 
quarterly measurements. The primary disadvantages of this option 
relative to the other options that were considered are that it is not 
as accurate as continuous emissions measurements, and that, if 
required, it would impose a cost burden for those mines that do not 
already have a daily sampling and monitoring program in place.
    We also decided against requiring mines with CEMS installed at 
ventilation systems to use the continuous monitoring devices to monitor 
ventilation system CH4 emissions. Mines without CEMS would 
follow the quarterly option proposed above. In many underground mines, 
CEMS devices are already in operation. In such cases, this option may 
involve only placing such devices at or near the mine vent outflows 
where the air samples are taken by MSHA inspectors. The primary 
advantage of continuous monitoring is that it could increase the 
accuracy of annual CH4 emissions calculations because it 
takes into consideration any variability in emissions from mining 
operations that may not be represented in the quarterly sampling. 
Moreover, since such devices are already used within the mine to assess 
safety conditions, mine operator personnel are familiar with their 
operation. The disadvantage in requiring CEMS installation would be the 
larger costs associated with purchasing and maintaining these devices. 
We seek comment on the accuracy and cost of monitoring ventilation 
emissions with CEMS.
    Finally, we decided not to propose Option 1, which applies default 
emission factors to coal production. We decided against the use of the 
default CH4 emission factors because their application is 
more appropriate for GHG estimates from aggregated process information 
on a sector-wide or national basis than for determining GHG emissions 
from specific mines.
    Proposed Option for Degasification. We propose that all coal mine 
operators subject to this rule that deploy degasification systems in 
underground mines install continuous monitors for CH4 
content and flowrates on all degasification wells or degasification 
vent holes, and that all CH4 liberated and CH4 
destroyed from these systems be reported (Option 3). For all systems 
with CH4 destruction, CH4 destruction would be 
monitored through direct measurement of CH4 flow to 
combustion devices with continuous monitoring systems. The resulting 
CO2 emissions would be calculated from these monitored 
values. Option 3 is consistent with current practices for 
CH4 that is destroyed, where the produced gas volume is 
presumably already being measured with continuous monitors. For gas 
that is simply vented to the atmosphere from degasification wells, this 
requirement would ensure that this gas is accurately measured.
    We considered, but are not proposing, Option 1, which would 
estimate CH4 emissions based on the type of degasification 
system employed. For example, in developing the U.S. GHG Inventory, we 
currently assume for selected mines that degasification emissions 
account for 40 percent of total CH4 liberated from the mine. 
This method is very simplistic and least costly, but there is 
relatively larger uncertainty associated with the emissions estimated. 
Considering that emissions from many degasification wells are currently 
monitored, and the need to characterize the quantity of these vented 
emissions more accurately, we do not believe this option is 
appropriate.

[[Page 16555]]

    We also considered, but are not proposing, Option 2, which would 
require mine operators to conduct periodic sampling of gob gas vent 
holes and any other degasification boreholes, rather than installing 
continuous monitoring. While such an approach would involve lower 
capital costs than CEMS, greater labor costs would be involved with 
traveling to each (often remote) well site to take samples. Moreover, 
this method would not accurately reflect fluctuations in gas quantity 
and CH4 concentration. Pre-mining degasification and gob 
wells are generally characterized by large variations in emissions over 
time, as emissions can decline rapidly in each individual well, while 
new wells/vents come on line as mining advances.
    The various approaches to monitoring GHG emissions are elaborated 
in the Underground Coal Mines TSD (EPA-HQ-OAR-2008-0508-032).
4. Selection of 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 shall be used in the calculations.
    For each missing value of CH4 concentration, flow rate, 
temperature, and pressure for ventilation and degassification systems, 
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.
5. Selection of Data Reporting Requirements
    We propose that coal mines report, for all ventilation shafts and 
degasification systems (e.g., all boreholes), the following parameters: 
CH4 liberated from the shaft or borehole, the quantity of 
CH4 destroyed (if applicable), and net CH4 
emissions on an annual basis. In addition to reporting emissions, all 
input data needed to calculate liberation and emissions are to be 
reported, as well as mine days of operation (for the ventilation and 
degasification systems). A full list of data to be reported is 
includedproposed 40 CFR part 98, subparts A and FF.
6. Selection of Records That Must Be Retained
    Reporters are to retain all data listed in Section V.FF.5 of this 
preamble. A full list of records to be retained onsite is included in 
proposed 40 CFR part 98, subparts A and FF.

GG. Zinc Production

1. Definition of the Source Category
    Zinc is a metal used as corrosion-protection coatings on steel 
(galvanized metal), as die castings, as an alloying metal with copper 
to make brass, and as chemical compounds in rubber, ceramics, paints, 
and agriculture. For this proposed rule, we are defining the zinc 
production source category to consist of zinc smelters using 
pyrometallurgical processes and secondary zinc recycling facilities. 
Zinc smelters can process zinc sulfide ore concentrates (primary zinc 
smelters) or zinc-bearing recycled and scrap materials (secondary zinc 
smelters). A secondary zinc recycling facility recovers zinc from zinc-
bearing recycled and scrap materials to produce crude zinc oxide for 
use as a feed material to zinc smelters. Many of these secondary zinc 
recycling facilities have been built specifically to process dust 
collected from electric arc furnace operations at steel mini-mills 
across the country.
    There are no primary zinc smelters in the U.S. that use 
pyrometallurgical processes. The one operating U.S. pyrometallurgical 
zinc smelter processes crude zinc oxide and calcine produced from 
recycled zinc materials. These feed materials are first processed 
through a sintering machine. The sinter is mixed with metallurgical 
coke and fed directly into the top of an electrothermic furnace. 
Metallic zinc vapor is drawn from the furnaces into a vacuum condenser, 
which is then tapped to produce molten zinc metal. The molten metal is 
then transferred directly to a zinc refinery or cast into zinc slabs.
    Secondary zinc recycling facilities operating in the U.S. use 
either of two thermal processes to recover zinc from recycled electric 
arc furnace dust and other scrap materials. For the Waelz kiln process, 
the feed material is charged to an inclined rotary kiln together with 
petroleum coke, metallurgical coke, or anthracite coal. The zinc oxides 
in the gases from the kiln are then collected in a baghouse or 
electrostatic precipitator. The second recovery process used for 
electric arc furnace dust uses a water-cooled, flash-smelting furnace 
to form vaporized zinc that is subsequently captured in a vacuum 
condenser. The crude zinc oxide produced at secondary zinc recycling 
facilities is shipped to a zinc smelter for further processing.
    Zinc production results in both combustion and process-related GHG 
emissions. The major sources of GHG emissions from a zinc production 
facility are the process-related emissions from the operation of 
electrothermic furnaces at zinc smelters and Waelz kilns at secondary 
zinc recycling facilities. In an electrothermic furnace, reduction of 
zinc oxide using carbon provided by the charging of coke to the furnace 
produces CO2. In the Waelz kiln, the zinc feed materials are 
heated to approximately 1200 [deg]C in the presence of carbon producing 
zinc vapor and carbon monoxide (CO). When combined with the surplus of 
air in the kiln, the zinc vapors are oxidized to form crude zinc oxide, 
and the CO oxidized to form process-related CO2 emissions.
    Total nationwide GHG emissions from zinc production facilities 
operating in the U.S. were estimated to be approximately 851,708 metric 
tons CO2e for the year 2006. This total GHG emissions 
estimate includes both process-related emissions (CO2 and 
CH4) and the additional combustion emissions 
(CO2, CH4, and N2O). Process-related 
GHG emissions were approximately 528,777 metric tons CO2e 
emissions (62 percent of the total emissions). The remaining 38 percent 
or 322,931 metric tons CO2e are from onsite stationary 
combustion.
    Additional background information about GHG emissions from the zinc 
production source category is available in the Zinc Production TSD 
(EPA-HQ-OAR-2008-0508-033).
2. Selection of Reporting Threshold
    Zinc smelters and secondary zinc recycling facilities in the U.S. 
vary in types and sizes of the metallurgical processes used and mix of 
zinc-containing feedstocks processed to produce zinc products. In 
developing the threshold for zinc production facilities, we considered 
using annual GHG emissions-based threshold levels of 1,000, 10,000, 
25,000 and 100,000 metric tons CO2e. Table GG-1 of this 
preamble illustrates the emissions and facilities that would be covered 
under these various thresholds.

[[Page 16556]]



                                              Table GG-1. Threshold Analysis for Zinc Production Facilities
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                               Total                             Emissions covered              Facilities covered
                                                            nationwide       National    ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr               emissions       number of
                                                            metric tons     facilities      Metric tons       Percent       Facilities        Percent
                                                              CO2e/yr                         CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................         851,708               9         851,708             100               9             100
10,000..................................................         851,708               9         843,154              99               8              89
25,000..................................................         851,708               9         801,893              94               5              56
100,000.................................................         851,708               9         712,181              84               4              44
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We have concluded, based on emissions estimates using production 
capacity, that the one primary zinc facility exceeds all thresholds 
considered (Table GG-1 of this preamble). For the eight secondary zinc 
production facilities, just half are over a 25,000 metric tons 
CO2e threshold. We decided it is appropriate to propose a 
threshold of 25,000 metric tons CO2e for reporting emissions 
from zinc production facilities that is consistent with the threshold 
level being proposed for other source categories. This threshold level 
would avoid placing a reporting burden on a zinc production facility 
with inherently low GHG emissions because of the type of metallurgical 
processes used and type of zinc product produced while still requiring 
the reporting of GHG emissions from the zinc production facilities 
releasing most of the GHG emissions in the source category. More 
discussion of the threshold selection analysis is available in the Zinc 
Production TSD (EPA-HQ-OAR-2008-0508-033). For specific information on 
costs, including unamortized first year capital expenditures, please 
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    EPA reviewed existing domestic and international GHG monitoring 
guidelines and protocols including the 2006 IPCC Guidelines, U.S. GHG 
Inventory, the EU Emissions Trading System, the Canadian Mandatory GHG 
Reporting Program, and the Australian National GHG Reporting Program. 
These methods coalesce around the following four options for estimating 
process-related GHG emissions from zinc production facilities. Zinc 
smelters using hydrometallurgical processes (e.g., electrolysis) would 
not be subject to the estimating and reporting requirements in proposed 
40 CFR part 98, subpart GG for zinc production because the processes 
used at these smelters do not release process-related GHG emissions. 
However, combustion GHG emissions from the process equipment at these 
smelters burning natural gas or other carbon-based fuels could be 
subject to the estimating and reporting requirements for general 
stationary fuel combustion units in proposed 40 CFR part 98, subpart C, 
depending on the level of total GHG emissions from the facility with 
respect to the reporting thresholds specified in proposed 40 CFR part 
98, subpart A.
    Option 1. Apply a default emission factor for the process-related 
emissions to the facility zinc production rate. This is a simplified 
emission calculation method using only default emission factors to 
estimate CO2 emissions. The method requires multiplying the 
amount of zinc produced by the appropriate default emission factors 
from the 2006 IPCC Guidelines.
    Option 2. Perform a carbon balance of all inputs and outputs using 
monthly measurements of the carbon content of specific process inputs 
and measure the mass rate of these inputs. This method is the same as 
the IPCC Tier 3 approach and the higher order methods in the Canadian 
and Australian reporting programs. Implementation of this method 
requires owners and operators of affected zinc smelters to determine 
the carbon contents of materials added to the electrothermic furnace or 
Waelz kiln by analysis of representative samples collected of the 
material or from information provided by the material suppliers. In 
addition, the quantities of these materials consumed during production 
are measured and recorded. To obtain the process-related CO2 
emission estimate, the material carbon content would be multiplied by 
the corresponding mass of material consumed and a factor for conversion 
of carbon to CO2. This method assumes that all of the carbon 
is converted during the reduction process. The facility owner or 
operator would determine the average carbon content of the material for 
each calendar month using information provided by the material supplier 
or by collecting a composite sample of material and sending it to an 
independent laboratory for chemical analysis.
    Option 3. Use CO2 emissions data from a stack test 
performed using U.S. EPA reference test methods to develop a site-
specific process emissions factor which is then applied to quantity 
measurement data of feed material or product for the specified 
reporting period. This monitoring method is applicable to furnace or 
Waelz kiln configurations for which the GHG emissions are contained 
within a stack or vent. Using site-specific emissions factors based on 
short-term stack testing is appropriate for those facilities where 
process inputs (e.g., feed materials, carbonaceous reducing agents) and 
process operating parameters remain relatively consistent over time.
    Option 4. Use direct emissions measurement of CO2 
emissions. For furnace and kiln configurations in which the process 
off-gases are contained within a stack or vent, direct measurement of 
the CO2 emissions can be made by either continuously 
measuring the off-gas stream CO2 concentration and flow rate 
using a CEMS, or periodically measuring the off-gas stream 
CO2 concentration and flow rate using standard stack testing 
methods. Using a CEMS, the recorded emissions measurement data would be 
reported annually. An annual emissions test could be used to develop a 
site-specific process emissions factor which would then be applied to 
quantity measurement data of feed material or product for the specified 
reporting period.
    Proposed Option. Under this proposed rule, if you are required to 
use an existing CEMS to meet the requirements outlined in proposed 40 
CFR part 98, subpart C, you would be required to use CEMS to estimate 
CO2 emissions. Provided that the CEMS capture all 
combustion- and process-related CO2 emissions, you would be 
required to follow the requirements of proposed 40 CFR part 98, subpart 
C to estimate CO2 emissions from the industrial source. You 
would also refer to proposed 40 CFR part 98, subpart C to estimate 
combustion-related CH4 and N2O emissions.

[[Page 16557]]

    If you do not have CEMS that meet the conditions outlined in 
proposed 40 CFR part 98, subpart C, or where the CEMS would not 
adequately account for process emissions, we propose that you follow 
Option 2, a carbon balance. You would still need to refer to proposed 
40 CFR part 98, subpart C to estimate combustion-related CH4 
and N2O emissions. Given the operating variations between 
the individual U.S. zinc production facilities (including differences 
in equipment configurations, mix of zinc feedstocks charged, and types 
of carbon materials used) we are proposing Option 2 to estimate 
CO2 emissions from an electrothermic furnace or Waelz kiln 
at zinc production facilities because of the lower uncertainties 
indicated by the IPCC Guidelines for these types of emissions 
estimates, as compared to applying exclusively a default emissions 
factor based approach to these units on a nationwide basis.
    We decided not to propose the use of default CO2 
emission factors (Option 1) because their application is more 
appropriate for GHG estimates from aggregated process information on a 
sector-wide or nationwide basis than for determining GHG emissions from 
specific facilities. According to the 2006 IPCC Guidelines, the 
uncertainty associated with default emission factors could be as high 
as 50 percent, while the uncertainty associated with facility specific 
estimates of process inputs and carbon contents would be within 5 to 10 
percent. We considered the additional burden of the material 
measurements required for the carbon calculations small in relation to 
the increased accuracy expected from using this site-specific 
information to calculate the process-related CO2 emissions.
    We also decided against proposing Option 3 because of the potential 
for significant variations at zinc production facilities in the 
characteristics and quantities of the furnace or Waelz kiln inputs 
(e.g., zinc scrap materials, carbonaceous reducing agents) and process 
operating parameters. A method using periodic, short-term stack testing 
would not be practical or appropriate for those zinc production 
facilities where the furnace or Waelz kiln inputs and operating 
parameters do not remain relatively consistent over the reporting 
period.
    Further details about the selection of the monitoring methods for 
GHG emissions are available in the Zinc Production TSD (EPA-HQ-OAR-
2008-0508-033).
4. Selection of Procedures for Estimating Missing Data
    For electrothermic furnaces or Waelz kilns for which the owner or 
operator calculates process GHG emissions using site-specific 
carbonaceous input material data, the proposed rule requires the use of 
substitute data whenever a quality-assured value of a parameter that is 
used to calculate GHG emissions is unavailable, or ``missing.'' If the 
carbon content analysis of carbon inputs is missing or lost the 
substitute data value would be the average of the quality-assured 
values of the parameter immediately before and immediately after the 
missing data period. In those cases when an owner or operator uses 
direct measurement by a CO2 CEMS, the missing data 
procedures would be the same as the Tier 4 requirements described for 
general stationary fuel combustion sources in proposed 40 CFR part 98, 
subpart C.
5. Selection of Data Reporting Requirements
    The proposed rule would require annual reporting of the total 
annual CO2 process-related emissions from the electrothermic 
furnaces and Waelz kilns at zinc production facilities, as well as any 
stationary fuel combustion emissions. In addition we propose that 
additional information which forms the basis of the emissions estimates 
also be reported so that we can understand and verify the reported 
emissions. This additional information includes the total number of 
Waelz kilns and electrothermic furnaces operated at the facility, the 
facility zinc product production capacity, and the number of facility 
operating hours in calendar year, carbon inputs by type, and carbon 
contents of inputs by type.
    A complete list of data to be reported is included in proposed 40 
CFR part 98, subparts A and GG.
6. Selection of Records That Must Be Retained
    Maintaining records of the information used to determine the 
reported GHG emissions is necessary to enable us to verify that the GHG 
emissions monitoring and calculations were done correctly. We propose 
that all affected facilities maintain records of monthly facility 
production quantities for each zinc product, number of facility 
operating hours each month, and the annual facility production quantity 
for each zinc product (in tons). If you use the carbon input procedure, 
you would record for each carbon-containing input material consumed or 
used (other than fuel) the monthly material quantity, monthly average 
carbon content determined for material, and records of the supplier 
provided information or analyses used for the determination. If you use 
the CEMS procedure, you would maintain the CEMS measurement records.
    A complete list of records to be retained is included in proposed 
40 CFR part 98, subparts A and GG.

HH. Landfills

1. Definition of the Source Category
    After being placed in a landfill, waste is initially decomposed by 
aerobic bacteria, and then by anaerobic bacteria, which break down 
organic matter into substances such as cellulose, amino acids, and 
sugars. These substances are further broken down through fermentation 
into gases and short-chain organic compounds that form the substrates 
for the growth of methanogenic bacteria, which convert the fermentation 
products into stabilized organic materials and biogas.
    CH4 generation from a given landfill is a function of 
several factors, including the total amount of waste disposed in the 
landfill, the characteristics of the waste, and the climatic 
conditions. The amount of CH4 emitted is the amount of 
CH4 generated minus the amount of CH4 that is 
destroyed and minus the amount of CH4 oxidized by aerobic 
microorganisms in the landfill cover material prior to being released 
into the atmosphere.
    Waste decaying in landfills also produces CO2; however, 
this CO2 is not counted in GHG totals as it is not 
considered an anthropogenic emission. Likewise, CO2 
resulting from the combustion of landfill CH4 is not 
accounted as an anthropogenic emission under international accounting 
guidance.
    According to the 2008 U.S. Inventory, MSW landfills emitted 111.2 
million metric tons CO2e of CH4 in 2006. 
Generation of CH4 at these landfills was 246.8 million 
metric tons CO2e; however, 65.3 million metric tons 
CO2e were recovered and used (destroyed) in energy projects, 
59.8 million metric tons CO2e were destroyed by flaring, and 
12.4 million metric tons CO2e were oxidized in cover soils. 
The majority of the CH4 emissions from on-site industrial 
landfills occur at pulp and paper facilities and food processing 
facilities. In 2006, these landfills emitted 14.6 million metric tons 
CO2e CH4: 7.3 million metric tons CO2e 
from pulp and paper facilities, and 7.2 million metric tons 
CO2e from food processing facilities.

[[Page 16558]]

    We propose to require reporting from open and closed,\88\ MSW 
landfills meeting or exceeding the thresholds described below. We also 
propose to require reporting of industrial landfills (e.g., landfills 
at food processing, pulp and paper, and ethanol production facilities) 
meeting or exceeding the applicable thresholds in the relevant 
subparts. Hazardous waste landfills and construction and demolition 
landfills are not included in the landfills source category as they are 
not considered significant sources of GHG emissions.
---------------------------------------------------------------------------

    \88\ For the purposes of this rule, an open landfill is one that 
has accepted waste during the reporting year.
---------------------------------------------------------------------------

    The definition of landfills in this rule does not include land 
application units. Several refineries have land application units (also 
known as land treatment units) in which oily waste is tilled into the 
soil. We are seeking comment on the exclusion of land application units 
from this rule.
    For additional background information on landfills, please refer to 
the Landfills TSD (EPA-HQ-OAR-2008-0508-034).
2. Selection of Reporting Threshold
    In developing the threshold for landfills, we considered thresholds 
of 1,000, 10,000, 25,000, and 100,000 metric tons CO2e of 
CH4 generation at a landfill minus soil oxidation 
(``generation threshold'') or of CH4 emissions from a 
landfill, minus oxidation, after any destruction of landfill gas at a 
combustion device (``emissions threshold'').
    Table HH-1 of this preamble illustrates the emissions and 
facilities that would be covered under these various thresholds for MSW 
landfills. For landfills located at industrial facilities,\89\ please 
refer to the threshold analyses for those sectors (e.g., food 
processing, ethanol, pulp and paper).
---------------------------------------------------------------------------

    \89\ As explained in sections III and IV of this preamble, many 
facilities reporting to the proposed rule will have more than one 
source category. In order to determine applicability, facilities 
must add the emissions from all source categories for which there 
are methods proposed in the proposed rule.

                                           Table HH-1. Threshold Analysis for MSW Landfills (Open and Closed)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   Total national                       Emissions covered          Facilities covered
                                                                      emissions    Total national ------------------------------------------------------
                         Threshold level                            (metric tons     facilities      Metric tons
                                                                        CO2e)                        CO2e /year      Percent       Number      Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000 metric tons CO2e (generation)..............................     111,100,000            7800     110,800,000         99.7        6,830           88
1,000 metric tons CO2e (emissions)...............................     111,100,000            7800     110,800,000         99.7        6,827           88
10,000 metric tons CO2e (generation).............................     111,100,000            7800     104,400,000           94        3,484           45
10,000 metric tons CO2e (emissions)..............................     111,100,000            7800     102,800,000           93        3,060           39
25,000 metric tons CO2e (generation).............................     111,100,000            7800      91,100,000           82        2,551           33
25,000 metric tons CO2e (emissions)..............................     111,100,000            7800      82,400,000           74        1,926           25
100,000 metric tons CO2e (generation)............................     111,100,000            7800      65,600,000           59        1,038           13
100,000 metric tons CO2e (emissions).............................     111,100,000            7800      39,300,000           35          441            6
--------------------------------------------------------------------------------------------------------------------------------------------------------

    The proposed threshold for reporting emissions from MSW landfills 
is a generation threshold of 25,000 metric tons CO2e (i.e., 
CH4 generated at the landfill, minus oxidation in landfill 
cover soils). This threshold is consistent with thresholds for other 
source categories and covers over 70 percent of emissions from the 
source category. It strikes a balance between the goal of covering the 
majority of the emissions while avoiding a reporting burden for small 
MSW landfills and, especially, small, closed MSW landfills.
    For a full discussion of the threshold analysis, please refer to 
the Landfills TSD (EPA-HQ-OAR-2008-0508-034). For specific information 
on costs, including unamortized first year capital expenditures, please 
refer to section 4 of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    This section of the preamble describes the proposed methods for 
estimating CH4 generation and emissions from landfills and 
for determining the quantity of landfill CH4 destroyed.
    Many domestic and international GHG monitoring guidelines and 
protocols include methodologies for estimating emissions from landfills 
(e.g., 2006 IPCC Guidelines, U.S. GHG Inventory, CCAR, EPA Climate 
Leaders, EU Emissions Trading System, TCR, EPA's Landfill Methane 
Outreach Program, DOE 1605(b), Australia's National Mandatory GHG 
Reporting Program (draft), NSPS/NESHAP, WRI/WBCSD GHG Protocol, and 
National Council of Air and Stream Improvement). In general, these 
methodologies include three methods for monitoring emissions: The 
modeling method, the engineering method, and the direct measurement 
method.
    Option 1. Modeling Method. The IPCC First Order Decay Model \90\ in 
the 2006 IPCC Guidelines produces emissions estimates that reflect the 
degradation rate of wastes in a landfill. This method uses waste 
disposal quantities, degradable organic carbon, dissimilated degradable 
organic carbon, a decay rate, time lag before CH4 
generation, fraction of CH4 in landfill gas, and an 
oxidation factor.
---------------------------------------------------------------------------

    \90\ The IPCC First Order Decay Model is available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol5.html.
---------------------------------------------------------------------------

    Option 2. Engineering Method. Direct measurement of collected 
landfill gas to determine CH4 generation from landfills 
depends on two measurable parameters: The rate of gas flow to the 
destruction device; and the CH4 content of the gas. These 
are quantified by directly measuring the flow rate and CH4 
concentration of the gas stream to the destruction device(s).
    Option 3. Direct Measurement. Direct measurement methods for 
calculating CH4 emissions from landfills include flux 
chambers and optical remote sensing.
    Proposed Option. As part of this proposed rule, stationary fuel 
combustion emissions unrelated to the flaring of recovered landfill 
CH4, and emissions from the use of auxiliary fuel to 
maintain effective operation of the flare (e.g., for pilot gas, or fuel 
used to supplement the heating value of the landfill gas occurring at 
the landfill), would be estimated and reported according to the 
proposed procedures in proposed 40 CFR part 98, subpart C (General 
Stationary Fuel Combustion Sources), which are discussed in Section V.C 
of this preamble.
    In order to estimate CH4 emissions from the landfill we 
propose a combination of Option 1 and Option 2.
    Modeling method. In the proposed rule, all landfills would be 
required to

[[Page 16559]]

calculate CH4 generation and emissions using the IPCC First 
Order Decay Model. The IPCC First Order Decay Model has two calculation 
options: A bulk waste option and a waste material-specific option. The 
proposed rule would require the use of the material-specific option for 
all industrial landfills, and for MSW landfills when material-specific 
waste quantity data are available, as this option is expected to 
provide more accurate emission estimates. However, the accuracy 
improvement is limited and at MSW landfills, material-specific waste 
quantity data are expected to be sparse, so use of the waste material-
specific approach would not be mandated for all MSW landfills. Where 
landfills do not have waste material-specific data, the bulk waste 
option would be used.
    We propose that the landfills use site-specific data to determine 
waste disposal quantities (by type of waste material disposed when 
material-specific waste quantity data are available) and use 
appropriate EPA and IPCC default values for all other factors used in 
the emissions calculation. To accurately estimate emissions using this 
method, waste disposal data are needed for the 50 year period prior to 
the year of the emissions estimate. Annual waste disposal data are 
estimated using receipts for disposal where available, and where 
unavailable, estimates based on national waste disposal rates and 
population served by the landfill.
    Engineering method. For landfills with gas collection systems, it 
is also possible to estimate CH4 generation and emissions 
using gas flow and composition metering along with an estimate of the 
landfill gas collection efficiency. We propose to require landfills 
that have gas collection systems to calculate their CH4 
generation (adjusted for oxidation) and emissions using both the IPCC 
First Order Decay Model (as described above), and the measured 
CH4 collection rates and estimated gas collection 
efficiency. This proposal provides a means by which all landfills would 
report emissions and generation consistently using the same (IPCC First 
Order Decay Model) methodology, while also providing reporting of site-
specific emissions and generation estimates based on gas collection 
data.
    We propose that landfills with gas collection systems continuously 
measure the CH4 flow and concentration at the flare or 
energy device. This monitoring option is more accurate than a monthly 
sample given variability in gas flow and concentration over time, and 
many landfills with gas collection systems already have such equipment 
in place.
    We are seeking comment on monthly sampling of landfill gas 
CH4 flow and concentration as an alternative to a continuous 
composition analyzer. For the monthly sampling alternative, a 
continuous gas flowmeter would still be required.
    To estimate CH4 emissions remaining in the landfill gas 
combustion exhaust of a destruction device, apply the DE of the 
equipment to the quantity of CH4 collected as measured by 
the monitoring systems described above.
    Calculating generation and emissions. CH4 generation 
(adjusted for oxidation) is calculated by applying an oxidation factor 
to generated CH4. For landfills without gas collection 
systems, the calculated value for CH4 generation (adjusted 
for oxidation) is equal to CH4 emissions. For landfills with 
collection systems, CH4 generation is also calculated using 
both the IPCC First Order Decay model method and the gas collection 
data measurement method with a collection efficiency as explained 
above. CH4 emissions are calculated by deducting destroyed 
CH4 and applying an oxidation factor to the fraction of 
generated CH4 that is not destroyed.
    Direct Measurement Method. We also considered direct measurement at 
landfills as an option. The direct measurement methods available (e.g., 
flux chambers and optical remote sensing) are currently being used for 
research purposes, but are complex and costly, their application to 
landfills is still under investigation, and they may not produce 
accurate results if the measuring system has incomplete coverage.
    We are considering developing a tool to assist reporters in 
calculating generation and emissions from this source category. We have 
reviewed tools for calculating emissions and emissions reductions from 
these sources, including IPCC's Waste Model, and National Council of 
Air and Stream Improvement's GHG Calculation Tools for Pulp and Paper 
Mills, and EPA's LandGEM, and are seeking comment on the advantages and 
disadvantages of using these tools as a model for tool development and 
on the utility of providing such a tool.
4. Selection of Procedures for Estimating Missing Data
    Missing data procedures for landfills are proposed based on the 
monitoring methodology. In the case where a monitoring system is used, 
the substitute value would be calculated as the average of the values 
immediately proceeding and succeeding the missing data period. For 
prolonged periods of missing data when a monitoring system is used, or 
for other non-monitored data, the substitute data would be determined 
from the average value for the missing parameter from the previous 
year, or from equations specified in the rule (for waste disposal 
quantities). The proposed rule would require a complete record of all 
parameters determined from company records that are used in the GHG 
emissions calculations (e.g., disposal data, gas recovery data).
    For purposes of the emissions calculation, we considered not 
deducting CH4 destruction that was not recorded. However, 
not including CH4 recovery could greatly overestimate a 
facility's emissions. On the other hand, allowing extended periods of 
missing data provides a disincentive to repairing the monitoring 
system.
5. Selection of Data Reporting Requirements
    We propose that landfills over the threshold report CH4 
generation, CH4 oxidation, CH4 destruction (if 
applicable), and net CH4 emissions on an annual basis, as 
calculated above using both the First Order Decay Model and, if 
applicable, gas flow data for landfills with gas collection systems. In 
addition to reporting emissions, input data needed to calculate 
CH4 generation and emissions would be required to be 
reported. These data form the basis of the GHG emission calculations 
and are needed for EPA to understand the emissions data and verify the 
reasonableness of the reported data. A full list of data to be reported 
is included in proposed 40 CFR part 98, subparts A and HH.
6. Selection of Records That Must Be Retained
    Records to be retained include information on waste disposal 
quantities, waste composition if available, and biogas measurements. 
These records are needed to allow verification that the GHG emission 
monitoring and calculations were done correctly. A full list of records 
to be retained onsite is included in proposed 40 CFR part 98, subparts 
A and HH.

II. Wastewater Treatment

1. Definition of the Source Category
    An industrial wastewater treatment system is a system located at an 
industrial facility which includes the collection of processes that 
treat or remove pollutants and contaminants, such as soluble organic 
matter, suspended solids, pathogenic organisms, and chemicals from 
waters

[[Page 16560]]

released from industrial processes. Industrial wastewater treatment 
systems may include a variety of processes, ranging from primary 
treatment for solids removal to secondary biological treatment (e.g., 
activated sludge, lagoons) for organics reduction to tertiary treatment 
for nutrient removal, disinfection, and more discrete filtration. In 
some systems, the biogas (primarily CH4) generated by 
anaerobic digestion of organic matter is captured and destroyed by 
flaring and/or energy recovery. The components and configuration of an 
industrial wastewater treatment system are determined by the type of 
pollutants and contaminants targeted for removal or treatment. 
Industrial wastewater systems that rely on microbial activity to 
degrade organic compounds under anaerobic conditions are sources of 
CH4.
    CH4 emissions from wastewater treatment systems are 
primarily a function of how much organic content is present in the 
wastewater system and how the wastewater is treated. Industries that 
have the potential to produce significant CH4B emissions 
from wastewater treatment--those with high volumes of wastewater 
generated and a high organic wastewater load--include pulp and paper 
manufacturing, food processing, ethanol production, and petroleum 
refining.
    Wastewater treatment also produces CO2; however, with 
the exception of CO2 from oil/water separators at petroleum 
refineries, this CO2 is not counted in GHG totals as it is 
not considered an anthropogenic emission. Likewise, CO2 
resulting from the combustion of digester CH4 is not 
accounted as an anthropogenic emission under international accounting 
guidance.
    In 2006, CH4B emissions from industrial wastewater 
treatment were estimated to be 7.9 million metric tons CO2e.
    The only wastewater treatment process emissions to be reported in 
this rule are those from onsite wastewater treatment located at 
industrial facilities, such as at pulp and paper, food processing, 
ethanol production, petrochemical, and petroleum refining facilities. 
POTWs are not included in this proposal because, as described in the 
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035), emissions from 
POTWs do not exceed the thresholds considered under this rule.
2. Selection of Reporting Threshold
    A separate threshold is not proposed for emissions from industrial 
wastewater treatment system as these emissions occur in a number of 
facilities across a range of industries (e.g., pulp and paper, food 
processing, ethanol production, petrochemical, and petroleum refining). 
As described in Sections III and IV of this preamble, a facility may 
have more than one source category and emissions from all source 
categories for which there are methods (e.g., emissions from industrial 
wastewater treatment systems) must be included in the facility's 
applicability determination. Please see the preamble sections for the 
relevant sectors for more information on the applicability 
determination for your facility.
    Despite the fact that we are not proposing a separate threshold for 
industrial wastewater systems, there is analysis in the Wastewater 
Treatment TSD on the types of industrial facilities that would meet 
thresholds at the 1,000, 10,000, 25,000 and 100,000 million metric tons 
CO2e level based on emissions from wastewater alone. There 
is also a separate threshold analysis on POTWs.
    For a full discussion of those threshold analyses, please refer to 
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    For this proposal, we reviewed several protocols and programs for 
monitoring and/or estimating GHG emissions including the 2006 IPCC 
Guidelines, the U.S. GHG Inventory, CARB Mandatory GHG Emissions 
Reporting System, CCAR, National Council of Air and Stream Improvement, 
DOE 1605(b), EPA Climate Leaders, TCR, UNFCCC Clean Development 
Mechanism, the EU Emissions Trading System, and the New Mexico 
Mandatory GHG Reporting Program. These methodologies are all primarily 
based on the IPCC Guidelines.
    Based on this review, we considered the following options.
    Option 1. Modeling Method. This method involves the use of certain 
site-specific measured activity data and emission factors. The IPCC 
method, for example, uses wastewater flow, COD, and wastewater 
treatment system type to calculate CH4 emissions from 
wastewater treatment.
    Option 2. Direct Measurement. This method allows for site-specific 
measurements, but the methods available (e.g., flux chambers and open 
path methods) are currently being used only for research purposes, are 
complex and costly, and might not be accurate if the measuring system 
has incomplete coverage.
    Proposed Methods. We propose that facilities use activity data, 
such as measured COD concentration, and operational characteristics 
(e.g., type of system), and the IPCC Tier 1 method to calculate 
CH4 generation. To determine CH4 destruction, we 
propose direct measurement of CH4 flow to combustion 
devices. The proposed monitoring method uses a separate equation to 
estimate CO2 from oil/water separators at petroleum 
refineries, based on California's AB32 mandatory reporting rule. This 
approach allows the use of default factors, such as a system emission 
factor, for certain elements of the calculation, and the use of site-
specific data where possible.
    CH4 emissions from industrial wastewater treatment 
system components other than digesters. To estimate the amount of 
CH4 emissions from industrial wastewater treatment, plant-
specific values of COD would be determined by weekly sampling. The 
maximum amount of CH4 that could potentially be produced by 
the wastewater under ideal conditions is calculated by multiplying the 
COD by the maximum CH4 producing capacity of the wastewater, 
per the 2006 IPCC Guidelines. This value is then multiplied by a 
system-specific CH4 conversion factor reflecting the 
capability of a system to produce the maximum achievable CH4 
based on the organic matter present in the wastewater.
    CH4 Generation from Anaerobic Digesters. If the 
wastewater treatment system includes an anaerobic digester, we propose 
that the CH4 generation of the digester be measured 
continuously. Direct measurement to determine CH4 generation 
from digesters depends on two measurable parameters: The rate of gas 
flow to the combustion device and the CH4 content of the 
gas. These are quantified by direct measurement of the gas stream to 
the destruction device(s). The gas stream is measured by continuous 
metering of both flow and gas concentration. This continuous monitoring 
option is more accurate than a monthly sample given variability in gas 
flow and concentration over time, and many digesters already have such 
equipment in place.
    We are also seeking comment on monthly sampling of digester gas 
CH4 content as an alternative to a continuous composition 
analyzer. For the monthly CH4 content sampling alternative, 
a continuous gas flow meter would still be required.
    CH4 Destruction. To estimate CH4 destroyed at 
a digester, you would apply

[[Page 16561]]

the DE of the combustion equipment (lesser of manufacturer's specified 
DE and 0.99) to the value of CH4 generated from anaerobic 
digestion estimated above.
    CO2 emissions from oil/water separators at petroleum 
refineries. To calculate CO2 emissions from degradation of 
petroleum or impurities at oil/water separators at petroleum 
refineries, the volume of wastewater treated would be measured weekly 
and multiplied by the non-methane volatile organic carbon emission 
factor for the type of separator used, and an emission factor for 
CO2 (mass of CO2/mass of non-methane volatile 
organic carbon).
    Total emissions. Total emissions from wastewater treatment are the 
sum of the CH4 emissions (including undestroyed 
CH4 from digesters), and CO2 emissions.
    Other Options Considered. Direct measurement is another option we 
considered but are not proposing in this rule. This method allows for 
site-specific measurements, but it is costly and might not be accurate 
if the measuring system has incomplete coverage. To be accurate, a 
direct measurement system would need to be complete both spatially (in 
that all emissions pathways are covered, not just individual pathways 
as is the case with anaerobic digesters, at which gas is commonly 
directly metered) and temporally (as emissions can vary greatly due to 
changes in influent and conditions at the facility).
    We are considering developing a tool to assist reporters in 
calculating emissions from this source category. EPA has reviewed tools 
for calculating emissions from these sources, such as National Council 
of Air and Stream Improvement's GHG Calculation Tools for Pulp and 
Paper Mills, and is seeking comment on the advantages and disadvantages 
of using these tools as a model for tool development, and the utility 
of providing such a tool.
    For additional information on the proposed method, please see the 
2006 IPCC Guidelines,\91\ the 2008 U.S. Inventory,\92\ and the 
Wastewater Treatment TSD (EPA-HQ-OAR-2008-0508-035).
---------------------------------------------------------------------------

    \91\ 2006 IPCC Guidelines. Chapter 6: Wastewater Treatment and 
Discharge. (Volume 5 Waste.) Available at http://www.ipcc-nggip.iges.or.jp/public/2006gl/pdf/5_Volume5/V5_6_Ch6_Wastewater.pdf.
    \92\ 2008 U.S. Inventory. Chapter 8: Waste. Available at http://www.epa.gov/climatechange/emissions/usinventoryreport.html.
---------------------------------------------------------------------------

4. Selection of Procedures for Estimating Missing Data
    On the occasion that a facility lacks data needed to determine the 
emissions from wastewater treatment over a period of time, we propose 
that the facility apply an average facility-level value for the missing 
parameter from measurements of the parameter preceding and following 
the missing data incident, as specified in the proposed rule. The 
proposed rule would require a complete record of all parameters 
determined from company records that are used in the GHG emissions 
calculations (e.g., production data, biogas combustion data).
    For purposes of the emissions calculations, we considered not 
deducting CH4 destruction that was not recorded. However, 
not including CH4 destruction could greatly overestimate a 
facility's actual CH4 emissions.
5. Selection of Data Reporting Requirements
    EPA proposes that industrial wastewater treatment plants over the 
threshold report annually both CH4 and CO2 
emissions from wastewater treatment system components other than 
digesters, and CH4 generation and destruction at digesters. 
In addition to reporting emissions, generation, and destruction, input 
data used to calculate emissions from the wastewater treatment process 
would be required to be reported. These data form the basis of the GHG 
emission calculations and are needed for EPA to understand the 
emissions data and verify the reasonableness of the reported data.
    A full list of data to be reported is included in proposed 40 CFR 
part 98, subparts A and II.
6. Selection of Records That Must Be Retained
    Records to be retained include information on influent flow rate, 
COD concentration, wastewater treatment system types, and digester 
biogas measurements. These records are needed to allow verification 
that the GHG emission monitoring and calculations were done correctly. 
A full list of records to be retained onsite is included in proposed 40 
CFR part 98, subparts A and II.

JJ. Manure Management

1. Definition of the Source Category
    A manure management system is a system that stabilizes or stores 
livestock manure, or does both. Anaerobic manure management systems 
include liquid/slurry handling in uncovered anaerobic lagoons, ponds, 
tanks, pits, or digesters. At some digesters, material other than 
manure is treated along with the manure. Manure management systems in 
which treatment is primarily aerobic include daily spread, solid 
storage, drylot, and manure composting. For the purposes of this rule, 
a manure management facility consists of uncovered anaerobic lagoons, 
liquid/slurry systems, pits, digesters, and drylots (including systems 
that combine drylot with solid storage) onsite manure composting, other 
poultry manure systems, and cattle and swine deep bedding systems. The 
manure management system does not include other onsite units and 
processes at a livestock operation unrelated to the stabilization and/
or storage of manure.
    When livestock manure are stored or treated, the anaerobic 
decomposition of materials in the manure management system produces 
CH4, while N2O is produced as part of the 
nitrogen cycle through the nitrification and denitrification of the 
organic nitrogen in livestock manure and urine. The amount and type of 
emissions produced are related to the specific types of manure 
management systems used at the farm and are driven by retention time, 
temperature, and treatment conditions.
    Manure management also produces CO2; however, this 
CO2 is not counted in GHG totals as it is not considered an 
anthropogenic emission. Likewise, CO2 resulting from the 
combustion of digester CH4 is not accounted as an 
anthropogenic emission under international accounting guidance.
    According to the 2008 U.S. Inventory, CH4 emissions from 
manure management systems totaled 41.4 million metric tons 
CO2e, and N2O emissions were 14.3 million metric 
tons CO2e in 2006; manure management systems account for 8 
percent of total anthropogenic CH4 emissions and 3 percent 
of N2O emissions in the U.S.
    Manure management systems which include one or more of the 
following components are to report emissions under this rule: Manure 
handling in uncovered anaerobic lagoons, liquid/slurry systems, pits, 
digesters, and drylots, including systems that combine drylot with 
solid storage. Emissions to be reported include those from the systems 
listed above, and also emissions from any high rise houses for caged 
laying hens, broiler and turkey production on litter, deep bedding 
systems for cattle and swine, and manure composting occuring onsite as 
part of the manure management system.
    This source category does not include systems which consist of only 
components classified as daily spread, solid storage, pasture/range/
paddock, or manure composting. For detailed descriptions of system 
types, please

[[Page 16562]]

refer to the Manure Management TSD (EPA-HQ-OAR-2008-0508-036).
    A facility that is subject to the proposed rule only because of 
emissions from manure management would also report CO2, 
CH4, and N2O emissions from the combustion of 
supplemental fuel in flares using the methods in proposed 40 CFR part 
98, subpart C, but would not be required to report any other combustion 
emissions.
2. Selection of Reporting Threshold
    In developing the threshold for manure management, we considered 
thresholds of 1,000, 10,000, 25,000, and 100,000 metric tons 
CO2e of CH4 generation and N2O 
emissions at a manure management system (``generation threshold''), and 
CH4 and N2O emissions at manure management 
systems (``emissions threshold''). The ``generation threshold'' is the 
amount of CH4 and N2O that would be emitted from 
the facility if no CH4 destruction takes place. This 
includes all CH4 generation from all manure management 
system types, including digesters, and N2O emissions. The 
``emissions threshold'' includes the CH4 and N2O 
that is emitted to the atmosphere from these facilities. In the 
emissions threshold, CH4 that is destroyed at digesters is 
taken into account and deducted from the total CH4 
generation calculated.
    To estimate the number of farms at each threshold, EPA first 
developed a number of model farms to represent the manure management 
systems that are most common on large farms and have the greatest 
potential to exceed the GHG thresholds. Next, we used EPA'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 farm type. Finally, we combined the numbers of livestock 
required on each model farm 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 farm.
    Table JJ-1 of this preamble presents the estimated head of 
livestock that would meet the thresholds evaluated for the highest GHG-
emitting common manure management systems for beef (steers and heifers 
at a feedlot), dairy (cows at an uncovered anaerobic lagoon, heifers on 
dry lot without solids separation), swine (farrow to finish at an 
uncovered anaerobic lagoon), and poultry (layers and pullets at an 
uncovered anaerobic lagoon).
    Other types of farms and manure management systems could require 
significantly higher head counts to meet the thresholds considered: 
Meeting the 25,000 tCO2e threshold could require 978,000 
head for beef on pasture, 13,000 head for some dairy liquid slurry 
systems, 171,000 head of farrow to finish swine using a deep pit for 
manure, and 47,028,300 broilers on litter. For more information on 
estimated head of livestock that would meet these thresholds for other 
manure management system types, please see the Manure Management TSD 
(EPA-HQ-OAR-2008-0508-036).

                           Table JJ-1. Estimated Head of Livestock To Meet Thresholds
----------------------------------------------------------------------------------------------------------------
 
----------------------------------------------------------------------------------------------------------------
                                                                      Threshold Levels (metric tons CO2e)
----------------------------------------------------------------------------------------------------------------
                                                                    1,000       10,000       25,000      100,000
                                                             ---------------------------------------------------
                                                                    Total number of head to meet threshold
----------------------------------------------------------------------------------------------------------------
Beef........................................................        3,500       35,500       89,000      356,000
Dairy.......................................................          200        2,000        5,000       20,000
Swine.......................................................        3,000       29,000       73,000      291,500
Poultry.....................................................       39,500      358,000      895,000    3,580,000
----------------------------------------------------------------------------------------------------------------

    Although data are available at the national level on the number of 
farms of certain sizes, most of the population sizes needed to meet 
these thresholds occur in the largest farm size categories, in which 
data are not sufficiently disaggregated to determine how many farms of 
such sizes exist. For example, the largest dairy farm size category for 
which data is available is ``1,000 head or more.'' The number of dairy 
farms with populations large enough to meet thresholds for 10,000 
metric tons CO2e (2,000 animals) and above therefore had to 
be estimated using expert judgment. It is estimated that at the 
proposed threshold, fewer than 50 manure management systems at beef, 
dairy, and swine operations would be required to report. Table JJ does 
not determine applicability alone, but rather serves as a ``screening'' 
guide in determining the approximate facility size that meets the 
applicability requirements. We are also seeking comment on the 
advantages and disadvantages of using additional screening tools such 
as a look-up table or computerized calculator to help owners or 
operators determine if they meet the reporting threshold. A table could 
be developed that indicated whether a facility had a sufficient number 
of animals to warrant further screening. If the initial screening 
through use of the table indicated that the facility may meet the 
reporting threshold a simple computerized calculator (e.g., web-based 
model) utilizing site-specifica data such as the type of manure 
management system and the average number of head, along with some other 
default data provided in look-up tables could be used to determine if a 
facility met the reporting threshold. Screening devices, if utilized, 
could assist owners or operators in determining if they are near the 
threshold for reporting and therefore potentially avoid costs incurred 
from monthly manure analysis proposed in the calculation method of the 
rule. More information and estimates based on existing farm size data 
are presented in the Manure Management TSD (EPA-HQ-OAR-2008-0508-036).
    The proposed threshold for reporting emissions from manure 
management systems is the emission threshold of 25,000 metric tons 
CO2e. More specifically, the CH4 and 
N2O emissions from manure management are summed to determine 
if a manure management system meets or exceeds the threshold. 
Facilities exceeding the threshold would report both of these GHG 
emissions. This threshold includes the largest emitters of GHG from 
this source category, while avoiding reporting from many small farms 
with less significant emissions. For a full discussion of the threshold 
analysis, please refer to Manure Management TSD (EPA-HQ-OAR-2008-0508-
036). For specific information on costs, including unamortized first 
year capital expenditures, please refer to section 4 of the RIA and the 
RIA cost appendix.

[[Page 16563]]

    We are seeking comment on the option of using a generation 
threshold instead of the proposed emissions threshold. In the 
generation threshold option, the CH4 generation (including 
CH4 generated and later combusted) and the N2O 
emissions from manure management are summed to determine if a manure 
management system meets or exceeds the threshold. Facilities exceeding 
the threshold would report both GHG generation and emissions. We 
estimated that this option would cover several farms with digesters 
that would not be covered in the emissions threshold option.
3. Selection of Proposed Monitoring Methods
    Many domestic and international GHG programs provide monitoring 
guidelines and protocols for estimating emissions from manure 
management (e.g., the 2006 IPCC Guidelines, the U.S. GHG Inventory, DOE 
1605(b), CARB Mandatory GHG Emissions Reporting System, CCAR, EPA 
Climate Leaders, TCR, UNFCCC Clean Development Mechanism, EPA AgSTAR, 
and Chicago Climate Exchange). These methodologies are all based on the 
IPCC Guidelines.
    Based on the review of these methods, we considered the following 
options.
    Option 1. Modeling Method. This method involves the use of certain 
site-specific measured activity data and emission factors. The IPCC 
method, for example, uses volatile solids, nitrogen excretion, climate 
data, and manure management system type to calculate CH4 and 
N2O emissions from manure management systems.
    Option 2. Direct Measurement. This method allows for site-specific 
measurements, but the methods available (e.g., flux chambers and open 
path methods) are currently being used only for research purposes, are 
complex and costly, and might not be accurate if the measuring system 
has incomplete coverage.
    Proposed option. We propose that facilities use activity data, such 
as the number of head of livestock, operational characteristics (e.g., 
physical and chemical characteristics of the manure, including measured 
volatile solids and nitrogen values, type of management system(s)), and 
climate data, with the IPCC method to calculate CH4 and 
N2O emissions, and measured values for gas destruction.
    CH4 emitted at manure management system types other than 
digesters. We propose that CH4 emissions at manure 
management system components other than digesters be calculated using 
the IPCC methodology and measured volatile solids values.
    We propose that the amount of volatile solids excreted be 
calculated using (1) calculation of manure quantity entering the system 
using livestock population data and default values for average animal 
mass and manure generation, and (2) monthly sampling and testing of 
excreted manure for total volatile solids content.
    We are seeking comment on the option of using facility-specific 
livestock population and mass, and default values for volatile solids 
rate to estimate total volatile solids, instead of measured values. We 
are also seeking comment on whether a different sampling and testing 
frequency, such as quarterly, would be more appropriate than monthly.
    The maximum amount of CH4 that could potentially be 
produced by the manure under ideal conditions would be calculated by 
multiplying the volatile solids by the maximum CH4-producing 
capacity of the manure (B0), a default value included in the GHG 
Inventory. A system-specific CH4 conversion factor would 
then be applied to determine the amount of CH4 produced by 
the specific system type.
    CH4 Generation at Digesters. If the manure management 
system includes a digester, we propose that the CH4 
generation of the digester be measured continuously. Direct measurement 
to determine CH4 generation from digesters depends on two 
measurable parameters: The rate of gas flow to the combustion device, 
and the CH4 content of the gas. These would be quantified by 
direct measurement of the total gas stream. We propose that the gas 
stream be measured by continuous metering of both flow and gas 
concentration. This continuous monitoring option is more accurate than 
a monthly sample given variability in gas flow and concentration over 
time, and many digesters already have such equipment in place.
    We are also seeking comment on monthly sampling of digester gas 
CH4 content as an alternative to a continuous composition 
analyzer. For the monthly CH4 content sampling alternative, 
a continuous gas flow meter would still be required.
    CH4 Destruction at Digesters. To estimate CH4 
destruction at a digester, you would apply the DE of the destruction 
equipment (lesser of manufacturer's specified DE and 0.99) and the 
ratio of operating hours to reporting hours to the value of 
CH4 generated from anaerobic digestion estimated above.
    CH4 Leakage at Digesters. To estimate CH4 
leakage from digesters, we propose that a default value for collection 
efficiency is applied to the measured quantity of CH4 flow 
to a destruction device. We are seeking comment on the proposed method 
and on the proposed default collection efficiency values for estimating 
leakage from digesters.
    CH4 Emissions from Digesters. We propose that emissions 
from digesters be calculated as the sum of CH4 that is not 
destroyed at the destruction device, and CH4 that leaks from 
the digester.
    N2O Emissions. We propose that N2O emissions 
be calculated using the IPCC methodology and measured nitrogen (N) 
values.
    We propose that the amount of nitrogen entering the manure 
management system be measured through (1) calculation of manure 
quantity entering the system using livestock population data and 
default values for average animal mass and manure generation, and (2) 
monthly sampling and testing of excreted manure for total nitrogen 
content.
    We are seeking comment on the option of using facility-specific 
livestock population and mass, and default values for nitrogen 
excretion rate to estimate total N, instead of measured values.
    Each manure management system type has an associated default 
N2O emission factor which would be applied to the amount of 
nitrogen managed by the system.
    GHG Emissions. Reporters would be required to complete the 
following to calculate the emissions for reporting.
    Estimate and report GHG emissions by adding the CH4 
emissions from manure management systems other than digesters, the 
N2O emissions from manure management systems, and, for 
manure management systems which include digesters, the CH4 
emissions (monitored CH4 generation at the digester minus 
CH4 destruction at the digester) from the anaerobic 
digester.
    Direct measurement is another option we considered but are not 
proposing in this rule. A direct measurement system must be complete 
both spatially (in that all emissions pathways are covered) and 
temporally (as emissions can vary greatly due to changes in population, 
diet, and conditions at the facility) and would hence be difficult and 
expensive to implement accurately.
    We are considering developing a tool to assist reporters in 
calculating emissions from this source category. There are several 
existing tools for calculating emissions and emissions reductions from 
manure management systems, including EPA's FarmWare and CCAR's 
Livestock Project Reporting Protocol. We are seeking comment on

[[Page 16564]]

the advantages and disadvantages of using such tools as a model for 
tool development and on the utility of providing such a tool.
    The various approaches to monitoring GHG emissions, as well as 
specific cost information, are elaborated in the Manure Management TSD 
(EPA-HQ-OAR-2008-0508-036).
4. Selection of Procedures for Estimating Missing Data
    On the occasion that a facility lacks sufficient data to determine 
the emissions from manure management over a period of time, we propose 
that the facility apply an average facility-level value for the missing 
parameter from measurements of the parameter preceding and following 
the missing data incident, as specified in the proposed rule. The 
proposed rule would require a complete record of all parameters 
determined from company records that are used in the GHG emissions 
calculations (e.g., historical livestock population data, biogas 
destruction data).
    For emissions calculation purposes, EPA considered not deducting 
CH4 recovery and destruction that was not recorded, but not 
including CH4 destruction could greatly overestimate an 
entity's actual CH4 emissions.
5. Selection of Data Reporting Requirements
    EPA proposes that facilities report CH4 and 
N2O emissions, along with the input data to calculate these 
values. These data form the basis of the GHG emission calculations and 
are needed for EPA to understand the emissions data and verify the 
reasonableness of the reported data. A full list of data to be reported 
is included in proposed 40 CFR part 98, subparts A and JJ.
6. Selection of Records That Must Be Retained
    Records to be retained include information on animal population, 
manure management system types, animal waste characteristics, and 
digester biogas measurements. These records are needed to allow 
verification that the GHG emission monitoring and calculations were 
done correctly. A full list of records to be retained onsite is 
included in proposed 40 CFR part 98, subparts A and JJ.

KK. Suppliers of Coal

1. Definition of the Source Category
    Proposed 40 CFR part 98, subpart KK would require reporting by 
facilities or companies that introduce or supply coal into the economy 
(e.g., coal mines, coal importers, and waste coal reclaimers). These 
facilities or companies (in the case of coal importers and exporters) 
would report on the CO2 emissions that would result from 
complete combustion or oxidation of the quantities of coal supplied. 
For completeness, this source category also includes coal exporters.
    Facilities that use coal for energy purposes should refer to 
proposed 40 CFR part 98, subpart C (General Stationary Fuel Combustion 
Sources). Facilities that use coal for non-energy uses (e.g., as a 
reducing agent in metal production such as ferroalloys, zinc, etc.) 
should refer to the relevant subparts of the proposed rule. Underground 
coal mine operators who are included in this subpart should also refer 
to proposed 40 CFR part 98, subpart FF (Underground Coal Mines) in 
order to account for any combustion and fugitive emissions separately, 
as described in Sections III and IV of this preamble. A description of 
the requirements related to the conversion of coal to liquid fuel is 
covered in Section V.LL of this preamble.
    Coal is a combustible black or brownish-black sedimentary rock 
composed mostly of carbon and hydrocarbons. It is the most abundant 
fossil fuel produced in the U.S. Over 90 percent of the coal used in 
the U.S. is used to generate electricity. Coal is also used as a basic 
energy source in many industries, including cement and paper. In 2006, 
the combustion of coal for useful heat and work resulted in emissions 
of 2,065.3 million metric tons CO2, or 29 percent of total 
U.S. GHG emissions.
    The supply chain for delivering coal to consumers is relatively 
straightforward. It includes coal mines or importers, in some cases 
coal washing or preparation onsite or at dedicated offsite plants, and 
transport (usually by rail) to consumers. The U.S. typically produces 
nearly all of its domestic coal needs; in 2007, domestic coal 
production accounted for 97 percent of domestic coal consumption. A 
relatively small share of coal consumed in the U.S. (3 percent in 2007) 
is imported from other countries, and a small share of U.S. production 
is exported for use abroad (5 percent in 2007).
    In determining the most appropriate point in the supply chain of 
coal for reporting potential CO2 emissions, we considered 
the following criteria: An administratively manageable number of 
reporting facilities; complete coverage of coal supply as a group of 
facilities or in combination with facilities reporting under other 
subparts of the proposed rule; minimal irreconcilable double-counting 
of coal supply; and feasibility of monitoring or calculation methods.
    We are proposing to include all active coal mines, coal importers, 
coal exporters, and reclaimers of waste coal as reporters under this 
subpart.
    We are proposing to require all owners or operators of active 
underground and surface coal mines to report under proposed 40 CFR part 
98, subpart KK. There were 1,365 active coal mines (both underground 
and surface mines) operating in the U.S. in 2007, according to the 
MSHA. Currently, coal mines routinely monitor coal quantity and coal 
quality data for use in coal sale contracts as well as for reporting 
requirements to various State and Federal agencies.
    We are proposing that importers of coal into the U.S. report under 
proposed 40 CFR part 98, subpart KK. Reporting for coal importers is 
proposed at the company level, as opposed to the facility level, 
because the importers of record are typically companies, and these 
companies currently track and report imports. Most of the 36 million 
tons of coal that were imported to the U.S. in 2007 were used for power 
generation. A small number of electric utility companies were 
responsible for the large majority of coal imports in 2006.\93\ In many 
cases, the importing companies also own and operate electricity 
generating or industrial facilities that would be included as covered 
facilities under other subparts of the proposed rule. Because these 
entities already collect much of this information, EPA believes that 
the reporting requirements for importers would impose a minimal 
additional burden.
---------------------------------------------------------------------------

    \93\ In 2006, the eight largest coal-importing power generating 
companies accounted for 87 percent of total imported coal by 
electric utilities (FERC Form 423 and EIA 906). Approximately 80 
percent of coal imports were used in the electricity sector in 2006.
---------------------------------------------------------------------------

    We are proposing that exporters of coal report under proposed 40 
CFR part 98, subpart KK. In 2007, 59.2 million tons of coal produced 
(mined) in the U.S. were exported. Coal exporters may include coal 
mining companies who directly sell their coal to entities outside the 
U.S., or other retailers who export the coal (typically via barge from 
one of several U.S. ports). Coal exports are included in proposed 40 
CFR part 98, subpart KK so that the total supply of coal (and 
associated GHG emissions) into the U.S. economy is balanced against the 
coal that leaves the country. Typically, coal exporters characterize 
the quantity (tons) and heat value of the coal. Thus, this reporting 
requirement would impose a minimal additional burden on coal exporters.

[[Page 16565]]

    We are proposing that reclaimers of waste coal report under 
proposed 40 CFR part 98, subpart KK. In some parts of the U.S., waste 
coal that was mined decades ago and placed in waste piles is now being 
actively recovered and sold to end users. Because this coal is 
technically not being ``mined'' but is nonetheless entering the U.S. 
economy for the first time, facilities that reclaim or recover such 
waste coal from waste coal piles and sell or deliver it to end-users 
are being included for reporting under proposed 40 CFR part 98, subpart 
KK as waste coal reclaimers. Because these facilities would need to 
collect data on the quantity and quality (e.g., heat value) of their 
product, this reporting requirement should impose a minimal additional 
burden on coal reclaimers.
    We considered but are not proposing that facilities that convert 
coking coal into industrial coke and importers of coke report under 
proposed 40 CFR part 98, subpart KK. U.S. coke imports in 2007 
constituted only 2.5 million tons (about 0.2 percent of total U.S. coal 
production) and can therefore be considered negligible. Most 
domestically consumed coal-based coke (87 percent) is derived from 
domestically-mined coal or imported coal, and therefore the inclusion 
of coal mines and coal importers in this subpart already provide for 
coverage of carbon contained in the coke (and the potential 
CO2 emissions from oxidizing or combusting the coke). Only 
14 percent of coal-based coke consumed domestically is imported 
directly as coke. Furthermore, coke production is an energy- and 
emissions-intensive process, and these facilities are likely to be 
above thresholds for the general stationary fuel combustion sources 
(proposed 40 CFR part 98, subpart C) and industrial process categories 
such as iron and steel, and ferro-alloys. Therefore, GHG emissions 
associated with the combustion or oxidation of coke imports and 
domestically produced coke would already be included in the actual GHG 
emissions reported under those subparts.
    We considered but are not proposing that coal preparation plants 
located offsite from coal mines report the potential CO2 
emissions associated with their processed coal. Some of these 
facilities may be included as reporting facilities under proposed 40 
CFR part 98, subpart C for direct emissions from combustion. An unknown 
but likely very small share of coal production annually requires 
additional preparation or washing at an offsite preparation plant. 
Typically, only the smaller mines do not do their preparation onsite. 
We are not requiring offsite coal preparation plants to report under 
this subpart because the potential CO2 emissions from coal 
supplied by these facilities is already accounted for by reported data 
from coal mines, coal importers, and waste coal reclaimers.
    Instead of requiring coal mines to report as coal suppliers, we 
also considered, but are not proposing, that rail operators report the 
quantity of coal they transport. We have determined that requiring 
reporting on coal transport would add complexity without increasing the 
accuracy of information on potential CO2 emissions 
associated with the supply of coal to the U.S. economy. It is our 
understanding that, unlike coal mines or coal importers, coal 
transporters do not routinely collect information about the carbon 
content or heating value of the coal they are transporting, so such 
reporting requirements would add to the reporting burden. Furthermore, 
in the case of mine mouth power plants for which the coal does not 
travel via rail, rail transporters would miss this coal production 
entirely.
    We request comment on the inclusion of active underground and 
surface coal mines, coal importers, coal exporters, and waste coal 
reclaimers, and the exclusion of offsite preparation plants, coke 
importers and coke manufacturing facilities, and coal rail transporters 
from reporting requirements under proposed 40 CFR part 98, subpart KK. 
For additional background information on suppliers of coal, please 
refer to the Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
2. Selection of Reporting Threshold
    In considering a threshold for coal suppliers, we considered the 
application of the following emissions-based thresholds for each 
affected company or facility under proposed 40 CFR part 98, subpart KK 
(e.g., coal mine, coal importer, coal exporter, or waste coal 
reclaimer): 1,000 metric tons CO2e, 10,000 metric tons 
CO2e, 25,000 metric tons CO2e and 100,000 metric 
tons CO2e per year. For coal suppliers, these thresholds 
would be applied to the CO2 emissions that would result from 
complete combustion or oxidation of the coal produced or supplied into 
the U.S. economy, rather than the actual GHG emissions for the 
individual facilities or companies. To provide general information on 
how the thresholds would affect the coal industry, we used a weighted 
average carbon content of 1,130 lbs/short ton.\94\ These thresholds 
translate into annual coal production for a single mine of 532 short 
tons, 5,321 short tons, 13,303 short tons, and 53,211 short tons, 
respectively.
---------------------------------------------------------------------------

    \94\ Carbon content is found using the weighted average of 
CO2 (lbs/MMbtu) from EIA Table FE4 along with the heat 
content (MMbtu/ton) and production (tons) from the 2007 MSHA 
database. The molecular mass ratio of carbon to CO2 (12/
44) is then used to find carbon content from the derived 
CO2 (4,143 lbs/short ton).
---------------------------------------------------------------------------

    Coal Mines. Table KK-1 of this preamble illustrates the coal mine 
emissions and facilities that would be covered under these various 
thresholds.

                                                      Table KK-1. Threshold Analysis for Coal Mines
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                            Total 2007                           Emissions covered              Facilities covered
                                                             national       Total 2007   ---------------------------------------------------------------
                                                             emissions       number of
           Threshold level metric tons CO2e/yr               (million      facilities in  Million metric                     Number of      Percent of
                                                            metric tons      the U.S.      tons CO2e/yr       Percent     facilities \3\    facilities
                                                           CO2e/yr) \1\                         \2\
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................           2,153           1,365           2,146            99.7           1,346              99
10,000..................................................           2,153           1,365           2,146            99.7           1,237              91
25,000..................................................           2,153           1,365           2,144            99.6           1,117              82
100,000.................................................           2,153           1,365           2,130            98.9             867              64
--------------------------------------------------------------------------------------------------------------------------------------------------------
Source: EIA Table FE4 and 2007 MSHA database.
Notes:
(1) 2007 National Emissions (metric tons CO2e) = 2007 Production x U.S. Weighted Average CO2 content (4,143 lbs/short ton)/(2205 lbs/metric ton).
(2) Emissions covered (metric tons CO2e) = sum of coal CO2 emissions for all facilities with metric tons CO2e production greater than the threshold.

[[Page 16566]]

 
(3) Facilities covered = total number of facilities with metric tons CO2e production greater than the threshold.

    For this rule, we propose to include all active underground and 
surface coal mines, with no threshold. Of the approximately 1,365 
active coal mines operating in 2007, the 25,000 metric tons 
CO2e threshold (corresponding to 1,140.8 million tons of 
coal production) would include the largest 1,117 coal mines and 99.6 
percent of U.S. coal production. All active U.S. coal mines already 
report annual (and quarterly) coal production (based on aggregated 
daily production data) to MSHA. The additional reporting required under 
this proposal is the carbon content of the coal, which can be 
calculated using the coal's higher heating value (HHV) also referred to 
as the gross calorific value (GCV). All active U.S. coal mines already 
conduct daily proximate analysis to record the HHV for coal sales 
contracts. An alternative for coal mines with annual production lower 
than 100,000 short tons is offered in the proposed rule to estimate 
CO2 emissions using HHV and default values, making this a 
very minimal additional reporting burden. Thus, we have determined that 
including all mines as reporters under proposed 40 CFR part 98, subpart 
KK would not significantly increase the burden on small coal mines. We 
are seeking comments on this conclusion.
    Coal Importers. As noted above, the majority of imported coal is 
imported by power plants for steam generation of electricity, with the 
remainder imported by other sizeable industrial facilities. We propose 
that all coal importers report, with no threshold. Because most of the 
imported coal is brought into the U.S. by companies owning facilities 
that would already be required to report GHG data to EPA under other 
subparts of the proposed 40 CFR part 98, EPA believes that there would 
be a minimal incremental burden associated the inclusion of all 
importing companies. We are seeking comments on this conclusion.
    Coal Exporters. Under proposed 40 CFR part 98, subpart KK, we are 
proposing that all coal exporting companies report, with no threshold. 
Coal exporters already collect information about the quantity and 
quality (e.g., heating value) of coal to be exported. Reporting to us 
under proposed 40 CFR part 98, subpart KK would therefore impose only 
minimal additional burden on these companies.
    Waste coal reclaimers. Under proposed 40 CFR part 98, subpart KK, 
we are proposing all waste coal reclaimers report, with no threshold. 
Parties that recover this waste coal for sale to consumers already 
collect information about the quantity and quality (e.g., heating 
value) of coal to be sold. Reporting to us under proposed 40 CFR part 
98, subpart KK would therefore impose only minimal additional burden on 
these facilities.
    For a full discussion of the threshold analysis, please refer to 
the Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037). For specific 
information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    We are proposing the reporting of the amount of coal produced or 
supplied to the economy annually, as well as the CO2 
emissions that would result from complete oxidation or combustion of 
this quantity of coal.
    The only GHG required to be reported under this subpart is 
CO2. Combustion of coal may also lead to trace quantities of 
CH4 and N2O emissions.\95\ Because the quantity 
of CH4 and N2O emissions are highly variable and 
dependent on technology and operating conditions in which the coal is 
being consumed (unlike CO2), we are not proposing that coal 
suppliers report on these emission. We seek comment on whether or not 
EPA should use the national inventory estimates of CH4 and 
N2O emissions from coal combustion, and apportion them to 
individual coal suppliers based on the quantity of their products.
---------------------------------------------------------------------------

    \95\ CO2, CH4, and N2O 
emissions from coal combustion 2065.3, 0.8, and 10.23 million metric 
tons CO2e, respectively.
---------------------------------------------------------------------------

    We are proposing that coal mines, coal importers, coal exporters, 
and reclaimers of waste coal use a mass-balance method to calculate 
CO2 emissions. The mass balance approach is based on readily 
available information: The quantity of coal (tons), and the carbon 
content of the coal (as determined by the mine, importer, exporter, or 
waste reclaimer, according to the methodology described below). The 
formula is simple and can be automated. The mass-balance approach is 
used extensively in national GHG inventories, and in existing reporting 
guidelines for facilities, companies, and states, such as the WRI/WBCSD 
GHG Protocol.
    We propose that coal suppliers be required to report both the total 
weight of coal produced or supplied annually (tons per year), as well 
as either the carbon content (carbon mass fraction) or coal HHV, which 
can be a proxy for carbon content. In practice, coal suppliers 
routinely and frequently monitor both the weight and energy content of 
coal for contractual purposes (e.g., daily measurements of tonnage and 
analyses of the BTU, sulfur, and ash content of coal) as well as for 
reporting requirements to various State and Federal agencies. We 
propose that all coal suppliers report these routinely-collected data, 
and use them as a basis for estimating the CO2 emissions 
associated with the coal.
    For the purpose of this calculation, we propose that larger coal 
mines (i.e., coal mines that produce over 100,000 short tons of coal 
per year) use mine-specific, carbon content values.
    Generally, the carbon content of coal can be determined through one 
of two procedures. The most accurate method is to determine the coal's 
carbon content (carbon mass fraction) directly through ultimate 
analysis of the coal's chemical constituents. An alternative method is 
to measure the coal's energy content (HHV, which is often expressed in 
units of MMBTU per unit weight) and use it as an indicator of the 
coal's carbon content. This is done by establishing a statistically 
significant correlation between the coal's heating value and the carbon 
content of the coal, and using this correlation to estimate the carbon 
content (carbon mass fraction) of a given batch of coal with known 
heating value. For instance, a linear relationship between coal heating 
value and coal carbon content can be established. This alternative 
approach is convenient because heat value measurements of coal are 
taken routinely and frequently by coal mines, coal importers, coal 
exporters, and coal retailers.
    For the purpose of proposed 40 CFR part 98, subpart KK, EPA 
proposes that coal mines that produce over 100,000 short tons of coal 
per year have two options for reporting the carbon content of their 
coal: (1) Daily measurements of coal carbon content through ultimate 
analyses (daily sampling and analyses, reported as annual weighted 
average), or (2) a combination of daily measurements of coal HHV 
through proximate analyses and monthly measurements of carbon content 
through ultimate analyses, using an established, statistically 
significant correlation to estimate the daily weighted average coal 
carbon content (mass fraction), as described in the rule. We propose 
that a minimum of one year of data be used to establish such a mine-
specific statistically significant correlation between the coal carbon

[[Page 16567]]

content (as measured by ultimate analyses) and coal heating value (as 
measured by proximate analyses). We request comment on this approach, 
including the minimum number of data points necessary to establish a 
statistically significant mine-specific relationship between coal 
carbon content and coal HHV, and how often and under what circumstances 
should the statistical relationship be reestablished. According to MSHA 
data, 706 mines produced over 100,000 short tons of coal during 2007 
(52 percent of all mines), accounting for 98 percent of total 
production. We propose that a more stringent method for calculating 
carbon content be applied to these larger mines in order to reduce the 
uncertainty of the CO2 data collected.
    EPA proposes that coal mines with annual coal production less 
100,000 short tons use either one of the above approaches for 
estimating carbon content, or use a third alternative. This alternative 
involves estimating the coal's carbon content based only on daily 
measurements of coal HHV through proximate analyses and a default 
CO2 emissions factor provided as described in proposed 40 
CFR part 98, subpart KK. EPA has concluded that this alternative is 
reasonable because it would reduce the sampling and analyses cost 
burden on these entities, yet would provide sufficient accuracy given 
their relatively small contribution to total U.S. coal supply. We 
request comments on this approach.
    EPA proposes that all coal importers, coal exporters, and 
reclaimers of waste coal use any of three above approaches for 
estimating carbon content based on measurements per shipment in place 
of daily measurements if preferred. We seek comment on this measurement 
approach.
    We propose that the ASTM Method D5373 should be used as the 
standard for all ultimate analyses.
    We considered, but are not recommending, an option to allow all 
coal mines to use default coal carbon content values instead of site-
specific values or measurements. Existing information available on the 
variability of carbon content for coal from USGS, the U.S. GHG 
Inventory, EIA's GHG Inventory, and the IPCC indicate that default 
values introduce considerable uncertainty into the emissions 
calculation. Given the large share of total GHG emissions represented 
by use of coal in the U.S. economy, we view the direct measurement or 
estimation of site-specific carbon content values as necessary. We seek 
comment on an appropriate approach for reporters--such as importers--
who estimate a weighted annual average GCV according to specified 
methodology that is not listed with a corresponding default coal carbon 
content value in table KK-1 of this rule. Further information on 
various approaches to monitoring GHG emissions is elaborated in the 
Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
4. Selection of Procedures for Estimating Missing Data
    We have determined that some of the information to be reported by 
coal mines, coal importers, coal exporters, and waste coal reclaimers 
is routinely collected as part of standard operating practices (e.g., 
coal tonnage). For these cases, we expect no missing data would occur.
    Typically, coal is weighed using automated systems on the conveyor 
belt or at the loadout facility. In general, the weighing and sampling 
of coal at coal mines are conducted at about the same time to ensure 
consistency between quantity and quality of coal. In this rule, EPA 
proposes that the most current version of NIST Handbook 44 published by 
Weights and Measures Division, National Institute of Standards and 
Technology be used as the standard practice for coal weighing. In cases 
where coal supply data are not available, reporters may estimate the 
missing quantity of coal supplied, using documentation for the quantity 
of coal received by end-users or other recipients. For any periods 
during which mine scales are not operational or records are 
unavailable, estimates of coal production at the mine may be estimated 
using an average of values of production immediately preceding and 
following the missing data period, or other standard industry 
practices, such as estimating the volume of coal transported by rail 
cars and coal density to estimate total coal weight in tons. For 
additional background information on coal weighing, please refer to the 
Suppliers of Coal TSD (EPA-HQ-OAR-2008-0508-037).
    In cases where carbon content or HHV measurements are missing, 
reporters may estimate the missing value based on an weighted average 
value for the previous seven days.
5. Selection of Data Reporting Requirements
    We propose that coal mines, coal importers, coal exporters, and 
waste coal reclaimers each report to us annually on the CO2 
emissions that would result from complete combustion or oxidation of 
coal produced during the previous calendar year.
    Information from coal mines should be reported at the facility 
level, and should include mine name, mine MSHA identification number, 
name of operating company, coal production coal rank or classification 
(e.g., anthracite, bituminous, sub-bituminous, or lignite), facility-
specific measured values of coal carbon content or HHV that are used to 
calculate CO2 emissions, and the estimated CO2 
emissions (metric tons CO2/yr).
    Coal importers, coal exporters, and waste coal reclaimers should 
report company name and technical contact information (name, e-mail, 
phone).
    Coal importers should report at the corporate level. Coal importers 
already measure coal quantity for each shipment entering the U.S. 
Importers generally conduct proximate analyses on each shipment to 
assure that coal quality meets the coal specification under contract. 
Some importers may also conduct ultimate analysis. Coal importers 
should report the quantity of coal imported, coal rank or 
classification (e.g., anthracite, bituminous, sub-bituminous, or 
lignite), country of origin, origin-specific measured values of coal 
carbon content and HHV that are used to calculate CO2 
emissions, and estimated CO2 emissions.
    Coal exporters should report, at the corporate level, the quantity 
of coal exported, coal rank or classification (e.g.anthracite, 
bituminous, sub-bituminous, or lignite), name and MSHA identification 
number of mine of origin, country of destination, mine-specific 
measured values of coal carbon content or HHV that are used to 
calculate CO2 emissions, and estimated CO2 
emissions (metric tons CO2/yr).
    Waste coal reclaimers should report, at the facility level, the 
quantity of coal recovered or reclaimed (tons/yr), coal rank or 
classification (e.g., anthracite, bituminous, sub-bituminous, or 
lignite), name of mine of origin, state of origin, mine-specific 
measured values of coal carbon content or HHV that are used to 
calculate CO2 emissions, and estimated CO2 
emissions.
    A full list of data to be reported is contained in the rule. These 
data to be reported form the basis of calculating potential 
CO2 emissions associated with the total supply of coal into 
the U.S. economy. Therefore, these data are necessary for us to 
understand the emissions data and to verify the reasonableness of the 
reported emissions.
    We considered, but are not proposing an option in which we would 
obtain facility-specific data for coal production through access to 
existing Federal

[[Page 16568]]

Government reporting databases, such as those maintained by MSHA. We 
have determined that comparability and consistency in reporting 
processes across all facilities included in the entire rule is vital, 
particularly with respect to timing of submission, reporting formats, 
QA/QC, database management, missing data procedures, transparency and 
access to information, and recordkeeping. In addition, EPA's 
methodological approach requires information that is not currently 
reported to Federal agencies, such as facility-specific information on 
coal quality (e.g., coal carbon content or heating value).
6. Selection of Records That Must Be Retained
    A full list of records that must be retained onsite is included in 
proposed 40 CFR part 98, subparts A and KK. EPA proposes that the 
following records specific to suppliers of coal be kept onsite: Daily 
production of coal, annual weighted average of coal carbon content 
values (if measured), annual weighted average of coal HHV, calibration 
records of any instruments used onsite (e.g., if coal analyses are done 
onsite), and calibration records of scales or other equipment used to 
weigh coal.
    These records consist of data that are directly used to calculate 
the potential CO2 emissions reported. We have concluded that 
these records are necessary to enable verification that the GHG 
emissions monitoring and calculation were done correctly.

LL. Suppliers of Coal-Based Liquid Fuels

1. Definition of the Source Category
    We are proposing to include facilities that produce coal-based 
liquids as well as importers and exporters of coal-based liquids in 
this source category. Owners and operators of coal-to-liquids 
facilities, or ``producers'', importers, and exporters would report on 
the CO2 emissions that would result from complete combustion 
or oxidation of the quantities of coal-based liquids supplied to or 
exported from the U.S. economy. Producers would report at the facility 
level; importers and exporters would report at the corporate level.
    The carbon in coal-based liquids would already be captured in the 
reporting from domestic coal suppliers and importers, but we believe 
that it is important for climate policy development to have additional 
information on a unique and potentially growing source of liquid fuels. 
As discussed in Sections III and IV of this preamble, emissions 
resulting from the combustion and other uses of coal-based liquids, as 
well as emissions generated in the production of coal-based liquids, 
are addressed in other sections of the preamble, particularly Section 
V.C of this preamble (General Stationary Fuel Combustion Sources), 
Section V.D (Electricity Generation), and Section V.FF (Underground 
Coal Mines).
    The output fuels from coal-to-liquids processes are compositionally 
similar to standard petroleum-based products e.g., gasoline, diesel 
fuel, jet fuel, light gases etc. The most common processes for 
converting coal to liquids are direct and indirect liquefaction. In the 
direct process, coal is processed directly to liquid. In the indirect 
process, coal is first gasified, and then liquefied.
    Once manufactured, the supply chain for coal-based liquids to 
consumers is basically the same as it is for refined petroleum 
products. Liquid fuels are moved from the manufacturing facility to a 
terminal, at which point they may be blended or mixed with other 
products, before entering the downstream distribution chain. Imported 
coal-based liquids would enter the U.S. in the same way that refined 
and semi-refined petroleum products enter the country. In determining 
the most appropriate point in the supply chain of coal-based liquids, 
we followed the decision-making process applied to suppliers of 
petroleum products discussed in Section V.MM of this preamble, and 
selected coal-to-liquids facilities (analogous to refineries), and 
importers and exporters. For further information, see the Coal to 
Liquids TSD (EPA-HQ-OAR-2008-0508-038). We request comment on the 
approach of establishing a separate source category and subpart for 
suppliers of coal-based liquids, and the selection of coal-to-liquids 
facilities and corporate importers and exporters of coal-based liquids. 
We also request comment on whether or not importers of liquid-based 
fuels are likely to have the necessary information with which to 
distinguish coal-based liquids from conventional petroleum-based 
liquids.
2. Selection of Reporting Threshold
    In developing the threshold for suppliers of coal-based liquids, 
EPA considered the emissions-based threshold of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e and 100,000 metric tons CO2e per year, but 
was limited by the fact that there are very few existing facilities. 
According to DOE, there is one facility operating in the world, one 
U.S. facility in the engineering phase, and thirteen facilities 
proposed in the U.S.\96\ Given that conversion of coal to liquids is a 
highly energy intensive process that is viable only on a large scale, 
we propose that any coal-to-liquids facility operating in the U.S. 
would be required to report.
---------------------------------------------------------------------------

    \96\ Coal Conversion--Pathway to Alternate Fuels. C. Lowell 
Miller. 2007 EIA Energy Outlook Modeling and Data Conference. 
Washington, DC, March 28, 2007.
---------------------------------------------------------------------------

    We also propose that all importers and exporters of coal-based 
liquids report under this rule. While the number of existing importers 
and exporters is very small in comparison to importers and exporters of 
petroleum products, importers of coal-based liquids would be required 
to track fuel quantities as part of routine business operations, and 
report to DOE and other Federal agencies.
    For further information, see the Coal to Liquids TSD (EPA-HQ-OAR-
2008-0508-038). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    We are proposing that producers, importers, and exporters of coal-
based liquids calculate potential CO2 emissions associated 
with coal-based liquids on the basis of a mass balance approach. Under 
this approach, CO2 emissions would be determined by applying 
a carbon content value to the quantity of each coal-based liquid 
supplied. The formulae are simple and can be automated. For carbon 
content, reporters can either use the default CO2 emission 
factors for standard petroleum-based fuels in proposed 40 CFR part 98, 
subpart MM or develop their own factors.\97\ Reporters that choose to 
substitute their own batch- or facility-specific values for density and 
carbon share of individual coal-based liquids, and develop their own 
CO2 emission factors, must do so according to the proposed 
ASTM standards and procedures discussed in proposed 40 CFR part 98, 
subpart MM. While carbon content of coal-based liquids may differ from 
petroleum products, we believe the default emission factors for 
petroleum products in proposed 40 CFR part 98, subpart MM can be used 
for estimating emissions from coal-based liquids. We request comment on 
this approach, the appropriateness of the proposed default 
CO2 emission factors, and ways to improve these default 
values. We also

[[Page 16569]]

request comment on the appropriateness of the proposed sampling and 
analysis standards and methods for developing batch- or facility-
specific CO2 emission factors, especially the methods for 
determining carbon share.
---------------------------------------------------------------------------

    \97\ For a discussion of the benefits and disadvantages of 
default carbon factors versus direct measurement see Section V.MM.3 
of this preamble.
---------------------------------------------------------------------------

4. Selection of Procedures for Estimating Missing Data
    We have determined that the information to be reported by suppliers 
of coal-based liquids is routinely collected by facilities and entities 
as part of standard operating practices, and therefore 100 percent data 
availability would be required. Typically, coal-based liquids would be 
metered directly at multiple stages. In cases where metered data are 
not available, reporters may estimate the missing volumes based on 
contracted maximum daily quantities and known conditions of receipt and 
delivery during the period when data are missing.
5. Selection of Data Reporting Requirements
    We propose that producers, importers, and exporters report 
CO2 emissions directly to EPA on an annual basis. Suppliers 
would report potential CO2 emissions disaggregated by fuel 
types.
    We considered but did not propose an option in which we would 
obtain facility-specific data for coal-based liquids through access to 
existing Federal government reporting databases, such as those 
maintained by EIA. EPA believes that comparability and consistency in 
reporting processes across all facilities included in the entire rule 
are vital, particularly with respect to timing of submission, reporting 
formats, QA/QC, database management, missing data procedures, 
transparency and access to information, and recordkeeping.
6. Selection of Records That Must Be Retained
    A full list of records that must be retained onsite is included in 
proposed 40 CFR part 98, subparts A and LL.

MM. Suppliers of Petroleum Products

1. Definition of the Source Category
    We are proposing that refineries as well as importers and exporters 
of petroleum products be included in this source category. Owners or 
operators of petroleum refineries, or ``refiners,'' and importers that 
introduce petroleum products into the U.S. economy would be required to 
report on the CO2 emissions associated with the complete 
combustion or oxidation of their petroleum products. Additionally, both 
refiners and importers would be required to report on biomass 
components of their petroleum products as well as NGLs they supply to 
the economy, and refiners would be required to report on certain types 
of feedstock entering their facility. Refiners would report at the 
facility level, and importers would report at the corporate level. 
Exporters of petroleum products are also included in this source 
category in order for us to appropriately account for petroleum 
products that are produced but not consumed in the U.S. and therefore 
do not result in direct CO2 emissions in the U.S. Exporters 
would report on the petroleum products and NGLs they export, including 
the biomass components of the petroleum products, at the corporate 
level.
    End users of petroleum products are addressed in other sections of 
this preamble, such as Section V.C (General Stationary Fuel Combustion 
Sources), and direct, onsite emissions at petroleum refineries are 
covered in Section V.Y of this preamble.
    The total estimated GHG emissions resulting from the combustion of 
petroleum products in the U.S. in 2006 was 2,417 million metric tons 
CO2e, according to the 2008 U.S. GHG Inventory. It is 
estimated that 75 percent of the combustion-related CO2 
emissions from petroleum use in the U.S. comes from the transportation 
sector. The next largest sector is industrial use (15 percent), and the 
commercial, residential, and electricity generation sectors make up the 
remainder.
    Petroleum products are ultimately consumed in one of two ways: 
Either through combustion for energy use, or through a non-energy use 
such as petrochemical feedstocks or lubricants. Combustion of petroleum 
products produces CO2 and lesser amounts of CH4 
and N2O, which are in almost all cases emitted directly into 
the atmosphere. Some non-energy uses of fuels, such as lubricants, also 
result in oxidation of carbon and CO2 emissions. This 
process may occur immediately upon first use or, in the case of 
biological deterioration, over time. Carbon in other petroleum 
products, such as asphalts and durable plastics, may remain un-oxidized 
for long periods unless burned as fuel or incinerated as waste.
    The following list, while not comprehensive, illustrates the types 
of products that EPA considers to fall under the category of petroleum 
products:
     Motor vehicle and nonroad gasoline and diesel fuels.
     Jet fuel and kerosene.
     Aviation gasoline.
     Propane and other LPGs.
     Home heating oil.
     Residual fuel oil.
     Petrochemical feedstocks.
     Asphalt.
     Petroleum coke.
     Lubricants and waxes.
    Reporting Parties. When considering the extent of the definition of 
this source category and who should be required to report under this 
rule, our approach was first to identify all parties within the 
petroleum product supply chain. We considered parties that function 
primarily in upstream petroleum production, such as oil drillers and 
well owners, as well as petroleum refiners and importers of refined and 
semi-refined products. We also considered parties located even further 
downstream, such as terminal operators, oxygenate blenders of 
transportation fuel, blenders of blendstock, transmix processors, and 
retail gas station owners. In addition, we considered pipeline owners 
and operators.
    As discussed earlier in this preamble, one of our objectives when 
determining which entities would fall within a source category was to 
identify logical data reporting points or groups of facilities that 
were relatively small in number but that could provide a comprehensive 
set of data for the particular source category. Of all the parties that 
make up the petroleum products supply chain, we have concluded that 
petroleum refiners \98\ and importers and exporters of semi-refined and 
refined petroleum products are the most appropriate parties to report 
to EPA under this source category and that the data they can report 
would be comprehensive.
---------------------------------------------------------------------------

    \98\ A petroleum refinery is any facility engaged in producing 
gasoline, kerosene, distillate fuel oils, residual fuel oils, 
lubricants, asphalt (bitumen) or other products through distillation 
of petroleum or through redistillation, cracking, or reforming of 
unfinished petroleum derivatives.
---------------------------------------------------------------------------

    There are approximately 150 operating petroleum refineries in the 
U.S. and its territories. Our thresholds analysis in Section V.MM.2 of 
this preamble, however, only reflects data on the 140 refineries that 
reported atmospheric distillation capacity to EIA (at DOE) in 2006. 
Petroleum products from these refineries account for approximately 90 
percent of U.S. consumption. Given the coverage provided by a 
relatively small number of facilities, we propose that all refiners be 
subject to the reporting requirements for petroleum product suppliers 
and that they report to EPA on a facility-by-facility basis. For 
refiners that trade semi-refined and refined petroleum products between 
facilities, leading to a

[[Page 16570]]

possible risk of double-counting in coverage, we are proposing a 
straight-forward accounting method in Section V.MM.5 of this preamble 
to address this possibility.
    To account for refined and semi-refined petroleum products that are 
not produced at U.S. refineries, we are proposing to include importers 
under this source category. Importers currently report to EPA on 
petroleum products designated for transportation or non-road mobile 
end-uses. This rule would include all importers regardless of end-use 
designations. The number of importing companies varies from year to 
year, but it is typically on the order of 100 to 200.
    We are also proposing to include under this source category 
exporters of refined and semi-refined petroleum products in order to 
have information on petroleum products that are produced but not 
consumed in the U.S. The rationale to include reporting from exporters 
is to be able to account for petroleum products that are consumed in 
other countries and that do not contribute to direct CO2 
emissions in the U.S.
    Many refiners are also importers and exporters of petroleum 
products. EPA is proposing that such refiners separately report data on 
the petroleum products that they produce on a facility-by-facility 
basis and report at a corporate level the petroleum products they 
import or export. The rationale for this separate reporting is that we 
are generally proposing coverage at the facility level where feasible 
(e.g., refineries) and proposing corporate reporting only where 
facility-level coverage may not be feasible (e.g., importers and 
exporters). In addition, the separation simplifies reporting in cases 
where a company that owns or operates multiple refineries may have a 
consolidated arrangement for imports of refined and semi-refined 
products destined for its refineries and for other consumers, or for 
exports.
    We considered but are not proposing to include parties that are 
involved in upstream petroleum production. We believe the number of 
domestic oil drillers and well owners is prohibitively large and 
represents only a portion of the amount of crude petroleum that is 
processed into finished products to be used in the U.S.
    We are not proposing to include retail gas station owners and 
oxygenate blenders to report to EPA as suppliers of petroleum products. 
Retail gas station owners and oxygenate blenders mostly handle 
transportation fuel and fuel used in small engines. Because we are 
interested in GHG emissions from all petroleum products combusted or 
consumed in the U.S. and can obtain information on such products on a 
more aggregated basis directly from refiners and importers, we are 
proposing to exclude retail gas station owners and oxygenate blenders 
from reporting under this rule.
    We are not proposing to include operators of terminals or 
pipelines, blenders of blendstocks, or transmix processors in this 
source category because we believe that refiners and importers can 
provide comprehensive information on petroleum products supplied in the 
U.S. with a lower risk of double-counting petroleum products. A given 
quantity of refined or semi-refined petroleum product may pass between 
multiple terminals and blending facilities, so asking terminal or 
pipeline operators, blenders of blendstock, or transmix processors to 
report information on incoming and outgoing products would likely 
result in unreliable data for estimating GHG emissions from petroleum 
products.\99\
---------------------------------------------------------------------------

    \99\ See Section V.MM.3 of this preamble regarding a method for 
accounting for trade between refineries.
---------------------------------------------------------------------------

    Liquid fossil fuel products can be derived from feedstocks other 
than petroleum crude, such as coal and natural gas. Suppliers of coal-
based products are covered under Section V.LL of this preamble, 
Suppliers of Coal-Based Liquid Fuels. Primary suppliers of natural gas-
based products are covered in Section V.NN of this preamble, Suppliers 
of Natural Gas and Natural Gas Liquids. We are proposing to require all 
reporters in this source category to report data on the NGLs they 
supply to or export from the economy because these products may not 
currently be captured under Section V.NN of this preamble, Suppliers of 
Natural Gas and NGLs. The natural-gas related reporting requirements 
are discussed in Section V.MM.5 of this preamble.
    This section of the preamble is focused on suppliers of petroleum 
products, so EPA is not proposing to include primary \100\ suppliers of 
renewable fuels, such as fuel derived from biomass like grains, animal 
fats and oils, or waste, under this source category. However, as 
described in Section IV.B of this preamble (Reporting by fuel and 
industrial gas suppliers), we note that we are not proposing to require 
suppliers of biomass-based fuels to report on their products anywhere 
under this rule, except as discussed below for petroleum suppliers, due 
to a longstanding accounting convention adopted by the IPCC, the 
UNFCCC, the U.S. GHG Inventory, and many other State and regional GHG 
reporting programs where emissions of CO2 from the 
combustion of renewable fuels are distinguished from emissions of 
CO2 from combustion of petroleum or other fossil-based 
products. Under such convention, potential emissions from the 
combustion of biomass-based fuels are accounted for at the time of 
feedstock harvest, collection, or disposal, not at the point of fuel 
combustion. Nonetheless, we seek comment on this approach.
---------------------------------------------------------------------------

    \100\ Refiners, exporters, and importers of petroleum products 
could, in some cases, be suppliers of renewable fuels but their 
supply of renewable fuels is not the focus of this subpart.
---------------------------------------------------------------------------

    Certain petroleum products can be co-processed or blended with 
renewable fuels. We are proposing a method in Section V.MM.5 of this 
preamble whereby petroleum product suppliers report data that allows 
EPA to distinguish between the biomass and fossil fuel-based carbon in 
their products.
2. Selection of Reporting Threshold
    In assessing the appropriateness of applying a threshold to 
refiners (at the facility level) and importers (at the corporate 
level), we calculated the volume of finished gasoline that would 
contain enough carbon that, when combusted or oxidized, would produce 
1,000 metric tons CO2e, 10,000 metric tons CO2e, 
25,000 metric tons CO2e, and 100,000 metric tons 
CO2e. We took the volume of finished gasoline as an example 
of how much of a refined or semi-refined product would result in a 
given level of CO2 emissions. These data are summarized in 
Table MM-1 of this preamble.

          Table MM-1. Threshold Analysis for Finished Gasoline
------------------------------------------------------------------------
                                                           Total volume
           Threshold level metric tons CO2/yr               of gasoline
                                                              bbls/yr
------------------------------------------------------------------------
1,000...................................................           2,564
10,000..................................................          25,641
25,000..................................................          64,103
100,000.................................................         256,410
------------------------------------------------------------------------

    Based on the calculations in Table MM-1 of this preamble and data 
on the annual volume of petroleum products that refiners and importers 
are currently reporting to the EIA, EPA estimated the number of 
refineries and importers that would meet each of the four selected 
threshold levels. The results of this analysis are summarized below.

[[Page 16571]]

    Refineries. Data on the typical production levels for refineries 
\101\ demonstrate that each of the thresholds considered would cover 
all domestic refineries (see Table MM-2 of this preamble). This 
conclusion is based on the result that all refineries would exceed the 
thresholds for gasoline alone, and therefore would also exceed the 
thresholds for all products combined. For this reason, we are proposing 
to cover all petroleum refineries.
---------------------------------------------------------------------------

    \101\ To simplify our reporting threshold analysis, EPA omitted 
roughly 10 refineries that meet our definition of a petroleum 
supplier but did not report any atmospheric distillation capacity to 
EIA.

                                                      Table MM-2. Threshold Analysis for Refineries
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                      Total national                           Emissions covered                Facilities covered
                                                      emissions 1 2     Total number  ------------------------------------------------------------------
        Threshold level metric tons CO2e/yr          metric tons CO2/   of facilities   Metric tons CO2/
                                                            yr               \3\               yr             Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000.............................................      2,447,738,368             140      2,447,738,368             100             140             100
10,000............................................      2,447,738,368             140      2,447,738,368             100             140             100
25,000............................................      2,447,738,368             140      2,447,738,368             100             140             100
100,000...........................................      2,447,738,368             140      2,447,738,368             100             140             100
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ These constitute total emissions from all petroleum products ex refinery gate. The total includes only CO2 emissions.
\2\ Estimated CO2 emissions for all refineries are based on applying product-specific default carbon contents to production of each product.
\3\ This number represents the total number of refineries that reported atmospheric distillation capacity to EIA in 2006.

    Small Refiners. In recent EPA fuel rulemakings, we have provided 
temporary exemptions from our regulations for small refiners, defined 
as producers of transportation fuel from crude oil that employed an 
average of 1,500 people or fewer over a given one-year period and with 
a corporate-average crude oil capacity of 155,000 barrels per calendar 
day or less. Such small refiner exemptions were provided to allow small 
refiners extra time to meet standards or comply with new regulations. 
This exemption was based on an assumption that to require small 
refiners to comply with new regulations on the same schedule as larger 
refiners would put them at a disadvantage if required to seek the same 
capital and administrative resources being sought by their larger 
competitors. Because of the nature of this reporting rule, however, we 
are not proposing any temporary exemptions for small refiners. We do 
not believe complying with this rule will require additional resources 
that might put small refiners at an unfair disadvantage. All refiners 
would already be reporting data to EPA, regardless of size, because all 
refineries meet the proposed reporting threshold in proposed 40 CFR 
part 98, subpart Y for direct onsite emissions.
    Importers. Data on importers of petroleum products in 2006, the 
most recent year available, show that 78 percent of the importing 
companies exceeded the 25,000 metric tons CO2e/yr reporting 
threshold and that some importing companies did not meet the 1,000 
metric tons CO2e/yr threshold (see Table MM-3 of this 
preamble). While 22 percent of importers supplied less than the amount 
of products that, when combusted or oxidized, would have resulted in 
25,000 metric tons CO2/yr, data on the amount and types of 
petroleum products is information that all importers maintain as part 
of their normal business operations. Therefore we believe the burden of 
reporting the required information listed in Section V.MM.5 of this 
preamble is minimal since no additional monitoring equipment has to be 
installed to comply with this rule. In addition, the quantity of 
products imported by a company may vary greatly from year to year. 
Furthermore, our proposed definition for petroleum products for 
importers and exporters in Subpart A excludes asphalt and road oil, 
lubricants, waxes, plastics, and plastic products. For these reasons, 
we are proposing that all importers of petroleum products be required 
to report to EPA, and we seek comment on our proposed definition of 
petroleum products as it applies to importers.

                                                      Table MM-3. Threshold Analysis for Importers
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   Total national                       Emissions covered           Companies covered
                                                                    emissions \1\   Total number  ------------------------------------------------------
               Threshold level metric tons CO2e/yr                   metric tons    of importers     Metric tons
                                                                       CO2/yr                          CO2/yr        Percent       Number      Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
<1000............................................................     393,294,390             224     393,294,390          100          224          100
1,000............................................................     393,294,390             224     393,291,916        >99.9          219           98
10,000...........................................................     393,294,390             224     393,171,144        >99.9          193           86
25,000...........................................................     393,294,390             224     392,895,841         99.9          175           78
100,000..........................................................     393,294,390             224     389,628,252           99          120           54
--------------------------------------------------------------------------------------------------------------------------------------------------------
\1\ These constitute total emissions from all product imports. Analysis is based on EIA's Company Reports for 2006.

    Exporters. Due to the limited availability of export data, EPA did 
not conduct a threshold analysis for petroleum products exporters. 
However, based on the type of information that exporters must maintain 
as part of their normal business operations, we believe that the 
incremental burden of reporting this information to EPA would be 
minimal. Considering this information and the importance of being able 
to account for petroleum products produced but not combusted or 
oxidized in the U.S., EPA is proposing that all exporters report on 
their exported petroleum products. Furthermore, our proposed definition 
for petroleum products for importers and exporters in Subpart A 
excludes asphalt and road oil, lubricants, waxes, plastics, and plastic 
products. We seek comment on this proposal.
    De Minimis Exports and Imports. We are seeking comment on whether 
or not to establish a de minimis level, either in terms of total 
product volume or potential CO2 emissions, to eliminate

[[Page 16572]]

any reporting burden for parties that may import or export a small 
amount of petroleum products on an annual basis. We also note that in 
the proposed rule some importers and exporters may not be required to 
report their onsite combustion, process, and/or fugitive emissions 
under other sections of the proposed rule because their combined 
emissions do not meet the applicable thresholds.
    For a full discussion of the threshold analysis, please refer to 
the Suppliers of Petroleum Products TSD (EPA-HQ-OAR-2008-0508-039). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    Rather than directly measuring emissions from the combustion or 
consumption of their products, suppliers of petroleum products would 
need to estimate the potential emissions of their non-crude feedstocks 
and products based on volume and characteristic information. Therefore 
product volume metering and sampling would be of utmost importance to 
accurately calculate potential CO2 emissions.
    Volume measurement. EPA is proposing to require specific industry-
standard test methods for flow meters and tank gauges for measuring 
volumes of feedstocks and products. For ultra-sonic flow meters, we 
propose to require the test method described in AGA Report No. 9 
(2007); for turbine meters, American National Standards Institute, 
ANSI/ASME MFC-4M-1986; for orifice meters, American National Standards 
Institute, ANSI/API 2530 (also called AGA-3) (1991); and for coriolis 
meters, ASME MFC-11 (2006). For tank gauges, we propose to require the 
following test methods: API-2550: Measurements and Calibration of 
Petroleum Storage Tanks (1965), API MPMS 2.2: A Manual of Petroleum 
Measurement Standards (1995), or API-653: Tank Inspection, Repair, 
Alteration and Reconstruction, 3rd edition (2008).
    We propose that all flow meters and tank gauges must be calibrated 
prior to monitoring under this rule using a method published by a 
consensus standards organization (e.g., ASTM, ASME, American Petroleum 
Institute, or NAESB), or using calibration procedures specified by the 
flow meter manufacturer. Product flow meters and tank gauges would be 
required to be recalibrated either annually or at the minimum frequency 
specified by the manufacturer.
    Carbon content determination. To translate data on petroleum 
product, NGLs, and biomass types and quantities into estimated 
potential GHG emissions, it is necessary either to estimate or measure 
the carbon content for each product type. For this proposal, we 
reviewed the existing CO2 emission factors developed by EIA 
and used in the U.S. GHG Inventory, and we researched the sampling and 
test methods that would be required for direct measurement of carbon 
content by reporters.
    We also considered the benefits and disadvantages of using default 
carbon content factors and of using direct measurements of carbon 
content. Default CO2 emission factors have been used 
extensively in the U.S. GHG Inventory, in inventories of other nations, 
and in corporate reporting guidance; they are simple and cost effective 
for evaluating GHG emissions from common classes of biomass and fossil 
fuel types (e.g., ethanol, motor gasoline, jet fuel, distillate fuel, 
etc). It is also possible to combine default CO2 emission 
factors to develop alternative factors for fuel reformulations by 
averaging according to weight. Some products, however, can have 
multiple chemical compositions due to different feedstock, blending 
components, and/or refinery processes, which can lead to variations in 
carbon content. Default CO2 emission factors for common 
chemical compositions of common products cannot account for the full 
variability of carbon content in petroleum, natural gas, and biomass 
products.
    Direct measurements would provide the most accurate determination 
of carbon content. It is relatively expensive, however, to design and 
implement a program for regular sampling and testing for carbon content 
across the variety of products produced at refineries. Many products 
are homogeneous because they must meet ``minimum'' specifications 
(e.g., jet fuel), and the use of direct measurements may not lead to 
noticeable improvements in accuracy over default CO2 
emission factors.
    Based on this information, we are proposing that for purposes of 
estimating emissions, reporters could either use the default 
CO2 emission factors for each product type published in 
proposed 40 CFR part 98, subpart MM or, in the case of petroleum 
products and NGLs, develop their own factors. Reporters that choose to 
substitute their own values for density and carbon share of individual 
petroleum products and NGLs, and develop their own CO2 
emission factors would be required to sample each product monthly for 
the reporting year and to test the composite sample at the end of the 
reporting period using ASTM D1298 (2003), ASTM D1657-02(2007), ASTM 
D4052-96(2002)el, ASTM D5002-99(2005), or ASTM D5004-89(2004)el for 
density, as appropriate, and ASTM D5291(2005) or ASTM D6729-(2004)el 
for carbon share, as appropriate (see Suppliers of Petroleum Products 
TSD (EPA-HQ-OAR-2008-0508-039)). For suppliers of seasonal gasoline, 
reporters would be required to take a sample each month of the season 
and test the composite sample at the end of the season.
    We request comment on this approach. We request comment on whether 
reporters should be allowed to combine default CO2 emission 
factors to develop alternative factors for fuel reformulations 
according to the volume percent of each fuel component, and if so using 
what methodology. We also request comment on the appropriateness and 
adequacy of the proposed default CO2 emission factors--
including factors for biomass products--and ways to improve these 
default values. For full documentation of the derivation of the 
proposed default factors, please refer to the Suppliers of Petroleum 
Products TSD (EPA-HQ-OAR-2008-0508-039).
    In addition, we request comment on the appropriateness of the 
proposed sampling and analysis standards and methods for developing 
CO2 emission factors for petroleum products and NGLs, 
especially the methods for determining carbon share. Specifically, we 
seek comment on specific ASTM or other industry standards that would be 
more appropriate for sampling petroleum products and NGLs to determine 
carbon share. Finally, we request comment on potential methods to 
determine carbon share of biomass products.
    The various approaches to monitoring GHG emissions are elaborated 
in the Suppliers of Petroleum Products TSD (EPA-HQ-OAR-2008-0508-039).
4. Selection of Procedures for Estimating Missing Data
    Under this proposal, we are suggesting methods for estimating data 
that may be missing from different source categories for various 
reasons. Petroleum product suppliers would need to estimate any missing 
data on the amount of petroleum products or NGLs supplied or exported, 
and the quantity of the crude and non-crude feedstocks, including 
biomass, consumed. In most cases, the source category would be missing 
data due to monitoring equipment malfunction or shutdown.

[[Page 16573]]

We have determined that the information to be reported by petroleum 
fuel suppliers is collected as part of standard operating practices, 
and expect that any missing data would be negligible. Typically, 
products are metered directly at multiple stages, and billing systems 
require rigorous reconciliation of data. In cases where metered data 
are not available, we are proposing that reporting parties may estimate 
the missing volumes based either on the last valid data point they 
recorded or on an average of two valid data points based on their 
established procedures for purposes of product tracking and billing. We 
seek comment on the appropriateness and adequacy of our proposed 
procedures for estimating missing data. Petroleum product suppliers 
reporting under this rule would be required to keep sufficient records 
to verify any volume estimates (see Section V.MM.6 of this preamble).
5. Selection of Data Reporting Requirements
    We are proposing that suppliers of petroleum products be required 
to report the type, volume, and CO2 emissions associated 
with the complete combustion or oxidation of each individual petroleum 
product and NGL they supply to the economy, export, or use as a 
feedstock annually. We are also proposing to require reporting on the 
total CO2 emissions of all products they supply to the 
economy annually, minus any emissions associated with non-crude 
feedstocks, including biomass, and renewable fuel blended in a 
petroleum product. Additionally, we are proposing to require refiners 
to report information on the volume, API gravity, sulfur content, and 
country of origin of each crude oil batch used as feedstock at a 
refinery. Finally, we are proposing to require reporting on the volume 
of diesel fuel that is most likely to be used in the onroad mobile 
source sector.
    The only GHG required to be reported under proposed 40 CFR part 98, 
subpart MM is CO2. Combustion of petroleum products may also 
lead to trace quantities of CH4 and N2O 
emissions.\102\ The amounts of CH4 and N2O are 
dependent on factors other than fuel characteristics such as combustion 
temperatures, air-fuel mixes, and use of pollution control equipment. 
These other factors vary significantly across and within the major 
categories of petroleum product end-uses. EPA bases national estimates 
of CH4 and N2O for the U.S. GHG Inventory on 
bottom-up data, such as penetration of control technologies and 
distance traveled for on-highway mobile sources.\103\ We seek comment 
on whether or not EPA should use the national inventory estimates of 
CH4 and N2O emissions from petroleum product 
combustion and apportion them to individual petroleum product suppliers 
based on the quantity of their product.
---------------------------------------------------------------------------

    \102\ CO2, CH4 and N2O 
emissions from combustion of petroleum products were 1900, 3.1, and 
34.1 million metric tons CO2e, respectively.
    \103\ 2008 U.S. GHG Inventory, Annex 3--Methodological 
Descriptions for Additional Source or Sink Categories. pp. A-106 to 
A-120.
---------------------------------------------------------------------------

    Data related to products supplied to or exported from the economy. 
We are proposing that petroleum product suppliers use a mass-balance 
method to calculate CO2 emissions, which is used extensively 
in national GHG inventories and in existing reporting guidelines for 
facilities, companies, and states, such as the WRI/WBCSD GHG 
Protocol.\104\ The mass balance approach is based on readily available 
information: The volume of fuel, which is typically tracked by 
suppliers, and the carbon content of the fuel, i.e., mass of carbon per 
volume of fuel (the carbon content of the petroleum product is also 
referred to as the CO2 emission factor). The formula to 
apply this method is simple and can be automated.\105\ Carbon content, 
where not measured directly, can be estimated using other readily 
available data and literature values.
---------------------------------------------------------------------------

    \104\ See The Greenhouse Gas Protocol (GHG Protocol) http://www.ghgprotocol.org/; the 2008 U.S. Inventory http://www.epa.gov/climatechange/emissions/downloads/08_Energy.pdf, and the 2006 IPCC 
Guidelines http://www.ipcc-nggip.iges.or.jp/public/2006gl/vol2.html.
    \105\ The generic formula is CO2 = Fuel Quantity * 
Carbon Content * 44/12.
---------------------------------------------------------------------------

    There is substantial trade and transfer of products between 
refiners, between importers and refiners, and between other parties. 
The products supplied by one refiner might in some cases serve as the 
feedstock for another refiner. To avoid double-counting of emissions, 
we are proposing an elaboration of the mass-balance approach for use by 
refiners. Under this elaborated approach, to account for the fact that 
any non-crude feedstock \106\ entering a refiner's facility would have 
already been reported by the non-crude feedstock's source (such as an 
importer or another refiner), the refiner would measure and report the 
potential CO2 emissions from the non-crude feedstock, but 
then subtract the amount from the overall CO2 emissions they 
report.
---------------------------------------------------------------------------

    \106\ This could include both petroleum- and natural gas-based 
products.
---------------------------------------------------------------------------

    We are proposing that suppliers report to EPA the types of products 
and quantities of products sold during the reporting period or 
otherwise transferred to another facility, in the case of refiners, or 
corporate entity, in the case of importers and exporters. This 
information underlies the proposed CO2 emissions 
calculations. By focusing on petroleum products sold versus produced, 
we would avoid double-counting products, especially semi-refined 
products, that would either be used onsite by the facility to generate 
energy or that would be reused as a feedstock at some point in the 
facility's production process.
    We are not proposing that petroleum product suppliers collect new 
information on those petroleum products which may be used or converted 
by other entities into long-lived products that are not oxidized or 
combusted, or oxidized slowly over long periods of time (e.g., 
plastics). A comprehensive and rigorous system for tracking the fate of 
non-energy petroleum products and their various end-uses is beyond the 
scope of this rule, and would require a much more burdensome reporting 
obligation for petroleum product suppliers. However, at some point, we 
may need to address the question of non-emissive end uses of petroleum 
products as part of future climate policy development. We request 
comment on our proposal to require petroleum product suppliers to 
report the CO2 emissions associated with products that could 
potentially have non-emissive end-uses. We also request comment on ways 
in which non-emissive end-uses could be tracked and reported.
    Data related to crude feedstocks. We are proposing that refiners 
report basic information to EPA on the crude oil feedstock type, API 
gravity, sulfur content and country of origin during the reporting 
period. This basic information on the feedstock characteristics would 
provide useful information to EPA to assess the lifecycle GHG emissions 
associated with petroleum refining.
    Data related to non-crude petroleum and natural gas feedstocks. As 
discussed previously, in order to minimize double-counting of non-crude 
petroleum products and NGLs, we would require refiners to report the 
volume and CO2 emissions of any non-crude petroleum and 
natural gas feedstock that was acquired from an outside facility. We 
are not proposing to require reporting of products produced at the 
facility and recycled back into processing. In the event that a 
reporter cannot determine whether a feedstock is petroleum-or natural 
gas-based, we are proposing to have the reporter assume the product is 
petroleum-based. We request comment on methods for distinguishing 
between natural gas- and petroleum-based feedstock.

[[Page 16574]]

    Data related to co-processed biomass and blended biomass-based 
fuels. We are proposing to require reporters to provide information on 
the biogenic portion of petroleum products under two circumstances 
discussed below. We are proposing these reporting requirements to 
ensure that EPA can distinguish between potential emissions of carbon 
from biogenic sources (i.e., biomass) and from non-biogenic sources 
(i.e., fossil fuel). We believe it is important to make this 
distinction because CO2 emissions from biogenic sources are 
traditionally accounted for at the time of harvest, collection, or 
disposal, rather than the point of fuel combustion.
    First, we are proposing to require refiners to report information 
related to biomass that is co-processed with a petroleum feedstock 
(crude or non-crude) to produce a product that would be supplied to the 
economy. We propose that refiners report the volume of and estimated 
CO2 emissions associated with both the biomass and 
petroleum-based portions of these products. Refiners would then 
subtract the estimated CO2 emissions from the biomass 
portion from their total CO2 emissions calculation. We are 
not proposing to require refiners to report on CO2 emissions 
from biomass they combust onsite or co-process with a petroleum 
feedstock to produce a product that they combust onsite; these 
emissions are addressed in Section V.Y of this preamble.
    Second, in the case where a reporter supplies or exports a 
petroleum product that is blended with a biomass-based fuel, we are 
proposing only to require CO2 emissions information on the 
petroleum-based portion of the product along with the volume of the 
biomass-based fuel. This reporting requirement would also apply to a 
refiner that receives a blended fuel (e.g., gasoline with ethanol) as 
feedstock to be further refined or otherwise used onsite. We are also 
assuming that all reporters would know the percent volume of the 
biomass-based component of any product. We seek comment on this 
assumption and on any necessary methods for distinguishing between 
biomass- and petroleum-based components of blended fuels.
    Under this proposal, we are proposing to require reporters to 
calculate and report CO2 emissions from products derived 
from co-processing biomass and petroleum feedstocks outside their 
operations as if the products were entirely petroleum-based. We are not 
requiring reporters to report information on products that were derived 
entirely from biomass. We seek comment on this proposed approach 
towards biomass reporting.
    Carbon Content. We are proposing that petroleum product suppliers 
that directly measure the batch-or facility-specific density or carbon 
share of their products report the density and carbon content values 
along with the testing and sampling standards they use for each 
product.\107\ We are not proposing that reporters that choose to use 
the default carbon content values provided in the proposed 40 CFR part 
98, subpart MM be required to report these values since they can easily 
be back-calculated with data on volume and CO2 emissions.
---------------------------------------------------------------------------

    \107\ Proposed 40 CFR part 98, subpart MM identifies the 
specific ASTM standards that reporters must use, but allows 
discretion for the reporter to select the most appropriate standard.
---------------------------------------------------------------------------

    Designated End-use. Although not required as a direct input to the 
mass-balance equation for estimating total emissions, EPA is also 
interested in collecting data on designated end-use (such as for use in 
a highway vehicle versus a stationary boiler) of petroleum products for 
effective policy development. EPA recognizes that petroleum product 
suppliers do not always have full knowledge of the ultimate end-use of 
their products. We evaluated the potential end-uses that petroleum 
product suppliers could know, including end-use designations required 
by EPA's transportation fuel regulations,\108\ and determined that 
reporters should be able to identify diesel fuel intended for use on 
highway since it must contain less than 15 ppm of sulfur and should not 
contain dyes or markers associated with nonroad and stationary fuel. We 
recognize, however, that some of this fuel may ultimately be used in 
nonroad and stationary sectors. We request comment on this proposal, on 
the extent to which this and other refinery gate (ex refinery) and 
importer end-use designations reflect actual end-use consumption 
patterns, and other options EPA could pursue to track the combustion-
related end-uses of petroleum products.
---------------------------------------------------------------------------

    \108\ Current regulations require refiners and importers to 
designate diesel fuel (40 CFR 80.598(a)(2)).
---------------------------------------------------------------------------

    Reporting to EIA. We realize that most petroleum product suppliers 
report much of the relevant fuel quantity information to EIA on a 
monthly, quarterly, or annual basis. During development of this 
proposal, EPA consulted with EIA on its existing reporting programs and 
discussed the feasibility of sharing this information through an 
interagency agreement, rather than requiring reporting parties to 
report the same information multiple times to the Federal government.
    However, we have concluded that comparability and consistency in 
reporting processes across all facilities included in the entire rule 
is vital, particularly with respect to timing of submission, reporting 
formats, QA/QC, database management, missing data procedures, 
transparency and access to information, and recordkeeping. In addition, 
all refineries would be reporting emissions from petroleum refining 
processes under proposed 40 CFR part 98, subpart Y. Finally, as noted 
above, we are requesting readily available information from petroleum 
product suppliers and do not consider reporting information to more 
than one Federal agency an undue burden for these industries. We thus 
considered but are not proposing an option in which EPA obtains 
facility-specific data for suppliers of petroleum products through 
access to existing Federal government reporting databases, such as 
those maintained by EIA. However, in order to reduce the reporting 
burden placed on industry, we would consider information that refiners 
and importers already report to EIA with respect to units and 
frequency, for example, when crafting the reporting requirements for 
refiners, importers, and exporters under the final rule.
    Reporting to EPA's Office of Transportation of Air Quality. EPA 
currently collects a variety of information associated with the 
production and use of most transportation fuels in the U.S. in order to 
ensure compliance with existing fuel regulations and standards. Over 
the course of many years, EPA has developed a reporting system for its 
transportation fuels programs that incorporates a number of compliance 
and enforcement mechanisms. For example, all reporting parties must 
register their facilities with EPA and in many cases use EPA's 
dedicated reporting web portal, the CDX, to submit their reports. We 
review reports to identify reporting errors (e.g. incorrect report 
formats or missing data) but also require reporting parties to self-
report any errors or anomalies in their data. For some of our existing 
transportation fuels reporting programs, we employ the use of annual 
attest engagements, audits of the reporting parties' records by an 
independent certified public accountant or certified internal auditor, 
to help ensure that the data submitted in reports to EPA reflect data 
maintained in the reporting parties' records.
    For purposes of this rule, we are interested in minimizing the 
additional reporting burden on reporters by

[[Page 16575]]

utilizing existing reporting and verification systems, such as EPA's 
transportation fuel programs reporting protocols, as appropriate. We 
request comments on ways to take advantage of existing reporting and 
verification programs, particularly those related to transportation 
fuels. Specifically, as noted in Section IV.J.3 of this preamble, we 
are seeking comment on requiring annual attest engagements for all 
reporters under proposed 40 CFR part 98, subpart MM. In addition, 
whereas the proposed deadline for annual report submission is March 31 
following the reporting year for all reporters under this rule, we seek 
comment on an alternative deadline of February 28 following the 
reporting year for annual reports from suppliers of petroleum products. 
This deadline would align with the submission deadline for annual 
compliance reports under several existing EPA fuels programs.
6. Selection of Records That Must Be Retained
    We are proposing that reporters under this source category must 
maintain all of the following records: copies of all reports submitted 
to EPA under this rule, records documenting the type and quantity of 
petroleum products and NGLs supplied to or exported from the economy, 
records documenting the type, characteristics, and quantity of 
purchased feedstocks, including crude oil, LPGs, biomass, and semi-
refined feedstocks, records documenting the CO2 emissions 
that would result from complete combustion or oxidation of the 
petroleum products, NGLs, and biomass, and sampling and analysis 
records related to all batch-or facility-specific carbon contents 
developed and used in reporting to EPA.
    These records should contain data directly used to calculate the 
emissions that are reported and are necessary to enable verification 
that the CO2 emissions monitoring and calculations were done 
correctly. These records would also consist of information used to 
determine the required characteristics of crude feedstocks.

NN. Suppliers of Natural Gas and Natural Gas Liquids

1. Definition of the Source Category
    This subpart would require reporting by facilities and companies 
that introduce or supply natural gas and NGLs into the economy (e.g., 
LDCs). These facilities and companies would report the CO2 
emissions that would result from complete combustion or oxidation of 
the quantities of natural gas and NGLs supplied (e.g., as a fuel).
    Combustion and other uses of natural gas are addressed in other 
subparts, such as proposed 40 CFR part 98, subpart C (General Fuel 
Stationary Combustion Sources).
    Natural gas is a combustible gaseous mixture of hydrocarbons, 
mostly CH4. It is produced from wells drilled into 
underground reservoirs of porous rock. Natural gas withdrawn from the 
well may contain liquid hydrocarbons and nonhydrocarbon gases. The 
natural gas separated from these components at gas processing plants is 
considered ``dry''. Dry natural gas is also known as consumer-grade 
natural gas. In 2006, the combustion of natural gas for useful heat and 
work resulted in 1,155.1 million metric tons CO2e emissions 
out of a total of 7,054.2 million metric tons CO2e of GHG 
emissions in the U.S.
    In addition to being combusted for energy, natural gas is also 
consumed for non-energy uses in the U.S. The non-energy applications of 
natural gas are diverse, and include feedstocks for petrochemical 
production, ammonia, and other products. In 2006, emissions from non-
energy uses of natural gas were 138 million metric tons 
CO2e.
    The supply chain for delivering natural gas to consumers is 
complex, involving producers (i.e., wells), processing plants, storage 
facilities, transmission pipelines, LNG terminals, and local 
distribution companies. In developing the proposed rule, we concluded 
that inclusion of all natural gas suppliers as reporters would not be 
practical from an administrative perspective, nor would it be necessary 
for complete coverage of the supply of natural gas. In determining the 
most appropriate point in the supply chain of natural gas, we applied 
the following criteria: An administratively manageable number of 
reporting facilities; complete coverage of natural gas supply as a 
group of facilities or in combination with facilities reporting under 
other subparts of this rule; minimal irreconcilable double-counting of 
natural gas supply; and feasibility of monitoring or calculation 
methods.
    Based on these criteria, we are proposing to include LDCs for 
deliveries of dry gas, and natural gas processing facilities for the 
supply of NGLs as reporters under this source category. LDCs receive 
natural gas from the large transmission pipelines and re-deliver the 
gas to end users on their systems, or, in some cases, re-deliver the 
natural gas to other LDCs or even other transmission pipelines. 
Importantly, LDCs keep records on the amount of natural gas delivered 
to their customers. In 2006, LDCs delivered about 12.0 trillion cf or 
60 percent of the total 19.9 trillion cf delivered to consumers. The 
balance of the natural gas is delivered directly to large end users in 
industry and for power generation. Most of these large end users would 
already be included as reporting facilities for direct GHG emissions 
because their emissions exceed the respective emissions threshold for 
their source category.
    LDCs meter the amount of gas they receive and meter and bill for 
the deliveries they make to all end-use customers or other LDCs and 
pipelines. Some of the end-use customers may be large industrial or 
electricity generating facilities that would be included under other 
subparts for direct emissions related to stationary combustion. LDCs 
already report their total deliveries to DOE as well as to State 
regulators. There are approximately 1,207 LDCs in the U.S.\109\
---------------------------------------------------------------------------

    \109\ This number includes all LDCs that report to EIA on Form 
176, and includes separate operating companies owned by a single 
larger company, as for example Niagara Mohawk, a LDC in New York, 
owned by National Grid, which also owns other LDCs in New York and 
New England. For the purposes of this rule, LDCs are defined as 
those companies that distribute natural gas to ultimate end users 
and which are regulated as separate entities by state public utility 
commissions.
---------------------------------------------------------------------------

    Natural gas processing facilities (defined as any facility that 
extracts or recovers NGLs from natural gas, separates individual 
components of NGLs using fractionation, or converts one form of natural 
gas liquid into another form such as butane to isobutene using 
isomerization process) take raw untreated natural gas from domestic 
production and strip out the NGLs, and other compounds. The NGLs are 
then sold, and the processed gas is delivered to transmission 
pipelines.\110\ According to EIA, processors generated about 638 
million barrels of NGLs, in 2006, which is 69 percent of NGLs supplied 
in the U.S. Processors meter the NGLs they produce and deliver to 
pipelines. These data are reported to DOE.
---------------------------------------------------------------------------

    \110\ This definition of processors does not include field 
gathering and boosting stations, and is therefore narrower in scope 
than the definition provided earlier in the preamble for the oil and 
gas sector.
---------------------------------------------------------------------------

    We are not proposing that processing plants report supply of dry 
natural gas to transmission pipelines. While the processing industry in 
2006 delivered an estimated 13.8 trillion cf of processed, pipeline 
quality gas into the pipeline system, an estimated 30 percent of dry 
natural gas goes directly from production fields to the transmission 
pipelines, completely by-passing processing plants. In the interest of 
increasing coverage, we considered but decided not to propose including

[[Page 16576]]

production wells producing pipeline quality natural gas (i.e., not 
needing significant processing) due to the large number of potential 
facilities affected.
    We considered but are not proposing to include the approximately 
448,641 (in 2006) production wells in the U.S. as covered facilities. 
Producers routinely monitor production to predict sales, to distribute 
sales revenues to working interest owners, pay royalties, and pay State 
severance taxes. These data are reported regularly to State agencies. 
At the national level, however, inclusion of producers would be 
administratively difficult and would include many small facilities. EIA 
collects reports from a subset of larger producers in key States, but 
relies on State data to develop comprehensive aggregated national 
statistics.
    We considered but are not proposing to include interstate and 
intrastate pipelines. Pipeline operators transport almost all of the 
natural gas consumed in the U.S. including both domestically produced 
and imported natural gas. While there are a relatively modest number of 
transmission pipelines, approximately 160, and the operators meter 
flows and report these data to DOE, their inclusion as reporters would 
introduce significant complications. The U.S. pipeline network is 
characterized by interconnectivity, in which natural gas moves through 
multiple pipelines on its way to the consumers. Given the hundreds of 
receipt and delivery points and the interconnections with a 
multiplicity of other pipelines, processing plants, LDCs, and end 
users, a substantial amount of double-counting errors would be 
introduced. A time- and resource-intensive administrative effort by EPA 
and reporting companies would be required annually in an attempt to 
correct this double-counting.
    We are also not proposing to include importers of natural gas as 
reporting facilities. Natural gas is imported by land via transmission 
pipelines (primarily from Canada), and as LNG via a small number of 
port terminals (predominantly on the East and Gulf coasts). Imported 
natural gas ultimately is delivered to consumers by LDCs or sent 
directly to high volume consumers who would report under other subparts 
of proposed 40 CFR part 98.
    EPA requests comment on the inclusion of LDCs and processing 
plants, and the exclusion of other parts of the natural gas supply and 
distribution chain. For additional background information on suppliers 
of natural gas, please refer to the Suppliers of Natural Gas and NGLs 
TSD (EPA-HQ-OAR-2008-0508-040).
2. Selection of Reporting Threshold
    In developing the reporting threshold for LDCs and natural gas 
processors, EPA considered emissions-based thresholds of 1,000 metric 
tons CO2e, 10,000 metric tons CO2e, 25,000 metric 
tons CO2e and 100,000 metric tons CO2e per year. 
For natural gas suppliers, these thresholds are applied on the amount 
of CO2 emissions that would result from complete combustion 
or oxidation of the natural gas. These thresholds translate into 18,281 
thousand cf, 182,812 thousand cf, 457,030 thousand cf, and 1,828,120 
thousand cf of natural gas, respectively.
    Table NN-1 of this preamble illustrates the LDC emissions and 
facilities that would be covered under these various thresholds.

                                                         Table NN-1. Threshold Analysis for LDCs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              metric tons    of facilities    Metric tons
                                                              CO2e/yr                         CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................     632,100,851           1,207     632,004,022           99.98           1,022              85
10,000..................................................     632,100,851           1,207     630,106,725           99.68             521              43
25,000..................................................     632,100,851           1,207     627,543,971           99.28             365              30
100,000.................................................     632,100,851           1,207     619,456,607           98.00             206              17
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We propose to include all LDCs as reporters in this source 
category. Of the approximate 1,207 LDCs, the 25,000 metric tons 
CO2e threshold would capture the 365 largest LDCs and 98 
percent of the natural gas that flows through them. The remaining LDCs 
already report annual throughput to EIA in form EIA 176. Thus, 
inclusion of all LDC's does not require collection of new information. 
Comments on this conclusion are requested.
    Table NN-2 of this preamble illustrates the NGL emissions and 
number of processing facilities that would be covered under these 
various thresholds.

                                             Table NN-2. Threshold Analysis for NGLs From Processing Plants
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                          Total national                         Emissions covered              Facilities covered
                                                             emissions     Total number  ---------------------------------------------------------------
           Threshold level metric tons CO2e/yr              metric tons    of facilities    Metric tons
                                                              CO2e/yr                         CO2e/yr         Percent         Number          Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000...................................................     164,712,077             566     164,704,346             100             466              82
10,000..................................................     164,712,077             566     164,404,207             100             400              71
25,000..................................................     164,712,077             566     163,516,733              99             347              61
100,000.................................................     164,712,077             566     157,341,629              96             244              43
--------------------------------------------------------------------------------------------------------------------------------------------------------

    We propose there be no reporting threshold for natural gas 
processing plants. Each natural gas processing plant is already 
required to report the supply (beginning stocks, receipts, and 
production) and disposition (input, shipments, fuel use and losses, and 
ending stocks) of NGLs monthly on EIA Form 816. Processing plants are 
also required to report the amounts of natural gas processed, NGLs 
produced, shrinkage of the natural gas from NGLs extraction, and the 
amount of natural gas used in processing on an annual basis on EIA Form 
64A.
    For a full discussion of the threshold analysis, please refer to 
the Suppliers of Natural Gas and NGLs TSD (EPA-HQ-

[[Page 16577]]

OAR-2008-0508-040). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
    Under this subpart, we are proposing reporting the amount of 
natural gas and NGLs produced or supplied to the economy annually, as 
well as the CO2 emissions that would result from complete 
oxidation or combustion of this quantity of natural gas and NGLs.
    The only GHG required to be reported under this subpart is 
CO2. Combustion of natural gas and NGLs may also lead to 
trace quantities of CH4 and N2O emission.\111\ 
Because the quantity of CH4 and N2O emissions are 
small, highly variable and dependent on technology and operating 
conditions in which the fuel is being consumed (unlike CO2), 
we are not proposing that natural gas suppliers report on these 
emissions. We seek comment on whether or not EPA should use the 
national inventory estimates of CH4 and N2O 
emissions from natural gas combustion, and apportion them to individual 
natural gas suppliers based on the quantity of their product. We 
request comments on this conclusion.
---------------------------------------------------------------------------

    \111\ In 2006, CO2, CH4 and N2O 
emissions from natural gas combustion were 1,155.1, 1.0, and 0.6 
MMTCO2e, respectively.
---------------------------------------------------------------------------

    We are proposing that LDCs and natural gas processing plants use a 
mass-balance method to calculate CO2 emissions. The mass 
balance approach is based on readily available information: The 
quantity of fuel (e.g., thousand cf, barrels, mmBtus), and the carbon 
content of the fuel. The formula is simple and can be automated. The 
mass-balance approach is used extensively in national GHG inventories, 
and in existing reporting guidelines for facilities, companies, and 
States, such as the WRI/WBCSD GHG Protocol.
    For carbon content, we have prepared two look-up tables listing 
default CO2 emission factors of natural gas and natural gas 
liquid. These emission factors are drawn from published sources, 
including the American Petroleum Institute Compendium, EIA, and the 
U.S. GHG Inventory.
    Where natural gas processing plants extract and separate individual 
components of NGLs, the facilities should report carbon content by 
individual component of the NGLs. In cases where raw NGLs are not 
separated, the processing plants should report carbon content for the 
raw NGLs. LDCs and natural gas processing plants can substitute their 
own values for carbon content provided they are developed according to 
nationally-accepted ASTM standards for sampling and analysis.
    We considered but do not propose an option in which LDCs and 
natural gas processing plants would be required to sample and analyze 
natural gas and NGLs periodically to determine the carbon content. 
Given the close correlation between carbon content and BTU value of 
natural gas and NGLs, and the availability of BTU information on these 
products, EPA believes that periodic sampling and analysis would impose 
a cost on facilities but would not result in improved accuracy of 
reported emissions values. We request comment on an approach in which 
natural gas suppliers would be required to develop facility- and batch-
specific carbon contents through periodic sampling and analysis. The 
various approaches to monitoring GHG emissions are elaborated in the 
Suppliers of Natural Gas and NGLs TSD (EPA-HQ-OAR-2008-0508-040).
4. Selection of Procedures for Estimating Missing Data
    EPA has determined that the information to be reported by LDCs and 
gas processing plants is routinely collected by facilities as part of 
standard operating practices, and expects that any missing data would 
be negligible. Typically, natural gas amounts are metered directly at 
multiple stages, and billing systems require rigorous reconciliation of 
data. In cases where metered data are not available, reporters may 
estimate the missing volumes based on contracted maximum daily 
quantities and known conditions of receipt and delivery during the 
period when data are missing.
5. Selection of Data Reporting Requirements
    We propose that LDCs and gas processing plants report 
CO2 emissions directly to EPA on an annual basis. LDCs would 
also report CO2 emissions disaggregated into categories that 
represent residential consumers, commercial consumers, industrial 
consumers, and electricity generating facilities. Further information 
would be provided on the facilities to which LDCs deliver greater than 
460,000 thousand cf of natural gas during the calendar year, which 
would be used by EPA to check and verify information on facilities 
covered under other subparts of this rule because of their onsite 
stationary combustion or process emissions.\112\
---------------------------------------------------------------------------

    \112\ 460,000 thousand cf/year is a conservative estimate of the 
amount of dry natural gas that when fully combusted would produce at 
least 25,000 metric tons of CO2.
---------------------------------------------------------------------------

    Natural gas processing plants would report CO2 emissions 
disaggregated by individual components of NGLs extracted and separated, 
where applicable. Where raw NGLs are not separated into individual 
components, plants should report CO2 emissions for raw NGLs.
    We considered but are not proposing an option in which EPA obtained 
facility-specific data for natural gas and NGLs through access to 
existing Federal government reporting databases, such as those 
maintained by EIA. We have concluded that comparability and consistency 
in reporting processes across all facilities included in the entire 
rule is vital, particularly with respect to timing of submission, 
reporting formats, QA/QC, database management, missing data procedures, 
transparency and access to information, and recordkeeping. In addition, 
large natural gas processing plants would already be included as 
reporting facilities under proposed 40 CFR 98.2(a)(2), therefore there 
is minimal burden in reporting the additional information proposed 
under this subpart. Finally, as noted above, we are requesting readily 
available information from LDCs and natural gas processing facilities, 
and do not consider reporting information to more than one Federal 
agency to place an undue burden on these industries.
6. Selection of Records That Must Be Retained
    Records that must be kept include quantity of individual fuels 
supplied, BTU content, carbon content determined, flow records and/or 
invoice records for customers with amount of natural gas received, type 
of customer receiving natural gas (so the disaggregated report by 
category can be checked), and data for determining carbon content for 
natural gas processing plants. These records are necessary to enable 
verification that the GHG monitoring and calculations were done 
correctly. Records related to the end-user (e.g., ammonia facility) are 
required to allow us to reconcile data reported by different facilities 
and entities, and to ensure that coverage of natural gas supply and 
end-use is comprehensive.
    A full list of records that must be retained onsite is included in 
proposed 40 CFR part 98, subparts A and NN.

[[Page 16578]]

OO. Suppliers of Industrial GHGs

1. Definition of the Source Category
    The industrial gas supply category includes facilities that produce 
N2O or fluorinated GHGs,\113\ importers of N2O or 
fluorinated GHGs, and exporters of N2O or fluorinated GHGs. 
These facilities and entities are collectively referred to as 
``suppliers of industrial GHGs''.
---------------------------------------------------------------------------

    \113\ Please see the proposed definition of fluorinated GHG near 
the end of this section.
---------------------------------------------------------------------------

    Under the proposed40 CFR part 98, subpart OO, if you produce 
fluorinated GHGs or N2O, you would be required to report the 
quantities of these gases that you produce, transform (use as 
feedstocks in the production of other chemicals), destroy, or send to 
another facility for transformation or destruction. Importers and 
exporters of bulk fluorinated GHGs and N2O would be required 
to report the quantities that they imported or exported and the 
quantities that they imported and sold or transferred to another person 
for transformation or destruction. As described in Sections III and IV 
of this preamble, emissions from general stationary fuel combustion 
sources and fugitive emissions from fluorinated gas production are 
addressed separately (Sections V.C and V.L of this preamble).
    Fluorinated GHGs. Fluorinated GHGs are man-made gases used in a 
wide variety of applications. They include HFCs, PFCs, SF6, 
NF3, fluorinated ethers, and other compounds such as 
perfluoropolyethers. CFCs and HCFCs also contain fluorine and are GHGs, 
but both the production and consumption (production plus import minus 
export) of these ODS are currently being phased out and otherwise 
regulated under the Montreal Protocol and Title VI of the CAA. We are 
not proposing requirements for ODS under proposed 40 CFR part 98.
    Fluorinated GHGs are powerful GHGs whose ability to trap heat in 
the atmosphere is often thousands to tens of thousands times as great 
as that of CO2, on a pound-for-pound basis. Some fluorinated 
GHGs are also very long lived; SF6 and PFCs have lifetimes 
ranging from 3,200 to 50,000 years.\114\
---------------------------------------------------------------------------

    \114\ IPCCC SAR available at: http://www.ipcc.ch/ipccreports/assessments-reports.htm.
---------------------------------------------------------------------------

    HFCs are the most commonly used fluorinated GHGs, they are used 
primarily as a replacement for ODS in a number of applications, 
including air-conditioning and refrigeration, foams, fire protection, 
solvents, and aerosols. PFCs are used in fire fighting and to 
manufacture semiconductors and other electronics. SF6 is 
used in a diverse array of applications, including electrical 
transmission and distribution equipment (as an electrical insulator and 
arc quencher) and in magnesium casting operations (as a cover gas to 
prevent oxidation of molten metal). NF3 is used in the 
semiconductor industry, increasingly to reduce overall semiconductor 
GHG emissions through processes such as NF3 remote cleaning 
and NF3 substitution during in-situ cleaning. Fluorinated 
ethers (HFEs and HCFEs) are used as anesthetics (e.g., isofluorane, 
desflurane, and sevoflurane) and as heat transfer fluids (e.g., the H-
Galdens).
    In 2006, 12 U.S. facilities produced over 350 million metric tons 
CO2e of HFCs, PFCs, SF6, and NF3. More 
specifically, 2006 production of HFCs is estimated to have exceeded 250 
million metric tons CO2e while production of PFCs, 
SF6, and NF3 was estimated to be almost 100 
million metric tons CO2e. We estimate that an additional 6 
facilities produced approximately 1 million metric tons CO2e 
of fluorinated anesthetics.
    Fluorinated GHGs are imported both in bulk (contained in shipping 
containers and cylinders) and in products. For further information, see 
the Bulk Imports and Exports of Fluorinated Gases TSD (EPA-HQ-OAR-2008-
0508-042) and the Imports of Fluorinated GHGs in Products TSD (EPA-HQ-
OAR-2008-0508-043). EPA estimates that over 110 million metric tons 
CO2e of bulk HFCs, PFCs, and SF6 were imported 
into the U.S. in 2007 by over 100 importers (PIERS, 2007). In 
CO2e terms, SF6 and NF3 each made up 
about one third of this total, while HFCs accounted for one quarter and 
PFCs made up the remainder. Several other fluorinated GHGs may be 
imported in smaller quantities, including fluorinated ethers such as 
the H-Galdens and anesthetics such as desflurane (HFE-236ea2), 
isoflurane (HCFE-235da2), and sevoflurane.
    A variety of products containing fluorinated GHGs are imported into 
the U.S. Imports of particular importance include pre-charged air-
conditioning, refrigeration, and electrical equipment and closed-cell 
foams. Pre-charged air-conditioning and refrigeration equipment 
contains a full or partial (holding) charge of HFC refrigerant, while 
pre-charged electrical equipment contains a full or partial charge of 
SF6 insulating gas. Closed-cell foams contain HFC blowing 
agent.
    We estimate that in 2010, approximately 18 million metric tons 
CO2e of fluorinated GHGs would be imported in pre-charged 
equipment.\115\ In 2006, an additional 2.5 million metric tons 
CO2e of fluorinated GHGs were imported in closed-cell foams. 
Together, these imports are expected to constitute between five and ten 
percent of U.S. consumption of fluorinated GHGs.
---------------------------------------------------------------------------

    \115\ The number of refrigeration and AC units imported in 2010 
was assumed to equal the number of units imported in 2006. The 
refrigeration and AC units imported in 2006 were pre-charged with 
both HFCs and HCFCs. (HCFCs are ozone-depleting substances that are 
regulated under the Montreal Protocol and are exempt from the 
proposed definition of fluorinated GHG.) However, by 2010, EPA 
expects that all imported refrigeration and AC units will be charged 
with HFCs, because imports pre-charged with HCFCs will not be 
permitted starting in that year.
---------------------------------------------------------------------------

    Once produced or imported, fluorinated GHGs can have hundreds of 
millions of downstream emission points. For example, the gases are used 
in almost all car air conditioners and household refrigerators and in 
other ubiquitous products and applications. Thus, tracking emissions of 
these gases from all downstream uses would not be practical.
    Nitrous oxide. N2O is a clear, colorless, oxidizing gas 
with a slightly sweet odor. N2O is a strong GHG with a GWP 
of 310.\116\
---------------------------------------------------------------------------

    \116\ IPCCC SAR.
---------------------------------------------------------------------------

    N2O is primarily used in carrier gases with oxygen to 
administer more potent inhalation anesthetics for general anesthesia 
and as an anesthetic in various dental and veterinary applications. In 
this application, it is used to treat short-term pain, for sedation in 
minor elective surgeries and as an induction anesthetic. The second 
main use of N2O is as a propellant in pressure and aerosol 
products, the largest application being pressure-packaged whipped 
cream. In smaller quantities, N2O is also used as an 
oxidizing agent and etchant in semiconductor manufacturing, an 
oxidizing agent (with acetylene) in atomic absorption spectrometry, an 
oxidizing agent in blowtorches used by jewelers and others, a fuel 
oxidant in auto racing, and a component of the production of sodium 
azide, which is used to inflate airbags.
    Two companies operate a total of five N2O production 
facilities in the U.S.. These facilities produced an estimated 4.5 
million metric tons CO2e of N2O in 2006.
    N2O may be imported in bulk or inside products. We 
estimate that approximately 300,000 metric tons CO2e of bulk 
N2O were imported into the U.S. in 2007 by 18 importers. 
Products that may be imported include several of those listed above, 
particularly pre-blended anesthetics and aerosol

[[Page 16579]]

products such as pressure-packaged whipped cream.
    Further information on N2O supply and import can be 
found in the Suppliers of Industrial GHGs TSD (EPA-HQ-OAR-2008-0508-
041).
    Selection of Reporting Facilities and Types of Data to be Reported. 
Because fluorinated GHGs and N2O have an extremely large 
number of relatively small downstream sources, reporting of downstream 
emissions of these gases would be incomplete, impractical, or both. On 
the other hand, the number of upstream producers, importers, and 
exporters is comparatively small, and the quantities that would be 
reported by individual gas suppliers are often quite large. Thus, 
upstream reporting is likely to be far more complete and cost-effective 
than downstream reporting. For these reasons, we are proposing to 
require upstream reporting of the quantities required to estimate U.S. 
consumption of N2O and fluorinated gases. ``Consumption'' is 
defined as the sum of the quantities of chemical produced in or 
imported into the U.S. minus the sum of the quantities of chemical 
transformed (used as a feedstock in the production of other chemicals), 
destroyed, or exported from the U.S.
    In developing this proposed rule, we reviewed a number of protocols 
that track chemical consumption, its components (production, import, 
export, etc.), or similar quantities. These protocols included EPA's 
Stratospheric Ozone Protection regulations at 40 CFR part 82, the EU 
Regulation on Certain Fluorinated Greenhouse Gases (No. 842/2006), the 
Australian Commonwealth Government Ozone Protection and Synthetic 
Greenhouse Gas Reporting Program, EPA's Chemical Substances Inventory 
Update Rule at 40 CFR 710.43, EPA's Acid Rain regulations at 40 CFR 
part 75, the TRI Program, and the 2006 IPCC Guidelines.\117\
---------------------------------------------------------------------------

    \117\ We also reviewed other programs, including the DOE's 
1605(b) Program, EPA's Climate Leaders Program, and the European 
Commission's Article 6 reporting requirements, but we found that 
these programs did not monitor consumption or its components.
---------------------------------------------------------------------------

    We reviewed these protocols both for their overall scope and for 
their specific requirements for monitoring and reporting. The 
monitoring requirements are discussed in Section V.OO.3 of this 
preamble. The protocols whose scopes were most similar to the one 
proposed for industrial gas supply were EPA's Stratospheric Protection 
Program, the EU Regulation on Certain Fluorinated Greenhouse Gases, the 
Australian Synthetic Greenhouse Gas Reporting Program, and EPA's 
Chemical Substances Inventory Update Rule. All four of these programs 
require reporting of production and imports, and the first three also 
require reporting of exports. In addition, the EU regulation and EPA's 
Stratospheric Ozone Protection Program require reporting of the 
quantities of chemicals (ODS) transformed or destroyed. In general, the 
proposed requirements in this rule are based closely on those in EPA's 
Stratospheric Ozone Protection Program. By accounting for all chemical 
flows into and out of the U.S., including destruction and 
transformation, this approach results in an estimate of consumption 
that is more closely related to actual U.S. emissions than are 
estimates of consumption that do not account for all of these flows.
    Proposed Definition of Fluorinated GHGs. We propose to define 
``Fluorinated GHG'' as SF6, NF3, and any 
fluorocarbon except for ODS as they are defined under EPA's 
stratospheric protection regulations at 40 CFR part 82, subpart A. In 
addition to SF6 and NF3, this definition would 
include any hydrofluorocarbon, any perfluorocarbon, any fully 
fluorinated linear, branched or cyclic alkane, ether, tertiary amine or 
aminoether, any perfluoropolyether, and any hydrofluoropolyether.
    EPA is proposing this definition because HFCs, PFCs, 
SF6, NF3, and many fluorinated ethers are known 
to have significant GWPs. (For a list of these GWPs, see Table A-1 of 
proposed 40 CFR part 98, subpart A.) In addition, although not all 
fluorocarbons have had their GWPs evaluated, any fluorocarbon with an 
atmospheric lifetime greater than one year is likely to have a 
significant GWP due to the radiative properties of the carbon-fluorine 
bond.
    As discussed above, ODS are excluded from the proposed definition 
of fluorinated GHG because they are already regulated under the 
Montreal Protocol and Title VI of the CAA.
    EPA requests comment on the proposed definition. EPA also requests 
comment on two other options for defining or refining the set of 
fluorinated GHGs to be reported. The first option would permit a 
fluorocarbon to be excluded from reporting if (1) the GWP for the 
fluorocarbon were not listed in Table A-1 of proposed 40 CFR part 98, 
subpart A or in any of the IPCC Assessment Reports or World 
Meteorological Organization (WMO) Scientific Assessments of Ozone 
Depletion, and (2) the producer or importer of the fluorocarbon could 
demonstrate, to the satisfaction of the Administrator, that the 
fluorocarbon had an atmospheric lifetime of less than one year and a 
100-year GWP of less than five. In general, we expect that new 
fluorocarbons would be used in relatively low volumes. For such 
chemicals, a GWP of five may be a reasonable trigger for reporting.
    The second option would be to require reporting only of those 
fluorinated chemicals listed in Table A-1 of proposed 40 CFR part 98, 
subpart A. The disadvantage of this approach is that it would exclude 
any new (or newly important) fluorocarbons whose GWPs have not been 
evaluated. As discussed above, fluorocarbons in general are likely to 
have significant GWPs. Given the pace of technological development in 
this area, production (and emissions) of these gases could become 
significant before the chemicals were added to the table.
2. Selection of Reporting Threshold
    In developing the proposed thresholds for producers and importers 
of fluorinated GHGs and N2O, we considered production, 
capacity, and import/export thresholds of 1,000 metric tons 
CO2e, 10,000 metric tons CO2e, 25,000 metric tons 
CO2e, and 100,000 metric tons CO2e per year. 
Table OO-1 of this preamble shows the emissions and facilities that 
would be covered under the various thresholds for production and bulk 
imports of N2O and HFCs, PFCs, SF6, and 
NF3.

[[Page 16580]]



                                                Table OO-1. Threshold Analysis for Industrial Gas Supply
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                            Emission     Total national                   Production or imports covered         Facilities Covered
                                            threshold     production or                 ----------------------------------------------------------------
            Source category                   level          import         Number of
                                          (metrics tons   (metric tons     facilities      Metric tons       Percent          Number          Percent
                                            CO2e/yr)        CO2e/yr)                         CO2e/yr
--------------------------------------------------------------------------------------------------------------------------------------------------------
HFC, PFC, SF6, and NF3 Producers.......           1,000     350,000,000              12     350,000,000            100                12             100
                                                 10,000     350,000,000              12     350,000,000            100                12             100
                                                 25,000     350,000,000              12     350,000,000            100                12             100
                                                100,000     350,000,000              12     350,000,000            100                12             100
N2O Producers..........................           1,000       4,500,000               5       4,500,000            100                 5             100
                                                 10,000       4,500,000               5       4,500,000            100                 5             100
                                                 25,000       4,500,000               5       4,500,000            100                 5             100
                                                100,000       4,500,000               5       4,500,000            100                 5             100
N2O and Fluorinated GHG Importers                 1,000     110,024,979             116     110,024,987            100               111              96
 (bulk)................................
                                                 10,000     110,024,979             116     109,921,970             99.9              81              70
                                                 25,000     110,024,979             116     109,580,067             99.6              61              53
                                                100,000     110,024,979             116     108,703,112             98.8              44              38
--------------------------------------------------------------------------------------------------------------------------------------------------------

    Producers. We are proposing to require reporting for all 
N2O and fluorinated GHG production facilities. As shown in 
Table OO-1 of this preamble, all identified N2O, HFC, PFC, 
SF6, and NF3 production facilities would be 
covered at all capacity and production-based thresholds considered in 
this analysis. We do not have facility-specific production capacity 
information for the six facilities producing fluorinated anesthetics; 
however, if all these facilities produced the same quantity in 
CO2e terms, they too would probably be covered at all 
capacity and production-based thresholds.
    The requirement that all facilities report would simplify the rule 
and permit facilities to quickly determine whether or not they must 
report. The one potential drawback of this requirement is that small-
scale production facilities (e.g., for research and development) could 
be inadvertently required to report their production, even though the 
quantities produced would be small in both absolute and CO2e 
terms. We are not currently aware of any small-scale deliberate 
production of N2O or fluorinated GHGs, but we request 
comment on this issue. These research and development facilities could 
be specifically exempt from reporting. An alternative approach that 
would address this concern would be to establish a capacity-based 
threshold of 25,000 metric tons CO2e, summed across the 
facility's production capacities for N2O and each 
fluorinated GHG. We request comment on these alternative approaches.
    Importers and Exporters. We are proposing to require importers and 
exporters to report their imports and exports if either their total 
imports or their total exports, in bulk, of all relevant gases, exceed 
25,000 metric tons CO2e. We are proposing this threshold to 
reduce the compliance burden on small businesses while still including 
the vast majority of imports and exports. As is true for HFC 
production, HFC import and export levels are expected to increase 
significantly during the next several years as HFCs replace ODS, which 
are being phased out under the Montreal Protocol.
    Because it may be relatively easy for importers and exporters to 
create new corporations in order to divide up their imports and exports 
and remain below applicable thresholds, we considered setting no 
threshold for importers and exporters. However, we are not proposing 
this option because we are concerned that it would be too burdensome to 
current small-scale importers. We request comment on this approach, 
specifically the burden on small-scale importers if they were required 
to report.
    Further information on the threshold analysis for industrial gas 
suppliers can be found in the Suppliers of Industrial GHGs TSD (EPA-HQ-
OAR-2008-0508-041). For specific information on costs, including 
unamortized first year capital expenditures, please refer to section 4 
of the RIA and the RIA cost appendix.
3. Selection of Proposed Monitoring Methods
a. Production
    If you produce N2O or fluorinated GHGs, we propose that 
you measure the total mass of N2O or fluorinated gases 
produced by chemical, including production that was later transformed 
or destroyed at the facility, but excluding any used GHG product that 
was added to the production process (e.g., HFCs returned to the 
production facility and added to the HFC production process for 
reclamation). Production would be measured wherever it is traditionally 
measured, e.g., at the inlet to the day tank or at the shipping dock. 
The quantities transformed or destroyed would be reported separately; 
see Sections V.OO.3.c and V.OO.3.d of this preamble. The quantities of 
used product added to the production process would be measured and 
subtracted from the total mass of product measured at the end of the 
process. This would avoid counting used GHG product as new production.
b. Imports and Exports
    If you import or export bulk N2O or fluorinated GHGs, we 
propose that you report the total quantities of N2O or 
fluorinated GHGs that you import or export by chemical. Reports would 
include quantities imported in mixtures and the name/number of the 
mixture, if applicable (e.g., HFC-410A). Reporting would occur at the 
corporate level. You would not be required to report imports or exports 
of heels (residual quantities inside returned containers) or 
transshipments (GHGs that originate in a foreign country and that are 
destined for another foreign country), but you would be required to 
keep records documenting the nature of these transactions.
    We propose to require reporting of imports and exports in metric 
tons of chemical because that is the unit in which other quantities 
(production, emissions, etc.) are proposed to be reported under this 
rule. However,

[[Page 16581]]

because the preferred unit for Customs reporting is kg rather than 
tons, EPA requests comment on whether it should require reporting of 
imports and exports in kg of chemical.
    In general, these proposed requirements are consistent with those 
of other programs that monitor imports and exports of bulk chemical, 
particularly EPA's Stratospheric Ozone Protection regulations.
    Existing programs vary in their treatment of products containing 
chemicals whose bulk import must be reported. The Australian program 
requires reporting of all ODS and GHGs imported in pre-charged 
equipment, including the identity of the refrigerant, the number of 
pieces of equipment, and the charge size. The Inventory Update Rule 
requires reporting of chemicals contained in products if the chemical 
is designed to be released from the product when it is used (e.g., ink 
from a pen). EPA's Stratospheric Ozone Protection regulations do not 
currently require reporting of ODS contained in imported equipment or 
other imported products; however, (1) EPA has prohibited the 
introduction into interstate commerce, including import, of certain 
non-essential products typically pre-charged with these chemicals, and 
(2) EPA is in the process of proposing new regulations to prohibit 
import of equipment pre-charged with HCFCs.
    We are not proposing to require that importers of products 
containing N2O or fluorinated GHGs report their imports. In 
general, we are concerned that it would be difficult for importers to 
identify and quantify the GHGs contained in these products and that the 
number of importers would be high. However, it may be easier for 
importers to identify and quantify the GHGs contained in a few types of 
products, such as pre-charged equipment and foams. For example, the 
identities and amounts of fluorinated GHGs contained in equipment are 
generally well known; this data is typically listed on the nameplate 
affixed to every unit. Moreover, in aggregate, the quantities of GHGs 
imported in equipment can be large, for example, over 7 million metric 
tons CO2e in imported pre-charged window air-conditioners. 
We request comment on whether we should require reporting of imports or 
exports of pre-charged equipment and/or closed-cell foams, including 
the likely burden and benefits of such reporting.
c. N2O or Fluorinated GHGs Transformed
    Under the proposed rule, if you chemically transform N2O 
or fluorinated GHGs, you would be required to estimate the mass of 
N2O or fluorinated GHGs transformed. This estimate would be 
the difference between (1) the quantity of the N2O or 
fluorinated GHG fed into the process for which the N2O or 
fluorinated GHG was used as a feedstock, and (2) the mass of any 
unreacted feedstock that was not returned to the process. Measuring the 
quantity of N2O or fluorinated GHGs actually fed into the 
process would account for any losses between the point where total 
production of the fluorinated GHG is measured and the point where the 
fluorinated GHG is reacted as a feedstock (transformed). The mass of 
any unreacted feedstock that was not returned to the process would be 
ascertained using mass flow measurements and (if necessary) gas 
chromatography.
d. Destruction
    Under the proposed rule, if you produce and destroy fluorinated 
GHGs, you would be required to estimate the quantity of each 
fluorinated GHG destroyed. This estimate would be based on (1) the 
quantity of the fluorinated GHG fed into the destruction device, and 
(2) the DE of the device. In developing the estimate, you would be 
required to account for any decreases in the DE of the device that 
occurred when the device was not operating properly (as defined in 
State or local permitting requirements and/or destruction device 
manufacturer specifications). Finally, you would be required to perform 
annual fluorinated GHG concentration measurements by gas chromatography 
to confirm that emissions from the destruction device were as low as 
expected based on the DE of the device. If emissions were found to be 
higher, then you would have the option of using the DE implied by the 
most recent measurements or of conducting more extensive measurements 
of the DE of the device.
    These proposed requirements are identical to those proposed for 
destruction of HFC-23 that is generated as a byproduct during HCFC-22 
production. They are also similar to those contained in EPA's 
Stratospheric Ozone Protection Regulations. Those regulations include 
detailed requirements for reporting and verifying transformation and 
destruction of chemicals.
    We are proposing requirements for verifying the DE of destruction 
devices used to destroy fluorinated GHGs because fluorinated GHGs, 
particularly PFCs and SF6, are difficult to destroy. In many 
cases, these chemicals have been selected for their end uses precisely 
because they are not flammable. For destruction to occur, temperatures 
must be quite high (over 2,300 [deg]F), fuel must be provided, flow 
rates of fuels and air (or oxygen) must be kept above certain limits, 
flow rates of fluorinated GHG must be kept below others, and for some 
particularly difficult-to-destroy chemicals such as CF4, 
pure oxygen must sometimes be fed into the process. If one or more of 
these process requirements is not met, DEs can drop sharply (in some 
cases, by an order of magnitude or more), and fluorinated GHGs would 
simply be exhausted from the device. Both construction deficiencies and 
operator error can lead to a failure to meet process requirements; 
thus, both initial testing and periodic monitoring are important for 
verifying destruction device performance. We request comment on the 
option of requiring that the annual destruction device emissions 
measurement be performed using a compound that is at least as difficult 
to destroy as the most difficult-to-destroy GHG ever fed into the 
device, e.g., SF6 or CF4.
    We believe that owners or operators of facilities that destroy 
fluorinated GHGs are already likely to verify the DEs of their 
destruction devices. Many facilities destroying fluorinated GHGs are 
likely to destroy ODS as well. In this case, they are already subject 
to requirements to verify the DEs of their devices.
    We request comment on the extent of potential overlap between the 
destruction reported under proposed 40 CFR part 98, subpart OO and that 
reported under proposed 40 CFR part 98, subpart L. To obtain an 
accurate estimate of the net supply of fluorinated industrial 
greenhouse gases, fluorinated GHGs that are produced and subsequently 
destroyed should be subtracted from the total produced or imported. 
However, if fluorinated GHGs are never included in the mass produced 
(e.g., because they are removed from the production process with or as 
byproducts), then including them in the mass destroyed would lead to an 
underestimate of supply. One possible solution to this problem would be 
to require facilities producing and destroying fluorinated GHGs to 
separately estimate and report their destruction of fluorinated GHGs 
that have been counted as produced in either the current year or 
previously.
    EPA is not proposing to require reporting of N2O 
destruction, because EPA is not aware that such destruction occurs. 
However, EPA requests comment on this.

[[Page 16582]]

e. Precision, Accuracy, and Calibration Requirements
    The protocols and guidance reviewed by EPA differ in their level of 
specificity regarding the measurement of production or other flows, 
particularly regarding their precision and accuracy requirements. Some 
programs, such as the Stratospheric Ozone Protection regulations, do 
not specify any accuracy requirements, while other programs 
specifically define acceptable errors and reference industry standards 
for calibrating and verifying monitoring equipment. One of the latter 
is 40 CFR part 75, Appendix D, which establishes requirements for 
measuring oil and gas flows as a means of estimating SO2 
emissions from their combustion. These requirements include a 
requirement that the fuel flowmeter accuracy be within 2 percent of the 
upper range value and a requirement that flowmeters be recalibrated at 
least once a year.
    In today's proposed rule, we are proposing to require facilities to 
measure the mass of N2O or fluorinated GHGs produced, 
transformed, or destroyed using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 0.2 percent of full scale or better. In addition, we are 
proposing to require that weigh scales, flowmeters, and/or other 
measurement devices be calibrated every year or sooner if an error is 
suspected based on mass-balance calculations or other information. 
Facilities could perform the verification and calibration of their 
scales and flowmeters during routine product line maintenance. Finally, 
we are proposing that facilities transforming or destroying fluorinated 
GHGs calibrate gas chromatographs by analyzing, on a monthly basis, 
certified standards with known GHG concentrations that are in the same 
range (percent levels) as the process samples.
    EPA requests comment on these proposed requirements. EPA 
specifically requests comment on the proposed frequency of calibration 
for flowmeters; the Agency understands that some types of flowmeters 
that are commonly employed in chemical production, such as the Coriolis 
type, may require less frequent calibration.
    We are proposing specific accuracy, precision, and calibration 
requirements because the high GWPs and large volumes of fluorinated 
GHGs produced make such requirements worthwhile for this source 
category. For example, a one percent error at a typical facility 
producing fluorinated GHGs would equate to 300,000 metric tons 
CO2e. The Agency believes that these precision and accuracy 
requirements (0.2 percent) should not represent a significant burden to 
chemical producers, who already use and regularly calibrate measurement 
devices with similar accuracies.
    EPA is not proposing precision and accuracy requirements for 
importers and exporters of bulk chemical; however, EPA requests comment 
on whether such requirements (e.g., 0.5 to 1 percent) would be 
appropriate.
4. Selection of Procedures for Estimating Missing Data
a. Production
    In the event that any data on the mass produced, fed into the 
production process (for used material being reclaimed), fed into 
transformation processes, fed into destruction devices, or sent to 
another facility for transformation or destruction, is unavailable, we 
propose that facilities be required to use secondary measurements of 
these quantities. For example, facilities that ordinarily measure 
production by metering the flow into the day tank could use the weight 
of product charged into shipping containers for sale and distribution. 
We understand that the types of flowmeters and scales used to measure 
fluorocarbon production (e.g., Coriolis meters) are generally quite 
reliable, and therefore it should rarely be necessary to rely on 
secondary production measurements. In general, production facilities 
rely on accurate monitoring and reporting of production and related 
quantities.
    If concentration measurements were unavailable for some period, we 
propose that the facility be required to report the average of the 
concentration measurements from just before and just after the period 
of missing data.
    There is one proposed exception to these requirements: If the 
facility has reason to believe that either method would result in a 
significant under- or overestimate of the missing parameter, then the 
facility would be required to develop an alternative estimate of the 
parameter and explain why and how it developed that estimate. We would 
have the option of rejecting this alternative estimate and replacing it 
with the value developed using the usual missing data method if we did 
not agree with the rationale or method for the alternative estimate.
    We request comment on these methods for estimating missing data. We 
also request comment on the option of estimating missing production 
data based on consumption of reactants, assuming complete 
stoichiometric conversion. This approach could be used in the very 
unlikely event that neither primary nor secondary direct measures of 
production were available.
b. Imports and Exports
    We do not believe that missing data would be a problem for 
importers and exporters of GHGs due to their requirement to declare the 
quantities of GHGs imported or exported for Customs purposes. However, 
we request comment on this assumption.
5. Selection of Data Reporting Requirements
    Under the proposed rule, facilities would be required to submit 
data, described below, in addition to the production, import, export, 
feedstock, and destruction data listed above. This data is intended to 
permit us to check the main estimates submitted. A complete list of 
data to be reported is included in proposed 40 CFR part 98, subparts A 
and OO.
a. Production
    Facilities producing N2O or fluorinated GHGs would be 
required to submit data on the total mass of reactants fed into the 
production process, the total mass of non-GHG reactants and byproducts 
permanently removed from the process, and the mass of used product 
added back into the production process. Facilities would also be 
required to provide the names and addresses of other facilities to 
which they sent N2O or fluorinated GHGs for transformation 
or destruction. All quantities would be annual totals in metric tons, 
by chemical.
b. Imports/Exports and Destroyers of Fluorinated GHG
    Importers of N2O or fluorinated GHGs would be required 
to submit an annual report that summarized their imports, providing the 
following information for each import: The quantity of GHGs imported by 
chemical, the date on which the GHGs were imported, the port of entry 
through which the GHGs passed, the country from which the imported GHGs 
were imported, and the importer number for the shipment. Importers 
would also be required to provide the names and addresses of any 
persons and facilities to which the imported GHGs were sold or 
transferred for transformation or destruction.
    Exporters of N2O and fluorinated GHGs would be required 
to submit an annual report that summarized their exports, similar to 
the report provided by importers. A complete list of data to be 
reported is included in the proposed rule.

[[Page 16583]]

    These proposed requirements are very similar to those that apply to 
importers and exporters of ODS under EPA's Stratospheric Ozone 
Protection Program. We are proposing them because they would provide us 
with valuable information for verifying the nature and size of GHG 
imports and exports.
    In addition to annually reporting the mass of fluorinated GHG fed 
into the destruction device, facilities destroying fluorinated GHGs 
would be required to submit a one-time report including the following: 
The destruction unit's DE, the methods used to record volume destroyed 
and to measure and record DE, and the names of other relevant Federal 
or State regulations that may apply to destruction process. This one-
time report is very similar to that required under EPA's Stratospheric 
Ozone Protection regulations.
6. Selection of Records That Must Be Retained
    EPA is proposing that the following records be retained because 
they are necessary to verify production, import, export, 
transformation, and destruction estimates and related quantities and 
calibrations.
a. Production
    Owners or operators of facilities producing N2O or 
fluorinated GHGs would be required to keep records of the data used to 
estimate production, as well as records documenting the initial and 
periodic calibration of the flowmeters or scales used to measure 
production.
b. Imports and Exports
    Importers of N2O or fluorinated GHGs would be required 
to keep the following records substantiating each of the imports that 
they report: A copy of the bill of lading for the import, the invoice 
for the import, the U.S. Customs entry form, and dated records 
documenting the sale or transfer of the imported GHG for transformation 
or destruction (if applicable).
    Every person who imported a container with a heel would be required 
to keep records of the amount brought into the U.S. and document that 
the residual amount in each shipment is less than 10 percent of the net 
mass of the container when full and would: Remain in the container and 
be included in a future shipment, be recovered and transformed, or be 
recovered and destroyed.
    Exporters of N2O, or fluorinated GHGs, would be required 
to keep the following records substantiating each of the exports that 
they report: A copy of the bill of lading for the export and the 
invoice for the import.
c. Transformation
    Owners or operators of production facilities using N2O 
or fluorinated GHGs as feedstocks would be required to keep records 
documenting: The initial and annual calibration of the flowmeters or 
scales used to measure the mass of GHG fed into the destruction device 
and the periodic calibration of gas chromatographs used to analyze the 
concentration of N2O fluorinated GHG in the product for 
which the GHG is used as a feedstock.
d. Destruction
    Owners or operators of GHG production facilities that destroy 
fluorinated GHGs would be required to keep records documenting: The 
information that they send in the one-time and annual reports, the 
initial and annual calibration of the flowmeters or scales used to 
measure the mass of GHG fed into the destruction device, the method for 
tracking startups, shutdowns, and malfunctions and any GHG emissions 
during these events, and the periodic calibration of gas chromatographs 
used to annually analyze the concentration of fluorinated GHG in the 
destruction device exhaust stream, as well as the representativeness of 
the conditions under which the measurement took place.

PP. Suppliers of Carbon Dioxide (CO2)

1. Definition of the Source Category
    CO2 is used for a variety of commercial applications, 
including food processing, chemical production, carbonated beverage 
production, refrigeration, and petroleum production for EOR, which 
involves injecting a CO2 stream into injection wells at well 
fields for the purposes of increasing crude oil production. Possible 
suppliers of CO2 include industrial facilities or process 
units that capture a CO2 stream, such as those found at 
electric power plants, natural gas processing plants, cement kilns, 
iron and steel mills, ammonia manufacturing plants, petroleum 
refineries, petrochemical plants, hydrogen production plants, and other 
combustion and industrial process sources. These suppliers can capture 
and/or compress CO2 for delivery to a variety of end users 
as discussed above.
    To ensure consistent treatment of CO2 suppliers and 
given the large percentage of CO2 supplied from 
CO2 production wells, we have also proposed inclusion of 
facilities producing CO2 from CO2 production 
wells in the proposal. Importers and exporters of CO2 are 
discussed under suppliers of industrial GHGs (see Section V.OO of this 
preamble) because most of these facilities import or export multiple 
industrial gases. For a full discussion of this source category, refer 
to the Suppliers of CO2 TSD (EPA-HQ-OAR-2008-0508-044).
    According to the U.S. GHG Inventory in 2006, the total supply of 
CO2 from industrial facilities and CO2 production 
wells was approximately 40.6 million metric tons CO2e. 
Further research in support of this rulemaking identified three 
additional facilities capturing a CO2 stream for sale. Data 
for two of these facilities suggest an additional 0.5 million metric 
tons CO2e captured. Currently, the majority of 
CO2 (79 percent) is produced from CO2 production 
wells. Approximately 18 percent of CO2 is produced at 
natural gas processing facilities and less than 2 percent from ammonia 
production facilities. Less than 1 percent of CO2 is 
captured at other industrial facilities.
    Fugitive Emissions from CO2 Supply. Fugitive CO2 
emissions can occur from the production of CO2 streams from 
CO2 production wells or capture at industrial facilities or 
process units, as well as during transport of the CO2, and 
during or after use of the gas. We propose to exclude the explicit 
reporting of fugitive CO2 emissions from CO2 
supply at industrial facilities or process units and CO2 
production wells, as well as from CO2 pipelines, injection 
wells and storage sites. Much of the CO2 that could 
ultimately be released as a fugitive emission during transportation, 
injection and storage, would be accounted for in the CO2 
supply calculated using the methods below. Although separate 
calculation and reporting of fugitive CO2 emissions are not 
proposed for inclusion, we believe that obtaining robust data on 
fugitive CO2 emissions from the entire carbon capture and 
storage chain would provide a more complete understanding of the 
efficacy of carbon capture and storage technologies as an option for 
mitigating CO2 emissions.
    We seek comment on the decision to exclude the reporting of 
fugitive CO2 emissions from the carbon capture and storage 
chain. We have concluded that there could be merit in requiring the 
reporting of fugitive emissions from geologic sequestration of 
CO2, in particular. This is discussed further below.
    Geologic Sequestration of CO2. CO2 used in most 
industrial applications would eventually be released to the atmosphere. 
For EOR applications, however, some amount of CO2 could 
ultimately remain sequestered in deep

[[Page 16584]]

geologic formations. The objective of EOR operations is not to maximize 
reservoir CO2 retention rates, but to maximize oil 
production and the amount of CO2 trapped underground would 
be a function of site specific and operational factors. There are 
several EOR operations in the Permian Basin of Texas. One study showed 
that retention rates for eight reservoirs ranged from 38 to 100 percent 
with an average of 71 percent, but many of these projects are not 
mature enough to predict final retention (see Suppliers of 
CO2 TSD (EPA-HQ-OAR-2008-0508-044)).
    We are not proposing the inclusion of geologic sequestration in the 
proposed rulemaking. However, the Agency recognizes that there may be 
significant stakeholder interest in reporting the amount of 
CO2 injected and geologically sequestered at EOR operations 
in order to demonstrate the effectiveness of EOR projects that 
ultimately intend to store the CO2 for long periods of time. 
If an EOR project intends to sequester CO2 for long periods 
of time, there would be additional operational factors and post-
operational considerations and monitoring. Although EPA is not 
proposing inclusion of this source in the rulemaking, we have outlined 
initial thoughts about how geologic sequestration might be included in 
a reporting program for EOR sequestration or other types of geologic 
sequestration. We welcome comment on the approach outlined below or 
other suggestions for how to quantify and verify the amount of 
CO2 sequestered in geologic formations.
    We reviewed a number of existing and proposed methodologies for 
monitoring and reporting fugitive emissions from carbon capture, 
transport, injection and storage. A summary of these protocols can be 
found in the Review of Existing Programs memorandum (EPA-HQ-OAR-2008-
0508-054). Based on this review, a possible approach to include 
geologic sequestration might be to ask EOR operators to submit a 
geologic sequestration report. This report could provide information on 
the amount of CO2 sequestered (based on the amount of 
CO2 injected minus any fugitive emissions) along with a 
written description of the activities undertaken to document and verify 
the amount sequestered at each site. This report could include the 
following supporting information:
     The owner and operator of the geologic sequestration 
site(s). Including the business name, address, contact name, and 
telephone number.
     Location of the geologic sequestration site(s) including a 
map showing the modeled aerial extent of the CO2 plume over 
the lifetime of the project.
     Permitting information. Including information on the UIC 
well permit(s) issued by the appropriate State or Federal agency: 
Permit number or other unique identification, date the permit was 
issued and modified if applicable, permitting agency, contact name, and 
telephone number.
     An overview of the site characteristics, referencing or 
providing information which demonstrates sufficient storage capacity 
for the expected operating lifetime of the plant and the presence of an 
effective confining system overlying the injection zone.
     An assessment of the risks of CO2 leakage, or 
escape of CO2 from the subsurface to the atmosphere, 
including an evaluation of potential leakage pathways such as deep 
wells, faults, and fractures.
     An overview of the methods used to model the subsurface 
behavior of CO2 and the results.
     Baseline conditions used to evaluate performance of the 
site including the amount of naturally occurring CO2 
emissions and/or other characteristics that would be used to 
demonstrate the effectiveness of the system to contain CO2.
     Summary of the monitoring plan that would be used to 
determine CO2 emissions from the site including a discussion 
of the methodology, rationale, and frequency of monitoring.
    The information listed above could be submitted one time and then 
updated as appropriate. However, the volume of CO2 injected 
and any emissions from the storage site, including physical leakage 
from the geologic formation (via natural features or wells) and/or 
fugitive emissions of CO2 co-produced with oil/gas, would be 
reported on an annual basis in order to quantify the amount of 
CO2 geologically sequestered.
2. Selection of Reporting Threshold
    EPA has identified at least nine industrial facilities or process 
units in the U.S. that currently capture CO2 (three natural 
gas processing plants, two ammonia facilities, two electricity 
generation facilities, one soda ash production plant, and one coal 
gasification facility) (Table PP-1 of this preamble).

            Table PP-1. Threshold Analysis for CO2 Supply From Industrial Facilities or Process Units
----------------------------------------------------------------------------------------------------------------
                              Total national                      Emissions covered        Facilities covered
 Threshold level metric tons     emissions     Total number  ---------------------------------------------------
            CO2e               (metric tons       of U.S.     Metric tons
                                   CO2e)        facilities      CO2e/yr      Percent       Number      Percent
----------------------------------------------------------------------------------------------------------------
1,000.......................       8,184,875               9    8,186,881          100            9          100
10,000......................       8,184,875               9    8,186,881          100            9          100
25,000......................       8,184,875               9    8,186,881          100            9          100
100,000.....................       8,184,875               9    8,036,472           98            5           56
----------------------------------------------------------------------------------------------------------------

    Under the proposed rule, all industrial facilities that capture and 
transfer a CO2 stream would be required to report the mass 
of CO2 captured and/or transferred. All known existing 
facilities exceed all but the highest reporting threshold of 100,000 
metric tons CO2e, taking into account solely the mass of 
CO2 captured. At the 25,000 metric tons CO2e 
threshold considered by other subparts of this rule, all industrial 
facilities and capture sites exceed the threshold. The analysis did not 
account for stationary combustion at each facility. We concluded that 
all facilities capturing CO2 would likely already exceed the 
reporting thresholds under other subparts of proposed 40 CFR part 98 
for their downstream emissions. Therefore, a proposed threshold of 
``All In'' for reporting CO2 supply from industrial 
facilities or process units would not bring in additional facilities 
not already triggering other subparts of the proposed rule.
    Based on the volumes of CO2 supplied by facilities 
producing a CO2 stream from CO2 production wells, 
we also propose that they be subject to reporting. Currently there are 
four natural formations--Jackson Dome, Bravo Dome, Sheep Mountain, and 
McElmo Dome. Data are not available to estimate emissions from 
individual owners or operators operating within

[[Page 16585]]

the Domes, therefore emissions data are presented at the Dome level 
(Table PP-2 of this preamble). We propose that all CO2 
production wells owned by a single owner or operator in a given Dome 
report the mass of CO2 extracted and/or transferred off 
site. We are seeking comment on alternative methods for defining the 
reporting facility (e.g., reporting at the level of an individual 
well).

                                           Table PP-2. Threshold Analysis for CO2 Supply CO2 Production Wells
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                   Total national                       Emissions covered          Facilities covered
                                                                      emissions     Total number  ------------------------------------------------------
                 Threshold level metric tons CO2e                   (metric tons       of U.S.       Metric tons
                                                                        CO2e)       facilities *       CO2e/yr       Percent       Number      Percent
--------------------------------------------------------------------------------------------------------------------------------------------------------
1,000............................................................      31,358,853               4      31,358,853          100            4          100
10,000...........................................................      31,358,853               4      31,358,853          100            4          100
25,000...........................................................      31,358,853               4      31,358,853          100            4          100
100,000..........................................................      31,358,853               4      31,358,853          100            4          100
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Under this proposal, owners or operator would be required to report on all CO2 production wells under their ownership/operation in a single Dome.

    We have concluded that reporting the volume of the CO2 
streams from CO2 production wells is important given the 
large fraction of CO2 supplied from CO2 
production wells. Further, we conclude that there is minimal burden 
associated with these requirements, as all necessary monitoring 
equipment should already be installed to support current operating 
practice.
    Importers and exporters of CO2 in bulk should review the 
threshold language for industrial GHG suppliers found in Section OO of 
this preamble, which proposes a threshold of 25,000 metric tons 
CO2e, for applicability. We decided to have a single 
threshold applicable for bulk importers and exporters of all industrial 
gases, because many are importing and/or exporting multiple industrial 
gases. We decided not to include CO2 imported or exported in 
products (e.g., fire extinguishers), because of the potentially large 
number of sources.
    For additional information on the threshold analysis please refer 
to the Suppliers of CO2 TSD (EPA-HQ-OAR-2008-0508-044). For 
specific information on costs, including unamortized first year capital 
expenditures, please refer to section 4 of the RIA and the RIA cost 
appendix.
3. Selection of Proposed Monitoring Methods
    The monitoring plan for CO2 suppliers at industrial 
facilities or process units, CO2 production wells, and 
CO2 importers and exporters involves accounting for the 
total volume of the CO2 stream captured, extracted, imported 
and exported. We propose that if CO2 suppliers already have 
the flow meter installed to directly measure the CO2 stream 
at the point of capture, extraction, import and/or export, that 
facilities use the existing flow meter to measure CO2 
supply. We propose that facilities sample the composition of the gas on 
at least a quarterly basis to determine CO2 composition of 
the CO2 stream. If the necessary flow meters are not 
currently installed, CO2 suppliers would use mass flow 
meters to measure the volume of the CO2 stream transferred 
offsite.
    We propose to require reporting on the volume of the CO2 
stream at the point of capture, extraction, import and export because 
this would provide information on the total quantity of CO2 
available for sale. Measuring at this initial point could provide 
additional information in the future on fugitive CO2 
emissions from onsite purification, processing, and compression of the 
gas. However, if the necessary flow meters are not currently in place, 
facilities may conduct measurements at the point of CO2 
transfer offsite.
    We conclude that there is minimal incremental burden associated 
with this approach for CO2 suppliers at industrial 
facilities or process units, CO2 production wells, importers 
and exporters because these sites likely already have the necessary 
flow meters installed to monitor the CO2 stream. In 
addition, facilities need to know CO2 composition of the gas 
in order to ensure the gas meets appropriate specifications (e.g., food 
grade CO2).
    We also considered requiring CO2 suppliers to report 
only on CO2 sales, without determining the actual 
CO2 composition of the gas sold. This is a relatively simple 
method, however, facilities already routinely measure the composition 
of the gas, providing greater certainty in the potential emissions 
data.
    The methods proposed are generally consistent with existing GHG 
reporting protocols. Although existing protocols focus on accounting 
for fugitive emissions, and not quantity of CO2 supplied, 
direct measurement is commonly the recommended approach for measuring 
fugitive emissions. We concluded that while direct measurement of 
fugitive emissions may not be common practice, and is therefore not 
proposed, measurement of CO2 transfer is.
4. Selection of Procedures for Estimating Missing Data
    Facilities with missing monitoring data on the volume of the 
CO2 stream captured, extracted, imported, and exported 
should use the greater of the volume of the CO2 stream 
transferred offsite or the quarterly or average value for the parameter 
from the past calendar year. The owners or operators of facilities 
monitoring emissions at the point of transfer offsite, that have 
missing monitoring data on the CO2 stream transferred, may 
use the quarterly or average value for the parameter from the past 
calendar year.
    Facilities with missing data on the composition of the 
CO2 stream captured, extracted, imported, and exported 
should use the quarterly or average value for the parameter from the 
past calendar year.
5. Selection of Data Reporting Requirements
    For CO2 supply, the proposed monitoring method is based 
on direct measurement of the gaseous and liquid CO2 streams. 
All CO2 suppliers would report, on an annual basis, the 
measured volume of the CO2 stream that is captured, 
extracted, imported and exported if the proper flow meter is installed 
to carry out these measurements. Facilities monitoring emissions at the 
point of transfer offsite would report the annual volume of the 
CO2 stream transferred. All suppliers also would report, on 
an annual basis, the CO2 composition of the gas sold. The 
end-use application of the supplied CO2 (e.g., EOR, food 
processing) should also be reported, if known.

[[Page 16586]]

    EPA proposes to collect data on the measured volume of the 
CO2 stream captured, extracted, imported and exported, as 
well as gas composition because these form the basis of the GHG 
calculations and are needed for EPA to understand the emissions data 
and verify reasonableness of the reported emissions. EPA also proposes 
to collect information on the end use of the transferred 
CO2, if known, because CO2 can be used in 
emissive or non-emissive applications. Collecting data on the ultimate 
fate of the CO2 stream can provide information on the 
potential emissions of CO2 released to the atmosphere.
6. Selection of Records That Must Be Retained
    Owners or operators of all CO2 suppliers would be 
required to retain onsite all quarterly measurements for the volume of 
the CO2 stream captured, extracted, imported and exported, 
and CO2 composition. Where measurements are based on 
CO2 transferred offsite, these quarterly measurements would 
be retained, along with CO2 composition.

QQ. Mobile Sources

1. Definition of the Source Category
    This section of the preamble describes proposed GHG reporting 
requirements for manufacturers of new mobile sources, including motor 
vehicles and engines, nonroad vehicles and engines, and aircraft 
engines.\118\ It also seeks comment on the need to collect additional 
in-use travel activity and other emissions-related data from States and 
local governments and mobile source fleet operators. These proposed 
requirements and the requests for comments are based on EPA's authority 
under CAA Sections 114 and 208.
---------------------------------------------------------------------------

    \118\ The terms ``manufacturers'' and ``manufacturing 
companies'', as used in this section, mean companies that are 
subject to EPA emissions certification requirements. This primarily 
includes companies that manufacture vehicles and engines 
domestically and foreign manufacturers that import vehicles and 
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 vehicles or 
engines.
---------------------------------------------------------------------------

    Not discussed in this portion of the preamble are proposed GHG 
reporting requirements related to transportation fuels (see Section 
V.MM of this preamble, Suppliers of Petroleum Products) and motor 
vehicle and engine manufacturing facilities (see Section V.C of this 
preamble, General Stationary Fuel Combustion Sources).
    Total Emissions. For the U.S. transportation sector, the 2008 U.S. 
Inventory includes GHGs from the operation of passenger and freight 
vehicles within U.S. boundaries, natural gas used to power domestic 
pipelines, lubricants associated with mobile sources, and international 
bunker fuels purchased in the U.S. for travel outside U.S. boundaries. 
GHG emissions from these sources in 2006 totaled 2102.6 Tg 
CO2e, representing 29.3 percent of total U.S. GHG emissions. 
Just under 79 percent of these emissions came from on-road sources, 
including passenger cars and light-duty trucks (58.8 percent), medium- 
and heavy-duty trucks (19.2 percent), buses (0.6 percent) and 
motorcycles (0.1 percent). Aircraft (including domestic military 
flights) accounted for 11.6 percent of transportation GHGs, ships and 
boats 5 percent, rail 2.8 percent, pipelines 1.5 percent, and 
lubricants 0.5 percent. These estimates primarily reflect GHGs 
resulting from the combustion of fuel to power U.S. transportation 
sources. These estimates do not include emissions from the operation of 
other non-transportation mobile equipment and recreational vehicles, 
which collectively accounted for over 2 percent of total U.S. GHG 
emissions.
    GHGs produced by transportation sources include CO2, 
N2O and CH4, which result primarily from the 
combustion of fuel to power these sources or from treatment of the 
exhaust gases, and HFCs, which are released through the operation, 
servicing and retirement of vehicle A/C systems. CO2 is the 
predominant GHG from these sources, representing 95 percent of 
transportation GHG emissions (weighted by the GWP of each gas). HFCs 
account for 3.3 percent, N2O for 1.6 percent, and 
CH4 for 0.1 percent of transportation GHG emissions. EPA is 
proposing reporting requirements for each of these gases, where 
appropriate.
2. Selection of Proposed GHG Measurement, Reporting, and Recordkeeping 
Requirements
    For the new vehicle and engine manufacturer reporting requirements 
proposed in this Notice, EPA intends to build on our long-established 
programs that control vehicle and engine emissions of criteria 
pollutants including hydrocarbons, NOX, CO, and PM. These 
programs, which include emissions standards, testing procedures, and 
emissions certification and compliance requirements, are based on 
emission rates over prescribed test cycles (e.g., grams of pollutant 
per mile or grams per kilowatt-hour). Thus, we propose having 
manufacturers also report GHG emissions in terms of emission rates for 
this reporting program. It is important to note that this approach is 
somewhat different from the direct reporting of tons per year of 
emissions that is appropriate for the non-mobile source categories 
addressed elsewhere in this preamble. However, EPA would be able to use 
the GHG emission rate data from manufacturers with our existing models 
and other information to project tons of GHG emissions for the various 
mobile source categories.
    Although the new reporting requirements proposed here focus on 
emission rates from new vehicles and engines, EPA also is very 
interested in continually updating and improving our understanding of 
the in-use activity and total emissions from mobile sources. Thus, we 
are seeking comment on the need to collect in-use travel activity and 
other emissions-related data from States and local governments and 
mobile source fleet operators. Section V.QQ.4 of this preamble 
describes the existing State and local government and fleet operator 
data that EPA currently collects and requests public comment on the 
need for, and substance of, additional reporting requirements.
3. Mobile Source Vehicle and Engine Manufacturers
a. Overview
    As mentioned above, EPA is proposing GHG reporting requirements 
that fit within the reporting framework established for EPA's long-
established criteria pollutant emissions control programs and vehicle 
fuel economy testing program. While the details of the programs vary 
widely among the vehicle and engine categories, EPA generally requires 
manufacturers to conduct emissions testing and report the resulting 
emissions data to EPA for approval on an annual basis prior to the 
introduction of the vehicles or engines into commerce. As a part of 
this process, since the early 1970s, EPA has collected criteria 
pollutant emissions data for all categories of vehicles and engines 
used in the transportation sector, including engines used in nonroad 
equipment (see Table QQ-1 of this preamble).

         Table QQ-1. Mobile Source Vehicle and Engine Categories
------------------------------------------------------------------------
                                Category
-------------------------------------------------------------------------
Light-duty vehicles
Highway heavy-duty vehicles (chassis-certified)
Highway heavy-duty engines
Highway motorcycles
Nonroad diesel engines
Marine diesel engines
Locomotive engines
Nonroad small spark ignition engines

[[Page 16587]]

 
Nonroad large spark ignition engines
Marine spark ignition engines/personal watercraft
Snowmobiles
Off-highway motorcycles and all terrain vehicles
Aircraft engines
------------------------------------------------------------------------

    For purposes of EPA certification, manufacturers typically group 
vehicles/engines with similar characteristics into families and perform 
emission tests on representative or worst-case vehicles/engines from 
each family. Integral to EPA's existing certification procedures are 
well-established methods for assuring the completeness and quality of 
reported emission test data. We are proposing to require manufacturers 
to measure and report GHG emissions data as part of these current 
emissions testing and certification procedures. These procedures, 
appropriate here because of the long-standing history and structure of 
mobile source control programs, are necessarily different from the 
monitoring-based methods proposed for other sources elsewhere in this 
notice.
    After a discussion of the proposed small business threshold, the 
following subsections describe the proposed GHG emissions measurement 
and reporting requirements for manufacturers. As discussed in those 
subsections, some manufacturers already measure and report some GHG 
emissions, some measure but do not have to report GHG emissions, and 
others would need to measure and report for the first time. We propose 
that the new measurement and reporting requirements apply beginning 
with the 2011 model year, although we encourage voluntary measurement 
and reporting for model year 2010.
b. Selection of a Reporting Threshold
    In most of EPA's recent mobile source regulatory programs for 
criteria pollutants, EPA has applied special provisions to small 
manufacturers. EPA proposes to exempt small manufacturers from the GHG 
reporting requirements. We define ``small business'' or ``small volume 
manufacturer'' separately for each mobile source category. These 
definitions were established in the regulations during the rulemaking 
process for each category, which included consultation with small 
entities and with the Small Business Administration. We're proposing to 
use these same definitions in each case for the reporting requirements 
exemption. We believe that this exemption would avoid the relatively 
high per-vehicle or per-engine reporting costs for small manufacturers 
without detracting from the goals of the reporting program, as 
discussed below.
    It is important to note that this ``threshold'' would differ from 
the approach proposed for other source categories discussed in Section 
V of this preamble. That is, EPA would not have manufacturers determine 
their eligibility based on total tons emitted per year. As discussed 
above, EPA's current mobile source criteria pollutant control programs 
are based on emissions rates over prescribed test cycles rather than 
tons per year estimates. Since we are proposing to build on our 
existing system, we believe that a threshold based on manufacturer size 
is appropriate for the mobile source sector. Although the emission 
rates of some vehicles and engines would not be reported, we do not 
believe this is a concern because the technologies--and thus emission 
rates--from larger manufacturers represent the same basic technologies 
and emission rates of essentially all vehicles and engines. It is also 
worth noting that the manufacturers that meet the small manufacturer 
definitions represent a very small fraction of overall vehicle and 
engine sales. For nine out of the twelve non-aircraft mobile source 
categories (there are currently no small aircraft engine 
manufacturers), we estimate that sales from small manufacturers 
represent less than 10 percent of overall sales (for eight of these 
categories, including light-duty vehicles, small manufacturers account 
for less than 3 percent of sales). For the remaining three categories 
(highway motorcycles, all terrain vehicles/off-road motorcycles, and 
small spark ignition engines) we estimate that small entities account 
for less than 32 percent of sales.
    Please see the discussion of our compliance with the RFA in Section 
IX.C of this preamble. We request comments on our proposed approach for 
the reporting threshold for mobile source categories.
c. Light-Duty Vehicles
    We propose that manufacturers of passenger cars, light trucks, and 
medium-duty passenger vehicles measure and report emissions of 
CO2 (including A/C-related CO2), CH4, 
N2O, and refrigerant leakage.\119\ Existing criteria 
pollutant emissions certification regulations, as well as fuel economy 
testing regulations, already require manufacturers to measure and 
report CO2 for essentially all of their vehicle testing. 
Requiring manufacturers to also measure and report the other GHGs 
emitted by these vehicles, as proposed in this Notice and discussed 
below, would introduce a modest but reasonable additional testing and 
reporting burden.
---------------------------------------------------------------------------

    \119\ See 40 CFR 1803-01 for full definitions of ``light-duty 
vehicle''.
---------------------------------------------------------------------------

    For CH4 and N2O, we propose that 
manufacturers begin to measure these emissions as a part of existing 
emissions certification and fuel economy test procedures (FTP, SFTP, 
HFET, et al.), if they are not already doing so, and then to report 
those emissions in the same cycle-weighted format that they report 
other emission results under the current certification requirements. 
Because such testing has not generally been required, some 
manufacturers would need to install additional exhaust analysis 
equipment for the measurement of CH4 and/or N2O. 
In most cases, both of these types of new analyzers could be added as 
modular units to existing test equipment.
    In the case of N2O, since this pollutant has not 
previously been included in the certification testing process, it is 
necessary to introduce a new analytical procedure for the measurement 
of N2O over the FTP. This is not the case for 
CH4, however, since an analytical procedure for 
CH4 testing already exists. We propose that manufacturers 
use an N2O procedure found in the regulatory language 
associated with this notice that would be based largely on the 
procedures currently used to measure CO2 and CO, using 
nondispersive infrared measurement technology. In addition, EPA is 
proposing a ``scrubbing'' stage as a part of this procedure that would 
remove sulfur compounds that can contribute to N2O formation 
in the sample bag. (See proposed 40 CFR 1065.257 and 1065.357 for the 
proposed N2O measurement procedures.) EPA requests comments 
on all aspects of the proposed N2O measurement procedure, 
including potential alternate methods with equal or better analytical 
performance.
    Measuring and Reporting A/C-Related CO2. Manufacturers of light-
duty vehicles, unlike manufacturers of heavy-duty and nonroad engines, 
sell their products as complete engine-plus-vehicle combinations that 
include the vehicles' A/C systems. Thus, we believe it is appropriate 
that these manufacturers report A/C-related emissions as a part of 
their existing vehicle certification requirements. EPA does not 
currently require these manufacturers to measure or report the A/C-
related CO2 emissions (or the

[[Page 16588]]

leakage of refrigerants, as discussed below) under current regulations. 
We propose that these manufacturers begin to measure A/C-related 
CO2 emissions (i.e., the indirect CO2 emissions 
resulting from the additional load placed on the engine by an operating 
A/C system), using a proposed new test cycle, which is described below. 
This testing would not require new equipment, and the proposed test 
cycle is similar to one that exists in many State Inspection & 
Maintenance (I/M) programs.
    The current FTP for light-duty vehicles is performed with the A/C 
turned on only during the SC03, or ``air conditioning,'' test 
procedure. This test is used to verify emissions compliance in a 
``worst-case'' situation when the A/C system is operating under 
relatively extreme conditions. The SC03 is also used in the 5-cycle 
fuel economy calculation for fuel economy labeling. Thus, although the 
SC03 test results in a value for CO2 emissions (in grams per 
mile), the incremental increase of CO2 resulting from 
operation of the A/C system, especially in a more typical situation, is 
not quantified.
    In order to provide for consistent, accurate measurement of A/C-
related CO2 emissions, EPA proposes to introduce a 
specifically-designed test procedure for A/C-related CO2 
emissions. Manufacturers would run this proposed test, the A/C 
CO2 Idle Test, with the engine idling, upon completion of an 
emissions certification test--such as the FTP, highway fuel economy, or 
US06 test. The proposed A/C CO2 Idle Test is similar to the 
``Idle CO'' test, which was once a part of vehicle certification, and 
is still used in State I/M programs (see 40 CFR part 51, subpart S, 
Appendix B).
    Within each vehicle model type, various configurations of engine 
and cooling system options can be expected to have somewhat different 
A/C-related CO2 performance.\120\ However, we believe that 
vehicles sharing certain technical characteristics would generally have 
similar A/C-related CO2 emissions. Specifically, vehicles 
with the same engine, A/C system design, and interior volume would be 
expected in most cases to have similar A/C-related CO2 
performance. In order to minimize the number of new tests that 
manufacturers would be required to perform, EPA is proposing that 
manufacturers be allowed to select a subset of vehicles for A/C 
CO2 Idle Testing, each of which would represent the 
performance of a larger group of vehicles with common A/C-related 
technical characteristics. We believe that in most cases the vehicles 
that manufacturers currently test for fuel economy purposes (as 
described in 40 CFR 600.208(a)(2)) would generally also capture the key 
engine-A/C system-vehicle configurations that may exist within a given 
model type. The complete set of our proposed criteria for manufacturers 
to meet in selecting the representative vehicles for the A/C 
CO2 Idle Test is found in the regulatory language in the 
proposed rule (see proposed 40 CFR 86.1843-01, ``Air conditioning 
system commonality'').
---------------------------------------------------------------------------

    \120\ In the existing regulations covering vehicle emissions 
certification, under `Definitions' in 40 CFR 600.002-85(a)(15), 
``model type'' means a unique combination of car line, basic engine, 
and transmission class.
---------------------------------------------------------------------------

    The A/C CO2 Idle Test would compare the additional 
CO2 generated at idle with the A/C system in operation to 
the CO2 generated at idle with the A/C system off. 
Manufacturers would run the test with the vehicle's A/C system 
operating under complete control of the climate control system and for 
a sufficient length of time to stabilize the cabin conditions and 
tailpipe emission levels. EPA believes that this test would account for 
the CO2 contributions from most of the key A/C system 
components and modes of operation.
    The additional CO2 generated when the A/C is operated 
during the Idle Test would then be normalized to account for the 
interior cabin volume of the vehicle. This normalization is necessary 
because the size and capacity of an A/C system is related to the volume 
of air that an A/C system must cool. Rather than simply reporting the 
vehicle's CO2 emissions, this normalization would provide a 
more appropriate metric of CO2 emissions to compare systems 
that must cool relatively larger volumes with those that cool smaller 
volumes. EPA proposes that the interior cabin volume be defined as the 
volume of air that the air conditioner cools, which includes the volume 
of space used by passengers and, in some vehicles, the volume used for 
cargo. The proposed calculation of interior cabin volume is adapted 
from an industry protocol, Society of Automotive Engineers (SAE) 
Surface Vehicle Standard J1100.
    The proposed A/C CO2 Idle Test would require three 
approximately 10-minute periods of CO2 emissions measurement 
once the vehicle's cabin conditions and climate control system have 
stabilized in order to quantify the A/C related CO2. The 
test would be run at 75 [deg]F, the standard temperature of the FTP. As 
discussed below, EPA considered proposing a more complex procedure that 
would be performed at a higher temperature, such as the 95 [deg]F used 
in the SC03 test. However, we believe that A/C-related CO2 
can be accurately demonstrated on the Idle Test at 75 [deg]F, avoiding 
the significant facility and testing issues associated with higher 
temperature testing. In order to better simulate ``real world'' idling 
conditions, we propose that the A/C CO2 Idle Test be 
performed with the engine compartment hood and windows closed and 
without operating the test site cooling fan that is usually used to 
simulate the motion of the vehicle on the road.
    The proposed A/C CO2 Idle Test procedure specifies how 
climate control systems, whether manual or automatic, would need to be 
set to appropriately simulate the maximum and minimum cooling demands 
on the A/C system. CO2 exhaust emission measurements, in 
grams per minute, would be taken during both of these modes. 
Manufacturers would conduct the idle test following the completion of a 
FTP certification test, a fuel economy test, or a test over the US06 
cycle. As discussed above, manufacturers would measure the change in 
CO2 due to A/C operation in grams per minute and then would 
divide this value by the interior volume in cubic feet, for an A/C 
CO2 emission value in terms of grams per minute per cubic 
foot. The manufacturer would report this value to EPA with other 
emission results.
    EPA also requests comment on three different approaches that could 
be used alone or in combination with the proposed A/C CO2 
Idle Test or with each other. Each of these tests would capture a 
somewhat different set of aspects of A/C-related CO2 
emissions. First, EPA is seeking comment on basing reporting 
requirements on the SC03 test (or some variant of this test), which, as 
described above, is designed to simulate more extreme driving 
conditions than the standard certification tests. Using the SC03 test 
to determine A/C-related CO2 performance would likely 
require manufacturers to run tests in additional modes or to repeat the 
test in order to capture more real-world A/C usage (i.e., a stabilized 
cabin temperature). Therefore such an approach could involve 
significant modifications to the SC03 test procedure. The rationale for 
considering such an adapted SC03 test would be to characterize more 
systemic technological features (such as thermal management and 
transient A/C control) that may not be captured in a 75 [deg]F idle 
test or a bench test (as discussed below).
    Second, EPA is seeking comment on basing reporting requirements on 
a ``bench'' test procedure similar to the one being developed by the 
SAE and the University of Illinois, which was employed to measure A/C 
efficiency

[[Page 16589]]

improvements for the industry/government Improved Mobile Air 
Conditioning project. This bench test only measures the power 
consumption of the A/C compressor with simulated loads, and is not 
integrated into a vehicle (as would be the case in the proposed A/C 
CO2 Idle Test, which is a ``chassis,'' or whole-vehicle, 
test). The purpose of the bench test for characterizing A/C-related 
CO2 emissions would be to have a relatively repeatable test 
that could represent a variety of temperature and humidity conditions 
around the country. Unlike a chassis test, there would not be a direct 
connection to a vehicle's interior volume, and we would need to develop 
assumptions about a vehicle's interior volume in order to normalize the 
results. This test procedure might be less expensive than a modified 
SC03 test.
    Finally, EPA is seeking comment on basing reporting requirements on 
design-based criteria for characterizing A/C-related CO2 
emissions. Design-based criteria would be conceptually similar to the 
ones proposed for leakage emissions characterization as described 
below. A manufacturer would choose technologies from a list provided by 
EPA in the rule where we would specify the A/C-related CO2 
characteristics associated with each major component and technology, 
including system control strategy and systems integration. While such a 
design-based approach might capture the expected CO2 
emissions of individual components and controls, it would not 
necessarily capture overall system A/C-related CO2 (when the 
A/C components would be integrated into the vehicle and would interact 
with the engine, cabin conditions, and other vehicle characteristics, 
such as the under-hood environment).
    Calculating and Reporting a ``Score'' for A/C-Related Refrigerant 
Leakage. As part of most of EPA's existing mobile source emissions 
testing and certification programs, where robust test procedures have 
been developed and are in widespread use, EPA has relied on 
``performance-based'' approaches, where emissions are measured directly 
during vehicle or engine operation to determine emission levels. 
Examples of performance-based test procedures include the FTP and the 
proposed A/C CO2 Idle Test discussed above. In the case of 
A/C refrigerant leakage, where it is known that leakage of refrigerants 
with high GWPs occurs, a reliable, performance-based test procedure to 
measure such emissions from a vehicle does not yet exist. Instead, we 
are proposing a ``design-based'' approach to establish a vehicle's 
expected refrigerant leakage emissions.
    Under our proposal, each key A/C-related component and system would 
be assigned an expected rate of refrigerant leakage, in the form of a 
leakage ``score,'' in terms of grams per year. These individual scores 
would be added to result in an overall leakage score for the vehicle. 
We propose that manufacturers establish an overall leakage score for 
the same test vehicle(s) on which they run the A/C CO2 Idle 
Test, as described above.
    The cooperative industry and government Improved Mobile Air 
Conditioning Program referenced above also has developed a 
comprehensive set of leakage scores that EPA proposes to use to 
represent the significant sources of A/C refrigerant leakage from newer 
vehicles. The Improved Mobile Air Conditioning Program and the SAE have 
established a template for calculating individual leakage scores based 
on the quantity and type of components, fittings, seals, and hoses 
utilized in a specific A/C system design; this template is known as the 
SAE Surface Vehicle Standard J2727. EPA is proposing a set of component 
and system leakage scores, based closely on J2727, but expanded to 
place greater emphasis on characterizing leakage emissions later in the 
vehicle's life. Like the J2727, this proposed EPA protocol would 
associate each technology or system design approach with a specific 
leakage score. Each score would be a design-based, ``leakage-
equivalent'' value that would take into account expected early-in-life 
refrigerant leakage from the specified components and systems. 
Manufacturers would report this value to EPA on their application for 
certification.
    In addition, we request comment on the whether other A/C design 
considerations, such as use of alternative refrigerants, monitoring 
refrigerant leakage (with fault storage and indicators), and minimizing 
refrigerant quantity, should be used in determining an A/C leakage 
score.
d. Highway Heavy-Duty Diesel and Gasoline Vehicles and Engines
    EPA's highway heavy-duty vehicle and engine emissions testing and 
certification programs generally cover vehicles above 8,500 pounds 
Gross Vehicle Weight Rating.\121\ For most large trucks, manufacturers 
are required to measure and report criteria air pollutant emissions 
data for engines rather than vehicles. Engine manufacturers measure and 
report emissions prior to the engines being sold to separate companies 
that build trucks or buses and install engines in them. Manufacturers 
of gasoline-fueled complete vehicles below 14,000 pounds Gross Vehicle 
Weight Rating, such as large pick-ups and SUVs, are required to measure 
and report vehicle emissions, as do manufacturers of light-duty 
vehicles. These vehicles are described as ``complete'' vehicles because 
the vehicles leave the primary manufacturing facility fully assembled, 
with the engine and associated hardware installed and the load-carrying 
container attached.
---------------------------------------------------------------------------

    \121\ See 40 CFR 1803-01 for full definitions of ``heavy-duty 
vehicle'' and ``heavy-duty engine.''
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    Manufacturers That Certify Engines. EPA proposes to require 
manufacturers to report CO2 emissions from highway heavy-
duty diesel and gasoline engines. All manufacturers currently measure 
CO2 as an integral part of calculating emissions of criteria 
pollutants, and some report CO2 emissions in some form. We 
propose that engine manufacturers report CO2 to EPA with 
criteria pollutant emission results and, as with the criteria 
emissions, report the CO2 emissions in terms of brake-
specific emissions (i.e., in units of grams of CO2 per 
brake-horsepower-hour).
    We also propose that highway heavy-duty engine manufacturers 
measure and report CH4 emissions. This would require most 
manufacturers to install CH4 exhaust analytical equipment or 
to arrange for testing at another facility. This equipment is usually 
designed to be installed as a modular addition to existing analytical 
equipment. Procedures for analyzing CH4 are currently in 
place.
    Finally, we also propose that these manufacturers measure and 
report N2O. As with CH4, this would require most 
manufacturers to install new, usually modular, N2O exhaust 
analytical equipment, or to arrange for testing at another facility. 
Because it has not been necessary in the past to measure 
N2O, we are proposing a new procedure for measuring 
N2O (see proposed 40 CFR 1065.257 and 1065.357).
    As with CO2, manufacturers would measure both 
CH4 and N2O as a part of the existing FTP for 
heavy-duty engines and report the results to EPA with other criteria 
pollutant emission test results.
    Manufacturers That Certify Complete Highway Heavy-Duty Vehicles. We 
propose that manufacturers certifying complete heavy-duty vehicles be 
subject to the same measurement and reporting requirements as 
manufacturers of heavy-duty engines. Thus, as described above, these 
manufacturers would report the CO2 emissions they are 
currently measuring as part of criteria air

[[Page 16590]]

pollutant emissions testing and would additionally measure and report 
CH4 and N2O. Although vehicle emissions testing 
(also known as ``chassis testing'') is different than engine-only 
testing, measurement procedures are the same, and we are proposing 
measurement and reporting requirements for complete heavy-duty vehicles 
that are essentially identical to our proposed requirements for heavy-
duty engines.
    However, manufacturers of complete heavy-duty vehicles, unlike 
heavy-duty engine manufacturers, are generally responsible for 
installing the vehicle's A/C equipment. For this reason, we propose 
that these manufacturers be responsible for reporting A/C-related 
emissions, in exactly the same ways that we are proposing for light-
duty manufacturers, as described in Section V.QQ.3.c of this preamble. 
Thus, we propose that these manufacturers perform the A/C 
CO2 Idle Test and report the A/C-related CO2 
emissions. We also request comment on the potential applicability of 
the alternate A/C CO2 measurement procedures discussed above 
to manufacturers of complete heavy-duty vehicles. In addition, we 
propose that these manufacturers calculate and report an overall A/C 
refrigerant leakage ``score,'' using the same assigned component and 
system scores we have developed for the proposed light-duty scoring 
system.
    Vehicle Manufacturers That Install Certified Engines. We are not 
proposing any requirements for the heavy-duty truck and bus 
manufacturers that install certified engines into their vehicles. These 
truck manufacturers currently are not required to certify their trucks 
to EPA emissions standards and do not conduct emissions testing. 
However, we recognize that these vehicles are generally equipped with 
A/C systems by the truck or bus manufacturer. We request comment on the 
appropriateness, feasibility, and cost of extending some form of the 
proposed A/C CO2 Idle Test and refrigerant leakage score 
requirements discussed above for manufacturers of complete heavy-duty 
trucks to these truck and bus manufacturers as well. In addition, we 
request comment on how original-equipment or aftermarket auxiliary 
power units--if used to provide power for cabin A/C--might be 
incorporated into a GHG reporting program.
e. Nonroad Diesel Engines and Nonroad Large Spark-Ignition Engines
    Nonroad diesel engines and nonroad large spark-ignition (generally 
gasoline-fueled) engines are used in a wide variety of construction, 
agricultural, and industrial equipment applications. However, these 
engines are very similar (in terms of design, technology, and 
certification process) to their counterparts certified for highway 
operation. Given these similarities, we propose that manufacturers of 
these engines measure and report CO2, CH4, and 
N2O in the same manner as manufacturers of highway heavy-
duty diesel and gasoline engines, as described earlier in this section 
of the preamble.
    Like highway heavy-duty truck and bus manufacturers that use 
certified engines, nonroad diesel equipment manufacturers install 
certified engines into their equipment but do not certify their 
equipment. As with trucks and buses, this equipment is often equipped 
with A/C systems. While we are not proposing any reporting requirements 
for nonroad equipment manufacturers, we request comment on the 
appropriateness, feasibility, and cost of extending some form of the 
proposed A/C CO2 Idle Test and refrigerant leakage score 
reporting requirements discussed above to nonroad equipment 
manufacturers. We also request comment on extending A/C-related GHG 
reporting requirements to transportation refrigeration units that are 
equipped with separate engines that are certified under EPA's nonroad 
engine program.
f. Nonroad Small Spark-Ignition Engines, Marine Spark-Ignition Engines, 
Personal Watercraft, Highway Motorcycles, and Recreational Engines and 
Vehicles
    There is a large range of spark-ignition engines in this category 
including engines used in portable power equipment, snowmobiles, all 
terrain vehicles, off-highway motorcycles, automotive-based, inboard 
engines used in marine vessels. For purposes of this proposed reporting 
rule, we also include highway motorcycles, which are tested as complete 
vehicles. We are proposing that manufacturers measure and report 
CO2, CH4, and N2O emissions for these 
engines and vehicles. As part of existing criteria pollutant emissions 
testing requirements, manufacturers must determine the amount of fuel 
consumed either through direct measurement or through chemical balances 
of the fuel, intake air, and exhaust. With the ``chemical balance'' 
approach, CO2 levels in the intake air and exhaust are 
measured (along with either the intake air flow rate or exhaust flow 
rate), and fuel consumption is calculated based on fuel properties and 
the change in CO2 level between the intake and exhaust 
flows. (CO2 levels with associated flow rates can be used to 
calculate a CO2 emission rates). Alternatively, when a 
``direct measurement'' approach is used to determine fuel consumption, 
there is no need to measure CO2 levels in the intake air or 
exhaust. For manufacturers that generally use only the direct 
measurement approach, new analysis equipment might be required to 
measure CO2 levels in the intake air and exhaust. We propose 
that manufacturers measure and report cycle-weighted CO2 
emissions (in the same ``grams-per-unit-of-work'' format used for 
criteria pollutant emissions reporting) for all engines in these 
categories, regardless of the method used to determine fuel 
consumption. We also propose that highway motorcycle manufacturers 
measure and report CO2 in terms of grams per mile.
    For CH4, many of the engines described above are subject 
to ``total'' hydrocarbon, or ``hydrocarbon + NOX '' 
standards (as opposed to ``non-CH4'' hydrocarbon standards 
applying to some other categories), and thus CH4 emissions 
may not typically be measured. In these cases, the manufacturers would 
need to install CH4 emissions analysis equipment. We propose 
that manufacturers report cycle-weighted CH4 emissions for 
these engines and for highway motorcycles.
    Finally, we are proposing that manufacturers also report the cycle-
weighted N2O emissions for these engines and for highway 
motorcycles. As with CH4, manufacturers would likely need to 
install N2O emissions analysis equipment. The proposed new 
procedure for measuring N2O is found in the draft 
regulations (40 CFR 1065.257 and 1065.357).
g. Locomotive and Marine Diesel Engines
    We are proposing that manufacturers of locomotive and marine diesel 
engines--including those who certify ``remanufactured'' engines--
measure and report CO2, CH4, and N2O 
emissions for locomotive and marine diesel engines. Manufacturers of 
these engines already measure CO2 emissions during the 
course of existing criteria air pollutant emission testing 
requirements, but generally do not report this to EPA. For 
manufacturers of these engines, we propose that CO2 
emissions be reported in the same cycle-weighted, work-based format 
(i.e., g/bhp-hr) as used for criteria pollutant emissions reporting. 
For C3 marine diesel engines, we are requesting comment on whether 
indirect CO2 measurement (i.e., calculating the 
CO2 levels based on fuel flow rate and fuel composition 
parameters) is an appropriate method for those manufacturers that do 
not utilize CO2

[[Page 16591]]

analysis equipment in the course of emission testing.
    Since diesel locomotives are subject to ``total'' hydrocarbon 
standards (which include CH4 in the measured and reported 
hydrocarbon value), as opposed to ``non-CH4'' hydrocarbon 
standards (which do not include CH4), manufacturers 
typically do not measure CH4 emissions. With the exception 
of C3 marine diesel engines (which do not have any ``hydrocarbon'' 
emission standards, and are not required to measure hydrocarbon or 
CH4 emissions), we propose that manufacturers measure and 
report CH4 emissions as a part of certification. To do so, 
we expect that some manufacturers would need to install equipment for 
analyzing CH4 emissions.
    We also propose that manufacturers--except for C3 marine--measure 
and report N2O emissions as well. For C3 marine diesel 
engines, we are requesting comment on the appropriateness and 
feasibility of requiring N2O measurement and reporting on 
the small number of engines represented by this category. As with 
CH4, we expect that most or all manufacturers would need to 
install N2O emissions analysis equipment. The proposed new 
procedure for measuring N2O is found in the proposed 
regulations (40 CFR 1065.257 and 1065.357).
h. Aircraft Engines
    This category comprises turbofan, turbojet, turboprop (turbine-
driven propeller), turboshaft (turbine-driven helicopters), and piston 
propulsion engines for commercial, air taxi, and general aviation 
aircraft. In the case of turbofan and turbojet engines of rated output 
(or thrust) greater than 26.7 kilonewtons, manufacturers of these 
engines are already measuring and recording CO2 emissions as 
part of existing criteria air pollutant emission requirements for the 
landing and takeoff cycle. In this notice, we propose that 
manufacturers measure, record and report CO2 separately for 
each mode of the landing and takeoff (LTO) cycle used in the emission 
certification test, as well as for the entire landing and takeoff 
cycle. (The modes of the landing and takeoff cycle are taxi/idle, 
takeoff, climb out, and approach.)
    CH4 may be emitted by gas turbine engines during idle 
and by relatively older technology engines, but recent data suggest 
that little or no CH4 may be emitted by some newer engines. 
Manufacturers of turbofan and turbojet engines of rated output greater 
than 26.7 kilonewtons are currently measuring hydrocarbon emissions as 
part of existing criteria air pollutant emissions testing, and 
CH4 is included in the total hydrocarbon measurement. We 
propose that manufacturers of these engines begin to separately measure 
and report CH4 for all engines in this category for which 
they are currently required to measure and record criteria air 
pollutant emissions as part of the certification process. Some 
manufacturers may need to acquire CH4 emissions analysis 
equipment. We ask for comment on the degree to which engine 
manufacturers now have the needed equipment in their certification test 
cells to measure CH4.
    Since little or no N2O is formed in modern gas turbine 
engines, we are not proposing to require N2O measurement or 
reporting.
    Within the mobile source sector, NOX is a climate change 
gas unique to aviation. As required in 40 CFR part 87, manufacturers of 
turbofan and turbojet engines of rated output greater than 26.7 
kilonewtons measure and record NOX emissions in each of the 
four LTO test modes, and these manufacturers must comply with the LTO 
NOX emission standard (for the entire LTO cycle). EPA asks 
for comment on whether NOX emissions in the four LTO test 
modes and for the overall LTO cycles should be reported under the 
provisions of this proposal, as they are now not reported to EPA for 
public consideration as is the case with all other mobile sources.\122\
---------------------------------------------------------------------------

    \122\ Currently, these engine manufacturers voluntarily report 
criteria air pollutant emissions for the LTO cycle to the 
International Civil Aviation Organization.
---------------------------------------------------------------------------

    EPA does not currently require manufacturers of piston engines 
(used in any application) to measure, record or report criteria air 
pollutant or GHG emissions, and no official FTP exists for these 
engines.\123\ For these reasons, we are not proposing any GHG reporting 
requirements for these engines. However, we request comment on the 
potential costs and benefits of reporting requirements for GHG 
emissions from these engines, including how an appropriate emission 
test cycle might be designed. We also ask for comment on whether the 
requirements should be applied to turbofan and turbojet engines of 
rated output less than or equal to 26.7 kilonewtons, turboprop engines, 
and turbo shaft engines which are not now regulated under 40 CFR 87 
requirements for criteria air pollutant emissions.\124\
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    \123\ EPA received an administrative petition asking the agency 
to determine under section 231 of the CAA whether lead emissions 
from general aviation (piston engine) aircraft cause or contribute 
to air pollution which may reasonably be anticipated to endanger 
public health or welfare, and, if so, to establish standards for 
such emissions. Today's proposal regarding GHG emissions from 
piston-engine aircraft is not intended to respond in any way to the 
petition regarding general aviation lead emissions.
    \124\ Existing regulations in 40 CFR part 87 include smoke 
number standards for turbofan and turbojet engines of rated output 
less than or equal to 26.7 kilonewtons and turboprop engines of 
rated output greater than or equal to 1,000 kilowatts. Requirements 
for the term turboshaft engine are currently not specified in 40 CFR 
part 87.
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4. Request for Comments on Travel Activity and Other In-Use, Emissions-
Related Data
    Travel activity and other emissions-related data from State and 
local governments and fleet operators are critical to understanding the 
overall GHG contribution of the mobile source sector. These data serve 
the important role of reflecting real-world conditions and capturing 
activity levels (e.g., distance traveled and hours operated) from all 
vehicles and engines, which can complement data that manufacturers 
report on expected emissions rates from new vehicles and engines. EPA 
already receives some in-use data through existing reporting programs. 
The purpose of this section of the preamble is to describe these 
existing data sources and to request public comment on the need for 
additional data. In Section V.QQ.4.a of this preamble, we describe data 
currently reported by State and local governments, and request comment 
on the potential benefits of the collection of additional data. In 
Section V.QQ.4.b of this preamble, we highlight the types of data 
reported by fleet operators as part of the SmartWay Transport Program 
or other Federal programs, and request comment on the value of other 
potential reporting requirements.
a. Travel Activity and Other Data From State and Local Governments
    Travel activity is a term EPA primarily uses for on-road vehicle 
activity and includes the number and type of vehicles and the distance 
they travel. State and local governments collect many types of travel 
activity data, including VMT by vehicle type and model year, fuel type, 
and/or functional road class (e.g., limited access highways, arterials 
with traffic signals, etc.). Other types of emissions-related data 
include vehicle operation and environmental conditions that can affect 
emissions during travel, such as idling practices and ambient 
temperature. Travel activity and other emissions-related data can vary 
over time, between regions, and between metropolitan and rural areas 
within a given State. EPA can use these data to evaluate how changes in 
vehicle

[[Page 16592]]

technology or travel activity can affect emissions.
    EPA currently collects on-road mobile source data to better 
understand criteria air pollutant emissions, and some of these data can 
also be used to understand GHG emissions. For example, States provide 
VMT data to the Agency through the AERR.\125\ EPA currently relies on 
AERR data to develop the NEI \126\ which is used for, among other 
things, evaluating Federal vehicle and fuel standards for criteria 
pollutants and mobile source air toxics.
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    \125\ EPA promulgated the AERR in December 2008 (73 FR 76539) 
(40 CFR part 51, subpart A). EPA promulgated the AERR to 
consolidate, reduce, and simplify the current requirements; add 
limited new requirements; provide additional flexibility to states 
in the ways they collect and report emissions data; and accelerate 
the reporting of emissions data to EPA by state and local agencies. 
The AERR replaces the Consolidated Emissions Reporting Rule (CERR) 
which was promulgated in June 2002 (67 FR 39602) in part to 
streamline existing periodic emissions inventory requirements for 
criteria pollutants.
    \126\ EPA prepares a national database of air emissions 
information from numerous state and local air agencies, from tribes, 
and from industry: http://www.epa.gov/ttn/chief/eiinformation.html.
---------------------------------------------------------------------------

    The AERR requires State air agencies to report mobile source data, 
including VMT data at the county level by roadway type, \127\ every 
three calendar years beginning with the 2002 calendar year (i.e., 
states report mobile source inventories for 2005, 2008, 2011, etc.). 
The most recent submissions are for the 2005 calendar year. Although 
not required by the rule, EPA understands that some State air agencies 
consult with State and local transportation agencies in preparing VMT 
data submissions. States also submit other information that can be used 
to estimate criteria pollutant emissions, e.g., age and speed 
distributions of vehicles by vehicle class and roadway type, fuel 
properties by county, month, and year, and temperature and humidity 
data by county, month, and year. The AERR also requires certain 
emissions-related information, such as activity data (e.g., hours/day 
of operation), for nonroad mobile sources, according to similar 
submission requirements as described above.
---------------------------------------------------------------------------

    \127\ Under the AERR, VMT data should reflect both roadway type 
and vehicle type information.
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    In addition to EPA's existing data collection requirements, there 
are other sources of travel activity and emissions-related data. DOT 
currently collects statewide VMT data for urban and rural roadway types 
through its Highway Performance Monitoring System. DOT and DOE also 
publish statistical reports such as the Census Transportation Planning 
Package, National Personal Transportation Survey, and the Urban 
Mobility Study. In the past, the U.S. Census Bureau conducted the 
Vehicle Inventory and Use Survey, which provided valuable data on the 
physical and operational characteristics of the nation's private and 
commercial truck populations.\128\ In specific geographic areas, 
agencies such as metropolitan planning organizations, State departments 
of transportation, transit agencies, air quality agencies, and county 
planning agencies also collect and project State and local travel 
activity and emissions data to meet Federal requirements, such as DOT's 
transportation planning requirements and EPA's SIP and transportation 
conformity requirements.
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    \128\ The primary goal of the Vehicle Inventory and Use Survey 
database was to produce national and state-level estimates of the 
total number of trucks. This survey was conducted every 5 years, 
until it was discontinued in 2002.
---------------------------------------------------------------------------

    In light of the existing data available to EPA, the Agency is not 
proposing any new reporting requirements for State and local 
governments at this time. However, EPA is interested in requesting 
comment on several topics.
    (1) Should EPA require States, local governments, or other entities 
to report additional travel activity or emissions-related data beyond 
what is required under EPA's existing reporting requirements? How would 
such data be used to inform future climate policy?
    (2) What, if any, are the specific gaps in the currently reported 
travel activity or emissions-related data that are important for 
understanding on-road mobile source GHG emissions? For example, would 
it be helpful for EPA to better understand State- or county-level VMT 
growth rates (e.g., based on VMT data collected over the past five or 
ten years or other methodology) or emissions data related to the 
freight sector (e.g., hours of long-duration truck idling or truck data 
that was previously provided by the Vehicle Inventory and Use Survey)? 
What is the quality of currently reported State and local VMT data, and 
should travel activity and emissions-related data quality be improved?
    (3) Is it sufficient to collect travel activity or emissions-
related data every three years as currently required, or should EPA 
collect such data on an annual basis, similar to other collections 
discussed in today's action?
    (4) Should EPA consider any threshold(s) for States, local 
governments, or other entities that must report additional travel 
activity or other emissions-related data? For example, should 
additional data be reported only from larger metropolitan areas with 
more sophisticated transportation systems (e.g., metropolitan planning 
organizations with an urbanized population of 200,000 or more)?
    (5) What nonroad activity data is of most interest for 
understanding GHG emissions, and should EPA consider any additional 
requirements for reporting such data beyond what is currently required?
    b. Mobile Source Fleet Operator Data
    Mobile source fleet operators \129\ are in a unique position to 
collect data that reflect real-world conditions that are difficult to 
integrate into vehicle and engine testing procedures or to capture in 
travel activity surveys. Fleet operator data includes fuel consumption, 
which can be robustly converted into CO2 emissions, distance 
traveled, and the number and/or weight of passengers and freight 
transported. EPA currently collects fleet operator data from sources 
that include DOT surveys such as the Vehicle Inventory and Use Survey 
(described in Section V.QQ.4.a of this preamble, but discontinued in 
2002), in-use testing as part of vehicle and engine manufacturer 
compliance programs, ad-hoc internal and external field studies and 
surveys, and voluntary programs such as the SmartWay Transport 
Partnership. The rest of this section of the preamble describes the 
data EPA collects as part of our voluntary programs as well as the 
DOT's (DOT) rail and aviation fleet reporting requirements, and 
requests comment on the need for, and substance of, any additional 
reporting requirements.
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    \129\ For the purpose of our request for comments, ``fleet 
operators'' are defined as entities that have operational control 
over mobile sources. ``Operational control'' is defined as having 
the full authority to introduce and implement operational, 
environmental, health, and safety policies.
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    EPA believes that one of the most important functions of collecting 
fleet operator data is to inform operators about their emissions 
profiles and to shed light on opportunities to reduce emissions through 
the use of clean technologies, fuels, and operational strategies. 
Through the SmartWay Transport Partnership program, EPA requires 
participating truck and rail equipment operators, or ``partners,'' to 
report data as part of their voluntary commitment to measure and 
improve the environmental performance of their fleets. EPA uses this 
data to evaluate partner performance. Partners report annually on their 
fuel consumption by fuel type, miles traveled, and tonnage of freight 
carried. Truck operators also have the option of reporting the 
configuration and model year of each of their trucks. There is no 
minimum emissions reporting threshold for either truck or rail 
operators. EPA requires partners to report their annual data

[[Page 16593]]

through the SmartWay Freight Logistics Environmental and Energy 
Tracking performance model.\130\ The SmartWay Freight Logistics 
Environmental and Energy Tracking model translates the partners' fuel 
consumption data into CO2 emissions based on EPA's default 
emissions factors for fuels. EPA does not publicly release individual 
partners' emissions data. At present, the SmartWay Transport 
Partnership has received annual data from more than 400 trucking 
companies and all seven Class I rail companies. These partners' 
CO2 emissions represent approximately 20 percent and 80 
percent, respectively, of the 2005 national inventory of trucking and 
rail GHG emissions.\131\
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    \130\ The SmartWay Freight Logistics Environmental and Energy 
Tracking model and accompanying user guide and glossary is available 
at http://www.epa.gov/otaq/smartway/smartway_fleets_software.htm.
    \131\ Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2005, EPA, 2007.
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    EPA's Climate Leaders program also requires participating companies 
that operate mobile sources to report CO2, N2O, 
CH4, and HFC emissions from those sources annually as a part 
of their voluntary commitment to develop a comprehensive, corporate-
wide GHG inventory. There are no minimum emissions reporting thresholds 
for mobile sources. Companies quantify mobile source emissions based on 
the Climate Leaders reporting protocol,\132\ which outlines several 
methods for calculating CO2 including applying EPA's default 
factors to fuel consumption data. The reporting protocol also includes 
default N2O and CH4 factors for non-road fuel 
consumption and on-road miles traveled by vehicle model year or 
technology type. Additionally, the reporting protocol includes default 
HFC leakage factors for mobile A/C units. As with SmartWay, EPA does 
not publicly release individual participating companies' emissions 
data. Currently, the Climate Leaders program has received mobile source 
data from 37 companies representing roughly 0.09 percent of the 2005 
national inventory of transportation sector GHG emissions.\133\
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    \132\ See Direct Emissions from Mobile Combustion Sources and 
Direct HFC and PFC Emissions from Use of Refrigeration and Air 
Conditioning Equipment, available at http://www.epa.gov/climateleaders/resources/cross-sector.html.
    \133\ Inventory of U.S. Greenhouse Gas Emissions and Sinks: 
1990-2005, EPA, 2007.
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    In addition, DOT collects and publicly releases extensive data from 
rail and aircraft operators. All seven Class I \134\ rail operators are 
required to report annual fuel consumption and ton-miles, among other 
data, to the Surface Transportation Board per the reporting guidelines 
in 49 U.S.C. 11145. Large certificated air carriers,\135\ small 
certificated air carriers, and commuter air carriers with more than 
$20,000,000 in annual operating revenues must report monthly fuel usage 
data to the Bureau of Transportation Statistics via Form 41 pursuant to 
14 CFR part 217 and part 241. Large certificated air carriers must also 
report monthly traffic data including distance traveled, tonnage of 
freight transported, and number of passengers transported.
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    \134\ A ``Class I railroad'' is defined as a carrier that has an 
annual operating revenue of $250 million or more after applying the 
railroad revenue deflator formula, which is based on the Railroad 
Freight Price Index developed by the U.S. Department of Labor, BLS. 
The formula is the current year's revenues x 1991 average index/
current year's average index.
    \135\ The definition of ``large certified air carrier'',``small 
certified air carrier'', and ``commuter air carrier'' for Form 41 
reporting requirements is available at: http://www.bts.gov/programs/statistical_policy_and_research/source_and_accuracy_compendium/form41_schedule.html.
---------------------------------------------------------------------------

    In light of the existing data available to EPA, the Agency is not 
proposing mandatory reporting requirements for mobile source fleet 
operators, but is requesting comments on the need for, and substance 
of, potential reporting requirements at this time. We request comment 
on the following questions:
    (1) Should fleet operators be required to report to EPA outside of 
voluntary participation in the SmartWay or Climate Leaders programs? 
How would this data be used to inform future climate policy?
    (2) Are there certain categories of mobile sources that should be 
included or excluded in potential reporting requirements (e.g., lawn 
mowers, commercial light-duty vehicles, heavy-duty trucks, rail 
equipment, aircraft, waterborne vehicles)?
    (3) Should one or more minimum emissions thresholds apply based on 
the mobile source category, and what would be appropriate annual 
thresholds?
    (4) Are there certain categories of fleets that should be included 
or excluded from potential reporting requirements (e.g., public fleets 
versus private fleets)?
    (5) If reporting requirements were to be introduced, what types of 
data should operators report (e.g., fuel consumption for estimating 
CO2 and non-road N2O and CH4 
emissions; mileage and vehicle technology for estimating on-road 
N2O and CH4 emissions; efficiency metrics such as 
emissions per tons carried)?
    (6) What type of data verification or quality control should EPA 
require in any potential reporting requirements?
    (7) For potential reporting requirements, are there preferred 
emissions quantification methods other than those presented in the 
SmartWay Freight Logistics Environmental and Energy Tracking model or 
the Climate Leaders reporting protocol?

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

A. Purpose

    This section of the preamble describes the process by which EPA 
proposes to collect, manage, and disseminate data under the GHG 
reporting rule.
    Section V.B of this preamble describes the proposed establishment 
of a new reporting system that would accept electronic submissions of 
GHG emissions and supporting data, quality assure the submissions, 
store the results, and provide access to the public. The new system 
would follow Agency standards for design, security, data element and 
reporting format conformance, and accessibility.
    Existing sources that would be affected by the proposed GHG 
reporting rule may currently report emissions or other data to the 
Agency (or in some cases States) under other titles of the CAA 
including Title I (Emission Inventory, SIP, NSPS and NESHAP), Title II 
(National Emissions Standards Act), Title IV (Acid Rain), Title V (Air 
Operating Permits) and Title VI (Stratospheric Ozone Protection). EPA 
intends to develop a reporting scheme that minimizes the burden of 
stakeholders by integrating the new reporting requirements with 
existing data collection and data management systems, when feasible. 
Also, EPA would work with States to ease the burden on reporters to 
State and Federal systems by harmonizing data management, where 
possible.
    Section VI.B of this preamble further describes the proposal 
regarding the frequency and timeliness of reporting, the requirement 
for a Designated Representative certification, and the units of measure 
for submissions and published results.
    Section VI.C of this preamble describes QA that EPA would perform 
to ensure the completeness, accuracy, and validity of submissions. It 
also describes the feedback that EPA would provide to emission 
reporters indicating the results of the electronic data quality checks.
    Section VI.D of this preamble discusses publication of data that 
would be collected under the proposed

[[Page 16594]]

mandatory GHG reporting rule. EPA proposes to make data collected under 
this rule available to State agencies and the public, with the 
exception of any CBI data, as discussed in Section I.C of this 
preamble. EPA requests comments on proposed strategies regarding data 
collection, management, and dissemination outlined in this section of 
the preamble.

B. Data Collection

1. Data Collection Methods
    If a reporting source already reports GHG emissions data to an 
existing EPA program, the Agency would make efforts to minimize any 
additional burden on the sources. Some existing programs, however, have 
data collection and reporting requirements that are inconsistent with 
the proposed requirements for the mandatory GHG reporting rule. When it 
is not feasible to adapt the existing program to collect the 
appropriate emissions data and supplemental data, EPA proposes to 
require affected sources to submit the data in the requested format to 
the new data reporting system for the mandatory GHG reporting rule.
    Emission sources may fall into one or more categories:
    (1) Reporting sources that use existing data collection and 
reporting methods and would not be required to report separately to the 
new data reporting system for the GHG reporting rule.
    (2) Reporting sources that use existing data collection and 
reporting methods but would be required to report the data separately 
to the new data reporting system for the GHG reporting rule.
    (3) Reporting sources that are not currently required to collect 
and report GHG emissions data to EPA and would be required to report 
using the new data reporting system for the mandatory GHG reporting 
rule.
    EPA believes that using existing data collection methods and 
reporting systems, when feasible, to collect data required by this 
proposed rule would minimize additional burden on sources and the 
Agency. We seek comment on the use of existing collection methods and 
reporting systems to collect information required by this proposed 
rule.
    For those sources that do not report GHGs or data used to calculate 
GHG emissions through an existing reporting system, EPA proposes to 
develop a new system for emission reporters to submit the required 
data. The detailed data elements that would be reported and other 
requirements are specified in Sections III, IV and V of this preamble. 
In general, reporters using this new method would report annually to 
the Agency covering each calendar year by March 31 of the following 
year (e.g., annual emissions for calendar year 2010 would be reported 
by March 31, 2011.)
2. Data Submission
    The Designated Representative (described in proposed 40 CFR part 
98, subpart A and Section IV.G of this preamble) must use an electronic 
signature device (for example, a 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 propose that the new reporting system would 
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.)
3. Unique Identifiers for Facilities and Units
    We believe that 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 ORIS (DOE) ID code, and consistency 
from one reporting year to the next, we are proposing that the 
reporting system provide each facility with a unique identification 
code to be specified by the Administrator.
4. Reporting Emissions in a Single Unit of Measure
    To maintain consistency with existing State-level and Federal-level 
greenhouse gas programs in the U.S. and internationally, the Agency is 
proposing that all emission measurements be 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 would be included in the 
data submission. All emissions data would be submitted to the agency in 
kg or metric tons per unit of time (per year in most cases, but for a 
few source categories emissions per hour, day, month, quarter, or other 
unit of time could also be required).
5. Conversion of Emissions to CO2e
    Under this proposed rule, reporters would submit the quantity of 
each applicable GHG emitted (or other metric) in two forms. The data 
would 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. Reporting the quantity and type of gas emitted allows for 
future recalculation of CO2e emissions in the event that GWP 
factors change.
6. Delegation of Authority to State Agencies To Collect GHG Data
    The Agency proposes that affected sources submit the emissions data 
and supplemental data directly to EPA. The Agency believes this would 
reduce the burden on reporters and State agencies, provide faster 
access to national emission data, and facilitate consistent QA.
    Under CAA Section 114(b), EPA may delegate the authority to collect 
emissions data from stationary sources to State agencies provided the 
State agency can satisfy the procedural requirements. We seek comment 
on the possibility of delegating the authority to State agencies that 
request such authority and assessing whether the State agency has 
procedures that are deemed consistent and adequate with the procedures 
outlined in this rule. For example, how should EPA determine whether a 
requesting State agency has ``consistent and adequate'' procedures?
7. Submission Method
    EPA proposes to require all sources affected by this rule to report 
in an electronic format to be specified by the Administrator. 
Advantages of electronic reporting include reduced burden on reporters 
and EPA staff, greater accuracy because data do not need to be manually 
entered by EPA staff, enhanced ability to conduct electronic audits to 
ensure data quality, improved comparability because data would be 
reported in a consistent format, and improved data availability for EPA 
and the public.
    By not specifying the exact reporting format in the regulatory 
text, EPA maintains flexibility to modify the reporting format and 
tools in a timely manner. Changes based on stakeholder comment, 
implementation experience, and new technology could be executed without 
regulatory action. EPA has used this approach successfully with 
existing programs, such as the ARP and the Title VI Stratospheric Ozone 
Protection Program, facilitating the deployment of new reporting 
formats and tools that take advantage of technologies (e.g., XML) and 
reduce the burden on reporters and the Agency. The electronic reports 
submitted under this rule would also be subject to the provisions of 40 
CFR 3.10, specifying EPA systems to which electronic submissions must 
be made and the requirements for valid electronic signatures.

[[Page 16595]]

C. Data Management

1. QA Procedures
    The new reporting system would include automated checks for data 
completeness, data quality, and data consistency. Such automated checks 
are used for many other Agency programs (e.g., ARP).
2. 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. 
The process is largely dependent upon such factors as the type of data 
being submitted and the manner of data transmission. Regardless of data 
collection system specifics, the goal is to ensure appropriate 
transparency and timeliness when providing feedback to submitting 
entities.

D. Data Dissemination

1. Public Access to Emissions Data
    The Agency proposes to publish data submitted or collected under 
this rulemaking through EPA's Web site, reports, and other formats, 
with the exception of any CBI data, as discussed in Section I.C of this 
preamble. This level of transparency would inform the public and 
facilitate greater data verification and review. Transparency helps to 
ensure data quality and build public confidence in the data so the data 
can be used to support the development of potential future climate 
policies or programs.
    EPA proposes to disseminate the data on an annual basis. Under this 
proposed rule, affected sources would be required to report at least on 
an annual basis, with some reporting more frequently to existing data 
reporting programs (e.g., the ARP). The Agency believes it would be 
appropriate to post or publish data collected under this rule once a 
year after the reporting deadline. The Agency recognizes the high level 
of public interest in this data, and proposes to disclose it in a 
timely manner, while also assuring accuracy.
2. 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. These 
programs would likely still continue because they may be broader in 
scope or more aggressive in implementation than this proposal. In order 
to be consistent with and supportive of these programs and to reduce 
burden on reporters and program agencies, EPA proposes that it share 
emission data with the exception of any CBI data, as discussed in 
Section III.C of this preamble, with relevant agencies or approved 
entities using, where practical, shared tools and infrastructure.

VII. Compliance and Enforcement

A. Compliance Assistance

    To facilitate implementation and compliance, EPA plans to conduct 
an active outreach and technical assistance program following 
publication of the final rule. The primary audience would be 
potentially affected industries. We intend to develop implementation 
and outreach materials to help facilities understand if the rule 
applies to them and explain the reporting requirements and timetables. 
The program particularly would target industrial, commercial, and 
institutional sectors that do not routinely deal with air pollution 
regulations.
    Compliance materials could be tailored to the needs of various 
sectors. These materials might include, for example, compliance guides, 
brochures, fact sheets, frequently asked question and answer documents, 
sample reporting forms, and GHG emissions calculating tools. We also 
are considering a compliance assistance hotline for answering questions 
and providing technical assistance. (We may also want to consider 
creating a compliance assistance center (http://www.assistancecenters.net).) EPA requests comment on the types of 
assistance needed and the most effective mechanisms for delivering this 
assistance to various industry sectors.

B. Role of the States

    State and local air pollution control agencies routinely interact 
with many of the sources that would report under this rule. Further, as 
mentioned in Section II of this preamble, many States have already 
implemented or are in the process of implementing mandatory GHG 
reporting and reduction programs. In fact, many States may have 
reporting programs that are broader in scope or more aggressive in 
implementation because those programs are either components of 
established reduction programs (e.g., cap and trade) or being used to 
design and inform specific complementary measures (e.g., energy 
efficiency).
    Therefore, State and local agencies will serve an important 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 also can assist with educating facilities and assuring 
compliance at facilities subject to this rule.
    As discussed in Section VI of this preamble, CAA section 114(b) 
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 to State and local agencies. Even 
without delegation, EPA will work with States to ease burden on 
reporters to State and Federal systems by harmonizing data management, 
where possible. Further, as discussed in Section VI of this preamble, 
EPA is proposing to make the data collected under this rule available 
to States and other interested parties as soon as possible. For 
example, the quarterly data reported to EPA under Title IV of the CAA 
is often available on EPA's Web site within a month after it is 
reported. Furthermore, we recognize that many States with mandatory 
reporting programs are members of TCR. In some cases, TCR would provide 
States support in reporting tools, database management and serve as the 
ultimate repository for data reported under State programs, after the 
States have verified the data. Given the leadership many of the States 
have shown in developing and implementing GHG reporting and reduction 
programs, EPA is seeking comment on the possibility of delegating the 
authority to collect data under this rule to State agencies. Overall, 
we request comments on the role of States in implementing this rule and 
on how States and EPA could interact in administering the reporting 
program.

C. Enforcement

    Facilities that fail to report GHG emissions according to the 
requirements of the proposed rule 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 
$32,500 per day.\136\
---------------------------------------------------------------------------

    \136\ 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 $32,500 per day of violation.

---------------------------------------------------------------------------

[[Page 16596]]

    Deviations from the rule that could ultimately be considered 
violations include but are not limited to the following:
     Failure to report GHG emissions.
     Failure to collect data needed to estimate 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 keep records needed to verify GHG emissions 
estimates.
     Failure to estimate GHG emissions according to the 
methodology(s) specified in the rule.
     Falsification of reports.

VIII. Economic Impacts of the Proposed Rule

    This section of the preamble examines the costs and economic 
impacts of the proposed rule, including the estimated costs and 
benefits of the proposed rule, and the estimated economic impacts of 
the proposed rule on affected entities, including estimated impacts on 
small entities. Complete detail of the economic impacts of the proposed 
rule can be found in the text of the regulatory impact analysis (RIA) 
(EPA-HQ-OAR-2008-0318-002).

A. How are compliance costs estimated?

    EPA estimated costs of complying with the proposed rule for process 
emissions of GHGs in each affected industrial facility, as well as 
emissions from stationary combustion sources at industrial facilities 
and other facilities, and emissions of GHGs from 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 proposed rule would 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 proposed rule. For some 
affected 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 
proposed 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 would 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 BLS.
    Equipment Costs. Equipment costs include both the initial purchase 
price of monitoring equipment and any 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 the 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 7 percent.

B. What are the costs of this proposed rule?

    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. 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 proposed rule (to allow only the incremental costs to be 
estimated). Many of the affected sources 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 proposed rule to develop unique unit costs. This analysis is 
documented in the RIA. The TSDs for each source category provide a 
discussion of the applicable measurement technologies and any existing 
programs and practices. Section 4 of the RIA contains a description of 
the engineering cost analysis.
    Table VIII-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 proposed rule. EPA 
estimates that the total national annualized cost for the first year is 
$168 million, and the total national annualized cost for subsequent 
years is $134 million (2006$). Of these costs, roughly 5 percent fall 
upon the public

[[Page 16597]]

sector for program administration, while 95 percent fall upon the 
private sector. General stationary combustion sources, which are widely 
distributed throughout the economy, are estimated to incur 
approximately 18 percent of ongoing costs; other sectors incurring 
relatively large shares of costs are oil and natural gas systems (21 
percent of ongoing costs), and iron and steel manufacturing (11 
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 
VIII-2 of this preamble provides the cost-effectiveness analysis for 
the various thresholds. Three 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. The third metric shown is the marginal 
cost of reported emissions. For this analysis, the marginal cost of 
reporting indicates the cost per metric ton of each threshold option 
relative to the 25,000 metric ton CO2e proposed threshold). 
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 and the RIA cost appendix. Not all 
subparts require capital expenditures but those that do are clearly 
documented in the RIA.

                                    Table VIII-1. Estimated Covered Entities, Emissions and Costs by Subpart (2006$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                              Downstream emissions    First year capital costs      First year total
                                                                Number of  ----------------------------------------------------   annualized costs \2\
                           Subpart                               covered    (Million of                                        -------------------------
                                                                 entities     MtCO2e)     Share (%)    (Million)    Share (%)    (Million)    Share (%)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Subpart A--General Provisions
Subpart B--Reserved
Subpart C--General Stationary Fuel Combustion Sources........        3,000        220.0            6        $12.7           15        $29.0           17
Subpart D--Electricity Generation............................        1,108      2,262.0           58          0.0            0          3.3            2
Subpart E--Adipic Acid Production............................            4          9.3            0          0.0            0          0.1            0
Subpart F--Aluminum Production...............................           14          6.4            0          0.0            0          0.4            0
Subpart G--Ammonia Manufacturing.............................           24         14.5            0          0.0            0          0.4            0
Subpart H--Cement Production.................................          107         86.8            2          5.4            6          6.9            4
Subpart I--Electronics Manufacturing.........................           96          5.7            0          0.0            0          3.6            2
Subpart J--Ethanol Production................................           85          0.0            0          0.3            0          0.5            0
Subpart K--Ferroalloy Production.............................            9          2.3            0          0.0            0          0.3            0
Subpart L--Fluorinated Gas Production........................           12          5.3            0          0.0            0          0.0            0
Subpart M--Food Processing...................................          113          0.0            0          0.0            0          0.6            0
Subpart N--Glass Production..................................           55          2.2            0          0.0            0          0.6            0
Subpart O--HCFC-22 Production................................            3         13.8            0          0.0            0          0.0            0
Subpart P--Hydrogen Production...............................           41         15.0            0          0.0            0          0.6            0
Subpart Q--Iron and Steel Production.........................          121         85.0            2          0.0            0         18.2           11
Subpart R--Lead Production...................................           13          0.8            0          0.0            0          0.3            0
Subpart S--Lime Manufacturing................................           89         25.4            1          4.9            6          5.3            3
Subpart T--Magnesium Production..............................           11          2.9            0          0.0            0          0.1            0
Subpart U--Miscellaneous Uses of Carbonates..................            0          0.0            0          0.0            0          0.0            0
Subpart V--Nitric Acid Production............................           45         17.7            0          0.2            0          0.9            1
Subpart W--Oil and Natural Gas Systems.......................        1,375        129.9            3         37.8           43         32.5           19
Subpart X--Petrochemical Production..........................           88         54.8            1          0.0            0          1.6            1
Subpart Y--Petroleum Refineries..............................          150        204.7            5          1.6            2          3.7            2
Subpart Z--Phosphoric Acid Production........................           14          3.8            0          0.8            1          0.8            0
Subpart AA--Pulp and Paper Manufacturing.....................          425         57.7            1         14.8           17          9.2            5
Subpart BB--Silicon Carbide Production.......................            1          0.1            0          0.0            0          0.0            0
Subpart CC--Soda Ash Manufacturing...........................            5          3.1            0          0.0            0          0.0            0
Subpart DD--Sulfur Hexafluoride (SF6) from Electric Power              141         10.3            0          0.0            0          0.4            0
 Systems.....................................................
Subpart EE--Titanium Dioxide Production......................            8          3.7            0          0.0            0          0.1            0
Subpart FF--Underground Coal Mines...........................          100         33.5            1          0.6            1          2.3            1
Subpart GG--Zinc Production..................................            5          0.8            0          0.0            0          0.1            0
Subpart HH--Landfills........................................        2,551         91.1            2          7.9            9         15.3            9
Subpart II--Wastewater.......................................            0          0.0            0          0.0            0          0.0            0
Subpart JJ--Manure Management................................           43          1.5            0          0.0            0          0.2            0
Subpart KK--Suppliers of Coal and Coal-based Products &              1,237        (\1\)            0          0.0            0         11.0            7
 Subpart LL--Suppliers of Coal-based Liquid Fuels............
Subpart MM--Suppliers of Petroleum Products..................          214        (\1\)            0          0.0            0          2.0            1
Subpart NN--Suppliers of Natural Gas and Natural Gas Liquids.        1,554        (\1\)            0          0.0            0          2.1            1
Subpart OO--Suppliers of Industrial Greenhouse Gases.........          121        464.1           12          0.0            0          0.4            0

[[Page 16598]]

 
Subpart PP--Suppliers of Carbon Dioxide (CO2)................           13        (\1\)            0          0.0            0          0.0            0
Subpart QQ--Motor Vehicle and Engine Manufacturers...........          350         35.4            1          0.0            0          7.4            4
Private Sector, Total........................................       13,205      3,869.9          100         87.1          100        160.4           95
Public Sector, Total.........................................           NA           NA           NA           NA           NA          8.0            5
                                                              ------------------------------------------------------------------------------------------
    Total....................................................       13,205      3,869.9          100         87.1          100        168.4          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 RIA section 4).


                                               Table VIII-2. Threshold Cost-Effectiveness Analysis (2006$)
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                           Million     Percentage
                                                                 Entities   Total costs  metric tons    of total     Average    Incremental    Marginal
                 Threshold (metric tons CO2e)                   (covered)   (million $)   CO2e/year    emissions     cost ($/     cost ($/    cost * ($/
                                                                                          (covered)     reported   metric ton)  metric ton)  metric ton)
--------------------------------------------------------------------------------------------------------------------------------------------------------
100,000......................................................        6,598         $101        3,699           52        $0.03           --       -$0.35
25,000.......................................................       13,205          160        3,870           55         0.04        $0.35           --
10,000.......................................................       20,765          213        3,916           56         0.05         1.16         1.16
1,000........................................................       59,587          426        3,951           56         0.11         6.09         3.29
--------------------------------------------------------------------------------------------------------------------------------------------------------
* Cost per metric ton relative to the selected option.

    Table VIII-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., coal mines, refineries, etc.) are also direct 
emitters of GHGs and are included in the downstream side of the table. 
As shown in Table VIII-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 VIII-3. Upstream versus Downstream Costs
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                   Upstream \1\                                                            Downstream \2\ \3\ \4\
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                 Emissions
                                                No. of     Emissions    First year                                    No. of      coverage    First year
              Source category                 Reporters     coverage       cost            Source category          Reporters     \3\ \10\     cost \3\
                                                            (%) \10\    (millions)                                     \2\          (%)       (millions)
--------------------------------------------------------------------------------------------------------------------------------------------------------
Coal Supply................................        1,237        100.0       $11.03  Coal \5\ \6\ Combustion......          N/A         99.0          N/A
Petroleum Supply...........................          214        100.0         1.99  Petroleum \5\ Combustion \10\          N/A         20.0          N/A
Natural Gas Supply.........................        1,554         68.0         2.14  Natural Gas \5\ Combustion...          N/A         23.0          N/A
                                             ...........  ...........  ...........  Sub Total Combustion.........        4,108      \5\ N/A        46.16
Industrial Gas Supply......................          133        99.91         0.41  Industrial Gas Consumption...          265         28.0         3.70
                                             ...........  ...........  ...........  Industrial Processes.........        1,077         99.6        36.12
                                             ...........  ...........  ...........  Fugitive Emissions (coal, oil        1,475         86.6        34.86
                                                                                     and gas).
                                             ...........  ...........  ...........  Biological Processes.........        2,792         55.5        16.59
                                             ...........  ...........  ...........  Vehicle \7\ and Engine                 350         84.0         7.41
                                                                                     Manufacturers \9\.
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes:
\1\ Most upstream facilities (e.g., coal mines, refineries, etc.) 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 proposed threshold (e.g., 25,000 metric tons of CO2e/
  yr).

[[Page 16599]]

 
\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 Acid Rain Program.
\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 would 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 vehicle and engine manufacturers covered by this proposal rather than emissions coverage. This rule
  proposes to collect an emissions rate for the four ``transportation-related'' GHG emissions (CO2, CH4, N2O and HFCs). The amounts of CH4 and N2O are
  dependent on factors other than fuel characteristics such as combustion temperatures, air-fuel mixes, and use of pollution control equipment.
\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 1 percent of the total emissions.
\11\ EPA estimates that the majority of the costs for manufacturers of vehicles and engines can be attributed to the reporting requirements for non-CO2
  gases.

C. What are the economic impacts of the proposed rule?

    EPA prepared an economic impact analysis to evaluate the impacts of 
the proposed 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 proposed rule.
    To estimate the economic impacts of the proposed 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 are 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 proposed 
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 proposed rule, rather than modeling market responses 
and using the resulting measures of social cost. Table VIII-4 of this 
preamble summarizes cost-to-sales ratios for affected industries.

                       Table VIII-4. Estimated Cost-To-Sales Ratios for Affected Entities
----------------------------------------------------------------------------------------------------------------
                                                                                          Average
                                                                                          cost per     Average
                    NAICS                                 NAICS description                entity    entity cost-
                                                                                          ($1,000/     to-sales
                                                                                          entity)     ratio \1\
----------------------------------------------------------------------------------------------------------------
211.........................................  Oil & gas extraction....................          $23         0.1%
212.........................................  Mining (except oil & gas)...............           10          0.1
221.........................................  Utilities...............................            1         <0.1
322.........................................  Paper mfg...............................           22          0.1
324.........................................  Petroleum & coal products mfg...........           16         <0.1
325.........................................  Chemical mfg............................           12         <0.1
327.........................................  Nonmetallic mineral product mfg.........           51          0.8
331.........................................  Primary metal mfg.......................          112          0.4
334.........................................  Computer & electronic product mfg.......           37          0.1
335.........................................  Electrical equipment, appliance, &                 37          0.2
                                               component mfg.
486.........................................  Pipeline transportation.................           12          0.1
562.........................................  Waste management & remediation services.            6          0.2
325199......................................  All other basic organic chemical mfg....           24         <0.1
325311......................................  Nitrogenous fertilizer mfg..............           19          0.1
327310......................................  Cement mfg..............................           65          0.2
331112......................................  Electrometallurgical ferroalloy product            28         <0.1
                                               mfg.
3272........................................  Glass & glass product mfg...............           11          0.1
325120......................................  Industrial gas mfg......................            3         <0.1
331112......................................  Electrometallurgical ferroalloy product           150          0.3
                                               mfg.
3314........................................  Nonferrous metal (except aluminum)                 23          0.1
                                               production & processing.
327410......................................  Lime mfg................................           60          0.4
325311......................................  Nitrogenous fertilizer mfg..............           20          0.1
324110......................................  Petroleum refineries....................           19         <0.1
325312......................................  Phosphatic fertilizer mfg...............           60          0.1
322110......................................  Pulp mills..............................           22         <0.1
324110......................................  Petroleum refineries....................           24         <0.1

[[Page 16600]]

 
327910......................................  Abrasive product mfg....................           11          0.1
3251........................................  Basic chemical mfg......................            9         <0.1
325188......................................  All other basic inorganic chemical mfg..            9         <0.1
3314........................................  Nonferrous metal (except aluminum)                 19          0.1
                                               production & processing.
----------------------------------------------------------------------------------------------------------------
\1\ This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not
  include initial start-up activities.

D. What are the impacts of the proposed rule on small entities?

    As required by the RFA and SBREFA, EPA assessed the potential 
impacts of the proposed rule on small entities (small businesses, 
governments, and non-profit organizations). (See Section IX.C of this 
preamble for definitions of small entities.)
    EPA believes the proposed thresholds maximize the rule coverage 
with 85 to 90 percent of U.S. GHG emissions reported by approximately 
13,205 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 captured by the rule, EPA has proposed 
simplified emission estimation methods where feasible (e.g., stationary 
combustion equipment under a certain rating can use a simplified mass 
balance approach as opposed to more rigorous direct monitoring) to keep 
the burden of reporting as low as possible. For further detail on the 
rationale for excluding small entities through threshold selection 
please see the Thresholds TSD (EPA-HQ-OAR-2008-0508-046).
    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 
proposed rule as a percentage of sales and determines whether the ratio 
exceeds some level (e.g., 1 percent or 3 percent).\137\ 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 VIII-5 of this preamble.
---------------------------------------------------------------------------

    \137\ EPA's RFA guidance for rule writers suggests the ``sales'' 
test continues to be the preferred quantitative metric for economic 
impact screening analysis.

                                                         Table VIII-5. Estimated Cost-To-Sales Ratios by Industry and Enterprise Size a
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                                                                   Owned by enterprises with:
                                                                                             SBA Size    Average               -----------------------------------------------------------------
                                                                                             standard    cost per      All                              100 to     500 to     750 to    1,000 to
                   Industry                      NAICS            NAICS description         (effective    entity   enterprises     <20      20 to 99     499        749        999       1,499
                                                                                             March 11,   ($1,000/      (%)      Employees  Employees  Employees  Employees  Employees  Employees
                                                                                               2008)     entity)                    f         (%)        (%)        (%)        (%)        (%)
------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Oil and Gas Extraction.......................        211  Oil & gas extraction............         500        $23         0.1         1.5        0.1        0.1        0.0        0.0        0.0
Petroleum and Coal Products..................        212  Mining (except oil & gas).......         500         10         0.1         0.9        0.2        0.1        0.1        0.1        0.1
SF6 from Electrical Systems..................        221  Utilities.......................       (\b\)          1         0.0         0.1        0.0        0.0        0.0        0.0        0.0
Pulp & Paper Manufacturing...................        322  Paper mfg.......................  500 to 750         22         0.1         1.3        0.3        0.1        0.1        0.0        0.0
Petroleum and Coal Products..................        324  Petroleum & coal products mfg...       (\c\)         16         0.0         0.4        0.1        0.1        0.0        0.1        0.0
Chemical Manufacturing.......................        325  Chemical mfg....................      500 to         12         0.0         0.6        0.1        0.0        0.0        0.0        0.0
                                                                                                 1,000
Cement & Other Mineral Production............        327  Nonmetallic mineral product mfg.      500 to         51         0.8         4.9        1.0        0.5        0.4        0.6        0.4
                                                                                                 1,000
Primary Metal Manufacturing..................        331  Primary metal mfg...............      500 to        112         0.4         9.1        1.4        0.4        0.2        0.1        0.2
                                                                                                 1,000
Computer and Electronic Product Manufacturing        334  Computer & electronic product         500 to         37         0.1         2.9        0.5        0.1        0.1        0.1        0.1
                                                           mfg.                                  1,000
Electrical Equipment, Appliance, and                 335  Electrical equipment, appliance,      500 to         37         0.2         2.9        0.5        0.2        0.1        0.1        0.1
 Component Manufacturing.                                  & component mfg.                      1,000
Oil & Natural Gas Transportation.............        486  Pipeline transportation.........       (\d\)         12         0.1         0.1        0.4        0.4         NA         NA         NA

[[Page 16601]]

 
Waste Management and Remediation Services....        562  Waste management & remediation         (\e\)          6         0.2         0.9        0.1        0.1        0.1        0.0        0.1
                                                           services.
Adipic Acid..................................     325199  All other basic organic chemical       1,000         24         0.0         0.9        0.3        0.1         NA        0.0         NA
                                                           mfg.
Ammonia......................................     325311  Nitrogenous fertilizer mfg......       1,000         19         0.1         1.0        0.6         NA         NA         NA         NA
Cement.......................................     327310  Cement mfg......................         750         65         0.2         2.1        1.6        0.3         NA         NA        0.1
Ferroalloys..................................     331112  Electrometallurgical ferroalloy          750         28         0.0          NA         NA         NA         NA         NA         NA
                                                           product mfg.
Glass........................................       3272  Glass & glass product mfg.......      500 to         11         0.1         1.7        0.2        0.1        0.0        0.1        0.0
                                                                                                 1,000
Hydrogen Production..........................     325120  Industrial gas mfg..............       1,000          3         0.0         0.6        0.0        0.1         NA         NA         NA
Iron and Steel...............................     331112  Electrometallurgical ferroalloy          750        150         0.3          NA         NA         NA         NA         NA         NA
                                                           product mfg.
Lead Production..............................       3314  Nonferrous metal (except              750 to         23         0.1         1.5        0.2        0.1         NA         NA        0.1
                                                           aluminum) production &                1,000
                                                           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\)         19         0.0         0.3        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         22         0.0         1.5         NA         NA         NA         NA         NA
Refineries...................................     324110  Petroleum refineries............       (\c\)         24         0.0         0.4        0.0        0.0        0.0         NA         NA
Silicon Carbide..............................     327910  Abrasive product mfg............         500         11         0.1         0.8        0.2        0.1         NA         NA         NA
Soda Ash Manufacturing.......................       3251  Basic chemical mfg..............      500 to          9         0.0         0.3        0.1        0.0        0.0        0.0        0.0
                                                                                                 1,000
Titanium Dioxide.............................     325188  All other basic inorganic              1,000          9         0.0         0.7        0.4        0.1         NA         NA         NA
                                                           chemical mfg.
Zinc Production..............................       3314  Nonferrous metal (except              750 to         19         0.1         1.2        0.1        0.1         NA         NA        0.1
                                                           aluminum) production &                1,000
                                                           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 4 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.


[[Page 16602]]

    EPA was not able to calculate a cost-to-sales ratio for manure 
management (NAICS 112) as SUSB (SBA, 2008a) data does 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 
$0.2 million with an average cost per ton reported of $0.14.
    As shown, the cost-to-sales ratios are less than 1 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 these small 
businesses would be covered by the rule, we performed several case 
studies for manufacturing industries where the cost-to-receipt ratio 
exceeded 1 percent. For each industry, we used and applied emission 
data from a recent study examining emission thresholds.\138\ This study 
provides industry-average CO2 emission rates (e.g., tons per 
employee) for these manufacturing industries.
---------------------------------------------------------------------------

    \138\ 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 1 percent.
    For the other enterprise categories identified with ratios between 
1 percent and 3 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 would 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 proposed 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 1 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 proposed 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 proposed 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 $17,047 per local government. Thus, for the 
smallest group of local governments (<10,000 people), cost-to-revenue 
ratio would be 0.8 percent. For the larger group of governments less 
than 50,000, the cost-to-revenue ratio is 0.3 percent.

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

    EPA examined the potential benefits of the GHG reporting rule. 
Because the benefits of a reporting system are based on their relevance 
to policy making, transparency issues, and market efficiency, and 
therefore benefits would be 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 would 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 would 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 would 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. Such monitoring 
allows for inclusion of standardized GHG data into environmental 
management systems, providing the necessary information to achieve and 
disseminate their environmental achievements.
    Standardization would 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 would also 
allow for facilities to benchmark themselves against similar facilities 
to understand better their relative standing within their industry.

IX. 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

[[Page 16603]]

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-2008-0508-002 and is briefly 
summarized in Section VIII of this preamble.

B. Paperwork Reduction Act

    The information collection requirements in this proposed rule have 
been submitted for approval to the OMB under the Paperwork Reduction 
Act, 44 U.S.C. 3501 et seq. The ICR document prepared by EPA has been 
assigned EPA ICR number 2300.01.
    EPA plans to collect complete and accurate economy-wide data on 
facility-level greenhouse gas emissions. Accurate and timely 
information on greenhouse gas 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 greenhouse gas 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 information collected under 
CAA sections 114 and 208 cannot be claimed as CBI and will be made 
public.
    The projected cost and hour burden for non-federal respondents is 
$143 million and 1.63 million hours per year. The estimated average 
burden per response is 2 hours; the proposed frequency of response is 
annual for all respondents that must comply with the proposed 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 18,775. 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 $20.7 million), a 
total operation and maintenance component (averaging $22.4 million per 
year), and a labor cost component (averaging $100.0 million per year). 
Burden is defined at 5 CFR 1320.3(b). These cost numbers differ from 
those shown elsewhere in the RIA for several reasons:
     ICR costs represent the average cost over the first three 
years of the rule, but costs are reported elsewhere in the RIA for the 
first year of the rule and for subsequent years of the rule;
     The costs of reporting electricity purchases have been 
excluded from the ICR, but are still reported in the RIA, although 
electricity use reporting has been removed from the proposed rule and 
EPA is soliciting comment on it (see Section 4.2.2, pg 4-18); and
     The first-year costs of coverage determination, estimated 
to be $867.60 per facility for approximately 16,800 facilities that 
ultimately determine they do not have to report, are included in the 
ICR but not in the RIA (see Section 4.2.2, pg 4-18). These costs, 
averaged over 3 years, are $4.87 million incurred by an average of 
5,613 respondents per year.
    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. To comment on the 
Agency's need for this information, the accuracy of the provided burden 
estimates, and any suggested methods for minimizing respondent burden, 
EPA has established a public docket for this rule. Submit any comments 
related to the ICR to EPA and OMB. See ADDRESSES section at the 
beginning of this notice for where to submit comments to EPA. Send 
comments to OMB at the Office of Information and Regulatory Affairs, 
Office of Management and Budget, 725 17th Street, NW., Washington, DC 
20503, Attention: Desk Office for EPA. Since OMB is required to make a 
decision concerning the ICR between 30 and 60 days after April 10, 
2009, a comment to OMB is best assured of having its full effect if OMB 
receives it by May 11, 2009. The final rule will respond to any OMB or 
public comments on the information collection requirements contained in 
this proposal.

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 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 proposed rule on 
small entities, I certify that this action will not have a significant 
economic impact on a substantial number of small entities. The small 
entities directly regulated by this proposed 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, or because they have 
stationary combustion units onsite that emit GHGs that must be 
reported. Small governments and small non-profits are generally 
affected because they have regulated landfills or stationary combustion 
units onsite, or because they own a 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 
proposed rule as a percentage of sales and determines whether the ratio 
exceeds some level (e.g., 1 percent or 3 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 VIII-5 of this preamble, the cost-

[[Page 16604]]

to-sales ratios are less than 1 percent for establishments owned by 
small businesses that EPA considers most likely to be covered by the 
reporting program.\139\
---------------------------------------------------------------------------

    \139\ 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 proposed rule will 
not have a significant economic impact on a substantial number of small 
entities. See Table VIII-4 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 1 percent of average revenues for the smallest 
category of governments (those with fewer than 10,000 people).
    Although this proposed 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, 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 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. EPA maintains an ``open door'' 
policy for stakeholders to provide input on key issues and to help 
inform EPA's understanding of issues, including thresholds for 
reporting and greenhouse gas calculation and reporting methodologies.
    EPA continues to be interested in the potential impacts of the 
proposed rule on small entities and welcomes comments on issues related 
to such impacts.

D. Unfunded Mandates Reform Act (UMRA)

    Title II of the UMRA 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, biologic and fugitive). 
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 $14.1 
million per year, based on average costs over the first three years of 
the rule. 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 air pollution control 
agencies, and other State and local government organizations. EPA 
contacted several States and State and regional organizations already 
involved in greenhouse gas emissions reporting. EPA also conducted 
several conference calls with Tribal organizations. For example, EPA 
staff provided information to tribes through conference calls with 
multiple Tribal working groups and organizations at EPA and through 
individual calls with two Tribal board members of TRI. In addition, EPA 
held meeting and conference calls with groups such as TRI, 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.
    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 proposed GHG reporting rule, and has 
concluded that the costs will fall mainly on the private sector 
(approximately $131 million), with some costs incurred by State, local, 
and Tribal governments that must report their emissions (less than 
$12.4 million) that own and operate stationary combustion units, 
landfills, or natural gas local distribution companies (LDCs). EPA 
estimates that an additional 1,979 facilities owned by state, local, or 
tribal governments will incur approximately $1.7 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 proposed 
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 $145 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% of company sales in affected industries. These costs are broadly 
distributed to a variety of economic sectors and represent 
approximately 0.001 percent of 2007 Gross Domestic Product; overall, 
EPA does not believe the proposed rule will have a significant 
macroeconomic

[[Page 16605]]

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 proposed rulemaking. EPA further expects that benefits 
of the proposed rule will include more and better information for EPA 
and the private sector about emissions of GHGs. This improved 
information would 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, 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 greenhouse gases above threshold levels such as a landfill or 
large stationary combustion source. 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 proposed 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 proposal relates to existing State programs, please see 
Section II of this preamble.
    This regulation applies directly to facilities that supply fuel or 
chemicals that when used emit greenhouse gases or facilities that 
directly emit greenhouses gases. It does not apply to governmental 
entities unless the government entity owns a facility that directly 
emits greenhouse gases above threshold levels such as a landfill or 
large stationary combustion source, so relatively few government 
facilities would be affected. This regulation also does not limit the 
power of States or localities to collect GHG data and/or regulate GHG 
emissions. Thus, EO 13132 does not apply to this 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 solicits comments on this proposed rule 
from State and local officials.

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

    This proposed rule is not expected to have Tribal implications, as 
specified in EO 13175 (65 FR 67249, November 9, 2000). This regulation 
applies directly to facilities that supply fuel or chemicals that when 
used emit greenhouse gases or facilities that directly emit greenhouses 
gases. Facilities expected to be affected by the proposed rule are not 
expected to be owned by Tribal governments. Thus, Executive Order 13175 
does not apply to this proposed rule.
    Although EO 13175 does not apply to this proposed 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. 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 specifically solicits additional comment on this proposed rule 
from Tribal officials.

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 proposed 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 proposal 
relates to monitoring, reporting and recordkeeping at facilities that 
supply fuel or chemicals that when used emit greenhouse gases 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 proposed rulemaking involves technical standards. EPA proposes 
to use more than 40 voluntary consensus

[[Page 16606]]

standards from six different voluntary consensus standards bodies: 
ASTM, ASME, ISO, Gas Processors Association, American Gas Association, 
and American Petroleum Institute. These voluntary consensus standards 
will help facilities monitor, report, and keep records of greenhouse 
gas emissions. No new test methods were developed for this proposed 
rule. Instead, from existing rules for source categories and voluntary 
greenhouse gas programs, EPA identified existing means of monitoring, 
reporting, and keeping records of greenhouse gas 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 proposed rule and are available as specified in proposed 40 
CFR 98.7.
    By incorporating voluntary consensus standards into this proposed 
rule, EPA is both meeting the requirements of the NTTAA and presenting 
multiple options and flexibility for measuring greenhouse gas 
emissions.
    EPA welcomes comments on this aspect of the proposed rulemaking 
and, specifically, invites the public to identify potentially-
applicable voluntary consensus standards and to explain why such 
standards should be used in this regulation.

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

    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 proposed rule will not have 
disproportionately high and adverse human health or environmental 
effects on minority or low-income populations because it does not 
affect the level of protection provided to human health or the 
environment. This proposed 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.

List of Subjects

40 CFR Part 86

    Environmental protection, Administrative practice and procedure, 
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 600

    Administrative practice and procedure, Electric power, Fuel 
economy, Incorporation by reference, Labeling, 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: March 10, 2009.
Lisa P. Jackson,
Administrator.
    For the reasons stated in the preamble, title 40, chapter I, of the 
Code of Federal Regulations is proposed to be amended as follows:

PART 86--[AMENDED]

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

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

Subpart A--[Amended]

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


Sec.  86.007-23  Required data.

* * * * *
    (n) Starting in the 2011 model year for heavy-duty engines, measure 
CO2, N2O, and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065. 
Report these values in your application for certification. 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/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.

[[Page 16607]]

    (3) Round CH4 to the nearest 0.001g/kW-hr.
    3. Section 86.078-3 is amended by removing the paragraph (a) 
designation 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 B--[Amended]

    4. A new Sec.  86.165-11 is added to read as follows:


Sec.  86.165-11  Air Conditioning Idle Test Procedure.

    (a) Applicability. This section describes procedures for 
determining air conditioning-related CO2 emissions from 2012 
and later model year light-duty vehicles, light-duty trucks, and 
medium-duty passenger vehicles.
    (b) Overview. The test consists of a brief period to stabilize the 
vehicle at idle, followed by a ten-minute period of idle when 
CO2 emissions are measured without any climate control 
systems operating; the test concludes with a ten-minute period when 
CO2 emissions are measured with the air conditioning system 
operating. This test is designed to determine the air conditioning-
related CO2 emission value, in grams per minute per cubic 
foot of interior volume. If engine stalling occurs during cycle 
operation, follow the provisions of Sec.  86.136-90 to restart the 
test. Measurement instruments must meet the specifications described in 
40 CFR part 1065, subparts C and D.
    (c) Test sequence. Before testing, precondition the vehicle as 
described in Sec.  86.132, then allow the vehicle to idle for not less 
than 1 minute and not more than 5 minutes.
    (1) Connect the vehicle exhaust system to the raw sampling location 
or dilution stage according to 40 CFR 1065.130. For dilution systems, 
dilute the exhaust as described in 40 CFR 1065.140. Continuous sampling 
systems must meet the specifications of 40 CFR 1065.145.
    (2) Test the vehicle in a fully warmed-up condition. If the vehicle 
has soaked for two hours or less since the last exhaust test element, 
preconditioning may consist of a 505, 866, highway, US06, or SC03 test 
cycle. For longer soak periods, precondition the vehicle using one full 
Urban Dynamometer Driving Schedule.
    (3) Immediately after the preconditioning described in paragraph 
(c)(1) of this section, turn off any cooling fans, if present, close 
the vehicle's hood, fully close all the vehicle's windows, ensure that 
all the vehicle's climate control systems are set to full off, start 
the CO2 sampling system, and then idle the vehicle for not 
less than 1 minute and not more than 5 minutes to achieve normal and 
stable idle operation.
    (4) Measure and record the continuous CO2 concentration 
for 10.0 minutes. Measure the CO2 concentration continuously 
using raw or dilute sampling procedures. Multiply this concentration by 
the continuous (raw or dilute) flow rate at the emission sampling 
location to determine the CO2 flow rate. Calculate the 
constituent's cumulative flow rate continuously over the test interval. 
This cumulative value is the total mass of the emitted constituent.
    (5) Within 60 seconds after completing the measurement described in 
paragraph (c)(4) of this section, turn on the vehicle's air 
conditioning system. Set automatic systems to a temperature 9 [deg]F (5 
[deg]C) below the ambient temperature of the test cell. Set manual 
systems to maximum cooling with recirculation turned off. Continue 
idling the vehicle while measuring and recording the continuous 
CO2 concentration for 10.0 minutes as described in paragraph 
(c)(4) of this section.
    (d) Calculations. (1) For the measurement with no air conditioning, 
calculate the CO2 emissions (in grams per minute) by 
dividing the total mass of CO2 from paragraph (c)(4) of this 
section by 10.0.
    (2) For the measurement with air conditioning in operation, 
calculate the CO2 emissions (in grams per minute) by 
dividing the total mass of CO2 from paragraph (c)(5) of this 
section by 10.0.
    (3) Calculate the increased CO2 emissions due to air 
conditioning (in grams per minute) by subtracting the results of 
paragraph (d)(1) of this section from the results of paragraph (d)(2) 
of this section.
    (4) Divide the value from paragraph (d)(3) of this section by the 
interior volume of the vehicle to determine the increase in 
CO2 emissions in grams per minute per cubic foot.
    (e) Reporting. Include the value calculated in paragraph (d)(4) of 
this section in your application for certification.

Subpart E--[Amended]

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


Sec.  86.431-78  Data submission.

* * * * *
    (e) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 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 procedures specified in 40 CFR part 1065 as needed to measure 
N2O, and CH4. Report these values in your 
application for certification. Small-volume manufacturers (as defined 
in Sec.  86.410-2006(e)) may omit this requirement. 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 0.001g/km.

Subpart S--[Amended]

    7. Section 86.1804-01 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  86.1804-01  Acronyms and abbreviations.

* * * * *
* * * * *
    CH4 methane.
* * * * *
    N2O nitrous oxide.
* * * * *
    8. Section 86.1843-01 is amended by adding paragraph (i) to read as 
follows:


Sec.  86.1843-01  General information requirements.

* * * * *
    (i) Air conditioning leakage reporting. Starting in the 2011 model 
year, the manufacturer shall calculate and report a value for the 
annual leakage of refrigerant emissions from the air conditioning 
system for each model type as described in 40 CFR 1064.201. The 
manufacturer shall also report the type of refrigerant and the 
refrigerant capacity for each air conditioning

[[Page 16608]]

system for each model type. The manufacturer shall calculate and report 
these items for each combination of vehicle model type (as defined in 
40 CFR 600.002) and air conditioning system produced. However, 
calculation and reporting of these items for multiple air conditioning 
systems for a given model type is not necessary if air conditioning 
systems are identical with respect to the characteristics identified in 
paragraphs (i)(1) through (8) of this section and they meet the 
quantitative criteria identified in paragraph (i)(9) of this section. 
Consider all the following criteria to determine whether to calculate 
separate leakage rates for different air conditioning systems.
    (1) Compressor type (e.g., belt driven or electric).
    (2) Number and type of rigid pipes and method of connecting 
sections of rigid pipes.
    (3) Number and type of flexible hose and method of connecting 
sections of flexible hose. Consider two hoses to be of a different type 
if they use different materials or if they have a different 
configuration of layers for reducing permeation.
    (4) Number of high-side service ports.
    (5) Number of low-side service ports.
    (6) Number and type of switches, transducers, and expansion valves.
    (7) Number and type of refrigerant control devices.
    (8) Number and type of heat exchangers, mufflers, receiver/driers, 
and accumulators.
    (9) The following quantitative criteria (based on nominal values) 
define operating characteristics for including air conditioning systems 
together:
    (i) Refrigerant mass (rated capacity) of larger system divided by 
refrigerant mass of smaller system at or below 1.1.
    (ii) Total length of rigid pipe in the longer system divided by 
total length of rigid pipe in the shorter system at or below 1.1.
    (iii) Total length of flexible hose in the longer system divided by 
total length of flexible hose in the shorter system at or below 1.1.
    9. Section 86.1844-01 is amended by adding paragraph (j) to read as 
follows:


Sec.  86.1844-01  Information requirements: Application for 
certification and submittal of information upon request.

* * * * *
    (j) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 with each certification test on an 
emission data vehicle. Do not apply deterioration factors to the 
results. Use the procedures specified in 40 CFR part 1065 as needed to 
measure N2O, and CH4. Report these values in your 
application for certification. Use the same measurement methods as for 
your other results to report a single value for CO2, 
N2O, and CH4 for each test. Round the final 
values as follows:
    (1) Round CO2 to the nearest 1 g/mi.
    (2) Round N2O to the nearest 0.001 g/mi.
    (3) Round CH4 to the nearest 0.001g/mi.

PART 87--[AMENDED]

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

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

Subpart A--[Amended]

    11. Section 87.2 is amended by adding the abbreviations 
CH4 and CO2 in alphanumeric order to read as 
follows:


Sec.  87.2  Acronyms and abbreviations.

* * * * *
    CH4 methane.
* * * * *
    CO2 carbon dioxide.
* * * * *
    12. 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 in the 2011 model year, measure CH4 with 
each certification test. Use good engineering judgment to determine 
CH4 emissions using a nonmethane cutter or gas chromatograph 
as described in 40 CFR 1065.265 and 1065.267. Report CH4 and 
CO2 values along with your emission levels of regulated 
pollutants. Round the final values as follows:
    (1) Round CO2 to the nearest 1 g/kilonewton rO.
    (2) Round CH4 to the nearest 0.01g/g/kilonewton rO.

PART 89--[AMENDED]

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

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

Subpart A--[Amended]

    14. Section 89.3 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  89.3  Acronyms and abbreviations.

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

Subpart B--[Amended]

    15. 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, N2O, and CH4 as 
specified in Sec.  89.407(d)(1);
* * * * *

Subpart E--[Amended]

    16. 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. Starting in the 2011 model year, 
also measure N2O, and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065. 
Small-volume engine manufacturers (as defined in 40 CFR 1039.801) may 
omit N2O, and CH4 measurements. 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:
    (i) Round CO2 to the nearest 1 g/kW-hr.
    (ii) Round N2O to the nearest 0.001 g/kW-hr.
    (iii) Round CH4 to the nearest 0.001g/kW-hr.
* * * * *

PART 90--[AMENDED]

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

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

Subpart A--[Amended]

    18. Section 90.5 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:

[[Page 16609]]

Sec.  90.5  Acronyms and abbreviations.

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

Subpart B--[Amended]

    19. 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, N2O, and CH4 as 
specified in Sec.  90.409(c)(1);
* * * * *

Subpart E--[Amended]

    20. 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. Starting in the 2011 model year, 
also measure N2O, and CH4 with each low-hour 
certification test using the procedures specified in 40 CFR part 1065. 
Small-volume engine manufacturers may omit N2O, and 
CH4 measurements. 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:
    (i) Round CO2 to the nearest 1 g/kW-hr.
    (ii) Round N2O to the nearest 0.001 g/kW-hr.
    (iii) Round CH4 to the nearest 0.001g/kW-hr.
* * * * *

PART 94--[AMENDED]

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

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

Subpart A--[Amended]

    22. Section 94.3 is amended by adding the abbreviations 
CH4 and N2O in alphanumeric order to read as 
follows:


Sec.  94.3  Abbreviations.

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

Subpart B--[Amended]

    22. 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. Starting in the 2011 model year, measure 
CO2, N2O, and CH4 as specified in 40 
CFR 1042.235.


Sec.  94.109  [Amended]

    23. Section 94.109 is amended by adding paragraph (d) to read as 
follows:

Subpart C--[Amended]

    24. 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, N2O, and CH4 as 
specified in 40 CFR 89.407(d)(1) 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 the requirement to measure 
and report N2O, and CH4.
* * * * *
    25. 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 Do I need to 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 do I submit my report?
98.6 What definitions do I need to understand?
98.7 What standardized methods are incorporated by reference into 
this part?
98.8 What are the compliance and enforcement provisions of this 
part?
Table A-1 of Subpart A--Global Warming Potentials (100-Year Time 
Horizon)
Table A-2 of Subpart A--Units of Measure Conversions
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 of Subpart C--Default CO2 Emission Factors and 
High Heat Values for Various Types of Fuel
Table C-2 of Subpart C--Default CO2 Emission Factors for 
the Combustion of Alternative Fuels
Table C-3 of Subpart C--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.
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.

[[Page 16610]]

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--Electronics Manufacturing
98.90 Definition of the source category.
98.91 Reporting threshold.
98.92 GHGs to report.
98.93 Calculating GHG emissions.
98.94 Monitoring and QA/QC requirements.
98.95 Procedures for estimating missing data.
98.96 Data reporting requirements.
98.97 Records that must be retained.
98.98 Definitions.
Table I-1 of Subpart I--F-GHGs Typically Used by the Electronics 
Industry
Table I-2 of Subpart I--Default Emission Factors for Semiconductor 
and MEMs Manufacturing
Table I-3 of Subpart I--Default Emission Factors for LCD 
Manufacturing
Table I-4 of Subpart I--Default Emission Factors for PV 
Manufacturing
Subpart J--Ethanol Production
98.100 Definition of the source category.
98.101 Reporting threshold.
98.102 GHGs to report.
98.103 Definitions.
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 of Subpart K--Electric Arc Furnace (EAF) CH4 
Emission Factors
Subpart L--Fluorinated Greenhouse Gas Production
98.120 Definition of the source category.
98.121 Reporting threshold.
98.122 GHGs to report.
98.123 Calculating GHG emissions.
98.124 Monitoring and QA/QC requirements.
98.125 Procedures for estimating missing data.
98.126 Data reporting requirements.
98.127 Records that must be retained.
98.128 Definitions.
Subpart M--Food Processing
98.130 Definition of the source category.
98.131 Reporting threshold.
98.132 GHGs to report.
98.133 Definitions.
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 of Subpart N--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.
Table O-1 of Subpart O--Emission Factors for Equipment Leaks
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.
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.
98.184 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 of Subpart S--Basic Parameters for the Calculation of 
Emission Factors for Lime Production
Subpart T--Magnesium Production
98.200 Definition of source category.
98.201 Reporting threshold.
98.202 GHGs to report.
98.203 Calculating GHG emissions.
98.204 Monitoring and QA/QC requirements.
98.205 Procedures for estimating missing data.
98.206 Data reporting requirements.
98.207 Records that must be retained.
98.208 Definitions.
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 of Subpart U--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.
Subpart W--Oil and Natural Gas Systems
98.230 Definition of the source category.
98.231 Reporting threshold.
98.232 GHGs to report.
98.233 Calculating GHG emissions.
98.234 Monitoring and QA/QC requirements.
98.235 Procedures for estimating missing data.
98.236 Data reporting requirements.
98.236 Records that must be retained.
98.237 Definitions.
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.

[[Page 16611]]

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.
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 of Subpart AA--Kraft Pulping Liquor Emissions Factors for 
Biomass-Based CO2, CH4, and N2O
Table AA-2 of Subpart AA--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.
98.283 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--Sulfur Hexafluoride (SF6) From Electrical Equipment
98.300 Definition of the source category.
98.301 Reporting threshold.
98.302 GHGs to report.
98.303 Calculating GHG emissions.
98.304 Monitoring and QA/QC requirements.
98.305 Procedures for estimating missing data.
98.306 Data reporting requirements.
98.307 Records that must be retained.
98.308 Definitions.
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--Underground Coal Mines
98.320 Definition of the source category.
98.321 Reporting threshold.
98.322 GHGs to report.
98.323 Calculating GHG emissions.
98.324 Monitoring and QA/QC requirements.
98.325 Procedures for estimating missing data.
98.326 Data reporting requirements.
98.327 Records that must be retained.
98.328 Definitions.
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--Landfills
98.340 Definition of the source category.
98.341 Reporting threshold.
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 of Subpart HH--Emissions Factors, Oxidation Factors and 
Methods
Table HH-2 of Subpart HH--U.S. Per Capita Waste Disposal Rates
Subpart II--Wastewater Treatment
98.350 Definition of source category.
98.351 Reporting threshold.
98.352 GHGs to report.
98.353 Calculating GHG emissions.
98.354 Monitoring and QA/QC requirements.
98.355 Procedures for estimating missing data.
98.356 Data reporting requirements.
98.357 Records that must be retained.
98.358 Definitions.
Table II-1 of Subpart II--Emission Factors
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 of Subpart JJ--Waste Characteristics Data
Table JJ-2 of Subpart JJ--Methane Conversion Factors
Table JJ-3 of Subpart JJ--Collection Efficiencies of Anaerobic 
Digesters
Table JJ-4 of Subpart JJ--Nitrous Oxide Emission Factors (kg 
N2O-N/kg Kjdl N)
Subpart KK--Suppliers of Coal
98.370 Definition of the source category.
98.371 Reporting threshold.
98.372 GHGs to report.
98.373 Calculating GHG emissions.
98.374 Monitoring and QA/QC requirements.
98.375 Procedures for estimating missing data.
98.376 Data reporting requirements.
98.377 Records that must be retained.
98.378 Definitions.
Table KK-1 of Subpart KK--Default Carbon Content of Coal for Method 
3 (CO2 lbs/MMBtu1)
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 of Subpart MM--Default CO2 Factors for 
Petroleum Products 1,2
Table MM-2 of Subpart MM--Default CO2 Factors for Natural 
Gas Liquids
Table MM-3 of Subpart MM--Default CO2 Factors for Biomass 
Products and Feedstock
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.

[[Page 16612]]

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 of Subpart NN--Default Factors for Calculation 
Methodology 1 of This Subpart
Table NN-2 of Subpart NN--Lookup Default Values for Calculation 
Methodology 2 of This Subpart
Subpart OO--Suppliers of Industrial Greenhouse Gases
98.410 Definition of the source category.
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 GHG emissions.
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) emissions 
reporting requirements for certain facilities that directly emit GHG as 
well as for fossil fuel suppliers and industrial GHG suppliers.
    (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  Do I need to report?

    (a) The GHG emissions reporting requirements, and related 
monitoring, recordkeeping, and verification requirements, of this part 
apply to the owners and operators of any facility 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 of the source categories listed in 
this paragraph in any calendar year starting in 2010. For these 
facilities, the GHG emission report must cover all sources in any 
source category for which calculation methodologies are provided in 
subparts B through JJ of this part.
    (i) Electricity generating facilities that are subject to the Acid 
Rain Program, or that contain electric generating units that 
collectively emit 25,000 metric tons CO2e or more per year.
    (ii) Adipic acid production.
    (iii) Aluminum production.
    (iv) Ammonia manufacturing.
    (v) Cement production.
    (vi) Electronics--Semiconductor, microelectricomechanical system 
(MEMS), and liquid crystal display (LCD) manufacturing facilities with 
an annual production capacity that exceeds any of the thresholds listed 
in this paragraph.
    (A) Semiconductors: 1,080 m\2\ silicon.
    (B) MEMS: 1,020 m\2\ silicon.
    (C) LCD: 235,700 m\2\ LCD.
    (vii) Electric power systems that include electrical equipment with 
a total nameplate capacity that exceeds 17,820 lbs (7,838 kg) of 
SF6 or perfluorocarbons (PFCs).
    (viii) HCFC-22 production.
    (ix) 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.
    (x) Lime manufacturing.
    (xi) Nitric acid production.
    (xii) Petrochemical production.
    (xiii) Petroleum refineries.
    (xiv) Phosphoric acid production.
    (xv) Silicon carbide production.
    (xvi) Soda ash production.
    (xvii) Titanium dioxide production.
    (xviii) Underground coal mines that are subject to quarterly or 
more frequent sampling by MSHA of ventilation systems.
    (xix) Municipal landfills that generate CH4 in amounts 
equivalent to 25,000 metric tons CO2e or more per year.
    (xx) Manure management systems that emit CH4 and 
N2O in amounts equivalent to 25,000 metric tons 
CO2e or more per year.
    (2) Any facility 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 (a)(2) and that are located at the 
facility in any calendar year starting in 2010. For these facilities, 
the GHG emission report must cover all source categories for which 
calculation methodologies are provided in subparts B through JJ of this 
part.
    (i) Electricity generation.
    (ii) Electronics--photovoltaic manufacturing.
    (iii) Ethanol production.
    (iv) Ferroalloy production.
    (v) Fluorinated greenhouse gas production.
    (vi) Food processing.
    (vii) Glass production.
    (viii) Hydrogen production.
    (ix) Iron and steel production.
    (x) Lead production.
    (xi) Magnesium production.
    (xii) Oil and natural gas systems.
    (xiii) Pulp and Paper Manufacturing.
    (xiv) Zinc production.
    (xv) Industrial landfills.
    (xvi) Wastewater treatment.
    (3) Any 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 GHG emission report must cover emissions from 
stationary fuel combustion sources only. For 2010 only, the facilities 
may submit an abbreviated emissions report according to Sec.  98.3(d).
    (i) The facility does not contain any source category designated in 
paragraphs (a)(1) and (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 from all stationary fuel combustion sources.
    (4) Any supplier of any of the products listed in this paragraph 
(a)(4) in any calendar year starting in 2010. For these suppliers, the 
GHG emissions report must cover all applicable products for which 
calculation methodologies are provided in subparts KK through PP of 
this part.
    (i) Coal.
    (ii) Coal-based liquid fuels.
    (iii) Petroleum products.
    (iv) Natural gas and natural gas liquids.
    (v) Industrial greenhouse gases, as specified in either paragraph 
(a)(4)(v)(A) or (B) of this section:
    (A) All producers of industrial greenhouse gases.
    (B) Importers of industrial greenhouse gases with total bulk 
imports that exceed 25,000 metric tons CO2e per year.
    (C) Exporters of industrial greenhouse gases with total bulk 
exports that exceed 25,000 metric tons CO2e per year.
    (vi) Carbon dioxide, as specified in either paragraph (a)(4)(vi)(A) 
or (B) of this section.
    (A) All producers of carbon dioxide.
    (B) Importers of CO2 or a combination of CO2 
and other industrial GHGs with total bulk imports that exceed 25,000 
metric tons CO2e per year.
    (C) Exporters of CO2 or a combination of CO2 
and other industrial GHGs with

[[Page 16613]]

total bulk exports that exceed 25,000 metric tons CO2e per 
year.
    (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 
CO2e emissions, as described in paragraphs (b)(1) through 
(4) of this section.
    (1) Estimate the annual emissions of CO2, 
CH4, N2O, and fluorinated GHG (as defined in 
Sec.  98.6) in metric tons from stationary fuel combustion units, 
miscellaneous uses of carbonate, and any applicable source category 
listed in paragraph Sec.  98.2(a)(2). The GHG emissions shall be 
calculated using the methodologies specified in each applicable 
subpart. For this calculation, facilities with industrial landfills 
must use the CH4 generation calculation methodology in 
subpart HH of this part.
    (2) For stationary combustion units, calculate the annual 
CO2 emissions in metric tons using any appropriate method 
specified in Sec.  98.33(a). Calculate the annual CH4 and 
N2O emissions from the stationary combustion sources in 
metric tons using Equation C-9 in Sec.  98.33(c). Carbon dioxide 
emissions from the combustion of biogenic fuels shall be excluded from 
the calculations. In using Equations C-2a and C-9 in Sec.  98.33, the 
high heat value for all types of fuel shall be determined monthly.
    (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), (2), and 
(3) of this section for each GHG and calculate metric tons of 
CO2e using Equation A-1.
[GRAPHIC] [TIFF OMITTED] TP10AP09.000

Where:

CO2e = Carbon dioxide equivalent, metric tons/year.
GHGi = Mass emissions of each greenhouse gas emitted, 
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, capture of CO2 for transfer off site must not be 
considered.
    (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, the owner or 
operator shall calculate CO2, CH4, N2O 
emissions from all stationary combustion units using 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 CO2e per year threshold for importers and exporters of 
industrial greenhouse gases under paragraph (a)(4) of this section, the 
owner or operator shall calculate the total annual CO2e of 
all the industrial GHGs that the company imported and the total annual 
CO2e of all the industrial GHGs that the company exported 
during the reporting year, as described in paragraphs (d)(1) through 
(d)(3) of this section.
    (1) Calculate the mass in metric tons per year of CO2, 
N2O, and each fluorinated GHG (as defined in Sec.  98.6) 
imported and the mass in metric tons per year of CO2, 
N2O, and fluorinated GHG exported during the year. The 
masses shall be calculated using the methodologies specified in subpart 
OO of this part.
    (2) Convert the mass of each GHG imported and each GHG exported 
from paragraph (d)(1) of this section to metric tons of CO2e 
using Equation A-1 of Sec.  98.3.
    (3) Sum the total annual metric tons of CO2e in 
paragraph (d)(2) of this section for all imported GHGs. Sum the total 
annual metric tons of CO2e in paragraph (d)(2) of this 
section for all exported GHGs.
    (e) If a capacity or generation reporting threshold in paragraph 
(a)(1) of this section applies, the owner or operator shall review the 
appropriate records to determine whether the threshold has been 
exceeded.
    (f) Except as provided in paragraph (g) of this section, the owners 
and operators of a facility or supplier that does not meet the 
applicability requirements of paragraph (a) of this section are not 
required to submit an emission report for the facility or supplier. 
Such owners and operators must reevaluate the applicability to this 
part to the facility or supplier (which reevaluation must include the 
revising of any relevant emissions calculations or other calculations) 
whenever there is any change to the facility or supplier that could 
cause the 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.
    (g) Once a facility or supplier is subject to the requirements of 
this part, the owners and operators of the facility or supply operation 
must continue for each year thereafter to comply with all requirements 
of this part, including the requirement to submit GHG emission reports, 
even if the facility or supplier does not meet the applicability 
requirements in paragraph (a) of this section in a future year. If a 
GHG emission source in a future year through change of ownership 
becomes part of a different facility that has not previously met, and 
does not in that future year meet, the applicability requirements of 
paragraph (a) of this section; the owner or operator shall comply with 
the requirements of this part only with regard to that source, 
including the requirement to submit GHG emission reports.
    (h) 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 emissions reports to the 
Administrator, as specified in paragraphs (a) through (g) of this 
section.
    (a) General. You must collect emissions data, calculate GHG 
emissions, and follow the procedures for quality assurance, missing 
data, recordkeeping, and reporting that are specified in each relevant 
subpart of this part.
    (b) Schedule. Unless otherwise specified in subparts B through PP, 
you must submit an annual GHG emissions report no later than March 31 
of each calendar year for GHG emissions in the previous calendar year.
    (1) For existing facilities that commenced operation before January 
1, 2010, you must report emissions for calendar year 2010 and each 
subsequent calendar year.
    (2) For new facilities that commence operation on or after January 
1, 2010, you must report emissions for the first calendar year in which 
the facility operates, 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.

[[Page 16614]]

    (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, you must 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. 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 emissions report shall contain the 
following information:
    (1) Facility name or supplier name (as appropriate), street 
address, physical address, and Federal Registry System identification 
number.
    (2) Year covered by the report.
    (3) Date of submittal.
    (4) Annual emissions of CO2, CH4, 
N2O, and each fluorinated GHG. Emissions must be calculated 
assuming no capture of CO2 and reported at the following 
levels:
    (i) Total facility emissions aggregated 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) Total emissions aggregated 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.
    (iii) Emissions from each applicable source category or supply 
category in subparts C through PP of this part, expressed in metric 
tons of each GHG.
    (iv) Emissions and other data for individual units, processes, 
activities, and operations as specified for each source category in the 
``Data reporting requirements'' section of each applicable subpart of 
this part.
    (5) Total electricity generated onsite in kilowatt hours.
    (6) Total pounds of synthetic fertilizer produced at the facility 
and total nitrogen contained in that fertilizer.
    (7) Total annual mass of CO2 captured in metric tons.
    (8) 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) Abbreviated emissions report. 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 is subject to 
Sec.  98.2(a)(3) may submit an abbreviated GHG emissions report for the 
facility for emissions in 2010. The abbreviated report must be 
submitted by March 31, 2011. An owner or operator that submits an 
abbreviated report for a facility in 2011 must submit a full GHG 
emissions report according to the requirements of paragraph (c) of this 
section for each calendar year thereafter. The abbreviated facility 
report must include the following information:
    (1) Facility name, street address, physical address, and Federal 
Registry System identification number.
    (2) The year covered by the report.
    (3) Date of submittal.
    (4) Total facility GHG emissions aggregated for all stationary fuel 
combustion units calculated according to any appropriate method 
specified in Sec.  98.33(a) and expressed in metric tons of 
CO2, CH4, N2O, and CO2e. If 
Equation C-2a or C-9 of subpart C are selected, the high heat value for 
all types of fuel shall be determined monthly.
    (5) 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).
    (e) Emission Calculations. In preparing the GHG emissions report, 
you must use the emissions calculation protocols specified in the 
relevant subparts, except as specified in paragraph (d) of this 
section.
    (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)(5) of this section 
and any other credible evidence, in conjunction with a comprehensive 
review of the emissions 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 
GHG emissions under this part must keep records as specified in this 
paragraph. You must retain all required records for at least 5 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 EPA, the records required under 
this section must be made available to the Administrator. 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. 
The results of all required fuel analyses for high heat value and 
carbon content, the results of all required certification and quality 
assurance tests of continuous monitoring systems and fuel flow meters 
if applicable, and analytical results for the development of site-
specific emissions factors.
    (3) Documentation of the process used to collect the necessary data 
for the GHG emissions calculations.
    (4) The GHG emissions calculations and methods used.
    (5) All emission factors used for the GHG emissions calculations.
    (6) Any facility operating data or process information used for the 
GHG emission calculations.
    (7) Names and documentation of key facility personnel involved in 
calculating and reporting the GHG emissions.
    (8) The annual GHG emissions reports.
    (9) A log book, documenting procedural changes (if any) to the GHG 
emissions accounting methods and changes (if any) to the 
instrumentation critical to GHG emissions calculations.
    (10) Missing data computations.
    (11) A written quality assurance performance plan (QAPP). Upon 
request from regulatory authorities, the owner or operator shall make 
all information that is collected in conformance with the QAPP 
available for review during an audit. Electronic storage of the 
information in the QAPP is permissible, provided that the information 
can be made available in hard copy upon request during an audit. At a 
minimum, the QAPP plan shall include (or refer to separate documents 
that contain) a detailed description of the procedures that are used 
for the following activities:
    (i) Maintenance and repair of all continuous monitoring systems, 
flow meters, and other instrumentation used to provide data for the GHG 
emissions reported under this part. A maintenance log shall be kept.
    (ii) Calibrations and other quality assurance tests performed on 
the continuous monitoring systems, flow meters, and other 
instrumentation used to provide data for the GHG emissions reported 
under this part.

[[Page 16615]]

Sec.  98.4  Authorization and responsibilities of the designated 
representative.

    (a) General. Except as provided under paragraph (f) of this 
section, each owner or operator that is subject to this part, shall 
have one and only one designated representative responsible for 
certifying and submitting GHG emissions reports and any other 
submissions to the Administrator under this part.
    (b) Authorization of a designated representative. The designated 
representative of the facility shall be selected by an agreement 
binding on the owners and operators and shall act in accordance with 
the certification statements in paragraph (i)(4) of this section. The 
designated representative must be an individual having responsibility 
for the overall operation of the facility or activity such as the 
position of the plant manager, operator of a well or a well field, 
superintendent, position of equivalent responsibility, or an individual 
or position having overall responsibility for enviromental matters for 
the company.
    (c) Responsibility of the designated representative. Upon receipt 
by the Administrator of a complete certificate of representation under 
this section, the designated representative of the facility shall 
represent and, by his or her representations, actions, inactions, or 
submissions, legally bind each owner and operator 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 will be accepted until the Administrator has received a complete 
certificate of representation under this section for a designated 
representative of the owner or operator.
    (e) Certification of the GHG emissions report. Each GHG emission 
report and any other submission under this part shall be submitted, 
signed, and certified by the designated representative in accordance 
with 40 CFR 3.10.
    (1) Each such submission shall include the following certification 
statement by the designated representative: ``I am authorized to make 
this submission on behalf of the owners and operators of the facility 
(or supply operation, as appropriate) 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 under this part only if the submission is signed and 
certified in accordance with paragraph (e)(1) of this section.
    (f) Alternate designated representative. A certificate of 
representation under this section may designate an alternate designated 
representative, who may act on behalf of the designated representative. 
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, 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, 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) may be changed at any time upon receipt by the 
Administrator of a superseding complete certificate of representation 
under this section. Notwithstanding any such change, all 
representations, actions, inactions, and submissions by the previous 
designated representative (or alternate designated representative) 
before the time and date when the Administrator receives the 
superseding certificate of representation shall be binding on the new 
designated representative and the owners and operators.
    (h) Changes in owners and operators. In the event a new owner or 
operator is not included in the list of owners and operators in the 
certificate of representation under this section, such new 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, as if the new owner or operator were 
included in such list. Within 30 days following any change in the 
owners and operators, including the addition of a new owner or 
operator, the designated representative or any alternate designated 
representative shall submit a revision to the certificate of 
representation under this section amending the list of owners and 
operators to include the change.
    (i) Certificate of representation. A complete certificate of 
representation for a designated representative or an alternate 
designated representative shall include the following elements in a 
format prescribed by the Administrator:
    (1) Identification of the facility or supply operation 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 supply 
operation.
    (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 that are subject to 
the requirements of 40 CFR 98.3.''
    (ii) ``I certify that I have all the necessary authority to carry 
out my duties and responsibilities under the Mandatory Greenhouse Gas 
Reporting Program on behalf of the owners and operators that are 
subject to the requirements of 40 CFR 98.3 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 that are subject to 
the requirements of 40 CFR 98.3 shall be bound by any order issued to 
me by the Administrator or a court regarding the source or unit.''
    (iv) ``Where there are multiple holders of a legal or equitable 
title to, or a leasehold interest in, a facility (or supply operation 
as appropriate) that is subject to the requirements of 40 CFR 98.3, 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

[[Page 16616]]

each owner and operator that is subject to the requirements of 40 CFR 
98.3.''
    (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 has been 
submitted and received, the Administrator will rely on the certificate 
of representation unless and until a superseding complete certificate 
of representation under this section 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 the 
Mandatory Greenhouse Gas Reporting Program.
    (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.


Sec.  98.5  How do I submit my report?

    Each GHG emissions report for a facility or supplier must be 
submitted electronically on behalf of the owners and operators of that 
facility or supplier by their designated representative, in a format 
specified by the Administrator.


Sec.  98.6  What definitions do I need to understand?

    All terms used in this part shall have the same meaning given in 
the Clean Air Act and in this section.
    Abandoned (closed) mines mean mines that are no longer operational 
(per MSHA definition).
    Absorbent circulation pump means a pump commonly powered by natural 
gas pressure that circulates the absorbent liquid between the absorbent 
regenerator and natural gas contactor.
    Accuracy of a measurement at a specified level (e.g., one percent 
of full scale) means that the mean of repeat measurements made by a 
device or technique has a 95 percent chance of falling within the range 
bounded by the true value plus or minus the specified level.
    Acid gas means hydrogen sulfide (H2S) and carbon dioxide 
(CO2) contaminants that are separated from sour natural gas 
by an acid gas removal process.
    Acid gas removal unit (AGR) means a process unit that separates 
hydrogen sulfide and/or carbon dioxide from sour natural gas using 
liquid or solid absorbents, such as liquid absorbents, solid 
adsorbents, or membrane separators.
    Acid gas removal vent stack fugitive emissions mean the acid gas 
(typically CO2 and H2S) separated from the acid 
gas absorbing medium (most commonly an amine solution) and released 
with methane and other light hydrocarbons to the atmosphere or a flare.
    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.
    Actual conditions mean temperature, pressure and volume at 
measurement conditions of natural gas.
    Actuation means, for the purposes of this rule, an event in which a 
natural gas pneumatically driven valve is opened and/or closed by 
release of natural gas pressure to the atmosphere.
    Administrator means the Administrator of the United States 
Environmental Protection Agency or the Administrator's authorized 
representative.
    AGA means the American Gas Association
    Air injected flare means a flare in which air is blown into the 
base of a flare stack to induce complete combustion of low Btu natural 
gas (i.e., high non-combustible component content).
    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 equipment designed and operated for 
waste stabilization by the microbial reduction of complex organic 
compounds to CO2 and CH4, which is captured and 
flared or used as a fuel.
    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.
    Anti-static wrap means wrap used to assist the process of ensuring 
that all fugitive emissions from a single source are captured and 
directed to a measurement instrument.
    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.
    ASME means the American Society of Mechanical Engineers.
    ASTM means the American Society of Testing and Materials.
    B0 means the maximum CH4 producing capacity of a waste 
stream, kg CH4/kg COD.
    Backpressure means impeding the natural atmospheric release of 
fugitive emissions by enclosing the release with a lower capacity 
sampling device and altering natural flow.
    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.
    Biodiesel means any liquid biofuel suitable as a diesel fuel 
substitute or a diesel fuel additive or extender. Biodiesel fuels are 
usually made from agricultural oils or from animal tallow.
    Biogenic CO2 means carbon dioxide emissions generated as the result 
of biomass combustion.
    Biomass means non-fossilized and biodegradable organic material 
originating from plants, animals and 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

[[Page 16617]]

plant and is used for the production of molten iron from iron ore 
pellets and other iron bearing materials.
    Bleed rate means the rate at which natural gas flows continuously 
or intermittently from a process measurement instrument to a valve 
actuator controller where it is vented (bleeds) to the atmosphere.
    Blendstocks are naphthas used for blending or compounding into 
finished motor gasoline. These include RBOB (reformulated gasoline for 
oxygenate blending), CBOB (conventional gasoline for oxygebate 
blending), and GTAB (gasoline treated as blendstock).
    Blowdown means manual or automatic opening of valves to relieve 
pressure and or release natural gas from but not limited to process 
vessels, compressors, storage vessels or pipelines by venting natural 
gas to the atmosphere or a flare. This practice is often implemented 
prior to shutdown or maintenance.
    Blowdown vent stack fugitive emissions mean natural gas released 
due to maintenance and/or blowdown operations including but not limited 
to compressor blowdown and Emergency Shut-Down system testing.
    Boil-off gas means natural gas that vaporizes from liquefied 
natural gas in storage tanks.
    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, means the transfer 
of a product inside containers, including but not limited to tanks, 
cylinders, drums, and pressure vessels.
    Butane (C4H10) or n-Butane means the normally gaseous straight-
chain or branch-chain hydrocarbon extracted from natural gas or 
refinery gas streams and is designated in ASTM Specification D1835 and 
Gas Processors Association Specifications for commercial butane. Not 
included in this definition is isobutene, which normally is used for 
feedstock.
    Butylene (C2H8) is an olefinic hydrocarbon 
recovered from refinery processes and used as a feedstock.
    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.
    By-product formation is the quantity of fluorinated GHGs created 
during the etching or chamber cleaning processes in an electronics 
manufacturing process.
    C2+ means the NGL fraction consisting of hydrocarbon molecules 
ethane and heavier. The characteristics for this fraction, as reported 
in Table MM-2, are derived from the mixture of 31 percent ethane and 29 
percent propane as reported in Table MM-1, and 41 percent C4+. These 
proportions are determined from an example API E&PTankCalc run on 
34[deg]API crude oil from a separator temperature of 100 [deg]F and 
pressure of 40 psig.
    C4+ means the NGL fraction consisting of hydrocarbon molecules 
butane and heavier. The characteristics for this fraction, as reported 
in Table MM-2, are derived from the mixture of 39 percent ``pentanes 
plus'' and 61 percent butane as reported in Table MM-1. These 
proportions are determined from an example API E&PTankCalc run on 
34[deg]API crude oil from a separator temperature of 100 [deg]F and 
pressure of 40 psig.
    C5+ is pentane plus in the specific chemical composition that 
underlies the default factors in Table MM-1.
    C6+ means NGL fraction consisting of hydrocarbon molecules hexane 
and heavier. The characteristics for this fraction, as reported in 
Table MM-2, are derived from the assumption that ``pentane plus'', as 
reported in Table MM-1, consists of a mixture of 53 percent C6+ and 47 
percent pentane. These proportions are determined from an example API 
E&PTankCalc run on 34[deg]API crude oil from a separator temperature of 
100 [deg]F and pressure of 40 psig.
    Calibrated bag means a flexible, non-elastic bag of a calibrated 
volume that can be quickly affixed to a fugitive emitting source such 
that the fugitive emissions inflate the bag to its calibrated volume.
    Carbon black oil means a heavy aromatic oil that may be derived 
either as a by-product of petroleum refining or metallurgical coke 
production. Carbon black oil consists mainly of unsaturated 
hydrocarbons, predominately higher than C14.
    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 primary greenhouse gas.
    Carbon dioxide production well means any hole drilled in the earth 
to extract a carbon dioxide stream from a geologic formation or group 
of formations which contain deposits of carbon dioxide.
    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.
    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 weight percentage of carbon 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.
    Carrier gas means the gas with which cover gas is mixed to 
transport and dilute the cover gas thus maximizing its efficient use. 
Carrier gases typically include CO2, N2, and/or 
dry air.
    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,

[[Page 16618]]

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.
    Cattle and swine deep bedding means 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 or conventional gasoline for oxygenate blending means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of conventional gasoline.
    Centrifugal compressor means any equipment that increases the 
pressure of a process natural gas by centrifugal action, employing 
rotating movement of the driven shaft.
    Centrifugal compressor dry seals mean a series of rings that are 
located around the compressor shaft where it exits the compressor case 
and that operate mechanically under the opposing forces to prevent 
natural gas from escaping to the atmosphere.
    Centrifugal compressor dry seals fugitive emissions mean natural 
gas released from a dry seal vent pipe and/or the seal face around the 
rotating shaft where it exits one or both ends of the compressor case.
    Centrifugal compressor wet seals mean a series of rings around the 
compressor shaft where it exits the compressor case, that use oil 
circulated under high pressure between the rings to prevent natural gas 
from escaping to the atmosphere.
    Centrifugal compressor wet seals fugitive emissions mean natural 
gas released from the seal face around the rotating shaft where it 
exits one or both ends of the compressor case PLUS the natural gas 
absorbed in the circulating seal oil and vented to the atmosphere from 
a seal oil degassing vessel or sump before the oil is re-circulated, or 
from a seal oil containment vessel vent.
    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.
    Close-range means, for the purposes of this rule, safely accessible 
within the operator's arm's reach from the ground or stationary 
platforms.
    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'' (as incorporated by reference in Sec.  98.7).
    COD means the chemical oxygen demand as determined using methods 
specified pursuant to 40 CFR Part 136.
    Coke (petroleum) means a solid residue consisting mainly of carbon 
which results from the cracking of petroleum hydrocarbons in processes 
such as coking and fluid coking. This includes catalyst coke deposited 
on a catalyst during the refining process which must be burned off in 
order to regenerate the catalyst.
    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.
    Cold and steady emissions mean a nearly constant and steady 
emissions stream that is low enough in temperature (i.e., less than 140 
degrees Fahrenheit) to be safely directly measured by a person.
    Commercial Applications means any use including but not limited to: 
Food and beverage, industrial and municipal water/wastewater treatment, 
metal fabrication, including welding and cutting, greenhouse uses for 
plant growth, fumigants (e.g., grain storage) and herbicides, pulp and 
paper, cleaning and solvent use, fire fighting, transportation and 
storage of explosives, enhanced oil and natural gas recovery, long-term 
storage (sequestration), or research and development.
    Completely destroyed means destroyed with a destruction efficiency 
of 99.99 percent or greater.
    Completely recaptured means 99.99 percent or greater of each GHG is 
removed from a process stream.
    Component, for the purposes of subpart W only, means but is not 
limited to each metal to metal joint or seal of non-welded connection 
separated by a compression gasket, screwed thread (with or without 
thread sealing compound), metal to metal compression, or fluid barrier 
through which natural gas or liquid can escape to the atmosphere.
    Compressor means any machine for raising the pressure of a natural 
gas by drawing in low pressure natural gas and discharging 
significantly higher pressure natural gas (i.e., compression ratio 
higher than 1.5).
    Compressor fugitive emissions mean natural gas emissions from all 
components in close physical proximity to compressors where mechanical 
and thermal cycles may cause elevated emission rates, including but not 
limited to open-ended blowdown vent stacks, piping and tubing 
connectors and flanges, pressure relief valves, pneumatic starter open-
ended lines, instrument connections, cylinder valve covers, and fuel 
valves.
    Condensate means hydrocarbon and other liquid separated from 
natural gas that condenses due to changes in the temperature, pressure, 
or both, and remains liquid at storage conditions, includes both water 
and hydrocarbon liquids.
    Connector means but is not limited 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 regulation.
    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).
    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

[[Page 16619]]

operates continuously except during periods of maintenance, 
malfunction, control device installation, reconstruction, or 
rebuilding.
    Control method means any equipment used for recovering and/or 
oxidizing air emissions of methane. Such equipment includes, but is not 
limited to, vapor recovery systems, absorbers, carbon dioxide 
adsorbers, condensers, incinerators, flares, catalytic oxidizers, 
boilers, and process heaters.
    Conventional gasoline means any gasoline which has not been 
certified under Sec.  80.40.
    Cover gas means SF6, HFC-134a, fluorinated ketone (FK 5-
1-12) or other gas used to protect the surface of molten magnesium from 
rapid oxidation and burning in the presence of air. The molten 
magnesium may be the surface of a casting or ingot production operation 
or the surface of a crucible of molten magnesium that is the source of 
the casting operation.
    Crude oil means any of the naturally occurring liquids and semi-
solids found in rock formations composed of complex mixtures of 
hydrocarbons ranging from one to hundreds of carbon atoms in straight 
and branched chains and rings.
    Daily spread means manure is routinely removed from a confinement 
facility and is applied to cropland or pasture within 24 hours of 
excretion.
    Degasification systems mean wells drilled from the surface or 
boreholes drilled inside the mine that remove large volumes of 
CH4 before, during, or after mining. Pre-mining 
degasification systems refer to drainage wells drilled through a coal 
seam or seams and cased to pre-drain the methane prior to mining. The 
wells are normally placed in operation 2 to 7 years ahead of mining. 
Degasification systems also include ``gob wells'' which recover methane 
from the longwall face area during and after mining.
    Degradable organic carbon (DOC) means the fraction of the total 
mass of a waste material that can be biologically degraded.
    Dehydrator means, for the purposes of this rule, a device in which 
a liquid absorbent (including but not limited to desiccant, ethylene 
glycol, diethylene glycol, or triethylene glycol) directly contacts a 
natural gas stream to absorb water vapor.
    Dehydrator vent stack fugitive emissions means natural gas released 
from a natural gas dehydrator system absorbent (typically glycol) 
reboiler or regenerator, including stripping natural gas and motive 
natural gas used in absorbent circulation pumps.
    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.
    De-methanizer means the natural gas processing unit that separates 
methane rich residue gas from the heavier hydrocarbons (ethane, 
propane, butane, pentane-plus) in feed natural gas stream.
    Density means the mass contained in a given unit volume (mass/
volume).
    Destruction means, with respect to underground coal mines, 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.
    Destruction means, 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. The Destruction Efficiency is expressed in the following 
Equation A-2:
[GRAPHIC] [TIFF OMITTED] TP10AP09.001

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

    Destruction efficiency, or flaring destruction efficiency, refers 
to the fraction of the gas that leaves the flare partially or fully 
oxidized
    Destruction or removal efficiency (DRE) is the efficiency of a 
control device to destroy or remove F-GHG and N2O. The DRE 
is equal to one minus the ratio of the mass of all relevant GHG exiting 
the emission control device to the mass of GHG entering the emission 
control device.
    Diesel fuel means a low sulfur fuel oil of grades 1BD or 2BD, as 
defined by the American Society for Testing and Materials standard ASTM 
D975-91, ``Standard Specification for Diesel Fuel Oils'' (as 
incorporated by reference in Sec.  98.7), grades 1-GT or 2-GT, as 
defined by ASTM D2880-90a, ``Standard Specification for Gas Turbine 
Fuel Oils'' (as incorporated by reference in Sec.  98.7), or fuel oil 
numbers 1 or 2, as defined by ASTM D396-90a, ``Standard Specification 
for Fuel Oils'' (as incorporated by reference in Sec.  98.7).
    Diesel fuel No. 1 has a distillation temperature of 550 [deg]F at 
the 90 percent recovery point and conforms to ASTM D975-08 (2007) 
Standard Specification for Diesel Fuel Oils. It is used in high speed 
diesel engines such as city buses. Compared to fuel oil No. 1 it has a 
higher octane number, a lower sulfur content, and a higher flash point. 
It is blended with diesel No. 2 in the colder regions of the country to 
facility cold starts.
    Diesel fuel No. 2 has a distillation temperature of 500 [deg]F at 
the 10 percent recovery point and 640 [deg]F at the 90 percent recovery 
point and is defined in ASTM D975. It is used in high speed diesel 
engines, such as locomotives, trucks and automobiles. Currently, there 
are three categories of diesel fuel No. 2 defined by sulfur content: 
High sulfur (>0.05%/wgt), low sulfur (<0.05%/wgt), and ultra low sulfur 
(<0.0015%/wgt). Ultra low sulfur is used for on road vehicles.
    Diesel fuel No. 4, made by blending diesel fuel and residual fuel 
and conforming to ASTM D975, is used for low and medium speed diesel 
engines.
    Digesters are systems where animal excreta are collected and 
anaerobically digested in a large containment vessel or covered lagoon. 
Digesters are designed and operated for waste stabilization by the 
microbial reduction of complex organic compounds to CO2 and 
CH4, which is captured and may be flared or used as fuel. 
There are multiple types of anaerobic digestion systems, including 
covered lagoon, complete mix, plug flow, and fixed film digesters.
    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

[[Page 16620]]

generic term distillate fuel oil includes both diesel fuels (Diesel 
Fuels No. 1, No. 2, and No. 4) and fuel oils (Fuel oil No. 1, No. 2, 
and No. 4). Fuel oils are used primarily for space heating, in 
industrial and commercial boilers and furnaces and for electric power 
generation. Diesel fuels are used in on-highway vehicles as well as in 
off highway engines, such as locomotives, marine engines, agricultural 
and construction equipment.
    DOCf means the fraction of DOC that actually decomposes under the 
(presumably anaerobic) conditions within the landfill.
    Dry lot means 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.
    Electrical equipment means any item used for the generation, 
conversion, transmission, distribution or utilization of electric 
energy, such as machines, transformers, apparatus, measuring 
instruments, or protective devices, that contains sulfur hexafluoride 
(SF6) or perfluorocarbons (PFCs) (including but not limited 
to gas-insulated switchgear substations (GIS), gas circuit breakers 
(GCB), and power transformers).
    Electricity generating unit or EGU means any unit that combusts 
solid, liquid, or gaseous fuel and is physically connected to a 
generator to produce electricity.
    Electrothermic furnace means a furnace that heats the charged 
materials with electric arcs from carbon electrodes.
    Emergency generator means a stationary internal combustion engine 
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 facility. Emergency engines operate only 
during emergency situations or for standard performance testing 
procedures as required by law or by the engine manufacturer. The hours 
of operation per calendar year for such standard performance testing 
shall not exceed 100 hours. An engine 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 
engine.
    Engineering estimation means an estimate of fugitive emissions 
based on engineering principles applied to measured and/or approximated 
physical parameters such as dimensions of containment, actual 
pressures, actual temperatures, and compositions.
    Equipment means but is not limited to each pump, compressor, pipe, 
pressure relief device, sampling connection system, open-ended valve or 
line, valve, connector, surge control vessel, tank, vessel, and 
instrumentation system in natural gas or liquid service; and any 
control devices or systems referenced by this subpart.
    Equipment chambers means the total natural gas-containing volume 
within any equipment and between the equipment isolation valves.
    Ethane (C2H6) is a colorless paraffinic gas 
that boils at temperatures of -127.48 [deg]F. It is extracted from 
natural gas and from refinery gas streams. Ethane is a major feedstock 
for the petrochemical industry.
    Ethylene (C2H4) is an olefinic hydrocarbon 
received from refinery processes or petrochemical processes. Ethylene 
is used as a petrochemical feedstock for numerous chemical applications 
and the production of consumer goods.
    Ex refinery gate means the point at which a refined or semi-refined 
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 United States military 
bases and ships for on-board use.
    Exporter means any person, company, or organization of record that 
contracts to transfer a product from the United States to another 
country or that transfers products to an affiliate in another country, 
excluding transfers to United States military bases and ships for on-
board use.
    Extracted means production of carbon dioxide from carbon dioxide 
production wells.
    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.
    Finished 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 (2002) and Military Specification MIL-G-5572.
    Finished motor gasoline means a complex mixture of volatile 
hydrocarbons, with or without additives, suitably blended to be used in 
spark ignition engines. Motor gasoline, defined in ASTM Specifications 
D4814-08a (2001) or Federal Specification VV-G-1690C, has a boiling 
range of 122 [deg] to 158 [deg]F at the 10 percent recovery point to 
365 [deg] to 374 [deg]F at the 90 percent recovery rate. 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.
    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.

[[Page 16621]]

    Flare combustion efficiency means the fraction of natural gas, on a 
volume or mole basis, that is combusted at the flare burner tip, 
assumed 95 percent for non-aspirated field flares and 98 percent for 
steam or air asperated flares.
    Flare stack means a device used to provide a safe means of 
combustible natural gas disposal from routine operations, upsets, or 
emergencies via combustion of the natural gas in an open, normally 
elevated flame.
    Flare stack fugitive emissions means the CH4 and 
CO2 content of that portion of natural gas (typically 5 
percent in non-aspirated field flares and 2 percent in steam or air 
asperated flares) that passes through flares un-combusted and the total 
CO2 emissions of that portion of the natural gas that is 
combusted.
    Flat glass means glass made of soda-lime recipe and produced into 
continuous flat sheets and other products listed in NAICS 327211.
    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. In addition to SF6 and NF3, 
``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 for purpose 
of creating useful heat.
    Fuel means solid, liquid or gaseous combustible material.
    Fuel ethanol (C2H5OH) is an anhydrous alcohol 
made either chemically from ethylene or biologically from the 
fermentation of sugars from carbohydrates found in agricultural 
products. It is used as a gasoline octane enhancer and as an oxygenate 
blendstock.
    Fuel gas (still 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.
    Fuel oil No. 1 has a distillation temperature of 400 [deg]F at the 
10 percent recovery point and 550 [deg]F at the 90 percent recovery 
point and is used primarily as fuel for portable outdoor stoves and 
heaters. It is defined in ASTM D396-08 (2007) Standard Specification 
for Fuel Oils.
    Fuel oil No. 2 has a distillation temperature of 400 [deg]F at the 
10 percent recovery point and 640 [deg]F at the 90 percent recovery 
point and is defined in ASTM D396. It is used primarily for residential 
heating and for moderate capacity commercial and industrial burner 
units.
    Fuel oil No. 4 is a distillate fuel oil made by blending distillate 
fuel oil and residual fuel oil and conforms to ASTM D396 or Federal 
Specification VV-F-815C. and is used extensively in industrial plants 
and commercial burner installations that are not equipped with 
preheating facilities.
    Fugitive emissions means unintentional equipment emissions of 
methane and/or carbon dioxide containing natural gas or hydrocarbon gas 
(not including combustion flue gas) from emissions sources including, 
but not limited to, open ended lines, equipment connections or seals to 
the atmosphere. Fugitive emissions also mean CO2 emissions 
resulting from combustion of natural gas in flares.
    Fugitive emissions detection means the process of identifying 
emissions from equipment, components, and other point sources.
    Fugitive emissions detection instruments mean any device or 
instrument that has been approved for fugitive emissions detection in 
this rule, namely infrared fugitive emissions detection instruments, 
OVAs, and TVAs.
    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 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 conditions mean the actual temperature, volume, and pressure of 
a gas sample.
    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.
    Gas utilization is the quantity of GHG gas consumed (and therefore 
not available for emission) during the etching and/or chamber cleaning 
processes.
    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 material into a gas.
    Gathering and boosting station means a station used to gather 
natural gas from well or field pipelines for delivery to a natural gas 
processing facility or central point. Stations may also provide 
compression, dehydration, and/or treating services.
    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.
    Global warming potential or GWP means the ratio of the time-
integrated radiative forcing from the instantaneous release of one 
kilogram (kg) of a trace substance relative to that of one kg 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), 
chlorofluorocarbons (CFCs), perfluorocarbons (PFCs), and other 
fluorinated greenhouse gases as defined in this section.

[[Page 16622]]

    Heat Transfer Fluids are F-GHGs that are liquid at room 
temperature, have appreciable vapor pressures, and are used for 
temperature control during certain processes in electronic 
manufacturing. Heat transfer fluids used in the electronics sector 
include perfluoropolyethers, perfluoroalkanes, perfluoroethers, 
tertiary perfluoroamines, and perfluorocyclic ethers.
    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.
    High volume sampler means an atmospheric emissions measurement 
device that captures emissions from a source in a calibrated air intake 
and uses dual hydrocarbon sensors and other devices to measure the flow 
rate and combustible hydrocarbon concentrations of the fugitive 
emission such that the quantity of emissions is determined.
    Hydrofluorocarbons or HFCs means a class of GHGs primarily used as 
refrigerants, consisting of hydrogen, fluorine, and carbon.
    Import means, with respect to fluorinated GHGs and nitrous oxide, 
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, and
    (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.
    Importer means any person, company, or organization of record that 
for any reason brings a product into the United States from a foreign 
country. An importer includes 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 also 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.
    Infrared remote fugitive emissions detection instrument means an 
instrument that detects infrared light in the narrow wavelength range 
absorbed by light hydrocarbons including methane, and presents a signal 
(sound, digital or visual image) indicating the presence of methane and 
other light hydrocarbon vapor emissions in the atmosphere. For the 
purpose of this rule, it must detect the presence of methane.
    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.
    Integrated process means a process that produces a petrochemical as 
well as one or more other chemicals that are part of other source 
categories under this part. An example of an integrated process is the 
production of both hydrogen for sale (i.e., a merchant hydrogen 
facility) and methanol from synthesis gas created by steam reforming of 
methane.
    Interstate pipeline means a natural gas pipeline designated as 
interstate pipelines under the Natural Gas Act, 15 U.S.C. 717a.
    Intrastate pipeline means a natural gas pipeline not subject to the 
jurisdiction of the Federal Energy Regulatory Commission as described 
in 15 U.S.C. 3301.
    Isobutane (C4H10) is a normally gaseous 
branch chain hydrocarbon extracted from natural gas or refinery gas 
streams. A colorless paraffinic gas that boils at 10.9 [deg]F, it is 
used as a feedstock in refineries.
    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. It 
meets ASTM Specification D1655-08a (2001) and Military Specification 
MIL-T-5624P and MIL-T-83133D (JP-5 and JP-8).
    Kiln means a device, including any associated preheater or 
precalciner devices, that produces clinker by heating limestone and 
other materials for subsequent production of portland cement.
    Kiln exhaust gas bypass means alkali bypass.
    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 Sec.  257.2 of this chapter.
    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.
    Liquefied natural gas (LNG) means natural gas (primarily methane) 
that has been liquefied by reducing its temperature to -260 degrees 
Fahrenheit at atmospheric pressure.
    Liquefied natural gas import and export facilities mean onshore 
and/or offshore facilities that send out exported or receive imported 
liquefied natural gas, store it in storage tanks, re-gasify it, and 
deliver re-gasified natural gas to natural gas transmission or 
distribution systems. The facilities include tanker unloading 
equipment, liquefied natural gas transportation pipelines, pumps, 
compressors to liquefy boil-off-gas, re-condensers, and vaporization 
units for re-gasification of the liquefied natural gas.
    Liquefied natural gas storage facilities means an onshore facility 
that stores liquefied natural gas in above ground storage vessels. The 
facility may include equipment for liquefying natural gas, compressors 
to liquefy boil-off-gas, re-condensers, and vaporization units for re-
gasification of the liquefied natural gas.
    Liquid/Slurry means manure is stored as excreted or with some 
minimal addition of water to facilitate handling

[[Page 16623]]

and is stored in either tanks or earthen ponds, usually for periods 
less than one year.
    LNG import and export facility fugitive emissions mean natural gas 
releases from valves, connectors, storage tanks, flanges, open-ended 
lines, pressure relief valves, boil-off-gas recovery, send outs (pumps 
and vaporizers), packing and gaskets. This does not include fugitive 
emissions from equipment and equipment components reported elsewhere 
for this rule.
    LNG storage station fugitive emissions mean natural gas releases 
from valves, connectors, flanges, open-ended lines, storage tanks, 
pressure relief valves, liquefaction process units, packing and 
gaskets. This does not include fugitive emissions from equipment and 
equipment components reported elsewhere for this rule.
    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 pulp mills to replace chemicals lost in the process.
    Mass-balance approach means a method for estimating emissions of 
fluorinated greenhouse gases from use in equipment that can be applied 
to aggregates of units (for example by system). In this approach, 
annual emissions are the difference between the quantity of gas 
consumed in the year and the quantity of gas used to fill the net 
increase in equipment capacity or to replace destroyed gas.
    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 amount of municipal 
solid waste per day (in tons/day) that a unit is capable of combusting 
on a steady state basis as of the initial installation of the unit as 
specified by the manufacturer of the unit.
    Mcf means thousand cubic feet.
    Meter means a device that measures gas flow rate from a fugitive 
emissions source or through a conduit by detecting a condition 
(pressure drop, spin induction, temperature loss, electronic signal) 
that varies in proportion to flow rate or measures gas velocity in a 
manner that can calculate flow rate.
    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.
    Miscellaneous products include all petroleum products not 
classified elsewhere. It includes petrolatum lube refining by-products 
(aromatic extracts and tars) absorption oils, ram-jet fuel, petroleum 
rocket fuels, synthetic natural gas feedstocks, and specialty oils.
    MMBtu means million British thermal units.
    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 (Sec.  257.2 of this chapter) 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. 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.
    NAESB is the North American Energy Standards Board.
    Nameplate capacity means the full and proper charge of gas 
specified by the equipment manufacturer to achieve the equipment's 
specified performance. The nameplate capacity is typically indicated on 
the equipment's nameplate; it is not necessarily the actual charge, 
which may be influenced by leakage and other emissions.
    Naphtha-type jet fuel means a fuel in the heavy naphtha boiling 
range having an average gravity of 52.8 API and meeting Military 
Specification MIL-T-5624L (Grade JP-4). It is used primarily for 
military turbojet and turboprop aircraft because it has a lower freeze 
point than other aviation fuels and meets engine requirements at high 
altitudes and speeds.
    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 driven pneumatic manual valve actuator device means 
valve control devices that use pressurized natural gas to provide the 
energy required for an operator to manually open, close, or throttle a 
liquid or gas stream. Typical manual control applications include, but 
are not limited to, equipment isolation valves, tank drain valves, 
pipeline valves.
    Natural gas driven pneumatic manual valve actuator device fugitive 
emissions means natural gas released due to manual actuation of natural 
gas pneumatic valve actuation devices, including, but not limited to, 
natural gas diaphragm and pneumatic-hydraulic valve actuators.
    Natural gas driven pneumatic pump means a pump that uses 
pressurized natural gas to move a piston or diaphragm, which pumps 
liquids on the opposite side of the piston or diaphragm.
    Natural gas driven pneumatic pump fugitive emissions means natural 
gas released from pumps that are powered or assisted by pressurized 
natural gas.
    Natural gas driven pneumatic valve bleed device means valve control 
devices that use pressurized natural gas to transmit a process 
measurement signal to a valve actuator to automatically control the 
valve opening. Typical bleeding process control applications include, 
but are not limited to, pressure, temperature, liquid level, and flow 
rate regulation.
    Natural gas driven pneumatic valve bleed devices fugitive emissions 
means the continuous or intermittant release of natural gas from 
automatic process control loops including the natural gas pressure 
signal flowing from a process measurement instrument (e.g. liquid 
level, pressure, temperature) to a process control instrument which 
activates a process control valve actuator.
    Natural gas liquids (NGL) means those hydrocarbons in natural gas 
that are separated from the gas as liquids through the process of 
absorption, condensation, adsorption, or other methods in gas 
processing or cycling

[[Page 16624]]

plants. Generally, such liquids consist of primarily ethane, propane, 
butane, and isobutane, primarily pentanes produced from natural gas at 
lease separators and field facilities. For the purposes of subpart NN 
only, natural gas liquids does not include lease condensate. Bulk NGLs 
refers to mixtures of NGLs that are sold or delivered as 
undifferentiated product from natural gas processing plants.
    Natural gas processing facilities are engaged in the extraction of 
natural gas liquids from produced natural gas; fractionation of mixed 
natural gas liquids to natural gas products; and removal of carbon 
dioxide, sulfur compounds, nitrogen, helium, water, and other 
contaminants. Natural gas processing facilities also encompass 
gathering and boosting stations that include equipment to phase-
separate natural gas liquids from natural gas, dehydrate the natural 
gas, and transport the natural gas to transmission pipelines or to a 
processing facility.
    Natural gas products means products produced for consumers from 
natural gas processing facilities including, but not limited to, 
ethane, propane, butane, iso-butane, and pentanes-plus.
    Natural gas transmission compression facility means any permanent 
combination of compressors that move natural gas at increased pressure 
from production fields or natural gas processing facilities, in 
transmission pipelines, to natural gas distribution pipelines, or into 
storage facilities. In addition, transmission compressor stations may 
include equipment for liquids separation, natural gas dehydration, and 
storage of water and hydrocarbon liquids.
    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 natural gas liquids, hydrogen and other 
hydrocarbons, and petroleum products that are input into the 
atmospheric distillation column or other processing units in a refinery
    Non-pneumatic pump means any pump that is not pneumatically powered 
with pressurized gas of any type, such as natural gas, air, or 
nitrogen.
    Non-pneumatic pump fugitive emissions means natural gas released 
through connectors and flanges of electric motor or engine driven 
pumps.
    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.
    Non-steam aspirated flare means a flare where natural gas burns at 
the tip with natural induction of air (and relatively lower combustion 
efficiency as may be evidenced by smoke formation).
    Offshore means tidal-affected borders of the U.S. lands, both state 
and Federal, adjacent to oceans, bays, lakes or other normally standing 
water.
    Offshore petroleum and natural gas production facilities means any 
platform structure, floating in the ocean or lake, fixed on ocean or 
lake bed, or located on artificial islands in the ocean or lake, that 
houses equipment to extract hydrocarbons from ocean floor and 
transports it to storage or transport vessels or onshore. In addition, 
offshore production facilities may include equipment for separation of 
liquids from natural gas components, dehydration of natural gas, 
extraction of H2S and CO2 from natural gas, crude 
oil and condensate storage tanks, both on the platform structure and 
floating storage tanks connected to the platform structure by a 
pipeline, and compression or pumping of hydrocarbons to vessels or 
onshore. The facilities under consideration are located in both State 
administered waters and Mineral Management Services administered 
Federal waters.
    Offshore platform pipeline fugitive emissions means natural gas 
above the water line released from piping connectors, pipe wall 
ruptures and holes in natural gas and crude oil pipeline surfaces on 
offshore production facilities.
    Oil/water separator means equipment used to routinely handle oily-
water streams, including gravity separators or ponds and air flotation 
systems.
    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 line fugitive emissions means natural gas released from 
pipes or valves open on one end to the atmosphere that are intended to 
periodically vent or drain natural gas to the atmosphere but may also 
leak process gas or liquid through incomplete valve closure including 
valve seat obstructions or damage.
    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.
    Operating pressure means the containment pressure that 
characterizes the normal state of gas and/or liquid inside a particular 
process, pipeline, vessel or tank.
    Operator means any person who operates or supervises a facility or 
supply operation.
    Organic monitoring device means an instrument used to indicate the 
concentration level of organic compounds exiting a control device based 
on a detection principle such as IR, photoionization, or thermal 
conductivity.
    Organic vapor analyzer (OVA) means an organic monitoring device 
that uses a flame ionization detector to measure the concentrations in 
air of combustible organic vapors from 9 to 10,000 parts per million 
sucked into the probe.
    Owner means any person who has legal or equitable title to, has a 
leasehold interest in, or control of a facility or supply operation.
    Oxygenated gasoline means gasoline which contains a measurable 
amount of oxygenate.
    Oxygenates means substances which, when added to gasoline increase 
the oxygen content of the gasoline. Common oxygenates are ethanol 
CH3-CH2OH, Methyl Tertiary Butl Ether 
(CH3)3COCH3 (MTBE), Ethyl Tertial Butl 
Ether (CH3)3COC2H (ETBE), Tertiary 
Amyl Methyl Ether (CH3)(2C2H5) 
COCH3 (TAME), Diisopropyl Ether 
(CH3)2CHOCH(CH3)2 (DIPE), 
and Methanol CH3OH. Lawful use of any of the substances or 
any combination of these substances requires that they be 
``substantially similar'' under section 211(f)(1) of the Clean Air Act.
    Pasture/Range/Paddock means the manure from pasture and range 
grazing animals is allowed to lie as deposited, and is not managed.
    Pentanes plus is a mixture of hydrocarbons, mostly pentanes and 
heavier, extracted from natural gas. Pentanes plus includes isopentane, 
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,

[[Page 16625]]

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 naphtha 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) and has low ash 
content. It is used as a feedstock in coke ovens for the steel 
industry, for heating purposes, for electrode manufacture and for 
production of chemicals.
    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. 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 asphalt and road oil, 
lubricants, waxes, plastics, and plastics products.
    Platform fugitive emissions means natural gas released from 
equipment and equipment components including valves, pressure relief 
valves, connectors, tube fittings, open-ended lines, ports, and 
hatches. This does not include fugitive emissions from equipment and 
components reported elsewhere for this rule.
    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:
    (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.
    Post-coal mining activities means the storage, processing, and 
transport of extracted coal.
    Poultry manure with litter is similar to cattle and swine deep 
bedding except usually not combined with a dry lot or pasture. 
Typically used for all poultry breeder flocks and for the production of 
meat type chickens (broiler) and other fowl.
    Poultry manure without litter systems 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) means that 95 percent of repeat measurements made by a 
device or technique fall within the range bounded by the mean of the 
measurements plus or minus the specified level.
    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 includes, but is 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.
    Primary product means the product of a process that is produced in 
greater mass quantity than any other product of the process.
    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 Type, for purposes of electronics manufacturing, means the 
kind of electronics manufacturing process, i.e., etching, cleaning, or 
chemical vapor deposition using N2O.
    Process gas means any gas generated by an industrial process such 
as petroleum refining.
    Processing facility fugitive emissions means natural gas released 
from all components including valves, flanges, connectors, open-ended 
lines, pump seals, ESD (emergency shut-down) system fugitive emissions, 
packing and gaskets in natural gas processing facilities. This does not 
include fugitive emissions from equipment and components reported 
elsewhere for this rule, such as compressor fugitive emissions; acid 
gas removal, blowdown, wet seal oil degassing, and dehydrator vents; 
and flare stacks.
    Production process unit means equipment used to capture a carbon 
dioxide stream.
    Propane means the normally gaseous paraffinic compound 
(C3H8), which includes all products covered by 
Natural Gas Policy Act Specifications for commercial and HD-5 propane 
and ASTM Specification D 1835. It excludes feedstock propanes, which 
are propanes not classified as consumer grade propanes, including the 
propane portion of any natural gas liquid mixes, i.e., butane-propane 
mix.
    Propylene (C3H6) is an olefinic hydrocarbon 
recovered from refinery processes or petrochemical processes.
    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.
    Pump seals means any seal on a pump drive shaft used to keep 
methane and/or carbon dioxide containing light liquids from escaping 
the inside of a pump case to the atmosphere.
    Pump seal fugitive emissions means natural gas released from the 
seal face between the pump internal chamber and the atmosphere.
    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,

[[Page 16626]]

a raw material dryer. The raw mill also includes the air separator 
associated with the raw mill.
    RBOB (reformulated gasoline for oxygenate blending) means a 
petroleum product which, when blended with a specified type and 
percentage of oxygenate, meets the definition of reformulated gasoline.
    Reciprocating compressor means a piece of equipment that increases 
the pressure of a process natural gas by positive displacement, 
employing linear movement of a shaft driving a piston in a cylinder.
    Reciprocating compressor rod packing means a series of flexible 
rings in machined metal cups that fit around the reciprocating 
compressor piston rod to create a seal limiting the amount of 
compressed natural gas that escapes to the atmosphere.
    Reciprocating compressor rod packing fugitive emissions means 
natural gas released from a connected tubing vent and/or around a 
piston rod where it passes through the rod packing case. It also 
includes emissions from uncovered distance piece, rod packing flange 
(on each cylinder), any packing vents, cover plates (on each cylinder), 
and the crankcase breather cap.
    Re-condenser means heat exchangers that cool compressed boil-off 
gas to a temperature that will condense natural gas to a liquid.
    Refined petroleum product means petroleum products produced from 
the processing of crude oil, lease condensate, natural gas and other 
hydrocarbon compounds
    Refinery fuel gas (still gas) means any gas generated at a 
petroleum refinery, or any gas generated by a refinery process unit, 
that is combusted separately or in any combination with any type of gas 
or used as a chemical feedstock.
    Reformulated gasoline means any gasoline whose formulation has been 
certified under 40 CFR 80.40, and which meets each of the standards and 
requirements prescribed under 40 CFR 80.41.
    Re-gasification means the process of vaporizing liquefied natural 
gas to gaseous phase natural gas.
    Research and development process unit means a process unit whose 
purpose is to conduct research and development for new processes and 
products and is not engaged in the manufacture of products for 
commercial sale, except in a de minimis manner.
    Residual fuel oil means a classification for the heavier fuel oils, 
No. 5 and No. 6. No. 5 is also known as Navy Special and is used in 
steam powered vessels in government service and inshore power plants. 
No.6 includes Bunker C and is used for the production of electric 
power, space heating, vessel bunkering and various industrial purposes.
    Residue gas means natural gas from which natural gas processing 
facilities liquid products and, in some cases, non-hydrocarbon 
components have been extracted.
    Rotameter means a flow meter in which gas flow rate upward through 
a tapered tube lifts a ``float bob'' to an elevation related to the gas 
flow rate indicated by etched calibrations on the wall of the tapered 
tube.
    Rotary lime kiln means a unit with an inclined rotating drum that 
is used to produce a lime product from limestone by calcination.
    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.
    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.
    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.
    Simulation software means a calibrated, empirical computer program 
that uses physical parameters and scientific laws to numerically 
simulate the performance variables of a physical process, outputting 
such parameters as emission rates from which methane emissions can be 
estimated.
    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 natural gas means natural gas that contains significant 
concentrations of hydrogen sulfide and/or carbon dioxide that exceed 
the concentrations specified for commercially saleable natural gas 
delivered from transmission and distribution pipelines.
    Special naphthas means all finished products with the naphtha 
boiling range (290[deg] to 470 [deg]F) that are used as paint thinners, 
cleaners or solvents.
    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 60 degrees Fahrenheit and 14.7 pounds per square inch absolute.
    Standby means for an equipment to be in a state ready for 
operation, but not operating.
    Steam aspirated flare means steam injected into the flare burner 
tip to induce air mixing with the hydrocarbon fuel to promote more 
complete combustion as indicated by lack of smoke formation.
    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.
    Storage station fugitive emissions means natural gas released from 
all components including valves, flanges, connectors, open-ended lines, 
pump seals, ESD (emergency shut-down) system emissions, packing and 
gaskets in natural gas storage station. This does not include fugitive 
emissions from equipment and equipment components reported elsewhere 
for this rule.
    Storage tank means other vessel that is designed to contain an 
accumulation of crude oil, condensate, intermediate

[[Page 16627]]

hydrocarbon liquids, or produced water and that is constructed entirely 
of non-earthen materials (e.g., wood, concrete, steel, plastic) that 
provide structural support.
    Storage tank fugitive emissions means natural gas vented when it 
flashes out of liquids; this occurs when liquids are transferred from 
higher pressure and temperature conditions upstream, plus working 
losses from liquid level increases and decreases during filling and 
draining and standing losses (breathing losses) from diurnal 
temperature changes and barometric pressure changes expanding and 
contracting the vapor volume of a tank.
    Storage wellhead fugitive emissions means natural gas released from 
storage station wellhead components including but not limited to 
valves, OELs, connectors, flanges, and tube fittings.
    Sub-surface or subsurface facility means for the purposes of this 
rule, a natural gas facility, such as a pipeline and metering and 
regulation station in a closed vault below the land surface of the 
Earth.
    Sulfur recovery plant means all process units which recover sulfur 
or produce sulfuric acid from hydrogen sulfide (H2S) and/or 
sulfur dioxide (SO2) 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 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.
    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.
    Tanker unloading means pumping of liquid hydrocarbon (e.g., crude 
oil, LNG) from an ocean-going tanker or barge to shore storage tanks.
    Toxic vapor analyzer (TVA) means an organic monitoring device that 
uses a flame ionization detector and photoionization detector to 
measure the concentrations in air of combustible organic vapors from 9 
parts per million and exceeding 10,000 parts per million sucked into 
the probe.
    Trace concentrations means concentrations of less than 0.1 percent 
by mass of the process stream.
    Trained technician means a person who has completed a vendor 
provided or equivalent training program and demonstrated proficiency to 
use specific equipment for its intended purpose, such as high volume 
sampler for the purposes of this rule.
    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.
    Transmission compressor station fugitive emissions means natural 
gas released from all components including but not limited to valves, 
flanges, connectors, open-ended lines, pump seals, ESD (emergency shut-
down) system emissions, packing and gaskets in natural gas transmission 
compressor stations. This does not include fugitive emissions from 
equipment and equipment components reported elsewhere for this rule, 
such as compressor fugitive emissions.
    Transmission pipeline means high pressure cross country pipeline 
transporting saleable quality natural gas from production or natural 
gas processing to natural gas distribution pressure let-down, metering, 
regulating stations where the natural gas is typically odorized before 
delivery to customers.
    Trona means the raw material (mineral) used to manufacture soda 
ash; hydrated sodium bicarbonate carbonate 
(NaCO3.NaHCO3.2H2O).
    Turbine meter means a flow meter in which a gas or liquid flow rate 
through the calibrated tube spins a turbine from which the spin rate is 
detected and calibrated to measure the fluid flow rate.
    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.
    Uncovered anaerobic lagoons are a type of liquid storage system 
designed and operated to combine waste stabilization and storage. 
Lagoon supernatant is usually used to remove manure from the associated 
confinement facilities to the lagoon. Anaerobic lagoons are designed 
with varying lengths of storage (up to a year or greater), depending on 
the climate region, the volatile solids loading rate, and other 
operational factors. The water from the lagoon may be recycled as flush 
water or used to irrigate and fertilize fields.
    Underground natural gas storage facility means a subsurface 
facility, including but not limited to depleted gas or oil reservoirs 
and salt dome caverns, utilized for storing natural gas that has been 
transferred from its original location for the primary purpose of load 
balancing, which is the process of equalizing the receipt and delivery 
of natural gas. Processes and operations that may be located at a 
natural gas underground storage facility include, but are not limited 
to, compression, dehydration and flow measurement. The storage facility 
also includes all the wellheads connected to the compression units 
located at the facility.
    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 subpart, 
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.
    Vapor recovery system means any equipment located at the source of 
potential gas emissions to the atmosphere or to a flare, that is 
composed of piping, connections, and, if necessary, flow-inducing 
devices; and that is used for routing the gas back into the process as 
a product and/or fuel.
    Vaporization unit means a process unit that performs controlled 
heat input to vaporize liquefied natural gas to supply transmission and 
distribution pipelines, or consumers with natural gas.

[[Page 16628]]

    Ventilation system means a system deployed within a mine to ensure 
that CH4 levels remain within safe concentrations.
    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 reducing agent (e.g., 
petroleum coke, metallurgical coke, or anthracite coal).
    Waste feedstocks are non-crude feedstocks that have been 
contaminated, downgraded, or no longer meet the specifications of the 
product category or end-use for which they were intended. Waste 
feedstocks include but are not limited to: Used plastics, used engine 
oils, used dry cleaning solvents, and trans-mix (mix of products at the 
interface in delivery pipelines).
    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.
    Wellhead means the piping, casing, tubing and connected valves 
protruding above the Earth's surface for an oil and/ or natural gas 
well. The wellhead ends where the flow line connects to a wellhead 
valve.
    Wet natural gas means natural gas in which water vapor exceeds the 
concentration specified for commercially saleable natural gas delivered 
from transmission and distribution pipelines. This input stream to a 
natural gas dehydrator is referred to as ``wet gas''.
    Wool fiberglass means fibrous glass of random texture, including 
fiberglass insulation, and other products listed in NAICS 327993.
    You means the 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 
for use in this part and are incorporated as they existed on the date 
of approval of this part.
    (a) The following materials are available for purchase from the 
following addresses: American Society for Testing and Material (ASTM), 
100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 
19428-B2959; and the University Microfilms International, 300 North 
Zeeb Road, Ann Arbor, Michigan 48106:
    (1) ASTM D240-02, (Reapproved 2007), Standard Test Method for Heat 
of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter.
    (2) ASTM D388-05, Standard Classification of Coals by Rank.
    (3) ASTM D396-08, Standard Specification for Fuel Oils.
    (4) ASTM D975-08, Standard Specification for Diesel Fuel Oils.
    (5) ASTM D1250-07, Standard Guide for Use of the Petroleum 
Measurement Tables.
    (6) ASTM D1826-94 (Reapproved 2003), Standard Test Method for 
Calorific (Heating) Value of Gases in Natural Gas Range by Continuous 
Recording Calorimeter.
    (7) ASTM Specification D1835-05 (2005).
    (8) ASTM D1945-03 (Reapproved 2006), Standard Test Method for 
Analysis of Natural Gas by Gas Chromatography.
    (9) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis 
of Reformed Gas by Gas Chromatography.
    (10) ASTM D2013-07, Standard Practice of Preparing Coal Samples for 
Analysis.
    (11) ASTM D2234/D2234M-07, Standard Practice for Collection of a 
Gross Sample of Coal.
    (12) ASTM D2502-04 (Reapproved 2002), Standard Test Method for 
Estimation of Molecular Weight (Relative Molecular Mass) of Petroleum 
Oils from Viscosity Measurements.
    (13) ASTM D2503-92 (Reapproved 2007), Standard Test Method for 
Relative Molecular Mass (Relative Molecular Weight) of Hydrocarbons by 
Thermoelectric Measurement of Vapor Pressure.
    (14) ASTM D2880-03, Standard Specification for Gas Turbine Fuel 
Oils.
    (15) ASTM D3176-89 (Reapproved 2002), Standard Practice for 
Ultimate Analysis of Coal and Coke.
    (16) 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.
    (17) ASTM D3588-98 (Reapproved 2003), Standard Practice for 
Calculating Heat Value, Compressibility Factor, and Relative Density of 
Gaseous Fuels.
    (18) ASTM Specification D3699-07, Standard Specification for 
Kerosene.
    (19) ASTM D4057-06, Standard Practice for Manual Sampling of 
Petroleum and Petroleum Products.
    (20) ASTM D4809-06, Standard Test Method for Heat of Combustion of 
Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method).
    (21) ASTM Specification D4814-08a, Standard Specification for 
Automotive Spark-Ignition Engine Fuel.
    (22) ASTM D4891-89 (Reapproved 2006), Standard Test Method for 
Heating Value of Gases in Natural Gas Range by Stoichiometric 
Combustion.
    (23) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Petroleum Products and Lubricants.
    (24) ASTM D5373-08, Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal and Coke.
    (25) ASTM D5865-07a, Standard Test Method for Gross Calorific Value 
of Coal and Coke.
    (26) ASTM D6316-04, Standard Test Method for the Determination of 
Total, Combustible and Carbonate Carbon in Solid Residues from Coal and 
Coke.
    (27) ASTM D6866-06a, Standard Test Methods for Determining the 
Biobased Content of Natural Range Materials Using Radiocarbon and 
Isotope Ratio Mass Spectrometry Analysis.
    (28) ASTM E1019-03, Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and 
Cobalt Alloys.
    (29) ASTM E1915-07a, Standard Test Methods for Analysis of Metal 
Bearing Ores and Related Materials by Combustion Infrared-Absorption 
Spectrometry.
    (30) ASTM CS-104 (1985), Carbon Steel of Medium Carbon Content.
    (31) ASTM D 7459-08, Standard Practice for Collection of Integrated 
Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived 
Carbon Dioxide Emitted from Stationary Emissions Sources.
    (32) ASTM D6060-96(2001) Standard Practice for Sampling of Process 
Vents With a Portable Gas Chromatograph.
    (33) ASTM D 2502-88(2004)e1 Standard Test Method for Ethylene, 
Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas 
Chromatography.
    (34) ASTM C25-06 Standard Test Method for Chemical Analysis of 
Limestone, quicklime, and Hydrated Lime.
    (35) UOP539-97 Refinery Gas Analysis by Gas Chromatography.
    (b) The following materials are available for purchase from the 
American Society of Mechanical

[[Page 16629]]

Engineers (ASME), 22 Law Drive, P.O. Box 2900, Fairfield, NJ 07007-
2900:
    (1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using 
Orifice, Nozzle, and Venturi.
    (2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by 
Turbine Meters.
    (3) ASME-MFC-5M-1985, (Reaffirmed 1994), Measurement of Liquid Flow 
in Closed Conduits Using Transit-Time Ultrasonic Flowmeters.
    (4) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using 
Vortex Flowmeters.
    (5) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by 
Means of Critical Flow Venturi Nozzles.
    (6) ASME MFC-9M-1988 (Reaffirmed 2001), Measurement of Liquid Flow 
in Closed Conduits by Weighing Method.
    (c) The following materials are available for purchase from the 
American National Standards Institute (ANSI), 25 West 43rd Street, 
Fourth Floor, New York, New York 10036:
    (1) ISO 8316: 1987 Measurement of Liquid Flow in Closed Conduits--
Method by Collection of the Liquid in a Volumetric Tank.
    (2) 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).
    (3) 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).
    (d) The following materials are available for purchase from the 
following address: Gas Processors Association (GPA), 6526 East 60th 
Street, Tulsa, Oklahoma 74143:
    (1) GPA Standard 2172-96, Calculation of Gross Heating Value, 
Relative Density and Compressibility Factor for Natural Gas Mixtures 
from Compositional Analysis.
    (2) GPA Standard 2261-00, Analysis for Natural Gas and Similar 
Gaseous Mixtures by Gas Chromatography.
    (e) The following American Gas Association materials are available 
for purchase from the following address: ILI Infodisk, 610 Winters 
Avenue, Paramus, New Jersey 07652:
    (1) American Gas Association Report No. 3: Orifice Metering of 
Natural Gas, Part 1: General Equations and Uncertainty Guidelines 
(1990), Part 2: Specification and Installation Requirements (1990).
    (2) American Gas Association Transmission Measurement Committee 
Report No. 7: Measurement of Gas by Turbine Meters (2006).
    (f) The following materials are available for purchase from the 
following address: American Petroleum Institute, Publications 
Department, 1220 L Street, NW., Washington, DC 20005-4070:
    (1) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 3--Tank Gauging:
    (i) Section 1A, Standard Practice for the Manual Gauging of 
Petroleum and Petroleum Products, Second Edition, August 2005.
    (ii) Section 1B--Standard Practice for Level Measurement of Liquid 
Hydrocarbons in Stationary Tanks by Automatic Tank Gauging, Second 
Edition June 2001 (Reaffirmed, October 2006).
    (iii) Section 3--Standard Practice for Level Measurement of Liquid 
Hydrocarbons in Stationary Pressurized Storage Tanks by Automatic Tank 
Gauging, First Edition June 1996 (Reaffirmed, October 2006).
    (2) Shop Testing of Automatic Liquid Level Gages, Bulletin 2509 B, 
December 1961 (Reaffirmed August 1987, October 1992).
    (3) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 4--Proving Systems:
    (i) Section 2--Displacement Provers, Third Edition, September 2003.
    (ii) Section 5--Master-Meter Provers, Second Edition, May 2000 
(Reaffirmed, August 2005).
    (4) American Petroleum Institute (API) Manual of Petroleum 
Measurement Standards, Chapter 22--Testing Protocol, Section 2--
Differential Pressure Flow Measurement Devices, First Edition, August 
2005.
    (g) The following material is available for purchase from the 
following address: American Society of Heating, Refrigerating and Air-
Conditioning Engineers, Inc., 1791 Tullie Circle, NE., Atlanta, Georgia 
30329.
    (1) ASHRAE 41.8-1989: Standard Methods of Measurement of Flow of 
Liquids in Pipes Using Orifice Flowmeters.


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

    Any violation of the requirements of this part shall be a violation 
of the Clean Air Act. 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 
emission, and failure to calculate GHG emissions following the 
methodologies specified in this part. Each day of a violation 
constitutes a separate violation.

                    Table A-1 of Subpart A--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

[[Page 16630]]

 
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
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 (Perfluorohexane)..................        355-42-0  C6F14...........................           7,400
PFC-9-1-18....................................        306-94-5  C10F18..........................           7,500
HCFE-235da2 (Isoflurane)......................      26675-46-7  CHF2OCHClCF3....................             350
HFE-43-10pccc (H-Galden 1040x)................              NA  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)...........................              NA  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....................................              NA  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...................................        156-05-3  CF3CF2OCH2CF3...................             552
HFE-338pcc13 (HG-01)..........................              NA  CHF2OCF2CF2OCHF2................           1,500
HFE-347mcc3...................................      28523-86-6  CH3OCF2CF2CF3...................             575
HFE-347mcf2...................................              NA  CF3CF2OCH2CHF2..................             374
HFE-347pcf2...................................        406-78-0  CHF2CF2OCH2CF3..................             580
HFE-356mec3...................................        382-34-3  CH3OCF2CHFCF3...................             101
HFE-356pcc3...................................              NA  CH3OCF2CF2CHF2..................             110
HFE-356pcf2...................................              NA  CHF2CH2OCF2CHF2.................             265
HFE-356pcf3...................................      35042-99-0  CHF2OCH2CF2CHF2.................             502
HFE-365mcf3...................................              NA  CF3CF2CH2OCH3...................              11
HFE-374pc2....................................        512-51-6  CH3CH2OCF2CHF2..................             557
HFE-449sl (HFE-7100) Chemical blend...........     163702-07-6  C4F9OCH3........................             297
                                                   163702-08-7  (CF3)2CFCF2OCH3.................
HFE-569sf2 (HFE-7200) Chemical blend..........     163702-05-4  C4F9OC2H5.......................              59
                                                   163702-06-5  (CF3)2CFCF2OC2H5................
Sevoflurane...................................      28523-86-6  CH2FOCH(CF3)2...................             345
NA............................................      13171-18-1  (CF3)2CHOCH3....................              27
NA............................................      26103-08-2  CHF2OCH(CF3)2...................             380
NA............................................              NA  -(CF2)4CH(OH)-..................              73
NA............................................              NA  CH3OCF(CF3)2....................             343
NA............................................              NA  (CF3)2CHOH......................             195
NA............................................              NA  CF3CF2CH2OH.....................              42
PFPMIE........................................              NA  CF3OCF(CF3)CF2OCF2OCF3..........         10,300
----------------------------------------------------------------------------------------------------------------
NA = not available.


                              Table A-2 of Subpart A--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.

[[Page 16631]]

 
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      6.289.
                                          (bbl).
Barrels of Liquid Fuel (bbl)...........  Gallons (liquid, US)......  42.
Gallons (liquid, US)...................  Barrels of Liquid Fuel      0.023810.
                                          (bbl).
Gallons (liquid, US)...................  Cubic meters (m\3\).......  0.0037854.
Liters (l).............................  Cubic meters (m\3\).......  0.001.
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]C = (5/9) x ([deg]F-32).
                                          ([deg]F).
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      0.49110.
                                          (psi).
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, combustion turbines, 
engines, incinerators, and process heaters.
    (b) This source category does not include portable equipment or 
generating units designated as emergency generators in a permit issued 
by a state or local air pollution control agency.


Sec.  98.31  Reporting threshold.

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

    The owner or operator shall use the methodologies in this section 
to calculate the GHG emissions from stationary fuel combustion sources, 
except for electricity generating units that are subject to the Acid 
Rain Program. The GHG emissions calculation methods for Acid Rain 
Program units are addressed in subpart D of this part.
    (a) CO2 emissions from fuel combustion. For each stationary fuel 
combustion unit, the owner or operator shall use the four-tiered 
approach in this paragraph, subject to the conditions, requirements, 
and restrictions set forth in paragraph (b) of this section.
    (1) Tier 1 Calculation Methodology. Calculate the annual 
CO2 mass emissions for a particular type of fuel combusted 
in a unit, by substituting a fuel-specific default CO2 
emission factor (from Table C-1 of this subpart), a default high 
heating value (from Table C-1 of this subpart), and the annual fuel 
consumption (from company records kept as provided in this rule) into 
the Equation C-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.002

Where:

CO2 = Annual CO2 mass emissions for the 
specific fuel type (metric tons).
Fuel = Mass or volume of fuel combusted per year, from company 
records (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 a particular type of fuel combusted 
in a unit, by substituting measured high heat values, a default 
CO2 emission factor (from Table C-1 or Table C-2 of this 
subpart), and the quantity of fuel combusted (from company records kept 
as provided in this rule) into the following equations:
    (i) Equation C-2a of this section applies to any type of fuel, 
except for municipal solid waste (MSW):

[[Page 16632]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.003

Where:

CO2 = Annual CO2 mass emissions for a specific 
fuel type (metric tons).
n = Number of required heat content measurements for the year.
(Fuel)p = Mass or volume of the fuel combusted during the 
measurement period ``p'' (express mass in short tons for solid fuel, 
volume in standard cubic feet for gaseous fuel, and volume in 
gallons for liquid fuel).
p = Measurement period (month).
(HHV)p = High heat value of the fuel for the measurement 
period (mmBtu per mass or volume).
EF = Fuel-specific default CO2 emission factor, from 
Table C-1 or C-2 of this subpart (kg CO2/mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric 
tons.

    (ii) In Equation C-2a of this section, the value of ``n'' depends 
upon the frequency at which high heat value (HHV) measurements are 
required under Sec.  98.34(c). For example, for natural gas, which 
requires monthly sampling and analysis, n = 6 if the unit combusts 
natural gas in only 6 months of the year.
    (iii) For MSW combustion, use Equation C-2b of this section:
    [GRAPHIC] [TIFF OMITTED] TP10AP09.004
    
Where:

CO2 = Annual CO2 mass emissions from MSW 
combustion (metric tons).
Steam = Total mass of steam generated by MSW 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 = Default CO2 emission factor for MSW, from Table C-3 
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 a particular type of fuel combusted 
in a unit, by substituting measurements of fuel carbon content, 
molecular weight (gaseous fuels, only), and the quantity of fuel 
combusted into the following Equations. For solid fuels, the amount of 
fuel combusted is obtained from company records kept as provided in 
this rule. For liquid and gaseous fuels, the volume of fuel combusted 
is measured directly, using fuel flow meters (including gas billing 
meters). For fuel oil, tank drop measurements may also be used.
    (i) For a solid fuel, use Equation C-3 of this section:
    [GRAPHIC] [TIFF OMITTED] TP10AP09.005
    
Where:

CO2 = Annual CO2 mass emissions from the 
combustion of the specific solid fuel (metric tons).
N = Number of required carbon content determinations for the year.
(Fuel)n = Mass of the solid fuel combusted in month ``n'' 
(metric tons).
P = Measurement period (month).
(CC)n = Carbon content of the solid fuel, from the fuel 
analysis results for month ``n'' (percent by weight, expressed as a 
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (ii) For a liquid fuel, use Equation C-4 of this section:
    [GRAPHIC] [TIFF OMITTED] TP10AP09.006
    
Where:

CO2 = Annual CO2 mass emissions from the 
combustion of the specific liquid fuel (metric tons).
N = Number of required carbon content determinations for the year.
(Fuel)n = Volume of the liquid fuel combusted in month 
``n'' (gallons).
P = Measurement period (month).
(CC)n = Carbon content of the liquid fuel, from the fuel 
analysis results for month ``n'' (kg C per gallon of fuel).
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] TP10AP09.007
    
Where:

CO2 = Annual CO2 mass emissions from 
combustion of the specific gaseous fuel (metric tons).
N = Number of required carbon content and molecular weight 
determinations for the year.
(Fuel)n = Volume of the gaseous fuel combusted on day 
``n'' or in month ``n'', as applicable (scf).
P = Measurement period (month or day, as applicable).

[[Page 16633]]

(CC)n = Average carbon content of the gaseous fuel, from 
the fuel analysis results for the day or month, as applicable (kg C 
per kg of fuel).
MW = Molecular weight of the gaseous fuel, from fuel analysis (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.

    (iv) In applying Equation C-5 of this section to natural gas 
combustion, the CO2 mass emissions are calculated only for 
those months in which natural gas is combusted during the reporting 
year. For the combustion of other gaseous fuels (e.g., refinery gas or 
process gas), the CO2 mass emissions are calculated only for 
those days on which the gaseous fuel is combusted during the reporting 
year. For example, if the unit combusts process gas on 250 of the 365 
days in the year, then n = 250 in Equation C-5 of this section.
    (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)(1)(iv)(D) 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] TP10AP09.008

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 (tons/scf-% 
CO2).

    (iii) If the CO2 concentration is measured on a dry 
basis, a correction for the stack gas moisture content is required. The 
owner or operator 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] TP10AP09.009

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 (tons/hr).
%H2O = Hourly moisture percentage in the stack gas 
(measured or default value, as appropriate).

    (iv) An oxygen (O2) concentration monitor may be used in 
lieu of a CO2 concentration monitor to determine the hourly 
CO2 concentrations, in accordance with Equation F-14a or F-
14b (as applicable) in appendix F to part 75 of this chapter, if the 
effluent gas stream monitored by the CEMS consists solely of combustion 
products and if only fuels that are listed in Table 1 in section 3.3.5 
of appendix F to part 75 of this chapter are combusted in the unit. If 
the O2 monitoring option is selected, the F-factors used in 
Equations F-14a and F-14b shall be determined according to section 
3.3.5 or section 3.3.6 of appendix F to part 75 of this chapter, as 
applicable. If Equation F-14b is used, the hourly moisture percentage 
in the stack gas shall be 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 
the entire calendar year.
    (vii) If both biogenic fuel and fossil fuel are combusted during 
the year, determine 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 may be used for any type of 
fuel combusted in a unit with a maximum rated heat input capacity of 
250 mmBtu/hr or less, provided that:
    (i) An applicable default CO2 emission factor and an 
applicable default high heat value for the fuel are specified in Table 
C-1 of this subpart.
    (ii) The owner or operator does not perform, or receive from the 
entity supplying the fuel, the results of fuel sampling and analysis on 
a monthly (or more frequent) basis that includes measurements of the 
HHV. If the owner or operator performs such fuel sampling and analysis 
or receives such fuel sampling and analysis results, the Tier 1 
Calculation Methodology shall not be used, and the Tier 2, Tier 3, or 
Tier 4 Calculation Methodology shall be used instead.
    (2) The Tier 1 Calculation Methodology may also be used to 
calculate the biogenic CO2 emissions from a unit of any size 
that combusts wood, wood waste, or other solid biomass-derived fuels, 
except when the Tier 4 Calculation Methodology is used to quantify the 
total CO2 mass emissions. If the Tier 4 Calculation 
Methodology is used, the biogenic CO2 emissions shall be 
calculated according to paragraph (e) of this section.
    (3) The Tier 2 Calculation Methodology may be used for any type of 
fuel combusted in any unit with a maximum rated heat input capacity of

[[Page 16634]]

250 mmBtu/hr or less, provided that a default CO2 emission 
factor for the fuel is specified in Table C-1 or C-2 of this subpart.
    (4) The Tier 3 Calculation Methodology may be used for a unit of 
any size, combusting any type of fuel, except when the use of Tier 4 is 
required or elected, as provided in paragraph (b)(5) of this section.
    (5) The Tier 4 Calculation Methodology:
    (i) May be used for a unit of any size, combusting any type of 
fuel.
    (ii) Shall be used for a unit if:
    (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, a stack 
gas volumetric flow rate monitor, or both and the monitors have been 
certified in accordance with the requirements of part 75 of this 
chapter, part 60 of this chapter, or an applicable State continuous 
monitoring program.
    (F) The installed gas and/or stack gas volumetric flow rate 
monitors are required, by an applicable Federal or State regulation or 
the unit's operating permit, to undergo periodic quality assurance 
testing in accordance with appendix B to part 75 of this chapter, 
appendix F to part 60 of this chapter, or an applicable State 
continuous monitoring program.
    (iii) Shall be used for a unit with a maximum rated heat input 
capacity of 250 mmBtu/hr or less and for a unit that combusts municipal 
solid waste with a maximum rated input capacity of 250 tons of MSW per 
day or less, if the unit:
    (A) Has both a stack gas volumetric flow rate monitor and a 
CO2 concentration monitor.
    (B) The unit meets the other conditions specified in paragraphs 
(b)(5)(ii)(B) and (C) of this section.
    (C) The CO2 and stack gas volumetric flow rate monitors 
meet the conditions specified in paragraphs (b)(5)(ii)(D) through 
(b)(5)(ii)(F) of this section.
    (6) The Tier 4 Calculation Methodology, if selected or required, 
shall be used beginning on:
    (i) January 1, 2010, for a unit 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, the 
owner or operator shall use the Tier 3 Calculation Methodology in 2010.
    (c) Calculation of CH4 and N2O emissions from all fuel combustion. 
Calculate the annual CH4 and N2O mass emissions 
from stationary fuel combustion sources as follows:
    (1) For units subject to the requirements of the Acid Rain Program 
and for other units monitoring and reporting heat input on a year-round 
basis according to Sec.  Sec.  75.10(c) and 75.64 of this chapter, use 
Equation C-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.010

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 report required under Sec.  75.64 
of this chapter (mmBtu).
EF = Fuel-specific emission factor for CH4 or 
N2O, from Table C-3 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kg to metric tons.

    (2) For all other units, use the applicable equations and 
procedures in paragraphs (c)(2) through (4) of this section to 
calculate the annual CH4 and N2O emissions.
    (i) If a default high heat value for a particular fuel is specified 
in Table C-1 of this subpart and if the HHV is not measured or provided 
by the entity supplying the fuel on a monthly (or more frequent) basis 
throughout the year, use Equation C-9 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.011

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, from company records 
(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-3 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10-\3\ = Conversion factor from kilograms to metric 
tons.

    (ii) If the high heat value of a particular fuel (except for 
municipal solid waste) is measured on a monthly (or more frequent) 
basis throughout the year, or if such data are provided by the entity 
supplying the fuel, use Equation C-10a of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.012

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a particular type of 
fuel (metric tons).
n = Number of required heat content measurements for the year.
(Fuel)p = Mass or volume of the fuel combusted during the 
measurement

[[Page 16635]]

period ``p'' (mass or volume per unit time).
(HHV)p = Measured high heat value of the fuel for period 
``p'' (mmBtu per mass or volume).
p = Measurement period (day or month, as applicable).
EF = Fuel-specific default emission factor for CH4 or 
N2O, from Table C-3 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10\-3\ = Conversion factor from kilograms to metric tons.

    (iii) For municipal solid waste combustion, use Equation C-10b of 
this section to estimate CH4 and N2O emissions:
[GRAPHIC] [TIFF OMITTED] TP10AP09.013

Where:

CH4 or N2O = Annual CH4 or 
N2O emissions from the combustion of a municipal solid 
waste (metric tons).
Steam = Total mass of steam generated by MSW 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-3 of this subpart (kg CH4 or 
N2O per mmBtu).
1 x 10\-3\ = Conversion factor from kilograms to metric tons.

    (3) Multiply the result from Equations C-8, C-9, C-10a, or C-10b of 
this section (as applicable) by the global warming potential (GWP) 
factor to convert the CH4 or N2O emissions to 
metric tons of CO2 equivalent.
    (4) If, for a particular type of fuel, default CH4 and 
N2O emission factors are not provided in Table C-4 of this 
subpart, the owner or operator may, subject to the approval of the 
Administrator, develop site-specific CH4 and N2O 
emission factors, based on the results of source testing.
    (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 the following equation to calculate the CO2 
emissions from the sorbent, if those CO2 emissions are not 
monitored by CEMS:
[GRAPHIC] [TIFF OMITTED] TP10AP09.014

Where:

CO2 = CO2 emitted from sorbent for the 
reporting year (metric tons).
S = Limestone or other sorbent used in the reporting year (metric 
tons).
R = Ratio of moles of CO2 released upon capture of one 
mole of acid gas.
MWCO2 = Molecular weight of carbon dioxide (44).
MWS = Molecular weight of sorbent (100, if calcium 
carbonate).

    (2) The total 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) Biogenic CO2 emissions. If any fuel combusted in the 
unit meet the definition of biomass or biomass-derived fuel in Sec.  
98.6, then the owner or operator shall estimate and report the total 
annual biogenic CO2 emissions, according to paragraph 
(e)(1), (2), (3), or (4) of this section, as applicable.
    (1) The owner or operator may use Equation C-1 of this section to 
calculate the annual CO2 mass emissions from the combustion 
of biogenic fuel, for a unit of any size, provided that:
    (i) The Tier 4 calculation methodology is not required or elected.
    (ii) The biogenic fuel consists of wood, wood waste, or other 
biomass-derived solid fuels (except for MSW).
    (2) If CEMS are used to determine the total annual CO2 
emissions, either according to part 75 of this chapter or the Tier 4 
Calculation Methodology of this section and if both fossil fuel and 
biogenic fuel (except for MSW) are combusted in the unit during the 
reporting year, 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] TP10AP09.015

Where:

VCO2h = Hourly volume of CO2 emitted (scf).
(%CO2)h = Hourly CO2 concentration, 
measured by the CO2 concentration monitor 
(%CO2).
Qh = Hourly 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] TP10AP09.016

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 (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 part 75 
of this chapter or a site-specific value determined under section 
3.3.6 of appendix F to part 75 of this chapter (scf CO2/
mmBtu).
GCV = Gross calorific 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).
10 \6\ = Conversion factor, Btu per mmBtu.

    (iv) Subtract Vff from Vtotal to obtain 
Vbio, the annual volume of CO2 from the 
combustion of biogenic fuels.
    (v) Calculate the biogenic percentage of the annual CO2 
emissions, using Equation C-14 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.017


[[Page 16636]]


    (vi) Calculate the annual biogenic CO2 mass emissions, 
in metric tons, by multiplying the percent Biogenic obtained from 
Equation C-14 of this section of this section by the total annual 
CO2 mass emissions in metric tons, as determined under 
paragraph (a)(1)(iv) of this section.
    (3) For a unit that combusts MSW, the owner or operator shall use, 
for each quarter, ASTM Methods D 6866-06a and D 7459-08, as described 
in Sec.  98.34(f), to determine the relative proportions of biogenic 
and non-biogenic CO2 emissions when MSW is combusted. The 
results of each determination shall be expressed as a decimal fraction 
(e.g., 0.30, if 30 percent of the CO2 from MSW combustion is 
biogenic), and the quarterly values shall be averaged over the 
reporting year. The annual biogenic CO2 emissions shall be 
calculated as follows:
    (i) If the unit qualifies for the Tier 2 or Tier 3 Calculation 
Methodology of this section and the owner or operator elects to use the 
Tier 2 or Tier 3 Calculation Methodology to quantify GHG emissions:
    (A) Use Equations C-2a, C-2b and C-3 of this section, as 
applicable, to calculate the annual CO2 mass emissions from 
MSW combustion and from any auxiliary fuels such as natural gas. Sum 
these values, to obtain the total annual CO2 mass emissions 
from the unit.
    (B) Determine the annual biogenic CO2 mass emissions 
from MSW combustion as follows. Multiply the total annual 
CO2 mass emissions from MSW combustion by the biogenic 
decimal fraction obtained from ASTM Methods D 6866-06a and D 7459-08.
    (ii) If the unit uses CEMS 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 total annual volume of CO2 emissions 
from MSW combustion.
    (D) Determine the annual volume of biogenic CO2 
emissions from MSW combustion as follows. Multiply the annual volume of 
CO2 emissions from MSW combustion by the biogenic decimal 
fraction obtained from ASTM Methods D 6866-06a and D 7459-08.
    (E) Calculate the biogenic percentage of the total 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) of this section.
    (4) For biogas combustion, the Tier 2 or Tier 3 Calculation 
Methodology shall be used to determine the annual biogenic 
CO2 mass emissions, except as provided in paragraph (e)(2) 
of this section.


Sec.  98.34  Monitoring and QA/QC requirements.

    The CO2 mass emissions data for stationary combustion 
units shall be quality-assured as follows:
    (a) For units using the calculation methodologies described in this 
paragraph, the records required under Sec.  98.3(g) shall include both 
the company records and a detailed explanation of how company records 
are used to estimate the following:
    (1) Fuel consumption, when the Tier 1 and Tier 2 Calculation 
Methodologies described in Sec.  98.33(a) are used.
    (2) Fuel consumption, when solid fuel is combusted and the Tier 3 
Calculation Methodology in Sec.  98.33(a)(3) is used.
    (3) 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.
    (4) Sorbent usage, if the methodology in Sec.  98.33(d) is used to 
calculate CO2 emissions from sorbent.
    (b) The owner or operator shall document the procedures used to 
ensure the accuracy of the estimates of fuel usage and sorbent usage 
(as applicable) in paragraph (a) of this section, 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.
    (c) For the Tier 2 Calculation Methodology, the applicable fuel 
sampling and analysis methods incorporated by reference in Sec.  98.7 
shall be used to determine the high heat values. For coal, the samples 
shall be taken at a location in the fuel handling system that provides 
a sample representative of the fuel bunkered or consumed. The minimum 
frequency of the sampling and analysis for each type of fuel (only for 
the weeks or months when that fuel is combusted in the unit) is as 
follows:
    (1) Monthly, for natural gas, biogas, fuel oil, and other liquid 
fuels.
    (2) For coal and other solid fuels, weekly sampling is required to 
obtain composite samples, which are analyzed monthly.
    (d) For the Tier 3 Calculation Methodology:
    (1) All oil and gas flow meters (except for gas billing meters) 
shall be calibrated prior to the first year for which GHG emissions are 
reported under this part, using an applicable flow meter test method 
listed in Sec.  98.7 or the calibration procedures specified by the 
flow meter manufacturer. Fuel flow meters shall be recalibrated either 
annually or at the minimum frequency specified by the manufacturer.
    (2) Oil tank drop measurements (if applicable) shall be performed 
according to one of the methods listed in Sec.  98.7.
    (3) The carbon content of the fuels listed in paragraphs (c)(1) and 
(2) of this section shall be determined monthly. For other gaseous 
fuels (e.g., refinery gas, or process gas), daily sampling and analysis 
is required to determine the carbon content and molecular weight of the 
fuel. An applicable method listed in Sec.  98.7 shall be used to 
determine the carbon content and (if applicable) molecular weight of 
the fuel.
    (e) 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)(6).
    (1) For initial certification, use the following procedures:
    (i) Section 75.20(c)(2) and (4) and appendix A to part 75) of this 
chapter.
    (ii) The calibration drift test and relative accuracy test audit 
(RATA) procedures of Performance Specification 3 in appendix B to part 
60 (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 part 75 of 
this chapter, part 60 of this chapter, or an applicable State 
continuous monitoring program shall be followed for initial 
certification and on-going quality assurance, and all required RATAs of 
the monitor shall be done on a percent CO2 basis.
    (3) For ongoing quality assurance, follow the applicable procedures 
in appendix B to part 75 of this chapter, appendix F to part 60 of this 
chapter, or an applicable State continuous monitoring program. If 
appendix F to

[[Page 16637]]

part 60 of this chapter is selected for on-going quality assurance, 
perform daily calibration drift (CD) assessments for both the 
CO2 and flow rate monitors, conduct cylinder gas audits of 
the CO2 concentration monitor in three of the four quarters 
of each year (except for non-operating quarters), and perform annual 
RATAs of the CO2 concentration monitor and the CERMS.
    (4) For the purposes of this part, the stack gas volumetric flow 
rate monitor RATAs required by appendix B to part 75 of this chapter 
and the annual RATAs of the CERMS required by appendix F to part 60 of 
this chapter need only be done at one operating level, representing 
normal load or normal process operating conditions, both for initial 
certification and for ongoing quality assurance.
    (f) When municipal solid waste (MSW) is combusted in a unit, the 
biogenic portion of the CO2 emissions from MSW combustion 
shall be determined using ASTM D6866-06a and ASTM D7459-08. The ASTM 
D6866-06a analysis shall be performed at least once in every calendar 
quarter in which MSW is combusted in the unit. Each gas sample shall be 
taken using ASTM D7459-08, 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 D6866-06a. The owner or operator shall 
separate total CO2 emissions from MSW combustion in to 
biogenic emissions and non-biogenic emissions, using the average 
proportion of biogenic emissions of all samples analyzed during the 
reporting year. If there is a common fuel source of MSW that feeds 
multiple units at the facility, performing the testing at only one of 
the units is sufficient.


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, the applicable missing data substitution procedures in part 75 
of this chapter shall be followed for CO2 concentration, 
stack gas flow rate, fuel flow rate, gross calorific value (GCV), and 
fuel carbon content.
    (b) For all units that are not subject to the requirements of the 
Acid Rain Program, when the Tier 1, Tier 2, Tier 3, or Tier 4 
calculation is used, perform missing data substitution as follows for 
each parameter:
    (1) For each missing value of the heat content, carbon content, or 
molecular weight of the fuel, and for each missing value of 
CO2 concentration and percent moisture, 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 missing records of stack gas flow rate, fuel usage, and 
sorbent usage, the substitute data value shall be the best available 
estimate of the flow rate, fuel usage, or sorbent consumption, based on 
all available process data (e.g., steam production, electrical load, 
and operating hours). The owner or operator shall document and keep 
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 paragraph (b) and (c) of this 
section (as applicable) and the emissions verification data in 
paragraph (d) of this section.
    (b) Unit-level emissions data reporting. Except where aggregation 
of unit-level information is permitted under paragraph (c) of this 
section, the owner or operator shall report:
    (1) The unit ID number (if applicable).
    (2) A code representing the type of unit.
    (3) Maximum rated heat input capacity of the unit, in mmBtu/hr 
(boilers, combustion turbines, engines, and process heaters only).
    (4) Each type of fuel combusted in the unit during the report year.
    (5) The calculated CO2, CH4, and 
N2O emissions for each type of fuel combusted, expressed in 
metric tons of each gas and in metric tons of CO2e.
    (6) The method used to calculate the CO2 emissions for 
each type of fuel combusted (e.g., part 75 of this chapter or the Tier 
1 or Tier 2 calculation methodology)
    (7) If applicable, indicate which one of the monitoring and 
reporting methodologies in part 75 of this chapter was used to quantify 
the CO2 emissions (e.g., CEMS, appendix G, LME).
    (8) The calculated CO2 emissions from sorbent (if any), 
expressed in metric tons.
    (9) The total GHG emissions from the unit for the reporting year, 
i.e., the sum of the CO2, CH4, and N2O 
emissions for all fuel types, expressed in metric tons of 
CO2e.
    (c) Reporting alternatives for stationary combustion units. For 
stationary combustion units, the following reporting alternatives may 
be used to simplify the unit-level reporting required under paragraph 
(b) of this section:
    (1) Aggregation of small units. If a facility contains two or more 
units (e.g., boilers or combustion turbines) that have a combined 
maximum rated heat input capacity of 250 mmBtu/hr or less, the owner or 
operator may report the combined emissions for the group of units in 
lieu of reporting separately the GHG emissions from the individual 
units, provided that the amount of each type of fuel combusted in the 
units in the group is accurately quantified. More than one such group 
of units may be defined at a facility, so long as the aggregate maximum 
rated heat input capacity of the units in the group does not exceed 250 
mmBtu/hr. 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) The ID number of each unit in the group.
    (iii) Cumulative maximum rated heat input capacity of the group 
(mmBtu/hr).
    (iv) Each type of fuel combusted in the units during the reporting 
year.
    (v) The calculated CO2, CH4, and 
N2O mass emissions 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.
    (vi) The methodology used to calculate the CO2 mass 
emissions for each type of fuel combusted in the units.
    (vii) The calculated CO2 mass emissions (if any) from 
sorbent.
    (viii) The total GHG emissions from the group for the year, i.e., 
the sum of the CO2, CH4, and N2O 
emissions across, all fuel types, expressed in metric tons of 
CO2e.
    (2) Monitored common stack configurations. When the flue gases from 
two or more stationary combustion units at a facility are discharged 
through a common stack, if CEMS are used to continuously monitor 
CO2 mass emissions at the common stack according to part 75 
of this chapter or as described in the Tier 4 Calculation Methodology 
in Sec.  98.33(a)(4), the owner or operator may report the combined 
emissions from the units sharing the

[[Page 16638]]

common stack, in lieu of reporting separately the GHG emissions from 
the individual units. If this option is selected, the following 
information shall be reported instead of the information in paragraph 
(b) of this section:
    (i) Common stack ID number, beginning with the prefix ``CS''.
    (ii) ID numbers of the units sharing the common stack.
    (iii) Maximum rated heat input capacity of each unit sharing the 
common stack (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., CEMS or the Tier 4 Calculation Methodology).
    (vi) The total CO2 mass emissions measured at the common 
stack for the year, expressed in metric tons of CO2e.
    (vii) The combined annual CH4 and N2O 
emissions from the units sharing the common stack, expressed in metric 
tons of each gas and in metric tons of CO2e.
    (A) If the monitoring is done according to part 75 of this chapter, 
use Equation C-8 of this subpart, where the term ``(HI)A'' 
is the cumulative annual heat input measured at the common stack.
    (B) For the Tier 4 calculation methodology, use Equation C-9, C-10a 
or C-10b of this subpart separately for each type of fuel combusted in 
the units during the year, and then sum the emissions for all fuel 
types.
    (viii) The total GHG emissions for the year from the units that 
share the common stack, 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 oil-fired or gas-
fired stationary combustion units at a facility combust the same type 
of fuel and that fuel is fed to the individual units through a common 
supply line or pipe, the owner or operator may report the combined 
emissions from the units served by the common supply line, in lieu of 
reporting separately 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 
calibrated fuel flow meter. If this option is selected, the following 
information shall be reported instead of the information in paragraph 
(b) of this section:
    (i) Common pipe ID number, beginning with the prefix ``CP''.
    (ii) ID 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 type of fuel combusted in the units during the reporting 
year.
    (v) The methodology used to calculate the CO2 mass 
emissions.
    (vi) The total CO2 mass emissions from the units served 
by the common pipe for the reporting year, expressed in metric tons of 
CO2e.
    (vii) The combined 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) The total GHG emissions for the reporting year from the 
units served by the common pipe, i.e., the sum of the CO2, 
CH4, and N2O emissions, expressed in metric tons 
of CO2e.
    (d) Verification data. The owner or operator shall report 
sufficient data and supplementary information to verify the reported 
GHG emissions.
    (1) For stationary combustion sources using the Tier 1, Tier 2, 
Tier 3, or Tier 4 Calculation Methodology in Sec.  98.33(a)(4) to 
quantify CO2 emissions, the following additional information 
shall be included in the GHG emissions report:
    (i) For the Tier 1 Calculation Methodology, report the total 
quantity of each type of fuel combusted during the reporting year, in 
short tons for solid fuels, gallons for liquid fuels and scf for 
gaseous fuels.
    (ii) For the Tier 2 Calculation Methodology, report:
    (A) The total quantity of each type of fuel combusted during each 
month (except for MSW). 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 number of required high heat value determinations for each 
type of fuel for the reporting year (i.e., ``n'' in Equation C-2a of 
this subpart, corresponding (as applicable) to the number of operating 
days or months when each type of fuel was combusted, in accordance with 
Sec.  Sec.  98.33(a)(2) and 98.34(c).
    (C) For each month, the high heat value used in Equation C-2a of 
this subpart 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.
    (D) For each reported HHV, indicate whether it is an actual 
measured value or a substitute data value.
    (E) Each method from Sec.  98.7 used to determine the HHV for each 
type of fuel combusted.
    (F) For MSW, the total quantity (i.e., lb) of steam produced from 
MSW combustion during the year, and ``B'', the ratio of the unit's 
maximum rate heat input capacity to its design rated steam output 
capacity, in mmBtu per lb of steam.
    (iii) For the Tier 3 Calculation Methodology, report:
    (A) The total quantity of each type of fuel combusted during each 
month or day (as applicable), in metric tons for solid fuels, gallons 
for liquid fuels, and scf for gaseous fuels.
    (B) The number of required carbon content determinations for each 
type of fuel for the reporting year, corresponding (as applicable) to 
the number of operating days or months when each type of fuel was 
combusted, in accordance with Sec. Sec.  98.33(a)(3) and 98.34(d).
    (C) For each operating month or day, the carbon content (CC) value 
used in Equation C-3, C-4, or C-5 of this subpart (as applicable), 
expressed as a decimal fraction for solid fuels, kg C per gallon for 
liquid fuels, and kg C per kg of fuel for gaseous fuels.
    (D) For gaseous fuel combustion, the molecular weight of the fuel 
used in Equation C-5 of this subpart, for each operating month or day, 
in kg per kg-mole.
    (E) For each reported CC value, indicate whether it is an actual 
measured value or a substitute data value.
    (F) For liquid and gaseous fuel combustion, the dates and results 
of the initial calibrations and periodic recalibrations of the fuel 
flow meters used to measure the amount of fuel combusted.
    (G) For fuel oil combustion, each method from Sec.  98.7 used to 
make tank drop measurements (if applicable).
    (H) Each method from Sec.  98.7 used to determine the CC for each 
type of fuel combusted.
    (I) Each method from Sec.  98.7 used to calibrate the fuel flow 
meters (if applicable).
    (iv) For the Tier 4 Calculation Methodology, report:
    (A) The total number of source operating days and the total number 
of source operating hours in the reporting year.
    (B) Whether the CEMS certification and quality assurance procedures 
of part 75 of this chapter, part 60 of this chapter, or an applicable 
State continuous monitoring program have been selected.
    (C) The CO2 emissions on each operating day, i.e., the 
sum of the hourly values calculated from Equation C-6 or C-7 (as 
applicable), in metric tons.
    (D) For CO2 concentration, stack gas flow rate, and (if 
applicable) stack gas moisture content, the number of source operating 
hours in which a substitute

[[Page 16639]]

data value of each parameter was used in the emissions calculations.
    (E) The dates and results of the initial certification tests of the 
CEMS, and
    (F) 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).
    (v) 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 
metric tons.
    (B) The molecular weight of the sorbent.
    (C) The ratio (``R'') in Equation C-11 of this subpart.
    (vi) When ASTM methods D7459-08 and D6866-06a are used to determine 
the biogenic portion of the annual CO2 emissions from MSW 
combustion, as described in Sec. Sec.  98.33(e) and 98.34(f), the owner 
or operator shall 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) The total quantity of MSW combusted during the reporting year, 
in short tons if the Tier 2 Calculation Methodology is used or in 
metric tons if the Tier 3 calculation methodology is used.
    (vii) For units that combust both fossil fuel and biogenic fuel, 
when CEMS are used to quantify the annual CO2 emissions, the 
owner or operator 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 biogenic fuels, i.e., Vbio, in scf.
    (D) The carbon-based F-factor used in Equation C-14 of this 
subpart, for each type of fossil fuel combusted, in scf CO2 
per mmBtu.
    (E) The annual average GCV value used in Equation C-14 of this 
subpart, for each type of fossil fuel combusted, 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) The total annual biogenic CO2 mass emissions, in 
metric tons.
    (2) Within 7 days of receipt of a written request (e.g., a request 
by electronic mail) from the Administrator or from the applicable State 
or local air pollution control agency, the owner or operator shall 
submit the explanations described in Sec.  98.34(a) and (b), as 
follows:
    (i) A detailed explanation of how company records are used to 
quantify fuel consumption, if Calculation Methodology Tier 1 or Tier 2 
of this subpart is used to calculate CO2 emissions.
    (ii) A detailed explanation of how company records are used to 
quantify fuel consumption, if solid fuel is combusted and the Tier 3 
Calculation Methodology in Sec.  98.33(a)(3) is used to calculate 
CO2 emissions.
    (iii) A detailed explanation of how sorbent usage is quantified, if 
the methodology in Sec.  98.33(d) is used to calculate CO2 
emissions from sorbent.
    (iv) A detailed explanation of how company records are used to 
quantify fossil fuel consumption, when, as described in Sec.  98.33(e), 
the owner or operator of a unit that combusts both fossil fuel and 
biogenic fuel uses CEMS to quantify CO2 emissions.


Sec.  98.37  Records that must be retained.

    The recordkeeping requirements of Sec.  98.3(g) and, if applicable, 
Sec.  98.34(a) and (b) shall be fully met for affected facilities with 
stationary combustion sources. Also, the records required under Sec.  
98.35(a)(1), documenting the data substitution procedures for missing 
stack flow rate, fuel flow rate, fuel usage and (if applicable) sorbent 
usage information and site-specific source testing (as allowed in Sec.  
98.33(c)(4)), shall be retained. No special recordkeeping beyond that 
specified in Sec. Sec.  98.3, 98.35(a)(4), and 98.34(a) and (b) is 
required. All required records must be retained for a period of five 
years.


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 of Subpart C--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
Sub-bituminous....................              17.25              97.02
Lignite...........................              14.21              96.36
Unspecified (Residential/                       22.24              95.26
 Commercial)......................
Unspecified (Industrial Coking)...              26.28              93.65
Unspecified (Other Industrial)....              22.18              93.91
Unspecified (Electric Power)......              19.97             94.38.
Coke..............................              24.80             102.04
------------------------------------------------------------------------
            Natural Gas                 mmBtu/scf        kg CO2/mmBtu.
------------------------------------------------------------------------
Unspecified (Weighted U.S.             1.027 x 10-\3\              53.02
 Average).........................
------------------------------------------------------------------------
        Petroleum Products             mmBtu/gallon       kg CO2/mmBtu
------------------------------------------------------------------------
Asphalt & Road Oil................              0.158              75.55
Aviation gasoline.................              0.120              69.14
Distillate Fuel Oil ( 1,               0.139              73.10
 2, & 4)..........................
Jet Fuel..........................              0.135              70.83
Kerosene..........................              0.135              72.25
LPG (energy use)..................              0.092              62.98

[[Page 16640]]

 
Propane...........................              0.091              63.02
Ethane............................              0.069              59.54
Isobutane.........................              0.099              65.04
n-Butane..........................              0.103              64.93
Lubricants........................              0.144              74.16
Motor Gasoline....................              0.124              70.83
Residual Fuel Oil ( 5 &                0.150              78.74
 6)...............................
Crude Oil.........................              0.138              74.49
Naphtha (< 401 deg. F)............              0.125              66.46
Natural Gasoline..................              0.110              66.83
Other Oil (> 401 deg. F)..........              0.139              73.10
Pentanes Plus.....................              0.110              66.83
Petrochemical Feedstocks..........              0.129              70.97
Petroleum Coke....................              0.143             102.04
Special Naphtha...................              0.125              72.77
Unfinished Oils...................              0.139              74.49
Waxes.............................              0.132              72.58
------------------------------------------------------------------------
   Biomass-derived Fuels (solid)     mmBtu/short Ton      kg CO2/mmBtu
------------------------------------------------------------------------
Wood and Wood waste (12% moisture               15.38              93.80
 content) or other solid biomass-
 derived fuels....................
------------------------------------------------------------------------
    Biomass-derived Fuels (Gas)             mmBtu/scf       kg CO2/mmBtu
------------------------------------------------------------------------
Biogas............................             Varies             52.07
------------------------------------------------------------------------
Note: Heat content factors are based on higher heating values (HHV).
  Also, for petroleum products, the default heat content values have
  been converted from units of mmBtu per barrel to mmBtu per gallon.


 Table C-2 of Subpart C--Default CO2 Emission Factors for the Combustion
                          of Alternative Fuels
------------------------------------------------------------------------
                                                          Default CO2
                      Fuel type                         emission factor
                                                        (kg CO2/mmBtu)
------------------------------------------------------------------------
Waste Oil...........................................              74
Tires...............................................              85
Plastics............................................              75
Solvents............................................              74
Impregnated Saw Dust................................              75
Other Fossil based wastes...........................              80
Dried Sewage Sludge.................................             110
Mixed Industrial waste..............................              83
Municipal Solid Waste...............................              90.652 
------------------------------------------------------------------------
Note: Emission factors are based on higher heating values (HHV). Values
  were converted from LHV to HHV assuming that LHV are 5 percent lower
  than HHV for solid and liquid fuels.


Table C-3 of Subpart C--Default CH4 and N2O Emission Factors for Various
                              Types of Fuel
------------------------------------------------------------------------
                                       Default CH4        Default N2O
             Fuel type               emission factor    emission factor
                                      (kg CH4/mmBtu)     (kg N2O/mmBtu)
------------------------------------------------------------------------
Asphalt...........................       3.0 x 10-\3\       6.0 x 10-\4\
Aviation Gasoline.................       3.0 x 10-\3\       6.0 x 10-\4\
Coal..............................       1.0 x 10-\2\       1.5 x 10-\3\
Crude Oil.........................       3.0 x 10-\3\       6.0 x 10-\4\
Digester Gas......................       9.0 x 10-\4\       1.0 x 10-\4\
Distillate........................       3.0 x 10-\3\       6.0 x 10-\4\
Gasoline..........................       3.0 x 10-\3\       6.0 x 10-\4\
Jet Fuel..........................       3.0 x 10-\3\       6.0 x 10-\4\
Kerosene..........................       3.0 x 10-\3\       6.0 x 10-\4\
Landfill Gas......................       9.0 x 10-\4\       1.0 x 10-\4\
LPG...............................       1.0 x 10-\3\       1.0 x 10-\4\
Lubricants........................       3.0 x 10-\3\       6.0 x 10-\4\
Municipal Solid Waste.............       3.0 x 10-\2\       4.0 x 10-\3\
Naphtha...........................       3.0 x 10-\3\       6.0 x 10-\4\
Natural Gas.......................       9.0 x 10-\4\       1.0 x 10-\4\
Natural Gas Liquids...............       3.0 x 10-\3\       6.0 x 10-\4\
Other Biomass.....................       3.0 x 10-\2\       4.0 x 10-\3\

[[Page 16641]]

 
Petroleum Coke....................       3.0 x 10-\3\       6.0 x 10-\4\
Propane...........................       1.0 x 10-\3\       1.0 x 10-\4\
Refinery Gas......................       9.0 x 10-\4\       1.0 x 10-\4\
Residual Fuel Oil.................       3.0 x 10-\3\       6.0 x 10-\4\
Tites.............................       3.0 x 10-\3\       6.0 x 10-\4\
Waste Oil.........................       3.0 x 10-\2\       4.0 x 10-\3\
Waxes.............................       3.0 x 10-\3\       6.0 x 10-\4\
Wood and Wood Waste...............       3.0 x 10-\2\       4.0 x 10-\3\
------------------------------------------------------------------------
Note: Values were converted from LHV to HHV assuming that LHV are 5
  percent lower than HHV for solid and liquid fuels and 10 percent lower
  for gaseous fuels. 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 all 
facilities with one or more electricity generating units, including 
electricity generating units that are subject to the requirements of 
the Acid Rain Program.
    (b) This source category does not include portable equipment or 
generating units designated as emergency generators in a permit issued 
by a State or local air pollution control agency.


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


Sec.  98.42  GHGs to report.

    The annual mass emissions of CO2, N2O, and 
CH4 shall be reported for each electricity generating unit.


Sec.  98.43  Calculating GHG emissions.

    (a) For each electricity generating unit subject to the 
requirements of the Acid Rain Program, the owner or operator shall 
continue to monitor and report CO2 mass emissions as 
required under Sec. Sec.  75.13 and 75.64 of this chapter. 
CO2 emissions for the purposes of the GHG emissions reports 
required under Sec. Sec.  98.3 and 98.36 shall be calculated as 
follows:
    (1) The owner or operator shall convert the cumulative annual 
CO2 mass emissions reported in the fourth quarter electronic 
data report required under Sec.  75.64 of this chapter from units of 
short tons to metric tons. To convert tons to metric tons, divide by 
1.1023.
    (2) The annual CH4 and N2O mass emissions 
shall be calculated using the methods specified in Sec.  98.33 for 
stationary fuel combustion units.
    (b) For each unit that is not subject to the reporting requirements 
of the Acid Rain Program, the annual CO2, CH4, 
and N2O mass emissions shall be calculated using the methods 
specified in Sec.  98.33 for stationary fuel combustion units.


Sec.  98.44  Monitoring and QA/QC requirements.

    (a) For electricity generation units subject to the requirements of 
the Acid Rain Program, the CO2 emissions data shall be 
quality assured according to the applicable procedures in appendices B, 
D, and G to part 75 of this chapter.
    (b) For electricity generating units that are not subject to the 
requirements of the Acid Rain Program, the quality assurance and 
quality control procedures specified in Sec.  98.34 for stationary fuel 
combustion units shall be followed.


Sec.  98.45  Procedures for estimating missing data.

    (a) For electricity generation units subject to the requirements of 
the Acid Rain Program, the applicable missing data substitution 
procedures in part 75 of this chapter shall be followed for 
CO2 concentration, stack gas flow rate, fuel flow rate, 
gross calorific value (GCV), and fuel carbon content.
    (b) For each electricity generating unit that is not subject to the 
requirements of the Acid Rain Program, the missing data substitution 
procedures specified in Sec.  98.35 for stationary fuel combustion 
units shall be implemented.


Sec.  98.46  Data reporting requirements.

    (a) For electricity generation units subject to the requirements of 
the Acid Rain Program, the owner or operator of a facility containing 
one or more electricity generating units shall meet the data reporting 
requirements specified in Sec.  98.36(b) and, if applicable, Sec.  
98.36(c)(2) or (3).
    (b) For electricity generating units not subject to the 
requirements of the Acid Rain Program, the owner or operator of a 
facility containing one or more electricity generating units shall meet 
the data reporting and verification requirements specified in Sec.  
98.36.


Sec.  98.47  Records that must be retained.

    The owner or operator of a facility containing one or more 
electricity generating units shall meet the recordkeeping requirements 
of Sec.  98.3(g) and, if applicable, Sec.  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 from adipic 
acid production as required by this subpart.
    (b) You must report CO2, CH4, and 
N2O emissions from each stationary combustion unit that uses 
a carbon-based fuel, following the requirements of subpart C of this 
part.


Sec.  98.53  Calculating GHG emissions.

    You must determine annual N2O emissions from adipic acid 
production using a facility-specific emission factor according to 
paragraphs (a) through (e) of this section.
    (a) You must conduct an annual performance test to measure 
N2O emissions from the waste gas streams of

[[Page 16642]]

each adipic acid oxidation process. You must conduct the performance 
test under normal process operating conditions.
    (b) You must conduct the emissions test using the methods specified 
in Sec.  98.54(b).
    (c) You must measure the adipic acid production rate for the 
facility during the test and calculate the production rate for the test 
period in metric tons per hour.
    (d) You must calculate an average facility-specific emission factor 
according to Equation E-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.018

Where:

EFN2O = Average facility-specific N2O 
emissions factor (lb N2O/ton adipic acid produced).
CN2O = N2O concentration during performance 
test (ppm N2O).
1.14x10-7 = Conversion factor (lb/dscf-ppm 
N2O).
Q = Volumetric flow rate of effluent gas (dscf/hr).
P = Production rate during performance test (tons adipic acid 
produced/hr).
n = Number of test runs.

    (e) You must calculate annual adipic acid production process 
emissions of N2O for the facility by multiplying the 
emissions factor by the total annual adipic acid production at the 
facility, according to Equation E-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.019

Where:

EN2O = N2O mass emissions per year (metric 
tons of N2O).
EFN2O = Facility-specific N2O emission factor 
(lb N2O/ton adipic acid produced).
Pa = Total production for the year (ton adipic acid 
produced).
DFN = Destruction factor of N2O abatement 
technology (abatement device manufacturer's specified destruction 
efficiency, percent of N2O removed from air stream).
AFN = Abatement factor of N2O abatement 
technology (percent of year that abatement technology was used).
2205 = Conversion factor (lb/metric ton).


Sec.  98.54  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new 
facility-specific emissions factor at least annually. You must also 
conduct a new performance test whenever the production rate is changed 
by more than 10 percent from the production rate measured during the 
most recent performance test. The new emissions factor may be 
calculated using all available performance test data (i.e., average 
with the data from previous years), except in cases where process 
modifications have occurred or operating conditions have changed. Only 
the data consistent with the reporting period after the changes were 
implemented shall be used.
    (b) You must conduct each emissions test using EPA Method 320 in 40 
CFR part 63, Appendix A or ASTM D6348-03 (incorporated by reference--
see Sec.  98.7) to measure the N2O concentration 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.
    (c) Each facility must conduct all required performance tests 
according to a test plan and EPA Method 320 in 40 CFR part 63, appendix 
A or ASTM D6348-03 (incorporated by reference-see Sec.  98.7). 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)(1) through (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 during the test and how it was determined. 
The production rate can be determined through sales records, or through 
direct measurement using flow meters or weigh scales.


Sec.  98.55  Procedures for estimating missing data.

    Procedures for estimating missing data are not provided for 
N2O process emissions for adipic acid production facilities 
calculated according to Sec.  98.53. A complete record of all measured 
parameters used in the GHG emissions calculations is required.


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 (h) of this section for each adipic acid production facility:
    (a) Annual N2O emissions from adipic acid production in 
metric tons.
    (b) Annual adipic acid production capacity (in metric tons).
    (c) Annual adipic acid production, in units of metric tons of 
adipic acid produced.
    (d) Number of facility operating hours in calendar year.
    (e) Emission rate factor used (lb N2O/ton adipic acid).
    (f) Abatement technology used (if applicable).
    (g) Abatement technology efficiency (percent destruction).
    (h) Abatement utilization factor (percent of time that abatement 
system is operating).


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 (f) of this 
section at the facility level:
    (a) Annual N2O emissions from adipic acid production, in 
metric tons.
    (b) Annual adipic acid production capacity, in metric tons.
    (c) Annual adipic acid production, in units of metric tons of 
adipic acid produced.
    (d) Number of facility operating hours in calendar year.
    (e) Measurements, records and calculations used to determine the 
annual production rate.

[[Page 16643]]

    (f) Emission rate factor used and supporting test or calculation 
information including the annual emission rate factor determination 
report specified in Sec.  98.54(c). This report must be available upon 
request.


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


Sec.  98.62  GHGs to report.

    You must report:
    (a) Total perfluoromethane (CF4), and perfluoroethane 
(C2F6) emissions from anode effects in all 
prebake and S[oslash]derberg electrolysis cells.
    (b) Total CO2 emissions from anode consumpton during 
electrolysis in all prebake and S[oslash]derberg electrolysis cells.
    (c) Total CO2 emissions from anode baking for all 
prebake cells.
    (d) For CO2, N2O, and CH4 
emissions from stationary fuel combustion units, you must follow the 
requirements in subpart C of this part.


Sec.  98.63  Calculating GHG emissions.

    (a) Use Equation F-1 of this section to estimate CF4 
emissions from anode effects, and use Equation F-2 to estimate 
C2F6 emissions from anode effects from each 
prebake and S[oslash]derberg electrolysis cell.
[GRAPHIC] [TIFF OMITTED] TP10AP09.020

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] TP10AP09.021

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.

    (b) 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-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.022

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 = Total 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-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.023

Where:

ECO2 = Annual CO2 emissions from paste 
consumption (metric ton CO2).
PC = Annual paste consumption (metric ton/metric ton Al).
MP = Total 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.

(c) Use the following procedures to calculate CO2 emissions 
from anode baking of prebake cells:

[[Page 16644]]

(1) Use Equation F-5 of this section to calculate emissions from pitch 
volatiles.
[GRAPHIC] [TIFF OMITTED] TP10AP09.024

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-6 of this section to calculate emissions from 
bake furnace packing material.
[GRAPHIC] [TIFF OMITTED] TP10AP09.025

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.


Sec.  98.64  Monitoring and QA/QC requirements.

    (a) The smelter-specific slope coefficient must be measured at 
least every 36 months in accordance with the EPA/IAI Protocol for 
Measurement of Tetrafluoromethane and Hexafluoroethane Emissions from 
Primary Aluminum Production (2008).
    (b) The minimum frequency of the measurement and analysis is 
annually except as follows: Monthly--anode effect minutes per cell day, 
production.
    (c) Sources may use 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 may use default 
values from Volume III, Section 4.4, in Chapter 4, of the 2006 IPCC 
Guidelines for National Greenhouse Gas Inventories.


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-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.026

Where:

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

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


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, anode effect frequency (AE/
cell-day), anode effect duration (minutes).
    (3) Smelter-specific slope coefficient and the last date when the 
smelter-specific-slope coefficient was measured.
    (d) Method used to measure the frequency and duration of anode 
effects.
    (e) The following CO2-specific information for prebake 
cells on an annual basis:
    (1) Total anode consumption.
    (2) Total CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells on an annual basis:
    (1) Total paste consumption.
    (2) Total 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).


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 each prebake and S[oslash]derberg electolysis cells.
    (2) Anode effect minutes per cell-day, anode effect frequency (AE/
cell-day), anode effect duration (minutes) from each prebake and 
S[oslash]derberg electolysis cells.

[[Page 16645]]

    (3) Smelter-specific slope coefficient and the last date when the 
smelter-specific-slope coefficient was measured.
    (d) Method used to measure the frequency and duration of anode 
effects.
    (e) The following CO2-specific information for prebake 
cells on an annual basis:
    (1) Total anode consumption.
    (2) Total CO2 emissions from the smelter.
    (f) The following CO2-specific information for 
S[oslash]derberg cells on an annual basis:
    (1) Total paste consumption.
    (2) Total 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).


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.

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 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) Carbon dioxide (CO2) process emissions from steam 
reforming of a hydrocarbon or the gasification of solid raw material, 
reported for each ammonia manufacturing process unit.
    (b) CO2, N2O, and CH4 emissions 
from fuel combustion at ammonia manufacturing processes and any other 
stationary fuel combustion units. You must follow the requirements of 
40 CFR 98, subpart C (General Stationary Fuel Combustion Sources).
    (c) For CO2 collected and used on site or transferred 
off site, you must follow the requirements of subpart PP (Suppliers of 
CO2) of this part.


Sec.  98.73  Calculating GHG emissions.

    You must determine CO2 process emissions in accordance 
with the procedures specified in either paragraph (a) or (b) of this 
section.
    (a) Any ammonia manufacturing process unit that meets the 
conditions specififed in Sec.  98.33(b)(5)(iii)(A), (B), and (C), or 
Sec.  98.33(b)(5)(ii)(A) through (F) shall calculate total 
CO2 emissions using a continuous emissions monitoring system 
according to the Tier 4 Calculation Methodology specified in Sec.  
98.33(a)(4).
    (b) If the facility does not measure total emissions with a CEMS, 
you must calculate the annual CO2 process emissions from 
feedstock used for ammonia manufacturing.
    (1) Gaseous feedstock. You must calculate the total CO2 
process emissions from gaseous feedstock according to Equation G-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.027

Where:

CO2 = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
(Fdstk)n = Volume of the gaseous feedstock used in month 
n (scf of feedstock).
(CC)n = Average carbon content of the gaseous feedstock, 
from the analysis results for month n (kg C per kg of feedstock).
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.

    (2) Liquid feedstock. You must calculate the total CO2 
process emissions from liquid feedstock according to Equation G-2 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.028

Where:

CO2 = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock used in month n 
(gallons of feedstock).
(CC)n = Average carbon content of the liquid feedstock, 
from the analysis results for month n (kg C per gallon of 
feedstock).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(RCO2)n = CO2 captured or recovered for use in 
urea or methanol production for month n, kg CO2.

    (3) Solid feedstock. You must calculate the total CO2 
process emissions from solid feedstock according to Equation G-3 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.029


[[Page 16646]]


Where:

CO2 = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
(Fdstk)n = Mass of the solid feedstock used in month n 
(kg of feedstock).
(CC)n = Average carbon content of the solid feedstock, 
from the analysis results for month n (kg C per kg of feedstock).
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.
(RCO2)n = CO2 captured or recovered 
for use in urea or methanol production for month n, kg 
CO2.


Sec.  98.74  Monitoring and QA/QC requirements.

    (a) Facilities 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 collect a sample of each feedstock on a monthly basis 
and analyze the carbon content using any suitable method incorporated 
by reference in Sec.  98.7.
    (c) All fuel flow meters and gas composition monitors shall be 
calibrated prior to the first reporting year, using a suitable method 
published by a consensus standards organization (e.g., ASTM, ASME, API, 
AGA, or others). Alternatively, calibration procedures specified by the 
flow meter manufacturer may be used. Fuel flow meters and gas 
composition monitors shall be recalibrated either annually or at the 
minimum frequency specified by the manufacturer, whichever is more 
frequent.
    (d) You must document the procedures used to ensure the accuracy of 
the estimates of feedstock consumption.


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 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 shall be used in the calculations, according to the 
requirements in paragraphs (a) and (b) of this section.
    (a) For missing feedstock supply rates, use the lesser of the 
maximum supply rate that the unit is capable of processing or the 
maximum supply rate that the meter can measure.
    (b) There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are 
determined to be invalid.


Sec.  98.76  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c) of subpart 
A of this part, each annual report must contain the information 
specified in paragraphs (a) through (c) for each ammonia manufacturing 
process unit:
    (a) Annual CO2 process emissions (metric tons).
    (b) Total quantity of feedstock consumed for ammonia manufacturing.
    (c) Monthly analyses of carbon content for each feedstock used in 
ammonia manufacturing (kg carbon/kg of feedstock).


Sec.  98.77  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) Method used for determining quantity of feedstock used.
    (b) Monthly analyses of carbon content for each feedstock used in 
ammonia manufacturing.


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.

    Carbon dioxide (CO2) process emissions from calcination, 
reported for all kilns combined.
    CO2, N2O, and CH4 emissions from 
fuel combustion at each kiln and any other stationary combustion units, 
by following the requirements of 40 CFR 98, subpart C (General 
Stationary Fuel Combustion Sources).


Sec.  98.83  Calculating GHG emissions.

    (a) Cement kilns that meet the conditions specified in Sec.  
98.33(b)(5)(ii) or (iii) shall calculate total CO2 emissions 
using the Tier 4 Calculation Methodology specified in Sec.  
98.33(a)(4).
    (b) If CEMS are not used to determine the total annual 
CO2 emissions from kilns, then you must calculate process 
CO2 emissions by following paragraphs (b)(1) through (3) of 
this section.
    (1) Calculate CO2 process emissions from all kilns at 
the facility using Equation H-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.030

Where:

CO2 CMF = Total annual 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 and H-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.031


[[Page 16647]]


Where:

Cli,j = Quantity of clinker produced in month j from kiln 
m, metric 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.
CKDi = Cement kiln dust (CKD) discarded in quarter i from 
kiln m, metric tons.
EFCKD,i = Kiln specific fraction of calcined material in 
CKD not recycled to the kiln, for quarter i from kiln m, as 
determined in paragraph (c)(2)(i).
p = Number of months for clinker calculation, 12.
r = Number of quarters for CKD calculation, 4.
[GRAPHIC] [TIFF OMITTED] TP10AP09.032

Where:

CliCaO = Monthly CaO content of Clinker, wt% as 
determined in Sec.  98.84(b).
MRCaO = Molecular Ratio of CO2/CaO = 0.785.
CliMgO = Monthly MgO content of Clinker, wt% as 
determined in Sec.  98.84(b).
MRMgO = Molecular Ratio of CO2/MgO = 1.092.
ClincCaO = Monthly non-carbonate CaO of Clinker, wt% as 
determined in Sec.  98.84(b).
ClincMgO = Monthly non-carbonate MgO of Clinker, wt% as 
determined in Sec.  98.84(b).

    (i) EFCKD must be determined through X-ray fluorescence 
(XRF) test or other testing method specified in Sec.  98.84(a), except 
as provided in paragraph (c)(2)(ii) of this section.
    (ii) A default factor of 1.0, which assumes that 100 percent of all 
carbonates in CKD are calcined, may be used instead of testing to 
determine EFCKD.
    (iii) The weight percents of CaO, MgO, non-carbonate CaO, and non-
carbonate MgO of clinker used in Equation H-3 must be determined using 
the measurement methods specified in Sec.  98.84(b).
    (3) CO2 emissions from raw materials. Calculate CO2 
emissions using Equation H-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.033

Where:

rm = The amount of raw material consumed annually, metric tons/yr.
TOCrm = Organic carbon content of raw material, as 
determined in Sec.  98.84(c) or using a default factor of 0.2 
percent of total raw material weight.
3.664 = The CO2 to carbon molar ratio.


Sec.  98.84  Monitoring and QA/QC requirements.

    (a) You must determine the plant-specific fraction of calcined 
material in cement kiln dust (CKD) not recycled to the kiln (EFCKD) 
using an x-ray fluorescence test or other enhanced testing method. The 
monitoring must be conducted quarterly for each kiln from a CKD sample 
drawn from bulk CKD storage.
    (b) You must determine the weight percents of CaO, MgO, non-
carbonate CaO, and non-carbonate MgO in clinker from each kiln using an 
x-ray fluorescence test or other enhanced testing method. The 
monitoring must be conducted monthly for each kiln from a clinker 
sample drawn from bulk clinker storage.
    (c) The total organic carbon contents of raw materials must be 
determined annually using ASTM Method C114-07 or a similar ASTM 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).
    (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 discarded quarterly 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.
    (f) The quantity of each category of raw materials consumed 
annually by the facility (i.e. limestone, sand, shale, iron oxide, and 
alumina) must be determined by direct weight measurement using the same 
plant instruments used for accounting purposes, such as weigh hoppers 
or belt weigh feeders.


Sec.  98.85  Procedures for estimating missing data.

    If the CEMS approach is used to determine CO2 emissions, 
the missing data procedures in Sec.  98.35 apply. Procedures for 
estimating missing data do not apply to CO2 process 
emissions from cement manufacturing facilities calculated according to 
Sec.  98.83(b). If data on the carbonate content or organic carbon 
content is missing, facilities must undertake a new analysis.


Sec.  98.86  Data reporting requirements.

    In addition to the information required by Sec.  98.3(b) of this 
part, each annual report must contain the information specified in 
paragraphs (a) through (k) of this section for each portland cement 
manufacturing facility.
    (a) The total combined CO2 emissions from all kilns at 
the facility (in metric tons).
    (b) Annual clinker production (tons).
    (c) Number of kilns.
    (d) Annual CKD production (in metric tons).
    (e) Total annual fraction of CKD recycled to the kilns (as a 
percentage).
    (f) Annual weighted average carbonate composition (by carbonate).
    (g) Annual weighted average fraction of calcination achieved (for 
each carbonate, percent).
    (h) Site-specific emission factor (metric tons CO2/
metric ton clinker produced).
    (i) Organic carbon content of the raw material (percent).
    (j) Annual consumption of raw material (metric tons).
    (k) Facilities that use CEMS must also comply with the data 
reporting requirements specified in Sec.  98.36(d)(iv).


Sec.  98.87  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 (i) of this 
section for each portland cement manufacturing facility.
    (a) Monthly carbonate consumption.
    (b) Monthly clinker production (tons).
    (c) Monthly CKD production (in metric tons).
    (d) Total annual fraction of CKD recycled to the kiln (as a 
percentage).
    (e) Monthly analysis of carbonate composition in clinker (by 
carbonate).
    (f) Monthly analysis of fraction of calcination achieved for CKD 
and each carbonate.

[[Page 16648]]

    (g) Monthly cement production.
    (h) Documentation of calculated site-specific clinker emission 
factor.
    (i) Facilities that use CEMS must also comply with the 
recordkeeping requirements specified in Sec.  98.37.


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--Electronics Manufacturing


Sec.  98.90  Definition of the source category.

    (a) The electronics source category consists of any of the 
processes listed in paragraphs (a)(1) through (5) of this section. 
Electronics manufacturing facilities include but are not limited to 
facilities that manufacture semiconductors, liquid crystal displays 
(LCD), microelectromechanical systems (MEMs), and photovoltaic (PV) 
cells.
    (1) Each electronics manufacturing production process in which the 
etching process uses plasma-generated fluorine atoms, which chemically 
react with exposed thin films (e.g., dielectric, metals) and silicon to 
selectively remove portions of material.
    (2) Each electronics manufacturing production process in which 
chambers used for depositing thin films are cleaned periodically using 
plasma-generated fluorine atoms from fluorinated and other gases.
    (3) Each electronics manufacturing production process in which some 
fluorinated compounds can be transformed in the plasma processes into 
different fluorinated compounds which are then exhausted, unless 
abated, into the atmosphere.
    (4) Each electronics manufacturing production process in which the 
chemical vapor deposition process uses nitrous oxide.
    (5) Each electronics manufacturing production process in which 
fluorinated GHGs are used as heat transfer fluids (HTFs) to cool 
process equipment, control temperature during device testing, and 
solder semiconductor devices to circuit boards.


Sec.  98.91  Reporting threshold.

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


Sec.  98.92  GHGs to report.

    (a) You shall report emissions of nitrous oxide and fluorinated 
GHGs (as defined in Sec.  98.6). The fluorinated GHGs that are emitted 
from electronics production processes include but are not limited to 
those listed in Table I-1 of this subpart. You must report:
    (1) Fluorinated GHGs from plasma etching.
    (2) Fluorinated GHGs from chamber cleaning.
    (3) Nitrous oxide from chemical vapor deposition.
    (4) Fluorinated GHGs from heat transfer fluid use.
    (b) You shall report CO2, N2O and 
CH4 combustion-related emissions, if any, at electronics 
manufacturing facilities. For stationary fuel combustion sources, 
follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements in subpart C of this part.


Sec.  98.93  Calculating GHG emissions.

    (a) You shall calculate annual facility-level F-GHG emissions of 
each F-GHG from all etching processes using Equations I-1 and I-2 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.034

Where:

etchEi = Annual emissions of input gas i from all etch 
processes
Eij = Annual emissions of input gas i from etch process j 
(metric tons), calculated in equation I-5.
[GRAPHIC] [TIFF OMITTED] TP10AP09.035

Where:

etchBEk = Annual emissions of by-product gas k from all 
etch processes (metric tons).
BEkij = Annual emissions of by-product k formed from 
input gas i during etch process j (metric tons), calculated in 
equation I-6.

    (b) You shall calculate annual facility-level F-GHG emissions of 
each F-GHG from all CVD chamber cleaning processes using Equations I-3 
and I-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.036

Where:

cleanEi = Annual emissions of input gas i from all CVD 
cleaning processes (metric tons).
Eij = Annual emissions of input gas i from CVD cleaning 
process j (metric tons), calculated in equation I-5.
[GRAPHIC] [TIFF OMITTED] TP10AP09.037

Where:

cleanBEk = Annual emissions of by-product gas k from all 
CVD cleaning processes (metric tons)
BEkij = Annual emissions of by-product k formed from 
input gas i during CVD cleaning process j (metric tons), calculated 
in equation I-6.

    (c) You shall calculate annual facility-level F-GHG emissions for 
each etching process and each chamber cleaning process using Equations 
I-5 and I-6 of this section.
    (1) Semiconductor facilities that have an annual capacity of 
greater than 10,500 m\2\ silicon shall use process-specific process 
utilization and by-product formation factors determined as specified in 
Sec.  98.94(b).
    (2) All other electronics facilities shall use the default emission 
factors for process utilization and by-production formation shown in 
Tables I-2, I-3, and I-4 of subpart I for semiconductor and MEMs, LCD, 
and PV manufacturing, respectively.
[GRAPHIC] [TIFF OMITTED] TP10AP09.038

Where:

Eij = Annual emissions of input gas i from process j 
(metric tons).
Cij = Amount of input gas i consumed in process j, (kg).
Uij = Process utilization rate for input gas i during 
process j.
aij = Fraction of input gas i used in process j with 
abatement devices.
dij = Fraction of input gas i destroyed in abatement 
devices connected to process j (defined in Equation I-11). This is 
zero unless the facility verifies the DRE of the device pursuant to 
Sec.  98.94(c) of Subpart I.
0.001 = Conversion factor from kg to metric tons.
[GRAPHIC] [TIFF OMITTED] TP10AP09.039


[[Page 16649]]


Where:

BEkij = Annual emissions of by-product k formed from 
input gas i during process j (metric tons).
Bkij = Kg of gas k created as a by-product per kg of 
input gas i consumed in process j.
Cij = Amount of input gas i consumed in process j (kg).
aij = Fraction of input gas i used in process j with 
abatement devices.
dkj = Fraction of by-product gas k destroyed in abatement 
devices connected to process (j). This is zero unless the facility 
verifies the DRE of the device pursuant to Sec.  98.94(c) of Subpart 
I.
0.001 = Conversion factor from kg to metric tons.

    (d) You shall report annual N2O facility-level emissions 
during chemical vapor deposition using Equation I-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.040

Where:

E(N2O) = Annual emissions of N2O (metric tons/
year).
CN2O = Annual Consumption of N2O 
(kg).
0.001 = Conversion factor from kg to metric tons.

    (e) For facilities that use heat transfer fluids, you shall report 
the annual emissions of fluorinated GHG heat transfer fluids using 
Equation I-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.041

Where:

EHi = Emissions of fluorinated GHG heat transfer fluid i, 
(metric tons/year).
Density = Density of heat transfer fluid i (kg/l).
Iio = Inventory of heat transfer fluid i at the end of 
previous reporting period (l).
Pit = Net purchases of heat transfer fluid i during the 
current reporting period (l).
Nit = Total nameplate capacity [charge] of equipment that 
contains heat transfer fluid i and that is installed during the 
current reporting period.
Rit = Total nameplate capacity [charge] of equipment that 
contains heat transfer fluid i and that is retired during the 
current reporting period.
Iit = Inventory of heat transfer fluid i at the end of 
current reporting period (l).
Dit = Amount of heat transfer fluid i recovered and sent 
off site during current reporting period, (l).
0.001 = Conversion factor from kg to metric tons.

Sec.  98.94  Monitoring and QA/QC requirements.

    (a) You must estimate gas consumption according to the requirements 
in paragraph (a)(1) or (a)(2) of this section for each process or 
process type, as appropriate.
    (1) Monitor changes in container mass and inventories for each gas 
using weigh scales with an accuracy and precision of one percent of 
full scale or better. Calculate the gas consumption using Equation I-9 
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.042

Where:

Ci = Annual consumption of input gas i (metric tons/
year).
IBi = Inventory of input gas i stored in cylinders or 
other containers at the beginning of the year, including heels (kg).
IEi = Inventory of input gas i stored in cylinders or 
other containers at the end of the year, including heels (kg).
A = Acquisitions of that gas during the year through purchases or 
other transactions, including heels in cylinders or other containers 
returned to the electronics production facility (kg).
D = Disbursements of gas through sales or other transactions during 
the year, including heels in cylinders or other containers returned 
by the electronics production facility to the gas distributor (kg).
0.001 = Conversion factor from kg to metric tons.

    (2) Monitor the mass flow of the pure gas into the system using 
flowmeters. The flowmeters must have an accuracy and precision of one 
percent of full scale or better.
    (b) If you use fluorinated GHG utilization rates and by-product 
emission factors other than the defaults in Tables I-2, I-3, or I-4 of 
Subpart I, you must use fluorinated GHG utilization rates and by-
product emission factors that have been measured using the 
International SEMATECH Manufacturing Initiative's Guideline for 
Environmental Characterization of Semiconductor Process Equipment. You 
may use fluorinated GHG utilization rates and by-product emission 
factors measured by manufacturing equipment suppliers if the conditions 
in paragraph (b)(1) and (2) of this section are met.
    (1) The manufacturing equipment supplier has measured the GHG 
utilization rates and by-product emission factors using the 
International SEMATECH Guideline.
    (2) The conditions under which the measurements were made are 
representative of your facility's F-GHG emitting processes.
    (c) If your facility employs abatement devices and you wish to 
reflect the emission reductions due to these devices in Sec.  98.93(c), 
you must verify the destruction or removal efficiency (DRE) of the 
devices using the methods in either paragraph (c)(1) or (2) of this 
section.
    (1) Experimentally determine the effective dilution through the 
abatement device and measure abatement DRE during actual or simulated 
process conditions by following the procedures of this paragraph.
    (i) Measure the concentrations of F-GHGs exiting the process tool 
and entering and exiting the abatement system under operating process 
and abatement system conditions that are representative of those for 
which F-GHG emissions are estimated and abatement-system DRE is used 
for the F-GHG reporting period.\1\
---------------------------------------------------------------------------

    \1\ Abatement system means a point-of-use (POU) abatement system 
whereby a single abatement system is attached to a single process 
tool or single process chamber of a multi-chamber tool.
---------------------------------------------------------------------------

    (ii) Measure the dilution through the abatement system and 
calculate the dilution factor under the representative operating 
conditions given in paragraph (c)(i) of this section by using the 
tracer method. This method consists of injecting known flows of a non-
reactive gas (such as krypton) at the inlet of the abatement system, 
measuring the time-averaged concentrations of krypton entering 
([Kr]in) and exiting ([Kr]out) the abatement 
system, and calculating the dilution factor (DF) as the ratio of the 
time-averaged measured krypton concentrations entering and exiting the 
abatement system, using equation I-10 of this section.

[[Page 16650]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.043

    (iii) Measure the F-GHG concentrations in and out of the device 
with all process chambers connected to the F-GHG abatement system and 
under the production and abatement system conditions for which F-GHG 
emissions are estimated for the reporting period.\2\
---------------------------------------------------------------------------

    \2\ Most process tools have multiple chambers. For combustion-
type abatement systems, the outlets of each chamber separately enter 
the destruction-reactor because premixing of certain gaseous 
mixtures may be conducive to fire or explosion. For the less-
frequently used plasma-type POU abatement systems, there is one 
system per chamber.
---------------------------------------------------------------------------

    (iv) Calculate abatement system DRE using Equation I-11 of this 
section, where it is assumed that the measurement pressure and 
temperature at the inlet and outlet of the abatement system are 
identical and where the relative precision ([egr]) of the quantity 
ci-out*DF/ci-in shall not exceed 10 
percent (two standard deviations) using proper statistical methods.
[GRAPHIC] [TIFF OMITTED] TP10AP09.044

Where:

dij = Destruction or removal efficiency (DRE)
ci-in = Concentration of gas i in the inflow to the 
abatement system (ppm).
ci-out = Concentration of gas i in the outflow from the 
abatement system (ppm).
DF = Dilution Factor calculated using Equation I-10.

    (v) The DF may not be obtained by calculation from flows other than 
those obtained by using the tracer method described in paragraph (ii) 
of this section.
    (2) Install abatement devices that have been tested by a third 
party (e.g., UL) according to EPA's Protocol for Measuring Destruction 
or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement 
Equipment in Electronics Manufacturing. This testing may be obtained by 
the manufacturer of the equipment.
    (d) Abatement devices must be operated within the manufacturer's 
specified equipment lifetime and gas flow and mix limits and must be 
maintained according to the manufacturer's guidelines.
    (e) You shall adhere to the QA/QC procedures of this paragraph when 
estimating F-GHG and N2O emissions from cleaning/etching 
processes:
    (1) You shall follow the QA/QC procedures in the International 
SEMATECH Manufacturing Initiative's Guideline for Environmental 
Characterization of Semiconductor Process Equipment when estimating 
facility-specific gas process utilization and by-product gas formation.
    (2) You shall follow the QA/QC procedures in the EPA DRE 
measurement protocol when estimating abatement device DRE.
    (3) You shall certify that abatement devices are maintained in 
accordance with manufacturer specified guidelines.
    (4) You shall certify that gas consumption is tracked to a high 
degree of precision as part of normal facility operations and that 
further QA/QC is not required.
    (f) You shall adhere to the QA/QC procedures of this paragraph when 
estimating F-GHG emissions from heat transfer fluid use:
    (1) You shall review all inputs to Equation I-4 of this section to 
ensure that all inputs and outputs to the facility's system are 
accounted for.
    (2) You shall not enter negative inputs into the mass balance 
Equation I-4 of this section and shall ensure that no negative 
emissions are calculated.
    (3) You shall ensure that the beginning of year inventory matches 
the end of year inventory from previous year.
    (g) All flowmeters, scales, load cells, and volumetric and density 
measures used to measure quantities that are to be reported under Sec.  
98.92 and Sec.  98.96 shall be calibrated using suitable NIST-traceable 
standards and suitable methods published by a consensus standards 
organization (e.g., ASTM, ASME, ASHRAE, or others). Alternatively, 
calibration procedures specified by the flowmeter, scale, or load cell 
manufacturer may be used. Calibration shall be performed prior to the 
first reporting year. After the initial calibration, recalibration 
shall be performed at least annually or at the minimum frequency 
specified by the manufacturer, whichever is more frequent.
    (h) All instruments (e.g., mass spectrometers and fourier transform 
infrared measuring systems) used to determine the concentration of 
fluorinated greenhouse gases in process streams shall be calibrated 
just prior to DRE, gas utilization, or product formation measurement 
through analysis of certified standards with known concentrations of 
the same chemicals in the same ranges (fractions by mass) as the 
process samples. Calibration gases prepared from a high-concentration 
certified standard using a gas dilution system that meets the 
requirements specified in Test Method 205, 40 CFR Part 51, Appendix M 
may also be used.


Sec.  98.95  Procedures for estimating missing data.

    (a) For semiconductor facilities that have an annual capacity of 
greater than 10,500 m2 silicon, you shall estimate missing 
site-specific gas process utilization and by-product formation using 
default factors from Tables I-2 through I-4 of this subpart. However, 
use of these default factors shall be restricted to less than 5 percent 
of the total facility emissions.
    (b) For facilities using heat transfer fluids and missing data for 
one or more of the parameters in Equation I-8, you shall estimate heat 
transfer fluid emissions using the arithmetic average of the emission 
rates for the year immediately preceding the period of missing data and 
the months immediately following the period of missing data. 
Alternatively, you may estimate missing information using records from 
the heat transfer fluid supplier. You shall document the method used 
and values estimated for all missing data values.
    (c) If the methods specified in paragraphs (a) and (b) of this 
section are likely to significantly under- or overestimate the value of 
the parameter during the period when data were missing (e.g., because 
the monitoring failure was linked to a process disturbance that is 
likely to have significantly increased the F-GHG emission rate), you 
shall develop a best estimate of the parameter, documenting the methods 
used, the rationale behind them, and the reasons why the methods 
specified in paragraphs (a) and (b) of this section would lead to a 
significant under-or overestimate of the parameter.


Sec.  98.96  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), you shall 
include in each annual report the following information for each 
electronics manufacturer.
    (a) Emissions of each GHG emitted from all plasma etching 
processes, all chamber cleaning, all chemical vapor deposition 
processes, and all heat transfer fluid use, respectively.
    (b) The method, mass of input F-GHG gases, and emission factors 
used for estimating F-GHG emissions.
    (c) Production in terms of substrate surface area (e.g., silicon, 
PV-cell, LCD).
    (d) Factors used for gas process utilization and by-product 
formation, and the source and uncertainty for each factor.
    (e) The verified DRE and its uncertainty for each abatement device 
used, if you have verified the DRE pursuant to Sec.  98.94(c).

[[Page 16651]]

    (f) Fraction of each gas fed into each process type with abatement 
devices.
    (g) Description of abatement devices, including the number of 
devices of each manufacturer and model.
    (h) For heat transfer fluid emissions, inputs in the mass-balance 
Equation.
    (i) Example calculations for F-GHG, N2O, and heat 
transfer fluid emissions.
    (j) Estimate of the overall uncertainty in the emissions estimate.


Sec.  98.97  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Data used to estimate emissions including all spreadsheets and 
copies of calculations used to estimate emissions.
    (b) Documentation for the values used for GHG utilization rates and 
by-product emission factors, including documentation that these were 
measured using the the International SEMATECH Manufacturing 
Initiative's Guideline for Environmental Characterization of 
Semiconductor Process Equipment.
    (c) The date and results of the initial and any subsequent tests of 
emission control device DRE, including the following information:
    (1) Dated certification, by the technician who made the 
measurement, that the dilution factor was determined using the tracer 
method.
    (2) Dated certification, by the technician who made the 
measurement, that the DRE was calculated using the formula given in 
Sec.  98.94(c)(1)(iv).
    (3) Documentation of the measured flows, concentrations and 
calculations used to calculate DF, relative precision ([egr]), and DRE.
    (d) The date and results of the initial and any subsequent tests to 
determine process tool gas utilization and by-product formation 
factors.
    (e) Abatement device calibration and maintenance records.


Sec.  98.98  Definitions.

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

 Table I-1 of Subpart I--GHGs Typically Used by the Electronics Industry
------------------------------------------------------------------------
           Product type                F-GHGs Used during manufacture
------------------------------------------------------------------------
Electronics.......................  CF4, C2F6, C3F8, c-C4F8, c-C4F8O,
                                     C4F6, C5F8, CHF3, CH2F2, NF3, SF6,
                                     and HTFs (CF3-(O-CF(CF3)-CF2)n-(O-
                                     CF2)m-O-CF3, CnF2n+2,
                                     CnF2n+1(O)CmF2m+1, CnF2nO,
                                     (CnF2n+1)3N)
------------------------------------------------------------------------


                                Table I-2 of Subpart I--Default Emission Factors for Semiconductor and MEMs Manufacturing
--------------------------------------------------------------------------------------------------------------------------------------------------------
                                                                                                      Factors
                      Process gases                      -----------------------------------------------------------------------------------------------
                                                             Etch 1-Ui       CVD 1-Ui        Etch BCF4      Etch BC2F6       CVD BCF4        CVD BC3F8
--------------------------------------------------------------------------------------------------------------------------------------------------------
CF4.....................................................             0.7             0.9              NA              NA              NA              NA
C2F6....................................................            0.4*             0.6            0.4*              NA             0.1              NA
CHF3....................................................            0.4*              NA           0.07*              NA              NA              NA
CH2F2...................................................           0.06*              NA           0.08*              NA              NA              NA
C3F8....................................................              NA             0.4              NA              NA             0.1              NA
c-C4F8..................................................            0.2*             0.1             0.2             0.2             0.1              NA
NF3.....................................................              NA            0.02              NA              NA   [dagger] 0.02              NA
Remote
NF3.....................................................             0.2             0.2              NA              NA    [dagger] 0.1              NA
SF6.....................................................             0.2              NA              NA              NA              NA              NA
C4F6a...................................................             0.1              NA            0.3*            0.2*              NA              NA
C5F8a...................................................             0.2             0.1             0.2             0.2             0.1              NA
C4F8Oa..................................................              NA             0.1              NA              NA             0.1            0.4
--------------------------------------------------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.
* Estimate includes multi-gas etch processes.
[dagger] Estimate reflects presence of low-k, carbide and multi-gas etch processes that may contain a C-containing FC additive.


                     Table I-3 of Subpart I--Default Emission Factors for LCD Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                                      Factors
          Process gases          -------------------------------------------------------------------------------
                                    Etch  1-Ui       CVD  1-Ui      Etch  BCF4      Etch  BCHF3     Etch  BC2F6
----------------------------------------------------------------------------------------------------------------
CF4.............................             0.6              NA              NA              NA              NA
C2F6............................              NA              NA              NA              NA              NA
CHF3............................             0.2              NA            0.07              NA            0.05
CH2F2...........................              NA              NA              NA              NA              NA
C3F8............................              NA              NA              NA              NA              NA
c-C4F8..........................             0.1              NA           0.009            0.02              NA
NF3 Remote......................              NA            0.03              NA              NA              NA
NF3.............................              NA             0.3              NA              NA              NA
SF6.............................             0.3             0.9              NA              NA             NA
----------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.


[[Page 16652]]


                      Table I-4 of Subpart I--Default Emission Factors for PV Manufacturing
----------------------------------------------------------------------------------------------------------------
                                                                      Factors
          Process gases          -------------------------------------------------------------------------------
                                    Etch  1-Ui       CVD  1-Ui      Etch  BCF4      Etch  BC2F6      CVD  BCF4
----------------------------------------------------------------------------------------------------------------
CF4.............................             0.7              NA              NA              NA              NA
C2F6............................             0.4             0.6             0.2              NA             0.2
CHF3............................             0.4              NA              NA              NA              NA
CH2F2...........................              NA              NA              NA              NA              NA
C3F8............................              NA             0.1              NA              NA             0.2
c-C4F8..........................             0.2             0.1             0.1             0.1             0.1
NF3 Remote......................              NA              NA              NA              NA              NA
NF3.............................              NA             0.3              NA              NA              NA
SF6.............................             0.4             0.4              NA              NA             NA
----------------------------------------------------------------------------------------------------------------
Notes: NA denotes not applicable based on currently available information.

Subpart J--Ethanol Production


Sec.  98.100  Definition of the source category.

    An ethanol production facility is a facility that produces ethanol 
from the fermentation of sugar, starch, grain, or cellulosic biomass 
feedstocks; or produces ethanol synthetically from ethylene or hydrogen 
and carbon monoxide.


Sec.  98.101  Reporting threshold.

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


Sec.  98.102  GHGs to report.

    You must report:
    (a) Emissions of CO2, N2O, and CH4 from on-site stationary 
combustion. You must follow the calculation procedures, monitoring and 
QA/QC methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of subpart C of this part.
    (b) Emissions of CH4 from on-site landfills. You must follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
subpart HH of this part.
    (c) Emissions of CH4 from on-site wastewater treatment. 
You must follow the calculation procedures, monitoring and QA/QC 
methods, missing data procedures, reporting requirements, and 
recordkeeping requirements of subpart II of this part.


Sec.  98.103  Definitions.

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

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.

    (a) You must report the CO2 emissions from each electric 
arc furnace used for ferroalloy production.
    (b) You must report the CH4 emissions from each electric 
arc furnace used for the production of any ferroalloy listed in Table 
K-1 of this subpart.
    (c) You must report the CO2, CH4, and 
N2O emissions from each stationary combustion unit following 
the requirements specified in subpart C of this part.


Sec.  98.113  Calculating GHG emissions.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must estimate total CO2 emissions 
according to the requirements in Sec.  98.33.
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 process emissions consistent with the requirements in 
subpart C, you must determine using the procedure specified in 
paragraphs (b)(1) and (2) of this section the total CO2 
emissions from all electric arc furnaces that are used for ferroalloy 
production.
    (1) For each EAF at your facility used for ferroalloy production, 
you must determine the mass of carbon in each carbon-containing input 
and output material for the electric arc furnace for each calendar 
month using Equation K-1 of this section. Carbon containing input 
materials include carbon eletrodes and carbonaceous reducing agents.

[[Page 16653]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.045

Where:

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

    (2) You must determine the total CO2 emissions from 
the electric arc furnaces using Equation K-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.046

Where:

CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions calcaluated using 
Equation K-1 of this supart, metric tons/year.
k = Total number of EAFs at facility used for the ferroalloy 
production.

    (c) For the electric arc furnaces used at your facility for the 
production of any ferroalloy listed in Table K-1 of this subpart, you 
must determine the total CH4 emissions using the procedure 
specified in paragraphs (c)(1) and (2) of this section.
    (1) For each EAF, calculate annual CH4 emissions using 
Equation K-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.047

Where:

ECH4 = Annual CH4 emissions from an individual 
EAF, metric tons.
Mproducti = Annual mass of alloy product i produced in 
the EAF, metric tons.
EFproducti = CH4 emission factor for alloy 
product i from Table K-1 of this subpart, kg of CH4 
emissions per metric ton of alloy product i.

    (2) You must determine the total CH4 emissions using 
Equation K-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.048

Where:

CH4 = Total annual CH4 emissions, metric tons/
year.
ECH4j = Annual CH4 emissions from EAF k 
calculated using Equation K-3 of this section, metric tons/year.
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 CO2 emissions using the carbon balance 
procedure in Sec.  98.113(b), you must meet the requirements specified 
in paragraphs (a) through (c) of this section.
    (a) Determine the mass of each solid carbon-containing process 
input and output material by direct measurements or calculations using 
process operating information, and record the total mass

[[Page 16654]]

of each material consumed or produced for each calendar month.
    (b) For each process input and output material identified in 
paragraph (a) of this section, you must determine the average carbon 
content of the material for the specified period using information 
provided by your material supplier or by collecting and analyzing a 
representative sample of the material.
    (c) For each input material identified in paragraph (a) of this 
section for which the carbon content is not provided by your material 
supplier, the carbon content of the material must be analyzed by an 
independent certified laboratory at least annually using the test 
methods (and their QA/QC procedures) in Sec.  98.7. Use ASTM E1941-04 
(``Standard Test Method for Determination of Carbon in Refractory and 
Reactive Metals and Their Alloys'') for analysis of metal ore and alloy 
product; ASTM D5373-02 (``Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal and Coke'') for analysis of carbonaceous reducing agents and 
carbon electrodes, and ASTM C25-06 (``Standard Test Methods for 
Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'') for 
analysis of flux materials such as limestone or dolomite.


Sec.  98.115  Procedures for estimating missing data.

    For the carbon input procedure in Sec.  98.113(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.
    (a) For each missing value of the carbon 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, 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 records of the mass of carbon-containing input or 
output material consumption, the substitute data value shall be the 
best available estimate of the mass of the input or output material. 
The owner or operator shall document and keep records of the procedures 
used for all such estimates.
    (c) If you are required to calculate CH4 emissions for 
the electric arc furnace as specified in Sec.  98.113(c), then you are 
required to have 100 percent of the specified data for each reporting 
period.


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 (f) of this section.
    (a) Annual CO2 emissions from each electric arc furnace 
used for ferroalloy production, in metric tons and the method used to 
estimate these emissions.
    (b) Annual CH4 emissions from each electric arc furnace 
used for the production of any ferroalloy listed in Table K-1 of this 
subpart.
    (c) Facility ferroalloy product production capacity (metric tons).
    (d) Annual facility production quantity for each ferroalloy product 
(metric tons).
    (d) Number of facility operating hours in calendar year.
    (f) If you use the carbon balance procedure, report for each 
carbon-containing input and output material consumed or used (other 
than fuel), the information specified in paragraphs (g)(1) and (2) of 
this section.
    (1) Annual material quantity (in metric tons).
    (2) Annual average of the monthly carbon content determinations for 
each material and the method used for the determination (e.g., supplier 
provided information, analyses of representative samples you 
collected).


Sec.  98.117  Records that must be retained.

    In addition to the records required by Sec.  98.3(g) of this part, 
you must retain the records specified in paragraphs (a) through (e) of 
this section.
    (a) Monthly facility production quantity for each ferroalloy 
product (in metric tons).
    (b) Number of facility operating hours each month.
    (c) If you use the carbon balance procedure, record for each 
carbon-containing input and output material consumed or used (other 
than fuel), the information specified in paragraphs (c)(1) and (2) of 
this section.
    (1) Monthly material quantity (in metric tons).
    (2) Monthly average carbon content determined for material and 
records of the supplier provided information or analyses used for the 
determination.
    (d) You must keep records that include a detailed explanation of 
how company records of measurements are used to estimate the carbon 
input input and output to each electric arc furnace. 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.
    (e) If you are required to calculate CH4 emissions for 
the electric arc furnace as specified in Sec.  98.113(c), 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 CH4 emissions.


Sec.  98.118  Definitions.

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

                    Table K-1 of Subpart K--Electric Arc Furnace (EAF) CH\4\ Emission Factors
----------------------------------------------------------------------------------------------------------------
                                                                    CH4 Emission factor  (kg CH4 per metric ton
                                                                                     product)
                                                                 -----------------------------------------------
                                                                                   EAF operation
                  Alloy product produced in EAF                  -----------------------------------------------
                                                                                                     Sprinkle-
                                                                  Batch-charging     Sprinkle-     charging and
                                                                                    charging a     >750 [deg] Cb
----------------------------------------------------------------------------------------------------------------
silicon metal...................................................             1.5             1.2             0.7
ferrosilicon 90%................................................             1.4             1.1             0.6
ferrosilicon 75%................................................             1.3             1.0             0.5

[[Page 16655]]

 
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--Fluorinated Greenhouse Gas Production


Sec.  98.120  Definition of the source category.

    The fluorinated gas production source category consists of 
facilities that produce a fluorinated GHG from any raw material or 
feedstock chemical. Producing a fluorinated GHG does not include the 
reuse or recycling of a fluorinated GHG or the generation of HFC-23 
during the production of HCFC-22.


Sec.  98.121  Reporting threshold.

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


Sec.  98.122  GHGs to report.

    (a) You must report the CO2, N2O, and 
CH4 emissions from each on-site stationary combustion unit. 
For these stationary combustion units, you must follow the applicable 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
subpart C of this part.
    (b) You must report the total mass of each fluorinated GHG emitted 
from each fluorinated GHG production process and from all fluorinated 
GHG production processes at the facility.


Sec.  98.123  Calculating GHG emissions.

    (a) The total mass of each fluorinated GHG product emitted annually 
from all fluorinated GHG production processes shall be estimated by 
using Equation L-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.049

Where:

EP = Total mass of each fluorinated GHG product emitted 
annually from all production processes (metric tons).
EPip = Total mass of the fluorinated GHG product emitted 
from production process i over the period p (metric tons, defined in 
Equation L-3 of this section).
n = Number of concentration and flow measurement periods for the 
year.
m = Number of production processes.

    (b) The total mass of fluorinated GHG by-product k emitted annually 
from all fluorinated GHG production processes shall be estimated by 
using Equation L-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.050

Where:

EBk = Total mass of fluorinated GHG by-product k emitted 
annually from all production processes (metric tons).
EBkip = Total mass of fluorinated GHG by-product k 
emitted from production process i over the period p (metric tons, 
defined in Equation L-8 on this section).
n = Number of concentration and flow measurement periods for the 
year.
m = Number of production processes.

    (c) The total mass of each fluorinated GHG product emitted from 
production process i over the period p shall be estimated at least 
daily by calculating the difference between the expected production of 
the fluorinated GHG based on the consumption of reactants (e.g., HF and 
a chlorocarbon reactant) and the measured production of the fluorinated 
GHG, accounting for yield losses related to by-products and wastes. 
This calculation shall be performed for each reactant, using Equation 
L-3 of this section. Estimated emissions shall equal the average of the 
results obtained for each reactant.
[GRAPHIC] [TIFF OMITTED] TP10AP09.051

Where:

EPip = Total mass of each fluorinated GHG product emitted 
from production process i over the period p (metric tons).
P = Total mass of the fluorinated GHG produced by production process 
i over the period p (metric tons).
R = Total mass of the reactant that is consumed by production 
process i over the period p (metric tons, defined in Equation L-4).
MWR = Molecular weight of the reactant.
MWP = Molecular weight of the fluorinated GHG produced.
SCR = Stoichiometric coefficient of the reactant.
SCP = Stoichiometric coefficient of the fluorinated GHG 
produced.
CP = Concentration (mass fraction) of the fluorinated GHG 
product in stream j of destroyed wastes. If this concentration is 
only a trace concentration, CP is equal to zero.
WDj = Mass of wastes removed from production process i in 
stream j and destroyed over the period p (metric tons, defined in 
Equation L-5 of this section).
LBkip = Yield loss related to by-product k for production 
process i over the period p (metric tons, defined in Equation L-6 of 
this section).
q = Number of waste streams destroyed in production process i.
u = Number of by-products generated in production process i.

    (d) The total mass of the reactant that is consumed by production 
process i over the period p shall be estimated by using Equation L-4 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.052

Where:

R = Total mass of the reactant that is consumed by production 
process i over the period p (metric tons).
RF = Total mass of the reactant that is fed into 
production process i over the period p (metric tons).

[[Page 16656]]

RR = Total mass of the reactant that is permanently 
removed from production process i over the period p (metric tons).

    (e) The mass of wastes removed from production process i in stream 
j and destroyed over the period p shall be estimated using Equation L-5 
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.053

Where:

WDj = The mass of wastes removed from production process 
i in stream j and destroyed over the period p (metric tons).
WFj = The total mass of wastes removed from production 
process i in stream j and fed into the destruction device over the 
period p (metric tons).
DE = Destruction Efficiency of the destruction device (fraction).

    (f) Yield loss related to by-product k for production process i 
over period p shall be estimated using Equation L-6 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.054

Where:

LBkip = Yield loss related to by-product k for production 
process i over the period p (metric tons).
Bkip = Mass of by-product k generated by production 
process i over the period p (metric tons, defined in Equation L-7 of 
this section).
MWP = Molecular weight of the fluorinated GHG produced.
MWBk = Molecular weight of by-product k.
MEBk = Moles of the element shared by the reactant, 
product, and by-product k per mole of by-product k.
MEP = Moles of the element shared by the reactant, 
product, and by-product k per mole of the product.

    (g) If by-product k is responsible for yield loss in production 
process i and occurs in any process stream in more than trace 
concentrations, the mass of by-product k generated by production 
process i over the period p shall be estimated using Equation L-7 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.055

Where:

Bkip = Mass of by-product k generated by production 
process i over the period p (metric tons).
CBkj = Concentration (mass fraction) of the by-product k 
in stream j of production process i over the period p. If this 
concentration is only a trace concentration, CBkj is 
equal to zero.
Sj = Mass flow of process stream j of production process 
i over the period p.
q = Number of streams in production process i.

    (h) If by-product k is responsible for yield loss, is a fluorinated 
GHG, occurs in any process stream in more than trace concentrations, 
and is not completely recaptured or completely destroyed; the total 
mass of by-product k emitted from production process i over the period 
p shall be estimated at least daily using Equation L-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.056

Where:

EBkip = Mass of by-product k emitted from production 
process i over the period p (metric tons).
Bkip = Mass of by-product k generated by production 
process i over the period p (metric tons).
CBkj = Concentration (mass fraction) of the by-product k 
in stream j of destroyed wastes over the period p. If this 
concentration is only a trace concentration, CBj is equal 
to zero.
WDj = The mass of wastes that are removed from production 
process i in stream j and that are destroyed over the period p 
(metric tons, defined in Equation L-5 of this section).
CBkl = The concentration (mass fraction) of the by-
product k in stream l of recaptured material over the period p. If 
this concentration is only a trace concentration, CBkl is 
equal to zero.
SRl = The mass of materials that are removed from 
production process i in stream l and that are recaptured over the 
period p.
q = Number of waste streams destroyed in production process i.
v = Number of streams recaptured in production process i.


Sec.  98.124  Monitoring and QA/QC requirements.

    (a) The total mass of fluorinated GHGs produced over the period p 
shall be estimated at least daily using the methods and measurements 
set forth in Sec. Sec.  98.413(b) and 98.414.
    (b) The total mass of each reactant fed into the production process 
shall be measured at least daily using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 0.2 percent of full scale or better.
    (c) The total mass of each reactant permanently removed from the 
production process shall be measured at least daily using flowmeters, 
weigh scales, or a combination of volumetric and density measurements 
with an accuracy and precision of 0.2 percent of full scale or better. 
If the measured mass includes more than trace concentrations of 
materials other than the reactant, the concentration of the reactant 
shall be measured at least daily 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 reactant permanently removed from the production process.
    (d) If the waste permanently removed from the production process 
and fed into the destruction device contains more than trace 
concentrations of the fluorinated GHG product, the mass of waste fed 
into the destruction device shall be measured at least daily using 
flowmeters, weigh scales, or a combination of volumetric and density 
measurements with an accuracy and precision of 0.2 percent of full 
scale or better. If the measured mass includes more than trace 
concentrations of materials other than the product, the concentration 
of the product shall be measured at least daily 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.

[[Page 16657]]

    (e) If a by-product is responsible for yield loss and occurs in any 
process stream in more than trace concentrations, the mass flow of each 
process stream that contains more than trace concentrations of the by-
product shall be measured at least daily using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 0.2 percent of full scale or better. If the 
measured mass includes more than trace concentrations of materials 
other than the by-product, the concentration of the by-product shall be 
measured at least daily 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.
    (f) If a by-product is a fluorinated GHG, occurs in more than trace 
concentrations in any process stream, occurs in more than trace 
concentrations in any stream that is recaptured or is fed into a 
destruction device, and is not completely recaptured or completely 
destroyed; the mass flow of each stream that contains more than trace 
concentrations of the by-product and that is recaptured or is fed into 
the destruction device or shall be measured at least daily using 
flowmeters, weigh scales, or a combination of volumetric and density 
measurements with an accuracy and precision of 0.2 percent of full 
scale or better. If the measured mass includes more than trace 
concentrations of materials other than the by-product, the 
concentration of the by-product shall be measured at least daily 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.
    (g) All flowmeters, scales, load cells, and volumetric and density 
measures used to measure quantities that are to be reported under Sec.  
98.126 shall be calibrated using suitable NIST-traceable standards and 
suitable methods published by a consensus standards organization (e.g., 
ASTM, ASME, ASHRAE, or others). Alternatively, calibration procedures 
specified by the flowmeter, scale, or load cell manufacturer may be 
used. Calibration shall be performed prior to the first reporting year. 
After the initial calibration, recalibration shall be performed at 
least annually or at the minimum frequency specified by the 
manufacturer, whichever is more frequent.
    (h) All gas chromatographs used to determine the concentration of 
fluorinated greenhouse gases in process streams shall be calibrated at 
least monthly through analysis of certified standards with known 
concentrations of the same chemicals in the same ranges (fractions by 
mass) as the process samples. Calibration gases prepared from a high-
concentration certified standard using a gas dilution system that meets 
the requirements specified in Test Method 205, 40 CFR Part 51, Appendix 
M may also be used.
    (i) For purposes of equation L-5, the destruction efficiency can 
initially 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. Fluorinated GHG production 
facilities that destroy fluorinated GHGs shall conduct annual 
measurements of mass flow and fluorinated GHG concentrations at the 
outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 
CFR part 60, appendix A-6. Tests shall be conducted under conditions 
that are typical for the production process and destruction device at 
the facility. The sensitivity of the emissions tests shall be 
sufficient to detect emissions equal to 0.01 percent of the mass of 
fluorinated GHGs being fed into the destruction device. If the test 
indicates that the actual DE of the destruction device is lower than 
the previously determined DE, facilities shall either:
    (1) Substitute the DE implied by the most recent emissions test for 
the previously determined DE in the calculations in Sec.  98.123, or
    (2) Perform more extensive performance testing of the DE of the 
oxidizer and use the DE determined by the more extensive testing in the 
calculations in Sec.  98.123.
    (j) 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.
    (k) Fluorinated GHG production facilities shall account for 
fluorinated GHG emissions that occur as a result of startups, 
shutdowns, and malfunctions, either recording fluorinated GHG emissions 
during these events, or documenting that these events do not result in 
significant fluorinated GHG emissions.


Sec.  98.125  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 mass of fluorinated GHG produced, 
the mass of reactants fed into the production process, the mass of 
reactants permanently removed from the production process, the mass 
flow of process streams containing more than trace concentrations of 
by-products that lead to yield losses, or the mass of wastes fed into 
the destruction device; the substitute value of that parameter shall be 
a secondary mass measurement taken during the period the primary mass 
measurement was not 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.
    (2) For each missing value of fluorinated GHG 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 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.
    (3) If the methods specified in paragraphs (a)(1) and (2) of this 
section are likely to significantly under- or overestimate the value of 
the parameter during the period when data were missing, you shall 
develop a best estimate of the parameter, documenting the methods used, 
the rationale behind them, and the reasons why the methods specified in 
(a)(1) and (2) would lead to a significant under- or overestimate of 
the parameter.


Sec.  98.126  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), you 
shall report the following information for each production process at 
the facility.

[[Page 16658]]

    (1) The total mass of the fluorinated GHG produced in metric tons, 
by chemical.
    (2) The total mass of each reactant fed into the production process 
in metric tons, by chemical.
    (3) The total mass of each reactant permanently removed from the 
production process in metric tons, by chemical.
    (4) The total mass of the fluorinated GHG product removed from the 
production process and destroyed.
    (5) The mass of each by-product generated.
    (6) The mass of each by-product destroyed at the facility.
    (7) The mass of each by-product recaptured and sent off-site for 
destruction.
    (8) The mass of each by-product recaptured for other purposes.
    (9) The mass of each fluorinated GHG emitted.
    (b) Where missing data have been estimated pursuant to Sec.  
98.125, you shall report the information specified in paragraphs (b)(1) 
and (2) of this section.
    (1) 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.
    (2) Where the missing data have been estimated pursuant to Sec.  
98.125(a)(3), you shall also report the rationale for the methods used 
to estimate the missing data and why the methods specified in Sec.  
98.125 (a)(1) and (2) would lead to a significant under- or 
overestimate of the parameter(s).
    (c) A fluorinated GHG production facility that destroys fluorinated 
GHGs shall report the results of the annual fluorinated GHG 
concentration measurements at the outlet of the destruction device, 
including:
    (1) Flow rate of fluorinated GHG being fed into the destruction 
device in kg/hr.
    (2) Concentration (mass fraction) of fluorinated GHG at the outlet 
of the destruction device.
    (3) Flow rate at the outlet of the destruction device in kg/hr.
    (4) Emission rate calculated from paragraphs(c)(2) and (c)(3) of 
this section in kg/hr.
    (d) A fluorinated GHG production facility that destroys fluorinated 
GHGs shall submit a one-time report containing the following 
information:
    (1) Destruction efficiency (DE) of each destruction unit.
    (2) Test 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.


Sec.  98.127  Records that must be retained.

    (a) In addition to the data required by Sec. Sec.  98.123 and 
98.126, you shall retain the following records:
    (1) Dated records of the data used to estimate the data reported 
under Sec. Sec.  98.123 and 98.126.
    (2) Dated 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.  98.124(g) and (h).
    (b) In addition to the data required by paragraph (a) of this 
section, the designated representative of a 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 annaul destruction device outlet 
reports in Sec.  98.126(c) and (d).


Sec.  98.128  Definitions.

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

Subpart M--Food Processing


Sec.  98.130  Definition of the source category.

    Food processing facilities prepare raw ingredients for consumption 
by animals or humans. Food processing facilities transform raw 
ingredients into food, transform food into other forms for consumption 
by humans or animals, or transform food for further processing by the 
food processing industry.


Sec.  98.131  Reporting threshold.

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


Sec.  98.132  GHGs to report.

    You must report:
    (a) Emissions of CO2, N2O, and CH4 
from on-site stationary combustion. You must follow the requirements of 
subpart C of this part.
    (b) Emissions of CH4 from on-site landfills. You must 
follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of subpart HH of this part.
    (c) Emissions of CH4 from on-site wastewater treatment. 
You must follow the requirements of subpart II of this part.


Sec.  98.133  Definitions.

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

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.

    (a) You must report CO2 process emissions from each 
continuous glass melting furnace at your glass manufacturing facility 
as required by this subpart.
    (b) You must report the CO2, N2O, and CH\4\ 
emissions from fuel combustion at each continuous glass melting furnace 
and at any other on-site stationary fuel combustion unit. For each 
stationary fuel combustion unit, you must follow the requirements of 
subpart C of this part.


Sec.  98.143  Calculating GHG emissions.

    (a) If you operate and maintain a continuous emission monitoring 
system (CEMS) that measures total CO2 emissions consistent 
with the requirements in subpart C of this part, you must estimate 
total CO2 emissions according to the requirements in Sec.  
98.33.
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you shall calculate process emissions of CO2 
from each glass melting furnace

[[Page 16659]]

according to paragraphs (b)(1) through (5) of this section, except as 
specified in paragraph (c) of this section.
    (1) For each carbonate-based raw material charged to the furnace, 
obtain from the supplier of the raw material the carbonate-based 
mineral mass fraction.
    (2) Determine the quantity of each carbonate-based raw material 
charged to the furnace.
    (3) Apply the appropriate emission factor for each carbonate-based 
raw material charged to the furnace, as shown in Table N-1 to this 
subpart.
    (4) Use Equation N-1 of this subpart to calculate process mass 
emissions of CO2 for each furnace:
[GRAPHIC] [TIFF OMITTED] TP10AP09.057

Where:

ECO2 = Process mass emissions of CO2 (metric 
ton/yr) from the furnace.
n = Number of carbonate-based raw materials charged to furnace.
MFi = Mass fraction of carbonate-based mineral i in 
carbonate-based raw material i (dimensionless unit).
Mi = Mass of carbonate-based raw material i charged to 
furnace (metric ton/yr).
EFi = Emission factor for carbonate-based raw material i 
(metric ton CO2/metric ton carbonate-based raw material).
Fi = Fraction of calcination achieved for carbonate-based 
raw material i, assumed to be equal to 1.0 (dimensionless unit).

    (5) You must determine the total process CO2 emissions 
from continuous glass melting furnaces at the facility using Equation 
N-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.058

Where:

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

    (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 shall determine annual amounts of carbonate-based raw 
materials charged to each continuous glass melting furnace using 
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) If raw material supplier data are used to determine carbonate-
based mineral mass fractions according to Sec.  98.143(b)(1), 
measurements of the mass fraction of each carbonate-based mineral in 
the carbonate-based raw materials shall be made 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 a suitable method 
published by a consensus standards organization (e.g., ASTM Method 
D3682, Test Method for Major and Minor Elements in Coal and Coke Ash by 
Atomic Absorption Method).


Sec.  98.145  Procedures for estimating missing data.

    (a) Missing data on the monthly amounts of carbonate-based raw 
materials charged to any continuous glass melting furnace shall be 
replaced by the average of the data from the previous month and the 
following month for each carbonate-based raw material charged.
    (b) Missing data on the mass fractions of carbonate-based minerals 
in the carbonate-based raw materials shall be replaced using the 
assumption that the mass fraction of each carbonate based mineral is 
1.0.


Sec.  98.146  Data reporting requirements.

    You shall report the information specified in paragraphs (a) 
through (d) of this section for each continuous glass melting furnace.
    (a) Annual process emissions of CO2, in metric tons/yr.
    (b) Annual quantity of each carbonate-based raw material charged, 
in metric tons/yr.
    (c) Annual quantity of glass produced, in metric tons/yr.
    (d) If process CO2 emissions are calculated based on 
data provided by the raw material supplier according to Sec.  
98.143(a)(1), the carbonate-based mineral mass fraction (as percent) 
for each carbonate-based raw material charged to a continuous glass 
melting furnace.


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) through (e) of this 
section.
    (a) Total number of continuous glass melting furnaces.
    (b) Monthly glass production rate for each continuous glass melting 
furnace.
    (c) Monthly amount of each carbonate-based raw material charged to 
each continuous glass melting furnace.
    (d) If process CO2 emissions are calculated using data 
provided by the raw material supplier according to Sec.  98.143(b)(1), 
you must retain the records in paragraphs (d)(1) and (2) of this 
section.
    (1) Data on carbonate-based mineral mass fractions provided by the 
raw material supplier.
    (2) 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.
    (e) 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 of Subpart N--CO2 Emission Factors for Carbonate-Based Raw
                                Materials
------------------------------------------------------------------------
                                                           CO2 Emission
         Carbonate-based raw  material--mineral              factor a
------------------------------------------------------------------------
Limestone--CaCO3........................................           0.440

[[Page 16660]]

 
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 a HCFC-22 production or HFC-23 destruction process and the 
facility meets the requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.152  GHGs to report.

    (a) You must report the CO2, N2O, and 
CH4 emissions from each on-site stationary combustion unit. 
For these stationary combustion units, you must follow the applicable 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
subpart C of this part.
    (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 total 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 daily 
(or more frequent) HFC-23 concentration measurement (which may be the 
average of more frequent concentration measurements) by the daily (or 
more frequent) mass flow of the combined stream of HFC-23 and the other 
product. To estimate annual HFC-23 production, sum the daily (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] TP10AP09.059

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 daily 
(or more frequent) measurement of the HFC-23 concentration and the 
daily (or more frequent) measurement of the other product concentration 
by the daily (or more frequent) mass produced of the other product. To 
estimate annual HFC-23 production, sum the daily (or more 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] TP10AP09.060

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).
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] TP10AP09.061

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 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] TP10AP09.062

Where:

E23 = Mass of HFC-23 emitted annually (metric tons).
G23 = Mass of HFC-23 generated annually (metric tons).
S23 = Mass of HFC-23 packaged 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).


[[Page 16661]]


    (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] TP10AP09.063

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 (metric tons).
EPV = Mass of HFC-23 emitted annually from process vents, 
calculated using Equation O-7 (metric tons).
ED = Mass of HFC-23 emitted annually from thermal 
oxidizer (metric tons), calculated using Equation O-9 of this 
section.

    (e) 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] TP10AP09.064

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 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(h).
FLt = The applicable leak rate specified in table O-1 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(i).
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.
10-3 = Factor converting kg to metric tons.

                          Table O-1 of Subpart O--Emission Factors for Equipment Leaks
----------------------------------------------------------------------------------------------------------------
                                                                                Emission factor (kg/hr/source)
               Equipment type                             Service            -----------------------------------
                                                                                >=10,000 ppmv     <10,000 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
----------------------------------------------------------------------------------------------------------------

    (f) 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] TP10AP09.065

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.

    (g) For facilities that destroy HFC-23, the total mass of HFC-23 
destroyed shall be estimated by using Equation O-8 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.066

Where:

D = 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).

    (h) The total mass of HFC-23 emitted from destruction devices shall 
be estimated by using Equation O-9 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.067

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).
D = Mass of HFC-23 destroyed annually (metric tons).


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 daily 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 continuously using a flow meter with an accuracy and 
precision of 1.0 percent of full scale or better.

[[Page 16662]]

    (c) The mass of HCFC-22 or HCl coming out of the production process 
shall be measured at least daily 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 at least daily (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.
    (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 packaged for sale shall be measured at least 
daily (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 daily (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 daily 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 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.
    (i) 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.
    (j) The mass of HFC-23 emitted from process vents shall be 
estimated at least monthly by conducting emissions tests at process 
vents at least annually and by incorporating the results of the most 
recent emissions test into Equation O-6 of this subpart. 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.
    (k) For purposes of Equation O-8, the destruction efficiency can 
initially 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. HFC-23 destruction 
facilities shall conduct annual measurements of mass flow and HFC-23 
concentrations at the outlet of the thermal oxidizer in accordance with 
EPA Method 18 at 40 CFR part 60, appendix A-6. Tests shall be conducted 
under conditions that are typical for the production process and 
destruction device at the facility. The sensitivity of the emissions 
tests shall be sufficient to detect emissions equal to 0.01 percent of 
the mass of HFC-23 being fed into the destruction device. If the test 
indicates that the actual DE of the destruction device is lower than 
the previously determined DE, facilities shall either:
    (1) Substitute the DE implied by the most recent emissions test for 
the previously determined DE in the calculations in Sec.  98.153.
    (2) Perform more extensive performance testing of the DE of the 
oxidizer and use the DE determined by the more extensive testing in the 
calculations in Sec.  98.153.
    (l) Designated representatives of 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.
    (m) The mass of HFC-23 fed into the destruction device shall be 
measured at least daily 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 concentrations of the HFC-23 shall be measured at least daily 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.
    (n) In their estimates of the mass of HFC-23 destroyed, designated 
representatives of 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.
    (o) All flowmeters, scales, and load cells used to measure 
quantities that are to be reported under Sec.  98.156 shall be 
calibrated using suitable NIST-traceable standards and suitable methods 
published by a consensus standards organization (e.g., ASTM, ASME, 
ASHRAE, or others). Alternatively, calibration procedures specified by 
the flowmeter, scale, or load cell manufacturer may be used. 
Calibration shall be performed prior to the first reporting year. After 
the initial calibration, recalibration shall be performed at least 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent.
    (p) 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 Test Method 205, 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

[[Page 16663]]

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. 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.
    (3) Notwithstanding paragraphs (a)(1) and (2) of this section, if 
the owner or operator has reason to believe that the methods specified 
in paragraphs (a)(1) and (2) of this section are likely to 
significantly under- or overestimate the value of the parameter during 
the period when data were missing (e.g., because the monitoring failure 
was linked to a process disturbance that is likely to have 
significantly increased the HFC-23 generation rate), the designated 
representative of the HCFC-22 production facility shall develop his or 
her best estimate of the parameter, documenting the methods used, the 
rationale behind them, and the reasons why the methods specified in 
(a)(1) and (2) would probably lead to a significant under- or 
overestimate of the parameter.


Sec.  98.156  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), the 
designated representative of an HCFC-22 production facility shall 
report the following information at the facility level:
    (1) The mass of HCFC-22 produced in metric tons.
    (2) The mass of reactants fed into the process in metric tons of 
reactant.
    (3) 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.
    (4) The method for tracking startups, shutdowns, and malfunctions 
and HFC-23 generation/emissions during these events.
    (5) 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.
    (6) The total mass of the HFC-23 generated in metric tons.
    (7) The mass of any HFC-23 packaged for sale in metric tons.
    (8) The mass of any HFC-23 sent off site for destruction in metric 
tons.
    (9) The mass of HFC-23 emitted in metric tons.
    (10) The mass of HFC-23 emitted from equipment leaks in metric 
tons.
    (11) The mass of HFC-23 emitted from process vents in metric tons.
    (b) Where missing data have been estimated pursuant to Sec.  
98.155, the designated representative of the HCFC-22 production 
facility or HCF-23 destruction facility shall report 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.
    (1) Where the missing data have been estimated pursuant to Sec.  
98.155(a)(3), the designated representative shall also report the 
rationale for the methods used to estimate the missing data and why the 
methods specified in Sec.  98.155(a)(1) and (2) would probably lead to 
a significant under- or overestimate of the parameter(s).
    (c) In addition to the information required by Sec.  98.3(c), the 
designated representative of a facility that destroys HFC-23 shall 
report the following for each HFC-23 destruction process:
    (1) The mass of HFC-23 fed into the thermal oxidizer.
    (2) The mass of HFC-23 destroyed.
    (3) The mass of HFC-23 emitted from the thermal oxidizer.
    (d) The designated representative of 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) The flow rate of HFC-23 being fed into the destruction device 
in kg/hr.
    (2) The concentration (mass fraction) of HFC-23 at the outlet of 
the destruction device.
    (3) The flow rate at the outlet of the destruction device in kg/hr.
    (4) The emission rate calculated from paragraphs (c)(2) and (3) of 
this section in kg/hr.
    (e) The designated representative of an HFC-23 destruction facility 
shall submit a one-time report including the following information:
    (1) The destruction unit's destruction efficiency (DE).
    (2) The methods used to determine the unit's 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.


Sec.  98.157  Records that must be retained.

    (a) In addition to the data required by Sec.  98.3(g), the 
designated representative of an HCFC-22 production facility 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(o) and (p).
    (b) In addition to the data required by Sec.  98.3(g), the 
designated representative of a HFC-23 destruction facility shall retain 
the following records:
    (1) Records documenting their one-time and annual reports in Sec.  
98.156(c), (d), and (e).
    (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 standards or manufacturer directions 
used for calibration pursuant to Sec.  98.154(o) and (p).


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.

Subpart P--Hydrogen Production


Sec.  98.160  Definition of the source category.

    (a) A hydrogen production source category produces hydrogen gas 
that is consumed at sites other than where it is produced.
    (b) This source category comprises process units that produce 
hydrogen by oxidation, reaction, or other transformations of 
feedstocks.
    (c) This source category includes hydrogen production facilities 
located within a petroleum refinery and that are not owned or under the 
direct control of the refinery owner and operator.

[[Page 16664]]

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 (2).


Sec.  98.162  GHGs to report.

    You must report:
    (a) CO2 process emissions for each hydrogen production process 
unit.
    (b) CO2, CH4, and N2O emissions from the combustion of fuels in 
each hydrogen production unit and any other stationary combustion units 
by following the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of subpart C of this part.
    (c) For CO2 collected and used on site or transferred off site, you 
must follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of subpart PP of this part.


Sec.  98.163  Calculating GHG emissions.

    You must determine CO2 emissions in accordance with the procedures 
specified in either paragraph (a) or (b) of this section.
    (a) Continuous emission monitoring system. Any hydrogen process 
unit that meets the conditions specified in Sec.  98.33(b)(5)(iii)(A), 
(B), and (C), or Sec.  98.33(b)(5)(ii)(A) through (F) shall calculate 
total CO2 emissions using a continuous emissions monitoring system 
according to the Tier 4 Calculation Methodology specified in Sec.  
98.33(a)(4).
    (b) Feedstock material balance approach. If you do not measure 
total emissions with a CEMS, you must calculate the annual CO2 process 
emissions from feedstock used for hydrogen production.
    (1) Gaseous feedstock. You must calculate the total CO2 
process emissions from gaseous feedstock according to Equation P-1 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.068

Where:

CO2 = Annual CO2 process emissions arising 
from feedstock consumption (metric tons).
(Fdstk)n = Volume of the gaseous feedstock used in month 
n (scf of feedstock).
(CC)n = Average carbon content of the gaseous feedstock, from the 
analysis results for month n (kg C per kg of feedstock).
MW = Molecular weight of the gaseous feedstock (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf per kg-mole at 
standard conditions).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon. and
0.001 = Conversion factor from kg to metric tons.

    (2) Liquid feedstock. You must calculate the total CO2 
process emissions from liquid feedstock according to Equation P-2 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.069

Where:

    CO2 = Annual CO2 emissions arising from 
feedstock consumption (metric tons).
(Fdstk)n = Volume of the liquid feedstock used in month n (gallons 
of feedstock).
(CC)n = Average carbon content of the liquid feedstock, from the 
analysis results for month n (kg C per gallon of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.

    (3) Solid feedstock. You must calculate the total CO2 
process emissions from solid feedstock according to Equation P-3 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.070

Where:

CO2 = Annual CO2 emissions from feedstock 
consumption in metric tons per month (metric tons).
(Fdstk)n = Mass of solid feedstock used in month n (kg of 
feedstock).
(CC)n = Average carbon content of the solid feedstock, from the 
analysis results for month n (kg C per kg of feedstock).
k = Months per year.
44/12 = Ratio of molecular weights, CO2 to carbon.
0.001 = Conversion factor from kg to metric tons.


Sec.  98.164  Monitoring and QA/QC requirements.

    (a) Facilities that use CEMS must comply with the monitoring and 
QA/QC procedures specified in Sec.  98.34(e).
    (b) The quantity of gaseous or liquid feedstock consumed must be 
measured continuously using a flow meter. The quantity of solid 
feedstock consumed can be obtained from company records and aggregated 
on a monthly basis.
    (c) You must collect a sample of each feedstock and analyze the 
carbon content of each sample using appropriate test methods 
incorporated by reference in Sec.  98.7. The minimum frequency of the 
fuel sampling and analysis is monthly.
    (d) All fuel flow meters, gas composition monitors, and heating 
value monitors shall be calibrated prior to the first reporting year, 
using a suitable method published by a consensus standards organization 
(e.g., ASTM, ASME, API, AGA, or others). Alternatively, calibration 
procedures specified by the flow meter manufacturer may be used. Fuel 
flow

[[Page 16665]]

meters, gas composition monitors, and heating value monitors shall be 
recalibrated either annually or at the minimum frequency specified by 
the manufacturer.
    (e) You must document the procedures used to ensure the accuracy of 
the estimates of feedstock consumption.


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 shall be used in the calculations, according to the 
following requirements:
    (a) For missing feedstock supply rates, use the lesser of the 
maximum supply rate that the unit is capable of processing or the 
maximum supply rate that the meter can measure.
    (b) There are no missing data procedures for carbon content. A re-
test must be performed if the data from any monthly measurements are 
determined to be invalid.
    (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 following information for each process 
unit:
    (a) Facilities that use CEMS must comply with the procedures 
specified in Sec.  98.36(a)(1)(iv).
    (b) Annual total consumption of feedstock for hydrogen production; 
annual total of hydrogen produced; and annual total of ammonia 
produced, if applicable.
    (c) Monthly analyses of carbon content for each feedstock used in 
hydrogen production (kg carbon/kg of feedstock).


Sec.  98.167  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) For all CEMS, you must comply with the CEMS recordkeeping 
requirements in Sec.  98.37.
    (b) Monthly analyses of carbon content for each feedstock used in 
hydrogen production.


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 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 combustion-related CO2, CH4, and N2O 
emissions from each stationary combustion unit and follow the 
requirements in subpart C of this part. 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, flares, flame suppression, ladle 
reheaters, and other miscellaneous combustion sources.
    (b) You must report process-related CO2 emissions from 
each taconite indurating furnace; basic oxygen furnace; non-recovery 
coke oven battery combustion stack; sinter process; EAF; argon-oxygen 
decarburization vessel; and direct reduction furnace by following the 
procedures in this subpart.
    (c) You must report CO2 emissions from each coke pushing 
process by following the procedures in this subpart.


Sec.  98.173  Calculating GHG emissions.

    (a) For each taconite indurating furnace, basic oxygen furnace, 
non-recovery coke oven battery, sinter process, EAF, argon-oxygen 
decarburization vessel, and direct reduction furnace, you must 
determine CO2 emissions using the procedures in paragraph 
(a)(1), (a)(2), or (3) of this section as appropriate.
    (1) Continuous emissions monitoring system (CEMS). If you operate 
and maintain a CEMS that measures CO2 emissions consistent 
with the requirements in subpart C, you must estimate total 
CO2 emissions according to the requirements in Sec.  98.33.
    (2) Carbon mass balance method. For the carbon balance method, 
calculate the mass emissions rate of CO2 in each calendar 
month for each process as specified in paragraphs (a)(2)(i) through 
(vii) of this section. The calculations are based on the monthly mass 
of inputs and outputs to each process and the respective weight 
fraction of carbon. If you have a process input or output that contains 
carbon that is not included in the Equations, you must account for the 
carbon and mass rate of that process input or output in your 
calculations.
    (i) For taconite indurating furnaces, estimate CO2 
emissions using Equation Q-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.071

Where:

CO2 = Annual CO2 mass emissions from the 
indurating furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fs)n = Mass of the solid fuel combusted in month ``n'' (metric 
tons).
(Csf)n = Carbon content of the solid fuel, from the fuel analysis 
results for month ``n'' (percent by weight, expressed as a decimal 
fraction, e.g., 95% = 0.95).
(Fg)n = Volume of the gaseous fuel combusted in month ``n'' (scf).
(Cgf)n = Average carbon content of the gaseous fuel, from the fuel 
analysis results for month ``n'' (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.

[[Page 16666]]

(Fl)n = Volume of the liquid fuel combusted in month 
``n'' (gallons).
(Clf)n = Carbon content of the liquid fuel, from the fuel analysis 
results for month ``n'' (kg C per gallon of fuel).
(O)n = Mass of greenball (taconite) pellets fed to the furnace in 
month ``n'' (metric tons).
(C0)n = Carbon content of the greenball (taconite) pellets, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(P)n = Mass of fired pellets produced by the furnace in month ``n'' 
(metric tons).
(Cp)n = Carbon content of the fired pellets, from the carbon 
analysis results for month ``n'' (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] TP10AP09.072

Where:

CO2 = Annual CO2 mass emissions from the basic 
oxygen furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron)n = Mass of molten iron charged to the furnace in month ``n'' 
(metric tons).
(CIron)n = Carbon content of the molten iron, from the carbon 
analysis results for month ``n'' (percent by weight, expressed as a 
decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to the furnace in month 
``n'' (metric tons).
(CScrap)n = Average carbon content of the ferrous scrap, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged 
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Steel)n = Mass of molten steel produced by the furnace in month 
``n'' (metric tons).
(CSteel)n = Average carbon content of the steel, from the carbon 
analysis results for month ``n'' (percent by weight, expressed as a 
decimal fraction).
(Slag)n = Mass of slag produced by the furnace in month ``n'' 
(metric tons).
(CSlag)n = Average carbon content of the slag, from the carbon 
analysis results for month ``n'' (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] TP10AP09.073

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)n = Mass of coal charged to the battery in month ``n'' (metric 
tons).
(CCoal)n = Carbon content of the coal, from the carbon analysis 
results for month ``n'' (percent by weight, expressed as a decimal 
fraction).
(Coke)n = Mass of coke produced by the battery in month ``n'' 
(metric tons).
(CCoke)n = Carbon content of the coke, from the carbon analysis 
results for month ``n'' (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] TP10AP09.074

Where:

CO2 = Annual CO2 mass emissions from the 
sinter process (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg)n = Volume of the gaseous fuel combusted in month ``n'' (scf).
(Cgf)n = Average carbon content of the gaseous fuel, from the fuel 
analysis results for month ``n'' (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)n = Mass of sinter feed material in month ``n'' (metric tons).
(CFeed)n = Carbon content of the sinter feed material, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Sinter)n = Mass of sinter produced in month ``n'' (metric tons).
(CSinter)n = Carbon content of the sinter pellets, from the carbon 
analysis results for month ``n'' (percent by weight, expressed as a 
decimal fraction).

    (v) For EAFs, estimate CO2 emissions using Equation Q-5 
of this section.

[[Page 16667]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.075

Where:

CO2 = Annual CO2 mass emissions from the EAF 
(metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Iron)n = Mass of direct reduced iron (if any) charged to the 
furnace in month ``n'' (metric tons).
(CIron)n = Carbon content of the molten iron, from the carbon 
analysis results for month ``n'' (percent by weight, expressed as a 
decimal fraction).
(Scrap)n = Mass of ferrous scrap charged to the furnace in month 
``n'' (metric tons).
(CScrap)n = Average carbon content of the ferrous scrap, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged 
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials, from the 
carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Electrode)n= Mass of carbon electrode consumed in month ``n'' 
(metric tons).
(CElectrode)n = Average carbon content of the carbon electrode, from 
the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Steel)n = Mass of molten steel produced by the furnace 
in month ``n'' (metric tons).
(CSteel)n = Average carbon content of the 
steel, from the carbon analysis results for month ``n'' (percent by 
weight, expressed as a decimal fraction).
(Slag)n = Mass of slag produced by the furnace in month 
``n'' (metric tons).
(CSlag)n = Average carbon content of the slag, 
from the carbon analysis results for month ``n'' (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] TP10AP09.076

Where:

CO2 = Annual CO2 mass emissions from the 
argon-oxygen decarburization vessel (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Steel)n = Mass of molten steel charged to the vessel in 
month ``n'' (metric tons).
(CSteelin)n = Carbon content of the molten 
steel before decarburization, from the carbon analysis results for 
month ``n'' (percent by weight, expressed as a decimal fraction).
(CSteelout)n = Average carbon content of the 
molten steel after decarburization, from the carbon analysis results 
for month ``n'' (percent by weight, expressed as a decimal 
fraction).

[GRAPHIC] [TIFF OMITTED] TP10AP09.077

    (vii) For direct reduction furnaces, estimate CO2 
emissions using Equation Q-7 of this section.

Where:

CO2 = Annual CO2 mass emissions from the 
direct reduction furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Fg)n = Volume of the gaseous fuel combusted 
on day ``n'' or in month ``n'', as applicable (scf).
(Cgf)n = Average carbon content of the gaseous 
fuel, from the fuel analysis results for month ``n'' (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)n = Mass of iron ore or iron ore pellets fed to the 
furnace in month ``n'' (metric tons).
(COre)n = Carbon content of the iron ore, from 
the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, 
coke) charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the 
carbonaceous materials, from the carbon analysis results for month 
``n'' (percent by weight, expressed as a decimal fraction).
(Other)n = Mass of other materials charged to the furnace 
in month ``n'' (metric tons).
(COther)n = Average carbon content of the 
other materials charged to the furnace, from the carbon analysis 
results for month ``n'' (percent by weight, expressed as a decimal 
fraction).
(Iron)n = Mass of iron produced in month ``n'' (metric 
tons).
(CIron)n = Carbon content of the iron, from 
the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(NM)n = Mass of non-metallic materials produced by the 
furnace in month ``n'' (metric tons).

[[Page 16668]]

(CNM)n = Average carbon content of the non-
metallic materials, from the carbon analysis results for month ``n'' 
(percent by weight, expressed as a decimal fraction).

    (3) Site-specific emission factor method. You must 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 (a)(3)(i) through (iv) of this section.
    (i) You must measure the production rate or feed rate, as 
applicable, during the test 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 and determine the average hourly CO2 
emission rate for the test.
[GRAPHIC] [TIFF OMITTED] TP10AP09.078

Where:

CO2 = CO2 mass emission rate (metric tons/hr).
5.18 x 10\-7\ = Conversion factor (tons/scf-% CO2).
CCO2 = Hourly CO2 concentration (% 
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.
    (b) 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.


Sec.  98.174  Monitoring and QA/QC requirements.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with subpart C of this part, you 
must meet the monitoring and QA/QC requirements of Sec.  98.34(e).
    (b) If you determine CO2 emissions using the carbon 
balance procedure in Sec.  98.173(a)(2), you must:
    (1) For each process input and output other than fuels, determine 
the mass rate of each process input and output and record the totals 
for each process input and output for each calendar month. Determine 
the mass rate of fuels using the procedures for combustion units in 
Sec.  98.34.
    (2) For each process input and output other than fuels, sample each 
process input and output weekly and prepare a monthly composite sample 
for carbon analysis. For each process input that is a fuel, determine 
the carbon content using the procedures for combustion units in Sec.  
98.34.
    (3) For each process input and output other than fuels, the carbon 
content must be analyzed by an independent certified laboratory using 
test method ASTM C25-06 (``Standard Test Methods for Chemical Analysis 
of Limestone, Quicklime, and Hydrated Lime'').
    (3) For each process input and output other than fuels, the carbon 
content must be analyzed by an independent certified laboratory using 
the test methods specified in this paragraph.
    (A) Use ASTM C25-06 (``Standard Test Methods for Chemical Analysis 
of Limestone, Quicklime, and Hydrated Lime'') for:
    (i) Limestone, dolomite, and slag; ASTM D5373-08 (``Standard Test 
Methods for Instrumental Determination of Carbon, Hydrogen, and 
Nitrogen in Laboratory Samples of Coal and Coke'') for coal, coke, and 
other carbonaceous materials; ASTM E1915-07a (``Standard Test Methods 
for Analysis of Metal Bearing Ores and Related Materials by Combustion 
Infrared-Absorption Spectrometry'') for iron ore, taconite pellets, and 
other iron-bearing materials.
    (ii) ASTM E1019-03 (``Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and 
Cobalt Alloys'') for iron and ferrous scrap.
    (iii) ASTM E1019-03 (``Standard Test Methods for Determination of 
Carbon, Sulfur, Nitrogen, and Oxygen in Steel and in Iron, Nickel, and 
Cobalt Alloys''), ASTM CS-104 (``Carbon Steel of Medium Carbon 
Content''), ISO/TR 15349-1:1998 (``Unalloyed steel--Determination of 
low carbon content. Part 1''), or ISO/TR 15349-3: 1998 (``Unalloyed 
steel--Determination of low carbon content. Part 3'') as applicable for 
steel.
    (c) If you determine CO2 emissions using the site-
specific emission factor procedure in Sec.  98.173(a)(3), you must:
    (1) Conduct an annual performance test under normal process 
operating conditions and at a production rate no less than 90 percent 
of the process rated capacity.
    (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 nine 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 9 hours.
    (4) Conduct the stack test using EPA Method 3A in 40 CFR part 60, 
Appendix A-2 to measure the CO2 concentration, Method 2, 2A, 2C, 2D, or 
2F in appendix A-1 or Method 26, appendix A-2 of 40 CFR part 60 to 
determine the stack gas volumetric flow rate, and Method 4 in appendix 
A-3 of 40 CFR part 60 to determine the moisture content of the stack 
gas.
    (5) Conduct a new performance test and calculate a new site-
specific emission factor if your fuel type or fuel/feedstock mix 
changes, the process changes in a manner that affects energy efficiency 
by more than 10 percent, or the process feed materials change in a 
manner that changes the carbon content of the fuel or feed by more than 
10 percent.
    (6) 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 CH4, and N2O emissions, you must meet the monitoring and 
QA/QC requirements of Sec.  98.34.
    (e) 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.

[[Page 16669]]

Sec.  98.175  Procedures for estimating missing data.

    There are no allowances for missing data for facilities that 
estimate emissions using the carbon balance procedure in Sec.  
98.173(a)(2) or the site-emission factor procedure in Sec.  
98.133(a)(3); 100 percent data availability is required.


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 (g) of this section for coke pushing and for each taconite 
indurating furnace; basic oxygen furnace; non-recovery coke oven 
battery; sinter process; EAF; argon-oxygen decarburization vessel; and 
direct reduction furnace, as applicable:
    (a) Annual CO2 emissions by calendar quarters.
    (b) Annual total for all process inputs and outputs when the carbon 
balance is used for specific processes by calendar quarters (short 
tons).
    (c) Annual production quantity (in metric tons) for taconite 
pellets, coke, sinter, iron, and raw steel by calendar quarters.
    (d) Production capacity (in tons per year) for the production of 
taconite pellets, coke, sinter, iron, and raw steel.
    (e) Annual operating hours for taconite furnaces, coke oven 
batteries, sinter production, blast furnaces, direct reduced iron 
furnaces, and electric arc furnaces.
    (f) Site-specific emission factor for all process units for which 
the site-specific emission factor approach is used.
    (g) Facilities that use CEMS must also comply with the data 
reporting requirements specified in Sec.  98.36(d)(iv).


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 (f) of this 
section, as applicable.
    (a) Annual CO2 emissions as measured or determined for 
each calendar quarter.
    (b) Monthly total for all process inputs and outputs for each 
calendar quarter when the carbon balance is used for specific 
processes.
    (c) Monthly analyses of carbon content for each calendar quarter 
when the carbon balance is used for specific processes.
    (d) Site-specific emission factor for all process units for which 
the site-specific emission factor approach is used.
    (e) Annual production quantity for taconite pellets, coke, sinter, 
iron, and raw steel with records for each calendar quarter.
    (f) 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). The owner or operator 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.

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 (2).


Sec.  98.182  GHGs to report.

    (a) You must report the CO2 process emissions from each 
smelting furnace used for lead production as required by this subpart.
    (b) You must report the CO2, CH4, and 
N2O emissions from each stationary combustion unit following 
the requirements specified in subpart C of this part.


Sec.  98.183  Calculating GHG emissions.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must estimate total CO2 emissions 
according to the requirements in Sec.  98.33.
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must determine using the procedure specified in 
paragraphs (b)(1) and (2) of this section the total CO2 
emissions from the smelting furnaces at your facility used for lead 
production.
    (1) For each smelting furnace at your facility used for lead 
production, you must determine the mass of carbon in each carbon-
containing material, other than fuel, that is fed, charged, or 
otherwise introduced into the smelting furnaces used at your facility 
for lead production for each calendar month and estimate total 
CO2 process emissions from the affected units at your 
facility using Equation R-1 of this section. Carbon containing input 
materials include carbonaceous reducing agents.
[GRAPHIC] [TIFF OMITTED] TP10AP09.079

Where:

CO2 = Total annual CO2 process emissions from 
the individual smelting furnace (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Lead)n = Mass of lead ore charged to the smelting 
furnace in month ``n'' (metric tons).
(CLead)n = Carbon content of the lead ore, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Scrap)n = Mass of lead scrap charged to the furnace in 
month ``n'' (metric tons).
(CScrap)n = Average carbon content of the lead 
scrap, from the carbon analysis results for month ``n'' (percent by 
weight, expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, 
dolomite) charged to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux 
materials, from the carbon analysis results for month ``n'' (percent 
by weight, expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, 
coke) charged to the furnace in month ``n'' (metric tons).

[[Page 16670]]

(CCarbon)n = Average carbon content of the 
carbonaceous materials, from the carbon analysis results for month 
``n'' (percent by weight, expressed as a decimal fraction).
(Other)n = Mass of any other materials charged to the 
furnace in month ``n'' (metric tons).
(COther)n = Average carbon content of any 
other materials from the carbon analysis results for month ``n'' 
(percent by weight, expressed as a decimal fraction).

    (2) You must determine the total CO2 emissions from the 
smelting furnaces using Equation R-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.080

Where:

CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions from smelting 
furnace k calculated using Equation R-1 of this subpart, metric 
tons/year.
k = Total number of smelting furnaces at facility used for the lead 
production.


Sec.  98.184  Monitoring and QA/QC requirements.

    If you determine CO2 emissions using the carbon input 
procedure in Sec.  98.183(b), you must meet the requirements specified 
in paragraphs (a) through (c) of this section.
    (a) Determine the mass of each solid carbon-containing input 
material by direct measurement of the quantity of the material placed 
in the unit or by calculations using process operating information, and 
record the total mass for the material for each calendar month.
    (b) For each input material identified in paragraph (a) of this 
section, you must determine the average carbon content of the material 
for each calendar month using information provided by your material 
supplier or by collecting and analyzing a representative sample of the 
material.
    (c) For each input material identified in paragraph (a) of this 
section for which the carbon content is not provided by your material 
supplier, the carbon content of the material must be analyzed by an 
independent certified laboratory each calendar month using the test 
methods and their QA/QC procedures in Sec.  98.7. Use ASTM E1941-04 
(``Standard Test Method for Determination of Carbon in Refractory and 
Reactive Metals and Their Alloys'') for analysis of lead bearing ore, 
lead scrap, and lead ingot; ASTM D5373-02 (``Standard Test Methods for 
Instrumental Determination of Carbon, Hydrogen, and Nitrogen in 
Laboratory Samples of Coal and Coke'') for analysis of carbonaceous 
reducing agents, and ASTM C25-06 (``Standard Test Methods for Chemical 
Analysis of Limestone, Quicklime, and Hydrated Lime'') for analysis of 
flux materials such as limestone or dolomite.


Sec.  98.185  Procedures for estimating missing data.

    For the carbon input procedure in Sec.  98.183(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.
    (a) For each missing value of the carbon 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, 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 records of the mass of carbon-containing input 
material consumption, the substitute data value shall be the best 
available estimate of the mass of the input material. The owner or 
operator shall document and keep records of the procedures used for all 
such estimates.


Sec.  98.186  Data Reporting Procedures.

    In addition to the information required by Sec.  98.3(c) of this 
part, each annual report must contain the information specified in 
paragraphs (a) through (e) of this section.
    (a) Total annual CO2 emissions from each smelting 
furnace operated at your facility for lead production (metric tons and 
the method used to estimate emissions).
    (b) Facility lead product production capacity (metric tons).
    (c) Annual facility production quantity (metric tons).
    (d) Number of facility operating hours in calendar year.
    (e) If you use the carbon input procedure, report for each carbon-
containing input material consumed or used (other than fuel), the 
following information:
    (1) Annual material quantity (in metric tons).
    (2) Annual weighted average carbon content determined for material 
and the method used for the determination (e.g., supplier provided 
information, analyses of representative samples you collected).


Sec.  98.187  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 facility production quantity for each lead product (in 
metric tons).
    (b) Number of facility operating hours each month.
    (c) If you use the carbon input procedure, record for each carbon-
containing input material consumed or used (other than fuel), the 
information specified in paragraphs (c)(1) and (2) of this section.
    (1) Monthly material quantity (in metric tons).
    (2) Monthly average carbon content determined for material and 
records of the supplier provided information or analyses used for the 
determination.
    (d) 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. 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.  98.188  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.

    Lime manufacturing processes use a rotary lime kiln to produce a 
lime product (e.g., calcium oxide, high-calcium quicklime, calcium 
hydroxide, hydrated lime, dolomitic quicklime, dolomitic hydrate, or 
other products) from limestone or dolomite by means of calcination. The 
lime manufacturing source category consists of marketed lime 
manufacturing facilities and non-marketed lime manufacturing 
facilities.


Sec.  98.191  Reporting threshold.

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


Sec.  98.192  GHGs to report.

    (a) You must report CO2 process emissions from each lime 
kiln as specified in this subpart.

[[Page 16671]]

    (b) You must report CO2, N2O, and CH4 emissions from fuel 
combustion at each lime kiln and any other stationary combustion unit. 
You must follow the requirements of subpart C of this part.


Sec.  98.193  Calculating GHG emissions.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must estimate total CO2 emissions 
according to the requirements in Sec.  98.33.
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you shall calculate CO2 process emissions 
based on the production of each type of lime and calcined by-products/
wastes produced at each kiln according to the procedures in paragraphs 
(b)(1) through (4) of this section.
    (1) You must calculate a monthly emission factor for each kiln 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 
kiln:
[GRAPHIC] [TIFF OMITTED] TP10AP09.081

Where:

EFk = Emission factor for kiln k for lime type i, metric tons 
CO2/metric ton lime.
SRCaO = Stoichiometric ratio of CO2 and CaO for lime type 
i (see Table S-1 of this subpart), metric tons CO2/ 
metric tons CaO.
SRMgO= Stoichiometric ratio of CO2 and MgO for lime type 
i (See Table S-1 of this subpart), metric tons CO2/ 
metric tons MgO.
CaOi= Calcium oxide content for lime type i determined according to 
Sec.  98.194(b), metric tons CaO/ton lime.
MgOi = Magnesium oxide content for lime type i determined according 
to Sec.  98.194(b), metric tons MgO/ metric ton lime.

    (2) You must calculate the correction factor for by-product/waste 
products at the kiln (monthly) using Equation S-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.082

Where:

CFlkd,k = Correction factor for by-products/waste products (such as 
lime kiln dust, LKD) at kiln k.
Md,i = Weight of by-product/waste product not recycled to the kiln 
from lime type i, (tons of lime).
Mlime,i= Weight of lime produced at the kiln from lime type i, (tons 
of lime).
Cd,i = Fraction of original carbonate in the LKD for lime type i, 
(fraction).
Fd,i = Fraction of calcination of the original. carbonate in the LKD 
of lime type i, assumed to be 1.00 (fraction).

    (3) You must calculate annual CO2 process emissions for 
each kiln using Equation S-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.083

Where:

Ek = Annual CO2 process emissions from lime production at 
kiln k (metric tons/year).
EFk,n = Emission factor for lime in calendar month n(tons 
CO2/tons carbonate) from Equation S-1.
Mk,n = Weight or mass of lime produced in calendar month n (tons/
calendar month) from Equation S-3.
CFlkd,k,n = Correction factor for LKD for lime in calendar month n 
from Equation S-2.
0.97 = Default correction factor for the proportion of hydrated lime 
(Assuming 90 percent of hydrated lime produced is high-calcium lime 
with a water content of 28 percent).
2000/2205
    = Conversion factor for tons to metric tons.
    = Number of lime types produced at kiln k.

    (4) You must determine the total CO2 process emissions 
for the facility using Equation S-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.084

Where:

CO2 = Annual CO2 process emissions from lime 
production (metric tons/year).
Ek = Annual CO2 emissions from lime production at kiln k 
(metric tons/year).
z = Number of kilns for lime production.

Sec.  98.194  Monitoring and QA/QC requirements.

    (a) Determine the quantity of each type of lime produced at each 
kiln and the quantity of each type of calcined by-product/waste 
produced for each lime type, such as LKD, at the kiln on a monthly 
basis. The quantity of each type of calcined by-product/waste produced 
at the kiln must include material that is sold or used in a product, 
inventoried, or disposed of. The quantity of lime types and LKD 
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.
    (b) You must determine the chemical composition (percent total CaO 
and percent total MgO) of each type of lime and each type of calcined 
by-product/waste produced from each lime type by an off-site laboratory 
analysis on a monthly basis. This determination must be performed 
according to the requirements of ASTM C25-06, ``Standard Test Methods 
for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'' 
(incorporated by reference--see Sec.  98.7) and the procedures in 
``CO2 Emissions Calculation Protocol for the Lime Industry 
English Units Version'', February 5, 2008 Revision (incorporated by 
reference--see Sec.  98.7).
    (c) You must use the most recent analysis of calcium oxide and 
magnesium oxide content of each lime product in monthly calculations.

[[Page 16672]]

    (d) You must follow the quality assurance/quality control 
procedures (including documentation) in the National Lime Association's 
``CO2 Emissions Calculation Protocol for the Lime Industry-
English Units Version'', February 5, 2008 Revision (incorporated by 
reference--see Sec.  98.7).


Sec.  98.195  Procedures for estimating missing data.

    For the procedure in Sec.  98.193(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.
    (a) For each missing value of quantity of lime types, CaO and MgO 
content, and quantity of LKD 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.
    (b) For missing records of mass of raw material consumption, the 
substitute data value shall be the best available estimate of the mass 
of inputs. The owner or operator shall document and keep records of the 
procedures used for all such estimates.


Sec.  98.196  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), each 
annual report must contain the information specified in paragraphs 
(a)(1) through (5) of this section for each lime kiln:
    (1) Annual CO2 process emissions;
    (2) Annual lime production (in metric tons);
    (3) Annual lime production capacity (in metric tons) per facility;
    (4) All monthly emission factors, and;
    (5) Number of operating hours in calendar year.
    (b) Facilities that use CEMS must also comply with the data 
reporting requirements specified in Sec.  98.36.


Sec.  98.197  Records that must be retained.

    (a) In addition to the records required by Sec.  98.3(g), you must 
retain the following records specified in paragraphs (a)(1) through (4) 
of this section for each lime kiln:
    (1) Annual calcined by-products/waste products (by lime type summed 
from monthly data.
    (2) Lime production (by lime type) per month (metric tons).
    (3) Calculation of emission factors.
    (4) Results of chemical composition analysis (by lime product) per 
month.
    (5) Monthly correction factors for by-products/waste products for 
each kiln.
    (b) Facilities that use CEMS must also comply with the 
recordkeeping requirements specified in Sec.  98.37.


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

Subpart T--Magnesium Production


Sec.  98.200  Definition of source category.

    The magnesium production and processing source category consists of 
the following facilities:
    (a) Any site where magnesium metal is produced through smelting 
(including electrolytic smelting), refining, or remelting operations.
    (b) Any site where molten magnesium is used in alloying, casting, 
drawing, extruding, forming, or rolling operations.


Sec.  98.201  Reporting threshold.

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


Sec.  98.202  GHGs to report.

    (a) You must report emissions of the following gases in kilograms 
and metric tons CO2e per year resulting from their use as 
cover gases or carrier gases in magnesium production or processing:
    (1) Sulfur hexafluoride (SF6).
    (2) HFC-134a.
    (3) The fluorinated ketone, FK 5-1-12.
    (4) Any other fluorinated GHGs.
    (5) Carbon dioxide (CO2).
    (b) You must report CO2, N2O, and 
CH4 emissions from each combustion unit on site by following 
the calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
subpart C of this part.


Sec.  98.203  Calculating GHG emissions.

    (a) Calculate CO2e GHG emissions from magnesium 
production or processing using Equation T-1 of this section. For 
Equation T-1 of this section, use the procedures of either paragraph 
(b) or (c) of this section to estimate consumption of cover gas or 
carrier gas.
[GRAPHIC] [TIFF OMITTED] TP10AP09.186

Where:

EGHG = GHG emissions from magnesium production and 
processing (mtCO2e).
ESF6 = SF6 emissions from magnesium production 
and processing (mtCO2e).
E134a = HFC-134a emissions from magnesium production and 
processing (mtCO2e).

[[Page 16673]]

EFK = FK 5-1-12 emissions from magnesium production and 
processing (mtCO2e).
ECO2 = CO2 emissions from magnesium production 
and processing (mtCO2e).
EOG = Emissions of other fluorinated GHGs from magnesium 
production and processing (mtCO2e).
CSF6 = Consumption of SF6 (kg).
C134a = Consumption of HFC-134a (kg).
CFK = Consumption of FK 5-1-12 (kg).
CCO2 = Consumption of CO2 (kg).
COG = Consumption of other fluorinated GHGs (kg).
GWPOG = The Global Warming Potential of the other 
fluorinated GHG provided in Table A-1 in subpart A of this part.

    (b) To estimate consumption of cover gases or carrier gases by 
monitoring changes in container masses and inventories, consumption of 
each cover gas or carrier gas shall be estimated using Equation T-2 of 
this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.085

Where:

C = Consumption of any cover gas or carrier gas in kg over the 
period (e.g., 1 year).
IB = Inventory of any cover gas or carrier gas stored in 
cylinders or other containers at the beginning of the period (e.g., 
1 year), including heels, in kg.
IE = Inventory of any cover gas or carrier gas stored in 
cylinders or other containers at the end of the period (e.g., 1 
year), including heels, in kg.
A = Acquisitions of any cover gas or carrier gas during the period 
(e.g., 1 year) through purchases or other transactions, including 
heels in cylinders or other containers returned to the magnesium 
production or processing facility, in kg.
D = Disbursements of cover gas or carrier gas to sources and 
locations outside the facility through sales or other transactions 
during the period, including heels in cylinders or other containers 
returned by the magnesium production or processing facility to the 
gas distributor, in kg.

    (c) To estimate consumption of cover gases or carrier gases by 
monitoring changes in the masses of individual containers as their 
contents are used, consumption of each cover gas or carrier gas shall 
be estimated using Equation T-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.086

Where:

CGHG = The consumption of the cover gas over the period 
(kg).
Qp = The mass of the cover gas used over the period (kg).
n = The number of periods in the year.

    (d) For purposes of Equation T-3 of this section, the mass of the 
cover gas used over the period p shall be estimated by using Equation 
T-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.087

Where:

Qp = The mass of the cover gas used over the period (kg).
MB = The mass of the contents of the cylinder at the 
beginning of period p.
ME = The mass of the contents of the cylinder at the end 
of period p.


Sec.  98.204  Monitoring and QA/QC requirements.

    (a) Consumption of cover gases and carrier gases may be estimated 
by monitoring the changes in container weights and inventories using 
Equation T-2 of this subpart, by monitoring the changes in individual 
container weights as the contents of each container are used using 
Equations T-3 and T-4 of this subpart, or by monitoring the mass flow 
of the pure cover gas or carrier gas into the cover gas distribution 
system. Consumption must be estimated at least annually.
    (b) When estimating consumption by monitoring the mass flow of the 
pure cover gas or carrier gas into the cover gas distribution system, 
you must use gas flow meters with an accuracy of one percent of full 
scale or better.
    (c) When estimating consumption using Equation T-2 of this subpart, 
you must ensure that all the quantities required by Equation T-2 of 
this subpart have been measured using scales or load cells with an 
accuracy of one percent of full scale or better, accounting for the 
tare weights of the containers. You may accept gas masses or weights 
provided by the gas supplier (e.g., for the contents of containers 
containing new gas or for the heels remaining in containers returned to 
the gas supplier); however, you remain responsible for the accuracy of 
these masses and weights under this subpart.
    (d) When estimating consumption using Equations T-3 and T-4 of this 
subpart, you must monitor and record container identities and masses as 
follows:
    (1) Track the identities and masses of containers leaving and 
entering storage with check-out and check-in sheets and procedures. The 
masses of cylinders returning to storage shall be measured immediately 
before the cylinders are put back into storage.
    (2) Ensure that all the quantities required by Equations T-3 and T-
4 of this subpart have been measured using scales or load cells with an 
accuracy of one percent of full scale or better, accounting for the 
tare weights of the containers. You may accept gas masses or weights 
provided by the gas supplier (e.g., for the contents of cylinders 
containing new gas or for the heels remaining in cylinders returned to 
the gas supplier); however, you remain responsible for the accuracy of 
these masses or weights under this subpart.
    (e) All flowmeters, scales, and load cells used to measure 
quantities that are to be reported under this subpart shall be 
calibrated using suitable NIST-traceable standards and suitable methods 
published by a consensus standards organization (e.g., ASTM, ASME, 
ASHRAE, or others). Alternatively, calibration procedures specified by 
the flowmeter, scale, or load cell manufacturer may be used. 
Calibration shall be performed prior to the first reporting year. After 
the initial calibration, recalibration shall be performed at least 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent.


Sec.  98.205  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the GHG 
emission calculations is required. Therefore, whenever a quality-
assured value of a required parameter is unavailable, a substitute data 
value for the missing parameter will be used in the calculations as 
specified in paragraph (b) of this section.
    (b) Replace missing data on the consumption of cover gases by 
multiplying magnesium production during the missing data period by the 
average cover gas usage rate from the most recent period when operating 
conditions were similar to those for the period for which the data are 
missing. Calculate the usage rate for each cover gas using Equation T-5 
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.088

Where:

RGHG = The usage rate for a particular cover gas over the 
period.
CGHG = The consumption of that cover gas over the period 
(kg).
Mg = The magnesium produced or fed into the casting process over the 
period (metric tons).


Sec.  98.206  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must include the following information for the magnesium 
production and processing facility:
    (a) Total GHG emissions for your facility by gas in metric tons and 
CO2e.
    (b) Type of production process (e.g. primary, secondary, die 
casting).
    (c) Magnesium production amount in metric tons for each process 
type.
    (d) Cover gas flow rate and composition.
    (e) Amount of CO2 used as a carrier gas during the 
reporting period.

[[Page 16674]]

    (f) For any missing data, you must report the length of time the 
data were missing, the method used to estimate emissions in their 
absence, and the quantity of emissions thereby estimated.
    (g) The facility's cover gas usage rate.
    (h) If applicable, an explanation of any change greater than 30 
percent in the facility's cover gas usage rate (e.g., installation of 
new melt protection technology or leak discovered in the cover gas 
delivery system that resulted in increased consumption).
    (i) A description of any new melt protection technologies adopted 
to account for reduced GHG emissions in any given year.


Sec.  98.207  Records that must be retained.

    In addition to the records specified in Sec.  98.3(g), you must 
retain the following information for the magnesium production or 
processing facility:
    (a) Check-out and weigh-in sheets and procedures for cylinders.
    (b) Accuracy certifications and calibration records for scales.
    (c) Residual gas amounts in cylinders sent back to suppliers.
    (d) Invoices for gas purchases and sales.


Sec.  98.208  Definitions.

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

Subpart U--Miscellaneous Uses of Carbonate


Sec.  98.210  Definition of the source category.

    (a) This source category consists of any equipment that uses 
limestone, dolomite, ankerite, magnesite, silerite, rhodochrosite, 
sodium carbonate, or any other carbonate in a manufacturing process.
    (b) This source category does not include carbonates consumed for 
producing cement, glass, ferroalloys, iron and steel, lead, lime, pulp 
and paper, or zinc.


Sec.  98.211  Reporting threshold.

    You must report GHG emissions from miscellaneous uses of carbonate 
if your facility meets the requirements of either Sec.  98.2(a)(1) or 
(2).


Sec.  98.212  GHGs to report.

    You must report CO2 emissions aggregated for all 
miscellaneous carbonate use at the facility.


Sec.  98.213  Calculating GHG emissions.

    Calculate process emissions of CO2 using Equation U-1 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.089

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.
i = number of the carbonate types.
2000/2205 = Conversion factor to convert tons to metric tons.

    As an alternative to measuring the calcination fraction 
(Fi), a value of 1.0 can be used in Equation U-1 of this 
section.


Sec.  98.214  Monitoring and QA/QC requirements.

    (a) The total mass of carbonate consumed can be determined by 
direct weight measurement using the same plant instruments used for 
accounting purposes, such as weigh hoppers or belt weigh feeders, or 
purchase records.
    (b) Determine on an annual basis the calcination fraction for each 
carbonate consumed based on sampling and chemical analysis conducted by 
a certified laboratory using a suitable method such as using an x-ray 
fluorescence test or other enhanced testing method published by a 
consensus standards organization (e.g., ASTM, ASME, API, etc.).


Sec.  98.215  Procedures for estimating missing data.

    There are no missing data procedures for miscellaneous uses of 
carbonates. A complete record of all measured parameters used in the 
GHG emissions calculations is required. A re-test must be performed if 
the data from any measurements are determined to be invalid.


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 (d) of this section at the facility level.
    (a) Annual CO2 emissions from miscellaneous carbonate 
use (in metric tons).
    (b) Annual carbonate consumption (by carbonate type in tons).
    (c) Annual fraction calcinations.
    (d) Average annual mass fraction of carbonate-based mineral in 
carbonate-based raw material by carbonate type.


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 (c) of this 
section.
    (a) Records of monthly carbonate consumption (by carbonate type). 
You must also document the procedures used to ensure the accuracy of 
monthly carbonate consumption.
    (b) Annual chemical analysis of mass fraction of carbonate-based 
mineral in carbonate-based raw material by carbonate type.
    (c) Records of all carbonate purchases and deliveries.


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 of Subpart U--CO2 Emission Factors for Common Carbonates
------------------------------------------------------------------------
                                                          CO2 emission
                Mineral name--carbonate                 factor (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.........................           0.44197
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 oxidation, condensation, and 
absorption to produce a weak nitric acid (30 to 70 percent in 
strength).


Sec.  98.221  Reporting threshold.

    You must report GHG emissions under this subpart if your facility 
contains a nitric acid production

[[Page 16675]]

process and the facility meets the requirements of either Sec.  
98.2(a)(1) or (2).


Sec.  98.222  GHGs to report.

    (a) You must report N2O process emissions from each 
nitric acid production line as required by this subpart.
    (b) You must report CO2, CH4, and 
N2O emissions from each stationary combustion unit. You must 
follow the requirements of subpart C of this part.


Sec.  98.223  Calculating GHG emissions.

    You must determine annual N2O process emissions from 
each nitric acid production line using a site-specific emission factor 
according to paragraphs (a) through (e) of this section.
    (a) You must conduct an annual performance test to measure 
N2O emissions from the absorber tail gas vent for each 
nitric acid production line. You must conduct the performance test(s) 
under normal process operating conditions.
    (b) You must conduct the emissions test(s) using either EPA Method 
320 in 40 CFR part 63, appendix A or ASTM D6348-03 incorporated by 
reference in Sec.  98.7 to measure the N2O concentration 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.
    (c) You must measure the production rate during the test(s) and 
calculate the production rate for the test period in tons (100 percent 
acid basis) per hour.
    (d) You must calculate a site-specific emission factor for each 
nitric acid production line according to Equation V-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.090

Where:

EFN2O = Site-specific N2O emissions factor (lb 
N2O/ton nitric acid produced, 100 percent acid basis).
CN2O = N2O concentration during performance 
test (ppm N2O).
1.14x10-7 = Conversion factor (lb/dscf-ppm 
N2O).
Q = Volumetric flow rate of effluent gas (dscf/hr).
P = Production rate during performance test (tons nitric acid 
produced per hour (100 percent acid basis)).
n = Number of test runs.

    (e) You must calculate N2O emissions for each nitric 
acid production line by multiplying the emissions factor by the total 
annual production from that production line, according to Equation V-2 
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.091

Where:

EN2O = N2O mass emissions per year 
(metric tons of N2O).
EFN2O = Site-specific N2O emission 
factor for the production line (lb N2O/ton acid produced, 
100 percent acid basis).
Pa = Total production for the year from the production 
line (ton acid produced, 100 percent acid basis).
DFN = Destruction factor of N2O abatement 
technology, 'as specified by the abatement device manufacturer 
(percent of N2O removed from air stream).
AFN = Abatement factor of N2O abatement 
technology (percent of year that abatement technology was used).
2205 = Conversion factor (lb/metric ton).


Sec.  98.224  Monitoring and QA/QC requirements.

    (a) You must conduct a new performance test and calculate a new 
site-specific emissions factor at least annually. You must also conduct 
a new performance test whenever the production rate of a production 
line is changed by more than 10 percent from the production rate 
measured during the most recent performance test. The new emissions 
factor may be calculated using all available performance test data 
(i.e., averaged with the data from previous years), except in cases 
where process modifications have occurred or operating conditions have 
changed. Only the data consistent with the period after the changes 
were implemented shall be used.
    (b) Each facility must conduct the performance test(s) according to 
a test plan and EPA Method 320 in 40 CFR part 63, Appendix A or ASTM 
D6348-03 (incorporated by reference--see Sec.  98.7). All QA/QC 
procedures specified in the reference test methods and any associated 
performance specifications apply. The report must include the items in 
paragraphs (b)(1) through (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. 
The production rate can be determined through sales records or by 
direct measurement using flow meters or weigh scales.


Sec.  98.225  Procedures for estimating missing data.

    Procedures for estimating missing data are not provided for 
N2O process emissions from nitric acid production lines. A 
complete record of all measured parameters used in the GHG emissions 
calculations is required.


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 (h) of this section for each nitric acid production line:
    (a) Annual nitric acid production capacity (metric tons).
    (b) Annual nitric acid production (metric tons).
    (c) Number of operating hours in the calendar year (hours).
    (d) Emission factor(s) used (lb N2O/ton of nitric acid 
produced).
    (e) Type of nitric acid process used.
    (f) Abatement technology used (if applicable).
    (g) Abatement utilization factor (percent of time that abatement 
system is operating).
    (h) Abatement technology efficiency.


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)

[[Page 16676]]

through (c) of this section for each nitric acid production line:
    (a) Records of significant changes to process.
    (b) Annual test reports of N2O emissions.
    (c) Calculations of the site-specific emissions factor(s).


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--Oil and Natural Gas Systems


Sec.  98.230  Definition of the source category.

    This source category consists of the following facilities:
    (a) Offshore petroleum and natural gas production facilities.
    (b) Onshore natural gas processing facilities.
    (c) Onshore natural gas transmission compression facilities.
    (d) Underground natural gas storage facilities.
    (e) Liquefied natural gas storage facilities.
    (f) Liquefied natural gas import and export facilities.


Sec.  98.231  Reporting threshold.

    You must report GHG emissions from oil and natural gas systems if 
your facility meets the requirements of either Sec.  98.2(a)(1) or (2).


Sec.  98.232  GHGs to report.

    (a) You must report CO2 and CH4 emissions in metric tons 
per year from sources specified in Sec.  98.232(a)(1) through (23) at 
offshore petroleum and natural gas production facilities, onshore 
natural gas processing facilities, onshore natural gas transmission 
compression facilities, underground natural gas storage facilities, 
liquefied natural gas storage facilities and liquefied natural gas 
import and export facilities.
    (1) Acid gas removal (AGR) vent stacks.
    (2) Blowdown vent stacks.
    (3) Centrifugal compressor dry seals.
    (4) Centrifugal compressor wet seals.
    (5) Compressor fugitive emissions.
    (6) Compressor wet seal degassing vents.
    (7) Dehydrator vent stacks.
    (8) Flare stacks.
    (9) Liquefied natural gas import and export facilities fugitive 
emissions.
    (10) Liquefied natural gas storage facilities fugitive emissions.
    (11) Natural gas driven pneumatic pumps.
    (12) Natural gas driven pneumatic manual valve actuator devices.
    (13) Natural gas driven pneumatic valve bleed devices.
    (14) Non-pneumatic pumps.
    (15) Offshore platform pipeline fugitive emissions.
    (16) Open-ended lines (oels).
    (17) Pump seals.
    (18) Platform fugitive emissions.
    (19) Processing facility fugitive emissions.
    (20) Reciprocating compressor rod packing.
    (21) Storage station fugitive emissions.
    (22) Storage tanks.
    (23) Storage wellhead fugitive emissions.
    (24) Transmission station fugitive emissions.
    (b) You must report the CO2, CH4, and N2O emissions for 
stationary combustion sources, by following the calculation procedures, 
monitoring and QA/QC methods, missing data procedures, reporting 
requirements, and recordkeeping requirements of subpart C of this part.


Sec.  98.233  Calculating GHG emissions.

    (a) Estimate emissions using either an annual direct measurement, 
as specified in Sec.  98.234, or an engineering estimation method 
specified in this section. You may use the engineering estimation 
method only for sources for which a method is specified in this 
section.
    (b) You may use engineering estimation methods described in this 
section to calculate emissions from the following fugitive emissions 
sources:
    (1) Acid gas removal vent stacks.
    (2) Natural gas driven pneumatic pumps.
    (3) Natural gas driven pneumatic manual valve actuator devices.
    (4) Natural gas driven pneumatic valve bleed devices.
    (5) Blowdown vent stacks.
    (6) Dehydrator vent stacks.
    (c) A combination of engineering estimation described in this 
section and direct measurement described in Sec.  98.234 shall be used 
to calculate emissions from the following fugitive emissions sources:
    (1) Flare stacks.
    (2) Storage tanks.
    (3) Compressor wet seal degassing vents.
    (d) You must use the methods described in Sec.  98.234 (d) or (e) 
to conduct annual leak detection of fugitive emissions from all sources 
listed in Sec.  98.232(a). If fugitive emissions are detected, 
engineering estimation methods may be used for sources listed in 
paragraphs (b) and (c) of this section. If engineering estimation is 
used, emissions must be calculated using the appropriate method from 
paragraphs (d)(1) through (9) of this section:
    (1) Acid gas removal vent stack. Calculate acid gas removal vent 
stack fugitive emissions using simulation software packages, such as 
ASPENTM or AMINECalcTM. Any standard simulation 
software may be used provided it accounts for the following parameters:
    (i) Natural gas feed temperature, pressure, and flow rate.
    (ii) Acid gas content of feed natural gas.
    (iii) Acid gas content of outlet natural gas.
    (iv) Unit operating hours, excluding downtime for maintenance or 
standby.
    (v) Exit temperature of natural gas.
    (vi) Solvent pressure, temperature, circulation rate and weight.
    (vii) If the acid gas removal unit is capturing CO2 and 
transferring it off site, then refer to subpart OO of this part for 
calculating transferred CO2.
    (2) Natural gas driven pneumatic pump. Calculate fugitive emissions 
from a natural gas driven pneumatic pump as follows:
    (i) Calculate fugitive emissions using manufacturer data.
    (A) Obtain from the manufacturer specific pump model natural gas 
emission per unit volume of liquid pumped at operating pressures.
    (B) Maintain a log of the amount of liquid pumped annually from 
individual pumps.
    (C) Calculate the natural gas fugitive emissions for each pump 
using Equation W-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.092

Where:

Es,n = Natural gas fugitive emissions at standard 
conditions.
Fs = Natural gas driven pneumatic pump gas emission in 
``emission per volume of liquid pumped at discharge pressure'' units 
at standard conditions, as provided by the manufacturer.
V = Volume of liquid pumped annually.

    (D) Both CH4 and CO2 volumetric and mass 
fugitive emissions shall be calculated from volumetric natural gas 
fugitive emissions using calculations in paragraphs (f) and (g) of this 
section.
    (ii) If manufacturer data for Fs are not available, 
follow the method in Sec.  98.234 (i)(1).
    (3) Natural gas driven pneumatic manual valve actuator devices. 
Calculate fugitive emissions from a natural gas driven pneumatic manual 
valve actuator device as follows:
    (i) Calculate fugitive emissions using manufacturer data.

[[Page 16677]]

    (A) Obtain from the manufacturer specific pneumatic device model 
natural gas emission per actuation.
    (B) Maintain a log of the number of times the pneumatic device was 
actuated throughout the reporting period.
    (C) Calculate the natural gas fugitive emissions for each manual 
valve actuator using Equation W-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.093

Where:

Es,n = Natural gas fugitive emissions at standard 
conditions.
As = Natural gas driven pneumatic valve actuator natural 
gas emission in ``emission per actuation'' units at standard 
conditions, as provided by the manufacturer.
N = Number of times the pneumatic device was actuated in a way that 
vented natural gas to the atmosphere through the reporting period.

    (D) Calculate both CH4 and CO2 volumetric and 
mass fugitive emissions from volumetric natural gas fugitive emissions 
using calculations in paragraphs (f) and (g) of this section.
    (ii) Follow the method in Sec.  98.234(i)(2) if manufacturer data 
are not available.
    (4) Natural gas driven pneumatic valve bleed devices. Calculate 
fugitive emissions from a natural gas driven pneumatic valve bleed 
device as follows:
    (i) Calculate fugitive emissions using manufacturer data.
    (A) Obtain from the manufacturer specific pneumatic device model 
natural gas bleed rate during normal operation.
    (B) Calculate the natural gas fugitive emissions for each valve 
bleed device using Equation W-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.094

Where:

Es,n = Natural gas fugitive emissions at standard 
conditions.

Bs = Natural gas driven pneumatic device bleed rate in 
``emission per unit time'' units at standard conditions, as provided 
by the manufacturer.

T = Amount of time the pneumatic device has been operational through 
the reporting period.

    (C) Calculate both CH4 and CO2 volumetric 
and mass fugitive emissions from volumetric natural gas fugitive 
emissions using calculations in paragraphs (f) and (g) of this 
section.
    (ii) Follow the method in Sec.  98.234(i)(3) if manufacturer 
data are not available.
    (5) Blowdown vent stacks. Calculate fugitive emissions from 
blowdown vent stacks as follows:
    (i) Calculate the total volume (including, but not limited to 
pipelines and vessels) between isolation valves (Vv in 
Equation W-4 of this subpart).
    (ii) Retain logs of the number of blowdowns for each equipment 
type.
    (iii) Calculate the total annual fugitive emissions using the 
following Equation W-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.095

Where:

Ea,n = Natural gas fugitive emissions at ambient 
conditions from blowdowns.
N = Number of blowdowns for the equipment in reporting year.
Vv = Total volume of blowdown equipment chambers 
(including, but not limited to, pipelines and vessels) between 
isolation valves.

    (iv) Calculate natural gas volumetric fugitive emissions at 
standard conditions using calculations in paragraph (e) of this 
section.
    (v) Calculate both CH4 and CO2 volumetric and 
mass fugitive emissions from volumetric natural gas fugitive emissions 
using calculations in paragraphs (f) and (g) of this section.
    (6) Dehydrator vent stacks. Calculate fugitive emissions from a 
dehydrator vent stack using a simulation software packages, such as 
GLYCalcTM. Any standard simulation software may be used 
provided it accounts for the following parameters:
    (i) Feed natural gas flow rate.
    (ii) Feed natural gas water content.
    (iii) Outlet natural gas water content.
    (iv) Absorbent circulation pump type (natural gas pneumatic/air 
pneumatic/electric).
    (v) Absorbent circulation rate.
    (vi) Absorbent type: Including, but not limited to, triethylene 
glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG).
    (vii) Use of stripping natural gas.
    (viii) Use of flash tank separator (and disposition of recovered 
gas).
    (ix) Hours operated.
    (x) Wet natural gas temperature, pressure, and composition.
    (7) Flare stacks. Calculate fugitive emissions from a flare stack 
as follows:
    (i) Determine flare combustion efficiency from manufacturer. If not 
available, assume that flare combustion efficiency is 95 percent for 
non-steam aspirated flares and 98 percent for steam aspirated or air 
injected flares.
    (ii) Calculate volume of natural gas sent to flare from velocity 
measurement in Sec.  98.234(j) using manufacturer's manual for the 
specific meter used to measure velocity.
    (iii) Calculate GHG volumetric fugitive emissions at actual 
conditions using Equation W-5 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.096

Where:

Ea,i = Annual fugitive emissions from flare stack.
Va = Volume of natural gas sent to flare stack determined 
from Sec.  98.234(j)(1).
[eta] = Percent of natural gas combusted by flare (default is 95 
percent for non-steam aspirated flares and 98 percent for steam 
aspirated or air injected flares).
Xi = Concentration of GHG i in the flare gas determined 
from Sec.  98.234(j)(1).
Yj = Concentration of natural gas hydrocarbon 
constituents j (such as methane, ethane, propane, butane, and 
pentanes plus).
Rj,i = Number of carbon atoms in the natural gas 
hydrocarbon constituent j; 1 for methane, 2 for ethane, 3 for 
propane, 4 for butane, and 5 for pentanes plus).
K = ``1'' when GHG i is CH4 and ``0'' when GHG i is 
CO2.

    (iv) Calculate GHG volumetric fugitive emissions at standard 
conditions using Equation W-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.097

Where:

Es,i = Natural gas volumetric fugitive emissions at 
standard temperature and pressure (STP) conditions.
Ea,i = Natural gas volumetric fugitive emissions at 
actual conditions.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (inches of 
Hg).
Pa = Absolute pressure at ambient conditions (inches of 
Hg).

    (v) Calculate both CH4 and CO2 mass fugitive 
emissions from volumetric CH4 and CO2 fugitive 
emissions using calculations in paragraph (g) of this section.
    (8) Storage tanks. Calculate fugitive emissions from a storage tank 
as follows:
    (i) Calculate the total annual hydrocarbon vapor fugitive emissions 
using Equation W-7 of this section:

[[Page 16678]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.098

Where:

Ea,h = Hydrocarbon vapor fugitive emissions at actual 
conditions.
Q = Storage tank total annual throughput.
ER = Measured hydrocarbon vapor emissions rate per throughput (e.g. 
cubic feet/barrel) determined from Sec.  98.234(j)(2).

    (ii) Estimate hydrocarbon vapor volumetric fugitive emissions at 
standard conditions using calculations in paragraph (e) of this 
section.
    (iii) Estimate CH4 and CO2 volumetric 
fugitive emissions from volumetric hydrocarbon fugitive emissions using 
Equation W-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.099

Where:

Es,i = GHG i (either CH4 or CO2) 
volumetric fugitive emissions at standard conditions.
Es,h = Hydrocarbon vapor volumetric fugitive emissions at 
standard conditions.
Mi = Mole percent of a particular GHG i in the 
hydrocarbon vapors; hydrocarbon vapor analysis shall be conducted in 
accordance with ASTM D1945-03.

    (iv) Estimate CH4 and CO2 mass fugitive 
emissions from GHG volumetric fugitive emissions using calculations in 
paragraph (g) of this section.
    (9) Compressor wet seal degassing vents. Calculate fugitive 
emissions from compressor wet seal degassing vents as follows:
    (i) Calculate volume of natural gas sent to vent from velocity 
measurement in Sec.  98.234(j) using manufacturer's manual for the 
specific meter used to measure velocity.
    (ii) Calculate natural gas volumetric fugitive emissions at 
standard conditions using calculations in paragraph (e) of this 
section.
    (iii) Calculate both CH4 and CO2 volumetric 
and mass fugitive emissions from volumetric natural gas fugitive 
emissions using calculations in paragraphs (f) and (g) of this section.
    (e) Calculate natural gas volumetric fugitive emissions at standard 
conditions by converting ambient temperature and pressure of natural 
gas fugitive emissions to standard temperature and pressure natural 
using Equation W-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.100

Where:

Es,n = Natural gas volumetric fugitive emissions at 
standard temperature and pressure (STP) conditions.
Ea,n = Natural gas volumetric fugitive emissions at 
actual conditions.
Ts = Temperature at standard conditions ([deg]F).
Ta = Temperature at actual emission conditions ([deg]F).
Ps = Absolute pressure at standard conditions (inches of 
Hg).
Pa = Absolute pressure at ambient conditions (inches of 
Hg).

    (f) Calculate GHG volumetric fugitive emissions at standard 
conditions as specified in paragraphs (f)(1) and (2) of this section.
    (1) Estimate CH4 and CO2 fugitive emissions 
from natural gas fugitive emissions using Equation W-10 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.101

Where:

Es,i = GHG i (either CH4 or CO2) 
volumetric fugitive emissions at standard conditions.
Es,n = Natural gas volumetric fugitive emissions at 
standard conditions.
Mi = Mole percent of GHG i in the natural gas.

    (2) For Equation W-10 of this section, the mole percent, 
Mi, shall be the annual average mole percent for each 
facility, as specified in paragraphs (f)(2)(i) through (vi) of this 
section.
    (i) GHG mole percent in produced natural gas for offshore petroleum 
and natural gas production facilities.
    (ii) GHG mole percent in feed natural gas for all fugitive 
emissions sources upstream of the de-methanizer and GHG mole percent in 
facility specific residue gas to transmission pipeline systems for all 
fugitive emissions sources downstream of the de-methanizer for onshore 
natural gas processing facilities.
    (iii) GHG mole percent in transmission pipeline natural gas that 
passes through the facility for onshore natural gas transmission 
compression facilities.
    (iv) GHG mole percent in natural gas stored in underground natural 
gas storage facilities.
    (v) GHG mole percent in natural gas stored in LNG storage 
facilities.
    (vi) GHG mole percent in natural gas stored in LNG import and 
export facilities.
    (g) Calculate GHG mass fugitive emissions at standard conditions by 
converting the GHG volumetric fugitive emissions into mass fugitive 
emissions using Equation W-11 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.102

Where:

Masss,i = GHG i (either CH4 or CO2) 
mass fugitive emissions at standard conditions.
Es,i = GHG i (either CH4 or CO2) 
volumetric fugitive emissions at standard conditions.
[rho]i = Density of GHG i;1.87 kg/m\3\ for CO2 
and 0.68 kg/m\3\ for CH4.


Sec.  98.234  Monitoring and QA/QC requirements.

    (a) You must use the methods described in paragraphs (d) or (e) in 
this section to conduct annual leak detection of fugitive emissions 
from all sources listed in Sec.  98.232(a), whether in operation or on 
standby. If fugitive emissions are detected for sources listed in 
paragraph (b) of this section, you must use the measurement methods 
described in paragraph(c) of this section to measure emissions from 
each source with fugitive emissions.
    (b) You shall use detection instruments described in paragraphs (d) 
and (e) of this section to monitor the following fugitive emissions:
    (1) Centrifugal compressor dry seals fugitive emissions.
    (2) Centrifugal compressor wet seals fugitive emissions.
    (3) Compressor fugitive emissions.
    (4) LNG import and export facility fugitive emissions.
    (5) LNG storage station fugitive emissions.
    (6) Non-pneumatic pumps fugitive emissions.
    (7) Open-ended lines (OELs) fugitive emissions.
    (8) Pump seals fugitive emissions.
    (9) Offshore platform pipeline fugitive emissions.
    (10) Platform fugitive emissions.
    (11) Processing facility fugitive emissions.
    (12) Reciprocating compressor rod packing fugitive emissions.
    (13) Storage station fugitive emissions.
    (14) Transmission station fugitive emissions.
    (15) Storage wellhead fugitive emissions.
    (c) You shall use a high volume sampler, described in paragraph (f) 
of this section, to measure fugitive emissions from the sources 
detected in Sec.  98.234(b), except as provided in paragraphs (c)(1) 
and (2) of this section:
    (1) Where high volume samplers cannot capture all of the fugitive 
emissions, you shall use calibrated bags described in paragraph (g) of 
this section or meters described in paragraph (h) of this section to 
measure the following fugitive emissions:
    (i) Open-ended lines (OELs).
    (ii) Centrifugal compressor dry seals fugitive emissions.
    (iii) Centrifugal compressor wet seals fugitive emissions.
    (iv) Compressor fugitive emissions.
    (v) Pump seals fugitive emissions.
    (vi) Reciprocating compressor rod packing fugitive emissions.
    (vii) Flare stacks and storage tanks, except that you shall use 
meters in

[[Page 16679]]

combination with engineering estimation methods to calculate fugitive 
emissions.
    (2) Use hot wire anemometer to calculate fugitive emissions from 
centrifugal compressor wet seal degassing vents and flares where it is 
unsafe or too high a flow rate to use calibrated bags.
    (d) Infrared Remote Fugitive Emissions Detection.
    (1) Use infrared fugitive emissions detection instruments that can 
identify specific equipment sources as emitting. Such instruments must 
have the capability to trace a fugitive emission back to the specific 
point where it escapes the process and enters the atmosphere.
    (2) If you are using instruments that visually display an image of 
fugitive emissions, you shall inspect the emissions source from 
multiple angles or locations until the entire source has been viewed 
without visual obstructions at least once annually.
    (3) If you are using any other infrared detection instruments, such 
as those based on infrared laser reflection, you shall monitor all 
potential emission points at least once annually.
    (4) Perform fugitive emissions detection under favorable 
conditions, including but not limited to during daylight hours, in the 
absence of precipitation, in the absence of high wind, and, for active 
laser devices, in front of appropriate reflective backgrounds within 
the detection range of the instrument.
    (5) Use fugitive emissions detection and measurement instrument 
manuals to determine optimal operating conditions.
    (e) Use organic vapor analyzers (OVAs) and toxic vapor analyzers 
(TVAs) for all fugitive emissions detection that are safely accessible 
at close-range.
    (1) Check each potential emissions source, all joints, connections, 
and other potential paths to the atmosphere for emissions.
    (2) Evaluate the lag time between the instrument sensing and 
alerting caused by the residence time of a sample in the probe shall be 
evaluated; upon alert, the instrument shall be slowly retraced over the 
source to pinpoint the location of fugitive emissions.
    (3) Use Method 21 of 40 CFR part 60, appendix A-7, Determination of 
Volatile Organic Compound Leaks to calibrate OVAs and TVAs.
    (f) Use a high volume sampler to measure only cold and steady 
emissions within the capacity of the instrument.
    (1) A trained technician shall conduct measurements. The technician 
shall be conversant with all operating procedures and measurement 
methodologies relevant to using a high volume sampler, including, but 
not limited to, positioning the instrument for complete capture of the 
fugitive emissions without creating backpressure on the source.
    (2) If the high volume sampler, along with all attachments 
available from the manufacturer, is not able to capture all the 
emissions from the source then you shall use anti-static wraps or other 
aids to capture all emissions without violating operating requirements 
as provided in the instrument manufacturer's manual.
    (3) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec.  98.233(f) and (g).
    (4) Calibrate the instrument at 2.5 percent methane with 97.5 
percent air and 100 percent CH4 by using calibrated gas 
samples and by following manufacturer's instructions for calibration.
    (g) Use calibrated bags (also known as vent bags) only where the 
emissions are at near-atmospheric pressures and the entire fugitive 
emissions volume can be captured for measurement.
    (1) Hold the bag in place enclosing the emissions source to capture 
the entire emissions and record the time required for completely 
filling the bag.
    (2) Perform three measurements of the time required to fill the 
bag; report the emissions as the average of the three readings.
    (3) Estimate natural gas volumetric emissions at standard 
conditions using calculations in Sec.  98.233(e).
    (4) Estimate CH4 and CO2 volumetric and mass 
emissions from volumetric natural gas emissions using the calculations 
in Sec.  98.233(f) and (g).
    (5) Obtain consistent results when measuring the time it takes to 
fill the bag with fugitive emissions.
    (h) Channel all emissions from a single source directly through the 
meter when using metering (e.g., rotameters, turbine meters, and 
others).
    (1) Use an appropriately sized meter so that the flow does not 
exceed the full range of the meter in the course of measurement and 
conversely has sufficient momentum for the meter to register 
continuously in the course of measurement.
    (2) Estimate natural gas volumetric fugitive emissions at standard 
conditions using calculations in Sec.  98.233(f).
    (3) Estimate CH4 and CO2 volumetric and mass 
fugitive emissions from volumetric natural gas fugitive emissions using 
calculations in Sec.  98.233(f) and (g).
    (4) Calibrate the meter using either one of the two methods 
provided as follows:
    (i) Develop calibration curves by following the manufacturer's 
instruction.
    (ii) Weigh the amount of gas that flows through the meter into or 
out of a container during the calibration procedure using a master 
weigh scale (approved by National Institute of Standards and Technology 
(NIST) or calibrated using standards traceable by NIST). Determine 
correction factors for the flow meter according to the manufacturer's 
instructions. Record deviations from the correct reading at several 
flow rates. Plot the data points, comparing the flowmeter output to the 
actual flowrate as determined by the master weigh scale and use the 
difference as a correction factor.
    (i) Where engineering estimation as described in Sec.  98.233 is 
not possible, use direct measurement methods as follows:
    (1) If manufacturer data on pneumatic pump natural gas emission are 
not available, conduct a one-time measurement to determine natural gas 
emission per unit volume of liquid pumped using a calibrated bag for 
each pneumatic pump, when it is pumping liquids. Determine the volume 
of liquid being pumped from the manufacturer's manual to provide the 
amount of natural gas emitted per unit of liquid pumped.
    (i) Record natural gas conditions (temperature and pressure) and 
convert natural gas emission per unit volume of liquid pumped at actual 
conditions into natural gas emission per pumping cycle at standard 
conditions using Equation W-9 of Sec.  98.233.
    (ii) Calculate annual fugitive emissions from the pump using 
Equation W-1, by replacing the manufacturer's data on emission 
(variable Fs) in the Equation with the standard conditions 
natural gas emission calculated in Sec.  98.234(i)(1)(i).
    (iii) Estimate CH4 and CO2 volumetric and 
mass fugitive emissions from volumetric natural gas fugitive emissions 
using calculations in Sec.  98.233(f) and (g).
    (2) If manufacturer data on pneumatic manual valve actuator device 
natural gas emission are not available, conduct a one-time measurement 
to determine natural gas emission per actuation using a calibrated bag 
for each pneumatic device per actuation.
    (i) Record natural gas conditions (temperature and pressure) and 
convert natural gas emission at actual conditions into natural gas 
emission per

[[Page 16680]]

actuation at standard conditions using Equation W-9 of this subpart.
    (ii) Calculate annual fugitive emissions from the pneumatic device 
using Equation W-2 of this section, by replacing the manufacturer's 
data on emission (variable As) in the Equation with the 
standard conditions natural gas emission calculated in Sec.  
98.234(i)(2)(i).
    (iii) Estimate CH4 and CO2 volumetric and 
mass emissions from volumetric natural gas fugitive emissions using the 
calculations in Sec.  98.233(f) and (g).
    (3) If manufacturer data on natural gas driven pneumatic valve 
bleed rate is not available, conduct a one-time measurement to 
determine natural gas bleed rate using a high volume sampler or 
calibrated bag or meter for each pneumatic device.
    (i) Record natural gas conditions (temperature and pressure) to 
convert natural gas bleed rate at actual conditions into natural gas 
bleed rate at standard conditions using Equation W-9 of this subpart.
    (ii) Calculate annual fugitive emissions from the pneumatic device 
using Equation W-3 of this subpart, by replacing the manufacturer's 
data on bleed rate (variable B) in the equation with the standard 
conditions bleed rate calculated in Sec.  98.234(i)(3)(i).
    (iii) Estimate CH4 and CO2 volumetric and 
mass fugitive emissions from volumetric natural gas fugitive emissions 
using calculations in Sec.  98.233(f) and (g).
    (j) Parameters for calculating emissions from flare stacks, 
compressor wet seal degassing vents, and storage tanks.
    (1) Estimate fugitive emissions from flare stacks and compressor 
wet seal degassing vents as follows:
    (i) Insert flow velocity measuring device (such as hot wire 
anemometer or pitot tube) directly upstream of the flare stack or 
compressor wet seal degassing vent to determine the velocity of gas 
sent to flare or vent.
    (ii) Record actual temperature and pressure conditions of the gas 
sent to flare or vent.
    (iii) Sample representative gas to the flare stack or compressor 
wet seal degassing vent every quarter to evaluate the composition of 
GHGs present in the stream. Record the average of the most recent four 
gas composition analyses, which shall be conducted using ASTM D1945-03 
(incorporated by reference, see Sec.  98.7).
    (2) Estimate fugitive emissions from storage tanks as follows:
    (i) Measure the hydrocarbon vapor emissions from storage tanks 
using a flow meter described in paragraph (h) of this section for a 
test period that is representative of the normal operating conditions 
of the storage tank throughout the year and which includes a complete 
cycle of accumulation of hydrocarbon liquids and pumping out of 
hydrocarbon liquids from the storage tank.
    (ii) Record the net (related to working loss) and gross (related to 
flashing loss) input of the storage tank during the test period.
    (iii) Record temperature and pressure of hydrocarbon vapors emitted 
during the test period.
    (iv) Collect a sample of hydrocarbon vapors for composition 
analysis
    (k) Component fugitive emissions sources that are not safely 
accessible within the operator's arm's reach from the ground or 
stationary platforms are excluded from the requirements of this 
section.
    (1) Determine annual emissions assuming that the fugitive emissions 
were continuous from the beginning of the reporting period or last 
recorded zero detection in the current reporting period and continuing 
until the fugitive emissions is repaired.


Sec.  98.235  Procedures for estimating missing data.

    There are no missing data procedures for this source category. A 
complete record of all measured parameters used in the GHG emissions 
calculations is required. If data are lost or an error occurs during 
annual emissions measurements, you must repeat the measurement activity 
for those sources until a valid measurement is obtained.


Sec.  98.236  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must report emissions data as specified in this section.
    (a) Annual emissions reported separately for each of the operations 
listed in paragraphs (a)(1) through (6) of this section. Within each 
operation, emissions from each source type must be reported in the 
aggregate. For example, an underground natural gas storage facility 
with multiple reciprocating compressors must report emissions from all 
reciprocating compressors as an aggregate number.
    (1) Offshore petroleum and natural gas production facilities.
    (2) Onshore natural gas processing facilities.
    (3) Onshore natural gas transmission compression facilities.
    (4) Underground natural gas storage facilities.
    (5) Liquefied natural gas storage facilities.
    (6) Liquefied natural gas import and export facilities.
    (b) Emissions reported separately for standby equipment.
    (c) Emissions calculated for these sources shall assume no 
CO2 capture and transfer off site.
    (d) Activity data for each aggregated source type level for which 
emissions are being reported.
    (e) Engineering estimate of total component count.
    (f) Total number of compressors and average operating hours per 
year for compressors for each operation listed in paragraphs (a)(1) 
through (6) of this section.
    (g) Minimum, maximum and average throughput for each operation 
listed in paragraphs (a)(1) through (6) of this section.
    (h) Specification of the type of any control device used, including 
flares, for any source type listed in 98.232(a).
    (i) For offshore petroleum and natural gas production facilities, 
the number of connected wells, and whether they are producing oil, gas, 
or both.
    (j) Detection and measurement instruments used.


Sec.  98.237  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Dates on which measurements were conducted.
    (b) Results of all emissions detected, whether quantification was 
made pursuant to Sec.  98.234(k) and measurements.
    (c) Calibration reports for detection and measurement instruments 
used.
    (d) Inputs and outputs of calculations or emissions computer model 
runs used for engineering estimation of emissions.


Sec.  98.238  Definitions.

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

Subpart X--Petrochemical Production


Sec.  98.240  Definition of the source category.

    (a) The petrochemical production source category consists of any 
facility that produces acrylonitrile, carbon black, ethylene, ethylene 
dichloride, ethylene oxide, or methanol as an intended product, except 
as specified in paragraph (b) of this section.
    (b) An integrated process is part of the petrochemical source 
category only if the petrochemical is the primary product of the 
integrated process.


Sec.  98.241  Reporting threshold.

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

[[Page 16681]]

Sec.  98.242  GHGs to report.

    You must report the information in paragraphs (a) through (d) of 
this section:
    (a) CO2 emissions from each petrochemical process unit, 
following the methods and procedures in Sec. Sec.  98.243 through 
98.248. You must include the volume of any CO2 captured from 
process off-gas in the reported CO2 emissions.
    (b) CO2, CH4, and N2O emissions 
from stationary combustion units. For each stationary combustion unit, 
you must follow the calculation methods and other requirements 
specified in subpart C of this part. If you determine CO2 
process-based emissions in accordance with Sec.  98.243(a)(2), then for 
each stationary combustion unit that burns off-gas from a petrochemical 
process, estimate CO2, CH4, and N2O 
emissions for the combustion of supplemental fuel in accordance with 
subpart C of this part. In addition, estimate CH4 and 
N2O emissions from combusting off-gas according to the 
requirements in Sec.  98.33(c)(2) and (3) using the emission factors 
for Refinery Gas in Table C-3 in subpart C of this part.
    (c) CO2 captured. You must follow the calculation 
procedures, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements specified in 
subpart PP of this part.
    (d) CH4 emissions for each on-site wastewater treatment 
system. For wastewater treatment systems, you must follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements 
specified in subpart II of this part.


Sec.  98.243  Calculating GHG emissions.

    (a) Determine process-based GHG emissions in accordance with the 
procedures specified in either paragraph (a)(1) or (2) of this section, 
and if applicable, comply with the procedures in paragraph (b) of this 
section.
    (1) Continuous emission monitoring system (CEMS).
    (i) If you operate and maintain a CEMS that measures total 
CO2 emissions from process vents and combustion sources 
according to subpart C of this part, you must estimate total 
CO2 emissions according to the Tier 4 Calculation 
Methodology requirements in Sec.  98.33(a)(4). For each flare, estimate 
CO2, CH4, and N2O emissions using the 
methodology specified in Sec.  98.253(b)(1) and (2).
    (ii) If you elect to install CEMS to comply with this subpart, you 
must route all process vent emissions to one or more stacks and use a 
CEMS on each stack (except flare stacks) to measure CO2 
emissions. You must estimate total CO2 emissions according 
to the Tier 4 Calculation Methodology requirements in Sec.  
98.33(a)(4). For each flare, estimate CO2, CH4, 
and N2O emissions using the methodology specified in Sec.  
98.253(b)(1) and (2) of subpart Y of this part.
    (2) Mass balance for each petrochemical process unit. Estimate the 
emissions of CO2 from each process unit, for each calendar 
week as described in paragraphs (a)(2)(i) through (v) of this section.
    (i) Measure the volume of each gaseous and liquid feedstock and 
product continuously with a flow meter by following the procedures 
outlined in Sec.  98.244(b)(2). Fuels used for combustion purposes are 
not considered to be feedstocks.
    (ii) Measure the mass rate of each solid feedstock and product by 
following the procedures outlined in Sec.  98.244(b)(1) and record the 
total for each calendar week.
    (iii) Collect a sample of each feedstock and product at least once 
per week and determine the carbon content of each sample according to 
the procedures in Sec.  98.244(b)(3).
    (iv) If you determine that the weekly average concentration of a 
specific compound in a feedstock or product is always 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 
(a)(2)(iii) 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 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 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 weekly 
concentration falls below 99.5 percent, you are no longer permitted to 
use this alternative method.
    (v) Estimate CO2 mass emissions for each petrochemical 
process unit using Equations X-1 through X-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.103

Where:

Cg = Annual net contribution to estimated emissions from carbon (C) 
in gaseous feedstocks (kilograms/year, kg/yr).
(Fgf)i,n = Volume of gaseous feedstock i 
introduced in week ``n'' (standard cubic feet, scf).
(CCgf)i,n = Average carbon content of the 
gaseous feedstock i for week ``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 week ``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 week ``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.
[GRAPHIC] [TIFF OMITTED] TP10AP09.104


[[Page 16682]]


Where:

Cl = Annual net contribution to estimated emissions from 
carbon in liquid feedstocks (kg/yr).
(Flf)i,n = Volume of liquid feedstock i 
introduced in week ``n'' (gallons).
(CClf)i,n = Average carbon content of liquid 
feedstock i for week ``n'' (kg C per gallon of feedstock).
(Plp)i,n = Volume of liquid product i produced 
in week ``n'' (gallons).
(CClp)i,n = Average carbon content of liquid 
product i, including organic liquid wastes, for week ``n'' (kg C per 
gallon of product).
[GRAPHIC] [TIFF OMITTED] TP10AP09.105

Where:

Cs = Annual net contribution to estimated emissions from 
carbon in solid feedstocks (kg/yr).
(Fsf)i,n = Mass of solid feedstock i 
introduced in week ``n'' (kg).
(CCsf)i,n = Average carbon content of solid 
feedstock i for week ``n'' (kg C per kg of feedstock).
(Psp)i,n = Mass of solid product i produced in 
week ``n'' (kg).
(CCsp)i,n = Average carbon content of solid 
product i in week ``n'' (kg C per kg of product).
[GRAPHIC] [TIFF OMITTED] TP10AP09.106

Where:

CO2 = Annual CO2 mass emissions from process 
operations and fuel 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).

    (b) If you have an integrated process unit that is determined to be 
part of the petrochemical production source category, comply with 
paragraph (a) of this section by including terms for additional carbon-
containing products in Equations X-1 through X-3 of this section as 
necessary.


Sec.  98.244  Monitoring and QA/QC requirements.

    (a) Each facility that uses CEMS to estimate emissions from process 
vents must comply with the procedures specified in Sec.  98.34(e).
    (b) Facilities that use the mass balance methodology in Sec.  
98.243(a)(2) must comply with paragraphs (b)(1) through (3) of this 
section.
    (1) Measure the mass rate of each solid feedstock and product 
(e.g., using belt scales or weighing at the loadout points of your 
process unit) and record the total for each calendar week. You must 
document procedures used to ensure the accuracy of the measurements of 
the feedstock and product flows including, but not limited to, 
calibration of all weighing equipment and other measurement devices. 
The estimated accuracy of measurements made with these devices shall be 
recorded, and the technical basis for these estimates shall be 
recorded.
    (2) Measure the volume of each gaseous and liquid feedstock and 
product for each process unit continuously with a flow meter. All 
feedstock and product flow meters must be calibrated prior to the first 
reporting year, using any applicable method incorporated by reference 
in Sec.  98.7(b)(1) through (6), (c)(1), (f)(3)(i) through (ii), or 
(g)(1). You should use the flow meter accuracy test procedures in 
appendix D to part 75 of this chapter. Alternatively, calibration 
procedures specified by the equipment manufacturer may be used. Flow 
meters and gas composition monitors shall be recalibrated annually or 
at the frequency specified by another applicable rule or the 
manufacturer, whichever is more frequent.
    (3) Collect a sample of each feedstock and product for each process 
unit at least once per week and determine the carbon content of each 
sample using an applicable ASTM method incorporated by reference in 
Sec.  98.7(a)(15), (23), or (24). Alternatively, you may determine the 
composition of the sample using a gas chromatograph and then calculate 
the carbon content based on the composition and molecular weights for 
compounds in the sample. Determine the composition of gas and liquid 
samples using either: ASTM D1945-03 incorporated by reference in Sec.  
98.7 (a)(8) of subpart A of this part; ASTM D6060-96(2001) incorporated 
by reference in Sec.  98.7; ASTM D2502-88(2004)e1 incorporated by 
reference in Sec.  98.7; method UOP539-97 incorporated by reference in 
Sec.  98.7; or EPA Method 18, 40 CFR part 60, appendix A-6; or 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. Calibrate 
the gas chromatograph using the procedures in the method prior to each 
use. 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 weekly period. For 
carbon black products, samples shall be taken of each grade or type of 
product produced during the weekly period. Samples of coal feedstock or 
carbon black product for carbon content determinations may be either 
grab samples collected and analyzed weekly or a composite of samples 
collected more frequently and analyzed weekly.


Sec.  98.245  Procedures for estimating missing data.

    (a) 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.
    (b) For missing CO2 concentration, stack gas flow rate, 
and moisture content for CEMS on any process vent stack, follow the 
applicable procedures specified in Sec.  98.35.


Sec.  98.246  Data reporting requirements.

    (a) Facilities using the mass balance methodology in Sec.  
98.243(a)(2) must report the information specified in paragraphs (a)(1) 
through (9) of this section for each type of petrochemical produced, 
reported by process unit.
    (1) Identification of the petrochemical process.
    (2) Annual CO2e emissions calculated using Equation X-4 
of this subpart.
    (3) Methods used to determine feedstock and product flows and 
carbon contents.

[[Page 16683]]

    (4) Number of actual and substitute data points for each measured 
parameter.
    (5) Annual quantity of each feedstock consumed.
    (6) Annual quantity of each product and by-product produced, 
including all products from integrated processes that are part of the 
petrochemical production source category.
    (7) Each carbon content measurement for each feedstock, product, 
and by-product.
    (8) All calculations, measurements, equipment calibrations, 
certifications, and other information used to assess the uncertainty in 
emission estimates and the underlying volumetric flow rates, mass flow 
rates, and carbon contents of feedstocks and products.
    (9) Identification of any combustion units that burned process off-
gas.
    (b) Each facility that uses CEMS to determine emissions from 
process vents must report the verification data specified in Sec.  
98.36(d)(1)(iv).


Sec.  98.247  Records that must be retained.

    In addition to the recordkeeping requirements in Sec.  98.3(g), you 
must retain the following records:
    (a) The CEMS recordkeeping requirements in Sec.  98.37, if you 
operate a CEMS on process vents.
    (b) Results of feedstock or product composition determinations 
conducted in accordance with Sec.  98.243(a)(2)(iv).
    (c) 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(a)(2)(iv) for determining 
carbon content of feedstock or product.


Sec.  98.248  Definitions.

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

Subpart Y--Petroleum Refineries


Sec.  98.250  Definition of source category.

    (a) A petroleum refinery is any facility engaged in producing 
gasoline, kerosene, distillate fuel oils, residual fuel oils, 
lubricants, asphalt (bitumen) or other products through distillation of 
petroleum or through redistillation, cracking, or reforming of 
unfinished petroleum derivatives.
    (b) 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; land disposal 
units; sulfur recovery plants. hydrogen plants (non-merchant plants 
only).


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 (2).


Sec.  98.252  GHGs to report.

    You must report:
    (a) CO2, CH4, and N2O combustion 
emissions from stationary combustion sources and from each flare. For 
each stationary combustion unit, you must follow the calculation 
procedures, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements specified in 
subpart C of this part.
    (b) CO2, CH4, and N2O coke burn-
off emissions from each catalytic cracking unit, fluid coking unit, and 
catalytic reforming unit.
    (c) CO2 emissions from sour gas sent off site for sulfur 
recovery operations. You must follow the calculation procedures from 
Sec.  98.253(f) of this subpart and the monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of this subpart of this part.
    (d) CO2 process emissions from each on-site sulfur 
recovery plant.
    (e) CO2, CH4, and N2O emissions 
from each coke calcining unit.
    (f) CO2 emissions from asphalt blowing operations 
controlled using a combustion device and CH4 emissions from 
asphalt blowing operations not controlled by a combustion device.
    (g) CH4 fugitive emissions from equipment leaks, storage 
tanks, loading operations, delayed coking units, and uncontrolled 
blowdown systems.
    (h) CO2, CH4, and N2O emissions 
from each process vent not specifically included in paragraphs (a) 
through (g) of this section.
    (i) CH4 emissions from on-site landfills. You must 
follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of subpart HH of this part.
    (j) CO2 and CH4 emissions from on-site 
wastewater treatment. You must follow the calculation procedures, 
monitoring and QA/QC methods, missing data procedures, reporting 
requirements, and recordkeeping requirements of subpart II of this 
part.
    (k) CO2 and CH4 emissions from non-merchant 
hydrogen production. You must follow the calculation procedures, 
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) For stationary combustion sources, if you operate and maintain 
a CEMS that measures total CO2 emissions according to 
subpart C of this part, you must estimate total CO2 
emissions according to the requirements in Sec.  98.33(a)(4).
    (b) For flares, calculate GHG emissions according to the 
requirements in paragraphs (b)(1) and (2) of this section for 
combustion systems fired with refinery fuel gas.
    (1) Calculate the CO2 emissions according to the applicable 
requirements in paragraphs (b)(1)(i) through (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, to calculate the flare gas flow. If you do not have a 
continuous flow monitor on the flare, you must use engineering 
calculations, company records, or similar estimates of volumetric flare 
gas flow.
    (ii) Carbon content. If you have a continuous higher heating value 
monitor or carbon content monitor on the flare or if you monitor these 
parameters at least daily, you must use the measured heat value or 
carbon content value in calculating the CO2 emissions from the flare. 
If you monitor carbon content, calculate the CO2 emissions from the 
flare using the applicable equation in Sec.  98.33(a). If you monitor 
heat content, calculate the CO2 emissions from the flare using the 
applicable equation in Sec.  98.33(a) and the default emission factor 
of 60 kilograms CO2/MMBtu on a higher heating value basis.
    (iii) Startup, shutdown, malfunction. If you do not measure the 
higher heating value or carbon content of the flare gas at least daily, 
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 (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.

[[Page 16684]]

    (B) For periods of normal operation, use the average heating value 
measured for the refinery fuel gas for the heating value of the flare 
gas.
    (C) Calculate the CO2 emissions using Equation Y-1 of this section.
    [GRAPHIC] [TIFF OMITTED] TP10AP09.107
    
Where:

CO2 = Annual CO2 emissions for a specific fuel 
type (metric tons/year).
FlareN = 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 refinery fuel or flare gas from 
company records (British thermal units per scf, Btu/scf = MMBtu/
MMscf).
EmF = Default CO2 emission factor of 60 kilograms 
CO2/MMBtu (HHV basis).
0.001 = Unit conversion factor (metric tons per kilogram, mt/kg).
n = Number of start-up, shutdown, and malfunction events during the 
reporting year.
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 = Volume of flare gas combusted during a start-
up, shutdown, or malfunctions from engineering calculations, (MMscf/
event).
(CC)p = Average carbon content of the gaseous fuel, from 
the fuel analysis results or engineering calculations for the event 
(gram C per scf = metric tons C per MMscf).

    (2) Calculate CH4 and N2O emissions according to the requirements 
in Sec.  98.33(c)(2) using the emission factors for Refinery Gas in 
Table C-3 in subpart C of this part.
    (c) For catalytic cracking units and traditional fluid coking 
units, calculate the GHG emissions using the applicable methods 
described in paragraphs (c)(1) through (4) of this section.
    (1) For catalytic cracking units and fluid coking units that use a 
continuous CO2 CEMS for the final exhaust stack, calculate 
the combined CO2 emissions from each catalytic cracking or 
fluid coking unit and CO boiler (if present) using the CEMS according 
to the Tier 4 Calculation Methodology requirements in Sec.  
98.33(a)(4). For units that do not have a CO boiler or other post-
combustion device, Equation Y-3 of this section may be used as an 
alternative to a continuous flow monitor, if one is not already 
present.
    (2) For catalytic cracking units and fluid coking units that do not 
use a continuous CO2 CEMS for the final exhaust stack, you 
must continuously monitor the O2, CO, and CO2 
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 (iii) of this 
section:
    (i) Calculate the CO2 emissions from each catalytic 
cracking unit and fluid coking unit using Equation Y-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.108

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 no auxiliary 
fuel is burned and a continuous CO monitor is not required, 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-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.109

Where:

Qr = Volumetric flow rate of exhaust gas from the fluid 
catalytic cracking unit regenerator or fluid coking unit burner 
prior to the combustion of other fossil fuels (dscfh).
Qa = Volumetric flow rate of air to the fluid catalytic 
cracking unit regenerator or fluid coking unit burner, as determined 
from control room instrumentation (dscfh).
Qoxy = Volumetric flow rate of oxygen enriched air to the 
fluid catalytic cracking unit regenerator or fluid coking unit 
burner as determined from control room instrumentation (dscfh).
%O2 = Hourly average percent oxygen concentration in 
exhaust gas stream from the fluid catalytic cracking unit 
regenerator or fluid coking unit burner (percent by volume--dry 
basis).
%Ooxy = O2 concentration in oxygen enriched 
gas stream inlet to the fluid catalytic cracking unit regenerator or 
fluid coking unit burner based on oxygen purity specifications of 
the oxygen supply used for enrichment (percent by volume--dry 
basis).
%CO2 = Hourly average percent CO2 
concentration in the exhaust gas stream from the fluid catalytic 
cracking unit regenerator or fluid coking unit burner (percent by 
volume--dry basis).
%CO = Hourly average percent CO concentration in the exhaust gas 
stream

[[Page 16685]]

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, assume %CO to 
be zero.

    (iii) If a CO boiler or other post-combustion device is used, 
calculate the GHG emissions from the fuel fired to the CO boiler or 
post-combustion device using the methods for stationary combustion 
sources in paragraph (a) of this section and report this separately for 
the combustion unit.
    (3) Calculate CH4 emissions using Equation Y-4 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.110

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 (kg 
CO2/MMBtu).
EmF2 = Default CH4 emission factor for 
petroleum coke from Table C-3 of subpart C of this part (kg 
CH4/MMBtu).

    (4) Calculate N2O emissions using Equation Y-5 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.111

Where:

N2O = Annual nitrous oxide emissions from coke burn-off 
(mt N2O/year).
EmF1 = Default CO2 emission factor for 
petroleum coke from Table C-1 of subpart C of this part (kg 
CO2/MMBtu).
EmF2 = Default N2O emission factor for 
petroleum coke from Table C-3 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 for 
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 either the methods described in paragraphs (e)(1) or 
(2) of this section and calculate the CH4 and N2O 
emissions using the Equations Y-4 and Y-5 of this section, 
respectively.
    (1) Calculate CO2 emissions from the catalytic reforming 
unit catalyst regenerator using the methods in paragraphs (c)(1) or (2) 
of this section, or
    (2) Calculate CO2 emissions from the catalytic reforming 
unit catalyst regenerator using Equation Y-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.112

Where:

CO2 = Annual CO2 emissions (metric tons/year).
CBQ = Coke burn-off quantity per regeneration cycle (kg 
coke/cycle).
CF = Site-specific fraction carbon content of produced coke, use 
0.94 if site-specific fraction carbon content is unavailable (kg C 
per kg coke).
44 = Molecular weight of CO2 (kg/kg-mole).
12 = Atomic weight of C (kg/kg-mole).
n = Number of regeneration cycles in the calendar year.
0.001 = Conversion factor (mt/kg).

    (f) For on-site sulfur recovery plants, calculate CO2 
process emissions from sulfur recovery plants according to the 
requirements in paragraphs (f)(1) through (4) of this section. Except 
as provided in paragraph (f)(4) 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. For the purposes of this subpart, the sour gas 
stream for which monitoring is required according to paragraphs (f)(1) 
through (3) of this section is not considered a fuel.
    (1) 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.
    (2) Carbon content. If you have a continuous compositional or 
carbon content monitor on the sour gas feed to the sulfur recovery 
plant or if you monitor these parameters on a routine basis, you must 
use the measured carbon content value. Alternatively, you may develop a 
site-specific carbon content factor or use the default factor of 0.20.
    (3) Calculate the CO2 emissions from each sulfur 
recovery plant using Equation Y-7 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.113

Where:

CO2 = Annual CO2 emissions (metric tons/year).
FSG = Volumetric flow rate of sour gas feed 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.

    (4) As an alternative to the monitoring methods in paragraphs 
(f)(1) through (3) of this section, you may use a continuous flow 
monitor and CO2 CEMS in the final exhaust stack from the 
sulfur recovery plant according to the requirements in Sec.  
98.33(a)(4) to calculate the combined process and combustion emissions 
for the sulfur recovery plant. 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. You must report 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.

[[Page 16686]]

    (g) For coke calcining units, calculate GHG emissions according to 
the applicable provisions in paragraphs (g)(1) through (3) of this 
section.
    (1) For coke calcining units that use a continuous CO2 
CEMS for the final exhaust stack, calculate the combined CO2 
emissions from the coke calcining process and any auxiliary fuel 
combusted using the CEMS according to the requirements in Sec.  
98.33(a)(4).
    (2) For coke calcining units that do not use a continuous 
CO2 CEMS for the final exhaust stack, calculate 
CO2 emissions from the coke calcining unit according to the 
requirements in paragraphs (g)(2)(i) and (ii) of this section.
    (i) Calculate the CO2 emissions for any auxiliary fuel 
fired to the calcining unit using the applicable methods in subpart C 
of this part.
    (ii) Calculate the CO2 emissions from the coke calcining 
process using Equation Y-8 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.114

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 (2), as 
applicable, and calculate CH4 using Equation Y-4 of this 
section and N2O emissions using Equation Y-5 of this 
section.
    (h) For asphalt blowing operations, calculate GHG emissions 
according to the applicable provisions in paragraphs (h)(1) and (2) of 
this section.
    (1) For uncontrolled asphalt blowing operations, calculate 
CH4 emissions using Equation Y-9 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.115

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 = Emission factor for asphalt blowing from facility-
specific test data (scf CH4/MMbbl); use 2,555,000 scf 
CH4/MMbbl if facility-specific test data are unavailable.
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).

    (2) For controlled asphalt blowing operations, calculate 
CO2 emissions using Equation Y-10 of this section, provided 
these emissions are not already included in the flare emissions 
calculated in paragraph (b) of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.116

Where:

CO2 = Annual CO2 emissions (metric ton/year).
QAB = Quantity of asphalt blown (MMbbl/year).
EFAB = Default emission factor (2,555,000 scf 
CH4/MM bbl).
44 = Molecular weight of CO2 (kg/kg-mole).
MVC = Molar volume conversion factor (849.5 scf/kg-mole).
1 = Assumed conversion efficiency (kg-mole CO2/kg-mole 
CH4).
0.001 = Conversion factor (metric tons/kg).

    (i) For delayed coking units, calculate the CH4 
emissions from the depressurization of the coking unit vessel to 
atmosphere using the process vent method in paragraph (j) of this 
section and calculate the CH4 emissions from the subsequent 
opening of the vessel for coke cutting operations using Equation Y-11 
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.117

Where:

CH4 = Annual methane emissions from the delayed coking 
unit vessel opening (metric ton/year).
N = Total number of vessel openings for all delayed coking unit 
vessels of the same dimensions during the year.
H = Height of coking unit vessel (feet).
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); default value is 0.03.
0.001 = Conversion factor (metric ton/kg).


[[Page 16687]]


    (j) For each process vent not covered in paragraphs (a) through (i) 
of this section, calculate GHG emissions using the Equation Y-12 of 
this section. You must use Equation Y-12 for catalytic reforming unit 
depressurization and purge vents when methane is used as the purge gas.
[GRAPHIC] [TIFF OMITTED] TP10AP09.118

Where:

Ex = Annual emissions of each GHG from process vent 
(metric ton/yr).
N = Number of venting events per year.
VRn = Volumetric flow rate of process vent (scf per hour 
per event).
44 = Molecular weight of CO2 (kg/kg-mole).
MFx = Mole fraction of GHG x in process vent.
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).
VTn = Venting time, (hours per event).
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-13 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.119

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-14 of this section.
    [GRAPHIC] [TIFF OMITTED] TP10AP09.120
    
Where:

CH4 = Annual methane emissions from fugitive 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, calculate CH4 emissions using the 
applicable methods in paragraphs (m)(1) and (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 TANKS Model 
(Version 4.09D) or estimate CH4 emissions from storage tanks 
using Equation Y-15 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.121

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-16 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.122

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).

[[Page 16688]]

MVC = Molar volume conversion factor (849.5 scf/kg-mole).
0.001 = Conversion factor (metric ton/kg).

    (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, report zero methane emissions.


Sec.  98.254  Monitoring and QA/QC requirements.

    (a) All fuel flow meters, gas composition monitors, and heating 
value monitors that are used to provide data for the GHG emissions 
calculations shall be calibrated prior to the first reporting year, 
using a suitable method published by a consensus standards organization 
(e.g., ASTM, ASME, API, AGA, etc.). Alternatively, calibration 
procedures specified by the flow meter manufacturer may be used. Fuel 
flow meters, gas composition monitors, and heating value monitors shall 
be recalibrated either annually or at the minimum frequency specified 
by the manufacturer.
    (b) 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.
    (c) All CO2 CEMS and flow rate monitors used for direct 
measurement of GHG emissions must comply with the QA procedures in 
Sec.  98.34(e).


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 each missing value of the heat content, carbon content, or 
molecular weight of the fuel, 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.
    (b) For missing oil and gas flow rates, use the standard missing 
data procedures in section 2.4.2 of appendix D to part 75 of this 
chapter.
    (c) For missing CO2, CO, or O2, 
CH4, and N2O concentrations, stack gas flow rate, 
and stack gas moisture content values, use the applicable initial 
missing data procedures in Sec.  98.35 of subpart C of this part.
    (d) For hydrogen plants, use the missing data procedures in subpart 
P of this part.
    (e) For petrochemical production units, use the missing data 
procedures in subpart X of this part.
    (f) For on-site landfills, use the missing data procedures in 
subpart HH of this part.
    (g) For on-site wastewater treatment systems, use the missing data 
procedures in subpart II 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 (e) of 
this section.
    (a) For combustion sources, including flares, use the data 
reporting requirements in Sec.  98.36.
    (b) For hydrogen plants, use the data reporting requirements in 
subpart P of this part.
    (c) For petrochemical production units, use the data reporting 
requirements in subpart X of this part.
    (d) For on-site landfills, use the data reporting requirements in 
subpart HH of this part.
    (e) For on-site wastewater treatment systems, use the data 
reporting requirements in subpart II of this part.
    (f) For catalytic cracking units, traditional fluid coking units, 
catalytic reforming units, sulfur recovery plants, and coke calcining 
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, 
catalytic reforming unit, sulfur recovery plant, or coke calcining 
unit).
    (3) Maximum rated throughput of the unit, in bbl/stream day, metric 
tons sulfur produced/stream day, or metric tons coke calcined/stream 
day, as applicable.
    (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).
    (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.
    (h) For asphalt blowing operations, the owner or operator shall 
report:
    (1) The unit ID number (if applicable).
    (2) The quantity of asphalt blown.
    (3) The type of control device used to reduce methane (and other 
organic) emissions from the unit.
    (4) The calculated annual CO2, CH4, and N2O emissions for each 
unit, expressed in metric tons of each pollutant emitted.
    (i) 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 
unit, expressed in metric tons of each pollutant emitted.
    (j) For equipment leaks, storage tanks, uncontrolled blowdown 
systems, delayed coking units, and loading operations, the owner or 
operator shall report:
    (1) 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.
    (2) The method used to calculate equipment leak emissions and the

[[Page 16689]]

calculated, cumulative CH4 emissions (in metric tons of each 
pollutant emitted) for all equipment leak sources.
    (3) 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.
    (4) The quantity of unstabilized crude oil received during the 
calendar year and the cumulative CH4 emissions (in metric tons of each 
pollutant emitted) for storage tanks used to process unstabilized crude 
oil.
    (5) The cumulative annual CH4 emissions (in metric tons of each 
pollutant emitted) for uncontrolled blowdown systems.
    (6) The total number of delayed coking units at the facility, the 
number of delayed coking drums per unit, the dimensions and annual 
number of coke-cutting cycles for each drum, and the cumulative annual 
CH4 emissions (in metric tons of each pollutant emitted) for delayed 
coking units.
    (7) The quantity and types of materials loaded 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.
    (8) 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.
    (9) The cumulative annual CH4 emissions (in metric tons of each 
pollutant emitted) for loading operations.
    (k) If you have a CEMS that measures CO2 emissions but that is not 
required to be used for reporting GHG emissions under this subpart 
(i.e., a CO2 CEMS on a process heater stack but the combustion 
emissions are calculated based on the fuel gas consumption), you must 
identify the emission source that has the CEMS and report the CO2 
emissions as measured by the CEMS for that emissions source.


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 
any system of operation that manufactures phosphoric acid by reacting 
phosphate rock and 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 (2).


Sec.  98.262  GHGs to report.

    (a) You must report CO2 process emissions from each wet-
process phosphoric acid production line.
    (b) You must report CO2, N2O, and CH4 emissions from 
each stationary combustion unit. You must follow the calculation 
methods and all other requirements of subpart C of this part.


Sec.  98.263  Calculating GHG emissions.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must estimate total CO2 emissions 
according to the requirements in Sec.  Sec.  98.33(a) and 98.35.
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must calculate process emissions of CO2 
from each wet-process phosphoric acid process line using Equation Z-1 
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.123

Where:

Em = Annual CO2 mass emissions from a wet-
process phosphoric acid process line m (metric tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
ICn = Inorganic carbon content of the batch of phosphate rock used 
during month n, from the carbon analysis results (percent by weight, 
expressed as a decimal fraction).
Pn = Mass of phosphate rock consumed in month n by wet-
process phosphoric acid process line m (tons).
m = Each wet-process phosphoric acid process line.
z = Number of months during which the process line m operates.
2000/2205 = Conversion factor to convert tons to metric tons.

    (c) You must determine the total emissions from the facility using 
Equation Z-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.124

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.


Sec.  98.264  Monitoring and QA/QC requirements.

    (a) Determine the inorganic carbon content of each batch of 
phosphate rock consumed in the production of phosphoric acid using the 
applicable test method in section IX of the ``Book of Methods Used and 
Adopted by the Association of Florida Phosphate Chemists'', Seventh 
Edition, 1991.
    (b) If more than one batch of phosphate rock is consumed in a 
month, use the highest inorganic carbon content measured during that 
month in Equation Z-1 of this subpart.
    (c) Record the mass of phosphate rock consumed each month in each 
wet-process phosphoric acid process line.


Sec.  98.265  Procedures for estimating missing data.

    There are no missing data procedures for wet-process phosphoric 
acid production facilities estimated according to Sec.  98.263(b). A 
complete record of all measured parameters used in the GHG emissions 
calculations is required. A re-test must be performed if the data from 
the measurement are determined to be unacceptable.


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 (e) of this section for each wet-process phosphoric acid 
production line:
    (a) Annual phosphoric acid production by origin of the phosphate 
rock (metric tons).

[[Page 16690]]

    (b) Annual phosphoric acid production by concentration of 
phosphoric acid produced (metric tons).
    (c) Annual phosphoric acid production capacity.
    (d) Annual arithmetic average percent inorganic carbon in phosphate 
rock from batch records.
    (e) Annual average phosphate rock consumption from monthly 
measurement records (in metric tons).


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 (h) of this 
section for each wet-process phosphoric acid production facility:
    (a) Total annual CO2 emissions from all wet-process 
phosphoric acid process lines (in metric tons).
    (b) Phosphoric acid production (by origin of the phosphate rock) 
and concentration.
    (c) Phosphoric acid production capacity (in metric tons/year).
    (d) Number of wet-process phosphoric acid process lines.
    (e) Monthly phosphate rock consumption (by origin of phosphate 
rock).
    (f) Measurements of percent inorganic carbon in phosphate rock for 
each batch consumed for phosphoric acid production.
    (g) Records of all phosphate rock purchases and/or deliveries (if 
vertically integrated with a mine).
    (h) Documentation of the procedures used to ensure the accuracy of 
monthly phosphate rock consumption.


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.

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), and operate coating and laminating processes.
    (b) The emission units for which GHG emissions must be reported are 
listed in paragraphs (b)(1) through (6) of this section:
    (1) Chemical recovery furnaces at kraft and sodamills (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).


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 (2).


Sec.  98.272  GHGs to report.

    You must report the emissions listed in paragraphs (a) through (h) 
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 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).
    (f) Emissions of CO2, N2O, and CH4 from any other on-
site stationary fuel combustion units (boilers, gas turbines, thermal 
oxiders, and other sources). You must follow the calculation 
procedures, monitoring and QA/QC methods, missing data procedures, 
reporting requirements, and recordkeeping requirements of subpart C of 
this part.
    (g) Emissions of CH4 from on-site landfills. You must follow the 
calculation procedures, monitoring and QA/QC methods, missing data 
procedures, reporting requirements, and recordkeeping requirements of 
subpart HH of this part.
    (h) Emissions of CH4 from on-site wastewater treatment. You must 
follow the calculation procedures, monitoring and QA/QC methods, 
missing data procedures, reporting requirements, and recordkeeping 
requirements of subpart II of this part.


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 (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)(2) and (3).
    (3) Calculate biogenic CO2, CH4, and N2O emissions 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] TP10AP09.125

Where:

CH4, or N2O, from Biomass = Biogenic CO2, CH4, or N2O 
mass emissions from spent liquor solids combustion (metric tons).
(Solids)p = Mass of spent liquor solids combusted per month p (short 
tons per month).
(HHV)p = High heat value of the spent liquor solids for month p 
(mmBtu per mass).
EF = Default emission factor for CO2, CH4, or N2O, from 
Table AA-1 of this subpart (kg CO2, CH4, or N2O per 
mmBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons.
907 = Conversion factor from tons to kilograms.

    (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

[[Page 16691]]

paragraphs (b)(1) through (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)(2).
    (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] TP10AP09.126

Where:

Biogenic CO2 = Annual CO2 mass emissions for 
spent liquor solids combustion (metric tons).
(Solids)p = Mass of the spent liquor solids combusted in month p 
(metric tons per month).
(CC)p = Carbon content of the spent liquor solids, from the fuel 
analysis results for the month p (percent by weight, expressed as a 
decimal fraction, e.g., 95% = 0.95).
44/12 = Ratio of molecular weights, CO2 to carbon.

    (4) Calculate CH4 and N2O emissions from biomass using Equation AA-
1 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 according to the methodology 
for stationary combustion sources in Sec.  98.2(b)(4).
    (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 (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 of this part 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)(2) and (3); use the default HHV listed in 
Table C-1 of subpart C of this part 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 calculated as part of the chemical recovery furnace biogenic 
CO2 estimates 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] TP10AP09.127

Where:

CO2 = CO2 mass emissions from makeup chemicals 
(kilograms/yr).
M (caCO3) = Make-up quantity of CaCO3 used for the 
reporting year (metric tons).
M (NaCO3) = Make-up quantity of Na2CO3 used for the reporting year 
(metric tons).
44 = Molecular weight of CO2.
180 = 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) High heat values of black liquor must be determined once per 
month using TAPPI Method T 684. The mass of spent black liquor solids 
must be determined once per month using TAPPI Method T 650. Carbon 
analyses for spent pulping liquor must be determined once per month 
using ASTM method D5373-08.
    (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 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 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 monthly measurements are determined to 
be invalid.
    (b) For missing spent pulping liquor flow rates, use the lesser 
value of either the maximum fuel flow rate for the combustion unit, or 
the maximum flow

[[Page 16692]]

rate that the fuel flow 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 
(e) of this section for each GHG emission unit listed in Sec.  
98.270(b).
    (a) Annual emissions of CO2, biogenic CO2, 
CH4, and N2O presented by calendar quarter.
    (b) Total consumption of all biomass fuels by calendar quarter.
    (c) Total annual quantity of spent liquor solids fired at the 
facility by calendar quarter.
    (d) Total annual steam purchases.
    (e) Total annual quantities of makeup chemicals (carbonates) used.


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 (h) of this section.
    (a) GHG emission estimates (including separate estimates of 
biogenic CO2) by calendar quarter for each emissions source 
listed under Sec.  98.270(b) of this subpart.
    (b) Monthly total consumption of all biomass fuels for each biomass 
combustion unit.
    (c) Monthly analyses of spent pulping liquor HHV for each chemical 
recovery furnace at kraft and soda facilities.
    (d) Monthly analyses of spent pulping liquor carbon content for 
each chemical recovery combustion unit at a sulfite or semichemical 
pulp facility.
    (e) Monthly quantities of spent liquor solids fired in each 
chemical recovery furnace and chemical recovery combustion unit.
    (f) Monthly and annual steam purchases.
    (g) Monthly and annual steam production for each biomass combustion 
unit.
    (h) Monthly 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 of Subpart AA--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
Straw..................................      95.1
------------------------------------------------------------------------
a Includes emissions from both the recovery furnace and pulp mill lime
  kiln.


Table AA-2 of Subpart AA--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  .........     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 (2).


Sec.  98.282  GHGs to report.

    (a) You must report CO2 and CH4 process 
emissions from all silicon carbide process units combined, as set forth 
in this subpart.
    (b) You must report CO2, N2O, and 
CH4 emissions from each stationary combustion unit by 
following all of the requirements of subpart C of this part.


Sec.  98.283  Calculating GHG emissions.

    You must determine CO2 emissions in accordance with the 
procedures specified in either paragraph (a) or (b) of this section.
    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements of Sec.  
98.33(b)(5)(iii)(A), (B), and (C), you must estimate total 
CO2 emissions according to the requirements for the Tier 4 
Calculation Methodology in Sec.  98.33(a)(4).
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must calculate the annual process CO2 
emissions from all silicon carbide production processes at the facility 
combined, using a facility-specific emission factor according to the 
procedures in paragraphs (b)(1) and (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

[[Page 16693]]

determined quarterly and used to calculate a quarterly CO2 
emisssions factor:
[GRAPHIC] [TIFF OMITTED] TP10AP09.128

Where:

EFCO2 = CO2 emissions factor (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).
CCF = Carbon content factor of petroleum coke from the supplier or 
as measured by the applicable method incorporated by reference in 
Sec.  98.7.
44/12 = Ratio of molecular weights, CO2 to carbon.

    (2) Use Equation BB-2 of this section to calculate CO2 
process emissions (quarterly) from all silicone carbide production:
[GRAPHIC] [TIFF OMITTED] TP10AP09.129

Where:

CO2 = Annual CO2 mass production emissions 
(metric tons CO2/year).
Tn = Petroleum coke consumption in calendar quarter n 
(tons coke).
EFCO2, n = CO2 emissions factor from calendar 
quarter n (calculated in Equation BB-1 of this section).
2000/2205 = Conversion factor to convert tons to metric tons.
q = Number of quarters.

    (c) You must determine annual process CH4 emissions from 
all silicon carbide production processes combined using Equation BB-3 
of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.130

Where:

CH4 = Annual CH4 mass emissions (metric tons 
CH4, year).
Tn = Petroleum coke consumption in calendar quarter n 
(tons coke).
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.
q = Number of quarters.


Sec.  98.284  Monitoring and QA/QC requirements.

    (a) You must determine the quantity of petroleum coke consumed each 
quarter (tons coke/quarter).
    (b) For CO2 process emissions, you must determine the 
carbon content of the petroleum coke for four calendar quarters per 
year based on reports from the supplier or by measurement of the carbon 
content by an off-site laboratory using the applicable test method 
incorporated by reference in Sec.  98.7.


Sec.  98.285  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. There are no missing value 
provisions for the carbon content factor or coke consumption. A re-test 
must be performed if the data from the quarterly carbon content 
measurements are determined to be unacceptable or not representative of 
typical operations.


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) 
through (e) of this section.
    (a) Annual CO2 and CH4 emissions from all silicon 
carbide production processes combined (in metric tons).
    (b) Annual production of silicon carbide (in metric tons).
    (c) Annual capacity of silicon carbide production (in metric tons).
    (d) Annual operating hours.
    (e) Quarterly facility-specific emission factors.


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) through (c) of this 
section for all silicon carbide production processes combined.
    (a) Annual consumption of petroleum coke (in metric tons).
    (b) Quarterly analyses of carbon content for consumed coke 
(averaged to an annual basis).
    (c) Quarterly facility-specific emission factor calculations.


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 soda ash manufacturing facility is any facility with a 
manufacturing line that calcines trona to produce soda ash.


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 (2).


Sec.  98.292  GHGs to report.

    (a) You must report CO2 process emissions from each soda 
ash manufacturing line as required in this subpart.
    (b) You must report the CO2, N2O, and 
CH4 emissions from fuel combustion at each kiln and from 
each stationary combustion unit by following the requirements of 
subpart C of this part.


Sec.  98.293  Calculating GHG emissions.

    You must determine CO2 emissions in accordance with the 
procedures specified in either paragraph (a) or (b) of this section.

[[Page 16694]]

    (a) Any soda ash manufacturing line that meets the conditions 
specified in Sec.  98.33(b)(5)(iii)(A),(B), and (C), or Sec.  
98.33(b)(5)(ii)(A) through (F) shall calculate total CO2 
emissions using a continuous emissions monitoring system according to 
the Tier 4 Calculation Methodology specified in Sec.  98.33(a)(4).
    (b) If the facility does not measure total emissions with a CEMS, 
you must determine the total process emissions from the facility using 
Equation CC-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.131

Where:

CO2 = Annual process CO2 emissions from soda 
ash manufacturing facility (metric tons/year).
Ek = Annual CO2 process emissions from each 
calciner (kiln), k (in metric tons/year), using either Equation CC-2 
or CC-3.
n = Number of calciners (kilns) located at the facility.

    (c) Calculate the annual CO2 process emissions from each 
kiln using either Equation CC-2 or CC-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.132

[GRAPHIC] [TIFF OMITTED] TP10AP09.133

Where:

CO2 = Annual CO2 process emissions (metric 
tons).
44/12 = Ratio of molecular weights, CO2 to carbon.
(ICT)n = Inorganic carbon content in trona 
input, from the carbon analysis results for month n (percent by 
weight, expressed as a decimal fraction).
(ICsa)n = Inorganic carbon content in soda ash 
output, from the carbon analysis results for month n (percent by 
weight, expressed as a decimal fraction).
(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 
natural soda ash produced.


Sec.  98.294  Monitoring and QA/QC requirements.

    (a) You must determine the inorganic carbon content of the trona or 
soda ash on a daily basis and determine the monthly average value for 
each soda ash manufacturing line.
    (b) If you calculate CO2 process emissions based on 
trona input, you must determine the inorganic carbon content of the 
trona using a total organic carbon analyzer according to the 
ultraviolet light/chemical (sodium persulfate) oxidation method 
(utilizing ASTM D4839-03).
    (c) If you calculate CO2 process emissions based on soda 
ash production, you must determine the inorganic carbon content of the 
soda ash using ASTM E359-00 (2005). The inorganic carbon content of 
soda ash can be directly expressed as the total alkalinity of the soda 
ash.
    (d) You must measure the mass of trona input or soda ash produced 
by each soda ash manufacturing line on a monthly basis using either 
belt scales or by weighing the soda ash at the truck or rail loadout 
points of your facility.
    (e) You must keep a record of all trona consumed and soda ash 
production. You also must document the procedures used to ensure the 
accuracy of the monthly measurements of trona consumed soda ash 
production.


Sec.  98.295  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. There are no missing value 
provisions for the carbon content of trona or soda ash. A re-test must 
be performed if the data from the daily carbon content measurements are 
determined to be unacceptable.


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) 
through (f) of this section for each soda ash manufacturing line.
    (a) Annual CO2 process emissions (metric tons).
    (b) Number of soda ash manufacturing lines.
    (c) Annual soda ash production (metric tons) and annual soda ash 
production capacity.
    (d) Annual consumption of trona from monthly measurements (metric 
tons).
    (e) Fractional purity (i.e., inorganic carbon content) of trona or 
soda ash (by daily measurements and by monthly average) depending on 
the components used in Equation CC-2 or CC-3 of this subpart).
    (f) Number of operating hours in calendar year.


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) through (d) of this 
section for each soda ash manufacturing line.
    (a) Monthly production of soda ash (metric tons).
    (b) Monthly consumption of trona (metric tons).
    (c) Daily analyses for inorganic carbon content of trona or soda 
ash (as fractional purity), depending on the components used in 
Equation CC-2 or CC-3 of this subpart.
    (d) Number of operating hours in calendar year.


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--Sulfur Hexafluoride (SF6) From Electrical 
Equipment


Sec.  98.300  Definition of the source category.

    The electric power system source category includes electric power 
transmission and distribution systems that operate gas-insulated 
substations, circuit breakers, other switchgear, gas-insulated lines, 
or power transformers containing sulfur-hexafluoride (SF6) or 
perfluorocarbons (PFCs).


Sec.  98.301  Reporting threshold.

    You must report GHG emissions from electric power systems if the 
total nameplate capacity of SF6 and PFC containing equipment 
in the system exceeds 17,820 lbs (7,838 kg).


Sec.  98.302  GHGs to report.

    You must report total SF6 and PFC emissions (including 
emissions from fugitive equipment leaks, installation,

[[Page 16695]]

servicing, equipment decommissioning and disposal, and from storage 
cylinders) from the following types of equipment:
    (a) Gas-insulated substations.
    (b) Circuit breakers.
    (c) Switchgear.
    (d) Gas-insulated lines.
    (d) Electrical transformers.


Sec.  98.303  Calculating GHG emissions.

    (a) For each electric power system, you must estimate the annual 
SF6 and PFC emissions using the mass-balance approach in 
Equation DD-1 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.134

Where:

Decrease in SF6 Inventory = (SF6 stored in 
containers, but not in equipment, at the beginning of the year)--
(SF6 stored in containers, but not in equipment, at the 
end of the year).
Acquisitions of SF6 = (SF6 purchased from 
chemical producers or distributors in bulk) + (SF6 
purchased from equipment manufacturers or distributors with or 
inside equipment) + (SF6 returned to site after off-site 
recycling).
Disbursements of SF6 = (SF6 in bulk and 
contained in equipment that is sold to other entities) + 
(SF6 returned to suppliers) + (SF6 sent off 
site for recycling) + (SF6 sent to destruction 
facilities).
Net Increase in Total Nameplate Capacity of Equipment Operated = 
(The Nameplate Capacity of new equipment)--(Nameplate Capacity of 
retiring equipment). (Note that Nameplate Capacity refers to the 
full and proper charge of equipment rather than to the actual 
charge, which may reflect leakage.)

    (b) The mass-balance method in paragraph (a) of this section shall 
be used to estimate emissions of PFCs from power transformers, 
substituting the relevant PFC(s) for SF6 in equation DD-1.


Sec.  98.304  Monitoring and QA/QC requirements.

    (a) You must adhere to the following QA/QC methods for reviewing 
the completeness and accuracy of reporting:
    (1) Review inputs to Equation DD-1 to ensure inputs and outputs to 
the company's system are included.
    (2) Do not enter negative inputs and confirm that negative 
emissions are not calculated. However, the Decrease in SF6 
Inventory and the Net Increase in Total Nameplate Capacity may be 
calculated as negative numbers.
    (3) Ensure that beginning-of-year inventory matches end-of-year 
inventory from the previous year.
    (4) Ensure that in addition to SF6 purchased from bulk 
gas distributors, SF6 purchased from Original Equipment 
Manufacturers (OEM) and SF6 returned to the facility from 
off-site recycling are also accounted for among the total additions.
    (b) Ensure the following QA/QC methods are employed throughout the 
year:
    (1) Ensure that cylinders returned to the gas supplier are 
consistently weighed on a scale that is certified to be accurate and 
precise to within 1 percent of the true weight and is periodically 
recalibrated per the manufacturer's specifications. Either measure 
residual gas (the amount of gas remaining in returned cylinders) or 
have the gas supplier measure it. If the gas supplier weighs the 
residual gas, obtain from the gas supplier a detailed monthly 
accounting, within 1 percent, of residual gas amounts in the cylinders 
returned to the gas supplier.
    (2) Ensure that procedures are in place and followed to track and 
weigh all cylinders as they are leaving and entering storage. Cylinders 
shall be weighed on a scale that is certified to be accurate to within 
1 percent of the true weight and the scale shall be recalibrated at 
least annually or at the minimum frequency specified by the 
manufacturer, whichever is more frequent. All scales used to measure 
quantities that are to be reported under Sec.  98.306 shall be 
calibrated using suitable NIST-traceable standards and suitable methods 
published by a consensus standards organization (e.g., ISWM, ISDA, 
NCWM, or others). Alternatively, calibration procedures specified by 
the scale manufacturer may be used. Calibration shall be performed 
prior to the first reporting year.
    (3) Ensure all substations have provided information to the manager 
compiling the emissions report (if it is not already handled through an 
electronic inventory system).


Sec.  98.305  Procedures for estimating missing data.

    A complete record of all measured parameters used in the GHG 
emissions calculations is required. Replace missing data, if needed, 
based on data from equipment with a similar nameplate capacity for 
SF6 and PFC, and from similar equipment repair, replacement, 
and maintenance operations.


Sec.  98.306  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each electric 
power system, by chemical:
    (a) Nameplate capacity of equipment containing SF6 and 
nameplate capacity of equipment containing each PFC:
    (1) Existing as of the beginning of the year.
    (2) New during the year.
    (3) Retired during the year.
    (b) Transmission miles (length of lines carrying voltages at or 
above 34.5 kV).
    (c) SF6 and PFC sales and purchases.
    (d) SF6 and PFC sent off site for destruction.
    (e) SF6 and PFC sent off site to be recycled.
    (f) SF6 and PFC returned from off site after recycling.
    (g) SF6 and PFC stored in containers at the beginning 
and end of the year.
    (h) SF6 and PFC with or inside new equipment purchased 
in the year.
    (i) SF6 and PFC with or inside equipment sold to other 
entities.
    (j) SF6 and PFC returned to suppliers.


Sec.  98.307  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain records of the information reported and listed in Sec.  98.306.


Sec.  98.308  Definitions.

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

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

[[Page 16696]]

contains a titanium dioxide production process and the facility meets 
the requirements of either Sec.  98.2(a)(1) or (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) Report the CO2, N2O, and CH4 
emissions from each stationary combustion unit. You must follow the 
requirements of subpart C of this part.


Sec.  98.313  Calculating GHG emissions.

    You must determine CO2 emissions for each process line 
in accordance with the procedures specified in either paragraph (a) or 
(b) of this section.
    (a) If the facility operates and maintains a continuous emission 
monitoring system (CEMS) that meets the conditions specififed in Sec.  
98.33(b)(5)(ii) or (iii), then you must calculate total CO2 
emissions using the Tier 4 Calculation Methodology specified in Sec.  
98.33(a)(4).
    (b) If the facility does not measure total emissions with a CEMS, 
you must calculate the process CO2 emissions for each 
calcined petroleum coke process line by determining the mass of 
calcined petroleum coke consumed in line. Use Equation EE-1 of this 
section to calculate annual CO2 process emissions for each 
process line:
[GRAPHIC] [TIFF OMITTED] TP10AP09.135

Where:

Ep = Annual CO2 mass emissions from each 
chloride process line (metric tons).
Cn = Calcined petroleum coke consumption in month n, 
tons.
44/12 = Ratio of molecular weights, CO2 to carbon.
2000/2205 = Conversion of tons to metric tons.

    (c) You must determine the total CO2 process emissions 
from the facility using Equation EE-2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.136

Where:

CO2 = Annual CO2 emissions from titanium 
dioxide production facility (metric tons/year).
Ep = Annual CO2 emissions from each chloride 
process line, p (in metric tons/year), determined using Equation EE-
1.
n = Number of separate chloride process lines located at the 
facility.


Sec.  98.314  Monitoring and QA/QC requirements.

    (a) You must measure your consumption of calcined petroleum coke 
either by 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.


Sec.  98.315  Procedures for estimating missing data.

    There are no missing data procedures for the measurement of 
petroleum coke consumption. A complete record of all measured 
parameters used in the GHG emissions calculations is required.


Sec.  98.316  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information specified in 
paragraphs (a) through (e) for each titanium dioxide production line.
    (a) Annual CO2 emissions (metric tons).
    (b) Annual consumption of calcined petroleum coke (metric tons).
    (c) Annual production of titanium dioxide (metric tons).
    (d) Annual production capacity of titanium dioxide (metric tons).
    (e) Annual operating hours for each titanium dioxide process line.


Sec.  98.317  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) through (e) of 
this section for each titanium dioxide production facility.
    (a) Monthly production of titanium dioxide (metric tons).
    (b) Production capacity of titanium dioxide (metric tons).
    (c) Records of all calcined petroleum coke purchases.
    (d) Records of monthly calcined petroleum coke consumption (metric 
tons).
    (e) Annual operating hours for each titanium dioxide process line.


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.

Subpart FF--Underground Coal Mines


Sec.  98.320  Definition of the source category.

    (a) This source category consists of active underground coal mines 
and any underground mines under development that have operational pre-
mining degasification systems. An underground coal mine is a mine at 
which coal is produced by tunneling into the earth to a subsurface coal 
seam, where the coal is then mined with equipment such as cutting 
machines, and transported to the surface. Active underground coal mines 
are mines categorized by MSHA as active and where coal is currently 
being produced or has been produced within the previous 90 days.
    (b) This source category comprises the following emission points:
    (1) Each ventilation well or shaft.
    (2) Each degasification system well or shaft, including 
degasification systems deployed before, during, or after mining 
operations are conducted in a mine area.
    (c) This source category does not include abandoned (closed) mines, 
surface coal mines, or post-coal mining activities.


Sec.  98.321  Reporting threshold.

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


Sec.  98.322  GHGs to report.

    You must report the following:
    (a) CH4 emissions from each ventilation well or shaft 
and each degasification system (this includes degasification systems 
deployed before, during, or after mining operations are conducted in a 
mine area).
    (b) CO2 emissions from coal mine gas CH4 
destruction, where the gas is not a fuel input for energy generation or 
use.
    (c) CO2, CH4, and N2O emissions 
from stationary fuel combustion devices. You must follow the 
requirements of subpart C of this part.


Sec.  98.323  Calculating GHG emissions.

    (a) For each ventilation well or shaft, you must estimate the 
quarterly CH4 liberated from the mine ventilation system 
using the measured CH4 content and flow rate, and Equation 
FF-1 of this section. You must measure CH4 content, flow 
rate, temperature, and pressure of the gas using the procedures 
outlined in Sec.  98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.137


[[Page 16697]]


Where:

CH4V = Quarterly CH4 liberated from 
ventilation systems (metric tons CH4).
V = Measured volumetric flow rate of active ventilation of mining 
operations (cfm).
C = Measured CH4 concentration of ventilation gas during 
active ventilation of mining operations (%, wet basis).
n = The number of days in the quarter where active ventilation of 
mining operations is taking place.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1 
atm (lb/scf).
T = Temperature at which flow is measured ([deg]R).
P = Pressure at which flow is measured (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).

    (b) For each degasification system, you must estimate the quarterly 
CH4 liberated from the mine degasification system using 
measured CH4 content, flow rate, temperature, and pressure, 
and Equation FF-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.138


Where:
CH4D = Quarterly CH4 liberated from the 
degasification system (metric tons CH4).
V = Measured average volumetric flow rate for the days in the 
quarter when the degasification system is in operation and the 
continuous monitoring equipment is properly functioning (cfm).
C = Estimated or measured average CH4 concentration of 
gas for the days in the quarter when the degasification system is in 
operation and the continuous monitoring equipment is properly 
functioning (%, wet basis).
n = The number of days in the quarter.
0.0423 = Density of CH4 at 520 [deg]R (60 [deg]F) and 1 
atm (lb/scf).
T = Measured average temperature at which flow is measured ([deg]R).
P = Measured average pressure at which flow is measured (atm).
1,440 = Conversion factor (min/day).
0.454/1,000 = Conversion factor (metric ton/lb).
    (c) If gas from degasification system wells or ventilation shafts 
is destroyed you must calculate the quarterly CH4 destroyed 
using Equation FF-3 of this section. You must measure CH4 
content and flowrate according to the provisions in Sec.  98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.139

Where:

CH4 destroyed = Quantity of CH4 liberated from 
mine that is destroyed (metric tons).
CH4 = Amount of CH4 collected for 
destruction(metric tons).
DE = Destruction efficiency of the destruction equipment, based on 
the lesser of the manufacturer's specified destruction efficiency or 
98 percent (%)'.

    (d) You must calculate the quarterly net CH4 emissions 
to the atmosphere using Equation FF-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.140

Where:

CH4 emitted (net) = Quarterly CH4 emissions 
from mine ventilation and degasification systems (metric tons).
CH4V = Quarterly CH4 liberated from mine 
ventilation systems, calculated using Equation FF-1 of this section 
(metric tons).
CH4D = Quarterly CH4 liberated from mine 
degasification systems, calculated using Equation FF-2 of this 
section (metric tons).
CH4 destroyed = Quarterly CH4 destroyed, 
calculated using Equation FF-3 of this section (metric tons).

    (e) For each degasification or ventilation system with on-site coal 
mine gas CH4 destruction, where the gas is not a fuel input 
for energy generation or use, you must estimate the CO2 
emissions using Equation FF-5 of this section. You must measure the 
CH4 content and the flow rate according to the provisions in 
Sec.  98.324.
[GRAPHIC] [TIFF OMITTED] TP10AP09.141

Where:

CO2 = Quarterly CO2 emissions from 
CH4 destruction (metric tons).
CH4o = CH4 destroyed, calculated using 
Equation FF-3 of this section (metric tons).
DE = Destruction efficiency, based on the lesser of the 
manufacturer's specified destruction efficiency or 98 percent (%).
44/16 = Ratio of molecular weights of CO2 to 
CH4.


Sec.  98.324  Monitoring and QA/QC requirements.

    (a) The flow and CH4 content of coal mine gas destroyed 
must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test 
Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by 
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test 
Method for Heating Value of Gases in Natural Gas Range by 
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas 
Chromatography (incorporated by reference, see Sec.  98.7).
    (b) For liberation of methane from ventilation systems, you must do 
one of the following:
    (1) Monitor emissions from each well or shaft where active 
ventilation is taking place by collecting quarterly grab samples and 
making quarterly measurements of flow rate, temperature, and pressure. 
The sampling and measurements must be made at the same location as MSHA 
inspection samples are taken. You must follow MSHA sampling procedures 
as set forth in the MSHA Handbook entitled, General Coal Mine 
Inspection Procedures and Inspection Tracking System Handbook Number: 
PH-08-V-1, January 1, 2008. You must record the airflow, temperature, 
and pressure measured, the hand-held methane and oxygen readings in 
percentile, the bottle number of samples collected, and the location of 
the measurement or collection.
    (2) Obtain results of the quarterly testing performed by MSHA.
    (c) For liberation of methane at degasification systems, you must 
monitor methane concentrations and flow rate from each degasification 
well or shaft using any of the oil and gas flow

[[Page 16698]]

meter test methods incorporated by reference in Sec.  98.7.
    (d) All fuel flow meters and gas composition monitors monitors 
shall be calibrated prior to the first reporting year, using a suitable 
method published by a consensus standards organization (e.g., ASTM, 
ASME, API, AGA, MSHA, or others). Alternatively, calibration procedures 
specified by the flow meter manufacturer may be used. Fuel flow meters, 
and gas composition monitors shall be recalibrated either annually or 
at the minimum frequency specified by the manufacturer or other 
applicable standards.
    (e) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer.
    (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, and 
the technical basis for the estimated accuracy shall be recorded.


Sec.  98.325  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, in accordance with paragraph (b) of this section.
    (b) For each missing value of CH4 concentration, flow 
rate, temperature, and pressure for ventilation and degasification 
systems, 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.  98.326  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for each mine:
    (a) Quarterly volumetric flow rate measurement results for all 
ventilation systems, including date and location of measurement.
    (b) Quarterly CH4 concentration measurement results for all 
ventilation systems, including date and location of measurement.
    (c) Quarterly CEMS volumetric flow data used to calculate CH4 
liberated from degasification systems (summed from daily data).
    (d) Quarterly CEMS CH4 concentration data used to calculate CH4 
liberated from degasification systems (average from daily data).
    (e) Quarterly CH4 destruction at ventilation and degasification 
systems.
    (f) Dates in reporting period where active ventilation of mining 
operations is taking place.
    (g) Dates in reporting period when continuous monitoring equipment 
is not properly functioning.
    (h) Quarterly averages of temperatures and pressures at the time 
and at the conditions for which all measurements are made.
    (i) Quarterly CH4 liberated from each ventilation well or shaft, 
and from each degasification system (this includes degasification 
systems deployed before, during, or after mining operations are 
conducted in a mine area).
    (j) Quarterly CH4 emissions (net) from each ventilation well or 
shaft, and from each degasification system (this includes 
degasification systems deployed before, during, or after mining 
operations are conducted in a mine area).
    (k) Quarterly CO2 emissions from on-site destruction of 
coal mine gas CH4, where the gas is not a fuel input for energy 
generation or use.


Sec.  98.327  Records that must be retained.

    In addition to the information required by Sec.  98.3(g), you must 
retain the following records:
    (a) Calibration records for all monitoring equipment.
    (b) Records of gas sales.
    (c) Logbooks of parameter measurements.
    (d) Laboratory analyses of samples.


Sec.  98.328  Definitions.

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

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.

    (a) You must report the CO2 process emissions from each 
Waelz kiln and electrothermic furnace used for zinc production, as 
applicable to your facility.
    (a) You must report the CO2, CH4, and N2O emissions from 
each stationary combustion unit, following requirements of subpart C of 
this part.


Sec.  98.333  Calculating GHG emissions.

    (a) If you operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must estimate total CO2 emissions 
according to the requirements in Sec.  98.33(a).
    (b) If you do not operate and maintain a CEMS that measures total 
CO2 emissions consistent with the requirements in subpart C 
of this part, you must determine the total CO2 emissions 
from the Waelz kilns or electrothermic furnaces at your facility used 
for zinc production using the procedures specified in paragraphs (b)(1) 
and (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 calendar month and estimate total annual 
CO2 process emissions from each affected unit at your 
facility using Equation GG-1. 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.
[GRAPHIC] [TIFF OMITTED] TP10AP09.142


[[Page 16699]]


Where:

ECO2 = Total CO2 process emissions from an 
individual Waelz kiln or electrothermic furnace (metric tons per 
year).
44/12 = Ratio of molecular weights, CO2 to carbon.
(Zinc)n = Mass of zinc bearing material charged to the furnace in 
month ``n'' (metric tons).
(CZinc)n = Carbon content of the zinc bearing material, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Flux)n = Mass of flux materials (e.g., limestone, dolomite) charged 
to the furnace in month ``n'' (metric tons).
(CFlux)n = Average carbon content of the flux materials, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).
(Electrode)n = Mass of carbon electrode consumed in month ``n'', for 
electrothermic furnace (metric tons).
(CElectrode)n = Average carbon content of the carbon electrode, from 
the carbon analysis results for month ``n'', for electrothermic 
furnace (percent by weight, expressed as a decimal fraction).
(Carbon)n = Mass of carbonaceous materials (e.g., coal, coke) 
charged to the furnace in month ``n'' (metric tons).
(CCarbon)n = Average carbon content of the carbonaceous materials, 
from the carbon analysis results for month ``n'' (percent by weight, 
expressed as a decimal fraction).

    (2) You must determine the total CO2 emissions from the 
Waelz kilns or electrothermic furnaces at your facility using Equation 
GG-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.143

Where:


CO2 = Total annual CO2 emissions, metric tons/
year.
ECO2k = Annual CO2 emissions from Waelz kiln 
or electrothermic furnace k calculated using Equation GG-1 of this 
section, metric tons/year.
k = Total number of Waelz kilns or electrothermic furnaces at 
facility used for the zinc production.


Sec.  98.334  Monitoring and QA/QC requirements.

    If you determine CO2 emissions using the carbon input 
procedure in Sec.  98.333(b)(1), you must meet the requirements 
specified in paragraphs (a) through (c) of this section.
    (a) Determine the mass of each solid carbon-containing input 
material by direct measurement of the quantity of the material placed 
in the unit or by calculations using process operating information, and 
record the total mass for the material for each calendar month.
    (b) For each input material identified in paragraph (a) of this 
section, you must determine the average carbon content of the material 
for each calendar month using information provided by your material 
supplier or by collecting and analyzing a representative sample of the 
material using an analysis method appropriate for the material.
    (c) For each input material identified in paragraph (a) of this 
section for which the carbon content is not provided by your material 
supplier, the carbon content of the material must be analyzed by an 
independent certified laboratory each calendar month using the test 
methods (and their QA/QC procedures) in Sec.  98.7. Use ASTM E1941-04 
(``Standard Test Method for Determination of Carbon in Refractory and 
Reactive Metals and Their Alloys'') for analysis of zinc bearing 
materials; ASTM D5373-02 (``Standard Test Methods for Instrumental 
Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples 
of Coal and Coke'') for analysis of carbonaceous reducing agents and 
carbon electrodes, and ASTM C25-06 (``Standard Test Methods for 
Chemical Analysis of Limestone, Quicklime, and Hydrated Lime'') for 
analysis of 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.
    (a) For each missing value of the carbon 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, 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 records of the mass of carbon-containing input 
material consumption, the substitute data value shall be the best 
available estimate of the mass of the input material. The owner or 
operator shall document and keep records of the procedures used for all 
such estimates.


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) 
through (e) of this section for each Waelz kiln or electrothermic 
furnace.
    (a) Annual CO2 emissions in metric tons, and the method 
used to estimate emissions.
    (b) Annual zinc product production capacity (in metric tons).
    (c) Total number of Waelz kilns and electrothermic furnaces at the 
facility.
    (d) Number of facility operating hours in calendar year.
    (e) If you use the carbon input procedure, report for each carbon-
containing input material consumed or used (other than fuel), the 
information specified in paragraphs (e)(1) and (2) of this section.
    (1) Annual material quantity (in metric tons).
    (2) Annual average of the monthly carbon content determinations for 
each material and the method used for the determination (e.g., supplier 
provided information, analyses of representative samples you 
collected).


Sec.  98.337  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 (d) of this section.
    (a) Monthly facility production quantity for each zinc product (in 
metric tons).
    (b) Number of facility operating hours each month.
    (c) Annual production Quantity for each zinc product (in metric 
tons).
    (d) If you use the carbon input procedure, record for each carbon-
containing input material consumed or used (other than fuel), the 
information specified in paragraphs (d)(1) and (2) of this section.
    (1) Monthly material quantity (in metric tons).
    (2) Monthly average carbon content determined for material and 
records of the supplier provided information or analyses used for the 
determination.
    (e) 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. 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.

[[Page 16700]]

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--Landfills


Sec.  98.340  Definition of the source category.

    (a) This source category consists of the following sources at 
municipal solid waste (MSW) landfill facilities: landfills, landfill 
gas collection systems, and landfill gas combustion systems (including 
flares). This source category also includes industrial landfills 
(including, but not limited to landfills located at food processing, 
pulp and paper, and ethanol production facilities).
    (b) This source category does not include hazardous waste landfills 
and construction and demolition landfills.


Sec.  98.341  Reporting threshold.

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


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 CO2, CH4, and N2O emissions from 
stationary fuel combustion devices. This includes emissions from the 
combustion of fuels used in flares (e.g., for pilot gas or to 
supplement the heating value of the landfill gas). Follow the 
requirements of subpart C of this part. Do not calculate CO2 
emissions resulting from the flaring of landfill gas.


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 (4) of this 
section.
    (1) Calculate annual modeled CH4 generation using recorded or 
estimated waste disposal quantities, default values from Table HH-1, 
and Equation HH-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.144

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*DOC*DOCF*F*16/12.
MCF = Methane correction factor (fraction).
DOC = Degradable organic carbon [fraction (metric tons C/metric ton 
waste)].
DOCF = Fraction of DOC dissimilated (fraction).
F = Fraction by volume of CH4 in landfill gas.
k = Rate constant (yr-1).

    (2) For years when material-specific waste quantity data are 
available, and for industrial waste landfills, 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. 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. For both MSW and industrial landfills, 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 for MSW landfills, Wx 
shall be estimated using the estimated population served by the 
landfill in each year, the values for national average per capita waste 
disposal and fraction of generated waste disposed of in solid waste 
disposal sites found in Table HH-2 of this subpart.
    (4) For industrial landfills, Wx in reporting years must 
be determined by direct mass measurement of waste entering the landfill 
using industrial scales with a manufacturer's stated accuracy of 2 percent. For previous years, where data are unavailable on 
waste disposal quantities, estimate the waste quantities according to 
the requirements in paragraphs (a)(4)(i) and (ii) of this section.
    (i) Calculate the average waste disposal rate per unit of 
production for the first applicable reporting year using Equation HH-2 
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.145

Where:

WDF = Average waste disposal factor determined on the first year of 
reporting (metric tons per production unit). The average waste 
disposal factor should not be re-calculated in subsequent reporting 
years.
N = Number of years for which disposal and production data are 
available.
Wn = Quantity of waste placed in the industrial landfill 
in year n (metric tons).
Pn = Quantity of product produced in year n (production 
units).

    (ii) Calculate the waste disposal quantities for historic years in 
which direct waste disposal measurements are not available using 
historical production data and Equation HH-3 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.146

Where:

X = Historic year in which waste was disposed.
Wx = Projected quantity of waste placed in the landfill 
in year X (metric tons).
WDF = Average waste disposal factor from Equation HH-1 of this 
section (metric tons per production unit).
Px = Production quantity for the facility in year X from 
company records (production units).

    (b) For landfills with gas collection systems, calculate the 
quantity of CH4 destroyed according to the requirements in 
paragraphs (b)(1) through (4) of this section.
    (1) Measure continuously the flow rate, CH4 
concentration, temperature, and pressure, of the collected landfill gas 
(before any treatment equipment) using a monitoring meter specifically 
for CH4 gas, as specified in Sec.  98.344.
    (2) Calculate the quantity of CH4 recovered for 
destruction using Equation HH-4 of this section.

[[Page 16701]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.147

Where:

R = Annual quantity of recovered CH4 (metric tons 
CH4).
Vn = Daily average volumetric flow rate for day n (acfm).
Cn = Daily average CH4 concentration of 
landfill gas for day n (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520[deg]R or 60[deg]F 
and 1 atm).
Tn = Temperature at which flow is measured for day n 
([deg]R).
Pn = 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).

    (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 (d)(1) through (4) of 
this section.
    (1) Calculate CH4 generation, adjusted for oxidation, 
from the modeled CH4 (GCH4 from Equation HH-1) 
using Equation HH-5 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.148

Where:

MG = Methane generation from the landfill in the reporting year, 
adjusted for oxidation (metric tons CH4).
GCH4 = Modeled methane generation rate in reporting year 
from Equation HH-1 of this section (metric tons CH4).
OX = Oxidation fraction default rate is 0.1 (10%).

    (2) For landfills that do not have landfill gas collection systems, 
the CH4 emissions are equal to the CH4 generation 
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 (ii) of this section.
    (i) Calculate CH4 emissions from the modeled 
CH4 generation and measured CH4 recovery using 
Equation HH-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.149

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 default rate is 0.1 (10%).
DE = Destruction efficiency (lesser of manufacturer's specified 
destruction efficiency and 0.99)

    (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] TP10AP09.150

[GRAPHIC] [TIFF OMITTED] TP10AP09.151

Where:

MG = Methane generation 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. 
(Default is 0.75).
OX = Oxidation fraction (default rate is 0.1 (10%)).
DE = Destruction efficiency, (lesser of manufacturer's specified 
destruction efficiency and 0.99).


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, 2008.
    (b) The quantity of landfill gas CH4 destroyed must be 
determined using ASTM D1945-03 (Reapproved 2006), Standard Test Method 
for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by 
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test 
Method for Heating Value of Gases in Natural Gas Range by 
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas 
Chromatography (incorporated by reference, see Sec.  98.7).
    (c) All fuel flow meters and gas composition monitors shall be 
calibrated prior to the first reporting year, using ASTM D1945-03 
(Reapproved 2006), Standard Test Method for Analysis of Natural Gas by 
Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice 
for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 
(Reapproved 2006), Standard Test Method for Heating Value of Gases in 
Natural Gas Range by Stoichiometric Combustion; or UOP539-97 Refinery 
Gas Analysis by Gas Chromatography (incorporated by reference, see 
Sec.  98.7). Alternatively, calibration procedures specified by the 
flow meter manufacturer may be used. Fuel flow meters, and gas 
composition monitors shall be recalibrated either annually or at the 
minimum frequency specified by the manufacturer.
    (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

[[Page 16702]]

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, 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, 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 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) Waste disposal for each year of landfilling.
    (b) Method for estimating waste disposal.
    (c) Waste composition, if available, in percentage categorized as--
    (1) Municipal,
    (2) Construction and demolition,
    (3) Biosolids or biological sludges,
    (4) Industrial, inorganic,
    (5) Industrial, organic,
    (6) Other, or more refined categories, such as those for which k 
rates are available in Table HH-1 of this subpart.
    (d) Method for estimating waste composition.
    (e) Fraction of CH4 in landfill gas based on measured 
values if the landfill has a gas collection system or a default.
    (f) Oxidation fraction used in the calculations.
    (g) Degradable organic carbon (DOC) used in the calculations.
    (h) Decay rate k used in the calculations.
    (i) Fraction of DOC dissimilated used in the calculations.
    (j) Methane correction factor used in the calculations.
    (k) Annual methane generation and methane emissions (metric tons/
year) according to the methodologies in Sec.  98.343(c)(1) through (3). 
Landfills with gas collection system must separately report methane 
generation and emissions according to the methodologies in Sec.  
98.343(c)(3)(i) and (ii) and indicate which values are calculated using 
the methodologies in Sec.  98.343(c)(ii).
    (l) Landfill design capacity.
    (m) Estimated year of landfill closure.
    (n) Total volumetric flow of landfill gas for landfills with gas 
collection systems.
    (o) CH4 concentration of landfill gas for landfills with 
gas collection systems.
    (p) Monthly average temperature at which flow is measured for 
landfills with gas collection systems.
    (q) Monthly average pressure at which flow is measured for 
landfills with gas collection systems.
    (r) Destruction efficiency used for landfills with gas collection 
systems.
    (s) Methane destruction for landfills with gas collection systems 
(total annual, metric tons/year).
    (t) Estimated gas collection system efficiency for landfills with 
gas collection systems.
    (u) Methodology for estimating gas collection system efficiency for 
landfills with gas collection systems.
    (v) Cover system description.
    (w) Number of wells in gas collection system.
    (x) Acreage and quantity of waste covered by intermediate cap.
    (y) Acreage and quantity of waste covered by final cap.
    (z) Total CH4 generation from landfills.
    (aa) Total CH4 emissions from landfills.


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.


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 of Subpart HH--Emissions Factors, Oxidation Factors and
                                 Methods
------------------------------------------------------------------------
           Factor                 Default value             Units
------------------------------------------------------------------------
                     Waste model--bulk waste option
------------------------------------------------------------------------
k (precipitation <20 inches/  0.02................  yr-1
 year).
k (precipitation 20-40        0.038...............  yr-1
 inches/year).
k (precipitation >40 inches/  0.057...............  yr-1
 year).
L0 (Equivalent to DOC =       0.067...............  metric tons CH4/
 0.2028 when MCF=1,                                  metric ton waste.
 DOCF=0.5, and F=0.5).
------------------------------------------------------------------------
           Waste model--All MSW and industrial waste landfills
------------------------------------------------------------------------
MCF.........................  1...................  ....................
DOCF........................  0.5.................  ....................
F...........................  0.5.................  ....................
------------------------------------------------------------------------

[[Page 16703]]

 
             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
------------------------------------------------------------------------
                 Waste model--Industrial waste landfills
------------------------------------------------------------------------
DOC (food processing).......  0.15................  Weight fraction, wet
                                                     basis.
DOC (pulp and paper)........  0.2.................  Weight fraction, wet
                                                     basis.
k (food processing).........  0.185...............  yr-1
k (pulp and paper)..........  0.06................  yr-1
------------------------------------------------------------------------
              Calculating methane generation and emissions
------------------------------------------------------------------------
OX..........................  0.1.................
DE..........................  0.99................
------------------------------------------------------------------------
\a\ Use the lesser value when the potential evapotranspiration rate
  exceeds the mean annual precipitation rate and the greater value when
  it does not.


     Table HH-2 of Subpart HH--U.S. Per Capita Waste Disposal Rates
------------------------------------------------------------------------
                                             Waste per
                  Year                    capita ton/cap/    % to SWDS
                                                yr
------------------------------------------------------------------------
1940....................................            0.64             100
1941....................................            0.64             100
1942....................................            0.64             100
1943....................................            0.64             100
1944....................................            0.63             100
1945....................................            0.64             100
1946....................................            0.64             100
1947....................................            0.63             100
1948....................................            0.63             100
1949....................................            0.63             100
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

[[Page 16704]]

 
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
------------------------------------------------------------------------

Subpart II--Wastewater Treatment


Sec.  98.350  Definition of source category.

    (a) A wastewater treatment system is the collection of all 
processes that treat or remove pollutants and contaminants, such as 
soluble organic matter, suspended solids, pathogenic organisms, and 
chemicals from waters released from industrial processes. This source 
category applies to on-site wastewater treatment systems at pulp and 
paper mills, food processing plants, ethanol production plants, 
petrochemical facilities, and petroleum refining facilities.
    (b) This source category does not include centralized domestic 
wastewater treatment plants.


Sec.  98.351  Reporting threshold.

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


Sec.  98.352  GHGs to report.

    (a) You must report annual CH4 emissions from anaerobic 
wastewater treatment processes.
    (b) You must report annual CO2 emissions from oil/water 
separators at petroleum refineries.
    (c) You must report CO2, CH4, and 
N2O emissions from the combustion of fuels in stationary 
combustion devices and fuels used in flares by following the 
requirements of subpart C of this part. For flares, calculate the 
CO2 emissions only from pilot gas and other auxiliary fuels 
combusted in the flare, as specified in subpart C of this part. Do not 
include CO2 emissions resulting from the combustion of 
anaerobic digester gas.


Sec.  98.353  Calculating GHG emissions.

    (a) Estimate the annual CH4 mass emissions from systems 
other than digesters using Equation II-1 of this section. The value of 
flow and COD must be determined in accordance with the monitoring 
requirements specified in Sec.  98.354. The flow and COD should reflect 
the wastewater treated anaerobically on site in anaerobic systems such 
as lagoons.
[GRAPHIC] [TIFF OMITTED] TP10AP09.152

Where:

CH4 = Annual CH4 mass emissions from the 
wastewater treatment system (metric tons).
Flown = Volumetric flow rate of wastewater sent to an 
anaerobic treatment system in month n (m\3\/month).
COD = Average monthly value for chemical oxygen demand of wastewater 
entering anaerobic treatment systems other than digesters (kg/m\3\).
B0 = Maximum CH4 producing potential of 
wastewater (kg CH4/kg COD), default is 0.25.

[[Page 16705]]

MCF = CH4 conversion factor, based on relevant values in 
Table II-1.
0.001 = Conversion factor from kg to metric tons.

    (b) For each petroleum refining facility having an on-site oil/
water separator, estimate the annual CO2 mass emissions 
using Equation II-2 using measured values for the volume of wastewater 
treated, and default values for emission factors by separator type from 
Table II-1 of this subpart. The flow should reflect the wastewater 
treated in the oil/water separator.
[GRAPHIC] [TIFF OMITTED] TP10AP09.153

Where:

CO2 = Annual emissions of CO2 from oil/water 
separators (metric tons/yr).
EFsep = Emissions factor for the type of separator (kg 
NMVOC/m\3\ wastewater treated).
VH20 = Volumetric flow rate of wastewater treated through 
oil/water separator in month m (m\3\/month).
C = Carbon fraction in NMVOC (default = 0.6).
44/12 = Conversion factor for carbon to carbon dioxide.
0.001 = Conversion factor from kg to metric tons.
    (c) For each anaerobic digester, estimate the annual mass of 
CH4 destroyed using Equations II-3 and II-4 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.154

Where:

CH4d = Annual quantity of CH4 destroyed (kg/
yr).
CH4AD = Annual quantity of CH4 generated by 
anaerobic digester, as calculated in Equation II-4 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).
[GRAPHIC] [TIFF OMITTED] TP10AP09.155

Where:

CH4AD = Annual quantity of CH4 generated by 
anaerobic digestion (metric tons CH4/yr).
Vn = Daily average volumetric flow rate for day n, as 
determined from daily monitoring specified in Sec.  98.354 (acfm).
Cn = Daily average CH4 concentration of 
digester gas for day n, as determined from daily monitoring 
specified in Sec.  98.354 (%, wet basis).
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60 
[deg]F and 1 atm).
Tn = Temperature at which flow is measured for day n 
([deg]R).
Pn = Pressure at which flow is measured for day n (atm).


Sec.  98.354  Monitoring and QA/QC requirements.

    (a) The quantity of COD treated anaerobically must be determined 
using analytical methods for industrial wastewater pollutants and must 
be conducted in accordance with the methods specified in 40 CFR part 
136.
    (b) All flow meters must be calibrated using the procedures and 
frequencies specified by the device manufacturer.
    (c) For anaerobic treatment systems, facilities must monitor the 
wastewater flow and COD no less than once per week. The sample location 
must represent the influent to anaerobic treatment for the time period 
that is monitored. The flow sample must correspond to the location used 
to measure the COD. Facilities must collect 24-hour flow-weighted 
composite samples, unless they can demonstrate that the COD 
concentration and wastewater flow into the anaerobic treatment system 
does not vary. In this case, facilities must collect 24-hour time-
weighted composites to characterize changes in wastewater due to 
production fluctuations, or a grab sample if the influent flow is 
equalized resulting in little variability.
    (d) For oil/water separators, facilities must monitor the flow no 
less than once per week. The sample location must represent the 
influent to oil/water separator for the time period that is monitored.
    (e) The quantity of gas destroyed must be determined using any of 
the oil and gas flow meter test methods incorporated by reference in 
Sec.  98.7.
    (f) All gas flow meters and gas composition monitors shall be 
calibrated prior to the first reporting year, using a suitable method 
published by a consensus standards organization (e.g., ASTM, ASME, API, 
AGA, or others). Alternatively, calibration procedures specified by the 
flow meter manufacturer may be used. Gas flow meters and gas 
composition monitors shall be recalibrated either annually or at the 
minimum frequency specified by the manufacturer.
    (g) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the device manufacturer.
    (h) All equipment (temperature and pressure monitors and gas flow 
meters and gas composition monitors) shall be maintained as specified 
by the manufacturer.
    (i) 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 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.  98.355  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 following requirements in 
paragraphs (a) and (b) of this section:
    (a) For each missing monthly value of COD or wastewater flow 
treated, the substitute data value shall be the arithmetic average of 
the quality-assured values of those parameters for the weeks 
immediately preceding and immediately following the missing data 
incident. For each missing value of the CH4 content or gas 
flow rates, the substitute data value shall be the arithmetic average 
of the quality-assured values of that parameter immediately preceding 
and

[[Page 16706]]

immediately following the missing data incident.
    (b) 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.  98.356  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information for the wastewater 
treatment system.
    (a) Type of wastewater treatment system.
    (b) Percent of wastewater treated at each system component.
    (c) COD.
    (d) Influent flow rate.
    (e) B0.
    (f) MCF.
    (g) Methane emissions.
    (h) Type of oil/water separator (petroleum refineries).
    (i) Emissions factor for the type of separator (petroleum 
refineries).
    (j) Carbon fraction in NMVOC (petroleum refineries).
    (k) CO2 emissions (petroleum refineries).
    (l) Total volumetric flow of digester gas (facilities with 
anaerobic digesters).
    (m) CH4 concentration of digester gas (facilities with 
anaerobic digesters).
    (n) Temperature at which flow is measured (facilities with 
anaerobic digesters).
    (o) Pressure at which flow is measured (facilities with anaerobic 
digesters).
    (p) Destruction efficiency used (facilities with anaerobic 
digesters).
    (q) Methane destruction (facilities with anaerobic digesters).
    (r) Fugitive methane (facilities with anaerobic digesters).


Sec.  98.357  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.


Sec.  98.358  Definitions.

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

               Table II-1 of Subpart II--Emission Factors
------------------------------------------------------------------------
                                     Default
             Factors                  value               Units
------------------------------------------------------------------------
B0...............................         0.25  Kg CH4/kg COD.
MCF--anaerobic deep lagoon,                0.8  Fraction.
 anaerobic reactor (e.g., upflow
 anaerobic sludge blanket, fixed
 film).
MCF--anaerobic shallow lagoon              0.2  Fraction.
 (less than 2 m).
MCF--centralized aerobic                     0  Fraction.
 treatment system, well managed.
MCF--Centralized aerobic                   0.3  Fraction.
 treatment system, not well
 managed (overloaded).
Anaerobic digester for sludge....          0.8  Fraction.
C fraction in NMOC...............          0.6  Fraction.
EF sep--Gravity Type (Uncovered).     1.11E-01  Kg NMVOC/m\3\ wastewater
EF sep--Gravity Type (Covered)...     3.30E-03  Kg NMVOC/m\3\
                                                 wastewater.
EF sep--Gravity Type--(Covered               0  Kg NMVOC/m\3\
 and Connected to a Destruction                  wastewater.
 Device).
DAF or IAF--uncovered............     4.00E-34  Kg NMVOC/m\3\
                                                 wastewater.
DAF or IAF--covered..............     1.20E-44  Kg NMVOC/m\3\
                                                 wastewater.
DAF or IAF--covered and connected            0  Kg NMVOC/m\3\
 to a destruction device.                        wastewater.
------------------------------------------------------------------------
DAF = dissolved air flotation type.
IAF = induced air flotation type.

Subpart JJ--Manure Management


Sec.  98.360  Definition of the source category.

    (a) This source category consists of manure management systems for 
livestock manure.
    (b) A manure management system is as a system that stabilizes or 
stores livestock manure in one or more of the following system 
components: uncovered anaerobic lagoons, liquid/slurry systems, storage 
pits, digesters, drylots, solid manure storage, feedlots and other dry 
lots, high rise houses for poultry production (poultry without litter), 
poultry production with litter, deep bedding systems for cattle and 
swine, and manure composting. This definition of manure management 
system encompasses the treatment of wastewaters from manure.
    (c) This source category does not include components at a livestock 
operation unrelated to the stabilization or storage of manure such as 
daily spread or pasture/range/paddock systems.


Sec.  98.361  Reporting threshold.

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


Sec.  98.362  GHGs to report.

    (a) You must report annual aggregate CH4 and 
N2O emissions for each of the following manure management 
system (MMS) components at the facility:
    (1) Liquid/slurry systems such as tanks and ponds.
    (2) Storage pits.
    (3) Uncovered anaerobic lagoons used for stabilization or storage 
or both.
    (4) Digesters, including covered anaerobic lagoons.
    (5) Solid manure storage including feedlots and other dry lots, 
high rise houses for caged laying hens, broiler and turkey production 
on litter, and deep bedding systems for cattle and swine.
    (6) Manure composting.
    (b) You must report CO2, CH4, and 
N2O emissions from the combustion of supplemental fuels used 
in flares by following the requirements of subpart C of this part. For 
flares, calculate the CO2 emissions only from pilot gas and 
other auxiliary fuels combusted in the flare, as specified in subpart C 
of this part. Do not include CO2 emissions resulting from 
the combustion of digester gas in flares.
    (c) A facility that is subject to this rule only because of 
emissions from manure management systems is not required to report 
emissions from fuels used in stationary combustion devices other than 
flares.

[[Page 16707]]

Sec.  98.363  Calculating GHG emissions.

    (a) For manure management systems except digesters, estimate the 
annual CH4 emissions using Equation JJ-1.
[GRAPHIC] [TIFF OMITTED] TP10AP09.156

Where:

TVS = Total volatile solids excreted by animal type, calculated 
using Equation JJ-2 of this section (kg/day).
VSMMS = Percent of manure that is managed in each MMS 
(decimal) (assumed to be equivalent to the amount of VS in each 
system).
B0 = Maximum CH4-producing capacity, as 
specified in Table JJ-1 of this section (m\3\ CH4/kg VS).
MCFMMS = CH4 conversion factor for MMS, as 
specified in Table JJ-2 of this section (decimal).
[GRAPHIC] [TIFF OMITTED] TP10AP09.187

Where:

TVS = Total volatile solids excreted per animal type (kg/day).
%TVS = Annual average percent total volatile solids by animal type, 
as determined from monthly manure monitoring as specified in Sec.  
98.364 (decimal).
Population = Average annual animal population (head).
TAM = Typical animal mass, using either default values in Table JJ-1 
of this section or farm-specific data (kg/head).
MER = Manure excretion rate, using either default values in Table 
JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg 
animal mass).

    (b) For each digester, estimate the annual CH4 flow to 
the combustion device using Equation JJ-3 of this section, the amount 
of CH4 destroyed using Eq JJ-4 of this section, and the 
amount of CH4 leakage using Equation JJ-5 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.157

Where:

CH4D = Methane flow to digester combustion device (metric 
tons CH4/yr)
Vn = Daily average volumetric flow rate for day n, as 
determined from daily monitoring as specified in Sec.  98.364 
(acfm).
Cn = Daily average CH4 concentration of 
digester gas for day n, as determined from daily monitoring as 
specified in Sec.  98.364 (%, wet basis)
0.0423 = Density of CH4 lb/scf (at 520 [deg]R or 60 
[deg]F and 1 atm).
Tn = Temperature at which flow is measured for day 
n([deg]R).
Pn = Pressure at which flow is measured for day n (atm).

[GRAPHIC] [TIFF OMITTED] TP10AP09.158

Where:

CH4D = Annual quantity of CH4 flow to digester 
combustion device, as calculated in Equation JJ-4 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).
OH = Number of hours combustion device is functioning in reporting 
year.
Hours = Hours in reporting year.
[GRAPHIC] [TIFF OMITTED] TP10AP09.159

CH4D = Annual quantity of CH4 combusted by 
digester, as calculated in Equation JJ-4 of this section (metric 
tons CH4).
CE = CH4 collection efficiency of anaerobic digester, as 
specified in Table JJ-3 of this section (decimal).

    (c) For each manure management system type, estimate the annual 
N2O emissions using Equation JJ-6 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.160


[[Page 16708]]


Where:

Nex = Total nitrogen excreted per animal type, calculated 
using Equation JJ-7 of this section (kg/day).
Nex,MMS = Percent of manure that is managed in each MMS 
(decimal) (assumed to be equivalent to the amount of Nex 
in each system).
EFMMS = Emission factor for MMS, as specified in Table 
JJ-4 of this section (kg N2O-N/kg N).
[GRAPHIC] [TIFF OMITTED] TP10AP09.161

Where:

Nex = Total nitrogen excreted per animal type (kg/day).
NManure = Annual average percent of nitrogen present in 
manure by animal type, as determined from monthly manure monitoring, 
as specified in Sec.  98.364 (decimal).
Population = Average annual animal population (head).
TAM = Typical animal mass, using either default values in Table JJ-1 
of this section or farm-specific data (kg/head).
MER = Manure excretion rate, using either default values in Table 
JJ-1 of this section or farm-specific data (kg manure/day/1,000 kg 
animal mass).

    (d) Estimate the annual total annual emissions using Equation JJ-8 
of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.162

Where:

CH4 emissions = From Equation JJ-1 of this section.
CH4 flow to digester combustion device = From Equation 
JJ-3 of this section.
CH4 destruction of digester = From Equation JJ-4 of this 
section.
CH4 leakage of digester = From Equation JJ-5 of this 
section.
21 = Global Warming Potential of CH4.
Direct N2O emissions = from Equation JJ-6 of this 
section.
310 = Global Warming Potential of N2O.


Sec.  98.364  Monitoring and QA/QC requirements.

    (a) Perform a one-time analysis on your operation to determine the 
percent of total manure by weight that is managed in each on-site 
manure management system.
    (b) Determine the annual average percent total volatile solids by 
animal type, (%TVS) by analysis of a representative sample using Method 
160.4 (Residue, Volatile) as described in Methods for Chemical Analysis 
of Water and Wastes, EPA-600/4-79/020, Revised March 1983. The 
laboratory performing the analyses should be certified for analysis of 
waste for National Pollutant Discharge Elimination System compliance 
reporting. The sample analyzed should be a representative composite of 
freshly excreted manure from each animal type contributing to the 
manure management system. Total volatile solids of manure must be 
sampled and analyzed monthly.
    (c) Determine the annual average percent of nitrogen present in 
manure by animal type (NManure) by analysis of a 
representative sample using Method 351.3 as described in Methods for 
Chemical Analysis of Water and Wastes, EPA-600/4-79-020, Revised March 
1983. The laboratory performing the analyses should be certified for 
analysis of waste for National Pollutant Discharge Elimination System 
compliance reporting. The sample analyzed should be a representative 
composite of freshly excreted manure from each animal type contributing 
to the manure management system. Sample collection and analysis must be 
monthly.
    (d) The flow and CH4 concentration of gas from digesters 
must be determined using ASTM D1945-03 (Reapproved 2006), Standard Test 
Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 
(Reapproved 2006), Standard Practice for Analysis of Reformed Gas by 
Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test 
Method for Heating Value of Gases in Natural Gas Range by 
Stoichiometric Combustion; or UOP539-97 Refinery Gas Analysis by Gas 
Chromatography (incorporated by reference in Sec.  98.7).
    (e) All temperature and pressure monitors must be calibrated using 
the procedures and frequencies specified by the manufacturer.
    (f) All gas flow meters and gas composition monitors shall be 
calibrated prior to the first reporting year, using a suitable method 
published by a consensus standards organization (e.g., ASTM, ASME, API, 
AGA, or others). Alternatively, calibration procedures specified by the 
flow meter manufacturer may be used. Gas flow meters and gas 
composition monitors shall be recalibrated either annually or at the 
minimum frequency specified by the manufacturer.
    (g) All equipment (temperature and pressure monitors and gas flow 
meters and gas composition monitors) shall be maintained as specified 
by the manufacturer.
    (h) 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.


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, volatile solids, or nitrogen or 
methane 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.

    In addition to the information required by Sec.  98.3(c), each 
annual report

[[Page 16709]]

must contain the following information for each manure management 
system component:
    (a) Type of manure management system component.
    (b) Animal population (by animal type).
    (c) Monthly total volatile solids content of excreted manure.
    (d) Percent of manure handled in each manure management system 
component.
    (e) B0 value used.
    (f) Methane conversion factor used.
    (g) Average animal mass (for each type of animal).
    (h) Monthly nitrogen content of excreted manure.
    (i) N2O emission factor selected.
    (j) CH4 emissions
    (k) N2O emissions.
    (l) Total annual volumetric biogas flow (for systems with 
digesters).
    (m) Average annual CH4 concentration (for systems with 
digesters).
    (n) Temperature at which gas flow is measured (for systems with 
digesters).
    (o) Pressure at which gas flow is measured (for systems with 
digesters).
    (p) Destruction efficiency used (for systems with digesters).
    (q) Methane destruction (for systems with digesters).
    (r) Methane generation from the digesters.


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.


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 of Subpart JJ--Waste Characteristics Data
------------------------------------------------------------------------
                                                               Maximum
                                      Animal       Manure      methane
                                      group      excretion    generation
           Animal group              typical     rate (kg/    potential,
                                   animal mass  day/1000 kg  Bo (m3 CH4/
                                       (kg)        animal       kg VS
                                                   mass)        added)
------------------------------------------------------------------------
Dairy Cows.......................          604        80.34         0.24
Dairy Heifers....................          476           85         0.17
Feedlot Steers...................          420         51.2         0.33
Feedlot Heifers..................          420         51.2         0.33
Market Swine <60 lbs.............           16          106         0.48
Market Swine 60-119 lbs..........           41         63.4         0.48
Market Swine 120-179 lbs.........           68         63.4         0.48
Market Swine >180 lbs............           91         63.4         0.48
Breeding Swine...................          198         31.8         0.48
Feedlot Sheep....................           25           40         0.36
Goats............................           64           41         0.17
Horses...........................          450           51         0.33
Hens >/= 1 yr....................          1.8         60.5         0.39
Pullets..........................          1.8         45.6         0.39
Other Chickens...................          1.8         60.5         0.39
Broilers.........................          0.9           80         0.36
Turkeys..........................          6.8         43.6         0.36
------------------------------------------------------------------------


[[Page 16710]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.163


Table JJ-3 of Subpart JJ--Collection Efficiencies of Anaerobic Digesters
------------------------------------------------------------------------
                                                              Methane
            System type                  Cover type         collection
                                                            efficiency
------------------------------------------------------------------------
Covered anaerobic lagoon..........  Bank to bank,                  0.975
                                     impermeable.
(biogas capture)..................  Modular, impermeable            0.70
Complete mix, fixed film, or plug   Enclosed Vessel.....            0.99
 flow digester.
------------------------------------------------------------------------


  Table JJ-4 of Subpart JJ--Nitrous Oxide Emission Factors (kg N2O-N/kg
                                 Kjdl N)
------------------------------------------------------------------------
                                                                 N2O
                  Waste management system                      emission
                                                                factor
------------------------------------------------------------------------
Aerobic Treatment (forced aeration)........................        0.005
Aerobic Treatment (natural aeration).......................         0.01
Digester...................................................            0
Uncovered Anaerobic Lagoon.................................            0
Cattle Deep Bed (active mix)...............................         0.07
Cattle Deep Bed (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

[[Page 16711]]

 
Deep Pit...................................................        0.002
Dry Lot....................................................         0.02
Liquid/Slurry..............................................        0.005
Poultry with bedding.......................................        0.001
Poultry without bedding....................................        0.001
Solid Storage..............................................        0.005
------------------------------------------------------------------------

Subpart KK--Supplies of Coal


Sec.  98.370  Definition of the source category.

    (a) This source category comprises coal mines, coal importers, coal 
exporters, and waste coal reclaimers.
    (b) Coal mine means any active U.S. coal mine engaged in the 
production of coal within the U.S. during the calendar year regardless 
of the rank of coal produced, e.g., bituminous, sub-bituminous, 
lignite, anthracite. Any coal mine categorized as an active coal mine 
by MSHA is included.
    (c) Coal importer has the same meaning given in Sec.  98.6 and 
includes any U.S. coal mining company, wholesale coal dealer, retail 
coal dealer, or other organization that imports coal into the U.S. 
``Importer'' includes the person primarily liable for the payment of 
any duties on the merchandise or an authorized agent acting on his or 
her behalf.
    (d) Coal exporter has the same meaning given in Sec.  98.6 and 
includes any U.S. coal mining company, wholesale coal dealer, retail 
coal dealer, or other organization that exports coal from the U.S.
    (e) Waste coal reclaimer means any U.S. facility that reclaims or 
recovers waste coal from waste coal piles from previous mining 
operations and sells or delivers to an end-user.


Sec.  98.371  Reporting threshold.

    Any supplier of coal who meets the requirements of Sec.  98.2(a)(4) 
must report GHG emissions.


Sec.  98.372  GHGs to report.

    You must report the CO2 emissions that would result from 
the complete combustion or oxidation of coal supplied during the 
calendar year.


Sec.  98.373  Calculating GHG emissions.

    (a) For coal mines producing 100,000 short tons of coal or more 
annually, the estimate of CO2 emissions shall be calculated 
using either Calculation Methodology 1 or Calculation Methodology 2 of 
this subpart.
    (b) For coal mines producing less than 100,000 short tons of coal 
annually, and for coal exporters, coal importers, and waste coal 
reclaimers; CO2 emissions shall be calculated using either 
Calculation Methodology 1, 2, or 3 of this subpart.
    (c) For Calculation Methodology 1, 2, and 3 of this subpart, 
emissions of CO2 shall be calculated using Equation KK-1 of 
this section. The difference between Calculation Methodology 1, 2, and 
3 of this subpart, is the method for determining the carbon content in 
coal, as specified in paragraphs (d), (e), and (f) of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.164

Where:

CO2 = Annual CO2 mass emissions from the 
combustion of coal (metric tons/yr).
44/12 = Ratio of molecular weights, CO2 to carbon.
Mass = Quantity of coal produced from company records (short tons/
yr).
Carbon = Annual weighted average fraction of carbon in the coal 
(decimal value).
0.907 = Conversion factor from short tons to metric tons.

    (d) For coal mines using Calculation Methodology 1 of this subpart, 
the annual weighted average of the mass fraction of carbon in the coal 
shall be based on daily measurements and calculated using Equation KK-2 
of this section. For importers, exporters, and waste coal reclaimers 
using Methodology 1 of this subpart, measurements of each shipment can 
be used in place of daily measurements:
[GRAPHIC] [TIFF OMITTED] TP10AP09.165

Where:

Carbon = Annual mass fraction of coal carbon (dimensionless).
Xi = Daily or per shipment mass fraction of carbon in coal for day i 
measured by ultimate analysis (decimal value).
Yi = Amount of coal supplied on day i(short tons) as measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short tons).

    (e) For coal mines using Calculation Methodology 2 of this subpart, 
the annual weighted average of the mass fraction of carbon in the coal 
shall be calculated on the basis of daily measurements of the gross 
calorific value (GCV) of the coal and a statistical relationship 
between carbon content and GCV (higher heating value). For importers, 
exporters, and waste coal reclaimers using Calculation Methodology 2 of 
this subpart, measurements of each shipment can be used in place of 
daily measurements.
    (1) Equation KK-3 shall be used to determine the weighted annual 
average GCV of the coal, and the individual daily or per shipment 
values shall be determined according to the monitoring methodology for 
gross calorific values in Sec.  98.374(f).
    (2) The statistical relationship between GCV and carbon content 
shall be established according to the requirements in Sec.  98.374(f).
    (3) The estimated annual weighted average of the mass fraction of 
carbon in the coal shall be calculated by applying the slope 
coefficient, determined according to the requirements of Sec.  
98.374(f)(4), to the weighted annual average GCV of the coal determined 
according to Equation KK-3 of this section.
    (f) For coal mines using Calculation Methodology 3 of this subpart, 
the annual weighted average of the mass fraction of carbon in the coal 
shall be calculated on the basis of daily measurements of GCV of the 
coal and a default fraction of carbon in coal from Table KK-1 of this 
subpart. For importers, exporters, and waste coal reclaimers using 
Methodology 3 of this subpart, measurements of each shipment can be 
used in place of daily measurements.
    (1) Equation KK-3 shall be used to determine the weighted annual 
average

[[Page 16712]]

GCV of the coal, and the individual daily or per shipment values shall 
be determined according to the monitoring methodology for gross 
calorific values in Sec.  98.374(g).
    (2) The estimated annual weighted average of the mass fraction of 
carbon in the coal shall be identified from Table KK-1 of this subpart 
using annual weighted GCV of the coal determined according to Equation 
KK-3 of this section.
    (g) For Calculation Methodologies 2 and 3 of this subpart, the 
weighted annual average gross calorific value (GCV) or higher heating 
value of the coal shall be calculated using Equation KK-3 of this 
section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.166

Where:

GCV = the weighted annual average gross calorific value or higher 
heating value of the coal (Btu/lb).
zi = Daily or per shipment GCV or HHV of coal for day i 
measured by proximate analysis (decimal value).
yi = Amount of coal supplied on day i (short tons) as 
measured.
n = Number of operating days per year.
S = Total coal supplied during the year (short tons).


Sec.  98.374  Monitoring and QA/QC requirements.

    (a) The most current version of the NIST Handbook published by 
Weights and Measures Division, National Institute of Standards and 
Technology shall be used as the standard practice for all coal 
weighing.
    (b) For all coal mines, the quantity of coal shall be determined as 
the total mass of coal in short tons sold and removed from the facility 
during the calendar year.
    (c) For coal importers, the quantity of coal shall be determined as 
the total mass of coal in short tons imported into the U.S. during the 
calendar year, as reported to U.S. Customs.
    (d) For coal exporters, the quantity of coal shall be determined as 
the total mass of coal in short tons sold and exported from the U.S., 
as reported to U.S. Customs.
    (e) For waste coal reclaimers, the quantity of coal shall be 
determined as the total mass of coal in short tons sold for use as 
reported to state agencies.
    (f) For reporters using Calculation Methodology 1 of this subpart, 
the carbon content shall be determined as follows:
    (1) Representative coal samples shall be collected daily or per 
shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or 
D7430-08 from coal loaded on the conveyor belt.
    (2) Daily or per shipment coal carbon content shall be determined 
using ASTM D5373 (Test Methods for Instrumental Determination of Carbon 
Hydrogen and Nitrogen in Laboratory Samples of Coal and Coke).
    (g) For reporters using Calculation Methodology 2 of this subpart, 
the carbon content shall be determined as follows:
    (1) Representative samples of coal shall be collected daily or per 
shipment using ASTM D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or 
D7430-08.
    (2) Coal gross calorific value (GCV) shall be determined on the set 
of samples collected in paragraph (f)(1) of this section using ASTM 
D5865-07a, ``Standard Test Method for Gross Calorific Value of Coal and 
Coke to record the heat content of the coal produced.
    (3) Coal carbon content shall be determined at a minimum once each 
month on one set of daily or per shipment samples collected in 
paragraph (f)(1) of this section using ASTM D5373 (Test Methods for 
Instrumental Determination of Carbon Hydrogen and Nitrogen in 
Laboratory Samples of Coal and Coke).
    (4) The individual samples for which both carbon content and GCV 
were determined according to paragraphs (f)(2) and (f)(3) of this 
section respectively, shall be used to establish a statistical 
relationship between the heat content and the carbon content of the 
coal produced. The owner or operator shall statistically plot the 
correlation of Btu/lb of coal vs. percent carbon (as a decimal value), 
where the x-axis is Btu/lb coal and the y-axis is percent carbon (as 
decimal value), then fit a line to the data points, then calculate the 
slope and the coefficient of determination, and the R-square (R\2\) of 
that line using the Btu/lb and percent carbon.
    (5) Calculation Methodology 2 of this subpart can be used only if 
all of the following four conditions are met:
    (i) At least 12 samples per reporting year from 12 different months 
of data must be used to construct the correlation graph.
    (ii) The correlation graph must be constructed using all paired 
data points from the first reporting year and all subsequent reporting 
years.
    (iii) There must be a linear relationship between percent carbon 
and Btu/lb of coal.
    (iv) For the second and subsequent years, R-square (R\2\) must be 
greater than or equal to 0.90. This R-square requirement does not apply 
during the first reporting year.
    (6) If all of the conditions specified in paragraph (f)(5) of this 
section are met, the weighted annual average gross calorific value or 
higher heating value (Btu/lb) calculated according to Equation KK-3 of 
this section shall be used to determine the corresponding annual 
average coal carbon content using the correlation graph plotted 
according to paragraph (f)(4) of this section.
    (h) Reporters complying with Calculation Methodology 3 of this 
subpart shall determine gross calorific value of the coal by collecting 
representative daily or per shipment samples of coal using either ASTM 
D4916-04, D6609-07, D6883-04, D7256/D7256M-06a, or D7430-08; and 
testing using ASTM D5865-07a, ``Standard Test Method for Gross 
Calorific Value of Coal and Coke to record the heat content of the coal 
produced.''
    (i) Coal exporters shall calculate carbon content for each shipment 
of coal using information on the carbon content of the exported coal 
provided by the source mine, according to Calculation Methodology 1, 2, 
or 3 of this subpart, as appropriate.
    (j) Coal importers shall calculate carbon content for each shipment 
of coal using Calculation Methodology 1, 2, or 3 of this subpart.
    (k) Waste coal reclaimers shall calculate carbon content for each 
shipment of coal using Calculation Methodology 1, 2, or 3 of this 
subpart.
    (l) Each owner or operator using mechanical coal sampling systems 
shall perform quality assurance and quality control according to ASTM 
D4702-07 and ASTM D6518-07.


Sec.  98.375  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.
    (b) Whenever a quality-assured value for coal production during any 
time period is unavailable, you must use the average of the parameter 
values recorded immediately before and after the missing data period in 
the calculations.
    (c) Facilities using Calculation Methodology 1 of this subpart 
shall develop the statistical relationship between GCV and carbon 
content according to Sec.  98.274(e), and use this statistical 
relationship to estimate daily carbon content for any day for which

[[Page 16713]]

measured carbon content is not available.
    (d) Facilities, importers and exporters using Calculation 
Methodology 2 or 3 of this subpart shall estimate the missing GCV 
values based on a weighted average value for the previous seven days.
    (e) Estimates of missing data shall be documented and records 
maintained showing the calculations.


Sec.  98.376  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information.
    (a) Each coal mine owner or operator shall report the following 
information for each coal mine:
    (1) The name and MSHA ID number of the mine.
    (2) The name of the operating company.
    (3) Annual CO2 emissions.
    (4) By rank, the total annual quantity in tons of coal produced.
    (5) The annual weighted carbon content of the coal as calculated 
according to Sec.  98.373.
    (6) If Calculation Methodology 1 of this subpart was used to 
determine CO2 mass emissions, you must report daily mass 
fraction of carbon in coal measured by ultimate analysis and daily 
amount of coal supplied.
    (7) If Calculation Methodology 2 of this subpart was used to 
determine CO2 mass emissions, you must report:
    (i) All of the data used to construct the carbon vs. Btu/lb 
correlation graph.
    (ii) Slope of the correlation line.
    (iii) The R-squared (R\2\) value of the correlation.
    (8) If Calculation Methodology 3 of this subpart was used to 
determine CO2 mass emissions, you must report daily GCV of 
coal measured by proximate analysis and daily amount of coal supplied.
    (b) Coal importers shall report the following information at the 
corporate level:
    (1) The total annual quantity in tons of coal imported into the 
U.S. by the importer, by rank, and country of origin.
    (2) Annual CO2 emissions.
    (3) The annual weighted carbon content of the coal as calculated 
according to Sec.  98.373.
    (4) If Calculation Methodology 1 of this subpart was used to 
determine CO2 mass emissions, you must report mass fraction 
of carbon in coal per shipment measured by ultimate analysis and amount 
of coal supplied per shipment.
    (5) If Calculation Methodology 2 of this subpart was used to 
determine CO2 mass emissions, you must report:
    (i) All of the data used to construct the carbon vs. Btu/lb 
correlation graph.
    (ii) Slope of the correlation line.
    (iii) The R-squared (R\2\) value of the correlation.
    (6) If Calculation Methodology 3 of this subpart was used to 
determine CO2 mass emissions, you must report GCV in coal 
per shipment measured by proximate analysis and amount of coal supplied 
per shipment.
    (d) Coal exporters shall report the following information at the 
corporate level:
    (1) The total annual quantity in tons of coal exported from the 
U.S. by rank and by coal producing company and mine.
    (2) Annual CO2 emissions.
    (3) The annual weighted carbon content of the coal as calculated 
according to Sec.  98.373.
    (4) If Calculation Methodology 1 of this subpart was used to 
determine CO2 mass emissions, you must report mass fraction 
of carbon in coal per shipment measured by ultimate analysis and amount 
of coal supplied per shipment.
    (5) If Calculation Methodology 2 of this subpart was used to 
determine CO2 mass emissions, you must report:
    (i) All of the data used to construct the carbon vs. Btu/lb 
correlation graph.
    (ii) Slope of the correlation line.
    (iii) The R-squared (R\2\) value of the correlation.
    (6) If Calculation Methodology 3 of this subpart was used to 
determine CO2 mass emissions, you must report GCV in coal 
per shipment measured by proximate analysis and amount of coal supplied 
per shipment.
    (e) Waste coal reclaimers shall report the following information 
for each reclamation site:
    (1) By rank, the total annual quantity in tons of waste coal 
produced.
    (2) Mine and state of origin if waste coal is reclaimed from mines 
that are no longer operating.
    (3) Annual CO2 emissions.
    (4) The annual weighted carbon content of the coal as calculated 
according to Sec.  98.373.
    (5) If Calculation Methodology 1 of this subpart was used to 
determine CO2 mass emissions, you must report mass fraction 
of carbon in coal per shipment measured by ultimate analysis and amount 
of coal supplied per shipment.
    (6) If Calculation Methodology 2 of this subpart was used to 
determine CO2 mass emissions, you must report:
    (i) All of the data used to construct the carbon vs. Btu/lb 
correlation graph.
    (ii) Slope of the correlation line.
    (iii) The R-squre (R \2\) value of the correlation.
    (7) If Calculation Methodology 3 of this subpart was used to 
determine CO2 mass emissions, you must report GCV in coal 
per shipment measured by proximate analysis and amount of coal supplied 
per shipment.


Sec.  98.377  Records that must be retained.

    In addition to the records required by Sec.  98.3(g), you must 
retain the following information:
    (a) A complete record of all measured parameters used in the 
reporting of fuel quantities, including all sample results and 
documentation to support quantities that are reported under this part.
    (b) Records documenting all calculations of missing data.
    (c) Calculations and worksheets used to estimate the CO2 
emissions.
    (d) Calibration records of any instruments used on site and 
calibration records of scales or other equipment used to weigh coal.


Sec.  98.378  Definitions.

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

  Table KK-1 of Subpart KK--Default Carbon Content of Coal for Method 3
                            (CO2 lbs/MMBtu1)
------------------------------------------------------------------------
                                                           Mass fraction
      Weighted annual average GCV of coal Btu/lb\1\        of carbon in
                                                          coal (decimal)
------------------------------------------------------------------------
2,000...................................................          0.1140
2,250...................................................          0.1283
2,500...................................................          0.1425
2,750...................................................          0.1568
3,000...................................................          0.1710
3,250...................................................          0.1853
3,500...................................................          0.1995
3,750...................................................          0.2138
4,000...................................................          0.2280
4,250...................................................          0.2423
4,500...................................................          0.2565
4,750...................................................          0.2708
5,000...................................................          0.2850
5,250...................................................          0.2993
5,500...................................................          0.3135
5,750...................................................          0.3278
6,000...................................................          0.3420
6,250...................................................          0.3563
6,500...................................................          0.3705
6,750...................................................          0.3848
7,000...................................................          0.3990
7,250...................................................          0.4133
7,500...................................................          0.4275
7,750...................................................          0.4418
8,000...................................................          0.4560
8,250...................................................          0.4703
8,500...................................................          0.4845
8,750...................................................          0.4988
9,000...................................................          0.5130
9,250...................................................          0.5273
9,500...................................................          0.5415
9,750...................................................          0.5558
10,000..................................................          0.5700
10,250..................................................          0.5843
10,500..................................................          0.5985
10,750..................................................          0.6128

[[Page 16714]]

 
11,000..................................................          0.6270
11,250..................................................          0.6413
11,500..................................................          0.6555
11,750..................................................          0.6698
12,000..................................................          0.6840
12,250..................................................          0.6983
12,500..................................................          0.7125
12,750..................................................          0.7268
13,000..................................................          0.7410
13,250..................................................          0.7553
13,500..................................................          0.7695
13,750..................................................          0.7838
14,000..................................................          0.7980
14,250..................................................          0.8123
14,500..................................................          0.8265
14,750..................................................          0.8408
15,000..................................................          0.8550
15,250..................................................          0.8693
15,500..................................................          0.8835
------------------------------------------------------------------------
\1\ Based on high heating values.

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 coal-based liquids.
    (a) A producer is the owner or operator of a coal-to-liquids 
facility. A coal-to-liquids facility is any facility engaged in 
coverting coal into liquid fuels such as gasoline and diesel using the 
Fischer-Tropsch process or an alternative process, involving conversion 
of coal into gas and then into liquids or conversion of coal directly 
into liquids (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-based liquid fuels 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 coal-based liquids during the 
calendar year.


Sec.  98.383  Calculating GHG emissions.

    (a) Coal-to-liquid producers, importers and exporters must 
calculate CO2 emissions using Equation LL-1 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.167

Where:

CO2 = Annual CO2 mass emissions from the 
combustion of fuel (metric tons).
Producti = Total annual volume (in standard barrels) of a 
coal-based liquid fuel ``i'' produced, imported, or exported.
EFi = CO2 emission factor (metric tons 
CO2 per barrel) specific to liquid fuel ``i''.

    (b) The emission factor (EF) for each type of coal-based liquid 
shall be determined using either of the calculation methodologies 
described in paragraphs (a) and (b) of this section. The same 
calculation methodology must be used for the entire volume of the 
product for the reporting year.
    (1) Calculation Methodology 1. Use the default CO2 
emission factor listed in column C of Table MM-1 of subpart MM 
(Suppliers of Petroleum Products) that most closely represents the 
coal-based liquid.
    (2) Calculation Methodology 2. Develop a CO2 emission 
factor according to Equation LL-2 of this section using direct 
measurement of density and carbon share according to methods set forth 
in Sec.  98.394(c) or a combination of direct measurement and the 
default factor listed in columns A or B of Table MM-1 of subpart MM 
that most closely represents the coal-based liquid.
[GRAPHIC] [TIFF OMITTED] TP10AP09.168

Where:

EF = Emission factor of coal-based liquid (metric tons 
CO2 per barrel).
Density = Density of coal-based liquid (metric tons per barrel).
Wt% = Percent of total mass that carbon represents in coal-based 
liquid.


Sec.  98.384  Monitoring and QA/QC requirements.

    (a) Producers must measure the quantity of coal-based liquid fuels 
using procedures for flow meters as described in subpart MM of this 
part.
    (b) Importers and exporters must determine the quantity of coal-
based liquid fuels using sales contract information on the volume 
imported or exported during the reporting period.
    (1) The quantity of coal-based liquid fuels must be measured using 
sales contract information.
    (2) The minimum frequency of the measurement of quantities of coal-
based liquid fuels shall be the number of sales contracts executed in 
the reporting period.
    (c) All flow meters and product monitors shall be calibrated prior 
to use for reporting, using a suitable method published by a consensus 
standards organization (e.g., ASTM, ASME, API, NAESB, or others). 
Alternatively, calibration procedures specified by the flow meter 
manufacturer may be used. Fuel flow meters shall be recalibrated either 
annually or at the minimum frequency specified by the manufacturer.
    (d) Reporters shall take the following steps to ensure the quality 
and accuracy of the data reported under these rules:
    (1) For all volumes of coal-based liquid fuels, reporters shall 
maintain meter and such other records as are normally maintained in the 
course of business to document fuel flows.
    (2) For all estimates of CO2 mass emissions, reporters 
shall maintain calculations and worksheets used to calculate the 
emissions.


Sec.  98.385  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the 
reporting of fuel volumes and the calculations of CO2 mass 
emissions is required. Therefore, whenever a quality-assured 
measurement of the quantity of coal-based liquid fuels is unavailable a 
substitute data value for the missing quantity measurement shall be 
calculated and used in the calculations.
    (b) For coal-to-liquids facilities, the last quality assured 
reading shall be

[[Page 16715]]

used. If substantial variation in the flow rate is observed or if a 
quality assured measurement of quantity is unavailable for any other 
reason, the average of the last and the next quality assured reading 
shall be used to calculate a substitute measurement of quantity.
    (c) Calculation of substitute data shall be documented and records 
maintained showing the calculations.


Sec.  98.386  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information:
    (a) Producers shall report the following information for each 
facility:
    (1) The total annual volume of each coal-based liquid supplied to 
the economy (in standard barrels).
    (2) The total annual CO2 emissions in metric tons 
associated with each coal-based liquid supplied to the economy, 
calculated according to Sec.  98.383(a).
    (b) Importers shall report the following information at the 
corporate level:
    (1) The total annual volume of each imported coal-based liquid (in 
standard barrels).
    (2) The total annual CO2 emissions in metric tons 
associated with each imported coal-based liquid, calculated according 
to Sec.  98.383(a).
    (c) Exporters shall report the following information at the 
corporate level:
    (1) The total annual volume of each exported coal-based liquid (in 
standard barrels).
    (2) The total annual CO2 emissions in metric tons 
associated with each exported coal-based liquid, calculated according 
to Sec.  98.383(a).


Sec.  98.387  Records that must be retained.

    Reporters shall retain copies of all reports submitted to EPA. 
Reporters shall maintain records to support volumes that are reported 
under this part, including records documenting any calculation of 
substitute measured data. Reporters shall also retain calculations and 
worksheets used to estimate the CO2 equivalent of the 
volumes reported under this part. These records shall be retained for 
five (5) years similar to 40 CFR part 80 fuels compliance reporting 
program.


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.
    (a) A petroleum refinery is any facility engaged in producing 
gasoline, kerosene, distillate fuel oils, residual fuel oils, 
lubricants, asphalt (bitumen) or other products through distillation of 
petroleum or through redistillation, cracking, or reforming of 
unfinished petroleum derivatives.
    (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 blender or refiner of refined or semi-refined petroleum products.
    (d) Exporter has the same meaning given in Sec.  98.6 and includes 
any blender or refiner of refined or semi-refined petroleum products.


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.

    You 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, if you are a refiner, you 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) Except as provided in paragraph (g) 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] TP10AP09.169

Where:

CO2i = Annual potential CO2 emissions from the 
complete combustion or oxidation of each petroleum product or 
natural gas liquid ``i'' (metric tons).
Producti = Total annual volume of 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).

    (b) Except as provided in paragraph (g) of this secton, any refiner 
shall calculate CO2 emissions from each non-crude feedstock 
using Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.170

Where:

CO2j = Annual potential CO2 emissions from the 
complete combustion or oxidation of each non-crude feedstock ``j'' 
(metric tons).
Feedstockj = Total annual volume of a petroleum product 
or natural gas liquid ``j'' that enters the refinery as a feedstock 
to be further refined or otherwise used on site (barrels). Any waste 
feedstock (see definitions) that enters the refinery must also be 
included.
EFj = Feedstock-specific CO2 emission factor 
(metric tons CO2 per barrel).

    (c) Refiners shall calculate CO2 emissions from all 
biomass co-processed with petroleum feedstocks using Equation MM-3 of 
this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.171

Where:

CO2m = Annual potential CO2 emissions from the 
complete combustion or oxidation of biomass ``m'' (metric tons).
Biomassm = Total annual volume 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 (barrels).
EFm = Biomass-specific CO2 emission factor 
(metric tons CO2 per barrel).

    (d) Refiners shall calculate total CO2 emissions from 
all products using Equation MM-4 of this section.

[[Page 16716]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.172

Where:

CO2r = Total annual potential CO2 emissions 
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 potential CO2 emissions from the 
complete combustion or oxidation of each petroleum product or 
natural gas liquid ``i'' (metric tons).
CO2j = Annual potential CO2 emissions from the 
complete combustion or oxidation of each non-crude feedstock ``j'' 
(metric tons).
CO2m = Annual potential CO2 emissions from the 
complete combustion or oxidation of biomass ``m'' (metric tons).

    (e) Importers and exporters shall calculate total 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] TP10AP09.173

Where:

CO2i = Annual potential CO2 emissions from the 
complete combustion or oxidation of each petroleum product or 
natural gas liquid ``i'' (metric tons).
CO2x = Total annual potential CO2 emissions 
from the complete combustion or oxidation of all petroleum products 
and natural gas liquids.

    (f) Except as provided in paragraph (g) of this section, the 
emission factor (EF) for each petroleum product and natural gas liquid 
shall be determined using either of the calculation methodologies 
described in paragraphs (f)(1) or (f)(2) of this section. The same 
calculation methodology must be used for the entire volume of the 
product for the reporting year.
    (1) Calculation Methodology 1. Use the appropriate default 
CO2 emission factors listed in column C of Tables MM-1 and 
MM-2 of this subpart.
    (2) Calculation Methodology 2. 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) or a 
combination of direct measurements and default factors listed in 
columns A and B of Tables MM-1 and MM-2 of this subpart.
[GRAPHIC] [TIFF OMITTED] TP10AP09.174

Where:

EF = Emission factor of petroleum or natural gas product or non-
crude feedstock (metric tons CO2 per barrel).
Density = Density of petroleum product or natural gas liquid or non-
crude feedstock (metric tons per barrel).
Wt% = Percent of total mass that carbon represents in petroleum 
product or natural gas liquid or non-crude feedstock.
44/12 = Conversion factor for carbon to carbon dioxide.

    (g) In the event that some portion of a petroleum product or 
feedstock is biomass-based and was not derived by co-processing biomass 
and petroleum feedstocks together (i.e., the petroleum product or 
feedstock was produced by blending a petroleum-based product with a 
biomass-based product), the reporting party shall calculate emissions 
for the petroleum product or feedstock according to one of the methods 
in paragraph (g)(1) or (2) of this section, as appropriate.
    (1) A reporting party using Calculation Methodology 1 of this 
subpart to determine the emission factor of a petroleum product shall 
calculate the CO2 emissions associated with that product 
using Equation MM-7 of this section in place of Equation MM-1 of this 
section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.175

Where:

CO2i = Annual potential CO2 emissions from the 
complete combustion or oxidation of petroleum product ``i'' (metric 
tons).
Producti = Total annual volume of 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 MM-1.
%Voli = Percent volume of product ``i'' that is 
petroleum-based.

    (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-8 in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.176

Where:

CO2j = Annual potential CO2 emissions from the 
complete combustion or oxidation of each non-crude feedstock ``j'' 
(metric tons).
Feedstockj = Total annual volume of a 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.

    (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-9 of this section in place of Equation MM-1 of this section.

[[Page 16717]]

[GRAPHIC] [TIFF OMITTED] TP10AP09.177

Where:

CO2i = Annual potential CO2 emissions from the 
complete combustion or oxidation of product ``i'' (metric tons).
Producti = Total annual volume of 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-3 that most closely represents the component of product ``i'' 
that is biomass-based.
%Volm = Percent volume of petroleum product ``i'' that is 
biomass-based.

    (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-10 in place of Equation MM-2 of this section.
[GRAPHIC] [TIFF OMITTED] TP10AP09.178

Where:

CO2j = Annual potential CO2 emissions from the 
complete combustion or oxidation of non-crude feedstock ``j'' 
(metric tons).
Feedstockj = Total annual volume of non-crude feedstock 
``j'' that enters the refinery as a feedstock to be further refined 
or otherwise used on site (barrels). Any waste feedstock (see 
definitions) that enters the refinery must also be included.
EFj = Feedstock-specific CO2 emission factor 
(metric tons CO2 per barrel).
EFm = Default CO2 emission factor from Table 
MM-3 of subpart MM that most closely represents the component of 
product ``i'' that is biomass-based.
%Volm = Percent volume of non-crude feedstock ``j'' that 
is biomass-based.

    (h) Refiners shall use the most appropriate default CO2 
emission factor (EFm) for biomass in Table MM-3 to calculate 
CO2 emissions in paragraph (c) of this section.


Sec.  98.394  Monitoring and QA/QC requirements.

    (a) The quantity of petroleum products, natural gas liquids, 
biomass, and all feedstocks shall be determined using either a flow 
meter or tank gauge, depending on the reporters existing equipment and 
preferences.
    (1) For flow meters any one of the following test methods can be 
used to determine quantity:
    (i) Ultra-sonic flow meter: AGA Report No. 9 (2007)
    (ii) Turbine meters: American National Standards Institute, ANSI/
ASME MFC-4M-1986
    (iii) Orifice meters: American National Standards Institute, AINSI/
API 2530 (also called AGA-3) (1991)
    (iv) Coriolis meters: ASME MFC-11 (2006)
    (2) For tank gauges any one of the following test methods can be 
used to determine quantity:
    (i) API-2550: Measurements and Calibration of Petroleum Storage 
Tanks (1965)
    (ii) API MPMS 2.2: A Manual of Petroleum Measurement Standards 
(1995)
    (iii) API-653: Tank Inspection, Repair, Alteration and 
Reconstruction, 3rd edition (2008)
    (b) All flow meters and tank gauges shall be calibrated prior to 
use for reporting, using a suitable method published by a consensus 
standards organization (e.g., ASTM, ASME, API, or NAESB). 
Alternatively, calibration procedures specified by the flow meter 
manufacturer may be used. Product flow meters and tank gauges shall be 
recalibrated either annually or at the minimum frequency specified by 
the manufacturer, whichever is more frequent.
    (c) For Calculation Methodology 2 of this subpart, samples of each 
petroleum product and natural gas liquid shall be taken each month for 
the reporting year. The composite sample shall be tested at the end of 
the reporting year using ASTM D1298 (2003), ASTM D1657-02 (2007), ASTM 
D4052-96 (2002)el, ASTM D5002-99 (2005), or ASTM D5004-89 (2004)el for 
density, as appropriate, and ASTM D5291 (2005) or ASTM D6729-(2004)el 
for carbon share, as appropriate (see Technical Support Document). 
Reporters must sample seasonal gasoline each month of the season and 
then test the composite sample at the end of the season.


Sec.  98.395  Procedures for estimating missing data.

    Whenever a metered or quality-assured value of the quantity of 
petroleum products, natural gas liquids, biomass, or feedstocks during 
any period is unavailable, a substitute data value for the missing 
quantity measurement shall be used in the calculations contained in 
Sec.  98.393.
    (a) For marine-imported and exported refined and semi-refined 
products, the reporting party shall attempt to reconcile any 
differences between ship and shore volume readings. If the reporting 
party is unable to reconcile the readings, the higher of the two volume 
values shall be used for emission calculation purposes.
    (b) For pipeline imported and exported refined and semi-refined 
products, the last valid volume reading based on the company's 
established procedures for purposes of product tracking and billing 
shall be used. If the pipeline experiences substantial variations in 
flow rate, the average of the last valid volume reading and the next 
valid volume reading shall be used for emission calculation purposes.
    (c) For petroleum refineries, the last valid volume reading based 
on the facility's established procedures for purposes of product 
tracking and billing shall be used. If substantial variation in the 
flow rate is observed, the average of the last and the next valid 
volume reading shall be used for emission calculation purposes.


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) CO2 emissions in metric tons for each petroleum 
product and natural gas liquid (ex refinery gate), calculated according 
to Sec.  98.393(a) or (g).
    (2) CO2 emissions in metric tons for each petroleum 
product or natural gas liquid that enters the refinery annually as a 
feedstock to be further refined or otherwise used on site, calculated 
according to Sec.  98.393(b) or (g).
    (3) CO2 emissions in metric tons from each type of 
biomass feedstock co-processed with petroleum feedstocks, calculated 
according to Sec.  98.393(c).
    (4) The total sum of CO2 emissions from all products, 
calculated according to Sec.  98.393(d).
    (5) The total volume of each petroleum product and natural gas 
liquid associated with the CO2 emissions reported in 
paragraphs (a)(1)

[[Page 16718]]

and (2) of this section, seperately, and the volume of the biomass-
based component of each petroleum product reported in this paragraph 
that was produced by blending a petroleum-based product with a biomass-
based product. If a determination cannot be made whether the material 
is a petroleum product or a natural gas liquid, it shall be reported as 
a petroleum product.
    (6) The total volume of any biomass co-processed with a petroleum 
product associated with the CO2 emissions reported in 
paragraph (a)(3) of this section.
    (7) The measured density and/or mass carbon share for any petroleum 
product or natural gas liquid for which CO2 emissions were 
calculated using Calculation Methodology 2 of this subpart, along with 
the selected method from Sec.  98.394(c) and the calculated EF.
    (8) The total volume of each distillate fuel oil product or 
feedstock reported in paragraph (a)(5) of this section that contains 
less than 15 ppm sulfur content and is free from marker solvent yellow 
124 and dye solvent red 164.
    (9) All of the following information for all crude oil feedstocks 
used at the refinery:
    (i) Batch volume (in standard barrels).
    (ii) API gravity of the batch.
    (iii) Sulfur content of the batch.
    (iv) Country of origin of the batch.
    (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) CO2 emissions in metric tons for each imported 
petroleum product and natural gas liquid, calculated according to Sec.  
98.393(a).
    (2) Total sum of CO2 emissions, calculated according to 
Sec.  98.393(e).
    (3) The total volume of each imported petroleum product and natural 
gas liquid associated with the CO2 emissions reported in 
paragraph (b)(1) of this section as well as the volume of the biomass-
based component of each petroleum product reported in this paragraph 
that was produced by blending a petroleum-based product with a biomass-
based product. If you cannot determine whether the material is a 
petroleum product or a natural gas liquid, you shall report it as a 
petroleum product.
    (4) The measured density and/or mass carbon share for any imported 
petroleum product or natural gas liquid for which CO2 
emissions were calculated using Calculation Methodology 2 of this 
subpart, along with the selected method from Sec.  98.394(c) and the 
calculated EF.
    (5) The total volume of each distillate fuel oil product reported 
in paragraph (b)(1) of this section that contains less than 15 ppm 
sulfur content and is free from marker solvent yellow 124 and dye 
solvent red 164.
    (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) CO2 emissions in metric tons for each exported 
petroleum product and natural gas liquid, calculated according to Sec.  
98.393(a).
    (2) Total sum of CO2 emissions, calculated according to 
Sec.  98.393(e).
    (3) The total volume of each exported petroleum product and natural 
gas liquid associated with the CO2 emissions reported in 
paragraph (c)(1) of this section as well as the volume of the biomass-
based component of each petroleum product reported in this paragraph 
that was produced by blending a petroleum-based product with a biomass-
based product. If you cannot determine whether the material is a 
petroleum product or a natural gas liquid, you shall report it as a 
petroleum product.
    (4) The measured density and/or mass carbon share for any petroleum 
product or natural gas liquid for which CO2 emissions were 
calculated using Calculation Methodology 2 of this subpart, along with 
the selected method from Sec.  98.394(c) and the calculated EF.
    (5) The total volume of each distillate fuel oil product reported 
in paragraph (c)(1) of this section that contains less than 15 ppm 
sulfur content and is free from marker solvent yellow 124 and dye 
solvent red 164.


Sec.  98.397  Records that must be retained.

    (a) Any reporter described in Sec.  98.391 shall retain copies of 
all reports submitted to EPA under Sec.  98.396. In addition, any 
reporter under this subpart 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 volumes that are 
reported under this part, including records documenting any estimations 
of missing metered data. For all volumes of petroleum products, natural 
gas liquids, biomass, and feedstocks, reporters shall maintain meter 
and other records normally maintained in the course of business to 
document product and feedstock flows.
    (c) Reporters shall also retain laboratory reports, calculations 
and worksheets used to estimate the CO2 emissions of the 
volumes reported under this part.
    (d) Estimates of missing data shall be documented and records 
maintained showing the calculations.
    (e) 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.

                    Table MM-1 of Subpart MM--Default CO2 Factors for Petroleum Products 1, 2
----------------------------------------------------------------------------------------------------------------
                                                                                                     Column C:
                                                                                                     emission
                                                                     Column A:                        factor
                                                                      density        Column B:     (metric tons
           Refined and semi-refined petroleum products             (metric tons/   carbon share      CO2/bbl)
                                                                       bbl)         (% of mass)     [Column A *
                                                                                                  Column B/100 *
                                                                                                      44/12]
----------------------------------------------------------------------------------------------------------------
Motor Gasoline \3\
----------------------------------------------------------------------------------------------------------------
    Conventional--Summer........................................            0.12           86.96            0.38
    Conventional--Winter........................................            0.12           86.96            0.37
    Reformulated--Summer........................................            0.12           86.60            0.37
    Reformulated--Winter........................................            0.12           86.60            0.37
    Finished Aviation Gasoline..................................            0.11           85.00            0.35
----------------------------------------------------------------------------------------------------------------

[[Page 16719]]

 
Blendstocks
----------------------------------------------------------------------------------------------------------------
    RBOB........................................................            0.12           86.60            0.38
    CBOB........................................................            0.12           85.60            0.37
    Others......................................................            0.11           84.00            0.34
----------------------------------------------------------------------------------------------------------------
Oxygenates
----------------------------------------------------------------------------------------------------------------
    Methanol....................................................            0.13           37.50            0.17
    GTBA........................................................            0.12           64.90            0.29
    t-butanol...................................................            0.12           64.90            0.29
    MTBE........................................................            0.12           68.20            0.29
    ETBE........................................................            0.12           70.50            0.30
    TAME........................................................            0.12           70.50            0.31
    DIPE........................................................            0.12           70.60            0.30
    Kerosene-Type Jet Fuel......................................            0.13           86.30            0.41
    Naptha-Type Jet Fuel........................................            0.12           85.80            0.39
    Kerosene....................................................            0.13           86.01            0.41
----------------------------------------------------------------------------------------------------------------
Distillate Fuel Oil
----------------------------------------------------------------------------------------------------------------
    Diesel No. 1................................................            0.13           86.40            0.43
    Diesel No. 2................................................            0.13           86.34            0.43
    Diesel No. 4................................................            0.15           86.47            0.46
    Fuel Oil No. 1..............................................            0.13           86.40            0.43
    Fuel Oil No. 2..............................................            0.13           86.34            0.43
    Fuel Oil No. 4..............................................            0.15           86.47            0.46
    Residual Fuel Oil No. 5 (Navy Special)......................            0.14           85.81            0.43
    Residual Fuel Oil No. 6 (a.k.a. Bunker C)...................            0.16           85.68            0.49
----------------------------------------------------------------------------------------------------------------
Petrochemical Feedstocks
----------------------------------------------------------------------------------------------------------------
     Naphthas (< 401 [deg]F)....................................            0.12           84.11            0.36
    Other Oils (> 401 [deg]F)...................................            0.13           86.34            0.43
    Special Naphthas............................................            0.12           84.76            0.38
    Lubricants..................................................            0.14           85.80            0.45
    Waxes.......................................................            0.13           85.29            0.40
    Petroleum Coke..............................................            0.07           92.28            0.23
    Asphalt and Road Oil........................................            0.16           83.47            0.50
    Still Gas...................................................            0.07           24.40            0.06
    Ethane......................................................            0.06           80.00            0.17
    Ethylene....................................................            0.09           85.71            0.28
    Propane.....................................................            0.08           81.80            0.24
    Propylene...................................................            0.08           85.71            0.26
    Butane......................................................            0.09           82.80            0.28
    Butylene....................................................            0.11           85.71            0.35
    Isobutane...................................................            0.09           82.80            0.27
    Isobutylene.................................................            0.09           85.71            0.29
    Pentanes Plus...............................................            0.11           83.70            0.32
    Miscellaneous Products......................................            0.14           85.49            0.43
    Unfinished Oils.............................................            0.14           85.49            0.43
    Naphthas....................................................            0.12           85.70            0.37
    Kerosenes...................................................            0.13           85.80            0.41
    Heavy Gas Oils..............................................            0.15           85.80            0.46
    Residuum....................................................            0.16           85.70            0.51
    Waste Feedstocks............................................            0.14           85.70            0.45
----------------------------------------------------------------------------------------------------------------
\1\ In the case of transportation fuels blended with some portion of biomass-based fuel, the carbon share in
  Table MM-1 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.


[[Page 16720]]


                      Table MM-2 of Subpart MM--Default CO2 Factors for Natural Gas Liquids
----------------------------------------------------------------------------------------------------------------
                                                                                                     Column C:
                                                                                                     computed
                                                                                                     emission
                                                                     Column A:       Column B:        factor
                       Natural gas liquids                            density      carbon share    (tonnes CO2/
                                                                   tonnes/barrel    (% of mass)    bbl)  [Column
                                                                                                   A * Column B/
                                                                                                   100 * 44/12]
----------------------------------------------------------------------------------------------------------------
C2+.............................................................            0.08           81.79            0.24
C4+.............................................................            0.10           83.15            0.30
C5+.............................................................            0.11           83.70            0.32
C6+.............................................................            0.11           84.04            0.34
----------------------------------------------------------------------------------------------------------------


Table MM-3 of Subpart MM--Default CO2 Factors for Biomass-based Fuel and
                            Biomass Feedstock
------------------------------------------------------------------------
                                                             Column A:
                                                             emission
             Biomass products and feedstock                   factor
                                                           (tonnes CO2/
                                                               bbl)
------------------------------------------------------------------------
Ethanol (100%)..........................................            0.23
Biodiesel (100%, methyl ester)..........................            0.40
Rendered Animal Fat.....................................            0.37
Vegetable Oil...........................................            0.41
------------------------------------------------------------------------

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 processing plants 
and local natural gas distribution companies.
    (a) Natural Gas Processing Plants are installations designed to 
separate and recover natural gas liquids (NGLs) or other gases and 
liquids from a stream of produced natural gas through the processes of 
condensation, absorption, adsorption, refrigeration, or other methods 
and to control the quality of natural gas marketed. This does not 
include field gathering and boosting stations.
    (b) Local Distribution Companies 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.


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) Natural gas processing plants must report the CO2 
emissions that would result from the complete combustion or oxidation 
of the annual quantity of propane, butane, ethane, isobutane and bulk 
NGLs sold or delivered for use off site.
    (b) Local distribution companies 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.


Sec.  98.403  Calculating GHG emissions.

    (a) For each type of fuel or product reported under this part, 
calculate the estimated CO2 equivalent emissions using 
either of Calculation Methodology 1 or 2 of this subpart:
    (1) Calculation Methodology 1. Estimate CO2 emissions 
using Equation NN-1. For Equation NN-1, use the default values for 
higher heating values and CO2 emission factors in Table NN-1 
to this subpart. Alternatively, reporter-specific higher heating values 
and CO2 emission factors may be used, provided they are 
developed using methods outlined in Sec.  98.404. For Equation NN-2 of 
this section, use 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] TP10AP09.179

Where:

CO2 = Annual potential CO2 mass emissions from 
the combustion of fuel (metric tons).
Fuel = Total annual volume of fuel or product (volume per year, 
typically in Mcf for gaseous fuels and bbl for liquid fuels).
HHV = Higher heat value of the fuel supplied (MMBtu/Mcf or MMBtu/
bbl).
EF = Fuel-specific CO2 emission factor (kg 
CO2/MMBtu).
1 x 10-3 = Conversion factor from kilograms to metric 
tons (MT/kg).

    (2) Calculation Methodology 2. Estimate CO2 emissions 
using Equation NN-2.
[GRAPHIC] [TIFF OMITTED] TP10AP09.180

Where:

CO2 = Annual CO2 mass emissions from the 
combustion of fuel supplied (metric tons)
Fuel = Total annual volume of fuel or product supplied (bbl or Mcf 
per year)
EF = Fuel-specific CO2 emission factor (MT 
CO2/bbl, or MT CO2/Mcf)


Sec.  98.404  Monitoring and QA/QC requirements.

    (a) The quantity of natural gas liquids and natural gas must be 
determined

[[Page 16721]]

using any of the oil and gas flow meter test methods that are in common 
use in the industry and consistent with the Gas Processors Association 
Technical Manual and the American Gas Association Gas Measurement 
Committee reports.
    (b) The minimum frequency of the measurements of quantities of 
natural gas liquids and natural gas shall be based on the industry 
standard practices for commercial operations. For natural gas liquids 
these are measurements taken at custody transfers summed to the annual 
reportable volume. For natural gas these are daily totals of continuous 
measurements, and summed to the annual reportable volume.
    (c) All flow meters and product or fuel composition monitors shall 
be calibrated prior to the first reporting year, using a suitable 
method published by the American Gas Association Gas Measurement 
Committee reports on flow metering and heating value calculations and 
the Gas Processors Association standards on measurement and heating 
value. Alternatively, calibration procedures specified by the flow 
meter manufacturer may be used. Fuel flow meters shall be recalibrated 
either annually or at the minimum frequency specified by the 
manufacturer.
    (d) Reporter-specific emission factors or higher heating values 
shall be determined using industry standard practices such as the 
American Gas Association (AGA) Gas Measurement Committee Report on 
heating value and the Gas Processors Association (GPA) Technical 
Standards Manual for NGL heating value; and ASTM D-2597-94 and ASTM D-
1945-03 for compositional analysis necessary for estimating 
CO2 emission factors.


Sec.  98.405  Procedures for estimating missing data.

    (a) A complete record of all measured parameters used in the 
reporting of fuel volumes and in the calculations of CO2 
mass emissions is required. Therefore, whenever a quality-assured value 
of the quantity of natural gas liquids or natural gas 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) For NGLs, natural gas processing plants 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 
processing plant 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, natural gas processors may substitute 
estimates based on contract quantities required to be delivered under 
purchase or delivery contracts with other parties.
    (c) Natural gas local distribution companies may substitute the 
metered quantities from the delivering pipelines for all deliveries 
into the distribution system. In cases where the pipeline metered 
delivery data are not available, local distribution companies may 
substitute their pipeline nominations and scheduled quantities for the 
period when metered values of actual deliveries are not available.
    (d) Estimates of missing data shall be documented and records 
maintained showing the calculations of the values used for the missing 
data.


Sec.  98.406  Data reporting requirements.

    (a) In addition to the information required by Sec.  98.3(c), the 
annual report for each natural gas processing plant must contain the 
following information.
    (1) The total annual quantity in barrels of NGLs produced for sale 
or delivery on behalf of others in the following categories: Propane, 
natural butane, ethane, and isobutane, and all other bulk NGLs as a 
single category.
    (2) The total annual CO2 mass emissions associated with 
the volumes in paragraph (a)(1) of this section and calculated in 
accordance with Sec.  98.403.
    (b) In addition to the information required by Sec.  98.3(c), the 
annual report for each local distribution company must contain the 
following information.
    (1) The total annual volume in Mcf of natural gas received by the 
local distribution company for redelivery to end users on the local 
distribution company's distribution system.
    (2) The total annual CO2 mass emissions associated with 
the volumes in paragraph (b)(1) of this section and calculated in 
accordance with Sec.  98.403.
    (3) The total natural gas volumes received for redelivery to 
downstream gas transmission pipelines and other local distribution 
companies.
    (4) The name and EPA and EIA identification code of each individual 
covered facility, and the name and EIA identification code of any other 
end-user for which the local gas distribution company delivered greater 
than or equal to 460,000 Mcf during the calendar year, and the total 
natural gas volumes actually delivered to each of these end-users.
    (5) The annual volume in Mcf 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 and 
Instructions.
    (i) Residential consumers.
    (ii) Commercial consumers.
    (iii) Industrial consumers.
    (iv) Electricity generating facilities.
    (6) The total annual CO2 mass emissions associated with 
the volumes in paragraph (b)(5) of this section and calculated in 
accordance with Sec.  98.403.


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.
    (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)(4).
    (e) Records relating to measured Btu content or carbon content.


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 of Subpart NN--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/Mcf.......        53.02
Propane............................  3.836 MMBtu/bbl.......        63.02
Butane.............................  4.326 MMBtu/bbl.......        64.93

[[Page 16722]]

 
Ethane.............................  3.082 MMBtu/bbl.......        59.58
Isobutane..........................  3.974 MMBtu/bbl.......        65.08
Natural Gas Liquids................  4.140 MMBtu/bbl.......        63.20
------------------------------------------------------------------------


     Table NN-2 of Subpart NN--Lookup Default Values for Calculation
                      Methodology 2 of this Subpart
------------------------------------------------------------------------
                                                             Default CO2
                                                               emission
                Fuel                          Unit            value (MT
                                                              CO2/Unit)
------------------------------------------------------------------------
Natural Gas........................  Mcf...................     0.054452
Propane............................  Barrel................     0.241745
Butane.............................  Barrel................     0.280887
Ethane.............................  Barrel................     0.183626
Isobutane..........................  Barrel................     0.258628
Natural Gas Liquids................  Barrel................     0.261648
------------------------------------------------------------------------

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 GHGs does not include the reuse or recycling of a 
fluorinated GHG or the generation of HFC-23 during the production of 
HCFC-22.
    (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) The total mass of each fluorinated GHG or nitrous oxide 
produced annually shall be estimated by using Equation OO-1 of this 
section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.181

Where:

P = Mass of fluorinated GHG or nitrous oxide produced annually.
Pp = Mass of fluorinated GHG or nitrous oxide produced 
over the period ``p''.

    (b) The total mass of each fluorinated GHG or nitrous oxide 
produced over the period ``p'' shall be estimated by using Equation OO-
2 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.182

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) The total mass of each fluorinated GHG or nitrous oxide 
transformed shall be estimated by using Equation OO-3 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.183

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).
R = Mass of residual, unreacted fluorinated GHG or nitrous oxide 
that is permanently removed from the transformation process (metric 
tons).

    (d) The total mass of each fluorinated GHG destroyed shall be 
estimated by using Equation OO-4 of this section:
[GRAPHIC] [TIFF OMITTED] TP10AP09.184

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 at least daily using flowmeters, 
weigh scales, or a combination of volumetric and density measurements 
with an accuracy and precision of 0.2 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 at least 
daily (when being added) using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 0.2 percent of full scale or better.
    (c) The mass of fluorinated GHGs or nitrous oxide fed into 
transformation processes shall be measured at least daily using 
flowmeters, weigh scales, or a combination of volumetric and density

[[Page 16723]]

measurements with an accuracy and precision of 0.2 percent of full 
scale or better.
    (d) If unreacted fluorinated GHGs or nitrous oxide are permanently 
removed (recovered, destroyed, or emitted) from the transformation 
process, the mass removed shall be measured using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 0.2 percent of full scale or better. If the 
measured mass includes more than trace concentrations of materials 
other than the unreacted fluorinated GHG or nitrous oxide, the 
concentration of the unreacted fluorinated GHG or nitrous oxide shall 
be measured at least daily 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 fluorinated GHG or nitrous oxide permanently removed from 
the transformation process.
    (e) The mass of fluorinated GHG or nitrous oxide sent to another 
facility for transformation shall be measured at least daily using 
flowmeters, weigh scales, or a combination of volumetric and density 
measurements with an accuracy and precision of 0.2 percent of full 
scale or better.
    (f) The mass of fluorinated GHG sent to another facility for 
destruction shall be measured at least daily using flowmeters, weigh 
scales, or a combination of volumetric and density measurements with an 
accuracy and precision of 0.2 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 measured at least daily 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 fluorinated GHG sent to another facility for 
destruction.
    (g) The mass of fluorinated GHGs fed into the destruction device 
shall be measured at least daily using flowmeters, weigh scales, or a 
combination of volumetric and density measurements with an accuracy and 
precision of 0.2 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 measured at least daily 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 fluorinated GHG destroyed.
    (h) For purposes of Equation OO-4, the destruction efficiency can 
initially 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. Fluorinated GHG production 
facilities that destroy fluorinated GHGs shall conduct annual 
measurements of mass flow and fluorinated GHG concentrations at the 
outlet of the thermal oxidizer in accordance with EPA Method 18 at 40 
CFR part 60, appendix A-6. Tests shall be conducted under conditions 
that are typical for the production process and destruction device at 
the facility. The sensitivity of the emissions tests shall be 
sufficient to detect emissions equal to 0.01 percent of the mass of 
fluorinated GHGs being fed into the destruction device. If the test 
indicates that the actual DE of the destruction device is lower than 
the previously determined DE, facilities shall either:
    (1) Substitute the DE implied by the most recent emissions test for 
the previously determined DE in the calculations in Sec.  98.413, or
    (2) Perform more extensive performance testing of the DE of the 
oxidizer and use the DE determined by the more extensive testing in the 
calculations in Sec.  98.413.
    (i) In their estimates of the mass of fluorinated GHGs destroyed, 
designated representatives of 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.
    (j) All flowmeters, weigh scales, and combinations of volumetric 
and density measurements that are used to measure or calculate 
quantities that are to be reported under this subpart shall be 
calibrated using suitable NIST-traceable standards and suitable methods 
published by a consensus standards organization (e.g., ASTM, ASME, 
ASHRAE, or others). Alternatively, calibration procedures specified by 
the flowmeter, scale, or load cell manufacturer may be used. 
Calibration shall be performed prior to the first reporting year. After 
the initial calibration, recalibration shall be performed at least 
annually or at the minimum frequency specified by the manufacturer, 
whichever is more frequent.
    (k) All gas chromatographs that are used to measure or calculate 
quantities that are to be reported under this subpart shall be 
calibrated at least monthly through analysis of certified standards 
with known concentrations of the same chemical(s) in the same range(s) 
(fractions by mass) as the process samples. Calibration gases prepared 
from a high-concentration certified standard using a gas dilution 
system that meets the requirements specified in Test Method 205, 40 CFR 
Part 51, Appendix M may also be used.


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 the following requirements:
    (1) For each missing value of the mass produced, fed into the 
production process (for used material being reclaimed), fed into 
transformation processes, 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. 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.
    (2) For each missing value of fluorinated GHG concentration, except 
the annual destruction device outlet concentration measurement 
specified in Sec.  98.414(h), 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-

[[Page 16724]]

assured value obtained after the missing data period. There are no 
missing value allowances for the annual destruction device outlet 
concentration measurement. A re-test must be performed if the data from 
the annual destruction device outlet concentration measurement are 
determined to be unacceptable or not representative of typical 
operations.
    (3) Notwithstanding paragraphs (a)(1) and (2) of this section, if 
the owner or operator has reason to believe that the methods specified 
in paragraphs (a)(1) and (2) of this section are likely to 
significantly under- or overestimate the value of the parameter during 
the period when data were missing, the designated representative of the 
fluorinated GHG production facility shall develop his or her best 
estimate of the parameter, documenting the methods used, the rationale 
behind them, and the reasons why the methods specified in paragraphs 
(a)(1) and (2) of this section would probably lead to a significant 
under- or overestimate of the parameter. EPA may reject the alternative 
estimate and replace it with an estimate based on the applicable method 
in paragraph (a)(1) or (2) if EPA does not agree with the rationale or 
method for the alternative estimate.


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 at the facility level:
    (1) Total mass in metric tons of each fluorinated GHG or nitrous 
oxide produced at that facility.
    (2) Total mass in metric tons of each fluorinated GHG or nitrous 
oxide transformed at that facility.
    (3) Total mass in metric tons of each fluorinated GHG destroyed at 
that facility.
    (4) Total mass in metric tons of any fluorinated GHG or nitrous 
oxide sent to another facility for transformation.
    (5) Total mass in metric tons of any fluorinated GHG sent to 
another facility for destruction.
    (6) Total mass in metric tons of each reactant fed into the 
production process.
    (7) Total mass in metric tons of each non-GHG reactant and by-
product permanently removed from the process.
    (8) Mass of used product added back into the production process 
(e.g., for reclamation).
    (9) 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.
    (10) 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.
    (11) 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. Where the missing data have been estimated 
pursuant to Sec.  98.415(a)(3), the report shall explain the rationale 
for the methods used to estimate the missing data and why the methods 
specified in Sec.  98.415(a)(1) and (2) would lead to a significant 
under- or overestimate of the parameters.
    (b) A fluorinated GHG production facility that destroys fluorinated 
GHGs shall report the results of the annual fluorinated GHG 
concentration measurements at the outlet of the destruction device, 
including:
    (1) Flow rate of fluorinated GHG being fed into the destruction 
device in kg/hr.
    (2) Concentration (mass fraction) of fluorinated GHG at the outlet 
of the destruction device.
    (3) Flow rate at the outlet of the destruction device in kg/hr.
    (4) Emission rate calculated from (b)(2) and (b)(3) in kg/hr.
    (c) A fluorinated GHG production facility that destroys fluorinated 
GHGs shall submit a one-time report containing the following 
information:
    (1) Destruction efficiency (DE) of each destruction unit.
    (2) Test 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.
    (d) A bulk importer of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes their imports at the corporate 
level, except for transshipments and heels. 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) 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.
    (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 destruction, and the quantities (metric tons) of 
nitrous oxide and of each fluorinated GHG that were sold or transferred 
to each facility for destruction.
    (e) A bulk exporter of fluorinated GHGs or nitrous oxide shall 
submit an annual report that summarizes their exports at the corporate 
level, except for 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) Quantity exported by chemical in metric tons of chemical.
    (5) Commodity code of the fluorinated GHGs and nitrous oxide 
shipped.
    (6) Date on which, and the port from which, fluorinated GHGs and 
nitrous oxide were exported from the United States or its territories.
    (7) Country to which the fluorinated GHGs or nitrous oxide were 
exported.


Sec.  98.417  Records that must be retained.

    (a) In addition to the data required by Sec.  98.3(g), the 
designated representative of a fluorinated GHG production facility 
shall retain the following records:

[[Page 16725]]

    (1) Dated records of the data used to estimate the data reported 
under Sec.  98.416, and
    (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 designated representative of a 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 (c).
    (c) In addition to the data required by Sec.  98.3(g), the 
designated representative of a 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 
designated representative of a 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 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.


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) Production process units that capture a CO2 stream for purposes 
of supplying CO2 for commercial applications. Capture refers to the 
separation and removal of CO2 from a manufacturing process; fuel 
combustion source; or a waste, wastewater, or water treatment process.
    (2) Facilities with CO2 production wells.
    (3) Importers or exporters of bulk CO2.
    (b) This source category does not include the following:
    (1) Geologic sequestration (long term storage) of CO2.
    (2) Injection and subsequent production and/or processing of 
CO2 for enhanced oil and gas recovery.
    (3) Above ground storage of CO2.
    (4) Transportation or distribution of CO2 via pipelines, 
vessels, motor carriers, or other means.
    (5) Purification, compression, or processing of CO2.
    (6) CO2 imported or exported in equipment.


Sec.  98.421  Reporting threshold.

    Any supplier of CO2 who meets the requirements of Sec.  
98.2(a)(4) must report GHG emissions.


Sec.  98.422  GHGs to report.

    You must report the mass of carbon dioxide captured from production 
process units, the mass of carbon dioxide extracted from carbon dioxide 
production wells, and the mass of carbon dioxide imported and exported 
regardless of the degree of impurities in the carbon dioxide stream.


Sec.  98.423  Calculating GHG emissions.

    (a) Facilities with production process units must calculate 
quarterly the total mass of carbon dioxide in a carbon dioxide stream 
in metric tons captured, prior to any subsequent purification, 
processing, or compressing, based on multiplying the mass flow by the 
composition data, according to Equation PP-1 of this section. Mass flow 
and composition data measurements are made in accordance with Sec.  
98.424.
[GRAPHIC] [TIFF OMITTED] TP10AP09.185

Where:

CO2 = CO2 mass emission (metric tons per 
year).
CCO2 = Quarterly average CO2 concentration in 
flow (wt. % CO2).
Q = Quarterly mass flow rate (metric tons per quarter).

    (b) CO2 production well facilities must calculate 
quarterly the total mass of carbon dioxide in a carbon dioxide stream 
from wells in metric tons, prior to any subsequent purification, 
processing, or compressing, based on multiplying the mass flow by the 
composition data, according to Equation PP-1. Mass flow and composition 
data measurements are made in accordance with Sec.  98.424.
    (c) Importers or exporters of a carbon dioxide stream must 
calculate quarterly the total mass of carbon dioxide imported or 
exported in metric tons, based on multiplying the mass flow by the 
composition data, according to Equation PP-1. Mass flow and composition 
data measurements are made in accordance with Sec.  98.424. The 
quantities of CO2 imported or exported in equipment, such as 
fire extinguishers, need not be calculated or reported.


Sec.  98.424  Monitoring and QA/QC requirements.

    (a) Facilities with production process units that capture a carbon 
dioxide stream must measure on a quarterly basis using a mass flow 
meter the mass flow of the CO2 stream captured. If 
production process units do not have mass flow meters installed to 
measure the mass flow of the CO2 stream captured, 
measurements shall be based on the mass flow of gas transferred off 
site using a mass flow meter. In either case, sampling also must be 
conducted on at least a quarterly basis to determine the composition of 
the captured or transferred CO2 stream.
    (b) Carbon dioxide production well facilities must measure on a 
quarterly basis the mass flow of the CO2 stream extracted 
using a mass flow meter. If the CO2 production wells do not 
have mass flow meters installed to measure the mass flow of the 
CO2 stream extracted, measurements shall be based on mass 
flow of gas transferred off site using a mass flow meter. In either 
case, sampling must be conducted on at least a quarterly basis to 
determine the composition of the extracted or transferred carbon 
dioxide.
    (c) Importers or exporters of bulk CO2 must measure on a 
quarterly basis the mass flow of the CO2 stream imported or 
exported using a mass flow meter and must conduct sampling on at least 
a quarterly basis to determine the composition of the imported or 
exported CO2 stream. If the importer of a CO2 
stream does not have mass flow meters installed to measure the mass 
flow of gas imported, the measurements shall be based on the mass flow 
of the imported CO2 stream transferred off site or used in 
on-site processes, as measured by mass flow meters. If an exporter of a 
CO2 stream does not have mass flow meters installed to 
measure the mass flow exported, the measurements shall be based on the 
mass flow of the CO2 stream received for export, as measured 
by mass flow meters. In all cases, sampling on at least a quarterly 
basis also must be conducted to determine the composition of the 
CO2 stream.

[[Page 16726]]

    (d) Mass flow meter calibrations must be NIST traceable.
    (e) Methods to measure the composition of the carbon dioxide 
captured, extracted, transferred, imported, or exported must conform to 
applicable chemical analytical standards. Acceptable methods include 
U.S. Food and Drug Administration food-grade specifications for carbon 
dioxide (see 21 CFR 184.1250) and ASTM standard E-1745-95 (2005).


Sec.  98.425  Procedures for estimating missing data.

    (a) Missing quarterly monitoring data on mass flow of 
CO2 streams captured, extracted, imported, or exported shall 
be substituted with the greater of the following values:

    (1) Quarterly CO2 mass flow of gas transferred off site 
measured during the current reporting year.
    (2) Quarterly or annual average values of the monitored 
CO2 mass flow from the past calendar year.
    (b) Missing monitoring data on the mass flow of the CO2 
stream transferred off site shall be substituted with the quarterly or 
annual average values from off site transfers from the past calendar 
year.
    (c) Missing data on composition of the CO2 stream 
captured, extracted, transferred, imported, or exported may be 
substituted for with quarterly or annual average values from the past 
calendar year.


Sec.  98.426  Data reporting requirements.

    In addition to the information required by Sec.  98.3(c), each 
annual report must contain the following information.
    (a) Each facility with production process units or CO2 
production wells must report the following information:
    (1) Total annual mass in metric tons and the weighted average 
composition of the CO2 stream captured, extracted, or 
transferred in either gas, liquid, or solid forms.
    (2) Annual quantities in metric tons transferred to the following 
end use applications by end-use, if known:
    (i) Food and beverage.
    (ii) Industrial and municipal water/wastewater treatment.
    (iii) Metal fabrication, including welding and cutting.
    (iv) Greenhouse uses for plant growth.
    (v) Fumigants (e.g., grain storage) and herbicides.
    (vi) Pulp and paper.
    (vii) Cleaning and solvent use.
    (viii) Fire fighting.
    (ix) Transportation and storage of explosives.
    (x) Enhanced oil and natural gas recovery.
    (xi) Long-term storage (sequestration).
    (xii) Research and development.
    (b) CO2 importers and exporters must report the 
information in paragraphs (a)(1) and (a)(2) at the corporate level.


Sec.  98.427  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.
    (a) The owner or operator of a facility containing production 
process units must retain quarterly records of captured and transferred 
CO2 streams and composition.
    (b) The owner or operator of a carbon dioxide production well 
facility must maintain quarterly records of the mass flow of the 
extracted and transferred CO2 stream and composition.
    (c) Importers or exporters of CO2 must retain quarterly 
records of the mass flow and composition of CO2 streams 
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 600--[AMENDED]

    27. The authority citation for part 600 continues to read as 
follows:

    Authority: 49 U.S.C. 32901-23919q, Pub. L. 109-58.

Subpart A--[Amended]

    28. Section 600.006-08 is amended by revising paragraph (c) 
introductory text and adding paragraph (c)(5) to read as follows:


Sec.  600.006-08  Data and information requirements for fuel economy 
vehicles.

* * * * *
    (c) The manufacturer shall submit the following data:
* * * * *
    (5) Starting with the 2011 model year, the data submitted according 
to paragraphs (c)(1) through (c)(4) of this section shall include 
CO2, N2O, and CH4 in addition to fuel 
economy. Use the procedures specified in 40 CFR part 1065 as needed to 
measure N2O and CH4. Round the test results as 
follows:
    (i) Round CO2 to the nearest 1 g/mi.
    (ii) Round N2O to the nearest 0.001 g/mi.
    (iii) Round CH4 to the nearest 0.001g/mi.
* * * * *

PART 1033--[AMENDED]

    29. The authority citation for part 1033 continues to read as 
follows:

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

Subpart C--[Amended]

    30. 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) Starting in the 2011 model year, report measured 
N2O and CH4 as described in Sec.  1033.235. Small 
manufacturers/remanufacturers may omit this requirement.
* * * * *
    31. Section 1033.235 is amended by adding paragraph (i) to read as 
follows:


Sec.  1033.235  Emission testing required for certification.

* * * * *
    (i) Starting in the 2011 model year, measure N2O, and 
CH4 with each low-hour certification test using the 
procedures specified in 40 CFR part 1065. Small manufacturers/
remanufacturers may omit this requirement. 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/kW-hr.
    (2) Round N2O to the nearest 0.001 g/kW-hr.
    (3) Round CH4 to the nearest 0.001g/kW-hr.

Subpart J--[Amended]

    32. 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]

    33. The authority citation for part 1039 continues to read as 
follows:

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

[[Page 16727]]

Subpart C--[Amended]

    34. 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 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) Starting in the 2011 model year, report measured CO2 
, N2O, and CH4 as described in Sec.  1039.235. 
Small-volume engine manufacturers may omit this requirement.
* * * * *
    35. 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) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 with each low-hour certification 
test using the procedures specified in 40 CFR part 1065. Small-volume 
engine manufacturers may omit this requirement. 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 I--[Amended]

    36. 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]

    37. The authority citation for part 1042 continues to read as 
follows:

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

Subpart C--[Amended]

    38. 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) Starting in the 2011 model year, report measured 
CO2, N2O, and CH4 as described in 
Sec.  1042.235. Small-volume engine manufacturers may omit this 
requirement.
* * * * *
    39. 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) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 with each low-hour certification 
test using the procedures specified in 40 CFR part 1065. Small-volume 
engine manufacturers may omit this requirement. 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 J--[Amended]

    40. 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]

    41. The authority citation for part 1045 continues to read as 
follows:

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

Subpart C--[Amended]

    42. 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.
    (2) Starting in the 2011 model year, report measured 
CO2, N2O, and CH4 as described in 
Sec.  1045.235. Small-volume engine manufacturers may omit this 
requirement.
* * * * *
    43. 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, N2O, and CH4 with 
each low-hour certification test using the procedures specified in 40 
CFR part 1065. Small-volume engine manufacturers may omit this 
requirement. 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.

PART 1048--[AMENDED]

    44. The authority citation for part 1048 continues to read as 
follows:

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

Subpart C--[Amended]

    45. Section 1048.205 is amended by revising paragraph (s) to read 
as follows:

[[Page 16728]]

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) Starting in the 2011 model year, report measured 
CO2, N2O, and CH4 as described in 
Sec.  1048.235. Small-volume engine manufacturers may omit this 
requirement.
* * * * *
    46. 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) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 with each low-hour certification 
test using the procedures specified in 40 CFR part 1065. Small-volume 
engine manufacturers may omit this requirement. 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 I--[Amended]

    47. 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]

    48. The authority citation for part 1051 continues to read as 
follows:

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

Subpart C--[Amended]

    49. 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) Starting in the 2011 model year, report measured 
CO2, N2O, and CH4 as described in 
Sec.  1051.235. Small-volume manufacturers may omit this requirement.
* * * * *
    50. 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) Starting in the 2011 model year, measure CO2, 
N2O, and CH4 with each low-hour certification 
test using the procedures specified in 40 CFR part 1065. Small-volume 
manufacturers may omit this requirement. 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 0.001g/kW-hr or 0.001 g/km, 
as appropriate.

Subpart I--[Amended]

    51. 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]

    52. The authority citation for part 1054 continues to read as 
follows:

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

Subpart C--[Amended]

    53. 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) Starting in the 2011 model year, report measured 
CO2, N2O, and CH4 as described in 
Sec.  1054.235. Small-volume engine manufacturers may omit this 
requirement.
* * * * *
    54. 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, N2O, and CH4 with 
each low-hour certification test using the procedures specified in 40 
CFR part 1065. Small-volume engine manufacturers may omit this 
requirement. 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.
    55. A new part 1064 is added to subchapter U of chapter I to read 
as follows:

PART 1064--VEHICLE TESTING PROCEDURES

Subpart A--Applicability and general provisions
Sec.
1064.1 Applicability.
Subpart B--Air Conditioning Systems
1064.201 Method for calculating emissions due to air conditioning 
leakage.


[[Page 16729]]


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

Subpart A--Applicability and General Provisions


Sec.  1064.1  Applicability.

    (a) This part describes procedures that apply to testing we require 
for 2011 and later model year light-duty vehicles, light-duty trucks, 
and medium-duty personal vehicles (see 40 CFR part 86).
    (b) See 40 CFR part 86 for measurement procedures related to 
exhaust and evaporative emissions.

Subpart B--Air Conditioning Systems


Sec.  1064.201  Method for calculating emissions due to air 
conditioning leakage.

    Determine a refrigerant leakage rate from vehicle-based air 
conditioning units as described in this section.
    (a) Emission totals. Calculate an annual rate of refrigerant 
leakage from an air conditioning system using the following equation:

Grams/YRTOT = Grams/YRRP + Grams/YRSP 
+ Grams/YRFH + Grams/YRMC + Grams/YRC

Where:

Grams/YRRP = Emission rate for rigid pipe connections as 
described in paragraph (b) of this section.
Grams/YRSP = Emission rate for service ports and 
refrigerant control devices as described in paragraph (c) of this 
section.
Grams/YRFH = Emission rate for flexible hoses as 
described in paragraph (d) of this section.
Grams/YRMC = Emission rate for heat exchangers, mufflers, 
receiver/driers, and accumulators as described in paragraph (e) of 
this section.
Grams/YRC = Emission rate for compressors as described in 
paragraph (f) of this section.

    (b) Fittings. Determine the emission rate for rigid pipe 
connections using the following Equation:

Grams/YRRP = 0.00522 [middot] [(125 [middot] SO) + (75 
[middot] SCO) + (50 [middot] MO) + (10 [middot] SW) + (5 [middot] SWO) 
+ (MG)]

Where:

SO = The number of single O-ring connections.
SCO = The number of single captured O-ring connections.
MO = The number of multiple O-ring connections.
SW = The number of seal washer connections.
SWO = The number of seal washer with O-ring connections.
MG = The number of metal gasket connections.

    (c) Service ports and refrigerant control devices. Determine the 
emission rate for service ports and refrigerant control devices using 
the following Equation:

Grams/YRSP = (0.3 [middot] HSSP) + (0.2 [middot] LSSP) + 
(0.2 [middot] STV) + (0.2 [middot] TXV)

Where:

HSSP = The number of high side service ports.
LSSP = The number of low side service ports.
STV = The total number of switches, transducers, and expansion 
valves.
TXV = The number of TXV refrigerant control devices.

    (d) Flexible hoses. Determine the permeation emission rate for each 
segment of flexible hose using the following Equation, then add those 
values to calculate a total emission rate for the system:

Grams/YRFH = 0.00522 [middot] (3.14159 [middot] ID [middot] 
L [middot] ER)

Where:

ID = Inner diameter of hose, in millimeters.
L = Length of hose, in millimeters.
ER = Emission rate per unit internal surface area of the hose, in g/
mm\2\. Select the appropriate value from the following table:

------------------------------------------------------------------------
                                                      ER
                                     -----------------------------------
       Material/configuration           High-pressure     Low-pressure
                                            side              side
------------------------------------------------------------------------
Rubber..............................           0.0216            0.0144
Standard barrier or veneer hose.....           0.0054            0.0036
Ultra-low permeation barrier or                0.00225           0.00167
 veneer hose........................
------------------------------------------------------------------------

    (e) Heat exchangers, mufflers, receiver/driers, and accumulators. 
Use an emission rate of 0.5 grams per year as a combined value for all 
heat exchangers, mufflers, receiver/driers, and accumulators (Grams/
YRMC).
    (f) Compressors. Determine the emission rate for compressors using 
the following equation:


Grams/YRC = 0.00522 [middot] [(300 [middot] OHS) + (200 
[middot] MHS) + (150 [middot] FAP) + (100 [middot] GHS) + (1500/SSL)]

Where:

OHS = The number of O-ring housing seals.
MHS = The number of molded housing seals.
FAP = The number of fitting adapter plates.
GHS = The number of gasket housing seals.
SSL = The number of lips on shaft seal (for belt-driven compressors 
only).

PART 1065--[AMENDED]

    56. The authority citation for part 1065 continues to read as 
follows:

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

Subpart C--[Amended]

    57. A new Sec.  1065.257 is added to subpart C to read as follows:


Sec.  1065.257  Nondispersive N2O infrared analyzer.

    (a) Application. Use a nondispersive infrared (NDIR) analyzer to 
measure N2O concentrations in diluted exhaust for batch 
sampling. Batch sampling may be performed in a single bag covering all 
phases of the test procedure.
    (b) Component requirements. We recommend that you use an NDIR 
analyzer that meets the specifications in Table 1 of Sec.  1065.205. 
Note that your NDIR-based system must meet the calibration and 
verification in Sec.  1065.357 and it must also meet the linearity 
verification in Sec.  1065.307. 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.
    (c) Artifact formation, SO2, and H2O removal. 
SO2, NOX, and H2O have been shown to 
react in the sample bag to form N2O. SO2 and 
H2O must therefore be sequentially removed from the sample 
gas before the sample enters the bag. SO2 can be neutralized 
from the sample gas by passing the sample through a sorbent cartridge 
packed with 120 cc of a 10:1 ratio of 18-20 mesh sand and 
Ca(OH)2. This sorbent works only in the presence of 
H2O so the H2O sorbent cartridge must be located 
downstream of the SO2 sorbent cartridge. H2O can 
be removed by passing the sample through a sorbent cartridge packed 
with 120 cc of P2O5.
    58. A new Sec.  1065.357 is added to subpart D to read as follows:


Sec.  1065.357  CO and Co2 interference verification for 
N2O NDIR analyzers.

    (a) Scope and frequency. If you measure CO using an NDIR analyzer,

[[Page 16730]]

verify the amount of CO and Co2 interference after initial 
analyzer installation and after major maintenance.
    (b) Measurement principles. CO and Co2 can positively 
interfere with an NDIR analyzer by causing a response similar to 
N2O. If the NDIR 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. A N2O NDIR analyzer must have 
combined CO and Co2 interference that is within 2 percent of the flow-weighted mean concentration of 
N2O expected at the standard, though we strongly recommend a 
lower interference that is within 1 percent.
    (d) Procedure. Perform the interference verification as follows:
    (1) Start, operate, zero, and span the N2O NDIR analyzer 
as you would before an emission test.
    (2) Introduce a CO span to the analyzer.
    (3) Allow time for the analyzer response to stabilize. 
Stabilization time may include time to purge the transfer line and to 
account for analyzer response.
    (4) While the analyzer measures the sample's concentration, record 
its output for 30 seconds. Calculate the arithmetic mean of this data.
    (5) Scale the CO interference by multiplying this mean value (from 
paragraph (d)(7) of this section) by the ratio of expected CO to span 
gas CO concentration. In other words, estimate the flow-weighted mean 
dry concentration of CO expected during testing, and then divide this 
value by the concentration of CO in the span gas used for this 
verification. Then multiply this ratio by the mean value recorded 
during this verification (from paragraph (d)(7) of this section).
    (6) Repeat the steps in paragraphs (d)(2) through (5) of this 
section, but with a CO2 analytical gas mixture instead of CO 
and without humidifying the sample through the distilled water in a 
sealed vessel.
    (7) Add together the CO and CO2-scaled result of 
paragraphs (d)(5) and (6) of this section.
    (8) The analyzer meets the interference verification if the result 
of paragraph (d)(7) of this section is within 2 percent of 
the flow-weighted mean concentration of N2O expected at the 
standard.
    (e) Exceptions. The following exceptions apply:
    (1) You may omit this verification if you can show by engineering 
analysis that for your N2O sampling system and your emission 
calculations procedures, the combined CO, CO2, and 
H2O interference for your N2O NDIR analyzer 
always affects your brake-specific N2O emission results 
within 0.5 percent of the applicable N2O 
standard.
    (2) You may use a N2O NDIR analyzer that you determine 
does not meet this verification, as long as you try to correct the 
problem and the measurement deficiency does not adversely affect your 
ability to show that engines comply with all applicable emission 
standards.

Subpart H--[Amended]

    59. 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/mol.  <0.05 [mu]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/mol.  <0.02 [mu]mol/mol.
N2O.............................  <0.05 [mu]mol/mol.  <0.05 [mu]mol/mol.
------------------------------------------------------------------------
\1\ We do not require these levels of purity to be NIST-traceable.

* * * * *
    (3) * * *
    (xi) N2O, balance purified N2.
* * * * *

Subpart K--[Amended]

    60. 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.
* * * * *
    61. Section 1065.1005 is amended by adding items to the table in 
paragraph (b) in alphanumeric order to read as follows:


Sec.  1065.1005   Symbols, abbreviations, acronyms, and units of 
measure.

* * * * *
    (b) * * *

[[Page 16731]]



------------------------------------------------------------------------
                 Symbol                              Species
------------------------------------------------------------------------
 
                              * * * * * * *
Ca(OH)2................................  calcium hydroxide
 
                              * * * * * * *
P2O5...................................  phosphorous pentoxide
 
                              * * * * * * *
SO2....................................  sulfur dioxide
 
                              * * * * * * *
------------------------------------------------------------------------

* * * * *

[FR Doc. E9-5711 Filed 4-9-09; 8:45 am]
BILLING CODE 6560-50-P