16448 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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: a-and-r-Docket@epa.gov. 

• 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: 

GHGReportingRule@epa.gov. For 

technical information, contact the 

Greenhouse Gas Reporting Rule Hotline 

at telephone number: (877) 444–1188; or 

e-mail: ghgmrr@epa.gov. 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 

GHGReportingRule@epa.gov. 

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

Category NAICS Examples of affected facilities 

General Stationary Fuel Combustion 

Sources.

........................ Facilities operating 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16449 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected facilities 

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 Destruction.325120 Chlorodifluoromethane 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 Electrical 

Equipment.

221121 Electric bulk power 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. 

16450 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected facilities 

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-based Products.212111 Bituminous, and lignite coal surface mining facilities. 

212113 Anthracite coal mining facilities. 

212112 Underground bituminous coal mining facilities. 

Suppliers of Coal Based Liquids Fuels .... 211111 Coal liquefaction at mine sites. 

Suppliers of Petroleum Products .............. 324110 Petroleum refineries. 

Suppliers of Natural Gas and NGLs ......... 221210 Natural gas distribution facilities. 

211112 Natural gas liquid extraction facilities. 

Suppliers of Industrial GHGs .................... 325120 Industrial gas manufacturing facilities. 

Suppliers of Carbon Dioxide (CO2) .......... 325120 Industrial gas 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 subpart) Subparts recommended for review to determine applicability 

General Stationary Fuel Combustion Sources ......................................... General Stationary Fuel 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 Destruction ...................................... General Stationary Fuel 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16451 

TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS—Continued 

Source category (and main applicable subpart) Subparts recommended for review to determine applicability 

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 Electrical Equipment ............................... General Stationary Fuel 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 

16452 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16453 

1For 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 * * *’’. 

2The 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. 3EPA 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. 

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 preindustrial era to 2005. The global 

atmospheric concentration of CH4 has 

increased by 148 percent from preindustrial 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 UNFCCC1 on an annual 

basis.2 A more detailed discussion of 

the Inventory is provided in Section I.D 

below. 

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. 

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 

16454 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

4 IPCCC: Climate Change 2007: The Physical 

Science Basis, February 2, 2007 (http:// 

www.ipcc.ch/). 

5Although 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. 

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.’’ 

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 °C (1.3 

°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 °C (1.0 °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 °C 

(3.2 to 7.2 °F) compared to the average 

temperature in 1990. The uncertainty 

range of this estimate is 1.1 to 6.4 °C (2.0 

to 11.5 °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. 

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 

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

16456 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

6Under 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/) 7For 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. 

8At 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. 

9The 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. 

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. 

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

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16457 

10For more information about the Climate 

Leaders program please see: http://www.epa.gov/ 

climateleaders/. 

Suppliers, and (7) Industrial GHG 

Suppliers. 

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 

16458 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

11For more information about the Non-CO2

Voluntary Partnership Programs please see: http:// 

www.epa.gov/nonco2/voluntaryprograms.html. 

12For more information about the CHP 

Partnership please see: http://www.epa.gov/chp/. 

13For more information about SmartWay please 

see: http://www.epa.gov/smartway/. 

14For more information about Performance Track 

please see: http://www.epa.gov/perftrac/index.htm. 

15For more information about DOE’s 1605(b) 

programs please see: http://www.pi.energy.gov/ 

enhancingGHGregistry/. 

annual GHG emissions inventory 

documenting their progress. The annual 

reporting form provides corporate-wide 

emissions by type of emissions source. 

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 sectorspecific 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. 

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. 

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 EPAdeveloped 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. 

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 independentlyassessed 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. 

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 companywide GHG emissions, but must still 

follow the technical guidelines. 

Reported data are made available on the 

Web in a public use database. 

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 processVerDate Nov<24>2008 15:41 Apr 09, 2009 Jkt 217001 PO 00000 Frm 00012 Fmt 4701 Sfmt 4702 E:\FR\FM\10APP2.SGM 10APP2
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16459 

16For more information about these cap and trade 

programs see http://www.epa.gov/airmarkt/. 

17The 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. 

18The 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. 

19For more information about TRI and what 

chemicals are on the list, please see: http:// 

www.epa.gov/tri/. 

20For more information about the NEI please see: 

http://www.epa.gov/ttn/chief/net/. 21As 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. 

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 NOX16. 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. 

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. 

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. 

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. 

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 

16460 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

22For more information about CCAR please see: 

http://www.climateregistry.org/. 

23For more information about TCR please see: 

http://www.theclimateregistry.org/. 

24For more information about RGGI please see: 

http://www.rggi.org/. 

25For more information about WCI please see: 

http://www.westernclimateinitiative.org/. 

26These include: California, Colorado, 

Connecticut, Delaware, Hawaii, Iowa, Maine, 

Maryland, Massachusetts, New Jersey, New Mexico, 

North Carolina, Oregon, Virginia, Washington, West 

Virginia, and Wisconsin. 

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. 

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 facilityspecific emissions, broken out by type 

of emission source (e.g., stationary 

combustion, electricity use, direct 

process emissions) within the facility. 

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-andtrade 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. 

WCI.25 WCI is another regional capand-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. 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16461 

27See Compilation of Air Pollutant Emission 

Factors, Fifth Edition: http://www.epa.gov/ttn/ 

chief/ap42/index.html_ac/index.html. 

28For more information about CA mandatory 

reporting program please see: http:// 

www.arb.ca.gov/cc/reporting/ghg-rep/ghg-rep.htm. 

29We 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. 

30For 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. 

31This 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. 

Emission Factors (known as AP–42 27) 

or other EPA guidance. 

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. 

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. 

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

—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: 

16462 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

32This 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. 

33This 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. 

34As discussed in Section V.QQ, manufacturers 

below a size threshold would be exempt. 

35Unless otherwise noted, years and dates in this 

notice refer to calendar years and dates. 

36There is a discussion in section I.IV of this 

preamble that takes comment on alternative 

reporting schedules. 

1,080 m2 silicon, MEMS: 1,202 m2

silicon, LCD: 235,700 m2 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

—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

• 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 sparkignition 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. 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16463 

37Although 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). 

38For more information about the reporting 

format please see section VI of this preamble. 

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

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. 

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 hardcopy 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. 

16464 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

39The GWPs for the GHGs to be reported are 

found in Table A–1 of proposed 40 CFR part 98, 

subpart A. 

40Pursuant 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. 

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/methodologyreports.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). 

42Under 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. 

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. 

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 longlived 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. 

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 humaninduced 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. 

Tropospheric Ozone. Increased 

concentrations of tropospheric O3 are 

causing a significant anthropogenic 

warming effect, but, unlike the longlived 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16465 

43National Academy of Sciences, ‘‘Radiative 

Forcing of Climate Change: Expanding the Concept 

and Addressing Uncertainties,’’ October 2005. 

44To read the full appropriations language please 

refer to the links on this Web site: http:// 

www.epa.gov/climatechange/emissions/ 

ghgrulemaking.html. 

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. 

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. 

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 

16466 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

45 In this context, suppliers include producers, 

importers, and exporters of fossil fuels and 

industrial GHGs. 

46While 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. 

47As 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.ipccnggip.iges.or.jp/public/2006gl/index.html). 

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 coalbased 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. 

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 doublereporting 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 doublereporting 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16467 

48Facilities 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). 

49For 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. 50A 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. 51To view a summary of EPA’s outreach efforts 

please refer to EPA–HQ–OAR–2008–0508–055. 

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 facilitylevel 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. 

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. 

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 

16468 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

52For more information on CA analysis please see 

http://www.arb.ca.gov/regact/2007/ghg2007/ 

isor.pdf. 

53For 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. 

54Other 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). 

55The 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. 

56For more information about the major source 

analysis please see docket number EPA–HQ–OAR– 

2008–0318. 

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

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. 

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. 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16469 

57This 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). 

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 

16470 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

58The 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. 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16471 

corresponds with the requirements of an 

existing reporting system. 

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 wellknown 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 

16472 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

59Consistent 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. 

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. 

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 

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

16474 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 FacilitySpecific Calculations. This option 

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

16476 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 selfcertification 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) Selfcertification without independent 

verification, (2) self-certification with 

third-party verification, and (3) selfcertification 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 thirdparty verification. Under this approach, 

reporters would submit the same selfcertification 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 selfcertification 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16477 

60For 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.) 

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 thirdparty 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. 

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 

16478 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

61High 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. 

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 multiyear reporting program allows EPA to 

track trends in emissions and 

understand factors that influence 

emissions levels. 

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 crosswalk 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. 

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

16480 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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 qualityassured 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. 

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 

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

Combustion unit size Additional requirement(s) 

Methodological 

tier 

required a

Solid Fossil Fuel (e.g., Coal) 

> 250 mmBtu/hour ................................... —Unit has operated more than 1,000 hours a year b ............................................... 4 

—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 conditions above .................................................................... 3 

≤ 250 mmBtu/hr ....................................... —Unit operates more than 1,000 hours a year b ...................................................... 4 

—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 conditions above .................................................................... 2 

—Monthly measured HHV is available.

—Unit does not meet conditions above .................................................................... 1 

—Monthly measured HHV is not available.

Gaseous Fossil Fuel (e.g., Natural Gas) 

> 250 mmBtu/hr ....................................... None .......................................................................................................................... 3 

≤ 250 mmBtu/hr ....................................... —Monthly measured HHV is available ..................................................................... 2 

—Monthly measured HHV is not available ............................................................... 1 

Fossil Liquid Fuel (e.g., Diesel) 

> 250 mmBtu/hr ....................................... None .......................................................................................................................... 3 

≤ 250 mmBtu/hr ....................................... —Monthly measured HHV is available ..................................................................... 2 

—Monthly measured HHV is not available ............................................................... 1 

Biomass or Biomass-Derived Fuels (e.g., wood) 

All Sizes ................................................... —EPA has provided a default CO2 emission factor and a default heating value for 

the fuel.

1 

All Sizes ................................................... —EPA has provided a default CO2 emission factor for specific fuel to be used 

with that fuel’s measured heating value.

2 

All Sizes ................................................... —EPA has not provided a default CO2 emission factor for specific fuel to be used 

with that fuel’s measured heating value.

3 

MSW 

> 250 tons MSW/day ............................... —Unit has operated more than 1,000 hours a year b ............................................... 4 

—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 conditions above .................................................................... 2 

≤ 250 tons MSW/day ............................... —Unit operates more than 1,000 hours a year b ...................................................... 4 

—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 conditions above .................................................................... 2 

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 

16482 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

63As 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. 

stationary combustion equipment are 

being discussed. 

TABLE C–2. THRESHOLD ANALYSIS FOR UNSPECIFIED INDUSTRIAL STATIONARY FUEL COMBUSTION

Threshold level metric tons CO2e/yr 

Total national 

emissions 

(million 

metric tons 

CO2e) 

Total number 

of facilities 

Emissions covered Facilities covered 

Million 

metric tons 

CO2e/yr 

Percent Number Percent 

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. 

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. 

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

16484 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 fuelspecific 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 biomassderived 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 nonbiogenic 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 

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

16486 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

camdataandmaps. 

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

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). 

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

Threshold level 

metric tons CO2e/yr 

Total national 

emissions 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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 

16488 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 facilityspecific 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 HallHe ́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 processrelated 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<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 emissionsbased 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

Emission threshold level metric tons 

CO2e/yr 

Total national 

emissions 

Total number 

of facilities 

Emissions covered Facilities covered 

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 

16490 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

65The 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 centerworked 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. 

66Aluminum Production TSD (EPA–HQ–OAR– 

2008–0508–006). 

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 effectMins/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, technologyspecific 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. 

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 slopecoefficients 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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16491 

than once. The Guidelines define ‘‘highperforming’’ 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 combustionrelated 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 noncarbon 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<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<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<derberg cells) 

or on net anode consumption (for 

Prebake cells), along with some smelterspecific 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<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 smelterspecific 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. 

16492 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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<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<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 onsite 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16493 

TABLE G–1. THRESHOLD ANALYSIS FOR AMMONIA MANUFACTURING

Threshold level metric tons CO2e/yr Total national 

emissions 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Number Percent 

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 sitespecific 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 sectorwide 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 qualityassured 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 

16494 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

67Cement Production TSD (EPA–HQ–OAR– 

2008–0508–008). 

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 °C (2,400 °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 byproduct. 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. 

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

Threshold level metric tons CO2e/yr 

Total 

national 

emissions 

(MMTCO2e) 

Total number 

of facilities 

Emissions Covered Facilities Covered 

Million 

metric tons 

CO2e/yr 

Percent Number Percent 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 combustionrelated 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 processrelated 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 facilityspecific 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 plantspecific 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 facilityspecific 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 

16496 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

68Electronics Manufacturing TSD (EPA–HQ– 

OAR–2008–0508–009); 2006 IPCC Guidelines. 

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, sitespecific 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 clinkerbased 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

Product type Fluorinated GHGs used during manufacture 

Electronics (e.g., Semiconductor, MEMS, LCD, PV) .. CF4, C2F6, C3F8, c–C4F8, c–C4F8O, 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 plasmagenerated 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 

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

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

Emission threshold level metric tons 

CO2e/yr 

Total national 

emissions 

Total number 

of facilities 

Emissions covered Facilities covered 

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 emissionsbased 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

Emissions source Capacity-based 

threshold 

Total national 

facilities 

Total 

emissions 

of source 

(metric tons 

CO2e) 

Emissions covered Facilities covered 

Metric tons 

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 

16498 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 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 manufacturerpublished 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 

m2 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. 

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 m2 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16499 

70This uncertainty refers only to semiconductors 

and LCDs. Tier 1 emission factor uncertainty for PV 

was not estimated in the 2006 IPCC Guidelines. 

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 companyspecific 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 gasspecific 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. 

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 

16500 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 massbalance 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

Threshold level National emissions 

mtCO2e 

Total number 

of facilities 

Emissions covered Facilities covered 

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 

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

Threshold level (metric tons CO2e/yr) 

Total national 

emissions 

(metric tons 

CO2e/yr) 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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. 

16502 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 sitespecific 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 sitespecific 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 materialspecific 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 facilityspecific methods in other reporting 

systems, we are proposing that facilities 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16503 

71Byproducts 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.’’ 

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 qualityassured 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. 

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 combustionrelated 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 

16504 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

Threshold level (metric tons CO2e/r) 

Total 

national 

emissions 

(metric tons 

CO2e) 

Number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e Percent Number Percent 

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 combustionrelated 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 combustionrelated 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 massbalance 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16505 

72EPA is proposing to define ‘‘trace 

concentration’’ as any concentration less than 0.1 

percent by mass of the process stream. 

73Fluorinated GHG Production TSD (EPA–HQ– 

OAR–2008–0508–012). 

74Conversations 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. 

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. 

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 byproducts are sometimes significantly 

different from those of the fluorinated 

GHG product, and if the quantity of byproduct 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. 

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 

16506 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

75One 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.) 

76Emissions 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. 

77However, this double-counting could be 

avoided if the emissions from returned cylinders 

were clearly distinguished from other production 

facility emissions in the emissions report. 

precision of the vent concentration 

measurements.) 

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 UnitSpecific 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

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

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 byproducts 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 

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

Threshold National Total 

Emissions covered Facilities covered 

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 colocation 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 onsite 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 onsite 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 

16508 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 sodalime 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

Threshold level 

metric tons CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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 processrelated 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 (productionbased): 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 productionbased 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 

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

16510 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

rule would also require facilities to 

report the quantity of each carbonatebased 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 nonfeedstock 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

Threshold level (HCFC–22 capacity in 

tons) 

Total national 

emissions 

(metric tons 

CO2e) 

Total national 

facilities 

Emissions covered Facilities covered 

Metric tons 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 capacitybased 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 emissionbased 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 twopercent 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-twopercent 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 

16512 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

78Although 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. 

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. 

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 twopercent 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. 

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

16514 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

CO2 Threshold level (metric tons CO2e/year) 

H2 Production 

capacity (tons 

H2/year) 

Emissions covered Facilities covered 

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 processrelated 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 

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

16516 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 byproduct 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

Threshold level metric tons CO2e 

Total national 

emissions 

(metric tons 

CO2e) 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16517 

TABLE Q–1. THRESHOLD ANALYSIS FOR IRON AND STEEL PRODUCTION—Continued 

Threshold level metric tons CO2e 

Total national 

emissions 

(metric tons 

CO2e) 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Number Percent 

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 carbonin 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 carbonout 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 sitespecific 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 combustionrelated 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 processrelated 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 

16518 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16519 

79See Compilation of Air Pollutant Emission 

Factors, Fifth Edition: http://www.epa.gov/ttn/ 

chief/ap42/ch12/final/c12s02_may08.pdf. 

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. 

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 (sitespecific 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, sitespecific 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 

16520 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

Threshold level metric tons CO2e/yr 

Total 

nationwide 

emissions 

Nationwide 

number of 

facilities 

Emissions covered Facilities covered 

metric tons 

CO2e/yr Percent Facility 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 carboncontaining 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 sitespecific 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 processrelated 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 processrelated 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 qualityassured 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 qualityassured 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 

16522 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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∑MgO)); and dolomitic 

hydrate ((Ca(OH)2∑MgO) or 

(Ca(OH)2∑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 processrelated 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

Threshold level metric tons CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total number 

of facilities 

Emissions covered Facilities covered 

metric tons 

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 

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

16524 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

Threshold level metric tons CO2e/yr 

Total 

nationwide 

emissions 

metric tons 

CO2e/Yr 

Nationwide 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Facilities Percent 

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

Capacity threshold level Mg/yr 

Total 

nationwide 

emissions 

metric tons 

CO2e/Yr 

Number of 

facilities 

Emissions covered Facilities Covered 

Metric tons 

CO2e/yr Percent Facilities Percent 

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) 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 processrelated SF6, HFC–134a, FK 5–1–12, and 

CO2 emissions. Refer to proposed 40 

CFR part 98, subpart C specifically for 

procedures to estimate combustionrelated 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 facilityspecific 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 

16526 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 offsite laboratory for a chemical analysis of 

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

Mineral name—carbonate 

CO2 emission 

factor 

(metric tons 

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 facilitylevel 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

N2O emission threshold 

(metric tons CO2e) 

Process N2O emissions covered 

(metric tons CO2e/yr) 

Facilities 

covered 

Number Percent Number Percent 

1,000 .............................................................................................................. 17,731,650 100 45 100 

10,000 ............................................................................................................ 17,723,576 99.9 44 97 .8 

16528 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE V–1. THRESHOLD ANALYSIS FOR NITRIC ACID PRODUCTION—Continued 

N2O emission threshold 

(metric tons CO2e) 

Process N2O emissions covered 

(metric tons CO2e/yr) 

Facilities 

covered 

Number Percent Number Percent 

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. Facilitylevel 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 sitespecific emissions factor. The sitespecific 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 sitespecific 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 sitespecific 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 sitespecific 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 

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

16530 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

80The 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. 

TABLE W–1. FUGITIVE EMISSIONS FROM PETROLEUM AND NATURAL GAS SYSTEMS (2006) 

Sector 

Fugitive 

CH4

(MMTCO2e) 

Fugitive 

CO2

(MMTCO2e) 

Natural Gas Systems1 ..................................................................................................................................................... 102.4 28.5 

Petroleum Systems .......................................................................................................................................................... 28.4 0.3 

1Emissions 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

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, openended 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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), recondensers, 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 regasified 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 

16532 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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, highpressure 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

Source category 

Total national emissions #a

(metric tons 

CO2e per 

year) 

Total number 

of facilities 

Threshold 

level 

Total emissions covered by 

thresholds s

Facilities covered 

(metric tons 

CO2e per 

year) 

Percent Number Percent 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16533 

TABLE W–2. THRESHOLD ANALYSIS FOR FUGITIVE EMISSIONS FROM THE PETROLEUM AND NATURAL GAS INDUSTRY— 

Continued 

Source category 

Total national emissions #a

(metric tons 

CO2e per 

year) 

Total number 

of facilities 

Threshold 

level 

Total emissions covered by 

thresholds s

Facilities covered 

(metric tons 

CO2e per 

year) 

Percent Number Percent 

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 

aThe 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

Emission source Monitoring method type Emissions quantification methods 

Acid Gas Removal Vent Stacks ......................... Engineering estimation .................................... Simulation software. 

Blowdown Vent Stacks ....................................... Engineering estimation .................................... Gas law and temperature, pressure, and volume between isolation valves. 

Centrifugal Compressor Dry Seals ..................... Direct measurement ......................................... (1) High volume sampler, or (2) Calibrated 

bag, or (3) Meter. 

Centrifugal Compressor Wet Seals .................... Direct measurement ......................................... (1) High volume sampler, or (2) Calibrated 

bag, or (3) Meter. 

Compressor Fugitive Emissions ......................... Direct measurement ......................................... (1) High volume sampler, or (2) Calibrated 

bag, or (3) Meter. 

Dehydrator Vent Stacks ..................................... Engineering estimation .................................... Simulation software. 

Flare Stacks ....................................................... Engineering estimation and direct measurement.Velocity meter and mass/volume equations. 

Natural Gas Driven Pneumatic Pumps .............. (1) Engineering estimation, or (2) Direct 

measurement.

(1) Manufacturer data, equipment counts, and 

amount of chemical pumped, or (2) Calibrated bag. 

Natural Gas Driven Pneumatic Manual Valve 

Actuator Devices.

(1) Engineering estimation, or (2) Direct 

measurement.

(1) Manufacturer data and actuation logs, or 

(2) Calibrated bag. 

Natural Gas Driven Pneumatic Valve Bleed Devices.(1) Engineering estimation, or (2) Direct 

measurement.

(1) Manufacturer data and equipment counts, 

or (2) High volume sampler, or (3) Calibrated bag, or (4) Meter. 

Non-pneumatic Pumps ....................................... Direct measurement ......................................... High volume sampler. 

Offshore Platform Pipeline Fugitive Emissions .. Direct measurement ......................................... High volume sampler. 

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. 

16534 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE W–3. SOURCE SPECIFIC MONITORING METHODS AND EMISSIONS QUANTIFICATION—Continued 

Emission source Monitoring method type Emissions quantification methods 

Reciprocating Compressor Rod Packing ........... Direct measurement ......................................... (1) High volume sampler, or (2) Calibrated 

bag, or (3) Meter. 

Storage Tanks .................................................... (1) Engineering estimation and direct measurement, or (2) Engineering estimation.(1) Meter, or (2) Simulation software, or (3) 

Vasquez-Beggs 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16535 

81EPA/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. 

82EPA (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. 

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. 

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 

16536 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 processrelated 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 processbased 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 offgas (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 (EPAHQ-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

Threshold level metric tons CO2e/yr 

Total National 

Emissions, 

metric tons 

CO2e/yr 

Total number 

of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Number of 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 

16538 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 processbased 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 sitespecific 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 

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

16540 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE Y–1. GHGS TO REPORT UNDER 40 CFR PART 98, SUBPART Y 

Emission source GHGs to report 

Subpart of proposed 40 CFR part 98 

where emissions reporting methodologies 

addressed 

Stationary combustion sources ........................................ CO2, CH4, and N2O .................................. Subpart C. 

Coke burn-off emissions from catalytic cracking units, 

fluid coking units, catalytic reforming units, and coke 

calcining units.

CO2, CH4, and N2O .................................. Subpart Y. 

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 and off-site ......................... CO2 ........................................................... Subpart Y. 

On-site wastewater treatment system .............................. CO2 and CH4 ............................................ Subpart II. 

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

Option/threshold level 

Emissions covered Facilities covered 

Million metric tons 

CO2e/year 

Percent Number Percent 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16541 

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. 

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). 

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 

16542 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 · 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

Threshold level metric tons 

CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16543 

84This 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. 

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 processrelated 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 combustionrelated 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 offsite 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 wetprocess 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 wetprocess 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

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 biomassderived 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 fuelfired boilers because these facilities do 

not generate byproduct biomass fuel. 

Table AA–1 of this preamble lists the 

GHG emission sources that may be 

16544 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

85The 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. 

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

Emissions source GHG emissions 

Subpart of 40 CFR part 98 where 

emissions reporting methodologies 

addressed 

General Stationary Fuel Combustion ...................................................................... CO2, CH4, N2O, 

biomass-CO2.

Subpart C. 

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 mineralbased, 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

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

Threshold level metric tons CO2e 

Total national 

emissions 

(metric tons 

CO2e) 

Total 

number of 

U.S. 

facilities 

Emissions covered Facilities covered 

Metric tons 

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 makeup 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 makeup 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. Makeup 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 

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

16546 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

Threshold level metric tons CO2e/yr 

Total 

national 

emissions 

(metric tons 

CO2e/yr) 

Total 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Number Percent 

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 processrelated 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 facilityspecific 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 processrelated 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 

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

16548 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE CC–1. THRESHOLD ANALYSIS FOR SODA ASH MANUFACTURING

Threshold level metric tons CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

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 combustionrelated 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16549 

86The 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 nonzero 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. 

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 gasinsulated 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 carbonweighted 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. 

This source category comprises 

electric power transmission and 

distribution systems that operate gasinsulated substations, circuit breakers, 

and other switchgear, or power 

transformers containing sulfurhexafluoride (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 emissionbased 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

Nameplate capacity threshold for all 

utilities 

(lbs SF6) 

Total 

national 

emissions 

MMTCO2e/yr 

Total number 

of 

facilities 

Emissions covered Facilities covered 

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 

16550 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE DD–2. OPTIONS FOR EMISSIONS-BASED THRESHOLDS FOR ELECTRIC POWER SYSTEMS

Threshold level metric tons CO2e/yr 

Total 

national 

emissions 

MMTCO2e/yr 

Total 

number of 

facilities 

Emissions covered Facilities covered 

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 massbalance 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 offsite 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16551 

accurate for a large percentage of the 

U.S. source category. 

IPCC Tier 2 methods use countryspecific 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 processrelated 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 sitespecific factor needs to be determined. 

The titanium tetrachloride (TiCl4) 

produced through this first reaction is 

oxidized with oxygen at about 1,000 °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. Processrelated 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

Threshold level metric tons CO2e/yr Total national 

emissions 

Total 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

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 

16552 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE EE–1. THRESHOLD ANALYSIS FOR TITANIUM DIOXIDE PRODUCTION—Continued 

Threshold level metric tons CO2e/yr Total national 

emissions 

Total 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Number Percent 

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 combustionrelated 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 sitespecific 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 processrelated 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 

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

Threshold level metric tons CO2e/yr 

Total national 

emissions 

(metric tons 

CO2e) 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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 

16554 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

87NIOSH, Handbook for Methane Control in 

Mining, CDC Information Circular 9486, June 2006. 

(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). 

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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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. Premining 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 corrosionprotection 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 watercooled, 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 °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). Processrelated 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 zinccontaining 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. 

16556 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE GG–1. THRESHOLD ANALYSIS FOR ZINC PRODUCTION FACILITIES

Threshold level 

metric tons CO2e/yr 

Total 

nationwide 

emissions 

metric tons 

CO2e/yr 

National 

number of 

facilities 

Emissions covered Facilities covered 

Metric tons 

CO2e/yr Percent Facilities Percent 

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 processrelated 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 sitespecific 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 processrelated 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. 

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

16558 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

88For the purposes of this rule, an open landfill 

is one that has accepted waste during the reporting 

year. 

89As 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. 

90The IPCC First Order Decay Model is available 

at http://www.ipcc-nggip.iges.or.jp/public/2006gl/ 

vol5.html. 

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. 

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). 

TABLE HH–1. THRESHOLD ANALYSIS FOR MSW LANDFILLS (OPEN AND CLOSED) 

Threshold level 

Total national 

emissions 

(metric tons 

CO2e) 

Total national 

facilities 

Emissions covered Facilities covered 

Metric tons 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 materialspecific 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 sitespecific data to determine waste 

disposal quantities (by type of waste 

material disposed when materialspecific 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 sitespecific 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 

16560 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 sitespecific 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 sitespecific 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16561 

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. 

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 nonmethane 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 sitespecific 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). 

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 

16562 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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

16564 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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 facilitylevel 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 doublecounting 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. 

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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16565 

94Carbon 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). 

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 endusers 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 emissionsbased 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. 

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

Threshold level 

metric tons CO2e/yr 

Total 2007 

national 

emissions 

(million metric 

tons CO2e/yr) 1

Total 2007 

number of 

facilities in the 

U.S. 

Emissions covered Facilities covered 

Million metric 

tons CO2e/yr 2 Percent Number of facilities 3

Percent of 

facilities 

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 × 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. 

16566 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

95CO2, CH4, and N2O emissions from coal 

combustion 2065.3, 0.8, and 10.23 million metric 

tons CO2e, respectively. 

(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. 

We are proposing that coal mines, 

coal importers, coal exporters, and 

reclaimers of waste coal use a massbalance 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 routinelycollected 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 minespecific, 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 minespecific statistically significant 

correlation between the coal carbon 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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, subbituminous, or lignite), name and 

MSHA identification number of mine of 

origin, country of destination, minespecific 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 

16568 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

96Coal Conversion—Pathway to Alternate Fuels. 

C. Lowell Miller. 2007 EIA Energy Outlook 

Modeling and Data Conference. Washington, DC, 

March 28, 2007. 

97For a discussion of the benefits and 

disadvantages of default carbon factors versus direct 

measurement see Section V.MM.3 of this preamble. 

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-toliquids 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. 

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 petroleumbased fuels in proposed 40 CFR part 98, 

subpart MM or develop their own 

factors.97 Reporters that choose to 

substitute their own batch- or facilityspecific 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16569 

98A 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. 

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. 

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, coalbased 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 semirefined 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. 

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-byfacility basis. For refiners that trade 

semi-refined and refined petroleum 

products between facilities, leading to a 

16570 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

99See Section V.MM.3 of this preamble regarding 

a method for accounting for trade between 

refineries. 

100Refiners, 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. 

possible risk of double-counting in 

coverage, we are proposing a straightforward accounting method in Section 

V.MM.5 of this preamble to address this 

possibility. 

To account for refined and semirefined 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 nonroad mobile end-uses. This rule would 

include all importers regardless of enduse 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-byfacility 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 semirefined 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

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. 

Certain petroleum products can be coprocessed 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

Threshold level metric tons 

CO2/yr 

Total volume 

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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16571 

101To 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. 

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. 

TABLE MM–2. THRESHOLD ANALYSIS FOR REFINERIES

Threshold level metric tons 

CO2e/yr 

Total national 

emissions 1 2 metric tons CO2/yr 

Total number 

of facilities 3

Emissions covered Facilities covered 

Metric tons CO2/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 

1These constitute total emissions from all petroleum products ex refinery gate. The total includes only CO2 emissions. 2Estimated CO2 emissions for all refineries are based on applying product-specific default carbon contents to production of each product. 3This 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 oneyear period and with a corporateaverage 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

Threshold level metric tons CO2e/yr 

Total national 

emissions 1

metric tons 

CO2/yr 

Total number 

of importers 

Emissions covered Companies covered 

Metric tons 

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 

1These 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 

16572 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 industrystandard test methods for flow meters 

and tank gauges for measuring volumes 

of feedstocks and products. For ultrasonic 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16573 

102CO2, 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. 

104See 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. 

105The generic formula is CO2 = Fuel Quantity * 

Carbon Content * 44/12. 

106This could include both petroleum- and 

natural gas-based products. 

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 noncrude 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. 

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. 

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. 

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 doublecounting products, especially semirefined 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 longlived 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 nonemissive 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 noncrude 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. 

16574 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

107Proposed 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. 

108Current regulations require refiners and 

importers to designate diesel fuel (40 CFR 

80.598(a)(2)). 

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 noncrude) 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 biomassbased 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 facilityspecific 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. 

Designated End-use. Although not 

required as a direct input to the massbalance 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 enduse consumption patterns, and other 

options EPA could pursue to track the 

combustion-related end-uses of 

petroleum products. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16575 

109This 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. 

110This 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. 

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 facilityspecific 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 nonenergy 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

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. 

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 bypassing processing plants. In the interest 

of increasing coverage, we considered 

but decided not to propose including 

16576 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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

Threshold level metric tons CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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

Threshold level metric tons CO2e/yr 

Total national 

emissions 

metric tons 

CO2e/yr 

Total number 

of facilities 

Emissions covered Facilities covered 

Metric tons 

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– 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16577 

111 In 2006, CO2, CH4 and N2O emissions from 

natural gas combustion were 1,155.1, 1.0, and 0.6 

MMTCO2e, respectively. 

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. 

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. 

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 nationallyaccepted 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

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. 

16578 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

113Please see the proposed definition of 

fluorinated GHG near the end of this section. 

114 IPCCC SAR available at: http://www.ipcc.ch/ 

ipccreports/assessments-reports.htm. 

115The 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. 

116 IPCCC SAR. 

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’’. 

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

HFCs are the most commonly used 

fluorinated GHGs, they are used 

primarily as a replacement for ODS in 

a number of applications, including airconditioning 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 airconditioning 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. 

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

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 pressurepackaged 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 preblended anesthetics and aerosol 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16579 

117We 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. 

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 costeffective 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

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. 

16580 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE OO–1. THRESHOLD ANALYSIS FOR INDUSTRIAL GAS SUPPLY

Source category 

Emission 

threshold level 

(metrics tons 

CO2e/yr) 

Total national 

production or 

import 

(metric tons 

CO2e/yr) 

Number of 

facilities 

Production or imports covered Facilities Covered 

Metric tons 

CO2e/yr Percent Number Percent 

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 

(bulk) ....................... 1,000 110,024,979 116 110,024,987 100 111 96 

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 facilityspecific 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, 

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

16582 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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

16584 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 postoperational 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

Threshold level metric tons 

CO2e 

Total national 

emissions 

(metric tons 

CO2e) 

Total number 

of U.S. 

facilities 

Emissions covered Facilities covered 

Metric tons 

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 

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

Threshold level metric tons CO2e 

Total national 

emissions 

(metric tons 

CO2e) 

Total number 

of U.S. 

facilities * 

Emissions covered Facilities covered 

Metric tons 

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. 

16586 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

118The 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. 

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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16587 

119See 40 CFR 1803–01 for full definitions of 

‘‘light-duty vehicle’’. 

TABLE QQ–1. MOBILE SOURCE VEHICLE AND ENGINE CATEGORIES— 

Continued 

Category 

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. 

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 heavyduty and nonroad engines, sell their 

products as complete engine-plusvehicle 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 

16588 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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/Crelated 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 systemvehicle 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’’). 

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 °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 °F 

used in the SC03 test. However, we 

believe that A/C-related CO2 can be 

accurately demonstrated on the Idle 

Test at 75 °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 °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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16589 

121See 40 CFR 1803–01 for full definitions of 

‘‘heavy-duty vehicle’’ and ‘‘heavy-duty engine.’’ 

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. Designbased 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/Crelated 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 loadcarrying container attached. 

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 heavyduty 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 heavyduty engines. Thus, as described above, 

these manufacturers would report the 

CO2 emissions they are currently 

measuring as part of criteria air 

16590 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 originalequipment 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 gasolinefueled) 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-unitof-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 cycleweighted CH4 emissions for these 

engines and for highway motorcycles. 

Finally, we are proposing that 

manufacturers also report the cycleweighted 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

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16591 

122Currently, these engine manufacturers 

voluntarily report criteria air pollutant emissions 

for the LTO cycle to the International Civil Aviation 

Organization. 

123EPA 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. 

124Existing 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. 

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

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

4. Request for Comments on Travel 

Activity and Other In-Use, EmissionsRelated Data 

Travel activity and other emissionsrelated 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 inuse 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 emissionsrelated 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 

16592 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

125EPA 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. 

126EPA 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. 

127Under the AERR, VMT data should reflect 

both roadway type and vehicle type information. 

128The 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. 

129For 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. 

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. 

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. 

In addition to EPA’s existing data 

collection requirements, there are other 

sources of travel activity and emissionsrelated 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. 

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 emissionsrelated 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), inuse testing as part of vehicle and engine 

manufacturer compliance programs, adhoc 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. 

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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16593 

130The 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. 

132See 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. 

134A ‘‘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. 

135The 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. 

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

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

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. 

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, heavyduty 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 

16594 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16595 

136The Federal Civil Penalties Inflation 

Adjustment Act of 1990, Public Law 101–410, 104 

Continued 

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

16596 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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 

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

Subpart 

Number of 

covered 

entities 

Downstream emissions First year capital costs First year total annualized 

costs 2

(Million of 

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 Systems ............... 141 10.3 0 0.0 0 0.4 0 

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 & Subpart LL— 

Suppliers of Coal-based Liquid Fuels .. 1,237 (1) 0 0.0 0 11.0 7 

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 

16598 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE VIII–1. ESTIMATED COVERED ENTITIES, EMISSIONS AND COSTS BY SUBPART (2006$)—Continued 

Subpart 

Number of 

covered 

entities 

Downstream emissions First year capital costs First year total annualized 

costs 2

(Million of 

MtCO2e) 

Share 

(%) (Million) Share (%) (Million) Share 

(%) 

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 

1Emissions from upstream facilities are excluded from these estimates to avoid double counting. 

2Total 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$) 

Threshold (metric tons CO2e) Entities 

(covered) 

Total costs 

(million $) 

Million 

metric tons 

CO2e/year 

(covered) 

Percentage 

of total 

emissions 

reported 

Average 

cost 

($/metric 

ton) 

Incremental 

cost 

($/metric 

ton) 

Marginal 

cost * 

($/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 234

Source category No. of 

Reporters 

Emissions 

coverage 

(%) 10

First year 

cost 

(millions) 

Source category No. of 

Reporters 2

Emissions 

coverage 3 10

(%) 

First year 

cost 3

(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 and gas).

1,475 86.6 34.86 

Biological Processes ........ 2,792 55.5 16.59 

Vehicle 7 and Engine Manufacturers 9.350 84.0 7.41 

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. 2Estimating 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). 3The 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. 4The 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). 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16599 

5Estimates 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. 6Approximately 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. 8The 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. 9The 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. 10Emissions 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. 11EPA 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 perentity costs are low. Average cost-tosales 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

NAICS NAICS description 

Average 

cost per 

entity 

($1,000/ 

entity) 

Average 

entity costto-sales 

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, & component mfg .............................................. 37 0.2 

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 mfg ........................................................... 28 <0.1 

3272 ............................................. Glass & glass product mfg .................................................................................... 11 0.1 

325120 ......................................... Industrial gas mfg .................................................................................................. 3 <0.1 

331112 ......................................... Electrometallurgical ferroalloy product mfg ........................................................... 150 0.3 

3314 ............................................. Nonferrous metal (except aluminum) production & processing ............................ 23 0.1 

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 

16600 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

137EPA’s RFA guidance for rule writers suggests 

the ‘‘sales’’ test continues to be the preferred 

quantitative metric for economic impact screening 

analysis. 

TABLE VIII–4. ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES—Continued 

NAICS NAICS description 

Average 

cost per 

entity 

($1,000/ 

entity) 

Average 

entity costto-sales 

ratio 1

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) production & processing ............................ 19 0.1 

1This 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 industryspecific 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. 

TABLE VIII–5. ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a

Industry NAICS NAICS description 

SBA Size 

standard 

(effective 

March 11, 

2008) 

Average 

cost per 

entity 

($1,000/ 

entity) 

All enterprises 

(%) 

Owned by enterprises with: 

<20 

Employees f

20 to 99 

Employ- ees 

(%) 

100 to 

499 Employees 

(%) 

500 to 

749 Employees 

(%) 

750 to 

999 Employees 

(%) 

1,000 to 

1,499 

Employ- ees 

(%) 

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 

1,000 

12 0.0 0.6 0.1 0.0 0.0 0.0 0.0 

Cement & Other 

Mineral Production.

327 Nonmetallic mineral 

product mfg.

500 to 

1,000 

51 0.8 4.9 1.0 0.5 0.4 0.6 0.4 

Primary Metal Manufacturing.331 Primary metal mfg 500 to 

1,000 

112 0.4 9.1 1.4 0.4 0.2 0.1 0.2 

Computer and 

Electronic Product Manufacturing.

334 Computer & electronic product 

mfg.

500 to 

1,000 

37 0.1 2.9 0.5 0.1 0.1 0.1 0.1 

Electrical Equipment, Appliance, 

and Component 

Manufacturing.

335 Electrical equipment, appliance, 

& component 

mfg.

500 to 

1,000 

37 0.2 2.9 0.5 0.2 0.1 0.1 0.1 

Oil & Natural Gas 

Transportation.

486 Pipeline transportation.(d) 12 0.1 0.1 0.4 0.4 NA NA NA 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16601 

TABLE VIII–5. ESTIMATED COST-TO-SALES RATIOS BY INDUSTRY AND ENTERPRISE SIZE a—Continued 

Industry NAICS NAICS description 

SBA Size 

standard 

(effective 

March 11, 

2008) 

Average 

cost per 

entity 

($1,000/ 

entity) 

All enterprises 

(%) 

Owned by enterprises with: 

<20 

Employees f

20 to 99 

Employees 

(%) 

100 to 

499 Employees 

(%) 

500 to 

749 Employees 

(%) 

750 to 

999 Employees 

(%) 

1,000 to 

1,499 

Employees 

(%) 

Waste Management and Remediation Services.

562 Waste management & remediation services.

(e) 6 0.2 0.9 0.1 0.1 0.1 0.0 0.1 

Adipic Acid ............. 325199 All other basic organic chemical 

mfg.

1,000 24 0.0 0.9 0.3 0.1 NA 0.0 NA 

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 product 

mfg.

750 28 0.0 NA NA NA NA NA NA 

Glass ..................... 3272 Glass & glass product mfg.500 to 

1,000 

11 0.1 1.7 0.2 0.1 0.0 0.1 0.0 

Hydrogen Production.325120 Industrial gas mfg .. 1,000 3 0.0 0.6 0.0 0.1 NA NA NA 

Iron and Steel ........ 331112 Electrometallurgical 

ferroalloy product 

mfg.

750 150 0.3 NA NA NA NA NA NA 

Lead Production .... 3314 Nonferrous metal 

(except aluminum) production & processing.

750 to 

1,000 

23 0.1 1.5 0.2 0.1 NA NA 0.1 

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 

1,000 

9 0.0 0.3 0.1 0.0 0.0 0.0 0.0 

Titanium Dioxide .... 325188 All other basic inorganic chemical 

mfg.

1,000 9 0.0 0.7 0.4 0.1 NA NA NA 

Zinc Production ..... 3314 Nonferrous metal 

(except aluminum) production & processing.

750 to 

1,000 

19 0.1 1.2 0.1 0.1 NA NA 0.1 

aThe 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. fGiven 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. 

16602 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

138Nicholas 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. 

EPA was not able to calculate a costto-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. 

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 perrespondent 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 facilitylevel 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 costto-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 costVerDate Nov<24>2008 15:41 Apr 09, 2009 Jkt 217001 PO 00000 Frm 00157 Fmt 4701 Sfmt 4702 E:\FR\FM\10APP2.SGM 10APP2
16604 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

139U.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. 

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

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 sectorspecific 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 

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

16606 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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: 

§ 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/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

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

§ 86.078–3 Abbreviations. 

* * * * * 

* * * * * 

CH4 methane. 

* * * * * 

N2O nitrous oxide. 

* * * * * 

Subpart B—[Amended] 

4. A new § 86.165–11 is added to read 

as follows: 

§ 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 lightduty 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 tenminute period when CO2 emissions are 

measured with the air conditioning 

system operating. This test is designed 

to determine the air conditioningrelated CO2 emission value, in grams 

per minute per cubic foot of interior 

volume. If engine stalling occurs during 

cycle operation, follow the provisions of 

§ 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 

§ 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 warmedup 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 °F (5 °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: 

§ 86.403–78 Abbreviations. 

* * * * * 

* * * * * 

CH4 methane. 

* * * * * 

N2O nitrous oxide. 

* * * * * 

6. Section 86.431–78 is amended by 

adding paragraph (e) to read as follows: 

§ 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 § 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. Smallvolume manufacturers (as defined in 

§ 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: 

§ 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: 

§ 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 

16608 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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: 

§ 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: 

§ 87.2 Acronyms and abbreviations. 

* * * * * 

CH4 methane. 

* * * * * 

CO2 carbon dioxide. 

* * * * * 

12. Section 87.64 is revised to read as 

follows: 

§ 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 § 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: 

§ 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: 

§ 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 § 89.407(d)(1); 

* * * * * 

Subpart E—[Amended] 

16. Section 89.407 is amended by 

revising paragraph (d)(1) to read as 

follows: 

§ 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 lowhour 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/kWhr. 

(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: 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16609 

§ 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: 

§ 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 § 90.409(c)(1); 

* * * * * 

Subpart E—[Amended] 

20. Section 90.409 is amended by 

revising paragraph (c)(1) to read as 

follows: 

§ 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 lowhour 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/kWhr. 

(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: 

§ 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: 

§ 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. 

§ 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: 

§ 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, § 94.104(e) for 

Category 2 engines, and § 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. 

16610 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

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

16612 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

§ 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. 

§ 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 m2 silicon. 

(B) MEMS: 1,020 m2 silicon. 

(C) LCD: 235,700 m2 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 § 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 § 98.6) in metric tons from 

stationary fuel combustion units, 

miscellaneous uses of carbonate, and 

any applicable source category listed in 

paragraph § 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 § 98.33(a). Calculate 

the annual CH4 and N2O emissions from 

the stationary combustion sources in 

metric tons using Equation C–9 in 

§ 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 

§ 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. 

CO e GHG x GWP i i

i

n

2

1

= =

∑ (Eq. A-1)

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 § 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 

§ 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. 

§ 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. 


EP10AP09.000</GPH>
16614 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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 

§ 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 § 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 

§ 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 

§ 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 sitespecific 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16615 

§ 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 

16616 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 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. 

§ 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 highpurity 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 nonfossilized and biodegradable organic 

material. 

Blast furnace means a furnace that is 

located at an integrated iron and steel 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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°API crude oil 

from a separator temperature of 100 °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°API crude oil 

from a separator temperature of 100 °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°API crude oil from a separator 

temperature of 100 °F and pressure of 40 

psig. 

Calibrated bag means a flexible, nonelastic 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, 

16618 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 § 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 

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

DE tCO e

tCO e

OUT

IN

= −1 2

2

(Eq. A-2)

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 

§ 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 § 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 § 98.7). 

Diesel fuel No. 1 has a distillation 

temperature of 550 °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 °F at the 10 percent 

recovery point and 640 °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 


EP10AP09.001</MATH>
16620 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 °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 byproducts. 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 ° to 

158 °F at the 10 percent recovery point 

to 365 ° to 374 °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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 nonaspirated 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 sodalime 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 °F at the 10 percent 

recovery point and 550 °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 °F at the 10 percent 

recovery point and 640 °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. 

16622 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 °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 °F at the 10 percent recovery point 

and a final maximum boiling point of 

572 °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 

§ 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, recondensers, 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, recondensers, 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 

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

16624 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 byproducts 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, 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 °F and other oils greater 

than 401 °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, 

16626 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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, nonhydrocarbon 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 ironbearing 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, carboncontaining 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° to 470 °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 semichemical 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16627 

hydrocarbon liquids, or produced water 

and that is constructed entirely of nonearthen 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. 

16628 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 °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 zincbearing feed materials charged to a 

furnace. 

§ 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 

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

§ 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) 

Name CAS No. Chemical formula 

Global warming 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 

16630 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE A–1 OF SUBPART A—GLOBAL WARMING POTENTIALS (100-YEAR TIME HORIZON)—Continued 

Name CAS No. Chemical formula 

Global warming potential 

(100 yr.) 

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 × 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 (m3) ............................................................ Cubic feet (ft3) .................................................................. 35.31467. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16631 

TABLE A–2 OF SUBPART A—UNITS OF MEASURE CONVERSIONS—Continued 

To convert from To Multiply by 

Cubic feet (ft3) .................................................................. Cubic meters (m3) ............................................................ 0.028317. 

Gallons (liquid, US) .......................................................... Liters (l) ............................................................................ 3.78541. 

Liters (l) ............................................................................ Gallons (liquid, US) .......................................................... 0.26417. 

Barrels of Liquid Fuel (bbl) .............................................. Cubic meters (m3) ............................................................ 0.15891. 

Cubic meters (m3) ............................................................ Barrels of Liquid Fuel (bbl) .............................................. 6.289. 

Barrels of Liquid Fuel (bbl) .............................................. Gallons (liquid, US) .......................................................... 42. 

Gallons (liquid, US) .......................................................... Barrels of Liquid Fuel (bbl) .............................................. 0.023810. 

Gallons (liquid, US) .......................................................... Cubic meters (m3) ............................................................ 0.0037854. 

Liters (l) ............................................................................ Cubic meters (m3) ............................................................ 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 (ft2) ............................................................... Acres ................................................................................ 2.29568 × 10¥5. 

Square meters (m2) ......................................................... Acres ................................................................................ 2.47105 × 10¥4. 

Square miles (mi2) ........................................................... Square kilometers (km2) .................................................. 2.58999. 

Degrees Celsius (°C) ....................................................... Degrees Fahrenheit (°F) .................................................. °C = (5/9) × (°F¥32). 

Degrees Fahrenheit (°F) .................................................. Degrees Celsius (°C) ....................................................... °F = (9/5) × °C + 32. 

Degrees Celsius (°C) ....................................................... Kelvin (K) ......................................................................... K = °C + 273.15. 

Kelvin (K) .......................................................................... Degrees Rankine (°R) ...................................................... 1.8. 

Joules ............................................................................... Btu .................................................................................... 9.47817 × 10¥4. 

Btu .................................................................................... MMBtu .............................................................................. 1 × 10¥6. 

Pascals (Pa) ..................................................................... Inches of Mercury (in Hg) ................................................ 2.95334 × 10¥4. 

Inches of Mercury (inHg) ................................................. Pounds per square inch (psi) .......................................... 0.49110. 

Pounds per square inch (psi) ........................................... Inches of Mercury (in Hg) ................................................ 2.03625. 

Subpart B—[Reserved] 

Subpart C—General Stationary Fuel 

Combustion Sources 

§ 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. 

§ 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 

§ 98.2(a)(1), (2), or (3). 

§ 98.32 GHGs to report. 

You must report CO2, CH4, and N2O 

mass emissions from each stationary 

fuel combustion unit. 

§ 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: 

CO x Fuel HHV EF 2

3 = ∗∗ ∗ 1 10− (Eq. C-1)

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): 


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CO x Fuel HHV EF p p

p

n

2

3

1

= ∗∗ 1 10−

=

∑ ( ) ( ) (Eq. C-2a)

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 

§ 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: 

CO x Steam B EF 2

3 = 1 10− ( ) ( ) ( ) (Eq. C-2b)

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: 

CO Fuel CC n n

p

n

2

1

44

12 =∗ ∗ =

∑ ( ) ( ) (Eq. C-3)

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: 

CO Fuel CC n n

p

n

2

1

44

12 = ∗ ∗∗ 0 001 =

∑ ( ) ( ) (Eq. C-4) .

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: 

CO Fuel CC MW

MVC n n

p

n

2

1

44

12 = ∗ ∗ ∗∗ 0 001 =

∑ ( ) ( ) (Eq. C-5) .

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). 


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(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: 

CO x C Q 2 CO

7 = ∗∗ 5 18 10− . 2 (Eq. C-6)

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 

§ 75.11(b)(2) of this chapter or, for 

certain types of fuel, use a default 

moisture percentage from § 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: 

CO CO H O 2 2

2 100

100

* % = ⎛ −

⎝

⎜ ⎞

⎠

⎟ (Eq. C-7)

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 § 75.11(b)(2) of this chapter, or, for 

certain types of fuel, a default moisture 

value from § 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 


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16634 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 § § 75.10(c) and 75.64 

of this chapter, use Equation C–8 of this 

section: 

CH or N O x HI EF 4 2 A 1 10 ( ) (Eq. C-8) = ∗∗ −3

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 § 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: 

CH or N O x Fuel HHV EF 4 2 1 10 (Eq. C-9) = ∗∗ ∗ −3

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: 

CH or N O x Fuel HHV EF p

n

4 2 p p 1 10 (Eq. C-10a) = ∗∗ ∗ −

=

∑ 3

1

( ( ) )

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 


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

CH or N O x Steam B EF 4 2 1 10 (Eq. C-10b) = −3 ( )( )( )

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: 

CO S R MW

MW

CO

S

2 =∗∗ ⎛

⎝

⎜ ⎞

⎠

⎟ 2 (Eq. C-11)

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 biomassderived fuel in § 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 biomassderived 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. 

V

CO

Q t CO h

h

2 = h h

( ) ∗ ∗ % 2

100 (Eq. C-12)

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. 

V Fuel F GCV

ff

c = ∗ ∗

106 (Eq. C-13)

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: 

% Biogenic V

V

x bio

total

= 100 (Eq. C-14)


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16636 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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 

§ 98.34(f), to determine the relative 

proportions of biogenic and nonbiogenic 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. 

§ 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 

§ 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 § 98.33(a) are used. 

(2) Fuel consumption, when solid fuel 

is combusted and the Tier 3 Calculation 

Methodology in § 98.33(a)(3) is used. 

(3) Fossil fuel consumption, when, 

pursuant to § 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 § 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 § 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 § 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 § 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 

§ 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 

§ 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16637 

part 60 of this chapter is selected for ongoing 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. 

§ 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 qualityassured values of that parameter 

immediately preceding and immediately 

following the missing data incident. If, 

for a particular parameter, no qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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. 

§ 98.36 Data reporting requirements. 

(a) In addition to the facility-level 

information required under § 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 § 98.33(a)(4), the owner 

or operator may report the combined 

emissions from the units sharing the 

16638 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

§ 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 § § 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 § 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 §§ 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 kgmole. 

(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 § 98.7 used to make tank 

drop measurements (if applicable). 

(H) Each method from § 98.7 used to 

determine the CC for each type of fuel 

combusted. 

(I) Each method from § 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 §§ 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 § 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 § 98.33(a)(3) is used to 

calculate CO2 emissions. 

(iii) A detailed explanation of how 

sorbent usage is quantified, if the 

methodology in § 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 § 98.33(e), the owner or 

operator of a unit that combusts both 

fossil fuel and biogenic fuel uses CEMS 

to quantify CO2 emissions. 

§ 98.37 Records that must be retained. 

The recordkeeping requirements of 

§ 98.3(g) and, if applicable, § 98.34(a) 

and (b) shall be fully met for affected 

facilities with stationary combustion 

sources. Also, the records required 

under § 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 § 98.33(c)(4)), 

shall be retained. No special 

recordkeeping beyond that specified in 

§§ 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. 

§ 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

Fuel type Default high heat 

value 

Default CO2

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/Commercial) ......................................................................................................... 22.24 95.26 

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. Average) ......................................................................................................... 1.027 x 10¥3 53.02 

Petroleum Products mmBtu/gallon kg CO2/mmBtu 

Asphalt & Road Oil ...................................................................................................................................... 0.158 75.55 

Aviation gasoline .......................................................................................................................................... 0.120 69.14 

Distillate Fuel Oil (# 1, 2, & 4) ..................................................................................................................... 0.139 73.10 

Jet Fuel ........................................................................................................................................................ 0.135 70.83 

Kerosene ...................................................................................................................................................... 0.135 72.25 

LPG (energy use) ........................................................................................................................................ 0.092 62.98 

16640 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE C–1 OF SUBPART C—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS TYPES OF FUEL— 

Continued 

Fuel type Default high heat 

value 

Default CO2

emission factor 

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 & 6) .......................................................................................................................... 0.150 78.74 

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 content) or other solid biomass-derived fuels .............................. 15.38 93.80 

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

Fuel type 

Default CO2

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

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Asphalt ......................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Aviation Gasoline ......................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Coal .............................................................................................................................................................. 1.0 × 10¥2 1.5 × 10¥3

Crude Oil ...................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Digester Gas ................................................................................................................................................ 9.0 × 10¥4 1.0 × 10¥4

Distillate ....................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Gasoline ....................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Jet Fuel ........................................................................................................................................................ 3.0 × 10¥3 6.0 × 10¥4

Kerosene ...................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Landfill Gas .................................................................................................................................................. 9.0 × 10¥4 1.0 × 10¥4

LPG .............................................................................................................................................................. 1.0 × 10¥3 1.0 × 10¥4

Lubricants .................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Municipal Solid Waste ................................................................................................................................. 3.0 × 10¥2 4.0 × 10¥3

Naphtha ....................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Natural Gas .................................................................................................................................................. 9.0 × 10¥4 1.0 × 10¥4

Natural Gas Liquids ..................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Other Biomass ............................................................................................................................................. 3.0 × 10¥2 4.0 × 10¥3

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16641 

TABLE C–3 OF SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL—Continued 

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Petroleum Coke ........................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Propane ....................................................................................................................................................... 1.0 × 10¥3 1.0 × 10¥4

Refinery Gas ................................................................................................................................................ 9.0 × 10¥4 1.0 × 10¥4

Residual Fuel Oil ......................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Tites ............................................................................................................................................................. 3.0 × 10¥3 6.0 × 10¥4

Waste Oil ..................................................................................................................................................... 3.0 × 10¥2 4.0 × 10¥3

Waxes .......................................................................................................................................................... 3.0 × 10¥3 6.0 × 10¥4

Wood and Wood Waste .............................................................................................................................. 3.0 × 10¥2 4.0 × 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 

§ 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. 

§ 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 § 98.2(a)(1) or 

(2). 

§ 98.42 GHGs to report. 

The annual mass emissions of CO2, 

N2O, and CH4 shall be reported for each 

electricity generating unit. 

§ 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 

§§ 75.13 and 75.64 of this chapter. CO2

emissions for the purposes of the GHG 

emissions reports required under 

§§ 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 § 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 § 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 § 98.33 

for stationary fuel combustion units. 

§ 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 § 98.34 for 

stationary fuel combustion units shall 

be followed. 

§ 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 

§ 98.35 for stationary fuel combustion 

units shall be implemented. 

§ 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 § 98.36(b) and, if applicable, 

§ 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 § 98.36. 

§ 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 § 98.3(g) 

and, if applicable, § 98.37. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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 carbonbased fuel, following the requirements 

of subpart C of this part. 

§ 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 

16642 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

§ 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: 

EF

C Q

P

n N O

N O

n

2

2

=

∗×∗ −

∑ 1 14 10 7

1

. 

(Eq. E-1)

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: 

EN2O = (Eq. E-2)

EF P AF ∗ ∗− ( ) ∗ NO a N 2 1

2205

DFN

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). 

§ 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 

§ 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 referencesee § 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. 

§ 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 § 98.53. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. 

§ 98.56 Data reporting requirements. 

In addition to the information 

required by § 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). 

§ 98.57 Records that must be retained. 

In addition to the information 

required by § 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. 


EP10AP09.018</GPH> EP10AP09.019</GPH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16643 

(f) Emission rate factor used and 

supporting test or calculation 

information including the annual 

emission rate factor determination 

report specified in § 98.54(c). This 

report must be available upon request. 

§ 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 

§ 98.60 Definition of the source category. 

(a) A primary aluminum production 

facility manufactures primary 

aluminum using the Hall-He ́roult 

manufacturing process. The primary 

aluminum manufacturing process 

comprises the following operations: 

(1) Electrolysis in prebake and 

S<derberg cells. 

(2) Anode baking for prebake cells. 

(b) This source category does not 

include experimental cells or research 

and development process units. 

§ 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 § 98.2(a)(1) or (2). 

§ 98.62 GHGs to report. 

You must report: 

(a) Total perfluoromethane (CF4), and 

perfluoroethane (C2F6) emissions from 

anode effects in all prebake and 

S<derberg electrolysis cells. 

(b) Total CO2 emissions from anode 

consumpton during electrolysis in all 

prebake and S<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. 

§ 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<derberg 

electrolysis cell. 

E S AEM MP CF CF 4 4 =× ×× (Eq. F-1) 0 001 .

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. 

E EF C F CF C F CF 26 4 26 4 (Eq. F-2) =× × 0 001 / .

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: 

E NAC MP S Ash CO a a 2 = × × −− (Eq. F-3) ( ) [ ] 100 100 44 12 / (/) ×

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<derberg cells you must 

calculate CO2 emissions using Equation 

F–4 of this section: 

E PC x MP CSM x MP BC PC

MP S

CO

p

2 = − [ ] 1000 100 − ××

× +

 ( 

 

/ /

Ash H BC PC MP

S Ash

p p

c c

 

 

⎡ + ⎣ ⎤

⎦ − − [ ] ×× ×

[ ] +

/ / 100 100 100

/ ( /) 100 44 12 

(Eq. F-4)

−×× MP CD

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<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: 


EP10AP09.020</MATH> EP10AP09.021</MATH> EP10AP09.022</MATH> EP10AP09.023</MATH>
16644 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(1) Use Equation F–5 of this section to 

calculate emissions from pitch 

volatiles. 

E GA H BA WT CO PV w 2 = −−− (Eq. F-5) ( ) × ( /) 44 12

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. 

E PCC BA S Ash CO PC pc pc 2 = ×× −− ⎡100 100 44 12 ⎣ ⎤ ( ) ⎦ (E / ( /) q ×. F-6)

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. 

§ 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 § 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. 

§ 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. 

ECO EF x MP EF x MP 2 = + ppss (Eq. F-7)

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<derberg technology specific emission 

factor (1.7 tonnes CO2/tonne Al 

produced). 

MPs = Metal production from S<derberg 

process (tonnes Al). 

(b) For other parameters, use the 

average of the two most recent data 

points. 

§ 98.66 Data reporting requirements. 

In addition to the information 

required by § 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<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 smelterspecific-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<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<derberg). 

§ 98.67 Records that must be retained. 

In addition to the information 

required by § 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<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<derberg electolysis 

cells. 


EP10AP09.024</GPH> EP10AP09.025</GPH> EP10AP09.026</GPH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16645 

(3) Smelter-specific slope coefficient 

and the last date when the smelterspecific-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<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<derberg). 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 § 98.33(b)(5)(iii)(A), (B), 

and (C), or § 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 

§ 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: 

CO Fdstk CC MW

MVC 2 n n

44

12 = ∗ ( ) ∗ ∗ 0 001 ⎛

⎝

⎜ ⎞

⎠

⎟ ∑ () . ∗ n=1

12

(Eq. G-1)

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: 

CO Fdstk CC 2 n n

44

12 = ∗ ( ) ∗ 0 001 ⎛

⎝

⎜ ⎞

⎠

⎟ v∑ () . ∗ n=1

12

(Eq. G-2)

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: 

CO Fdstk CC n n

n

2

1

12 44

12 = ∗ ( ) ∗ 0 001 ⎛

⎝

⎜ ⎞

⎠

⎟∗ =

∑ ( ) . (Eq. G-3)


EP10AP09.027</GPH> EP10AP09.028</GPH> EP10AP09.029</MATH>
16646 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 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 § 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. 

§ 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. 

§ 98.76 Data reporting requirements. 

In addition to the information 

required by § 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). 

§ 98.77 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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). 

§ 98.83 Calculating GHG emissions. 

(a) Cement kilns that meet the 

conditions specified in § 98.33(b)(5)(ii) 

or (iii) shall calculate total CO2

emissions using the Tier 4 Calculation 

Methodology specified in § 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: 

CO CO CO CMF cli m rm

m

k

2 22

1

 (Eq. H-1) = + =

∑ ,

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. 

CO cli,m Cli, EFcli, CKD, EFCKD, 2 jj i i (Eq. = ( ) ∗( ) ⎡

⎣ ⎤⎦ + ⎡( ) ∗ ( ) ⎣ ⎤

⎦ H-2) i

r

j

p

= =

∑ ∑ 1 1


EP10AP09.030</MATH> EP10AP09.031</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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. 

EF CLi Cli MR Cli Cli MR Cli CaO ncCaO CaO MgO ncMgO MgO = − ( ) ∗+ − ( ) ∗ (Eq. H-3)

Where: 

CliCaO = Monthly CaO content of Clinker, 

wt% as determined in § 98.84(b). 

MRCaO = Molecular Ratio of CO2/CaO = 

0.785. 

CliMgO = Monthly MgO content of Clinker, 

wt% as determined in § 98.84(b). 

MRMgO = Molecular Ratio of CO2/MgO = 

1.092. 

ClincCaO = Monthly non-carbonate CaO of 

Clinker, wt% as determined in 

§ 98.84(b). 

ClincMgO = Monthly non-carbonate MgO of 

Clinker, wt% as determined in 

§ 98.84(b). 

(i) EFCKD must be determined through 

X-ray fluorescence (XRF) test or other 

testing method specified in § 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 noncarbonate MgO of clinker used in 

Equation H–3 must be determined using 

the measurement methods specified in 

§ 98.84(b). 

(3) CO2 emissions from raw materials. 

Calculate CO2 emissions using Equation 

H–4 of this section: 

CO rm TOC 2 rm (Eq. H-4) 3 664 rm =∗ ∗ .

Where: 

rm = The amount of raw material consumed 

annually, metric tons/yr. 

TOCrm = Organic carbon content of raw 

material, as determined in § 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. 

§ 98.84 Monitoring and QA/QC 

requirements. 

(a) You must determine the plantspecific 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. 

§ 98.85 Procedures for estimating missing 

data. 

If the CEMS approach is used to 

determine CO2 emissions, the missing 

data procedures in § 98.35 apply. 

Procedures for estimating missing data 

do not apply to CO2 process emissions 

from cement manufacturing facilities 

calculated according to § 98.83(b). If 

data on the carbonate content or organic 

carbon content is missing, facilities 

must undertake a new analysis. 

§ 98.86 Data reporting requirements. 

In addition to the information 

required by § 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 § 98.36(d)(iv). 

§ 98.87 Records that must be retained. 

In addition to the records required by 

§ 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. 


EP10AP09.032</MATH> EP10AP09.033</MATH>
16648 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(g) Monthly cement production. 

(h) Documentation of calculated sitespecific clinker emission factor. 

(i) Facilities that use CEMS must also 

comply with the recordkeeping 

requirements specified in § 98.37. 

§ 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 

§ 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 plasmagenerated 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 98.92 GHGs to report. 

(a) You shall report emissions of 

nitrous oxide and fluorinated GHGs (as 

defined in § 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. 

§ 98.93 Calculating GHG emissions. 

(a) You shall calculate annual facilitylevel F–GHG emissions of each F–GHG 

from all etching processes using 

Equations I–1 and I–2 of this section: 

etchE E i ij

j

= ∑ (Eq. I-1)

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. 

etchBE BE k kij

j i

= ∑∑ (Eq. I-2)

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 facilitylevel F–GHG emissions of each F–GHG 

from all CVD chamber cleaning 

processes using Equations I–3 and I–4 of 

this section: 

cleanE E i ij

j

= ∑ (Eq. I-3)

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. 

cleanBE BE k kij

j i

= ∑∑ (Eq. I-4)

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 facilitylevel 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 m2 silicon shall use processspecific process utilization and byproduct formation factors determined as 

specified in § 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. 

E C U ad ij ij ij ij ij = ∗− ( ) 1 1 0 001 ∗− ∗ ( ) ∗ . (Eq. I-5)

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 § 98.94(c) of Subpart 

I. 

0.001 = Conversion factor from kg to metric 

tons. 

BE B C a d ij kij ij ij kj = ∗ ∗− ∗ ( ) 1 (Eq. I-6)


EP10AP09.034</MATH> EP10AP09.035</MATH> EP10AP09.036</MATH> EP10AP09.037</MATH> EP10AP09.038</MATH> EP10AP09.039</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16649 

1Abatement 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. 

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 § 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. 

E NO C 2 N O2 ( ) = (Eq. I-7) x 0 001 .

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. 

EH density I P N R I D i io it it it it it = ∗ +− + −− ∗ [ ] 0 001 . (Eq. I-8)

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. 

§ 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. 

C I I AD i Bi Ei = − +− ∗ (Eq. I-9) 0 001 .

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 § 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

(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 timeaveraged 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. 


EP10AP09.040</MATH> EP10AP09.041</MATH> EP10AP09.042</MATH>
16650 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

2Most process tools have multiple chambers. For 

combustion-type abatement systems, the outlets of 

each chamber separately enter the destructionreactor 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. 

DF

Kr

Kr

in

out

= [ ]

[ ] (Eq. I-10)

(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

(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 (e) of the quantity 

ci¥out*DF/ci¥in shall not exceed ±10 

percent (two standard deviations) using 

proper statistical methods. 

d DF c

c ij

i out

i in

= − ∗ −

−

1 (Eq. I -11)

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 § 98.92 and § 98.96 shall 

be calibrated using suitable NISTtraceable 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 highconcentration 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. 

§ 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. 

§ 98.96 Data reporting requirements. 

In addition to the information 

required by § 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 § 98.94(c). 


EP10AP09.043</MATH> EP10AP09.044</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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. 

§ 98.97 Records that must be retained. 

In addition to the information 

required by § 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 § 98.94(c)(1)(iv). 

(3) Documentation of the measured 

flows, concentrations and calculations 

used to calculate DF, relative precision 

(e), and DRE. 

(d) The date and results of the initial 

and any subsequent tests to determine 

process tool gas utilization and byproduct formation factors. 

(e) Abatement device calibration and 

maintenance records. 

§ 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

Process gases 

Factors 

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 † 0.02 NA 

Remote 

NF3 ........................................................... 0.2 0.2 NA NA † 0.1 NA 

SF6 ........................................................... 0.2 NA NA NA NA NA 

C4F6

a ........................................................ 0.1 NA 0.3* 0.2* NA NA 

C5F8

a ........................................................ 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. 

† 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

Process gases 

Factors 

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. 

16652 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE I–4 OF SUBPART I—DEFAULT EMISSION FACTORS FOR PV MANUFACTURING

Process gases 

Factors 

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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16653 

ECO

n i n

2

1

1 44

12

=× × ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟ =

M C reducing agenti reducing agenti

2

1

12 44

12

44

12

∑

+× × ∑ ∑

⎛

⎝

⎜ ⎞

⎠

⎟

+ ×

=

M

M

n m n

electrodem electrodem

or

 C

eh oreh C × ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟ h n

 (Eq. K-1)

flux C j flux j

n

j

M

=

∑

+× × ∑

1

12

44

12

⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟

−× × ⎛

⎝

⎜ ⎞

⎠

⎟

=

=

∑

∑ ∑

n n

n k n

M

1

12

1

12 44

12 productk productk C

−× × ∑ 44

12

M

l

 non-product outgoingl non-product outgoing1 C ⎛

⎝

⎜ ⎞

⎠

⎟ =

∑n 1 n

12

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 nonproduct 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: 

CO ECO k

k

2 2

1

= ∑ (Eq. K-2)

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: 

E M EF CH producti producti

i

4

1

= × ∑( ) (Eq. K-3)

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: 

CH ECH j

j

4 4

1

= ∑ (Eq. K-4)

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. 

§ 98.114 Monitoring and QA/QC 

requirements. 

If you determine CO2 emissions using 

the carbon balance procedure in 

§ 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 


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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 § 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. 

§ 98.115 Procedures for estimating 

missing data. 

For the carbon input procedure in 

§ 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 qualityassured 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 qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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 § 98.113(c), then you are 

required to have 100 percent of the 

specified data for each reporting period. 

§ 98.116 Data reporting requirements. 

In addition to the information 

required by § 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 carboncontaining 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). 

§ 98.117 Records that must be retained. 

In addition to the records required by 

§ 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 carboncontaining 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 § 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. 

§ 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) CH4 EMISSION FACTORS

Alloy product produced in EAF 

CH4 Emission factor 

(kg CH4 per metric ton product) 

EAF operation 

Batch-charging Sprinklecharging a

Sprinklecharging and 

>750 ° 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16655 

TABLE K–1 OF SUBPART K—ELECTRIC ARC FURNACE (EAF) CH4 EMISSION FACTORS—Continued 

Alloy product produced in EAF 

CH4 Emission factor 

(kg CH4 per metric ton product) 

EAF operation 

Batch-charging Sprinklecharging a

Sprinklecharging and 

>750 ° Cb

ferrosilicon 65% ........................................................................................................................... 1.3 1.0 0.5 

aSprinkle-charging is charging intermittently every minute. 

bTemperature measured in off-gas channel downstream of the furnace hood. 

Subpart L—Fluorinated Greenhouse 

Gas Production 

§ 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. 

§ 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 

§ 98.2(a)(1) or (2). 

§ 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. 

§ 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: 

E E p Pip

i

m

p

n

= = =

∑∑ (Eq. L-1) 1 1

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: 

E E Bk Bkip

i

m

p

n

= = =

∑∑ (Eq. L-2) 1 1

Where: 

EBk = Total mass of fluorinated GHG byproduct k emitted annually from all 

production processes (metric tons). 

EBkip = Total mass of fluorinated GHG byproduct 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. 

E R MW SC

MW SC Pip P WL P P

R R

p Dj Bkip

k

u

j

q

= ∗ ∗

∗ −− ∗ ( ) − = =

∑ C ∑ 1 1

(Eq. L-3)

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: 

RR R F R = (Eq. L-4) −

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). 


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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: 

W W DE Dj Fj = (Eq. L-5) ∗

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: 

L

B MW ME

MW * ME Bkip

kip P Bk

Bk p

= ( )

( )

 * * 

(Eq. L-6)

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: 

B cS kip Bjk j

j

q

 = (Eq. L-7) ∑ ∗

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: 

E B c W cS Bkip kip Bkj Dj

j

q

Bkl Rl

l

v

=− ∗ − ∗ = =

∑ ∑ l

(. ) Eq L-8 1

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. 

§ 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 

§§ 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. 


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(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 § 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 § 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 § 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. 

§ 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 qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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. 

§ 98.126 Data reporting requirements. 

(a) In addition to the information 

required by § 98.3(c), you shall report 

the following information for each 

production process at the facility. 

16658 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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 § 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 § 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 § 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. 

§ 98.127 Records that must be retained. 

(a) In addition to the data required by 

§§ 98.123 and 98.126, you shall retain 

the following records: 

(1) Dated records of the data used to 

estimate the data reported under 

§§ 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 § 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 § 98.126(c) and (d). 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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 

CH4 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. 

§ 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 

§ 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 

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

E MF M EF F Eq CO i i i i

i

n

2

1

= ••• =

∑ (. ) N-1

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: 

CO E Eq CO i

i

k

2 2 1

= =

∑ (. ) N-2

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. 

§ 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 

§ 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). 

§ 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. 

§ 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 carbonatebased 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 

§ 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. 

§ 98.147 Records that must be retained. 

In addition to the information 

required by § 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 

§ 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. 

§ 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

Carbonate-based raw 

material—mineral 

CO2 Emission 

factor a

Limestone—CaCO3 .............. 0.440 


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TABLE N–1 OF SUBPART N—CO2

EMISSION FACTORS FOR CARBONATE-BASED RAW MATERIALS— 

Continued 

Carbonate-based raw 

material—mineral 

CO2 Emission 

factor a

Dolomite—CaMg(CO3)2 ........ 0.477 

Sodium carbonate/soda 

ash—Na2CO3 .................... 0.415 

aEmission factors in units of metric tons of 

CO2 emitted per metric ton of carbonatebased raw material charged to the furnace. 

Subpart O—HCFC–22 Production and 

HFC–23 Destruction 

§ 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. 

§ 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 

§ 98.2(a)(1) or (2). 

§ 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. 

§ 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: 

G cFp

p

n

23 23

3

1

= ∗∗10−

=

∑ (. ) Eq O -1

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. 

G c

c

P p

n

23

23

22

3

1

= 10 2 ⎛

⎝

⎜ ⎞

⎠

⎟ ∗ ∗ −

=

∑ 22 (. ) Eq O -

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: 

P LF O U 22 22 22 =∗ − ( ) ( . Eq O-3)

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 § 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: 

E G S OD D 23 23 23 23 23 =− + + ( ) ( . Eq O- ) 4

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). 


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(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: 

E =E +E +E 23 L PV D ( . Eq O-5)

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: 

E FN FN L

t

Gt Gt Lt Lt

p

n

= ∗ ∗+∗ ∑∑ ( ) ∗ −

=

c23

3

1

10 ( . Eq O-6)

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 § 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 § 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

Equipment type Service 

Emission factor (kg/hr/source) 

≥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: 

E = ER *

PR

PR

* l PV T

p=

n p

T

p

1

∑ ⎛

⎝

⎜ ⎞

⎠

⎟ ∗ − 10 3 ( . Eq O-7)

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: 

D = F * DE D ( . Eq O-8)

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: 

E =F D D D − ( . Eq O- ) 9

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). 

§ 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 § 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. 


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(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 § 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 § 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 § 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 highconcentration 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. 

§ 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 

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

§ 98.156 Data reporting requirements. 

(a) In addition to the information 

required by § 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 § 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 § 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 

§ 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 § 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. 

§ 98.157 Records that must be retained. 

(a) In addition to the data required by 

§ 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 § 98.154(o) and 

(p). 

(b) In addition to the data required by 

§ 98.3(g), the designated representative 

of a HFC–23 destruction facility shall 

retain the following records: 

(1) Records documenting their onetime and annual reports in § 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 § 98.154(o) and 

(p). 

§ 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 

§ 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. 

16664 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 98.33(b)(5)(iii)(A), (B), and (C), or 

§ 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 

§ 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: 

CO Fdstk CC MW

MVC n n

n

k

2

1

44

12 = ∗ ∗∗ 0 001 ⎛

⎝

⎜ ⎞

⎠

⎟ ∗ =

∑ ( ) ( ) . (. Eq P-1)

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: 

CO Fdstk CC n

k

2 n n

=1

= ( )( )

44 0 001

12 ∑ ∗ ∗ P-2) ⎛

⎝

⎜ ⎞

⎠

⎟ ∗ . (. Eq

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: 

CO Fdstk CC n

k

2 n n

=1

= ( )( )

44

12 ∑ ∗ ∗ P- ) ⎛

⎝

⎜ ⎞

⎠

⎟ ∗ 0 001 3 . (. Eq

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. 

§ 98.164 Monitoring and QA/QC 

requirements. 

(a) Facilities that use CEMS must 

comply with the monitoring and QA/QC 

procedures specified in § 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 § 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 


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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. 

§ 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 

§ 98.35. 

§ 98.166 Data reporting requirements. 

In addition to the information 

required by § 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 

§ 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). 

§ 98.167 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

the following records: 

(a) For all CEMS, you must comply 

with the CEMS recordkeeping 

requirements in § 98.37. 

(b) Monthly analyses of carbon 

content for each feedstock used in 

hydrogen production. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 98.172 GHGs to report. 

(a) You must report combustionrelated 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, byproduct 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. 

§ 98.173 Calculating GHG emissions. 

(a) For each taconite indurating 

furnace, basic oxygen furnace, nonrecovery 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 § 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. 

CO F F C MW

MVC s F n sf n g n gf n 2 1 n 1

12 44

12 = ∑ ( ) ( ) C + () ( ) 0 001 . + ( ) C OCPC 1f n n o n p n ( ) + () ( ) − ( ) ( ) ⎡

⎣

⎢ ⎤

⎦

⎥ 0 001 . (Eq. Q-1)

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. 


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16666 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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. 

CO Iron Scrap C Flux n Iron n n Scrap 2 n n 1

12 44

12 = ∑ ( ) ( ) C C + ( ) ( ) + ( ) C

Carbon C Steel C

Flux n

n Carbon n Steel

( ) ⎡

⎣

+( ) ( ) − ( ) (

(Eq. Q- ) 2

n ) − ( ) ( ) ⎤ n ⎦ Slag n Slag C n 

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. 

CO Coal Coke C 2 n Coal n n Coke n 1

12 44

12 = ⎡( ) ( ) − ( ) ( ) ⎣ ⎤ ∑ ⎦ C ( . Eq Q-3)

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. 

CO F MW

MVC

Feed

g n gf n

n

2

1

12 44

12 = ⎡() ( ) 0 001 ⎣ +

( )

∑ 



C . ( . Eq Q-4)

C Sinter C Feed n Sinter n ( ) − ( ) ( ) ⎤

⎦ 

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. 


EP10AP09.072</MATH> EP10AP09.073</MATH> EP10AP09.074</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16667 

CO Iron Scrap C Flux n Iron n n Scrap 2 n n 1

12 44

12 = ( ) ( ) + ( ) ( ) + ( ) ∑ ⎡ C ⎣

( ) C Electrode Carbon C Steel f + ( ) ( ) + ( ) ( ) − ( ) n n CElectrode n n C n

Steel n Slag n C Slag C

(Eq. Q- ) 5

( ) − ( ) ( ) n

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. 

CO Steel C 2 n Steelin n Steelout n 1

12 44

12 = ∑ ( ) [ ] (. ( ) C − ( ) Eq Q- ) 6

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). 

CO (Eq. 2 = ()( ) + ( ) ⎡

⎣ ∑ ⎢

44

12

0 001 1

12

F C MW

MVC g Ore C n gf n n ore . ( ) Q-7)

 

+ ( ) + ( )

−

( (

(

Carbon C Other C

Iron C

n Carbon n n Other n

n

) )

)



Iron n n NM n ( ) − NM C( ) ⎤

⎦ ( ) 

(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). 


EP10AP09.075</MATH> EP10AP09.076</MATH> EP10AP09.077</MATH>
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(CNM)n = Average carbon content of the nonmetallic 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. 

CO x C H O 2 CO

7 2 5 18 10 100

100 = ⎛ −

⎝

⎜ ⎞

⎠

⎟ − . % (Eq. Q-8) 2 Q

Where: 

CO2 = CO2 mass emission rate (metric tons/ 

hr). 

5.18 × 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. 

§ 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 § 98.34(e). 

(b) If you determine CO2 emissions 

using the carbon balance procedure in 

§ 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 § 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 § 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 § 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 § 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. 


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§ 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 § 98.173(a)(2) or the siteemission factor procedure in 

§ 98.133(a)(3); 100 percent data 

availability is required. 

§ 98.176 Data reporting requirements. 

In addition to the information 

required by § 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; argonoxygen 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 § 98.36(d)(iv). 

§ 98.177 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 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. 

ECO2

1

12 44

12 = ( )( ) + ( ) ( ) + ( ) =

∑n n Lead n n Scrap n Lead C Scrap C Flux n Flux n n Carbon n n Other n ( ) C Carbon C Other C + ( )( ) + ( )( ) ⎡

⎣ ⎤⎦ (Eq. R-1)

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). 


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16670 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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. 

CO = E (Eq. R-2) 2 CO2k 1

k

∑

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. 

§ 98.184 Monitoring and QA/QC 

requirements. 

If you determine CO2 emissions using 

the carbon input procedure in 

§ 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 § 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. 

§ 98.185 Procedures for estimating 

missing data. 

For the carbon input procedure in 

§ 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 qualityassured 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 qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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. 

§ 98.186 Data Reporting Procedures. 

In addition to the information 

required by § 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 carboncontaining 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). 

§ 98.187 Records that must be retained. 

In addition to the records required by 

§ 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 carboncontaining 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. 

§ 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 

§ 98.190 Definition of the source category. 

Lime manufacturing processes use a 

rotary lime kiln to produce a lime 

product (e.g., calcium oxide, highcalcium 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 nonmarketed lime manufacturing facilities. 

§ 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 § 98.2(a)(1) or (2). 

§ 98.192 GHGs to report. 

(a) You must report CO2 process 

emissions from each lime kiln as 

specified in this subpart. 


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(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. 

§ 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 

§ 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 byproducts/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: 

EF CaO + (Eq. S-1) k,i i = × ( ) SR SR MgO CaO i MgO i i , , ( ) ×

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 § 98.194(b), 

metric tons CaO/ton lime. 

MgOi = Magnesium oxide content for lime 

type i determined according to 

§ 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: 

CF M M lkd k d i , , = + 1 C F (Eq. S-2) ( ) / lime,i d,i d,i × ×

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: 

E EK k kn

n

∑= ∑( ) ) =

, M CF (Eq. S-3) . k,n lkd,k,n 0 97 2000

2205

12

ι 1

φ

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: 

CO Ek

k

z

2

1

= =

∑ (Eq. S-4)

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. 

§ 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 byproduct/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 § 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 § 98.7). 

(c) You must use the most recent 

analysis of calcium oxide and 

magnesium oxide content of each lime 

product in monthly calculations. 


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(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 § 98.7). 

§ 98.195 Procedures for estimating 

missing data. 

For the procedure in § 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. 

§ 98.196 Data reporting requirements. 

(a) In addition to the information 

required by § 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 § 98.36. 

§ 98.197 Records that must be retained. 

(a) In addition to the records required 

by § 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 byproducts/waste products for each kiln. 

(b) Facilities that use CEMS must also 

comply with the recordkeeping 

requirements specified in § 98.37. 

§ 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

Variable Stoichiometric 

ratio 

SRCaO ................................ 0.7848 

SRMgO ............................... 1.0918 

Subpart T—Magnesium Production 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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. 

E E E E E E Eq

C

E C

GHG SF a FK CO OG

SF

a

= + ++ +

= ×

=

6 134 2

6

134

23 9

( .

.

 T-1)

ESF6

134

2 2

1 3

0 001

0 001

a

FK FK

CO CO

OG OG OG

E C

E C

E C GWP

×

= ×

= ×

= ×

.

.

.

/1000

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). 


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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: 

CI I A =− + − B E D (Eq. T-2)

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: 

C Q GHG p

p

n

= ∑ (Eq. T-3) =1

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: 

QMM p BE = − (Eq. T-4)

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. 

§ 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 NISTtraceable 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. 

§ 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: 

R C Mg GHG GHG = / (Eq. T-5)

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). 

§ 98.206 Data reporting requirements. 

In addition to the information 

required by § 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. 


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(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. 

§ 98.207 Records that must be retained. 

In addition to the records specified in 

§ 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. 

§ 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 

§ 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. 

§ 98.211 Reporting threshold. 

You must report GHG emissions from 

miscellaneous uses of carbonate if your 

facility meets the requirements of either 

§ 98.2(a)(1) or (2). 

§ 98.212 GHGs to report. 

You must report CO2 emissions 

aggregated for all miscellaneous 

carbonate use at the facility. 

§ 98.213 Calculating GHG emissions. 

Calculate process emissions of CO2

using Equation U–1 of this section. 

ECO

i

2 1

2000

2205 = ∑ M EF F (Eq. U-1) i ii 

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. 

§ 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.). 

§ 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. 

§ 98.216 Data reporting requirements. 

In addition to the information 

required by § 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 carbonatebased raw material by carbonate type. 

§ 98.217 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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

Mineral name—carbonate 

CO2 emission 

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 

§ 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). 

§ 98.221 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 

contains a nitric acid production 


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process and the facility meets the 

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

§ 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. 

§ 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 

§ 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: 

 

(Eq. V-1)

2

EF

C Q

P

n N O

N O n

2

7

1

1 14 10

=

=∗ × ∗ −

∑ .

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). 

1.14×10¥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: 

E

EF P DF AF

N

Na N N

2

2

O

O = ∗ ∗− ( ) ∗ (Eq. V-2)

1

2205

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). 

§ 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 

§ 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. 

§ 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. 

§ 98.226 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.227 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

the records specified in paragraphs (a) 


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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). 

§ 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 

§ 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. 

§ 98.231 Reporting threshold. 

You must report GHG emissions from 

oil and natural gas systems if your 

facility meets the requirements of either 

§ 98.2(a)(1) or (2). 

§ 98.232 GHGs to report. 

(a) You must report CO2 and CH4

emissions in metric tons per year from 

sources specified in § 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. 

§ 98.233 Calculating GHG emissions. 

(a) Estimate emissions using either an 

annual direct measurement, as specified 

in § 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 

§ 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 § 98.234 (d) or (e) to 

conduct annual leak detection of 

fugitive emissions from all sources 

listed in § 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. 

E FV s,n s = ∗ (Eq. W-1)

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 § 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. 


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(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. 

E AN s,n s = ∗ (Eq. W-2)

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 

§ 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. 

E BT s,n s = ∗ (Eq. W-3)

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 § 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: 

E NV a,n v = ∗ (Eq. W-4)

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 § 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: 

E V X K VYR a,i a i a j j,i = ×− (Eq. W-5) ( ) 1 1 η η × +− ( ) ∗∗ ∗ ∗

Where: 

Ea,i = Annual fugitive emissions from flare 

stack. 

Va = Volume of natural gas sent to flare stack 

determined from § 98.234(j)(1). 

h = 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 § 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. 

E

E TP

T P s,i

a,i s a

a s

= ∗ + ( ) ∗

( ) + ∗

460

460 (Eq. W-6)

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 (°F). 

Ta = Temperature at actual emission 

conditions (°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: 


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E Q ER a,h = × (Eq. W-7)

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 § 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. 

EEM s,i s,h i = ∗ (Eq. W-8)

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 § 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. 

E

E TP

T P s,n

a,n s a

a s

= ∗ + ( ) ∗

( ) + ∗

460

460 (Eq. W-9)

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 (°F). 

Ta = Temperature at actual emission 

conditions (°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. 

E EM s,i s,n i = ∗ (Eq. W-10)

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. 

Mass E s,i s,i i = ∗ ρ (Eq. W-11)

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. 

ri = Density of GHG i;1.87 kg/m3 for CO2 and 

0.68 kg/m3 for CH4. 

§ 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 § 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 

§ 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 


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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 § 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 § 98.233(e). 

(4) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas emissions using the 

calculations in § 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 

§ 98.233(f). 

(3) Estimate CH4 and CO2 volumetric 

and mass fugitive emissions from 

volumetric natural gas fugitive 

emissions using calculations in 

§ 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 § 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 § 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 § 98.234(i)(1)(i). 

(iii) Estimate CH4 and CO2 volumetric 

and mass fugitive emissions from 

volumetric natural gas fugitive 

emissions using calculations in 

§ 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 

16680 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 § 98.234(i)(2)(i). 

(iii) Estimate CH4 and CO2 volumetric 

and mass emissions from volumetric 

natural gas fugitive emissions using the 

calculations in § 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 § 98.234(i)(3)(i). 

(iii) Estimate CH4 and CO2 volumetric 

and mass fugitive emissions from 

volumetric natural gas fugitive 

emissions using calculations in 

§ 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 § 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. 

§ 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. 

§ 98.236 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.237 Records that must be retained. 

In addition to the information 

required by § 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 § 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16681 

§ 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 

§§ 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 § 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 

§ 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. 

§ 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 § 98.33(a)(4). For each 

flare, estimate CO2, CH4, and N2O 

emissions using the methodology 

specified in § 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 § 98.33(a)(4). For each flare, estimate 

CO2, CH4, and N2O emissions using the 

methodology specified in § 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 

§ 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 

§ 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 

§ 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 offspecification 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: 

C F CC

MW

MVC

P CC

MW

M g gf i,n gf i,n

f i

gp i,n gp i,n

p i = ( ) ∗( ) ∗

( ) − ( ) ∗( ) ∗( )

i= VC

or

n

⎡

⎣

⎢

⎢

⎤

⎦

⎥

⎥ ∑ ∑= 1

j k

1

52

(Eq. X-1)

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. 

C F CC P CC l lf i,n lf i,n lp i,n lp i,n i

j or k

= (Eq. X-2) =1

∑ ∑ ( ) ∗ ( ) − ( ) ∗ ( ) n=1

52


EP10AP09.103</MATH> EP10AP09.104</MATH>
16682 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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). 

C F CC P CC s sf i,n sf i,n sp i,n sp i,n i

j or

= (Eq. X-3) =1

( ) ∗ ( ) − ( ) ∗ ( ) ⎤

⎦

 k

n

∑ ∑=1

52

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). 

CO C C C 2 gls 0.001 44

12 = ∗∗ + + (Eq. X-4) ( )

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/kgmole). 

(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. 

§ 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 § 98.34(e). 

(b) Facilities that use the mass balance 

methodology in § 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 § 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 § 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 § 98.7 (a)(8) 

of subpart A of this part; ASTM D6060– 

96(2001) incorporated by reference in 

§ 98.7; ASTM D2502–88(2004)e1 

incorporated by reference in § 98.7; 

method UOP539–97 incorporated by 

reference in § 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. 

§ 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 § 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 § 98.35. 

§ 98.246 Data reporting requirements. 

(a) Facilities using the mass balance 

methodology in § 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. 


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

(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 § 98.36(d)(1)(iv). 

§ 98.247 Records that must be retained. 

In addition to the recordkeeping 

requirements in § 98.3(g), you must 

retain the following records: 

(a) The CEMS recordkeeping 

requirements in § 98.37, if you operate 

a CEMS on process vents. 

(b) Results of feedstock or product 

composition determinations conducted 

in accordance with § 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 § 98.243(a)(2)(iv) for 

determining carbon content of feedstock 

or product. 

§ 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 

§ 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). 

§ 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 § 98.2(a)(1) or (2). 

§ 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 § 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 onsite 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 nonmerchant 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. 

§ 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 § 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 § 98.33(a). If you 

monitor heat content, calculate the CO2 

emissions from the flare using the 

applicable equation in § 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. 

16684 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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. 

CO Flare HHV EmF Flare CC N

p

n

2 SSM p p = ∗∗ ∗ + ∗ 0.001 ) (Eq ( ) ∗ =

( () ∑ 44

1 12 . Y-1)

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 

§ 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 § 98.33(a)(4). For units that do not 

have a CO boiler or other postcombustion 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. 

CO Q

CO CO

MVC r n

n

n

2

% 2

= ( ) ∗ (Eq. Y-2) ( ) +

∑ ∗ ∗ %

100

44 0 001 1 % .

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. 

Q

Q OQ

CO CO O r

a oxy oxy

= ( ) ∗+ − ( ) ∗

− −−

79 100

100

%

% %% 2 2

(Eq. Y-3)

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 


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

CH EmF

EmF (Eq. Y-4) 4

1

2

= ∗ ⎛

⎝

⎜ ⎞

⎠

CO2 ⎟

Where: 

CH4 = Annual methane emissions from coke 

burn-off (metric tons CH4/year). 

CO2 = Emission rate of CO2 from coke burnoff 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. 

N O CO EmF

EmF (Eq. Y-5) 2 2

1

2

= ∗ ⎛

⎝

⎜ ⎞

⎠

⎟

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. 

CO CB CF Q n

n

2

1

44

12 = ∑( ) ∗ ∗∗ 0 001 . (Eq. Y-6)

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. 

CO F

MVC 2 =∗ ∗ ∗ SG C MF 44 0.001 (Eq. Y-7)

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 § 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. 


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16686 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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 § 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. 

CO M CC M M CC 2 = in GC out dust MPC

44

12

∗∗ − + ( ) ( ) ∗ (Eq. Y-8)

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. 

CH Q EF MVC 4 = AB AB

16 ∗∗ ∗ (Eq. Y-9) ⎛

⎝

⎜ ⎞

⎠

⎟ 0 001 .

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. 

CO Q EF MVC 2 AB AB

44 = ∗ ∗ ∗∗1 (Eq. Y-10) ⎛

⎝

⎜ ⎞

⎠

⎟ 0 001 .

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. 

CH N H D

MVC 4 = MFCH 4 ∗ ∗ (Eq. Y-11) ∗ ∗∗ ∗ ⎛

⎝

⎜ ⎞

⎠

⎟ π 2 16 0 001 4 .

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). 


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

E VR MF MW

MVC x nx VT x

n

n

N

= (Eq. Y-12) =1

∑ ∗ ∗ ∗∗ 0 001 .

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/kgmole); 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. 

CH Q EF MVC 4 = (Eq. Y-13) Re f BD ∗∗ ∗ ⎛

⎝

⎜ ⎞

⎠

⎟ 16 0 001 .

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. 

CH N N N N N 4 12 = 0.4 + 0.2 + 0.1 + 4.3 (Eq. CD PU PU H FGS ( ) ∗ ∗ ∗ ∗ +∗ 2 6 Y-14)

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 vaporphase methane concentration of 0.5 

volume percent or more using tankspecific 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. 

CH Q 4 f = 0.1 (Eq. Y-15) ( ) ∗ Re

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 tankspecific 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. 

CH Q P MF MVC 4 = 995,000 un CH

16 ( ) ∗ ∗Δ ∗ ∗∗ (Eq. Y-16) 4 0 001 .

Where: 

CH4 = Annual methane emissions from 

storage tanks (metric tons/year). 

Qun = Quantity of unstabilized crude oil 

received at the facility (MMbbl/year). 

DP = 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 (kgmole 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). 


EP10AP09.118</MATH> EP10AP09.119</MATH> EP10AP09.120</MATH> EP10AP09.121</MATH> EP10AP09.122</MATH>
16688 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 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 § 98.34(e). 

§ 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 § 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. 

§ 98.256 Data reporting requirements. 

In addition to the reporting 

requirements of § 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 § 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 § 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 

§ 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 offsite that are processed at the facility in 

the reporting year. 

(2) The method used to calculate 

equipment leak emissions and the 

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

§ 98.257 Records that must be retained. 

In addition to the records required by 

§ 98.3(g), you must retain the records of 

all parameters monitored under 

§ 98.255. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ § 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: 

E IC P m nn

n

z

= ∗∗ [ ]∗ =

∑ 44

12

2000

1 2205 (Eq. Z-1)

Where: 

Em = Annual CO2 mass emissions from a wetprocess 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: 

CO Em

m

p

2

=1

= (Eq. Z-2) ∑

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. 

§ 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 wetprocess phosphoric acid process line. 

§ 98.265 Procedures for estimating 

missing data. 

There are no missing data procedures 

for wet-process phosphoric acid 

production facilities estimated 

according to § 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. 

§ 98.266 Data reporting requirements. 

In addition to the information 

required by § 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). 


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16690 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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). 

§ 98.267 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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). 

§ 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 

§ 98.2(a)(1) or (2). 

§ 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. 

§ 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 § 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 

§ 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: 

CO CH or N O from biomass x Solids HH 24 2 p , , = ( ) ∗ − 1 10 907 3 ( )( ) ( V EF p

p

) ∗ =

∑ (Eq. AA-1) 1

12

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 × 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 


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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 

§ 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 § 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: 

Biogenic CO (Eq. AA-2) 2 =∗ ∗ =

∑44

1 12

12

( )() Solids CC p p

p

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 § 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 

§ 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 § 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: 

CO M M kg/metric 2 CaCO Na CO 3 23 = ∗+ ⎡

⎣

⎢ ⎤

⎦

⎥ ∗ () ( )

44

100

44

105 99

1000 . ton (Eq. AA-3)

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. 

§ 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 § 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. 

§ 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 


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16692 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 98.276 Data reporting requirements. 

In addition to the information 

required by § 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 

§ 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. 

§ 98.277 Records that must be retained. 

In addition to the information 

required by § 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 § 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. 

§ 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 

Wood furnish 

Biomass-based emissions factors 

(kg/mmBtu HHV) 

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 

Fuel 

Fossil fuel-based emissions factors (kg/mmBtu HHV) 

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 

§ 98.280 Definition of the source category. 

Silicon carbide production includes 

any process that produces silicon 

carbide for abrasive purposes. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 § 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 § 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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16693 

determined quarterly and used to calculate a quarterly CO2 emisssions 

factor: 

EF CCF CO2 =∗ ∗ ⎛

⎝

⎜ ⎞

⎠

⎟ 0 65 . 44

12 (Eq. BB-1)

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 § 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: 

CO T EF n CO n

n

q

2

=1

= (Eq. BB-2) ⎡ ∗ ⎣ ⎤

⎦ ∑ ∗ 2,

2000

2205

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: 

CH Tn

n

q

4

=1

= ∗ ∑[ ] 10 2 ∗ ∗ (Eq. BB-3) 2000

2205 . . 0 001

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. 

§ 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 § 98.7. 

§ 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. 

§ 98.286 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.287 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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. 


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16694 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(a) Any soda ash manufacturing line 

that meets the conditions specified in 

§ 98.33(b)(5)(iii)(A),(B), and (C), or 

§ 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 

§ 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: 

CO Ek

k

n

2

1

= =

∑ (Eq. CC-1)

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. 

CO (Eq. CC-2) 2 = ⎡( ) ( ) ⎣ ⎤

⎦ =

∑ 44

12

2000

2205

0 097

1 1

12

IC T T n t n n

.

CO (Eq. CC-3) 2 = ⎡( )( ) ⎣ ⎤

⎦ =

44

12

2000

2205

0 138

1 1

12

ICsa Tsa n n n

. ∑

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. 

§ 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. 

§ 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. 

§ 98.296 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.297 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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, gasinsulated lines, or power transformers 

containing sulfur-hexafluoride (SF6) or 

perfluorocarbons (PFCs). 

§ 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). 

§ 98.302 GHGs to report. 

You must report total SF6 and PFC 

emissions (including emissions from 

fugitive equipment leaks, installation, 


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

§ 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: 

User Emissions = Decrease in SF Inventory Acquisitions ( ) 6 + of SF

 of SF Net Increase in Total N 6

6

( ) − ( ) Disbursements ( a −meplate 

Capacity of Equipment Operated)

(Eq. DD-1)

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. 

§ 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 

§ 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). 

§ 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. 

§ 98.306 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.307 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

records of the information reported and 

listed in § 98.306. 

§ 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 

§ 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. 

§ 98.311 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 


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16696 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

contains a titanium dioxide production 

process and the facility meets the 

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

§ 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. 

§ 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 

§ 98.33(b)(5)(ii) or (iii), then you must 

calculate total CO2 emissions using the 

Tier 4 Calculation Methodology 

specified in § 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: 

E C p n

n

= ∗∗ =

∑ 44

12

2000

2205 (Eq. EE-1) 1

12

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: 

CO Ep

p

n

2

1

= −

∑ (Eq. EE-2)

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. 

§ 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. 

§ 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. 

§ 98.316 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.317 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 98.324. 

CH n V C

100% atm 4V = ⎛

⎝

⎜ ⎞

⎠

⎟ 0 0423 520

1

1 440 0 454

1 000 . , .,

o

R

T

P (Eq. FF-1)


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Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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 °R (60 °F) and 

1 atm (lb/scf). 

T = Temperature at which flow is measured 

(°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. 

CH n V C

100% atm 4D = ⎛

⎝

⎜ ⎞

⎠

⎟ 0 0423 520

1

1 440 0 454

1 000 . , .,

o

R

T

P (Eq. FF-2)

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 °R (60 °F) and 

1 atm (lb/scf). 

T = Measured average temperature at which 

flow is measured (°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 § 98.324. 

CH destroyed CH DE/100 (Eq. FF-3) 4 4 = x

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. 

CH emitted (net) CH CH CH destroyed (Eq. FF-4) 4 4V 4D 4 =+−

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 § 98.324. 

CO CH 44/16 (Eq. FF-5) 2 4o = 

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. 

§ 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 § 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 


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16698 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

meter test methods incorporated by 

reference in § 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. 

§ 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. 

§ 98.326 Data reporting requirements. 

In addition to the information 

required by § 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 onsite destruction of coal mine gas CH4, 

where the gas is not a fuel input for 

energy generation or use. 

§ 98.327 Records that must be retained. 

In addition to the information 

required by § 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. 

§ 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 

§ 98.330 Definition of the source category. 

The zinc production source category 

consists of zinc smelters and secondary 

zinc recycling facilities. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 

§ 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. 

E 44

12 CO2 = ∗ ( ) Zinc C Flux C Electrode C ∗ ( ) +∗+ ∗ n Zinc n n Flux n n ( )( ) ( ) Electrode n n c

n

⎡ ( ) + ∗ Carbon C( ) ⎣ ⎤ ∑ ⎦ ( ) (Eq. GG-1) =1

12


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

CO ECO k

k

2 2

1

= ∑ (Eq. GG-2)

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. 

§ 98.334 Monitoring and QA/QC 

requirements. 

If you determine CO2 emissions using 

the carbon input procedure in 

§ 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 § 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. 

§ 98.335 Procedures for estimating 

missing data. 

For the carbon input procedure in 

§ 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 qualityassured 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 qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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. 

§ 98.336 Data reporting requirements. 

In addition to the information 

required by § 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 carboncontaining 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). 

§ 98.337 Records that must be retained. 

In addition to the records required by 

§ 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 carboncontaining 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. 


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16700 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

§ 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 

§ 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. 

§ 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 

§ 98.2(a)(1) or (2). 

§ 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. 

§ 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. 

G WL e e CH x x

kT x kT x

x S

T

4 = − { } ( ) ⎡

⎣

⎢ ⎤

⎦

⎥ − −− − −

=

−

∑ 0

1 1

,

( ) () ( . Eq HH-1)

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. 

WDF W

N P

n

n n

N

= ∗

⎧

⎨

⎩

⎫

⎬

⎭

⎡

⎣

⎢

⎢

⎤

⎦

⎥ = ⎥ ∑1

( . Eq HH-2)

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. 

W WDF P x x = ∗ ( . Eq HH-3)

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 § 98.344. 

(2) Calculate the quantity of CH4

recovered for destruction using 

Equation HH–4 of this section. 


EP10AP09.144</MATH> EP10AP09.145</MATH> EP10AP09.146</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16701 

R V C R

T

P n

n

o

n

n = ∗ ∗ ∗ ∗∗∗ ⎛

⎝

⎜ ⎞

⎠

⎟ 100

0 0423 520

1

1 440 0 454

% 1 000 . , ., ( atm

Eq n. HH-4) =

∑1

365

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°R or 

60°F and 1 atm). 

Tn = Temperature at which flow is measured 

for day n (°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. 

MG G OX Eq = − CH4 ( ) ( . HH-5) 1

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. 

Emissions G R OX R DE Eq = − ( ) CH ⎡ ∗ − ( ) + − ( ) ⎣ ⎤ 4 ⎦ 1 1 ( . HH-6)

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. 

MG R

CE = − ( ) (. 1 HH-7) OX Eq

Emissions R

CE R OX R DE Eq

CH

= − ⎛

⎝

⎜ ⎞

⎠

⎟∗ − ( ) + − ( ) ⎡

⎣

⎢

⎢

⎤

⎦

⎥ 4 ⎥

11 8 ( . HH- )

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). 

§ 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 § 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 § 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 


EP10AP09.147</MATH> EP10AP09.148</MATH> EP10AP09.149</MATH> EP10AP09.150</MATH> EP10AP09.151</MATH>
16702 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 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 qualityassured values of that parameter 

immediately preceding and immediately 

following the missing data incident. If, 

for a particular parameter, no qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured 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. 

§ 98.346 Data reporting requirements. 

In addition to the information 

required by § 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 

§ 98.343(c)(1) through (3). Landfills with 

gas collection system must separately 

report methane generation and 

emissions according to the 

methodologies in § 98.343(c)(3)(i) and 

(ii) and indicate which values are 

calculated using the methodologies in 

§ 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. 

§ 98.347 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

the calibration records for all 

monitoring equipment. 

§ 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/year) ........................ 0.02 .................................................................. yr¥1

k (precipitation 20–40 inches/year) .................... 0.038 ................................................................ yr¥1

k (precipitation >40 inches/year) ........................ 0.057 ................................................................ yr¥1

L0 (Equivalent to DOC = 0.2028 when MCF=1, 

DOCF=0.5, and F=0.5).

0.067 ................................................................ metric tons CH4/ metric ton waste. 

Waste model—All MSW and industrial waste landfills 

MCF .................................................................... 1 .......................................................................

DOCF .................................................................. 0.5 ....................................................................

F ......................................................................... 0.5 ....................................................................

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16703 

TABLE HH–1 OF SUBPART HH—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued 

Factor Default value Units 

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

Year 

Waste per 

capita ton/cap/ 

yr 

% to SWDS 

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 

16704 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE HH–2 OF SUBPART HH—U.S. PER CAPITA WASTE DISPOSAL RATES—Continued 

Year 

Waste per 

capita ton/cap/ 

yr 

% to SWDS 

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 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

§ 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 § 98.354. The flow and COD should 

reflect the wastewater treated 

anaerobically on site in anaerobic 

systems such as lagoons. 

CH Flow COD B MCF Eq n o

n

4

1

12

= ∗ ∗∗ ∗ [ ] 0 001 =

∑ . ( . II-1)

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 (m3/month). 

COD = Average monthly value for chemical 

oxygen demand of wastewater entering 

anaerobic treatment systems other than 

digesters (kg/m3). 

B0 = Maximum CH4 producing potential of 

wastewater (kg CH4/kg COD), default is 

0.25. 


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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. 

CO kg H O

n

2 2 1

12 44

12 = ∗ ∗∗ ∗ ⎡

⎣

⎢ ⎤

⎦

⎥ =

∑ EF V C 0.001 metric tons CH sep 4 / ( . Eq II-2)

Where: 

CO2 = Annual emissions of CO2 from oil/ 

water separators (metric tons/yr). 

EFsep = Emissions factor for the type of 

separator (kg NMVOC/m3 wastewater 

treated). 

VH20 = Volumetric flow rate of wastewater 

treated through oil/water separator in 

month m (m3/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. 

CH d CH AD DE Eq 4 4 = ∗ ( . II-3)

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). 

CH AD V C

T

P n

n

n

n

4 100

0 0423 520

1 = 1 440% . , R atm minutes/day 0.454 metric ton pounds II-4) 1 1 000

365

, ( . ⎡

⎣

⎢ ⎤

⎦

⎥ =

∑ Eq n

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 § 98.354 (acfm). 

Cn = Daily average CH4 concentration of 

digester gas for day n, as determined 

from daily monitoring specified in 

§ 98.354 (%, wet basis). 

0.0423 = Density of CH4 lb/scf (at 520 °R or 

60 °F and 1 atm). 

Tn = Temperature at which flow is measured 

for day n (°R). 

Pn = Pressure at which flow is measured for 

day n (atm). 

§ 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 § 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. 

§ 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 


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16706 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 98.356 Data reporting requirements. 

In addition to the information 

required by § 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). 

§ 98.357 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

the calibration records for all 

monitoring equipment. 

§ 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

Factors Default 

value Units 

B0 ................................................................................................... 0.25 Kg CH4/kg COD. 

MCF—anaerobic deep lagoon, anaerobic reactor (e.g., upflow 

anaerobic sludge blanket, fixed film).

0.8 Fraction. 

MCF—anaerobic shallow lagoon (less than 2 m) ........................ 0.2 Fraction. 

MCF—centralized aerobic treatment system, well managed ....... 0 Fraction. 

MCF—Centralized aerobic treatment system, not well managed 

(overloaded).

0.3 Fraction. 

Anaerobic digester for sludge ....................................................... 0.8 Fraction. 

C fraction in NMOC ....................................................................... 0.6 Fraction. 

EF sep—Gravity Type (Uncovered) .............................................. 1.11E–01 Kg NMVOC/m3 wastewater 

EF sep—Gravity Type (Covered) ................................................. 3.30E–03 Kg NMVOC/m3 wastewater. 

EF sep—Gravity Type—(Covered and Connected to a Destruction Device).0 Kg NMVOC/m3 wastewater. 

DAF or IAF—uncovered ................................................................ 4.00E–34 Kg NMVOC/m3 wastewater. 

DAF or IAF—covered .................................................................... 1.20E–44 Kg NMVOC/m3 wastewater. 

DAF or IAF—covered and connected to a destruction device ..... 0 Kg NMVOC/m3 wastewater. 

DAF = dissolved air flotation type. 

IAF = induced air flotation type. 

Subpart JJ—Manure Management 

§ 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. 

§ 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 § 98.2(a)(1) or (2). 

§ 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16707 

§ 98.363 Calculating GHG emissions. 

(a) For manure management systems 

except digesters, estimate the annual 

CH4 emissions using Equation JJ–1. 

CH Emissions 4 animal (kg/yr) TVS VS days/ 365 25 = type MMS MMS . yr B kg CH /m JJ-1) 0 4

3 [ ] MCF Eq MMS ⎡

⎣ ⎤ ∑ ∑ ⎦ 0 662 . (.

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 (m3

CH4/kg VS). 

MCFMMS = CH4 conversion factor for MMS, 

as specified in Table JJ–2 of this section 

(decimal). 

TVS TVS Population TAM MER Eq = % ( ) (. /1000 JJ-2)

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 § 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. 

CH D V C

100% atm minutes/day 0. 4 n

n = ∗ ∗ ∗ ∗∗ ∗ 0 0423 520

1 . , 1 440

o

n

R n

T

P 454 metric ton

1,000 pounds (Eq. JJ-3) n=1

365 ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟

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 § 98.364 

(acfm). 

Cn = Daily average CH4 concentration of 

digester gas for day n, as determined 

from daily monitoring as specified in 

§ 98.364 (%, wet basis) 

0.0423 = Density of CH4 lb/scf (at 520 °R or 

60 °F and 1 atm). 

Tn = Temperature at which flow is measured 

for day n(°R). 

Pn = Pressure at which flow is measured for 

day n (atm). 

CH Destruction at Digesters (kg/yr) CH D DE OH/Hours Eq. 4 4 = ( JJ-4)

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. 

CH Leakage at Digesters (kg/yr) (Eq. JJ-5 4 = ×− ⎛

⎝

⎜ ⎞

⎠ CH D ⎟ CE 4

1 1 )

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. 

Direct N O Emissions (kg/yr) 

 N

2

animal type ex,

=

∑ ∑ MMS ex N x MMS MMS 2 2 ⎡ x EF x 365.25 days/yr x 44 N O/28 N O-N (Eq. ⎣ ⎤

⎦ ] JJ-6)


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16708 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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). 

Nex = × ×× N (Population TAM MER/1000) (Eq. JJ-7) Manure

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 § 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. 

Total Emissions (metric tons CO (CH emissions + C 2 4 e yr /) [ = H flow to digester combustion

 device CH destruction o 4− 4 f digester + CH leakage of digester) 

 1 metric ton/1000 4

x kg 21] +[direct N O emissions 1 metric ton/1000 kg 2 x x x 310]

(Eq. JJ-8)

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. 

§ 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 § 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. 

§ 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 qualityassured values of that parameter 

immediately preceding and immediately 

following the missing data incident. If, 

for a particular parameter, no qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value obtained after the missing 

data period. 

§ 98.366 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 


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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. 

§ 98.367 Records that must be retained. 

In addition to the information 

required by § 98.3(g), you must retain 

the calibration records for all 

monitoring equipment. 

§ 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

Animal group 

Animal 

group typical animal 

mass (kg) 

Manure excretion rate 

(kg/day/ 

1000 kg animal mass) 

Maximum 

methane 

generation 

potential, Bo

(m3 CH4/kg 

VS 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 

16710 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE JJ–3 OF SUBPART JJ—COLLECTION EFFICIENCIES OF ANAEROBIC DIGESTERS

System type Cover type 

Methane 

collection 

efficiency 

Covered anaerobic lagoon ......................................................... Bank to bank, impermeable ....................................................... 0.975 

(biogas capture) .......................................................................... Modular, impermeable ................................................................ 0.70 

Complete mix, fixed film, or plug flow digester .......................... Enclosed Vessel ......................................................................... 0.99 

TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS

(kg N2O-N/kg Kjdl N) 

Waste management system N2O emission factor 

Aerobic Treatment (forced aeration) ..................................... 0.005 

Aerobic Treatment (natural aeration) ..................................... 0.01 

TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS

(kg N2O-N/kg Kjdl N)—Continued 

Waste management system N2O emission factor 

Digester .................................... 0 

Uncovered Anaerobic Lagoon .. 0 

Cattle Deep Bed (active mix) ... 0.07 

Cattle Deep Bed (no mix) ......... 0.01 

TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS

(kg N2O-N/kg Kjdl N)—Continued 

Waste management system N2O emission factor 

Manure Composting (in vessel) 0.006 

Manure Composting (intensive) 0.1 

Manure Composting (passive) 0.01 

Manure Composting (static) ..... 0.006 


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Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16711 

TABLE JJ–4 OF SUBPART JJ—NITROUS OXIDE EMISSION FACTORS

(kg N2O-N/kg Kjdl N)—Continued 

Waste management system N2O emission factor 

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 

§ 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, subbituminous, lignite, anthracite. Any coal 

mine categorized as an active coal mine 

by MSHA is included. 

(c) Coal importer has the same 

meaning given in § 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 § 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. 

§ 98.371 Reporting threshold. 

Any supplier of coal who meets the 

requirements of § 98.2(a)(4) must report 

GHG emissions. 

§ 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. 

§ 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: 

CO 44/12 (Eq. KK-1) 2 = Mass Carbon 0 907 .

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: 

Carbon x y S i i

i

n

= ∑( ) (Eq. KK-2) =1/

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 

§ 98.374(f). 

(2) The statistical relationship 

between GCV and carbon content shall 

be established according to the 

requirements in § 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 

§ 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 


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16712 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 

§ 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: 

GCV z y S i i

i

n

= ∗ ∑( ) (Eq. KK-3) =1/

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). 

§ 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 (R2) 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 (R2) 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. 

§ 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 § 98.274(e), and use this 

statistical relationship to estimate daily 

carbon content for any day for which 


EP10AP09.166</MATH>
Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 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. 

§ 98.376 Data reporting requirements. 

In addition to the information 

required by § 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 § 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 (R2) 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 § 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 (R2) 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 § 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 (R2) 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 § 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 (R2) 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. 

§ 98.377 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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) 

Weighted annual average 

GCV of coal Btu/lb1

Mass fraction 

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 

16714 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE KK–1 OF SUBPART KK—DEFAULT CARBON CONTENT OF COAL

FOR METHOD 3 (CO2 lbs/ 

MMBtu1)—Continued 

Weighted annual average 

GCV of coal Btu/lb1

Mass fraction 

of carbon in 

coal 

(decimal) 

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 

TABLE KK–1 OF SUBPART KK—DEFAULT CARBON CONTENT OF COAL

FOR METHOD 3 (CO2 lbs/ 

MMBtu1)—Continued 

Weighted annual average 

GCV of coal Btu/lb1

Mass fraction 

of carbon in 

coal 

(decimal) 

15,250 ................................... 0.8693 

15,500 ................................... 0.8835 

1Based on high heating values. 

Subpart LL—Suppliers of Coal-based 

Liquid Fuels 

§ 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 § 98.6. 

§ 98.381 Reporting threshold. 

Any supplier of coal-based liquid 

fuels who meets the requirements of 

§ 98.2(a)(4) must report GHG emissions. 

§ 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. 

§ 98.383 Calculating GHG emissions. 

(a) Coal-to-liquid producers, 

importers and exporters must calculate 

CO2 emissions using Equation LL–1 of 

this section. 

CO oduct 2 = ∗ ∑( ) Pr EF (Eq. LL-1) i i

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 coalbased 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 § 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. 

EF Density Wt% (44/12) (Eq. LL-2) = 

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. 

§ 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. 

§ 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 coalbased 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 


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

§ 98.386 Data reporting requirements. 

In addition to the information 

required by § 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 coalbased liquid supplied to the economy, 

calculated according to § 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 § 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 § 98.383(a). 

§ 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. 

§ 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 

§ 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 § 98.6 and includes any blender 

or refiner of refined or semi-refined 

petroleum products. 

(d) Exporter has the same meaning 

given in § 98.6 and includes any blender 

or refiner of refined or semi-refined 

petroleum products. 

§ 98.391 Reporting threshold. 

Any supplier of petroleum products 

who meets the requirements of 

§ 98.2(a)(4) must report GHG emissions. 

§ 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. 

§ 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. 

CO Product EF (Eq. MM-1) 2i i i = 

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 noncrude feedstock using Equation MM–2 

of this section. 

CO Feedstock EF (Eq. MM-2) 2j j j = 

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. 

CO Biomass EF (Eq. MM-3) 2m m m = 

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. 


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16716 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

CO CO CO CO (Eq. MM-4) 2r 2i 2j 2m = ∑∑∑ ( ) − ( ) − ( )

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. 

CO CO Eq 2 2 x i = ∑( ) ( . MM-5)

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 § 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. 

EF Density Wt = % (44/12) (Eq. MM-6)

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. 

CO oduct EF Vol Eq 2i ii i = Pr % ( . MM-7)

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 noncrude petroleum feedstock shall 

calculate the CO2 emissions associated 

with that feedstock using Equation MM– 

8 in place of Equation MM–2 of this 

section. 

CO Feedstock EF Vol Eq 2 j jj j = % ( . MM-8)

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. 


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Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16717 

CO oduct EF oduct EF Vol Eq 2i ii im m = ( ) Pr Pr % ( . − ( ) MM-9)

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 noncrude petroleum feedstock must 

calculate the CO2 emissions associated 

with that feedstock using Equation MM– 

10 in place of Equation MM–2 of this 

section. 

CO Feedstock EF Feedstock EF Vol Eq 2 j jj im m = ( ) − ( ) % ( . MM-10)

Where: 

CO2j = Annual potential CO2 emissions from 

the complete combustion or oxidation of 

non-crude feedstock ‘‘j’’ (metric tons). 

Feedstockj = Total annual volume of noncrude 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. 

§ 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. 

§ 98.395 Procedures for estimating 

missing data. 

Whenever a metered or qualityassured 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 § 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. 

§ 98.396 Data reporting requirements. 

In addition to the information 

required by § 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 § 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 § 98.393(b) or (g). 

(3) CO2 emissions in metric tons from 

each type of biomass feedstock coprocessed with petroleum feedstocks, 

calculated according to § 98.393(c). 

(4) The total sum of CO2 emissions 

from all products, calculated according 

to § 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) 


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16718 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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 petroleumbased 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 § 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 § 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 § 98.393(a). 

(2) Total sum of CO2 emissions, 

calculated according to § 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 

§ 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 § 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 § 98.393(a). 

(2) Total sum of CO2 emissions, 

calculated according to § 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 § 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. 

§ 98.397 Records that must be retained. 

(a) Any reporter described in § 98.391 

shall retain copies of all reports 

submitted to EPA under § 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 

§ 98.3(g). 

§ 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

Refined and semi-refined petroleum products 

Column A: 

density 

(metric tons/ 

bbl) 

Column B: 

carbon share 

(% of mass) 

Column C: 

emission 

factor 

(metric tons 

CO2/bbl) 

[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 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16719 

TABLE MM–1 OF SUBPART MM—DEFAULT CO2 FACTORS FOR PETROLEUM PRODUCTS 1, 2—Continued 

Refined and semi-refined petroleum products 

Column A: 

density 

(metric tons/ 

bbl) 

Column B: 

carbon share 

(% of mass) 

Column C: 

emission 

factor 

(metric tons 

CO2/bbl) 

[Column A * 

Column B/100 

* 44/12] 

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 °F) ............................................................................................................. 0.12 84.11 0.36 

Other Oils (> 401 °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. 2Products 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. 

16720 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE MM–2 OF SUBPART MM—DEFAULT CO2 FACTORS FOR NATURAL GAS LIQUIDS

Natural gas liquids 

Column A: 

density 

tonnes/barrel 

Column B: 

carbon share 

(% of mass) 

Column C: 

computed 

emission 

factor 

(tonnes CO2/ 

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

Biomass products and feedstock 

Column A: 

emission 

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 

§ 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. 

§ 98.401 Reporting threshold. 

Any supplier of natural gas and 

natural gas liquids that meets the 

requirements of § 98.2(a)(4) must report 

GHG emissions. 

§ 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. 

§ 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, reporterspecific higher heating values and CO2

emission factors may be used, provided 

they are developed using methods 

outlined in § 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 § 98.404. 

CO x Fuel HHV EF Eq 2

3 = 1 10− ( . NN-1)

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 × 10¥3 = Conversion factor from kilograms 

to metric tons (MT/kg). 

(2) Calculation Methodology 2. 

Estimate CO2 emissions using Equation 

NN–2. 

CO Fuel EF Eq 2 = ( . NN- ) 2

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) 

§ 98.404 Monitoring and QA/QC 

requirements. 

(a) The quantity of natural gas liquids 

and natural gas must be determined 


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

§ 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. 

§ 98.406 Data reporting requirements. 

(a) In addition to the information 

required by § 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 § 98.403. 

(b) In addition to the information 

required by § 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 § 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 enduser 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 endusers. 

(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 § 98.403. 

§ 98.407 Records that must be retained. 

In addition to the information 

required by § 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 endusers identified in § 98.406(b)(4). 

(e) Records relating to measured Btu 

content or carbon content. 

§ 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

Fuel Default high heating value factor 

Default CO2

emission 

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 

16722 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

TABLE NN–1 OF SUBPART NN—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART—Continued 

Fuel Default high heating value factor 

Default CO2

emission 

factor (kg 

CO2/ 

MMBtu) 

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

Fuel Unit 

Default CO2

emission 

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 

§ 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 byproducts that are released or destroyed 

at the production facility. 

§ 98.411 Reporting threshold. 

Any supplier of industrial greenhouse 

gases who meets the requirements of 

§ 98.2(a)(4) must report GHG emissions. 

§ 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. 

§ 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: 

P Pp

p

n

= =

∑1

( . Eq OO-1)

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: 

POU ppp = − ( . Eq OO-2)

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: 

T=F R T − ( . Eq OO-3)

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: 

D = F DE D ∗ ( . Eq OO- ) 4

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). 

§ 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 


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

§ 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 

§ 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 qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityVerDate Nov<24>2008 15:41 Apr 09, 2009 Jkt 217001 PO 00000 Frm 00277 Fmt 4701 Sfmt 4702 E:\FR\FM\10APP2.SGM 10APP2
16724 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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. 

§ 98.416 Data reporting requirements. 

In addition to the information 

required by § 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 § 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 § 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 

§ 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. 

§ 98.417 Records that must be retained. 

(a) In addition to the data required by 

§ 98.3(g), the designated representative 

of a fluorinated GHG production facility 

shall retain the following records: 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16725 

(1) Dated records of the data used to 

estimate the data reported under 

§ 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 § 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 § 98.416(b) and (c). 

(c) In addition to the data required by 

§ 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 

§ 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. 

§ 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 

§ 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. 

§ 98.421 Reporting threshold. 

Any supplier of CO2 who meets the 

requirements of § 98.2(a)(4) must report 

GHG emissions. 

§ 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. 

§ 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 § 98.424. 

CO Eq 2 2 1

4

= ∗ =

∑Q CCO

p

( . PP-1)

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 § 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 § 98.424. The 

quantities of CO2 imported or exported 

in equipment, such as fire extinguishers, 

need not be calculated or reported. 

§ 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. 


EP10AP09.185</MATH>
16726 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

(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). 

§ 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. 

§ 98.426 Data reporting requirements. 

In addition to the information 

required by § 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. 

§ 98.427 Records that must be retained. 

In addition to the records required by 

§ 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. 

§ 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: 

§ 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: 

§ 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 § 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 § 1033.235. Small 

manufacturers/remanufacturers may 

omit this requirement. 

* * * * * 

31. Section 1033.235 is amended by 

adding paragraph (i) to read as follows: 

§ 1033.235 Emission testing required for 

certification. 

* * * * * 

(i) Starting in the 2011 model year, 

measure N2O, and CH4 with each lowhour 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/kWhr. 

(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: 

§ 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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16727 

Subpart C—[Amended] 

34. Section 1039.205 is amended by 

revising paragraph (r) to read as follows: 

§ 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 § 1039.235. Small-volume 

engine manufacturers may omit this 

requirement. 

* * * * * 

35. Section 1039.235 is amended by 

adding paragraph (g) to read as follows: 

§ 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/kWhr. 

(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: 

§ 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: 

§ 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 § 1042.235. Small-volume 

engine manufacturers may omit this 

requirement. 

* * * * * 

39. Section 1042.235 is amended by 

adding paragraph (g) to read as follows: 

§ 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/kWhr. 

(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: 

§ 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: 

§ 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 § 1045.235. Small-volume 

engine manufacturers may omit this 

requirement. 

* * * * * 

43. Section 1045.235 is amended by 

adding paragraph (g) to read as follows: 

§ 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/kWhr. 

(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: 

16728 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

§ 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 § 1048.235. Small-volume 

engine manufacturers may omit this 

requirement. 

* * * * * 

46. Section 1048.235 is amended by 

adding paragraph (g) to read as follows: 

§ 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/kWhr. 

(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: 

§ 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: 

§ 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 § 1051.235. Small-volume 

manufacturers may omit this 

requirement. 

* * * * * 

50. Section 1051.235 is amended by 

adding paragraph (i) to read as follows: 

§ 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/kWhr 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: 

§ 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: 

§ 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 § 1054.235. Small-volume 

engine manufacturers may omit this 

requirement. 

* * * * * 

54. Section 1054.235 is amended by 

adding paragraph (g) to read as follows: 

§ 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/kWhr. 

(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. 

Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 16729 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—Applicability and General 

Provisions 

§ 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 

§ 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 · [(125 · SO) + 

(75 · SCO) + (50 · MO) + (10 · SW) 

+ (5 · 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 Oring 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 · HSSP) + (0.2 · 

LSSP) + (0.2 · STV) + (0.2 · 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 · (3.14159 · ID · 

L · 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/mm2. Select the 

appropriate value from the following 

table: 

Material/configuration 

ER 

High-pressure 

side Low-pressure side 

Rubber ......................................................................................................................................................... 0 .0216 0 .0144 

Standard barrier or veneer hose ................................................................................................................. 0 .0054 0 .0036 

Ultra-low permeation barrier or veneer hose .............................................................................................. 0 .00225 0 .00167 

(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 · [(300 · OHS) + 

(200 · MHS) + (150 · FAP) + (100 · 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 § 1065.257 is added to 

subpart C to read as follows: 

§ 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 § 1065.205. Note that your 

NDIR-based system must meet the 

calibration and verification in 

§ 1065.357 and it must also meet the 

linearity verification in § 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 § 1065.357 is added to 

subpart D to read as follows: 

§ 1065.357 CO and Co2 interference 

verification for N2O NDIR analyzers. 

(a) Scope and frequency. If you 

measure CO using an NDIR analyzer, 

16730 Federal Register / Vol. 74, No. 68 / Friday, April 10, 2009 / Proposed Rules 

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: 

§ 1065.750 Analytical gases. 

* * * * * 

(a) * * * 

(1) * * * 

(ii) Contamination as specified in the 

following table: 

TABLE 1 OF § 1065.750—GENERAL SPECIFICATIONS FOR PURIFIED GASES

Constituent Purified synthetic air 1 Purified N2

1

THC (C1 equivalent) ........................................... <0.05 μmol/mol ................................................ <0.05 μmol/mol 

CO ...................................................................... <1 μmol/mol ..................................................... <1 μmol/mol. 

CO2 .................................................................... <10 μmol/mol ................................................... <10 μmol/mol. 

O2 ....................................................................... 0.205 to 0.215 mol/mol .................................... <2 μmol/mol. 

NOX .................................................................... <0.02 μmol/mol ................................................ <0.02 μmol/mol. 

N2O .................................................................... <0.05 μmol/mol ................................................ <0.05 μmol/mol. 

1We 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: 

§ 1065.1001 Definitions. 

* * * * * 

Oxides of nitrogen means NO and 

NO2 as measured by the procedures 

specified in § 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: 

§ 1065.1005 Symbols, abbreviations, 

acronyms, and units of measure. 

* * * * * 

(b) * * * 

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