Friday, 

October 30, 2009 

Part II 

Environmental 

Protection Agency 

40 CFR Parts 86, 87, 89 et al. 

Mandatory Reporting of Greenhouse 

Gases; Final Rule 


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ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Parts 86, 87, 89, 90, 94, 98, 

1033, 1039, 1042, 1045, 1048, 1051, 

1054, 1065 

[EPA–HQ–OAR–2008–0508; FRL–8963–5] 

RIN 2060–A079 

Mandatory Reporting of Greenhouse 

Gases 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: EPA is promulgating a 

regulation to require reporting of 

greenhouse gas emissions from all 

sectors of the economy. The final rule 

applies to fossil fuel suppliers and 

industrial gas suppliers, direct 

greenhouse gas emitters and 

manufacturers of heavy-duty and offroad vehicles and engines. The rule 

does not require control of greenhouse 

gases, rather it requires only that 

sources above certain threshold levels 

monitor and report emissions. 

DATES: The final rule is effective on 

December 29, 2009. The incorporation 

by reference of certain publications 

listed in the rule is approved by the 

Director of the Federal Register as of 

December 29, 2009. 

ADDRESSES: EPA has established a 

docket for this action under Docket ID 

No. EPA–HQ–OAR–2008–0508. All 

documents in the docket are listed on 

the www.regulations.gov Web site. 

Although listed in the index, some 

information is not publicly available, 

e.g., confidential business information 

(CBI) or other information whose 

disclosure is restricted by statute. 

Certain other material, such as 

copyrighted material, is not placed on 

the Internet and will be publicly 

available only in hard copy form. 

Publicly available docket materials are 

available either electronically through 

www.regulations.gov or in hard copy at 

EPA’s Docket Center, Public Reading 

Room, EPA West Building, Room 3334, 

1301 Constitution Avenue, NW., 

Washington, DC 20004. This Docket 

Facility is open from 8:30 a.m. to 4:30 

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744, and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER INFORMATION CONTACT: 

Carole Cook, Climate Change Division, 

Office of Atmospheric Programs (MC– 

6207J), Environmental Protection 

Agency, 1200 Pennsylvania Ave., NW., 

Washington, DC 20460; telephone 

number: (202) 343–9263; fax number: 

(202) 343–2342; e-mail address: 

GHGReportingRule@epa.gov. For 

technical information and 

implementation materials, please go to 

the Web site www.epa.gov/ 

climatechange/emissions/ 

ghgrulemaking.html. You may also 

contact the Greenhouse Gas Reporting 

Rule Hotline at telephone number: (877) 

444–1188; or e-mail: ghgmrr@epa.gov. 

SUPPLEMENTARY INFORMATION: 

Regulated Entities. The Administrator 

determined that this action is subject to 

the provisions of Clean Air Act (CAA) 

section 307(d). See CAA section 

307(d)(1)(V) (the provisions of section 

307(d) apply to ‘‘such other actions as 

the Administrator may determine.’’). 

The final rule affects fuel and chemicals 

suppliers, direct emitters of greenhouse 

gases (GHGs) and manufacturers of 

mobile sources and engines. Regulated 

categories and entities include those 

listed in Table 1 of this preamble: 

TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY

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. 

316, 326, 339 Manufacturers of rubber and miscellaneous plastic products. 

331 Steel works, blast furnaces. 

332 Electroplating, plating, polishing, anodizing, and coloring. 

336 Manufacturers of motor vehicle parts and accessories. 

221 Electric, gas, and sanitary services. 

622 Health services. 

611 Educational services. 

Electricity Generation ................................ 221112 Fossil-fuel fired electric generating units, including units owned by Federal and municipal governments and units located in Indian Country. 

Adipic Acid Production .............................. 325199 Adipic acid manufacturing facilities. 

Aluminum Production ................................ 331312 Primary Aluminum production facilities. 

Ammonia Manufacturing ........................... 325311 Anhydrous and aqueous ammonia manufacturing facilities. 

Cement Production ................................... 327310 Portland Cement manufacturing plants. 

Ferroalloy Production ................................ 331112 Ferroalloys manufacturing facilities. 

Glass Production ...................................... 327211 Flat glass manufacturing facilities. 

327213 Glass container manufacturing facilities. 

327212 Other pressed and blown glass and glassware manufacturing facilities. 

HCFC–22 Production and HFC–23 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. 

Nitric Acid Production ............................... 325311 Nitric acid manufacturing facilities. 

Petrochemical Production ......................... 32511 Ethylene dichloride manufacturing facilities. 

325199 Acrylonitrile, ethylene oxide, methanol manufacturing facilities. 

325110 Ethylene manufacturing facilities. 


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TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected 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. 

212391 Soda ash, natural, mining and/or beneficiation. 

Titanium Dioxide Production ..................... 325188 Titanium dioxide manufacturing facilities. 

Zinc Production ......................................... 331419 Primary zinc refining facilities. 

331492 Zinc dust reclaiming facilities, recovering from scrap and/or alloying purchased metals. 

Municipal Solid Waste Landfills ................ 562212 Solid waste landfills. 

221320 Sewage treatment facilities. 

Manure Management ................................ 112111 Beef cattle feedlots. 

112120 Dairy cattle and milk production facilities. 

112210 Hog and pig farms. 

112310 Chicken egg production facilities. 

112330 Turkey Production. 

112320 Broilers and Other Meat type Chicken Production. 

Suppliers of Coal Based Liquids 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 ......................................... 333618 Heavy-duty, non-road, aircraft, locomotive, and marine diesel engine manufacturing. 

336120 Heavy-duty vehicle manufacturing facilities. 

336312 Small non-road, and marine spark-ignition engine manufacturing facilities. 

336999 Personal watercraft manufacturing facilities. 

336991 Motorcycle manufacturing facilities. 

Table 1 of this preamble is not 

intended to be exhaustive, but rather 

provides a guide for readers regarding 

facilities likely to be affected by this 

action. Table 1 of this preamble lists the 

types of facilities that EPA is now aware 

could be potentially affected by the 

reporting requirements. Other types of 

facilities and suppliers not listed in the 

table could also be subject to reporting 

requirements. To determine whether 

you are affected by this action, you 

should carefully examine the 

applicability criteria found in 40 CFR 

part 98, subpart A or the relevant 

criteria in the sections related to 

manufacturers of heavy-duty and offroad vehicles and engines. If you have 

questions regarding the applicability of 

this action to a particular facility, 

consult the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section. 

Many facilities that are affected by the 

final rule have GHG emissions from 

multiple source categories listed in 

Table 1 of this preamble. Table 2 of this 

preamble has been developed as a guide 

to help potential reporters subject to the 

mandatory reporting rule identify the 

source categories (by subpart) that they 

may need to (1) consider in their facility 

applicability determination, and (2) 

include in their reporting. For each 

source category, activity, or facility type 

(e.g., electricity generation, aluminum 

production), Table 2 of this preamble 

identifies the subparts that are likely to 

be relevant. The table should only be 

seen as a guide. Additional subparts 

may be relevant for a given reporter. 

Similarly, not all listed subparts are 

relevant for all reporters. 

TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS

Source category 

(and main applicable subpart) Other subparts recommended for review to determine applicability 

General Stationary Fuel Combustion Sources.

Electricity Generation ............................................................................... General Stationary Fuel Combustion, Suppliers of CO2. 

Adipic Acid Production ............................................................................. General Stationary Fuel Combustion. 

Aluminum Production ............................................................................... General Stationary Fuel Combustion. 

Ammonia Manufacturing ........................................................................... General Stationary Fuel Combustion, Hydrogen, Nitric Acid, Petroleum 

Refineries, Suppliers of CO2. 

Cement Production ................................................................................... General Stationary Fuel Combustion, Suppliers of CO2. 

Ferroalloy Production ............................................................................... General Stationary Fuel Combustion. 

Glass Production ...................................................................................... General Stationary Fuel Combustion. 

HCFC–22 Production and HFC–23 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. 


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TABLE 2—SOURCE CATEGORIES AND RELEVANT SUBPARTS—Continued 

Source category 

(and main applicable subpart) Other subparts recommended for review to determine applicability 

Lead Production ....................................................................................... General Stationary Fuel Combustion. 

Lime Manufacturing .................................................................................. General Stationary Fuel Combustion. 

Nitric Acid Production ............................................................................... General Stationary Fuel Combustion, Adipic Acid. 

Petrochemical Production ......................................................................... General Stationary Fuel Combustion, Ammonia, Petroleum Refineries. 

Petroleum Refineries ................................................................................ General Stationary Fuel Combustion, Hydrogen, Suppliers of Petroleum Products. 

Phosphoric Acid Production ..................................................................... General Stationary Fuel Combustion. 

Pulp and Paper Manufacturing ................................................................. General Stationary Fuel Combustion. 

Silicon Carbide Production ....................................................................... General Stationary Fuel Combustion. 

Soda Ash Manufacturing .......................................................................... General Stationary Fuel Combustion. 

Titanium Dioxide Production .................................................................... General Stationary Fuel Combustion. 

Zinc Production ......................................................................................... General Stationary Fuel Combustion. 

Municipal Solid Waste Landfills ................................................................ General Stationary Fuel Combustion. 

Manure Management ............................................................................... General Stationary Fuel Combustion. 

Suppliers of Coal-based Liquid Fuels ...................................................... Suppliers of Petroleum Products. 

Suppliers of Petroleum Products .............................................................. General Stationary Fuel Combustion. 

Suppliers of Natural Gas and NGLs ........................................................ General Stationary Fuel Combustion, Suppliers of CO2. 

Suppliers of Industrial GHGs .................................................................... General Stationary Fuel Combustion, Hydrogen Production, Suppliers 

of CO2. 

Suppliers of Carbon Dioxide (CO2) .......................................................... General Stationary Fuel Combustion, Electricity Generation, Ammonia,

Cement, Hydrogen, Iron and Steel, Suppliers of Industrial GHGs. 

Mobile Sources ......................................................................................... General Stationary Fuel Combustion. 

Judicial Review. Under section 

307(b)(1) of the CAA, judicial review of 

this final rule is available only by filing 

a petition for review in the U.S. Court 

of Appeals for the District of Columbia 

Circuit by December 29, 2009. Under 

CAA section 307(d)(7)(B), only an 

objection to this final rule that was 

raised with reasonable specificity 

during the period for public comment 

can be raised during judicial review. 

This section also provides a mechanism 

for us to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of this rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, Environmental 

Protection Agency, Room 3000, Ariel 

Rios Building, 1200 Pennsylvania Ave., 

NW., Washington, DC 20004, with a 

copy to the person listed in the 

preceding FOR FURTHER INFORMATION

CONTACT section, and the Associate 

General Counsel for the Air and 

Radiation Law Office, Office of General 

Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave., NW., Washington, 

DC 20004. Note, under CAA section 

307(b)(2), the requirements established 

by this final rule may not be challenged 

separately in any civil or criminal 

proceedings brought by EPA to enforce 

these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

ARP Acid Rain Program 

ASME American Society of Mechanical 

Engineers 

ASTM American Society for Testing and 

Materials 

BLS Bureau of Labor Statistics 

CAA Clean Air Act 

CAFE Corporate Average Fuel Economy 

CAIR Clean Air Interstate Rule 

CARB California Air Resources Board 

CBI confidential business information 

CCAR California Climate Action Registry 

CCS carbon capture and sequestration 

CEMS continuous emission monitoring 

system(s) 

cf cubic feet 

CFCs chlorofluorocarbons 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e CO2-equivalent 

COD chemical oxygen demand 

DOE U.S. Department of Energy 

DOT U.S. Department of Transportation 

EAF electric arc furnace 

ECOS Environmental Council of the States 

EGUs electric generating units 

EIA Energy Information Administration 

EO Executive Order 

EOR enhanced oil recovery 

EPA U.S. Environmental Protection Agency 

FY2008 fiscal year 2008 

GHG greenhouse gas 

GWP global warming potential 

HCFC–22 chlorodifluoromethane (or 

CHClF2) 

HCFCs hydrochlorofluorocarbons 

HFC–23 trifluoromethane (or CHF3) 

HFCs hydrofluorocarbons 

HFEs hydrofluorinated ethers 

HHV higher heating value 

ICR information collection request 

IPCC Intergovernmental Panel on Climate 

Change 

kg kilograms 

LDCs local natural gas distribution 

companies 

LMP lime manufacturing plants 

mmBtu/hr millions British thermal units 

per hour 

MSW municipal solid waste 

MW megawatts 

MY mileage year 

N2O nitrous oxide 

NACAA National Association of Clean Air 

Agencies 

NAICS North American Industry 

Classification System 

NEI National Emissions Inventory 

NESHAP national emission standards for 

hazardous air pollutants 

NF3 nitrogen trifluoride 

NGLs natural gas liquids 

NSPS new source performance standards 

NSR New Source Review 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

O3 ozone 

ODS ozone-depleting substance(s) 

OMB Office of Management and Budget 

ORIS Office of Regulatory Information 

Systems 

PFCs perfluorocarbons 

PIN personal identification number 

PSD Prevention of Significant Deterioration 

QA quality assurance 

QA/QC quality assurance/quality control 

QAPP quality assurance performance plan 

R&D research and development 

RFA Regulatory Flexibility Act 

RGGI Regional Greenhouse Gas Initiative 

RICE reciprocating internal combustion 

engine 

RIA regulatory impact analysis 

SBREFA Small Business Regulatory 

Enforcement Fairness Act 


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scf standard cubic feet 

SF6 sulfur hexafluoride 

SIP State Implementation Plan 

SOP standard operating procedure 

SSM startup, shutdown, and malfunction 

TCR The Climate Registry 

TRI Toxic Release Inventory 

TSD technical support document 

U.S. United States 

UIC underground injection control 

UMRA Unfunded Mandates Reform Act of 

1995 

UNFCCC United Nations Framework 

Convention on Climate Change 

VMT vehicle miles traveled 

VOC volatile organic compound(s) 

WBCSD World Business Council for 

Sustainable Development 

WCI Western Climate Initiative 

WRI World Resources Institute 

XML eXtensible Markup Language 

Table of Contents 

I. Background 

A. Organization of This Preamble 

B. Background on the Final Rule 

C. Legal Authority 

D. How does this rule relate to EPA and 

U.S. government climate change efforts? 

E. How does this rule relate to State and 

regional programs? 

II. General Requirements of the Rule 

A. Summary of the General Requirements 

of the Final Rule 

B. Summary of the Major Changes Since 

Proposal 

C. Summary of Comments and Responses 

on GHGs To Report 

D. Summary of Comments and Responses 

on Source Categories To Report 

E. Summary of Comments and Responses 

on Thresholds 

F. Summary of Comments and Responses 

on Level of Reporting 

G. Summary of Comments and Responses 

on Initial Reporting Year and Best 

Available Monitoring Methods 

H. Summary of Comments and Responses 

on Frequency of Reporting and 

Provisions To Cease Reporting 

I. Summary of Comments and Responses 

on General Content of the Annual GHG 

Report 

J. Summary of Comments and Responses 

on Submittal Date and Making 

Corrections to Annual Reports 

K. Summary of Comments and Responses 

on De Minimis Reporting 

L. Summary of Comments and Responses 

on General Monitoring Requirements 

M. Summary of Comments and Responses 

on General Recordkeeping Requirements 

N. Summary of Comments and Responses 

on Emissions Verification Approach 

O. Summary of Comments and Responses 

on the Role of States and Relationship of 

This Rule to Other Programs 

P. Summary of Comments and Responses 

on Other General Rule Requirements 

Q. Summary of Comments and Responses 

on Statutory Authority 

R. Summary of Comments and Responses 

on CBI 

S. Summary of Comments and Responses 

on Other Legal Issues 

III. Reporting and Recordkeeping 

Requirements for Specific Source 

Categories 

A. Overview 

B. Electricity Purchases 

C. General Stationary Fuel Combustion 

Sources 

D. Electricity Generation 

E. Adipic Acid Production 

F. Aluminum Production 

G. Ammonia Manufacturing 

H. Cement Production 

I. Electronics Manufacturing 

J. Ethanol Production 

K. Ferroalloy Production 

L. Fluorinated GHG Production 

M. Food Processing 

N. Glass Production 

O. HCFC–22 Production and HFC–23 

Destruction 

P. Hydrogen Production 

Q. Iron and Steel Production 

R. Lead Production 

S. Lime Manufacturing 

T. Magnesium Production 

U. Miscellaneous Uses of Carbonates 

V. Nitric Acid Production 

W. Oil and Natural Gas Systems 

X. Petrochemical Production 

Y. Petroleum Refineries 

Z. Phosphoric Acid Production 

AA. Pulp and Paper Manufacturing 

BB. Silicon Carbide Production 

CC. Soda Ash Manufacturing 

DD. Sulfur Hexafluoride (SF6) from 

Electrical Equipment 

EE. Titanium Dioxide Production 

FF. Underground Coal Mines 

GG. Zinc Production 

HH. Municipal Solid Waste Landfills 

II. Wastewater Treatment 

JJ. Manure Management 

KK. Suppliers of Coal 

LL. Suppliers of Coal-Based Liquid Fuels 

MM. Suppliers of Petroleum Products 

NN. Suppliers of Natural Gas and Natural 

Gas Liquids 

OO. Suppliers of Industrial GHGs 

PP. Suppliers of Carbon Dioxide (CO2) 

IV. Mobile Sources 

A. Summary of Requirements of the Final 

Rule 

B. Summary of Changes Since Proposal 

C. Summary of Comments and Responses 

V. Collection, Management, and 

Dissemination of GHG Emissions Data 

A. Summary of Data Collection, 

Management and Dissemination for the 

Final Rule 

B. Summary of Comments and Responses 

on Collection, Management, and 

Dissemination of GHG Emissions Data 

VI. Compliance and Enforcement 

A. Compliance and Enforcement Summary 

B. Summary of Public Comments and 

Responses on Compliance and 

Enforcement 

VII. Economic Impacts of the Rule 

A. How were compliance costs estimated? 

B. What are the costs of the rule? 

C. What are the economic impacts of the 

rule? 

D. What are the impacts of the rule on 

small businesses? 

E. What are the benefits of the rule for 

society? 

VIII. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. Organization of This Preamble 

This preamble is broken into several 

large sections, as detailed above in the 

Table of Contents. The paragraphs 

below describe the layout of the 

preamble and provide a brief summary 

of each section. 

The first section of this preamble 

contains the basic background 

information about the origin of this rule, 

our legal authority, and how this 

proposal relates to other Federal, State, 

and regional efforts to address emissions 

of GHGs. 

The second section of this preamble 

summarizes the general provisions of 

the final GHG reporting rule and 

identifies the major changes since 

proposal. It also provides a brief 

summary of public comments and 

responses on key design elements such 

as: (i) Source categories included, (ii) 

the level of reporting, (iii) applicability 

thresholds, (iv) selection of reporting 

and monitoring methods, (v) emissions 

verification, (vi) frequency of reporting 

and (vii) duration of reporting. It also 

addresses some of the legal comments 

on the statutory authority for the rule 

and the relationship of this rule to other 

CAA programs. 

The third section of this preamble 

contains separate subsections 

addressing each individual source 

category of the proposed rule. Each 

source category section contains a 

summary of specific requirements of the 

rule for that source category, identifies 

major changes since proposal, and 

briefly discusses public comments and 

EPA responses specific to the source 

category. For example, comments on 

EPA’s general approach for selecting 

monitoring methods are discussed in 

Section II of this preamble, whereas, 


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1Consolidated Appropriations Act, 2008, Public 

Law 110–161, 121 Stat. 1844, 2128. Congress 

reaffirmed interest in a GHG reporting rule, and 

provided additional funding, in the 2009 

Appropriations Act (Consolidated Appropriations 

Act, 2009, Public Law 110–329, 122 Stat. 3574– 

3716). 

comments on specific monitoring 

methods for individual source 

categories are discussed in Section III of 

this preamble. 

The fourth section of this preamble 

summarizes rule requirements and 

addresses public comments pertaining 

to mobile sources. 

The fifth section of this preamble 

explains how EPA plans to collect, 

manage and disseminate the data, while 

the sixth section describes the approach 

to compliance and enforcement. In both 

sections key public comments are 

summarized and responses are 

presented. 

The seventh section provides the 

summary of the cost impacts, economic 

impacts, and benefits of the final rule 

and discusses comments on the 

regulatory impacts analyses. Finally, the 

last section discusses the various 

statutory and executive order 

requirements applicable to this 

rulemaking. 

B. Background on the Final Rule 

The fiscal year 2008 (FY2008) 

Consolidated Appropriations Act, 

signed on December 26, 2007, 

authorized funding for EPA to ‘‘develop 

and publish a draft rule not later than 

nine months after the date of enactment 

of [the] Act, and a final rule not later 

than 18 months after the date of 

enactment of [the] Act, to require 

mandatory reporting of greenhouse gas 

emissions above appropriate thresholds 

in all sectors of the economy of the 

United States.’’ Consolidated 

Appropriations Act, 2008, Public Law 

110–161, 121 Stat. 1844, 2128 (2008). 

The accompanying joint explanatory 

statement directed EPA to ‘‘use its 

existing authority under the Clean Air 

Act’’ to develop a mandatory GHG 

reporting rule. ‘‘The Agency is further 

directed to include in its rule reporting 

of emissions resulting from upstream 

production and downstream sources, to 

the extent that the Administrator deems 

it appropriate.’’ EPA interpreted that 

language to confirm that it was 

appropriate for the Agency to exercise 

its CAA authority to develop this 

rulemaking. The joint explanatory 

statement further states that ‘‘[t]he 

Administrator shall determine 

appropriate thresholds of emissions 

above which reporting is required, and 

how frequently reports shall be 

submitted to EPA. The Administrator 

shall have discretion to use existing 

reporting requirements for electric 

generating units (EGUs)’’ under section 

821 of the 1990 CAA Amendments. 

On April 10, 2009 (74 FR 16448), EPA 

proposed the GHG reporting rule. EPA 

held two public hearings, and received 

approximately 16,800 written public 

comments. The public comment period 

ended on June 9, 2009. 

In addition to the public hearings, 

EPA had an open door policy, similar to 

the outreach conducted during the 

development of the proposal. As a 

result, EPA has met with over 4,000 

people and 135 groups since proposal 

signature (March 10, 2009). Details of 

these meetings are available in the 

docket (EPA–HQ–OAR–2008–0508). 

EPA developed this final rule and 

included reporting of GHGs from the 

facilities that we determined 

appropriately responded to the direction 

in the FY2008 Consolidated 

Appropriations Act 1 (e.g., capturing 

approximately 85 percent of U.S. GHG 

emissions through reporting by direct 

emitters as well as suppliers of fossil 

fuels and industrial gases and 

manufacturers of heavy-duty and offroad vehicles and engines). There are, 

however, many additional types of data 

and reporting that the Agency deems 

important and necessary to address an 

issue as large and complex as climate 

change (e.g., indirect emissions, 

electricity use). In that sense, one could 

view this final rule as narrowly focused 

on certain sources of emissions and 

upstream suppliers. As described in 

Sections I.C and D of this preamble as 

well as in the comment response 

sections, there are several existing 

programs at the Federal, regional and 

State levels that also collect valuable 

information to inform and implement 

policies necessary to address climate 

change. Many of these programs are 

focused on cost-effectively reducing 

GHG emissions through improvements 

in energy efficiency and by other means. 

These programs are an essential 

component of the Nation’s climate 

policy, and the targeted nature of this 

rule should not be interpreted to mean 

that the data EPA collects through this 

program are the only data necessary to 

support the full range of climate policies 

and programs. 

Today’s rule requires the reporting of 

the GHG emissions that could result 

from the combustion or use of fossil fuel 

or industrial gas that is produced or 

imported from upstream sources such as 

fuel suppliers, as well as reporting of 

GHG emissions directly emitted from 

facilities (downstream sources) through 

their processes and/or from fuel 

combustion, as appropriate. Vehicle and 

engine manufacturers are also required 

to report emissions rate data on the 

heavy-duty and off-road engines they 

produce. The rule also establishes 

appropriate thresholds and frequency 

for reporting. 

The rule requires reporting of annual 

emissions of carbon dioxide (CO2), 

methane (CH4), nitrous oxide (N2O), 

sulfur hexafluoride (SF6), 

hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and other 

fluorinated gases (e.g., nitrogen 

trifluoride (NF3) and hydrofluorinated 

ethers (HFEs)). It also includes 

provisions to ensure the accuracy of 

emissions data through monitoring, 

recordkeeping and verification 

requirements. The rule applies to 

certain downstream facilities that emit 

GHGs (primarily large facilities emitting 

25,000 metric tons or more of CO2

equivalent (CO2e) GHG emissions per 

year) and to most upstream suppliers of 

fossil fuels and industrial GHGs, as well 

as to manufacturers of vehicles and 

engines. Reporting is at the facility 

level, except certain suppliers and 

vehicle and engine manufacturers report 

at the corporate level. 

C. Legal Authority 

As proposed, EPA is promulgating 

this rule under its existing CAA 

authority, specifically authorities 

provided in CAA sections 114 and 208. 

As discussed further below and in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Legal Issues’’, we are not 

citing the FY 2008 Consolidated 

Appropriations Act as the statutory 

basis for this action. While that law 

required that EPA spend no less than 

$3.5 million on a rule requiring the 

mandatory reporting of GHG emissions, 

it is the CAA, not the Appropriations 

Act, that EPA is citing as the authority 

to gather the information required by 

this rule. 

Sections 114 and 208 of the CAA 

provide EPA broad authority to require 

the information mandated by this rule 

because such data will inform and are 

relevant to EPA’s carrying out a wide 

variety of CAA provisions. As discussed 

in the proposed rule, CAA section 

114(a)(1) authorizes the Administrator 

to require emissions sources, persons 

subject to the CAA, or persons whom 

the Administrator believes may have 

necessary information to monitor and 

report emissions and provide such other 

information the Administrator requests 

for the purposes of carrying out any 

provision of the CAA (except for a 

provision of title II with respect to 

manufacturers of new motor vehicles or 


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2Although there are exclusions in CAA section 

114(a)(1) regarding certain title II requirements 

applicable to manufacturers of new motor vehicle 

and motor vehicle engines, CAA section 208 

authorizes the gathering of information related to 

those areas. 

new motor vehicle engines).2 Section 

208 of the CAA provides EPA with 

similar broad authority regarding the 

manufacturers of new motor vehicles or 

new motor vehicle engines, and other 

persons subject to the requirements of 

parts A and C of title II. We note that 

while climate change legislation 

approved by the U.S. House of 

Representatives would provide EPA 

additional authority for a GHG registry 

similar to today’s rule, and would do so 

for purposes of that pending legislation, 

this final rule is authorized by, and the 

information being gathered by the rule 

is relevant to implementing, the existing 

CAA. We expect, however, that the 

information collected by this final rule 

will also prove useful to legislative 

efforts to address GHG emissions. 

As discussed in the proposal, 

emissions from direct emitters should 

inform decisions about whether and 

how to use CAA section 111 to establish 

new source performance standards 

(NSPS) for various source categories 

emitting GHGs, including whether there 

are any additional categories of sources 

that should be listed under CAA section 

111(b). Similarly, the information 

required of manufacturers of mobile 

sources should support decisions 

regarding treatment of those sources 

under CAA sections 202, 213 or 231. In 

addition, the information from fuel 

suppliers would be relevant in 

analyzing whether to proceed, and 

particular options for how to proceed, 

under CAA section 211(c) regarding 

fuels, or to inform action concerning 

downstream sources under a variety of 

Title I or Title II provisions. The data 

overall also would inform EPA’s 

implementation of CAA section 103(g) 

regarding improvements in nonregulatory strategies and technologies 

for preventing or reducing air pollutants 

(e.g., EPA’s voluntary GHG reduction 

programs such as the non-CO2

partnership programs and ENERGY 

STAR, described below in Section I.D of 

this preamble and Section II of the 

proposal preamble (74 FR 16448, April 

10, 2009)). 

D. How does this rule relate to EPA and 

U.S. government climate change efforts? 

This reporting rule is one specific 

action EPA has taken, consistent with 

the Congressional request contained in 

the FY2008 Consolidated 

Appropriations Act, to collect GHG 

emissions data. EPA has recently 

announced a number of climate change 

related actions, including proposed 

findings that GHG emissions from new 

motor vehicles and engines contribute 

to air pollution which may reasonably 

be anticipated to endanger public health 

and welfare (74 FR 18886, April 24, 

2009, ‘‘Proposed Endangerment and 

Cause or Contribute Findings for 

Greenhouse Gases Under Section 202(a) 

of the Clean Air Act’’), and an intent to 

regulate light duty vehicles, jointly 

published with U.S. Department of 

Transportation (DOT) (74 FR 24007, 

May 22, 2009, ‘‘Notice of Upcoming 

Joint Rulemaking To Establish Vehicle 

GHG Emissions and CAFE Standards’’). 

The Administrator has also announced 

her reconsideration of the memo 

entitled ‘‘EPA’s Interpretation of 

Regulations that Determine Pollutants 

Covered By Federal Prevention of 

Significant Deterioration (PSD) Permit 

Program’’ (73 FR 80300, December 31, 

2008), and granted California’s request 

for a waiver for its GHG vehicle 

standard (74 FR 32744, July 8, 2009). 

These are all separate actions, some of 

which are related to EPA’s response to 

the U.S. Supreme Court’s decision in 

Massachusetts v. EPA. 127 S. Ct. 1438 

(2007). This rulemaking does not 

indicate EPA has made any final 

decisions on pending actions. In fact the 

mandatory GHG reporting program will 

provide EPA, other government 

agencies, and outside stakeholders with 

economy-wide data on facility-level 

(and in some cases corporate-level) GHG 

emissions, which should assist in future 

policy development. 

Accurate and timely information on 

GHG emissions is essential for 

informing many future climate change 

policy decisions. Although additional 

data collection (e.g., for other source 

categories or to support additional 

policy or program needs) will no doubt 

be required as the development of 

climate policies evolves, the data 

collected in this rule will provide useful 

information for a variety of polices. 

Through data collected under this rule, 

EPA, States and the public will gain a 

better understanding of the relative 

emissions of specific industries across 

the nation and the distribution of 

emissions from individual facilities 

within those industries. The facilityspecific data will also improve our 

understanding of the factors that 

influence GHG emission rates and 

actions that facilities could in the future 

or already take to reduce emissions, 

including under traditional and more 

flexible programs. 

As discussed in more detail in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Legal Issues’’ and elsewhere, 

EPA is promulgating this rule to gather 

GHG information to assist EPA in 

assessing how to address GHG 

emissions and climate change under the 

Clean Air Act. However, we expect that 

the information will prove useful for 

other purposes as well. For example, 

using the rich data set provided by this 

rulemaking, EPA, States and the public 

will be able to track emission trends 

from industries and facilities within 

industries over time, particularly in 

response to policies and potential 

regulations. The data collected by this 

rule will also improve the U.S. 

government’s ability to formulate 

climate policies, and to assess which 

industries might be affected, and how 

these industries might be affected by 

potential policies. Finally, EPA’s 

experience with other reporting 

programs is that such programs raise 

awareness of emissions among reporters 

and other stakeholders, and thus 

contribute to efforts to identify and 

implement emission reduction 

opportunities. These data can also be 

coupled with efforts at the local, State 

and Federal levels to assist corporations 

and facilities in determining their GHG 

footprints and identifying opportunities 

to reduce emissions (e.g., through 

energy audits or other forms of 

assistance). 

This GHG reporting program 

supplements and complements, rather 

than duplicates, existing U.S. 

government programs (e.g., climate 

policy and research programs). For 

example, EPA anticipates that facilitylevel GHG emissions data will lead to 

improvements in the quality of the 

Inventory of U.S. Greenhouse Gas 

Emissions and Sinks (Inventory), which 

EPA prepares annually, with input from 

several other agencies, and submits to 

the Secretariat of the United Nations 

Framework Convention on Climate 

Change (UNFCCC). 

A number of EPA voluntary 

partnership programs include a GHG 

emissions and/or reductions reporting 

component (e.g., Climate Leaders, the 

Natural Gas STAR program, Energy 

Star). This mandatory reporting program 

has broader coverage of U.S. GHG 

emissions than most voluntary 

programs, which typically focus on a 

specific industry and/or goal (e.g., 

reduction of CH4 emissions or 

development of corporate inventories). 

It will improve EPA’s understanding of 

emissions from facilities not currently 

included in these programs and increase 

the coverage of these industries. That 

said, we expect ongoing and potential 

new voluntary programs to continue to 


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3Under 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/) 

4For 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. 

5Unless otherwise noted, years and dates in this 

notice refer to calendar years and dates. 

play an important role in achieving lowcost reductions in GHG emissions. 

In addition to EPA’s programs 

mentioned above, U.S. Department of 

Energy (DOE) EIA implements a 

voluntary GHG registry under section 

1605(b) of the Energy Policy Act, which 

is further discussed in Section II of the 

proposal preamble (74 FR 16458, April 

10, 2009). Under EIA’s ‘‘1605(b) 

program,’’ reporters can choose to 

prepare an entity-wide GHG inventory 

and identify specific GHG reductions 

made by the entity.3 EPA’s mandatory 

GHG reporting rule covers a much 

broader set of reporters, primarily at the 

facility rather than entity-level, but this 

reporting rule is not designed with the 

specific intent of reporting of emission 

reductions, as is the 1605(b) program. 

For additional information about 

these programs, please see Sections I 

and II of the preamble to the proposed 

GHG reporting rule (74 FR 16454, April 

10, 2009). 

E. How does this rule relate to other 

State and Regional Programs? 

There are several existing State and 

regional GHG reporting and/or 

reduction programs summarized in 

Section II of the proposal preamble (74 

FR 16457, April 10, 2009). These are 

important programs that not only led 

the way in reporting of GHG emissions 

before the Federal government acted but 

also assist in quantifying the GHG 

reductions achieved by various policies. 

Many of these programs collect different 

or additional data as compared to this 

rule. For example, State programs may 

establish lower thresholds for reporting 

or request information on areas not 

addressed in EPA’s reporting rule (e.g., 

electricity use or emission related to 

other indirect sources). States collecting 

additional information have determined 

that these data are necessary to 

implement their specific climate 

policies and programs. EPA agrees that 

State and regional programs are crucial 

to achieving emissions reductions, and 

this rule does not preempt any other 

programs. 

EPA’s GHG reporting rule is a specific 

single action that was developed in 

response to the Appropriations Act, and 

therefore is targeted to accomplish the 

purpose of the language of the 

Appropriations Act and serve EPA’s 

purposes under the CAA. As State 

experience has demonstrated, we 

recognize that in order to address the 

breadth of climate change issues there 

will likely be a need to collect 

additional data from sources subject to 

this rule as well as other sources. The 

timing and nature of these additional 

needs will be dependent on the types of 

programs and actions the Agency has 

underway or may develop and 

implement in response to future policy 

developments and/or new requests from 

Congress. Addressing climate change 

will require a suite of policies and 

programs and this reporting rule is just 

one effort to collect information to 

inform those policies. 

EPA is committed to working with 

State and regional programs to 

coordinate implementation of reporting 

programs, reduce burden on reporters, 

provide timely access to verified 

emissions data, establish mechanisms to 

efficiently share data, and harmonize 

data systems to the extent possible. See 

Section II.O of this preamble for a 

summary of public comments and 

responses on the role of States and the 

relationship of this GHG reporting rule 

to other programs. See Section VI.B of 

this preamble for a summary of 

comments and responses on State 

delegation of rule implementation and 

enforcement. As mentioned above, for 

additional information about existing 

State and regional programs please see 

Section II of the proposal preamble (74 

FR 16457, April 10, 2009) and the 

docket EPA–HQ–OAR–2008–0508. 

II. General Requirements of the Rule 

The rule requires reporting of annual 

emissions of CO2, CH4, N2O, SF6, HFCs, 

PFCs, and other fluorinated gases (as 

defined in 40 CFR part 98, subpart A) 

in metric tons. The final 40 CFR part 98 

applies to certain downstream facilities 

that emit GHGs, and to certain upstream 

suppliers of fossil fuels and industrial 

GHGs. For suppliers, the GHG emissions 

reported are the emissions that would 

result from combustion or use of the 

products supplied. The rule also 

includes provisions to ensure the 

accuracy of emissions data through 

monitoring, recordkeeping and 

verification requirements. Reporting is 

at the facility 4 level, except that certain 

suppliers of fossil fuels and industrial 

gases would report at the corporate 

level. 

In addition, GHG reporting by 

manufacturers of heavy-duty and offroad vehicles and engines is required, 

by incorporating new requirements into 

the existing reporting requirements for 

motor vehicles and engine 

manufacturers in 40 CFR parts 86, 87, 

89, 90, 94, 1033, 1039, 1042, 1045, 1048, 

1051, 1054, and 1065. A summary of the 

reporting requirements for 

manufacturers of motor vehicles and 

engines is contained in Section IV of 

this preamble. A discussion of public 

comments and responses that pertain to 

motor vehicles is also contained in 

Section IV of this preamble and in the 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Motor Vehicle and Engine 

Manufacturers.’’ 

The remainder of this section 

summarizes the general provisions of 40 

CFR part 98, identifies changes since the 

proposed rule, and summarizes key 

public comments and responses on the 

general requirements of the rule. 

A. Summary of the General 

Requirements of the Final Rule 

1. Applicability 

Reporters must submit annual GHG 

reports for the following facilities and 

supply operations. 

• Any facility that contains any 

source category (as defined in 40 CFR 

part 98, subparts C through JJ) that is 

listed below in any calendar year 

starting in 2010.5 For these facilities, the 

annual GHG report covers all source 

categories and GHGs for which 

calculation methodologies are provided 

in 40 CFR part 98, subparts C through 

JJ. 

—Electricity generating facilities that 

are subject to the Acid Rain Program 

(ARP) or otherwise report CO2 mass 

emissions year-round through 40 CFR 

part 75. 

—Adipic acid production. 

—Aluminum production. 

—Ammonia manufacturing. 

—Cement production. 

—HCFC–22 production. 

—HFC–23 destruction processes that are 

not co-located with a HCFC–22 

production facility and that destroy 

more than 2.14 metric tons of HFC– 

23 per year. 

—Lime manufacturing. 

—Nitric acid production. 

—Petrochemical production. 

—Petroleum refineries. 


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6This does not include portable equipment, 

emergency generators, or emergency equipment as 

defined in the rule. 

7Supplied means produced, imported, or 

exported. 

—Phosphoric acid production. 

—Silicon carbide production. 

—Soda ash production. 

—Titanium dioxide production. 

—Municipal solid waste (MSW) 

landfills that generate CH4 in amounts 

equivalent to 25,000 metric tons CO2e 

or more per year, as determined 

according to 40 CFR part 98, subpart 

HH. 

—Manure management systems that 

emit CH4 and N20 (combined) in 

amounts equivalent to 25,000 metric 

tons CO2e or more per year, as 

determined according to 40 CFR part 

98, subpart JJ. 

• Any facility that contains any 

source category (as defined in 40 CFR 

part 98, subparts C through JJ) that is 

listed below and that emits 25,000 

metric tons CO2e or more per year in 

combined emissions from stationary 

fuel combustion units, miscellaneous 

use of carbonates and all of the source 

categories listed in this paragraph in any 

calendar year starting in 2010. For these 

facilities, the annual GHG report must 

cover all source categories and GHGs for 

which calculation methodologies are 

provided in 40 CFR part 98, subparts C 

through JJ. 

—Ferroalloy Production. 

—Glass Production. 

—Hydrogen Production. 

—Iron and Steel Production. 

—Lead Production. 

—Pulp and Paper Manufacturing. 

—Zinc Production. 

• Any facility that in any calendar 

year starting in 2010 meets all three of 

the conditions listed in this paragraph. 

For these facilities, the annual GHG 

report covers emissions from stationary 

fuel combustion sources only. For 2010 

only, the facilities can submit an 

abbreviated GHG report according to 40 

CFR 98.3(d). 

—The facility does not meet the 

requirements described in the above 

two paragraphs; 

—The aggregate maximum rated heat 

input capacity of the stationary fuel 

combustion units at the facility is 30 

million British thermal units per hour 

(mmBtu/hr) or greater; and 

—The facility emits 25,000 metric tons 

CO2e or more per year from all 

stationary fuel combustion sources.6

• Any supplier (as defined in 40 CFR 

part 98, subparts LL through PP) of any 

of the products as listed below in any 

calendar year starting in 2010. For these 

suppliers, the annual GHG report covers 

all applicable products for which 

calculation methodologies are provided 

in 40 CFR part 98, subparts KK through 

PP. 

—Coal-based liquid fuels: All producers 

of coal-to-liquid fuels; importers and 

exporters of coal-to-liquid fuels with 

annual imports or annual exports that 

are equivalent to 25,000 metric tons 

CO2e or more per year. 

—Petroleum products: All petroleum 

refiners that distill crude oil; 

importers and exporters of petroleum 

products with annual imports or 

annual exports that are equivalent to 

25,000 metric tons CO2e or more per 

year. 

—Natural gas and natural gas liquids 

(NGLs): All natural gas fractionators 

and all local natural gas distribution 

companies (LDCs). 

—Industrial GHGs: All producers of 

industrial GHGs; importers and 

exporters of industrial GHGs with 

annual bulk imports or exports of 

N2O, fluorinated GHGs, and CO2 that 

in combination are equivalent to 

25,000 metric tons CO2e or more per 

year. 

—CO2: All producers of CO2; importers 

and exporters of CO2 with annual 

bulk imports or exports of N2O, 

fluorinated GHGs, and CO2 that in 

combination are equivalent to 25,000 

metric tons CO2e or more per year. 

• Research and development 

activities (as defined in 40 CFR 98.6) are 

not considered to be part of any source 

category subject to the rule. 

It is important to note that the 

applicability criteria apply to a facility’s 

annual emissions or a supplier’s annual 

quantity of product supplied.7 For 

example, while a facility’s emissions 

may be below 25,000 metric tons CO2e 

in January, if the cumulative emissions 

for the calendar year are 25,000 metric 

tons CO2e or more at the end of 

December, the rule applies and the 

reporter must submit an annual GHG 

report for that facility. Therefore, it is in 

a facility’s or supplier’s interest to 

collect the GHG data required by the 

rule if they think they will meet or 

exceed the applicability criteria in 40 

CFR 98.2 by the end of the year. EPA 

plans to have tools and guidance 

available to assist potential reporters in 

assessing whether the rule applies to 

their facilities or supply operations. 

2. Schedule for Reporting 

Reporters must begin collecting data 

on January 1, 2010. The first annual 

GHG report is due on March 31, 2011, 

for GHGs emitted or products supplied 

during 2010. For a portion of 2010, the 

rule allows reporters to use best 

available monitoring methods for 

parameters that cannot reasonably be 

measured according to the monitoring 

and quality assurance/quality control 

(QA/QC) requirements of the relevant 

subpart as described in Sections II.A.3 

and II.G of this preamble. 

Reports are submitted annually. For 

EGUs that are subject to the ARP, 

reporters must continue to report CO2

mass emissions quarterly, as required by 

the ARP, in addition to providing 

annual GHG reports under this rule. 

Reporters must submit GHG data on an 

ongoing, annual basis. The snapshot of 

information provided by a one-time 

information collection request (ICR) 

would not provide the type of ongoing 

information which could inform the 

variety of potential CAA policy options 

being evaluated for addressing climate 

change. 

Once subject to this reporting rule, 

reporters must continue to submit GHG 

reports annually. A reporter can cease 

reporting if the required annual GHG 

reports demonstrate that reported GHG 

emissions are either (1) less than 25,000 

metric tons of CO2e per year for five 

consecutive years or (2) less than 15,000 

metric tons of CO2e per year for three 

consecutive years. The reporter must 

notify EPA that they intend to cease 

reporting and explain the reasons for the 

reduction in emissions. This provision 

applies to all facilities and suppliers 

subject to the rule, regardless of their 

applicability category (i.e., whether rule 

applicability was initially triggered by 

an ‘‘all-in’’ source category or a source 

category with a 25,000 metric tons CO2e 

threshold). The reporter must keep 

records for all five consecutive years in 

which emissions were less than 25,000 

metric tons per year, or all three 

consecutive years in which emissions 

were less than 15,000 metric tons per 

year, as appropriate. If GHG emissions 

(or quantities in products supplied) 

subsequently increase to 25,000 metric 

tons CO2e in any calendar year, the 

reporter must again begin annual 

reporting. The rule also contains a 

provision to allow facilities and 

suppliers to notify EPA and stop 

reporting if they close all GHG-emitting 

processes and operations covered by the 

rule. 

If reporters discover or are notified by 

EPA of errors in an annual GHG report, 

they must submit a revised GHG report 

within 45 days. 

3. What has to be included in the annual 

GHG report? 

Reporters must include the following 

information in each annual GHG report: 


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8Suppliers include producers, importers, and 

exporters of fuels and industrial gases. The level of 

reporting for suppliers is specified in the rule. Most 

report at the facility level. Imports and exports are 

reported at the corporate level. 

9 ‘‘Use’’ for purposes of industrial GHGs presumes 

that there will be 100 percent release of the GHG. 

10Although CBI determinations are usually made 

on a case-by-case basis, EPA has discussed in an 

earlier Federal Register notice what constitutes 

emissions data that cannot be withheld as CBI (956 

FR 7042–7043, February 21, 1991). In addition, as 

discussed in Section II.R of this preamble, EPA will 

be initiating a separate notice and comment process 

to make CBI and emissions data determinations for 

the categories of data collected under this 

rulemaking. 

11For more information about the reporting 

format please see Section V of this preamble. 

• Facility name or supplier name (as 

appropriate) and physical street address 

including the city, State, and zip code. 

• Year and months covered by the 

report, and date of report submittal. 

• For facilities that directly emit 

GHG: 

—Annual facility emissions (excluding 

biogenic CO2), expressed in metric 

tons of CO2e per year, aggregated for 

all GHG from all source categories in 

40 CFR part 98, subparts C through JJ 

that are located at the facility. 

—Annual emissions of biogenic CO2

(i.e., CO2 from combustion of 

biomass) aggregated for all applicable 

source categories in subparts C 

through JJ located at the facility. 

—Annual GHG emissions for each of the 

source categories located at the 

facility, by gas. Gases are: CO2

(excluding biogenic CO2), biogenic 

CO2, CH4, N2O, and each fluorinated 

GHG. 

—Within each source category, 

emissions broken out at the level 

specified in the respective subpart 

(e.g., some source categories require 

reporting for each individual unit or 

each process line). 

—Additional data specified in the 

applicable subparts for each source 

category. This includes activity data 

(e.g., fuel use, feedstock inputs) that 

were used to generate the emissions 

data and additional data to support 

QA/QC and emissions verification. 

—Total pounds of synthetic fertilizer 

produced through nitric acid or 

ammonia production and total 

nitrogen contained in that fertilizer. 

• For suppliers: 8

—Annual quantities of each GHG that 

would be emitted from combustion or 

use 9 of the products supplied, 

imported, or exported during the year. 

Report this for each applicable supply 

category in 40 CFR part 98 subparts 

KK through PP, by gas. Also report the 

total quantity, expressed in metric 

tons of CO2e, aggregated for all GHGs 

from all applicable supply categories. 

—Additional data specified in the 

applicable subparts for each supply 

category. This includes data used to 

calculate GHG quantities or needed to 

support QA/QC and verification. 

• A written explanation if the 

reporter changes GHG calculation 

methodologies during the reporting 

period. 

• If best available monitoring 

methods were used for part of calendar 

year 2010, a brief description of the 

methods used. 

• Each data element for which a 

missing data procedure was used 

according to the procedures of an 

applicable subpart and the total number 

of hours in the year that a missing data 

procedure was used for each data 

element. 

• A signed and dated certification 

statement provided by the Designated 

Representative of the owner or operator. 

Note that in some cases, the same 

facility is subject to the rule 

requirements for direct emitters as well 

as for suppliers. For example, petroleum 

refineries are suppliers of petroleum 

products (40 CFR part 98, subpart NN) 

and also directly emit GHGs from 

petroleum refining (40 CFR part 98, 

subpart Y), general stationary fuel 

combustion (40 CFR part 98, subpart C), 

and possibly other source categories 

located at a refinery. In such cases, 

reporters must report the information in 

both the facility and supplier bullets 

listed above. 

EPA will protect any information 

claimed as CBI in accordance with 

regulations in 40 CFR part 2, subpart B. 

However, note that in general, emission 

data collected under CAA sections 114 

and 208 shall be available to the public 

and cannot be withheld as CBI.10

Special Provisions for Reporting Year 

2010. During January 1, 2010 through 

March 31, 2010, reporters may use best 

available monitoring methods for any 

parameter (e.g., fuel use, daily carbon 

content of feedstock by process line) 

that cannot reasonably be measured 

according to the monitoring and QA/QC 

requirements of a relevant subpart. The 

reporter must still use the calculation 

methodologies and equations in the 

‘‘Calculating GHG Emissions’’ sections 

of each relevant subpart, but may use 

the best available monitoring method for 

any parameter for which it is not 

reasonably feasible to acquire, install, 

and operate a required piece of 

monitoring equipment by January 1, 

2010. Starting no later than April 1, 

2010, the reporter must begin following 

all applicable monitoring and QA/QC 

requirements of this part, unless they 

submit a request to EPA showing that it 

is not reasonably feasible to acquire, 

install, and operate a required piece of 

monitoring equipment by April 1, 2010, 

and EPA approves the request. EPA will 

not approve use of best available 

methods beyond December 31, 2010. 

Best available monitoring methods 

include any of the following methods: 

• Monitoring methods currently used 

by the facility that do not meet the 

specifications of a relevant subpart. 

• Supplier data. 

• Engineering calculations. 

• Other company data. 

Abbreviated GHG Report for Facilities 

Containing Only General Stationary 

Fuel Combustion Sources. In lieu of a 

full annual GHG report, reporters may 

submit an abbreviated GHG report for 

2010 emissions from existing facilities 

that were in operation as of January 1, 

2010, and are required to report only 

their stationary combustion source 

emissions per 40 CFR 98.2(a)(3). The 

abbreviated report contains total facility 

GHG emissions aggregated for all 

stationary combustion units calculated 

according to any of the methods in 40 

CFR 98.33(a) and expressed in metric 

tons of CO2, CH4, N2O, and CO2e. While 

the breakdown of emissions by 

individual combustion units and the 

activity data used to calculate the 

emissions do not need to be reported as 

part of the abbreviated GHG report, the 

calculation variables used in the 

selected method must be reported. For 

calendar year 2011, all reporters must 

submit the full annual GHG report 

containing all required information. 

4. How is the report submitted? 

The reports must be submitted 

electronically, in a format to be 

specified by the Administrator after 

publication of the final rule.11 To the 

extent practicable, we plan to adapt 

existing EPA facility reporting programs 

to accept GHG emissions data. We are 

developing a new electronic data 

reporting system for source categories or 

suppliers for which it is not feasible to 

use existing EPA reporting mechanisms. 

Each report must contain a signed 

certification by a Designated 

Representative of the facility. On behalf 

of the owners and operators, the 

Designated Representative must certify 

under penalty of law that the report has 

been prepared in accordance with the 

requirements of 40 CFR part 98 and that 

the information contained in the report 

is true and accurate. 

5. What records must be retained? 

Each reporter must also retain and 

make available to EPA upon request the 


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12See the following sections of this preamble for 

discussion of source categories not included in 

today’s final rule: sections III.I (electronics 

manufacturing), III.J (ethanol production), III.L 

(fluorinated GHG production), III.M (food 

processing), III.T (magnesium production), III.W (oil 

and natural gas systems), III.DD (SF6 from electrical 

equipment), III.FF (underground coal mines), III.HH 

(industrial landfills are not included in today’s rule, 

but MSW landfills are covered by the rule), III.II 

(wastewater treatment), and III.KK (suppliers of 

coal). 

following records for three years in an 

electronic or hard-copy format as 

appropriate: 

• A list of all units, operations, 

processes and activities for which GHG 

emissions are calculated. 

• The data used to calculate the GHG 

emissions for each unit, operation, 

process, and activity, categorized by fuel 

or material type. These data include, but 

are not limited to: 

—The GHG emissions calculations and 

methods used. 

—Analytical results for the development 

of site-specific emissions factors. 

—The results of all required analyses for 

high heat value, carbon content, or 

other required fuel or feedstock 

parameters. 

—Any facility operating data or process 

information used for the GHG 

emissions calculations. 

• The annual GHG reports. 

• Missing data computations. For 

each missing data event, also retain a 

record of the duration of the event, 

actions taken to restore malfunctioning 

monitoring equipment, the cause of the 

event, and the actions taken to prevent 

or minimize occurrence in the future. 

• A written GHG monitoring plan 

containing the information specified in 

40 CFR 98.3(g)(5). 

• The results of all required 

certification and quality assurance (QA) 

tests of CEMS, fuel flow meters, and 

other instrumentation used to provide 

data for the GHGs reported. 

• Maintenance records for all CEMS, 

flow meters, and other instrumentation 

used to provide data for the GHGs 

reported. 

• Any other data specified in any 

applicable subpart of 40 CFR part 98. 

Examples of such data could include the 

results of sampling and analysis 

procedures required by the subparts 

(e.g., fuel heat content, carbon content 

of raw materials, and flow rate) and 

other data used to calculate emissions. 

B. Summary of the Major Changes Since 

Proposal 

EPA received approximately 16,800 

public comments on the proposed 

rulemaking. As mentioned earlier in this 

preamble, we had two public hearings 

and conducted an unprecedented level 

of outreach between signature of the 

proposal and the close of the public 

comment period. Below are the major 

changes to the program since the 

proposal. The rationale for these and 

any other significant changes can be 

found in this preamble or in the 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments.’’ 

• Reduced the number of source 

categories included in the final rule as 

we further consider comments and 

options on several categories.12

• Added a mechanism in 40 CFR 98.2 

to allow facilities and suppliers that 

report less than 25,000 metric tons of 

CO2e for five consecutive years, or less 

than 15,000 metric tons for 3 

consecutive years, to cease annual 

reporting to EPA. 

• Added a mechanism in 40 CFR 98.2 

to allow facilities and suppliers that 

stop operating all GHG-emitting 

processes and operations covered by the 

rule to cease annual reporting to EPA. 

• Added a provision in 40 CFR 98.3 

for submittal of revised annual GHG 

reports to correct errors. 

• Added provisions in 40 CFR 98.3 to 

allow use of best available monitoring 

methods for part of calendar year 2010. 

• Added, in 40 CFR 98.3, calibration 

requirements for monitoring 

instruments including an accuracy 

specification of plus or minus five 

percent for flow meters. 

• Excluded R&D activities from 

reporting under 40 CFR part 98 by 

adding an exclusion in 40 CFR 98.2. 

• Revised the requirements of the 

Designated Representative in 40 CFR 

98.4 to align them with those in 40 CFR 

part 75 (ARP regulations). 

• Changed record retention to three 

years instead of five years for most 

records (40 CFR 98.3). 

• In the recordkeeping section (40 

CFR 98.3), clarified the contents of the 

monitoring plan (called the quality 

assurance performance plan (QAPP) at 

proposal). 

• Edited references to the stationary 

fuel combustion subpart to improve 

consistency and edited the CEMS 

language in several subparts for 

consistency and to clarify when CEMS 

are used and under what circumstances 

upgrades are needed. 

• Revised several definitions in 40 

CFR part 98, subpart A to address 

comments. 

• In several subparts of 40 CFR part 

98, moved some of the data elements 

listed in the recordkeeping section of 

the proposed rule to the reporting 

section. In general, these changes were 

made to provide sufficient data for EPA 

to verify the reported emissions using 

the verification approach described in 

Section II.N of this preamble. Specific 

changes and reasons for them are 

summarized in the relevant source 

category sections within Section III of 

this preamble. 

C. Summary of Comments and 

Responses on GHGs To Report 

This section contains a brief summary 

of major comments and responses on 

the issue of which GHGs to report. A 

large number of comments were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, 

Selection of Reporting Thresholds, 

Greenhouse Gases, and De Minimis 

Provisions.’’ Reponses to comments on 

fluorinated gases can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Suppliers of Industrial 

GHGs.’’ 

Comment: Many commenters 

supported reporting of the GHGs 

included in the proposed rule: CO2, 

CH4, N2O, HFCs, PFCs, SF6, and other 

fluorinated compounds. Many 

commenters noted that IPCC and 

national inventories focus on these 

gases, and that they are directly emitted 

by human activities, long-lived in the 

atmosphere, and contribute to global 

climate change. A few of these also 

stated that collection of data on these 

gases is useful for future GHG policy 

development. While some commenters 

suggested collecting data on fewer gases 

or requiring reporting of additional 

gases, most agreed with the proposed 

list. 

Some commenters raised concerns 

that the proposed definition of 

fluorinated GHGs was broad and 

included compounds for which global 

warming potentials (GWPs) were not 

currently available. 

Response: The final rule requires 

reporting of the same gases as the 

proposed rule. These are the most 

abundantly emitted GHGs that result 

from human activity. They are not 

currently controlled by mandatory 

Federal programs and, with the 

exception of the CO2 emissions data 

reported by EGUs subject to the ARP, 

data on their emissions are also not 

reported under mandatory Federal 

programs. CO2 is the most abundant 

GHG directly emitted by human 

activities, and is a significant driver of 

climate change. The global 

anthropogenic combined heating effect 

of CH4, N2O, HFCs, PFCs, SF6, and the 

other fluorinated compounds are also 


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13 2006 IPCC Guidelines for National Greenhouse 

Gas Inventories. The National Greenhouse Gas 

Inventories Programme, H.S. Eggleston, L. Buendia, 

K. Miwa, T. Ngara, and K. Tanabe (eds), hereafter 

referred to as the ‘‘2006 IPCC Guidelines’’ are found 

at: http://www.ipcc.ch/ipccreports/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). 

14For the discussion of the CAA authority to 

collect these data, see Section II.Q of this preamble. 

Also see the relevant source category sections 

within Section III of this preamble. 

significant: About 40 percent as large as 

the CO2 heating effect according to the 

Fourth Assessment Report of the IPCC. 

The IPCC focuses on CO2, CH4, N2O, 

HFCs, PFCs, and SF6 for both scientific 

assessments and emissions inventory 

purposes because these are long-lived, 

well-mixed GHGs not controlled by the 

Montreal Protocol as Substances that 

Deplete the Ozone (O3) Layer. These 

GHGs are directly emitted by human 

activities, are reported annually in 

EPA’s Inventory of U.S. Greenhouse Gas 

Emissions and Sinks, and are a major 

focus of the climate change research and 

policy communities. The IPCC also 

included methods for accounting for 

emissions from several specified 

fluorinated gases in the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories.13 These gases include 

fluorinated ethers, which are used in 

electronics, in anesthetics, and as heat 

transfer fluids. These fluorinated 

compounds are long-lived in the 

atmosphere and have high GWPs, like 

the HFCs, PFCs, and SF6. In many cases 

these fluorinated gases are used in 

growing industries (e.g., electronics) or 

as substitutes for HFCs. As such, EPA is 

requiring reporting of these gases to 

ensure that the Agency has an accurate 

understanding of the emissions and uses 

of these gases, particularly as those uses 

expand. 

There are other GHGs and aerosols 

that have climatic warming effects that 

we are not including in this rule: water 

vapor, chlorofluorocarbons (CFCs), 

hydrochlorofluorocarbons (HCFCs), 

halons, tropospheric O3, and black 

carbon. The reasons why we are not 

requiring reporting of these gases and 

aerosols under this rule are contained in 

Section IV.A of the preamble to the 

proposed rule (74 FR 16464, April 10, 

2009) and in the ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, 

Selection of Reporting Thresholds, 

Greenhouse Gases, and De Minimis 

Provisions.’’ 

In response to comments, the 

definition of fluorinated gases to report 

has been changed. See Section III.OO of 

this preamble (Suppliers of Industrial 

GHGs) for the response to comments on 

fluorinated gases to be reported. 

D. Summary of Comments and 

Responses on Source Categories To 

Report 

This section contains a brief summary 

of major comments and responses on 

which source categories must report. A 

large number of comments were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, 

Selection of Source Categories to Report 

and Level of Reporting.’’ 

1. Reduction in Number of Source 

Categories Included in the Final Rule 

Comment: While many commenters 

agreed with the source categories 

selected for inclusion in the proposed 

rule, some commenters objected to the 

inclusion of specific source categories. 

Some also expressed concern that there 

might not be sufficient time for EPA to 

consider and address public comments 

and finalize the rules by fall 2009 for 

particular source categories. 

Response: In today’s notice EPA is 

promulgating subparts that require 

reporting for most of the source 

categories included in the proposed 

rule. For these categories, EPA fully 

considered and addressed the public 

comments, and has determined that the 

source categories should be included in 

the rule for reasons stated in Section 

IV.B of the preamble for the proposed 

rule (74 FR 16465, April 10, 2009), the 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments: EPA’s Response to Public 

Comments, Selection of Source 

Categories to Report and Level of 

Reporting’’, and the relevant comment 

response volumes for each of the 

individual source categories. However, 

at this time EPA is not going final with 

the following subparts as we further 

evaluate public comments: 

• Electronics manufacturing 

• Ethanol production 

• Fluorinated GHG production 

• Food processing 

• Magnesium production 

• Oil and natural gas systems 

• SF6 from electrical equipment 

• Underground coal mines 

• Industrial landfills 

• Wastewater treatment 

• Suppliers of coal 

We plan to further review public 

comments and other information before 

finalizing these subparts. Additional 

discussion of our reasons for not 

finalizing these particular source 

categories at this time can be found in 

the individual subsections in Section III 

of this preamble. 

2. Scope of Source Categories Covered 

Comment: Several commenters 

suggested that the scope of reporting 

and the source categories covered 

should be broader. Some indicated that 

the rule should require reporting of net 

rather than gross emissions, including 

reporting of offset projects. In addition, 

some of the comments suggested 

requiring reporting of emissions and 

sequestration from forestry practices. 

Response: EPA selected the source 

categories required to report under the 

rule after considering the language of 

the Appropriations Act, the 

accompanying explanatory statement, 

the CAA, and EPA’s experience in 

developing the U.S. GHG Inventory. The 

Appropriations Act referred to reporting 

‘‘in all sectors of the economy,’’ and the 

explanatory statement directed EPA to 

include ‘‘emissions from upstream 

production and downstream sources to 

the extent the Administrator deems it 

appropriate.’’ EPA interpreted this to 

mean direct emissions from facilities 

over a certain threshold as well as the 

emissions associated with fuel or 

industrial gases when completely 

combusted or used, but not necessarily 

project-based reductions or 

sequestration.14 Calculation and 

reporting of net emissions (emissions at 

a facility less any sequestration 

occurring at the facility) was determined 

to be outside of the scope of this rule. 

In selecting source categories, EPA 

considered all anthropogenic sources of 

GHG emissions (those produced as a 

result of human activities) included in 

the U.S. GHG Inventory and reviewed 

the 2006 IPCC Guidelines for National 

Greenhouse Gas Inventories and 

existing voluntary and regulatory GHG 

reporting programs for additional source 

categories that might be relevant. EPA 

systematically reviewed the list of 

source categories developed from the 

U.S. GHG Inventory and the IPCC 

guidance to ensure the inclusion of 

those that emit the most significant 

amounts of GHG emissions while 

minimizing the number of reporters. 

Some sources were deemed 

inappropriate for inclusion in this rule 

for a variety of reasons including the 

current ability to monitor and verify the 

emissions or products with sufficient 

accuracy and consistency. For further 

discussions of sources included and 

excluded please see Section IV.B of the 

preamble to the proposed rule (74 FR 

16465). In total, the rule is estimated to 


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cover approximately 85 percent of U.S. 

GHG emissions. 

With respect to emissions and 

sequestration from agricultural sources 

and other land uses, the rule does not 

require reporting of emissions or 

sequestration associated with 

deforestation, carbon storage in living 

biomass or harvested wood products. 

These categories were excluded because 

currently available, practical reporting 

methods to calculate facility-level 

emissions for these sources can be 

difficult to implement and can yield 

uncertain results. Currently, there are no 

direct GHG emission measurement 

methods available except for research 

methods that are very expensive and 

require sophisticated equipment. 

Limited modeling-based methods have 

been developed for voluntary GHG 

reporting protocols which use general 

emission factors, and large-scale models 

have been developed to produce 

comprehensive national-level emissions 

estimates, such as those reported in the 

U.S. GHG Inventory report. To calculate 

emissions or sequestration using 

emission factor or carbon stock 

exchange approaches, it would be 

necessary for landowners to report on 

management practices and a variety of 

data inputs. The activity data collection 

and emission factor development 

necessary for emissions calculations at 

the scale of individual reporters can be 

complex and costly. Due to the current 

lack of reasonably accurate facility-level 

emissions/stock change factors and the 

ability to accurately measure all facilitylevel calculation variables at a 

reasonable cost to reporters, the 

reporting of emissions and sequestration 

associated with deforestation and 

carbon sequestration from forestry 

practices was excluded as a source 

category. 

While this reporting rule does not 

require reporting by facilities or 

suppliers in every source category, the 

U.S. GHG Inventory does provide 

national estimates of emissions from all 

U.S. anthropogenic GHG sources. In the 

case of land-based emissions, this 

includes all emissions by sources and 

removals by sinks on lands that are 

managed. The Inventory is prepared 

annually by EPA, in collaboration with 

other Federal agencies, and is an 

impartial, policy-neutral report that 

tracks annual GHG emissions at the 

national level and presents historical 

emissions from 1990 to 2007. The 

Inventory also calculates carbon dioxide 

emissions that are removed from the 

atmosphere by ‘‘sinks,’’ such as through 

the uptake of carbon by forests, 

vegetation, and soils. 

Offsets projects are of interest to many 

stakeholders because they could be an 

important component of a potential 

future cap and trade system. Some 

commenters requested EPA to include 

accounting methods for offsets in this 

reporting rule. We believe that this issue 

is beyond the scope of this rulemaking 

and the Congressional request that 

initiated it. However, EPA will continue 

to monitor policy needs and 

developments in the future and is 

prepared to initiate additional reporting 

efforts at the appropriate time. 

3. Reporting by Both Upstream and 

Downstream Sources 

Comment: Some commenters were 

concerned that requiring reporting by 

both fuel and industrial GHG suppliers 

(upstream sources) and direct emitters 

(downstream sources) results in double 

counting of GHG emissions and could 

lead to overestimation of emissions. 

Some commenters thought reporting by 

both upstream and downstream sources 

was duplicative, confusing, 

unnecessary, or burdensome and 

recommended the rule be revised to 

eliminate double reporting. Other 

commenters agreed with EPA’s 

proposed selection of source categories 

to report and that reporting by upstream 

sources and downstream sources is 

needed to inform development of GHG 

policies and programs. 

Response: This rule responds to a 

specific request from Congress to collect 

data on GHG emissions from both 

upstream production and downstream 

sources, as appropriate. The rule 

requires reporting by facilities that 

directly emit GHGs above the selected 

threshold as a result of combustion of 

fuel or industrial processes 

(downstream sources). The majority of 

these reporters are large facilities in the 

electricity generation and industrial 

sectors. The rule also requires upstream 

suppliers of fossil fuels and industrial 

GHGs to report the GHG emissions that 

could be emitted from combustion or 

use of the quantity of fuels or industrial 

gases supplied into the economy. In 

many cases, the fossil fuels and 

industrial GHGs supplied by producers 

and importers are used and ultimately 

emitted by a large number of small 

sources. To cover these direct emissions 

would require reporting by hundreds or 

thousands of small facilities. To avoid 

this impact, the rule does not include all 

of those emitters but instead requires 

reporting by the suppliers of industrial 

gases and suppliers of fossil fuels. 

The data collected under this rule are 

consistent with the appropriations 

language and provide valuable 

information to EPA and stakeholders in 

the development of climate change 

policy and programs. Potential policies 

such as low carbon fuel standards can 

only be applied upstream, whereas enduse emission standards can only be 

applied downstream. Data from 

upstream and downstream sources 

would be necessary to formulate and 

assess the impacts of such potential 

policies. Eliminating reporting by either 

upstream sources or downstream 

sources would not satisfy EPA’s data 

needs and policy objectives of this rule. 

EPA acknowledges that there is 

inherent double reporting of emissions 

in a program that includes both 

upstream and downstream sources. 

However, as discussed in Sections I.D 

and IV.B of the preamble to the 

proposed rule (74 FR 16448, April 10, 

2009) EPA does not intend to use 

emissions data collected by this rule as 

a replacement for the national emission 

estimates found in the annual Inventory 

of GHG emissions. 

E. Summary of Comments and 

Responses on Thresholds 

This section contains a brief summary 

of major comments and responses on 

EPA’s approach and rationale for 

selection of reporting thresholds. See 

sections III.C through PP of this 

preamble for summaries of comments 

and responses on specific threshold 

analyses for the individual source 

categories contained in 40 CFR part 98, 

subparts C through PP. A large number 

of comments were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Selection of 

Reporting Thresholds, Greenhouse 

Gases, and De Minimis Provisions.’’ 

Comment: Many commenters 

supported the proposed threshold of 

25,000 metric tons of CO2e per calendar 

year. These commenters generally 

agreed that the 25,000 metric ton 

threshold level achieves a reasonable 

balance between the percentage of 

national emissions covered and the 

number of reporters, resulting in a 

sufficiently comprehensive dataset 

while minimizing the impact on small 

facilities. Some also commented that 

this threshold is consistent with other 

existing GHG programs or likely future 

programs. Some commenters supported 

a 100,000 metric ton CO2e threshold 

because they believe this level covers an 

appropriate percentage of national GHG 

emissions while easing the reporting 

burden on industry. Some commenters 

supported an emission threshold of 

10,000 metric tons CO2e to enable 

collection of emissions data for smaller 


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15As explained in section II.A of this preamble, 

facilities that only have stationary combustion units 

as their only source of emissions and have units 

with an aggregate maximum heat input of less than 

30 mmbtu are not included in this rule. 

16Although the thresholds were expressed in 

different ways (e.g., ‘‘all-in’’, annual emissions) 

most corresponded to, or were consistent with, an 

annual facility-wide emission level of 25,000 metric 

tons of CO2e. 

sources. Some of these commenters also 

noted that a 10,000 metric ton CO2e 

threshold is more appropriate in order 

to monitor leakage of emissions to 

smaller sources (since 25,000 metric 

tons of CO2e is a likely threshold for 

future emissions reductions mandates). 

Some commenters suggested 

quantitative evaluation of intermediate 

threshold options in addition to the four 

evaluated by EPA (1,000; 10,000; 

25,000; and 100,000); several of these 

suggested EPA analyze a threshold of 

50,000 metric tons CO2e to reduce the 

number of reporting facilities. 

Response: As described in the 

preamble to the proposed rule (74 FR 

16448, April 10, 2009), EPA considered 

four threshold levels, as well as 

capacity-based thresholds where 

appropriate, and we proposed a 

threshold of 25,000 metric tons of CO2e 

for many source categories, and 

capacity-based or ‘‘all in’’ thresholds for 

other categories. Based on comments 

received, we reexamined the threshold 

analyses both in general and for each 

industry, taking into account additional 

data provided, and we considered 

whether there were reasons to develop 

different thresholds in specific industry 

sectors. The specific elements of these 

analyses are discussed in the relevant 

source category discussions in this 

preamble and the accompanying 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments’’ volumes for each source 

category. At the general level, we also 

considered non-quantitative factors, 

such as consistency with State and other 

programs (the majority have established 

thresholds for GHG reporting at 25,000 

metric tons or lower, such as 10,000 or 

5,000 metric tons), and the need to 

select a threshold level that best satisfies 

the objective of the reporting rule to 

collect a national data set that is 

sufficiently comprehensive for use in 

analyzing a range of GHG policies and 

programs. 

From these analyses, we concluded 

that a 25,000 metric ton threshold suited 

the needs of the reporting program by 

providing comprehensive coverage of 

emissions with a reasonable number of 

reporters, thereby creating the robust 

data set necessary for the quantitative 

analyses of the range of likely GHG 

policies, programs and regulations. 

Moreover, the 25,000 metric ton 

threshold covers similarly sized sources 

as covered by many current CAA 

programs (e.g., NSPS applies PM 

emissions limits to oil-fired and coalfired units larger than 30 mmBtu per 

hour).15 And, as mentioned previously, 

this level is consistent with (or higher 

than) the majority of other GHG 

reporting programs. Furthermore, 

having a uniform threshold 16 was an 

equitable approach because like 

facilities could be compared across 

sectors and no one industry would be 

disproportionately affected or subjected 

to a lower or higher threshold. A 

uniform threshold is also essential for 

evaluating potential policies and 

programs that could have a single 

emissions threshold across source 

categories (e.g., PSD), and simplifies the 

applicability determination for facilities 

that emit GHGs from more than one 

source category under the rule. 

As discussed in Section IV.C of the 

preamble to the proposed rule (74 FR 

16448, April 10, 2009), we considered 

four potential thresholds (the range of 

1,000 to 100,000 metric tons of CO2e) 

and from our analysis and the 

comments we concluded we had 

enough information to select an 

appropriate threshold for the final rule 

and that detailed quantitative analyses 

of additional intermediate thresholds 

would not change EPA’s decision. For 

example, in reviewing our threshold 

analyses, we determined that the 

intermediate options between 25,000 

and 100,000 metric tons would not 

provide an alternative threshold that 

substantially reduced the number of the 

reporters relative to other options 

considered or substantially improved 

the cost effectiveness. (See ‘‘Review of 

Threshold Analyses’’ memorandum in 

docket EPA–HQ–OAR–2008–0508.) 

Based on our proposal analysis on the 

data available, we saw that the majority 

of the affected facilities or suppliers had 

emissions either considerably above or 

below 25,000 metric tons CO2e per year. 

(As previously explained, supplier GHG 

quantities represent the emissions that 

could be released when the products 

they supply are combusted or used.) 

The selected threshold took into 

account our finding that while a 

threshold other than 25,000 metric tons 

of CO2e might appear to achieve an 

appropriate balance between the 

number of facilities and emissions 

covered for a limited number of source 

categories, there are several additional 

reasons for selecting the threshold of 

25,000 metric tons of CO2e per year. 

The lower threshold alternatives that 

we considered were 1,000 metric tons of 

CO2e per year, and 10,000 metric tons 

of CO2e per year. At proposal, we 

explained that we did not select either 

of these thresholds because although 

both broaden national emissions 

coverage, they do so by 

disproportionately increasing the 

number of affected facilities. With the 

data available at proposal and from the 

comment period, we remain convinced 

that the 1,000 metric ton CO2e/year 

threshold would increase the number of 

reporters by an order of magnitude, thus 

changing the focus of the program from 

large to small emitters and imposing 

reporting costs on tens of thousands of 

small businesses that in total would 

amount to less than 10 percent of 

national GHG emissions. Our analysis 

indicates that a 10,000 metric ton CO2e/ 

yr threshold would approximately 

double the number of reporters, but 

would only increase national emissions 

coverage by one percent. (See the 

Regulatory Impacts Analysis for the 

final rule for the estimated number of 

facilities and GHG emissions covered by 

the alternative thresholds examined.) 

While some proposals (e.g., WCI and 

H.R. 2454, American Clean Energy and 

Security Act) contain a 10,000 metric 

ton threshold for reporting, EPA 

concluded for policy evaluation 

purposes, the 25,000 metric ton 

threshold more effectively targets large 

industrial emitters and suppliers, covers 

approximately 85 percent of U.S. 

emissions, and minimizes the burden on 

smaller facilities. 

We also reviewed the 100,000 metric 

tons of CO2e per year as an alternative 

threshold but concluded that it fails to 

satisfy key objectives. It excludes a 

number of emitters in certain source 

categories such that the emissions data 

would not adequately cover key sectors 

of the economy. At 100,000 metric tons 

CO2e per year, reporting for some large 

industry sectors would be rather 

significantly fragmented, resulting in an 

incomplete understanding of direct 

emissions from that sector. We 

concluded that this threshold would not 

sufficiently cover the types of facilities 

that are typically regulated under the 

CAA and would be inadequate for the 

intended use of analyzing potential 

policies and developing future CAA 

programs. 

Based on our review, EPA has 

determined that the selected 25,000 

metric ton CO2e threshold will cover 

many of the types of facilities and 

suppliers typically regulated under the 

CAA, while appropriately balancing 


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emission coverage and burden. At this 

threshold, EPA will be able to evaluate 

the effects of a number of options and 

policies that could address GHG 

emissions without placing an undue 

burden on a large number of smaller 

facilities and sources. In addition, this 

threshold level is largely consistent with 

many of the existing GHG reporting 

programs and different legislative 

proposals in Congress. Furthermore, 

many industry stakeholders that EPA 

met with and the majority of public 

commenters, representing a wide variety 

of stakeholders, expressed support for a 

25,000 metric ton CO2e threshold, 

agreeing with the Agency’s assessment 

of coverage. 

F. Summary of Comments and 

Responses on Level of Reporting 

This section contains a brief summary 

of major comments and responses on 

the level of reporting. A large number of 

comments were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Selection of Source 

Categories to Report and Level of 

Reporting.’’ 

Comment: Many commenters 

supported facility-level reporting rather 

than corporate-level reporting. The 

reasons they gave included: Facilitylevel reporting is consistent with most 

air rules and permitting programs, 

environmental managers are used to 

facility-level reporting, facility-level 

data would be needed to implement 

likely future regulatory programs such 

as a cap and trade program, this 

approach is simpler to implement and 

minimizes administrative burden, a 

facility’s corporate status can change 

during the year, and tying data to 

physical sources makes emissions easier 

to track and monitor over time. On the 

other hand, several commenters favored 

corporate-level reporting. The reasons 

they gave included: The effect of GHG 

emissions is global, therefore the 

location where the GHGs are emitted is 

not important; various other GHG 

programs require corporate-level 

reporting and have mechanisms for 

handling ownership changes; the overall 

carbon footprint of a corporation is 

important; a company’s entire emissions 

should be reported, not just those 

facilities that are above a threshold; and 

facility-level data are more likely to be 

CBI. 

Response: In response to comments, 

EPA reviewed our initial views outlined 

in Sections IV.D and V of the proposal 

preamble (74 FR 16448, April 10, 2009) 

in light of our data needs under the 

CAA, our interpretation of the 

Congressional request, and the feedback 

received. Based on these considerations, 

we determined that the final rule will 

retain the same reporting level as the 

proposed rule. Facility-level reporting is 

required, with the exception of some 

supplier source categories (e.g., 

importers of fuels or industrial GHGs or 

manufacturers of motor vehicles and 

engines). If a facility is covered by the 

rule, the reporter must report the 

facility’s GHG emissions from all source 

categories for which the rule contains 

GHG emission methods. The total 

emissions for the facility are reported, as 

well as emissions broken out by source 

category within the facility. Subparts for 

some source categories specify further 

breakout of emissions by process line or 

unit. 

We retained this approach because 

the purpose of this rule is to collect data 

from suppliers and from facilities with 

direct GHG emissions above selected 

thresholds for use in analyzing, 

developing, and implementing potential 

future CAA GHG policies and programs. 

Facility-level data are needed to support 

analyses of some types of potential GHG 

reduction programs, such as NSPS. The 

data collected from facility-level 

reporting under this rule will improve 

our ability to formulate a set of climate 

change policy options and to assess 

which facilities and industries would be 

affected by the options and how they 

would be affected. (Note, we expect that 

similarly, facility-level data will also be 

useful to States, the public, and other 

stakeholders to formulate State and 

regional programs and track emission 

trends over time.) Reporting by 

individual facilities is also consistent 

with most existing air regulatory such as 

ARP, NSPS and national emission 

standards for hazardous air pollutants 

(NESHAP), and permitting programs. 

Many facility environmental managers 

are already experienced with facilitylevel emissions reporting under such 

programs and can likewise submit 

reports under the mandatory GHG 

reporting rule. 

Corporate-level reporting was not 

selected because corporate reporting 

without facility-specific details would 

not provide sufficient data to assess 

many potential CAA GHG policies and 

programs. EPA understands that some 

corporate-level GHG reporting programs 

have mechanisms to establish reporting 

responsibilities under complex and 

changing ownership situations, but we 

find corporate-level reporting overly 

complex for this rulemaking given that 

facility level data are needed, and it is 

simpler to place reporting responsibility 

directly on individual facilities. We note 

that while EPA requires facility-level 

reporting, it is up to the facility owners 

and operators to select the designated 

representative who will submit the 

report for a facility, and reporters can 

also establish any internal corporate 

review processes they deem 

appropriate. 

While EPA agrees with the 

commenters who indicated that 

information on corporate carbon 

footprints is useful for various purposes, 

collection of such information is outside 

the scope of this rulemaking. With that 

said, we are exploring options for 

adding additional data elements to the 

reports, such as name of parent 

company and NAICS code(s), to allow 

easier aggregation of facility-level data 

to the corporate level under this 

program. EPA expects to subject any 

additional requests to notice and 

comment rulemaking. In any event, we 

expect that the facility-level data 

collected under this rule will be useful 

for programs that request or require 

corporate reporting. But, as explained in 

Sections I.D and I.E of this preamble, 

this reporting rule is one action to 

respond to a specific request from 

Congress. Various other Federal and 

State programs are collecting and will 

continue to collect corporate-level data 

on direct and indirect emissions, energy 

efficiency, and other data as part of a 

broad array of climate change 

initiatives. 

For the response to the commenters’ 

concern about CBI, see Section II.R of 

this preamble. 

G. Summary of Comments and 

Responses on Initial Reporting Year and 

Best Available Monitoring Methods 

This section contains a brief summary 

of major comments and responses on 

the initial reporting year. A large 

number of comments were received 

covering numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Initial Year of 

Reporting, Duration of the Reporting 

Program, and Provisions to Cease 

Reporting.’’ 

Comment: The proposed rule 

included reporting of calendar year 

2010 emissions in March 2011, which 

would require reporters to collect data 

starting on January 1, 2010. The 

preamble to the proposed rule also 

discussed options of allowing reporting 

of best available data for 2010, or 

delaying reporting by one year (64 FR 

16471, April 10, 2009). Many industries 

with source categories covered by the 

proposed rule commented that a data 

collection start date of January 1, 2010, 


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does not provide sufficient time to 

review the final rule, purchase and 

install required monitoring equipment, 

train staff, and develop internal 

electronic data management and 

recordkeeping systems needed to 

comply with the rule. Many indicated 

that they do not currently have all the 

meters and monitoring equipment 

required by the rule. Most of these 

commenters strongly stated that 

calendar year 2011 should be the first 

reporting year. Many of them also stated 

that if EPA decides data collection must 

begin in 2010, a best available data 

approach should be allowed for 

calculating and reporting 2010 

emissions. 

Conversely, Congressional inquiries 

and a large number of public 

commenters including States, NGOs, 

and the general public, emphasized that 

data collection must start in 2010 

because time is of the essence for 

developing and implementing GHG 

policies and programs. These 

commenters urged EPA to require 

reporting of calendar year 2010 GHG 

emissions and not to delay data 

collection until calendar year 2011. 

Some of the commenters made 

suggestions about the types of data and 

methods that could be allowed if EPA 

chose to use a best available data 

approach for 2010. 

Response: EPA carefully reviewed 

input from all commenters with the goal 

of balancing the urgent need for data 

against the legitimate concerns raised 

regarding timing. As a result, we have 

revised the approach for the final rule. 

The final rule requires data collection 

for calendar year 2010, but has been 

changed since proposal to allow use of 

best available monitoring methods for 

the first quarter of 2010. 

Schedule. EPA decided to require 

reporting of calendar year 2010 

emissions because the data are crucial to 

the timely development of future GHG 

policy and regulatory programs. In the 

Appropriation Act, Congress requested 

EPA to develop this reporting program 

on an expedited schedule, and 

Congressional inquiries along with 

public comments reinforce that data 

collection for calendar year 2010 is a 

priority. Delaying data collection until 

calendar year 2011 would mean the data 

would not be received until 2012, which 

would likely be too late for many 

ongoing GHG policy and program 

development needs. 

However, EPA understands that 

because the final rule is not being 

promulgated until fall of 2009, facilities 

that do not already have the monitoring 

systems required by the rule in place 

might not have time to install and begin 

operating them by January 1, 2010. 

Under the schedule in the 

Appropriations Act, the final rule would 

have been signed at the end of June 

2009, which would have allowed 

approximately six months to prepare for 

data collection in January 2010. Given 

the delay in promulgating the rule, there 

is less time between signature of the 

rule and a January 1, 2010 start date. In 

light of this fact, and the industry 

comments indicating that facilities do 

not currently have all of the required 

monitoring systems, EPA has decided to 

provide flexibility by establishing a best 

available monitoring methods option for 

the first quarter of calendar year 2010. 

This approach will provide time 

comparable to what would have 

occurred had EPA met the schedule in 

the Congressional request. We will post 

the rule on EPA’s Web site soon after 

signature, allowing reporters to see the 

final requirements and begin 

compliance planning even before the 

rule is published in the Federal 

Register. 

For the time period of January 1 

through March 31, 2010, the rule allows 

use of best available monitoring 

methods for parameters that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

the relevant subpart. Starting no later 

than April 1, 2010, the reporter must 

begin following all applicable 

monitoring and QA/QC requirements of 

this part, unless they submit an 

extension request showing that it is not 

reasonably feasible to acquire, install, 

and operate a required piece of 

monitoring equipment by the specified 

date and EPA approves the request. EPA 

may approve such requests for a set time 

period, but will not approve the use of 

best available methods beyond 

December 31, 2010. See the paragraph 

heading ‘‘Extension Request Process’’ 

near the end of this response for further 

details. 

EPA has concluded that the time 

period allowed under this schedule 

(including the provision for facilityspecific requests) will allow facilities 

that do not currently have the required 

monitoring systems sufficient time to 

begin implementing the monitoring 

methods required by the rule. In 

general, the required monitors, such as 

flow meters, are widely available and 

are not time consuming to install. By 

allowing the additional time, many 

facilities may also be able to install the 

equipment during other planned (or 

unplanned) process unit downtime, 

thus avoiding process interruptions. 

Definition of Best Available 

Monitoring Methods. In determining 

methods that would be allowed under a 

best available monitoring methods 

approach, EPA considered the goal of 

collecting consistent data to provide 

information of sufficient quality to 

inform policy and program 

development, while recognizing that not 

all facilities may be able to implement 

the full monitoring methods required by 

the rule by January 2010. We reviewed 

the public comments as well as the 

California Air Resources Board (CARB) 

mandatory reporting rule, and we 

considered options falling between full 

flexibility to use any method and the 

full requirements of EPA’s mandatory 

reporting rule. 

The least stringent approach would be 

to allow facilities to calculate GHG 

emissions using any data, methods, 

calculation procedures, or emission 

factors they choose during the best 

available monitoring period and submit 

minimal supporting data. This approach 

would provide maximum flexibility to 

industry, but EPA did not select this 

approach because the usefulness of the 

collected data would be questionable 

given that it would be obtained using 

inconsistent methods and it could not 

be verified with sufficient confidence. 

Instead, EPA developed a hybrid 

approach that falls between full 

flexibility and implementation of full 

monitoring requirements in January 

2010. Under the final rule, during 

January 1, 2010, through March 31, 

2010, reporters may use best available 

monitoring methods for any parameter 

(e.g., fuel use, daily carbon content of 

feedstock by process line) if that 

parameter cannot reasonably be 

measured following the monitoring and 

QA/QC requirements of a relevant 

subpart. The reporter must use the 

calculation procedures and equations in 

the ‘‘Calculating GHG Emissions’’ 

sections of each relevant subpart, but 

may use the best available monitoring 

method for any parameter for which it 

is not reasonably feasible to acquire, 

install, and operate a required piece of 

monitoring equipment by January 1, 

2010. Best available monitoring 

methods include the following: 

• Monitoring methods currently used 

by the facility that do not meet the 

specifications of a relevant subpart. 

• Supplier data. 

• Engineering calculations. 

• Other company data. 

Reporters must submit an annual 

GHG report for 2010. This calendar year 

2010 report (submitted March 31, 2011) 

includes the same information as in 

subsequent years, but also requires brief 

descriptions of each best available 

monitoring method used, the parameter 

measured using that method, and the 


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time period during which the method 

was used. 

EPA selected this approach because it 

is responsive to commenters’ concerns 

that monitoring equipment cannot be 

installed by January 1, 2010, while also 

ensuring timely submission of more 

consistent and verifiable data than the 

alternatives. We have concluded that 

the data will be more consistent because 

all reporters will use the same basic 

emissions calculation equations that are 

in the rule, with best available inputs, 

rather than the wide range of calculation 

methods that would likely be used 

under a full flexibility approach. 

Furthermore, the selected approach 

requires reporting of sufficient 

information for EPA to verify the 

emissions data. We have therefore 

determined that this approach for 

collection and reporting of the calendar 

year 2010 data will fulfill the objectives 

of this reporting rule. 

It should also be noted that, like the 

proposed rule, the final rule allows 

facilities that must report only 

emissions from general stationary fuel 

combustion equipment (and do not have 

other covered source categories) to 

determine calendar year 2010 emissions 

using any of the methods (tiers) in 40 

CFR part 98, subpart C, and submit an 

abbreviated GHG report. Full reporting 

starts with calendar year 2011. This 

allows such facilities, which are less 

likely to have experience with 

emissions monitoring and reporting, an 

extra year to begin full reporting using 

all the procedures required by the rule. 

Extension Request Process. We expect 

that the vast majority of facilities will 

begin complying with the full 

monitoring requirements of the rule no 

later than April 1, 2010, and will not 

require or be granted an extension. 

However, EPA is providing facilities 

with specific circumstances an 

opportunity to request an extension in 

the use of best available monitoring 

methods. EPA will review extension 

requests to determine whether they 

should be approved. We envision that 

extensions will apply primarily to 

situations when needed monitoring 

instrumentation could not be obtained 

within the timeframe despite good faith 

efforts by the facility, or when 

installation of monitoring 

instrumentation would require a process 

unit shutdown that could not feasibly be 

scheduled prior to April 1, 2010. 

Timing. Reporters must submit 

extension requests to EPA no later than 

30 days after the effective data of the 

GHG reporting rule. EPA intends to 

review each submitted request and may 

approve or disapprove the requests. EPA 

may approve the request for a specified 

time period, but will not approve the 

use of best available methods beyond 

December 31, 2010. If EPA disapproves 

an extension request, then the reporter 

is required to implement the full 

monitoring methods required by the 

rule by April 1, 2010. 

Content of Request. Requests must 

contain the following information: 

• A list of specific monitoring 

instrumentation for which the request is 

being made and the locations where 

each piece of monitoring 

instrumentation will be installed. 

• Identification of the specific rule 

requirements (by rule subpart, section, 

and paragraph numbers) for which the 

instrumentation is needed. 

• A detailed description of the 

reasons why the needed equipment 

could not be obtained and installed 

before April 1, 2010. 

• If the reason for the extension is 

that the equipment cannot be purchased 

and delivered by April 1, 2010, include 

supporting documentation such as the 

date the monitoring equipment was 

ordered, investigation of alternative 

suppliers and the dates by which 

alternative vendors promised delivery, 

backorder notices or unexpected delays, 

descriptions of actions taken to expedite 

delivery, and the current expected date 

of delivery. 

• If the reason for the extension is 

that the equipment cannot be installed 

without a process unit shutdown, 

include supporting documentation 

demonstrating that it is not possible to 

isolate the equipment, piping, or line 

and install the monitoring instrument 

without a full process unit shutdown. 

Also include the date of the most recent 

process unit shutdown, the frequency of 

shutdowns for this process unit, and the 

date of the next planned shutdown 

during which the monitoring equipment 

can be installed. If there has been a 

shutdown or if there is a planned 

process unit shutdown between 

promulgation of this rule and April 1, 

2010, include a justification of why the 

equipment could not be obtained and 

installed during that shutdown. 

• A description of the specific actions 

the facility will take to obtain and 

install the equipment as soon as 

reasonably feasible and the expected 

date by which the equipment will be 

installed and operating. 

Approval Criteria. EPA will approve a 

request if it contains all of the 

information required by the rule and if 

it demonstrates to the Administrator’s 

satisfaction that it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by April 1, 2010. 

For example, EPA is likely to approve 

a request for an extension if the 

documentation provided by the reporter 

shows that they ordered monitoring 

equipment in a timely manner, 

attempted to find a supplier who could 

deliver it in time, and could not control 

the fact that the equipment was not 

received for installation prior to April 1, 

2010. 

If a reporter requests an extension 

because equipment cannot be installed 

without a process unit shutdown, EPA 

is likely to approve such a request if the 

documentation clearly demonstrates 

why it is not feasible to install the 

equipment without a process unit 

shutdown, shows there is not a planned 

shutdown (and has not been a 

shutdown) prior to April 1, 2010, during 

which the monitoring instrument could 

be installed. There are many locations 

where monitors can be installed without 

a process unit shutdown, because there 

is often some redundancy in process or 

combustion equipment or in the piping 

that conveys fuels, raw materials and 

products. For example, many facilities 

have multiple combustion units and 

fuel feed lines such that when one 

combustion unit is not operating they 

can obtain the needed steam, heat, or 

emissions destruction by using other 

combustion devices. Some facilities 

have multiple process lines that can 

operate independently, so one line can 

be temporarily shut down to install 

monitors while the facility continues to 

make the same product in other process 

lines to maintain production goals. If a 

monitor needs to be installed in a 

section of piping or ductwork, it can be 

possible in some cases to isolate a line 

without shutting down the process unit 

(depending on the process 

configuration, mode of operation, 

storage capacity, etc.). If the line or 

equipment location where a monitor 

needs to be installed can be temporarily 

isolated and the monitor can be 

installed without a full process unit 

shutdown, it is less likely EPA will 

approve an extension request. 

While there might be other unique 

facility-specific situations for which an 

extension might be granted, EPA 

expects few of these. There have been 

several changes to the rule since 

proposal that would reduce the need for 

extensions. For example, fewer source 

categories are included in the final rule; 

changes have been made to the 

monitoring requirements of some rule 

subparts to allow more flexibility in 

monitoring methods; and provisions 

have been added to the general 

stationary fuel combustion, petroleum 

refineries, and petrochemical 

productions subparts allowing facilities 


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17Applicability thresholds for different source 

categories are expressed in different ways (e.g., 

actual emissions, production capacity, ‘‘all-in’’), but 

most correspond to a facility-wide emission level of 

25,000 metric tons per year. The provision to cease 

reporting applies to reporters regardless of the 

specific applicability threshold that triggered 

reporting for their facility or supply operation. 

additional time to perform some 

monitor calibrations. These changes 

address many of the specific situations 

about which commenters raised 

concerns. 

It is highly unlikely we would 

approve extension requests for 

parameters that are measured by 

periodic sampling and analyses. 

Facilities should be able to make 

arrangements to collect periodic 

samples and send them off-site for 

analyses (if they don’t have on-site 

analytical capabilities) without the need 

for an extension. Similarly, extensions 

for design of electronic recordkeeping 

systems seem unnecessary. Many 

facilities already have electronic 

recordkeeping systems that can be 

altered to keep the records needed for 

this rule. Furthermore, reporters can 

keep the specified records in any type 

of hard copy or electronic format they 

choose, as long as it is in a form suitable 

for expeditious inspection and review. 

H. Summary of Comments and 

Responses on Frequency of Reporting 

and Provisions To Cease Reporting 

This section contains a brief summary 

of major comments and responses on 

the frequency of reporting and on 

whether reporters should be allowed to 

stop submitting annual reports if 

emissions are reduced below a 

threshold level. A large number of 

comments were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Initial Year of 

Reporting, Duration of the Reporting 

Program, and Provisions to Cease 

Reporting’’ and ‘‘Mandatory Greenhouse 

Gas Reporting Rule: EPA’s Response to 

Public Comments, Subpart A: 

Applicability and Reporting Schedule.’’ 

1. Provisions To Cease Reporting if 

Emissions Decrease 

Comment: The majority of public 

commenters favored annual reporting as 

opposed to more or less frequent 

reporting. Many commenters, especially 

industrial facilities required to report 

under the rule, objected to the ‘‘once in 

always in’’ reporting approach in the 

proposed rule and requested a 

mechanism to stop reporting if 

emissions fall below the 25,000 metric 

tons CO2e per year annual threshold. 

Others suggested a level different from 

25,000 metric tons CO2e per year to 

cease reporting. Some commented that 

the lack of such a mechanism is a 

disincentive to reduce facility 

emissions. Conversely, other 

commenters supported the proposed 

once in always in approach in order to 

create a consistent, long term data set 

covering the same population of 

facilities over time that could be used to 

track trends and understand factors that 

influence emission levels. 

Response: After reviewing the 

comments, EPA has not changed the 

frequency of reporting since the 

proposed rule. Affected facilities and 

suppliers must submit annual GHG 

reports. Facilities with ARP units that 

report CO2 emissions data to EPA on a 

quarterly basis would continue to 

submit quarterly reports as required by 

40 CFR part 75, in addition to providing 

the annual GHG reports. We have 

determined that annual reporting is 

sufficient for policy and regulatory 

development. It is also consistent with 

other existing mandatory and voluntary 

GHG reporting programs at the State and 

Federal levels (e.g., The Climate 

Registry (TCR), several individual State 

mandatory GHG reporting rules, EPA 

voluntary partnership programs, the 

DOE voluntary GHG registry). 

In response to comments on ‘‘once in, 

always in,’’ however, EPA has added 

provisions to allow facilities and 

suppliers to stop submitting annual 

reports under certain conditions. These 

provisions apply to facilities and 

suppliers regardless of their 

applicability threshold as it is based on 

the annual report. 

• Under the first provision, if any 

facility’s annual GHG reports 

demonstrate emissions of less than 

25,000 metric tons of CO2e per year for 

five consecutive years, they can cease 

submitting annual reports. Similarly, if 

any supplier’s annual reports 

demonstrate that the products supplied 

equate to less than 25,000 metric tons of 

CO2e per year for five consecutive years, 

they can cease submitting annual 

reports. 

• Under the second provision, if any 

facility’s or supplier’s annual GHG 

reports demonstrate emissions of less 

than 15,000 metric tons CO2e per year 

for three consecutive years, they can 

cease submitting annual reports. 

In either case, before they can stop 

reporting, the facility or supplier must 

submit a notification to EPA that 

announces the cessation of reporting 

and explains the reasons for the 

reduction in emissions so EPA can 

understand the reason for the decrease 

in emissions to help aid in evaluating 

emission reduction options across the 

industry. 

If emissions subsequently increase to 

25,000 metric tons of CO2e or more in 

any calendar year, the facility or 

supplier must again begin annual 

reporting. Importantly, although a 

source may not know its emissions (or 

quantities supplied) exceeded the 

reporting threshold until later in the 

year, the requirements of the rule apply 

as of January 1, unless the increase is a 

result of a physical or operational 

change covered by 40 CFR 98.3(b). Thus 

sources close to the threshold should 

consider monitoring their emissions 

according to requirements of 40 CFR 

part 98 if they determine there is a 

chance they will meet or exceed the 

threshold. EPA is developing tools and 

guidance to assist facilities and 

suppliers in assessing whether the 

requirements of the rule apply to them. 

EPA concluded that adding the 

provisions to allow cessation of 

reporting balances the need for a 

complete dataset with the burden of 

continued annual reporting by facilities 

where there has been a change that has 

consistently reduced emissions (or 

supplier quantities) below 25,000 metric 

tons CO2e. This approach rewards 

actions taken to reduce emissions and 

reduces the reporting burden. It is 

consistent with other reporting 

programs, such as the CARB mandatory 

reporting rule and the WCI program, 

both of which have mechanisms to 

allow facilities to cease reporting if their 

emissions are below a specified 

threshold for multiple consecutive 

years. 

For the first provision, EPA selected 

25,000 metric tons CO2e per year 

because it is the same as the general 

applicability threshold for this rule.17

We selected a 5-year period, instead of 

a shorter time frame, because it allows 

reporters that consistently report less 

than 25,000 metric tons CO2e to stop 

reporting, but avoids the situation 

where a facility or supplier near this 

level would be constantly moving in 

and out of the reporting program due to 

small variations from one year to the 

next. Because this reporting rule is 

based on actual rather than potential 

emissions, such a situation would make 

tracking of facilities and analyses of 

trends difficult. 

The second provision (cease reporting 

if emissions were below 15,000 metric 

tons for three consecutive years) was 

added to reduce the duration of 

reporting for facilities and suppliers that 

reduce emissions to well below 25,000 

metric tons. In such cases, a 5-year 

period is longer than necessary to 


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demonstrate that annual emissions will 

remain below 25,000 metric tons per 

year. If emissions are less than 15,000 

metric tons for three consecutive years, 

it is unlikely that annual variation in 

emissions would cause the facility or 

supplier to exceed the threshold of 

25,000 metric tons per year. The shorter 

time period provides an incentive for 

facilities that significantly reduce their 

GHG emissions. 

2. Provisions To Cease Reporting Due to 

Closures 

Comment: Several commenters 

suggested that EPA add a provision to 

allow closed facilities, or facilities or 

suppliers that stop operating their GHGemitting processes, to cease annual 

reporting. 

Response: In response to comments, 

EPA has added a mechanism to allow 

facilities or suppliers that close all of 

their GHG-emitting processes or 

operations covered by the rule to cease 

annual reporting. The reporter must 

submit an annual report covering the 

calendar year during which the closure 

occurs. The reporter must also notify 

EPA that they intend to cease reporting 

and must certify that all GHG-emitting 

processes and operations for which 

there are methods in the rule have been 

closed. EPA agrees that it does not make 

sense for closed facilities or facilities 

that close all of their GHG-emitting 

processes to continue reporting 

indefinitely or for the 5-year period 

needed to demonstrate that emissions 

are less than 25,000 metric tons CO2e 

per year (or the 3-year period needed to 

demonstrate emissions are less than 

15,000 metric tons CO2e per year). 

However, notification is required so that 

we can track facilities and understand 

why facilities stop reporting. If a facility 

or supplier that was once subject to the 

reporting rule and ceased reporting 

under this provision restarts any of the 

GHG-emitting processes or operations 

formerly reported, then they must 

resume annual reporting regardless of 

whether they exceed the thresholds in 

40 CFR 98.2(a) when they restart. This 

provision is important so that EPA can 

consistently track emissions from 

facilities covered by the rule. If after the 

restart, annual reports show emissions 

of less than 25,000 metric tons CO2e per 

year for five consecutive calendar years 

or less than 15,000 metric tons CO2e per 

year for three consecutive years, then 

the facility could be exempt under the 

separate mechanism discussed in 

Section II.H.1 of this preamble. 

It is important to note that the 

provision to stop reporting is not 

intended to apply to seasonal or longer 

temporary cessation of operation. The 

mechanism is intended for long-term 

closure situations. It should also be 

noted that in order to use this provision 

to cease reporting, a facility or supplier 

must close all of their processes and 

operations that are required to report 

emissions. For example, consider a 

facility that is required to report process 

emissions from one or more source 

categories covered by 40 CFR part 98 

and general stationary fuel combustion 

source emissions. If the facility closes 

some of the process units subject to the 

rule but continues to operate other 

process units covered by the rule or 

continues to operate stationary fuel 

combustion sources, then they must 

continue to submit annual reports until 

the required annual GHG reports 

demonstrate emissions of less than 

25,000 metric tons of CO2e per year for 

five consecutive years (or less than 

15,000 metric tons of CO2e per year for 

three consecutive years) and the facility 

qualifies for the separate provisions to 

stop reporting discussed in Section 

II.H.1 of this preamble. 

I. Summary of Comments and 

Responses on General Content of the 

Annual GHG Report 

This section contains a brief summary 

of major comments and responses on 

the emissions information to be reported 

under the general provisions (40 CFR 

part 98, subpart A). See sections III.C 

through PP of this preamble for 

summaries of comments and responses 

on specific reporting requirements for 

the individual source categories 

contained in 40 CFR part 98, subparts C 

through PP. A large number of 

comments on emission information to 

report under the general provisions 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart A: Content of the 

Annual Report, the Abbreviated 

Emission Report, Recordkeeping, and 

Monitoring Plan.’’ 

Comment: EPA received a variety of 

comments on the general content of the 

annual GHG reports. Some commenters 

objected to the level of detail required 

in the annual GHG reports. Some 

suggested reporting only facility-level 

emissions and keeping as records more 

detailed emissions breakouts (e.g., by 

source category, process line, or unit) 

and activity data used to calculate 

emissions. Other commenters supported 

the proposed general reporting 

requirements. 

Response: After reviewing the 

comments, we have not made any major 

changes in the general content of the 

annual GHG reports since proposal. The 

final rule requires facilities to report 

emissions from all source categories at 

the facility for which methods are 

defined in the rule. The General 

Provisions (40 CFR part 98, subpart A) 

require facilities to report total annual 

GHG emissions in metric tons CO2e and 

to separately present annual mass 

emissions of each individual GHG 

emitted from each source category at the 

facility. Reporting of CO2e allows a 

comparison of total GHG emissions 

across facilities in varying categories 

which emit different GHGs. Knowledge 

of both individual gases emitted and 

total CO2e emissions maintains 

transparency, is valuable for future 

policy and regulatory development, and 

will help EPA quantify the relative 

contribution of each gas to a source 

category’s emissions and maintain 

transparency. 

Individual rule subparts for each 

source category, rather than the General 

Provisions, identify the specific data 

elements to be reported for that source 

category. Comments received on the 

need for specific data elements are 

described and responded to in Section 

III of this preamble and in relevant 

source category volumes of the 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments’’. Where appropriate, the 

final rule has been modified based on 

those comments. In general, reporting of 

such data is required primarily to enable 

emissions verification and ensure the 

consistency and accuracy of data 

collected under this rule. The 

information is also needed to support 

analyses of GHG emissions for future 

CAA policy and program development. 

Besides total facility emissions, it 

benefits policy makers to understand: 

(1) The specific sources of emissions 

and the amounts emitted by each unit/ 

process to effectively interpret the data, 

and (2) the effect of different processes, 

fuels, and feedstocks on emissions. 

Many of these data are already routinely 

monitored and recorded by facilities for 

business reasons. Further discussion of 

the selection of general reporting 

requirements is contained in Section 

IV.G of the proposal preamble (74 FR 

16472, April 10, 2009). Other responses 

to comments on the reporting 

requirements in 40 CFR Part 98, Subpart 

A, and discussion of some clarifications 

made to the rule, are contained in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart A: Applicability 

and Reporting Schedule’’, ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 


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A: Content of the Annual Report, the 

Abbreviated Emission Report, 

Recordkeeping, and Monitoring Plan’’, 

and ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart A: 

Definitions, Incorporation by Reference, 

and Other Subpart A Comments’’. 

J. Summary of Comments and 

Responses on Submittal Date and 

Making Corrections to Annual Reports 

1. Submittal Date for Annual Report 

Comment: Several commenters 

requested that EPA change the annual 

submittal date for GHG reports from 

March 31 to a later date, such as April 

30 or June 30. Several commenters 

stated that March 31 does not provide 

adequate time for data collection, 

aggregation and disaggregation, GHG 

calculations, QA, management review, 

and certification, and explained that 

this is a complex process for large 

industrial sites that have many 

individual GHG emission sources. Some 

of these commenters indicated that 

unexpected issues can arise during GHG 

emissions calculations and QA that take 

time to resolve. Some of these 

commenters suggested a date of June 30 

to align this mandatory reporting rule 

with the submittal dates for other 

reporting programs such as California 

Climate Action Registry (CCAR), TCR, 

Climate Leaders, and Toxic Release 

Inventory (TRI). Some commented that 

the same personnel who will prepare 

the GHG reports are also involved in 

preparing other EPA mandated reports 

and that completing multiple reporting 

activities in the first quarter is a large 

workload. Other commenters favored 

the March 31 reporting date so that the 

data could be disseminated and 

available for use by policy makers, EPA, 

States, and the public in a timely 

fashion. 

Response: After reviewing and 

addressing both general comments and 

comments received on this issue for 

specific source categories, and 

considering the need to balance prompt 

reporting with the burden on reporters, 

EPA has determined that the reporting 

deadline of March 31 allows a sufficient 

amount of time for compiling, 

reviewing, certifying, and submitting 

annual GHG reports. The March 

deadline will ensure timely collection of 

the data necessary to inform decisions 

regarding future GHG policy and 

program development. Since the data 

needed to calculate emissions and 

prepare the report must be collected on 

an ongoing basis throughout the year, 

reporters can begin to compile the data 

for the report and initiate QA activities 

during the year as the data are collected. 

Reporters would then only have to 

compile the most recently collected 

information, complete the final 

calculations, and review and certify the 

annual report after the reporting period 

has ended. Because the reports required 

by the rule rely on well-defined 

calculation methodologies, EPA 

determined that three months is a 

sufficient amount of time to complete 

the report. Moreover, as discussed in 

Section III of this preamble for the 

specific subparts, we have made several 

changes to reporting requirements that 

will ease burden and further facilitate 

reporting by March 31. In addition, EPA 

intends to provide outreach and training 

on rule requirements and an electronic 

reporting system that will help expedite 

report submission. 

The March 31 reporting deadline is 

also consistent with the reporting 

deadline implemented in 2005 for 

reporting GHG emissions under the EU 

Emissions Trading System and is longer 

than the deadlines allowed for reporting 

under many other CAA programs. For 

example, many NESHAPs and NSPSs, 

including those for large complex 

industrial facilities such as chemical 

plants and refineries, require reports of 

excess emissions and monitoring system 

performance to be submitted within 30 

calendar days of the end of each 

compliance period. The ARP and 

Regional Greenhouse Gas Initiative 

(RGGI) programs, which are established 

emission cap and trade programs that 

rely on the same types of data many 

sources will have to submit under the 

GHG reporting rule, require facilities to 

submit their quarterly emissions reports 

within 30 days of the end of each 

quarter. 

2. Making Corrections to Annual 

Reports 

Comment: Several commenters 

representing multiple stakeholders 

suggested the rule should include 

provisions to submit revised annual 

reports. Many commented that even 

with good-faith efforts to follow all the 

monitoring and reporting requirements, 

there will likely be unintentional errors 

that are not discovered by the reporter 

or by EPA until after an annual report 

is submitted. Some commenters added 

that given the stringency of the selfcertification provisions and potential 

penalties involved, reporters need a way 

to submit corrected data, and some 

provided examples of other reporting 

rules that include provisions to submit 

revised reports. 

Response: EPA has addressed this 

comment in the final rule. We have 

added a provision in 40 CFR 98.3 that 

requires the reporters to submit a 

revised GHG report within 45 days of 

discovering or being notified by EPA of 

errors in an annual GHG report. The 

revised report must correct all identified 

errors. We agree that it is important for 

facilities to correct errors, regardless of 

whether they are discovered by the 

reporter or by EPA. In order to ensure 

accurate data for future GHG policies 

and programs, known errors should be 

corrected. Furthermore, adding a 

requirement to submit corrected reports 

is consistent with other EPA reporting 

programs, such as ARP and TRI, as well 

as State and other GHG programs. EPA 

intends to review the annual GHG 

reports submitted under this rule by 

performing electronic data QA checks 

and a range of other emission 

verification activities. When we find 

reporting errors (as we have in ARP and 

other reporting programs), we will 

notify reporters of errors and require 

them to submit revised reports. The 

time period of 45 days was selected to 

allow reporters time to retrieve any 

needed data, perform revised 

calculations, and resubmit the report. 

Because data for the calendar year 

covered by the report has already been 

collected and must be retained 

according to the rule, it should be 

readily available for any reanalyses 

needed to correct a reporting error. 

Given that facilities are allowed three 

months from the end of a reporting 

period to submit the annual report, 

revising a report to address a known 

error would logically require less time 

and EPA concluded that 45 days is 

sufficient. 

K. Summary of Comments and 

Responses on De Minimis Reporting 

Comment: Some commenters 

suggested that de minimis cutoffs or 

simplified methods for de minimis 

sources should be provided to be 

consistent with other programs, such as 

the California mandatory GHG reporting 

rule. The commenters argued that it 

makes sense to focus effort on the 

significant emissions sources at a 

facility, rather than spending a lot of 

effort to precisely calculate emissions 

from sources that are a small percent of 

a facility’s total emissions. 

Response: EPA considered public 

comments on de minimis reporting, 

both general comments and those 

received on individual source 

categories, in addition to the analyses of 

de minimis provisions we conducted at 

proposal of the rule. Based on these 

considerations, we concluded that de 

minimis provisions are not necessary for 

this rule. 


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18For additional information about these 

programs please see overview of existing programs 

(EPA–HQ–OAR–2008–0508–0052) and the de 

minimis memo (EPA–HQ–OAR–2008–0508–0048). 

As discussed in the preamble to the 

proposal (74 FR 16448, April 10, 2009), 

many existing reporting programs 

require corporate level reporting of all 

emissions, including emissions from 

numerous remote facilities and small 

onsite equipment (e.g., lawn mowers). 

Other reporting programs require 

reporting at the facility level but require 

reporting of emissions from all types of 

emission sources.18 These reporting 

programs recognize that it may not be 

possible or efficient to specify the 

reporting methods for every source that 

must be reported and include de 

minimis provisions to reduce the 

reporting burden. The de minimis 

provisions included in these programs 

either allow the reporter to exclude a 

portion of their emissions (e.g., the DOE 

1605(b) voluntary reporting program 

allows up to three percent of facilitylevel emissions to be excluded) or allow 

simplified calculation methods for small 

sources. 

Since reporters must determine the de 

minimis emissions even when reporting 

is not required, the trend for both 

mandatory and voluntary reporting 

programs is to require reporting of all 

emissions but allow simplified 

calculation methods for small sources of 

emissions. Hence, the de minimis 

provisions included in many existing 

reporting programs are designed to 

avoid potentially unreasonable 

reporting burdens. For example, TCR 

allows reporters to use simplified 

calculation methods of their own design 

for calculating up to five percent of their 

emissions. Some programs recognize 

that a small percentage of emissions 

may still represent a large mass of 

emissions. For this reason, some 

existing reporting programs include a 

cap on the mass of de minimis 

emissions. For example, both the 

California mandatory reporting rule and 

EU Emissions Trading System cap de 

minimis emissions at 20,000 metric tons 

CO2e/year cap. For additional 

information on the treatment of de 

minimis in existing GHG reporting 

programs, please refer to the ‘‘Reporting 

Methods for Small Emission Points (De 

Minimis Reporting)’’ (EPA–HQ–OAR– 

2008–0508–0048). 

In contrast to such existing programs, 

this rule already avoids burdensome 

reporting requirements for smaller 

emissions sources in two ways. First, 

the rule excludes small facilities 

through the application of the 25,000 

metric tons of CO2e threshold. As 

described earlier in this preamble, that 

threshold appropriately balances the 

number and size of reporter with the 

coverage of emissions. The source 

categories included in the rule are 

typically for larger sources of emissions. 

Second, reporters must report only the 

emissions from sources for which 

calculation methods are provided in the 

rule. Calculation methods are generally 

not included for smaller sources of 

emissions (e.g., coal piles on industrial 

sites). In some cases, where a source 

category includes relatively small 

sources, the rule provides simplified 

emissions calculation methods for those 

sources. For example, reporters may use 

a default emission factor and heat rate 

to calculate emissions from small 

stationary combustion units, rather than 

the fuel measurements required for 

larger stationary combustion units. 

Given that this rule has taken steps to 

avoid burdensome calculations, we have 

concluded that de minimis reporting 

cutoffs are not necessary. 

Furthermore, de minimis cutoffs 

would compromise the quality of the 

data collected. The goal of this rule is 

to collect accurate and consistent data of 

sufficient quality to inform future CAA 

policy and regulatory decisions. 

Allowing sources to report up to 20,000 

metric tons CO2e emissions annually 

using their own simplified calculation 

methods (as allowed under some 

programs) would impact the usefulness 

of the data. The reported emissions 

would not be comparable across a given 

industry because the calculation 

methods, accuracy and reliability of a 

portion of the reported emissions would 

vary substantially from one reporter to 

another. 

In response to comments, we have 

made several changes to this rule that 

further reduce any need for a de 

minimis reporting provision. As 

discussed in Section III of this preamble 

for individual source categories, we 

have revised monitoring and reporting 

requirements to allow simpler GHG 

calculation methods for many 

combustion units and other source 

categories. These changes reduce the 

reporting burden for various types of 

small emission sources. Also, as noted 

earlier in Section II.D of this preamble, 

there are a number of source categories 

that are not being finalized at this time. 

A few of them (e.g., industrial landfills 

and wastewater) represent the type of 

emission sources that commenters 

referenced as de minimis at some 

facilities. EPA is taking some additional 

time with these source categories, which 

affects commenters in two ways: (1) 

Until EPA promulgates a final rule for 

these source categories, these emissions 

would not be included in a facility’s 

annual report and (2) EPA can further 

consider the comments and evaluate our 

options with respect to the methods for 

these source categories to ensure the 

methods adequately address our need 

for high quality data as well as 

recognize the commenters’ requests for 

additional flexibility for smaller 

sources. 

L. Summary of Comments and 

Responses on General Monitoring 

Approach 

This section contains a brief summary 

of major comments and responses on 

general monitoring requirements. See 

sections III.C through PP of this 

preamble for summaries of comments 

and responses on specific monitoring 

requirements for the individual source 

categories contained in 40 CFR part 98, 

subparts C through PP. A large number 

of comments were received on general 

monitoring requirements covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, General Montoring 

Approach, the Need for Detailed 

Reporting, and Other General Rationale 

Comments.’’ 

Comment: Many commenters favored 

the general monitoring approach 

contained in the proposed rule, which 

is a combination of direct emissions 

measurement and facility-specific 

calculations. These commenters agreed 

that the selected approach results in 

high quality data and strikes a 

reasonable balance between data 

accuracy and cost. Other commenters 

believed that the approach contained in 

the proposed rule is overly stringent and 

costly. They contended that since the 

data are not being used to demonstrate 

compliance with a cap and trade 

program or other regulation with 

emission limits or emissions reduction 

requirements, a lower level of accuracy 

is acceptable, simpler monitoring 

approaches should be allowed, and/or 

facilities should have flexibility to 

choose monitoring methods. Some 

commenters requested clarification on 

whether there were accuracy 

requirements or performance standards 

for flow monitoring equipment, outside 

of the accuracy requirements already 

required for CEMS. Some commenters 

requested clarification on whether 

upgrades to CEMS were needed under 

various circumstances. Some requested 

additional time for upgrading CEMS or 

installing and calibrating other 

equipment such as flow meters. 

Response: After reviewing the 

comments in light of the analysis 


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presented in Section IV.H of the 

preamble to the proposed rule (74 FR 

16474, April 10, 2009), EPA decided not 

to change the general monitoring 

approach from the proposal. In general, 

the rule requires direct measurement of 

emissions from certain units that 

already are required to collect and 

report data using CEMS under other 

programs (e.g., ARP, NSPS, NESHAP, 

State Implementation Plans (SIPs)). In 

some cases, this may require upgrading 

existing CEMS that currently monitor 

criteria pollutants to also monitor CO2

or add a volumetric flow meter. For 

facilities with units that do not have 

CEMS installed, reporters have the 

choice to either install and operate 

CEMS to directly measure emissions or 

to use facility-specific GHG calculation 

methods. The measurement and 

calculation methods for each source 

category are specified in each subpart. 

As policies and programs evolve and/or 

particular calculation or monitoring 

equipment improves EPA will evaluate 

whether or not to update the 

methodologies in this rule. 

The data collected by the rule are 

expected to be used in analyzing and 

developing a range of potential CAA 

GHG policies and programs. A 

consistent and accurate data set is 

crucial to serve this intended purpose. 

Therefore, the selected monitoring 

approach that combines direct 

measurement and facility-specific 

calculations is warranted even though 

the rule does not contain any emissions 

limits or emissions reduction 

requirements. EPA remains convinced 

that this approach strikes an appropriate 

balance between data accuracy and cost. 

It makes use of existing data and 

methodologies to the extent feasible, 

and avoids the cost of installing and 

operating CEMS at numerous facilities. 

It is consistent with the types of 

methods contained in other GHG 

reporting programs (e.g., the California 

mandatory reporting rule, WCI, RGGI, 

TCR, and Climate Leaders). Because this 

option specifies methods for each 

source category, it will result in data 

that are comparable across facilities. 

EPA chose not to adopt simplified 

calculation methods as a general 

monitoring approach (e.g., using default 

emission factors) because the data 

would be less accurate than under the 

selected option and would not make use 

of site-specific data that many facilities 

already have available and refined 

calculation approaches that many 

facilities are already using. EPA is not 

allowing reporters full flexibility to use 

any method because the accuracy and 

reliability of the data would be 

unknown. Because consistent methods 

would not be used under such an 

approach, the reported data would not 

be comparable across similar facilities. 

While the general approach is 

unchanged, it is important to note that 

EPA has made changes to the General 

Provisions and to the specific 

monitoring requirements for particular 

source categories in response to public 

comments on the proposal. EPA has 

added to the General Provisions (40 CFR 

part 98, subpart A) an accuracy 

specification of plus or minus five 

percent for the calibration of flow 

meters used to collect data for the 

emissions calculations under this rule. 

It provides procedures for calculating 

calibration error, including specific 

procedures for orifice, nozzle, and 

venturi flow meters. Given the 

comments that were submitted 

regarding concerns on the timing of 

performing meter calibration, EPA is 

providing flexibility to reporters subject 

to certain operational limitations. For 

example, facilities that operate 

continuously may postpone calibration 

until the next scheduled maintenance 

outage to avoid operational disruptions. 

Individual rule subparts for each 

source category, rather than the General 

Provisions, contain the specific 

monitoring methods for that source 

category. Comments received on the 

specific methods are described and 

responded to in Section III of this 

preamble and in the relevant source 

category volumes of ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments.’’ Where 

appropriate, the final rule has been 

modified based on those comments. For 

example, since proposal, in response to 

public comments, EPA has made 

changes to individual subparts of 40 

CFR part 98 to clarify when CEMS and 

CEMS upgrades are required and has 

made other changes to reduce the 

monitoring burden. Interested parties 

are encouraged to review the relevant 

sections of the preamble and rule. 

Furthermore, some subparts for which 

significant monitoring approach 

comments were received are not 

included in the final rule and will be 

finalized later as explained in Section 

II.D of this preamble. These changes to 

the rule address monitoring approach 

concerns raised by some commenters. 

Comment: Some commenters 

expressed concern that duplicative 

reporting would occur if the rule was 

interpreted to require a reporter to 

submit data on general stationary fuel 

combustion emissions at a facility both 

under 40 CFR part 98, subpart C and 

also under one of the other source 

category subparts that applies to the 

same facility. Some of them indicated 

that language used in the source 

category subparts to reference subpart C 

was not sufficiently clear and 

consistent. Other commenters indicated 

the proposed rule was not clear about 

whether CEMS can be used to report 

combustion emissions, process CO2

emissions, or combined emissions. 

Response: EPA reviewed each subpart 

in light of these comments and 

acknowledges that the proposed rule 

language referencing 40 CFR part 98 

subpart C and the language discussing 

the of CEMS was inconsistent between 

subparts and was not always clear. EPA 

has revised the final rule to clarify our 

intent. 

As indicated by the commenters, 

many manufacturing facilities are 

subject to one of the source category 

subparts and also to the general 

stationary fuel combustion subpart. For 

most facilities, emissions from 

stationary fuel combustion sources (e.g., 

boilers or engines) are emitted from 

separate equipment and through 

separate stacks/emission points than 

process GHG emissions covered by 40 

CFR part 98, subparts E through GG. We 

have edited the rule to make it clear that 

in such cases, the reporter would report 

stationary fuel combustion emissions 

under 40 CFR part 98, subpart C, and 

they would report process GHG 

emissions under each applicable source 

category subpart. 

We have further clarified those source 

category subparts that require reporting 

of process CO2 emissions. We have 

made it clear that the reporter can elect 

to monitor and report process CO2

emissions by either: (1) Installing and 

operating CEMS and following the Tier 

4 methodology in 40 CFR part 98, 

subpart C, or (2) using the source 

category-specific monitoring and 

calculation procedure specified in the 

subpart. In either case, process CO2

emissions would be reported under the 

source category subpart. The source 

category subparts have also been revised 

to specify that if process CO2 emissions 

are comingled with and emitted through 

the same stack as emissions from 

combustion units or process equipment 

required to use CEMS, than the reporter 

must use the CEMS and follow the Tier 

4 methodology to report combined 

emissions from the common stack under 

the specified subpart. This approach 

makes sense for comingled emissions 

because CEMS accurately measure total 

stack CO2 emissions and the reporter 

would not be able to accurately separate 

the fraction of the CO2 emissions that 

came from the combustion units and 

process emission points that are 

comingled in the same stack. 


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19As described earlier in this section, facilities or 

suppliers that have emissions or products with 

emission less than 25,000 metric tons CO2e for five 

years in a row may cease reporting. Those that cease 

reporting must have records to cover those five 

years of emissions. Similarly, reporters who 

demonstrate emissions less than 15,000 metric CO2e 

for three years is a row may cease reporting, and 

must have records to cover those three years of 

emissions. 

Source categories with direct-fired 

equipment (e.g., kilns, furnaces) present 

a special situation. Examples include 

cement production, glass production, 

lead production, lime manufacturing, 

and soda ash manufacturing. In directfired units, fuel combustion emissions 

and process emissions are both 

generated within the kiln or furnace and 

are always emitted together. If CEMS are 

used on such units, the CEMS will 

always be measuring combined 

combustion and process emissions. The 

language regarding CO2 reporting and 

use of CEMS for these source categories 

has been clarified and harmonized to 

reflect this situation. 

• For kilns or furnaces in these source 

categories that have CEMS in place and 

meet specified conditions, the reporter 

must use the CEMS and follow Tier 4 

methodology to determine combined 

process and combustion CO2 emissions. 

The combined emissions are reported 

under the relevant source category 

subpart (e.g., for cement production, 

combined combustion and process 

emissions from a kiln with a CEMS 

would be reported under 40 CFR part 

98, subpart H, Cement Production). 

• For other kilns or furnaces in these 

source categories, the reporter has the 

choice to (1) install and operate CEMS 

to measure combined process and 

combustion CO2 emissions, or (2) 

calculate process CO2 emissions using 

the source category-specific monitoring 

and calculation procedures contained in 

the subpart. If reporters don’t have 

CEMS and choose the source categoryspecific calculation approach, then they 

report process CO2 emissions under the 

relevant source category subpart, and 

report combustion emissions under 40 

CFR part 98, subpart C (general 

stationary fuel combustion). 

See the sections for the relevant 

source categories in Section III of this 

preamble for summary and discussion 

of the specific monitoring and reporting 

requirements for each source category. 

M. Summary of Comments and 

Responses on General Recordkeeping 

Requirements 

This section contains a brief summary 

of major comments and responses on 

the general recordkeeping requirements 

contained in the general provisions (40 

CFR part 98, subpart A). See sections 

III.C through PP of this preamble for 

summaries of comments and responses 

on specific recordkeeping requirements 

for the individual source categories 

contained in 40 CFR part 98, subparts C 

through PP. A large number of 

comments were received on general 

recordkeeping requirements covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart A, Content of 

the Annual Report, the Abbreviated 

Emission Report, Recordkeeping, and 

the Monitoring Plan’’ and in the 

individual source category volumes of 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments.’’ 

1. Record Retention 

Comment: Several commenters 

suggested that EPA require retention of 

records for three years rather than the 

five years specified in the proposed 

rule. Some of these commenters stated 

that three years is consistent with ARP, 

which is a comparable program that 

requires electronic reporting of similar, 

detailed data. Many contended that 

retaining the large amount of data 

required by this rule for five years rather 

than three years is overly burdensome 

and is not necessary. They indicated 

that three years of records is sufficient 

to allow verification of annual GHG 

reports. A smaller number of 

commenters supported record retention 

for five years, which is consistent with 

permitting and other programs. 

Response: In response to public 

comments, EPA has changed the record 

retention requirement in the final rule 

from five years to three years.19 We 

agree that a 3-year time period is 

sufficient to allow for EPA audit and 

review of records needed to verify the 

emissions data submitted in annual 

reports. Changing the record retention 

duration to three years will reduce the 

recordkeeping burden for many 

facilities reporting under this rule. As 

stated by various commenters, a 3-year 

record retention requirement would be 

consistent with the recordkeeping 

provisions of the ARP and other Federal 

reporting programs, including the TRI 

rules and the DOE Energy Information 

Administration’s 1605(b) Voluntary 

Reporting of GHG Emission and 

Reductions program. 

2. Monitoring Plan 

Comment: We received several 

comments on the QAPP recordkeeping 

requirement in proposed 40 CFR 98.3(g). 

Some had questions about the content 

and level of detail required in the 

QAPP, and indicated it would be a 

costly and burdensome requirement. 

Others stated that the QAPP would be 

duplicative of their facility SOPs or 

documentation kept under ARP or other 

programs. Some commenters indicated 

that the list of items to report in 40 CFR 

98.3(g) was repetitive because a few of 

the items listed separately would 

typically be contained in a QAPP. 

Response: The final rule requires a 

‘‘monitoring plan.’’ The ‘‘QAPP’’ 

terminology in the proposed rule caused 

confusion because ‘‘QAPP’’ is used in a 

variety of other contexts, has various 

connotations to different readers, and 

caused readers to presume requirements 

EPA did not intend. The final rule 

specifies monitoring plan contents such 

as: 

• Identification of persons 

responsible for collecting emissions 

data. 

• Explanation of the processes and 

methods used to collect the necessary 

data for the GHG emissions calculation. 

• Description of the procedures that 

are used for QA, maintenance, and 

repair of all CEMS, flow meters, and 

other instrumentation used to provide 

data for the GHG emissions reported 

under 40 CFR part 98. 

The first two items in this list were 

formerly listed as separate line items in 

the recordkeeping requirements, but 

would logically be a part of the 

monitoring plan, so were consolidated 

under the monitoring plan to avoid 

repetition. 

The monitoring plan paragraph in the 

final rule explicitly states that the 

monitoring plan can rely on references 

to existing corporate documents. Such 

documents include SOPs, QA programs 

under Appendix F to 40 CFR part 60 or 

Appendix B to 40 CFR part 75, and 

other documents provided that the 

information required by the monitoring 

plan is clearly recognizable. The 

provision allowing the monitoring plan 

to refer to such documents avoids 

duplicative effort and addresses the 

commenters’ concerns that monitoring 

plan information is already contained in 

other documents. 

The final rule also contains a 

provision to update the monitoring 

plan. Reporters need their monitoring 

plan to be up to date in order to ensure 

that facility or supplier personnel follow 

the right monitoring and QA procedures 

and that the reporter meets the 

requirements of the reporting rule. 

Likewise, EPA needs to be able to view 

an up-to-date monitoring plan during 

facility audits. Updates to the plan 

would be needed if, for example, the 

facility makes a process change, changes 

monitoring instrumentation or QA 


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procedures, or improves procedures for 

maintenance and repair of monitoring 

systems to reduce the frequency of 

monitoring equipment downtime. 

N. Summary of Comments and 

Responses on Emissions Verification 

Approach 

This section contains a brief summary 

of major comments and responses on 

emissions verification of the GHG 

reports. A large number of comments 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Approach to Verification 

and Missing Data.’’ 

Comment: Many commenters, 

including most facilities and suppliers 

required to report under the rule and 

several other stakeholders, supported 

EPA’s proposal to require selfcertification with EPA verification of 

GHG reports. These commenters 

provided a variety of reasons. Many 

supported EPA emissions verification 

because the alternative of third party 

verification would be more costly to 

reporters. Several also commented that 

EPA emissions verification would 

provide a consistent and transparent 

data set. 

Other commenters suggested that EPA 

require third party verification of GHG 

reports, and they provided a variety of 

reasons. A few noted that third party 

verification is consistent with other 

GHG reporting systems (e.g., the 

European Emissions Trading Scheme, 

The Climate Registry, the California 

mandatory GHG reporting rule, and 

other State programs). Many stated that 

third party emissions verification will 

improve the quality of the data 

submittals and told us that third party 

verification led to the correction of 

inaccuracies in GHG emission reports 

submitted under other programs. Some 

of the commenters questioned whether 

EPA would have the time to conduct 

verification, given the number of reports 

and volume of supporting data that 

must be submitted. Others were 

concerned that EPA verification requires 

submittal of detailed supporting data 

and contended that some of these 

supporting data would be CBI. 

A smaller number of commenters 

favored self-certification without 

independent emissions verification. 

They believed the designated 

representative provisions in the rule 

would cause reporters to take selfcertification seriously and ensure the 

emissions they report are correct. Some 

also stated that independent verification 

is not needed for a reporting program 

that does not require emissions 

reductions. 

Response: In selecting the approach to 

emissions verification, EPA reviewed all 

of the comments, as well as emissions 

verification requirements and 

procedures under a number of existing 

EPA regulatory programs and domestic 

and international GHG reporting 

programs. Based on this review, EPA 

considered three alternatives: (1) Selfcertification without independent 

verification, (2) self-certification with 

third party verification, and (3) selfcertification with EPA verification. For 

this particular program, EPA is not 

changing the verification approach from 

the proposal and is requiring selfcertification with EPA emissions 

verification. We decided to retain this 

verification approach because it 

provides greater assurance of accuracy 

and impartiality than self-certification 

without verification, and has a number 

of advantages over third party 

verification for this type of Federal 

program. Our objective with emissions 

verification in this program is to ensure 

collection and dissemination of highquality data while providing the 

reporters a ‘‘level playing field’’ in terms 

of requirements and process. 

To enable effective review of the large 

volume of data reported, the rule 

requires reporters to submit data 

electronically in a standard format 

through a centralized data system. EPA 

is developing this system and intends to 

make it available to reporters, along 

with training and instructional 

materials, before the reporting 

deadlines. To the extent possible, EPA 

will leverage existing reporting systems 

and work with other State and regional 

programs and systems to develop a 

reporting scheme that minimizes the 

burden on reporters. 

In implementing the emissions 

verification under this rule, EPA 

envisions a two step process. First, we 

will conduct an initial centralized 

review of the data which will be largely 

automated. EPA intends to build into 

the data system an electronic data QA 

program for use by reporters and EPA to 

help assure the completeness and 

accuracy of data. In addition, to verify 

reported data and ensure consistency, 

EPA may review facility-level 

monitoring plans and procedures, and 

will perform detailed, automated checks 

on data utilizing recent and historical 

data submittals, comparison against like 

facilities and/or other electronic audit 

tools where appropriate. Second, EPA 

intends to follow-up with facilities 

should potential errors, discrepancies, 

or questions arise through the review of 

reported data and conduct on-site audits 

of selected facilities. The on-site audits 

may be conducted by private verifiers 

contracted by EPA or by Federal, State 

or local personnel, as appropriate. We 

plan to coordinate closely with the 

States to develop an efficient approach 

toward on-site auditing that can meet 

the needs of multiple programs. We do 

not anticipate conducting on-site audits 

of every facility every year. 

EPA decided to finalize the rule with 

EPA emissions verification for several 

reasons. First, we determined that the 

combination of comprehensive 

electronic review and a flexible and 

adaptive program of on-site auditing 

will enable us to effectively target 

verification resources while also 

providing the necessary consistency and 

quality in the data. Utilizing the 

national data set developed under this 

rule will provide unique resources for 

the review of reports. A centralized 

emissions verification system provides 

greater ability for EPA to identify trends 

and outliers in data and thus assist with 

targeted follow-up review, and our 

approach can evolve over time as we 

gain experience with GHG reporting. 

This approach also provides 

opportunity to work closely with and 

leverage both the experience and 

ongoing activities of States and others 

already engaged in similar and different 

types of GHG reporting. 

Our emissions verification approach 

in this rule is consistent with other EPA 

emission reporting programs and 

follows a model similar to the ARP 

which is a highly successful emissions 

cap and trade program that consistently 

produces credible, high-quality data. 

Facilities regulated under ARP must 

have a Designated Representative sign 

data reports to self-certify that the 

reported data are accurate. Then, 

facilities and EPA use a series of 

electronic tools to ensure proper data 

collection and reporting, including 

establishing a monitoring plan, 

calibrating equipment to certain 

specifications, frequent testing and data 

submittal. Similar to what we are 

intending with this program, EPA 

conducts site audits on those facilities 

targeted during the electronic review as 

having been outliers or had anomalies 

in their reported data. These audits are 

done by EPA personnel, States and/or 

contractors to EPA. We support these 

audits by providing a field audit manual 

to both government and private auditors 

as well as additional training to State 

and Federal auditors. 

Second, this approach is the best way 

to address the many comments we 

received on the importance of obtaining 

2010 data and making the data widely 

available. EPA has determined that this 


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verification approach will enable us to 

make data available more quickly than 

under a third party verification 

approach. We will be able to share a 

complete data set promptly upon 

completion of the electronic review 

(subject to relevant CBI concerns, please 

see the discussion of our plans to 

address CBI and emissions data in 

Section II.S of this preamble and 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Legal Issues’’). We 

determined that the third party 

verification approach could take from 

three to six months after initial data 

submission, and EPA would still need 

to review and perform consistency 

checks after the third party verification 

was complete. 

In addition, developing the third 

party verification approach would 

require EPA to establish and develop 

emissions verification protocols and a 

system to qualify and accredit the third 

party verifiers, and to develop and 

administer a process to ensure that 

verifiers hired by reporting facilities do 

not have conflicts of interest. Such a 

program could require EPA to review 

numerous individual conflict of interest 

screening determinations made each 

time a reporter hires a third party 

verifier. Even if EPA were to partner 

with an existing program or 

organization to accredit verifiers, EPA 

would still need to develop the criteria 

and systems described above to 

implement this rule and ensure high 

quality emissions verification given the 

unique reporting requirements of this 

rule. These efforts would slow down 

implementation of the rule and sharing 

of data. 

Finally, we agree with many of the 

commenters regarding their concerns 

about the cost of third party verification. 

Given the information currently 

available to us, under a third party 

verification approach we would have 

required that each facility verify its 

submission each year. As a national 

reporting program with a substantially 

larger number of reporters than existing 

State programs, we determined that the 

costs to the reporters of third party 

verification would have been 

substantial. By finalizing selfcertification with EPA emissions 

verification for this rule, it also ensures 

a lower cost burden for reporters. 

EPA’s decision to use self certification 

with EPA emissions verification was 

made in the context of the specific 

scope of this rulemaking, the types of 

data to be collected, and the intended 

uses of the emissions data. For other 

types of programs (e.g., offsets, 

corporate footprinting, energy 

efficiency) other verification approaches 

may be more suitable. We recognize that 

many GHG reporting and reduction 

programs developed by the States and 

Regions are broader in scope and for 

this and other reasons, the use of third 

party verifiers is an appropriate way to 

verify the data they collect. EPA’s 

decision in this rulemaking does not 

preempt State GHG reporting programs 

or any other programs from requiring 

third party verification. More 

importantly, the selection of EPA 

emissions verification for this rule is not 

intended to suggest that third party 

verification cannot result in accurate, 

high quality data. 

EPA received a smaller number of 

comments in support of selfcertification without emissions 

verification. While recognizing that this 

approach would place a low burden on 

both reporters and the government, it 

also has major disadvantages. Without 

any verification of submitted reports, 

there is far greater potential for 

inconsistent and inaccurate data and 

this will result in less confidence at EPA 

and with public stakeholders in the 

data. These disadvantages would make 

the data collected under this option less 

useful for informing decisions on 

climate policy and supporting the 

development of potential future policies 

and regulations. 

Comment: Commenters asked what 

role State and local regulatory agencies 

will have in verification of reported 

emissions data. Some suggested that 

State and local agencies should assist 

with emissions verification because they 

already have detailed knowledge of the 

facilities in their areas. Some indicated 

that States would need resources to play 

a role in verification and other rule 

implementation activities. 

Response: While EPA is responsible 

for emissions verification as explained 

in the previous response, EPA will 

likely enlist State assistance, when it is 

available, during the implementation 

phase of the final rule. (However, State 

and local agencies will not be required 

to provide EPA any assistance with 

verification or implementation 

activities, given State and local agency 

resource constraints and priorities.) For 

example, in concert with their routine 

inspection and other compliance and 

enforcement activities for other CAA 

programs, State and local agencies 

could, as resources allow, assist with 

educating facilities and assuring 

compliance at facilities subject to this 

rule. 

Assistance from State and local 

agencies could include such activities as 

identifying the facilities for on-site 

audits or conducting audits where 

appropriate. This type of assistance 

from State and local governments has 

been valuable in other programs. State 

and local air pollution control agencies 

routinely interact as part of other 

regulatory programs with many of the 

sources that would report under this 

rule. States have knowledge of specific 

facilities and sources that would be 

required to report under this rule. In 

addition, many States have already 

implemented or are in the process of 

implementing GHG reporting and 

reduction programs. Therefore, some 

State and local agencies could serve a 

role in communicating the requirements 

of the rule and providing compliance 

assistance. 

O. Summary of Comments and 

Responses on the Role of States and 

Relationship of This Rule to Other 

Programs 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on the 

relationship between this rule and other 

programs were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Relationship to Other 

GHG Reporting Programs’’ and 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Legal Issues.’’ 

Comment: Several commenters 

requested that EPA make it clear that 

States can collect additional GHG data 

under State rules and GHG programs 

and are not limited to collecting only 

the data in this Federal mandatory 

reporting rule. Other commenters 

requested that this rule preempt or 

supersede State GHG reporting rules. 

Response: EPA reaffirms that States 

can collect additional data under State 

rules and GHG programs, and that this 

rule does not preempt or replace State 

reporting programs. This rule has been 

developed in response to a specific 

request from Congress (in the 

Appropriations Act) and is narrower 

and more targeted than many existing 

State programs that are coupled with 

GHG emission reduction programs. As 

EPA stated in Section II of the proposal 

preamble (74 FR 16457, April 10, 2009) 

and Section I.E of this preamble, many 

State programs are broader in scope, in 

a more advanced state of development, 

and have different policy objectives 

than this rulemaking. These are 

important programs that not only led 

the way in reporting of GHG emissions 

before the Federal government acted but 

also have catalyzed important GHG 

reductions. 


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EPA supports and recognizes the 

success and necessity of State programs 

as a vital component in achieving GHG 

emissions reductions, particularly those 

focused on energy efficiency 

improvements. It is appropriate that 

State and regional GHG reporting and 

reduction programs have different 

scopes or implementation schedules, 

and that they require reporting of 

different information than this rule for 

various program-specific reasons. For 

example, some State programs might 

require reporting of electricity 

purchases and other data to provide 

information for energy efficiency 

programs; they may require or allow 

reporting of a variety of indirect 

emissions to gather data to help 

facilities reduce their carbon footprint; 

they may require or allow reporting of 

emissions such as from fleet vehicles to 

encourage fleet operators to take steps to 

reduce emissions; or they may be 

developing or implementing GHG 

reduction rules including cap and trade 

programs, and require specific 

information on emissions and offsets to 

implement those programs. State 

programs already have, or may evolve to 

include, additional monitoring and 

reporting requirements than those 

included in this rule. Many States are 

actively collecting additional data they 

need for their programs and policies, 

and this reporting rule does not preempt 

State programs. 

Comment: Some commenters were 

concerned that the Federal GHG 

reporting rule will result in duplicative 

reporting for facilities that are also 

reporting GHG emissions under State 

rules or voluntary GHG reporting 

programs. Some requested that to 

reduce burden, facilities should be 

required to submit data only once, and 

not have to submit different data to 

multiple different programs. Some 

commenters strongly recommended that 

the electronic data systems used by this 

reporting rule and other programs need 

to be consistent and allow data 

exchange between this rule and TCR, 

State rules, National Emissions 

Inventory (NEI), ARP, or other 

programs. Many commenters supported 

submittal of all data directly to EPA, 

while others favored delegation of data 

collection to State agencies to encourage 

consistency between State and Federal 

data collection efforts. 

Response: EPA carefully considered 

the issue of State delegation, 

particularly in light of the leadership 

and experience of several States in 

developing GHG reporting and 

reduction programs, and also in the 

context of the pressing need for a 

national reporting program and the 

strong emphasis placed by the vast 

majority of the commenters on this rule 

for EPA to ensure that data collection 

begins on January 1, 2010 and that data 

are reported early in 2011. We 

determined that developing a program 

to delegate to States would take 

additional time and would not be 

available for 2010 reporting, and we also 

determined that a significant number of 

States would likely not request 

delegation, which would increase the 

complexity of assembling a consistent 

national data set. For these reasons, we 

determined that the most effective way 

to achieve nationwide GHG reporting of 

2010 data was for reporters to submit 

data directly to EPA, as proposed. 

Additional reasons for selection of this 

data flow approach are described in the 

response on emissions verification in 

Section II.N of this preamble, the 

responses on collection, management, 

and dissemination of GHG emissions 

data in Section V of this preamble, and 

the responses on compliance and 

enforcement in Section VI of this 

preamble. 

While EPA is not formally delegating 

rule implementation and enforcement to 

States, we are committed to working in 

partnership to address the issues 

expressed in their comments on 

interaction between State and Federal 

reporting programs. Design and 

implementation of electronic systems 

for data systems has been an area of 

particular focus in determining how to 

ease reporting burdens and facilitate use 

of the many different types of data 

collected by State and Federal reporting 

programs by all levels of government. 

EPA is committed to working with 

States to develop electronic reporting 

tools that can both collect and share 

data in an efficient and timely manner. 

At this time, EPA is in the process of 

developing the reporting format and 

tools and therefore has not specified the 

exact reporting format, other than it will 

be electronic, in order to maintain 

flexibility to modify the reporting 

format and tools in a timely manner. To 

the extent possible, EPA will work with 

existing reporting programs and systems 

to develop a reporting scheme that 

minimizes the burden on sources. 

EPA recognizes the need to develop 

reporting tools that can support 

reporting across programs that collect 

different types of data, and we intend to 

coordinate with States and other 

organizations to explore development of 

shared web-based tools that can 

simplify and expedite reporting. We 

recognize that State and regional 

programs may be collecting additional 

GHG information beyond what is 

required in this rule. For example, many 

of these programs collect emissions data 

on fleet vehicles, indirect emissions 

data for utility purchase, and other data 

not required by the Federal rule. 

Moreover, our rule requires reporting of 

additional data necessary for emissions 

verification, which is likely more 

expansive than what many existing 

State and regional programs are 

collecting. For example this rule 

requires reporting of emissions at the 

process or unit level for many source 

categories, rather than the company or 

facility level as allowed by various other 

mandatory and voluntary reporting 

programs. We will also collect detailed 

monitoring data and activity data used 

to calculate emissions, which will 

enable emissions verification. We are 

interested in working with others to 

determine the extent to which shared 

tools can be designed to facilitate 

reporting across multiple programs, 

consistent with obligations regarding 

CBI. 

EPA carefully reviewed Federal, State, 

and international voluntary and 

mandatory programs during 

development of the reporting rule and 

attempted to be consistent with the GHG 

protocols and requirements within these 

rules, to the extent feasible given the 

differing scopes and policy objectives. 

(See Section II of the preamble for the 

proposed rule (74 FR 16457, April 10, 

2009), the Review of Existing Programs 

memorandum (EPA–HQ–OAR–2008– 

0508–052), and the memorandum 

summarizing State mandatory rules 

(EPA–HQ–OAR–2008–0508–054).) EPA 

has worked with and will continue to 

coordinate closely with other Federal, 

State, and regional programs to facilitate 

data exchange when designing the data 

reporting systems that will be used for 

the rule and planning implementation 

activities. We will work with the States, 

TCR, and others on data exchange 

standards to ease sharing of data 

between systems, consistent with CBI 

obligations. And finally, we see 

substantial opportunities for EPA and 

States to cooperate on strategic efforts to 

identify uses of the data collected under 

this rule and work together on a broad 

array of climate change issues. 

P. Summary of Comments and 

Responses on Other General Rule 

Requirements 

This section contains a brief summary 

of major comments and responses on 

other general rule requirements. A large 

number of other general comments were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 


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Response to Public Comments’’ volumes 

on subpart A. 

1. Research and Development 

Comment: Commenters representing 

institutions and industries subject to the 

reporting rule requested an exclusion 

for R&D activities. They noted that the 

aluminum production and glass 

production subparts of the proposed 

rule excluded R&D process units, but 

requested that R&D be excluded from 

the rule as a whole, not only from the 

two subparts. Some also commented 

that the exclusion should encompass 

R&D activities other than R&D process 

units, including bench scale laboratory 

research and pilot plants. Commenters 

pointed out that many other EPA air 

rules exclude R&D and they explained 

that R&D activities are small-scale, 

emissions change frequently as the 

focus and scope of the R&D activity 

changes, reliable information on CO2e 

emissions during any particular phase 

of the research might not be available, 

and quantifying R&D emissions would 

impose a high burden relative to the 

quantity of emissions. 

Response: In response to these public 

comments, EPA has added an R&D 

exclusion in 40 CFR 98.2(a)(5) stating 

that R&D activities are not considered to 

be part of any source category defined 

in 40 CFR part 98. Because R&D 

activities are not included in any source 

category, their GHG emissions are not 

reported. EPA agreed with the 

commenters that R&D process units and 

laboratory R&D for new processes, 

technologies, or products should be 

excluded. It is not reasonable to 

calculate GHG emissions from processes 

and activities that continually change as 

the research focus changes and have 

highly variable inputs and operating 

conditions due to their R&D nature. 

Also, emissions from R&D are expected 

to be small. Therefore, the final rule 

defines R&D as activities conducted in 

process units or at laboratory bench 

scale settings whose purpose is to 

conduct R&D for new processes, 

technologies, or products, and whose 

purpose is not for the manufacture of 

products for commercial sale, except in 

a de minimis manner. 

We point out that the exclusion 

applies to each individual R&D activity 

that meets the R&D definition, not to an 

entire facility as a whole. For example, 

a facility that has some commercial 

process units and some R&D process 

units can exclude only the R&D process 

units. A facility that meets the 

applicability criteria in 40 CFR part 98, 

subpart A and contains general 

stationary combustion sources must 

report emissions from the combustion 

units, even if the steam, heat, or 

electricity generated by a combustion 

unit is used in an R&D process unit. 

Laboratory activities are excluded only 

if they are for R&D purposes. Laboratory 

analyses activities conducted for 

commercial purposes, process operating 

purposes, or to comply with a rule 

would not be excluded. 

We decided not to include pilot 

plants in the definition of R&D. Pilot 

plants that meet the rule applicability 

criteria must report their GHG 

emissions. Pilot plants tend to be 

relatively large in scale compared to the 

excluded R&D activities. Because pilot 

plants are designed to prove the 

viability of a particular process or 

technology rather than to research a 

wide range of processes and products, 

their operations and emissions are more 

consistent than the excluded R&D 

activities. Pilot plants also tend to be 

operated for relatively long periods of 

time and in some cases are converted to 

commercial facilities. For these reasons, 

EPA views the data as more useful and 

has not applied the R&D exclusion to 

pilot plants. 

2. Determining Applicability 

Comment: Some commenters were 

concerned that the GHG reporting rule 

will virtually require every commercial 

and industrial facility to collect fuel 

usage data and perform relatively 

complex calculations, and in some cases 

modeling, in strict accordance with the 

prescribed monitoring methodologies 

and emissions calculation procedures, 

to determine if they are subject to the 

rule. The commenters added that this 

will be burdensome, especially for small 

sources that will just be documenting 

that the calculated GHG emissions from 

the facility are well below the reporting 

threshold. They also indicated that 

recordkeeping would be needed to show 

that facilities are below the reporting 

threshold, and anticipated that the rule 

will be nearly as burdensome on 

facilities that do not have to report, as 

on those that must report. Many of the 

commenters asked that EPA provide 

simplified source category thresholds to 

determine applicability, like the 30 

mmBtu/hr aggregate maximum rated 

heat input capacity for stationary fuel 

combustion units, to reduce the burden 

on the majority of facilities making 

applicability determinations. 

Response: We disagree that the initial 

applicability determination process is 

burdensome. While the rule requires 

reporters who are subject to the rule to 

determine applicability using the 

calculation procedures required in the 

rule, the rule does not contain any 

requirements for facilities that are not 

subject to the rule. Therefore, the rule 

does not necessarily require monitoring 

in 2010 to determine applicability. To 

determine applicability, anyone who 

believes their facility might be subject to 

the rule could start by calculating 

emissions using the relevant equations 

provided in each applicable subpart 

along with the available data from 

company records and the likely 

operating scenario for the reporting year 

that would lead to worst case GHG 

emissions. For example, for the input 

parameters needed for the equations, 

use the 2010 production goals from the 

company’s business plan, company 

records, process knowledge, engineering 

judgment, and vendor data (e.g., vendor 

information could be used to estimate 

the carbon content of feedstocks, using 

the highest likely carbon content of 

those feedstocks.) EPA expects that for 

most facilities, emissions calculated in 

this manner are likely to be significantly 

above or below the 25,000 metric ton 

CO2e per year threshold, such that most 

potential reporters can determine their 

applicability to the rule solely using the 

available data. 

For those facilities with estimated 

emissions that are near the 25,000 tons/ 

year threshold using available data, the 

company will have to make the decision 

on whether to install monitoring 

equipment to calculate emissions during 

the 2010 reporting year for purposes of 

determining applicability and/or 

reporting emissions. It is in a facility’s 

interest to collect the GHG data required 

by the rule if they think they will meet 

or exceed the applicability criteria in 40 

CFR 98.2 by the end of the year. EPA 

anticipates that relatively few potential 

reporters will face uncertainty in 

making this decision. 

Given the large number of industrial 

and commercial facilities potentially 

subject to the rule due to stationary fuel 

combustion emissions, EPA has 

provided in 40 CFR 98.2 simplified 

procedures for calculating emissions 

from fuel combustion. These facilities 

may first assess applicability based on 

the aggregate heat input capacity of all 

their fuel combustion units. Per 40 CFR 

98.2(a)(3), facilities with an aggregate 

maximum rated heat input capacity of 

less than 30 mmBtu/hour are 

automatically not covered under the 

rule, because emissions of CO2e will be 

less than 25,000 metric tons of CO2e per 

year in all cases. If a facility is not below 

the 30 mmBTU/hour cutoff, the next 

logical step to determine applicability is 

to use any of the four calculation 

methods provided in subpart C, as 

allowed by 40 CFR 98.2(b). The simplest 

of the four methods requires 

determination of only one parameter— 


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annual fuel use. Most companies 

already record fuel use, and can use this 

to calculate emissions and determine 

applicability. 

To assist facilities in determining 

applicability, EPA plans to provide 

implementation guidance with 

simplified means to determine 

applicability. For combustion sources, 

EPA plans to publish tables that will 

specify by fuel type both an annual fuel 

consumption level and maximum heat 

input capacity that correlates with 

emissions of 25,000 metric tons per year 

of CO2e. For non-combustion source 

categories with a 25,000 metric ton CO2e 

threshold, EPA plans to publish 

guidance, as feasible, on equipment 

capacities, production levels, or other 

parameters that correlate with emissions 

of 25,000 metric tons per year of CO2e. 

The capacity and production levels 

provided in these tables would be based 

on worst-case assumptions, but would 

allow facilities to quickly and easily 

determine if they need to develop more 

precise estimates or plan to implement 

monitoring in 2010. 

Q. Summary of Comments and 

Responses on Statutory Authority 

This section contains a brief summary 

of some major comments and responses. 

A large number of comments on 

statutory authority were received 

covering numerous topics. This section 

will highlight only two of the key 

categories of comments. Additional 

discussion on these comments and 

others can be found in the comment 

response documents. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues’’. 

Comment: EPA received numerous 

comments on whether the CAA or the 

FY 2008 Consolidated Appropriations 

Act authorized the rule. Some 

commenters argued that EPA was 

required to issue the reporting rule 

under the authority created by the 

Appropriations Act, not the CAA. 

Others argued that the Appropriation 

Act could not create new authority, and 

therefore either (1) EPA had to rely on 

the CAA, or (2) EPA was not authorized 

to issue the rule at all. 

Response: As noted above, EPA is 

relying on the authority provided in the 

CAA, not the Appropriations Act, for 

this final rule. While the Appropriations 

Act required that EPA spend a certain 

amount of money on a rule requiring 

mandatory reporting of GHG emissions, 

the authority to gather such information 

already existed in the CAA. Indeed, EPA 

could have promulgated this rule in the 

absence of the Appropriations Act. 

Thus, the comments about the inability 

of an appropriations law to create new 

legal authority are inapposite to this 

rulemaking. 

Comment: Commenters opined on 

whether the statute in question (either 

the Appropriations Act or the CAA) 

contained sufficient authority for 

various elements of the rule, ranging 

from broad issues like the scope and 

duration of the rule as a whole, to more 

specific issues related to particular 

source categories covered, and specific 

monitoring, recordkeeping and 

reporting requirements. 

Several commenters argued that the 

appropriations language contained 

limitations on the scope of the rule EPA 

could promulgate, regardless of the 

underlying authority for the rule. For 

example, some commenters contended 

that because the appropriations were for 

a single fiscal year, EPA was authorized 

to promulgate only a one-time data 

collection. Others argued that the 

Appropriations Act authorized the 

collection solely of GHG emissions, and 

not any of the additional data elements 

related to verification of emissions data. 

As for the CAA, some commenters 

questioned whether section 114 

authorized a broad reporting rule, as 

opposed to the targeted 114 information 

requests used by EPA in the past. Many 

commenters questioned whether EPA 

had adequately linked the requirements 

of the reporting rule to particular 

provisions of the CAA that EPA was 

carrying out. Others questioned EPA’s 

general ability to gather information 

about GHGs before it had made an 

endangerment finding and/or regulated 

GHGs under the CAA. 

Not all comments were negative. 

Some commenters supported EPA’s 

interpretation of the CAA, and agreed 

that it authorized the proposed 

reporting rule. 

Response: We disagree that the 

language in the Appropriations Act 

limited EPA’s authority for this rule. 

First, the Environmental Programs and 

Management (EP&M) funds Congress 

appropriated for the GHG reporting rule 

are available for two fiscal years as are 

the funds EPA historically has used for 

most other Agency rules. The fact that 

the appropriations EPA uses to develop 

rules are available for specified fiscal 

years does not mean that the 

effectiveness of the rules is limited by 

the same period of time that the funds 

are available. Moreover, as noted above, 

EPA is issuing this rule under the 

authority of the CAA, and indeed EPA 

could have issued this rule absent the 

direct instruction from Congress to 

spend at least a certain amount of 

money on a mandatory GHG reporting 

rule. Thus, we do not agree that the 

appropriations language limited EPA’s 

ability to collect the information under 

this rule, either in duration or scope of 

the information requested. 

Regarding the scope of the rule, while 

it is true that EPA has used section 114 

in a more targeted fashion in the past, 

there is nothing in the CAA that so 

limits our ability. EPA is undertaking a 

comprehensive evaluation of GHGs 

under the CAA and hence, is issuing a 

comprehensive reporting rule. 

Moreover, as noted above, CAA 

sections 114 and 208 authorize EPA to 

gather the information under this rule, 

which will prove useful to EPA in 

carrying out numerous provisions of the 

CAA. This final rule imposes 

requirements on direct sources of GHG 

emissions. These sources are clearly 

persons from whom the Administrator 

may gather information under CAA 

section 114, as long as that information 

is for purposes of carrying out any 

provision of the CAA. As discussed 

further in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Selection of Source 

Categories to Report and Level of 

Reporting’’ and ‘‘Mandatory Greenhouse 

Gas Reporting Rule: EPA’s Response to 

Public Comments, Legal Issues,’’ the 

information provided by direct emitters 

will prove invaluable to the Agency in 

several areas, including the evaluation 

of the appropriate action to take under 

section 111 regarding NSPS, and the 

investigation into non-regulatory 

strategies to encourage pollution 

prevention pursuant to section 103(g). 

For example, the Agency currently has 

pending before it a court remand, 

comments in an ongoing rulemaking, a 

petition for reconsideration, notices of 

intent to sue and litigation regarding 

EPA’s treatment of GHGs under section 

111. 

The requirements applicable to 

manufacturers of mobile sources are 

authorized by section 208 because they 

will help inform various options 

regarding the regulation of these sources 

under title II of the CAA. The Agency 

currently has pending before it several 

petitions requesting that the Agency 

regulate emissions from a variety of 

mobile sources, including motor 

vehicles, aircraft, nonroad engines and 

marine engines. 

Finally, the final rule also gathers 

information from upstream suppliers of 

industrial GHGs and fossil fuels (except 

for suppliers of coal). The information 

gathered from suppliers of fossil fuels, 

in particular petroleum products, is 

relevant to an evaluation of possible 

regulation of fuels under title II of the 


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20We note that the statute is ambiguous, and thus 

EPA may adopt any reasonable interpretation. See 

Chevron v. NRDC et al., 467 U.S. 837, 864 (1984). 

CAA, as well as for potential efforts to 

address GHG emissions at downstream 

sources. Information from suppliers of 

industrial GHGs is relevant to 

understanding the quantities and types 

of gases being supplied to the economy, 

in particular those that could be emitted 

downstream which will aid in 

evaluating action under CAA section 

111 as well as various sections of title 

VI (e.g., 609 and 612) that address 

substitutes to ozone depleting 

substances (ODS). Additional 

discussion on this issue is available in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Selection of Source 

Categories to Report and Level of 

Reporting’’ and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

Finally, we disagree with commenters 

who argue that we cannot use CAA 

sections 114 of 208 to gather 

information on a pollutant until we 

have issued an endangerment finding 

for that pollutant, or actually decided to 

regulate it under the CAA. The statute 

is not so inflexible. 20 For example, the 

information collected under sections 

114 and 208 could inform the 

contribution element of endangerment 

determinations (e.g., whether emissions 

from the relevant sector contribute to air 

pollution which may reasonably be 

anticipated to endanger public health or 

welfare). Similarly, information 

gathered under these sections could 

inform decisions on whether to regulate 

a pollutant or source category. 

Commenters’ interpretation would 

prevent EPA from gathering information 

that could be critical to key decisions 

until after those decisions are made. 

EPA does not agree with, and will not 

adopt, such an interpretation. 

Thus, as discussed in more detail 

above and in ‘‘Mandatory Greenhouse 

Gas Reporting Rule: EPA’s Response to 

Public Comments, Legal Issues,’’ EPA 

has adequate authority to issue this rule. 

R. Summary of Comments and 

Responses on CBI 

This section contains a brief summary 

of major comments and responses on 

CBI issues. A large number of comments 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Legal Issues.’’ 

Comment: EPA received numerous 

comments addressing the issue of CBI. 

Industry commenters generally 

expressed concern that much of the 

information reported under this rule 

would be CBI (e.g., production and 

process data). Many commenters also 

presented arguments regarding why 

certain information would not be 

‘‘emissions data’’ under the CAA. 

Among the various recommendations 

were that the final rule (i) not require 

the reporting of such information at all, 

(ii) require only that the source maintain 

such information on site, but not report 

it to EPA, and/or (iii) clearly state that 

some classes of information are CBI. 

Some commenters expressed concern 

about EPA’s ability to maintain the 

confidentiality of CBI, and thus 

suggested that EPA should provide 

further detail regarding how we will 

protect CBI from disclosure. The 

agricultural industry expressed 

particular concerns about making 

information about the location of 

facilities public due to concerns about 

biosecurity and other potential threats. 

Other commenters favored the wide 

dissemination of information, and 

argued that the information gathered 

under this rule should be ‘‘emissions 

data’’ and hence not protected as CBI. 

Response: As discussed in Section 

II.N of this preamble, EPA is finalizing 

its proposal that EPA verify the 

information collected by this rule. Data 

regarding inputs into emissions 

calculations and monitoring are critical 

elements of that verification process. 

Because EPA will routinely need this 

data in order to verify the information 

collected under this rule, we are not 

adopting the recommendation that 

sources maintain such information on 

site and only provide it during an 

inspection or when otherwise 

specifically requested. 

EPA also recognizes the importance of 

this issue to both reporters and the 

public. EPA’s public information 

regulations contain a definition of 

‘‘emissions data’’ at 40 CFR 2.301, and 

EPA has discussed in an earlier Federal 

Register notice what data elements 

constitute emissions data that cannot be 

withheld as CBI (56 FR 7042–7043, 

February 21, 1991). We further 

recognize that while determinations 

about whether information claimed as 

CBI meets the definition of CBI, as well 

as whether it meets the definition of 

emissions data, are usually made on a 

case-by-case basis, such an approach 

would be cumbersome given the scope 

of this rule and the potential 

inconsistencies across reporters and 

source categories and the compelling 

need to make data that are not CBI, or 

are emissions data, available to the 

public. For this reasons, EPA intends to 

undertake an effort similar to what was 

done in 1991 for the data elements 

collected in this rule. Through a notice 

and comment process, we will establish 

those data elements that are ‘‘emissions 

data’’ and therefore will not be afforded 

the protections of CBI. As part of that 

exercise, in response to requests 

provided in comments, we may identify 

classes of information that are not 

emissions data, and are CBI. EPA plans 

to initiate this effort later this year, or 

in early 2010. We will consider the 

comments received on this issue as part 

of that notice and comment process. 

As stated in the proposed rule, EPA 

will protect any information claimed as 

CBI in accordance with regulations in 

40 CFR part 2, subpart B. As we noted 

previously however, in general the CAA 

prohibits the treatment of emission data 

collected under CAA sections 114 and 

208 as CBI. 

S. Summary of Comments and 

Responses on Other Legal Issues 

This section contains a brief summary 

of major comments and responses on 

other legal issues. A large number of 

other legal issue comments were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

Comment: We received numerous 

comments on EPA’s statements in the 

proposed rule that a final rule requiring 

the monitoring and reporting of GHG 

emissions would not render GHGs 

‘‘regulated pollutants’’ under the CAA. 

See, e.g., ‘‘EPA’s Interpretation of 

Regulations that Determine Pollutants 

Covered By Federal Prevention of 

Significant Deterioration (PSD) Permit 

Program’’ (Dec. 18, 2008) (‘‘PSD 

Interpretive Memo). Some agreed, while 

others took issue with the position in 

the memorandum. 

Response: As we noted in the 

proposal, EPA is reconsidering the PSD 

Interpretive Memo and will be seeking 

public comment on the issues raised in 

it. That proceeding, not this rulemaking, 

is the appropriate venue for submitting 

comments on the substantive issue of 

whether monitoring regulations under 

the CAA should make GHGs subject to 

regulation. At this time however, the 

PSD Interpretive Memo reflects EPA’s 

current position, and hence, this final 

rule does not make GHGs subject to 

regulation under the CAA. 

Comment: EPA also received 

numerous comments about whether the 

requirements imposed by this rule are 


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‘‘applicable requirements’’ under the 

title V operating permit program. The 

majority of the comments took the 

position that the current definitions of 

‘‘applicable requirement’’ at 40 CFR 

70.2 and 71.2 do not include a rule such 

as this, promulgated under CAA section 

114(a)(1) and 208. Commenters 

requested that EPA confirm their 

interpretation of the regulations. 

Response: As currently written, the 

definition of ‘‘applicable requirement’’ 

in 40 CFR 70.2 and 71.2 does not 

include a monitoring rule such as 

today’s action, which is promulgated 

under CAA sections 114(a)(1) and 208. 

III. Reporting and Recordkeeping 

Requirements for Specific Source 

Categories 

A. Overview 

Once a reporter has determined that 

its facility or supply operation meets 

any of the reporting rule applicability 

criteria in 40 CFR 98.2(a), the reporter 

must calculate and report GHG 

emissions or alternate information as 

required (e.g., suppliers report 

quantities supplied and the quantity of 

CO2e that could be emitted when the 

products they supply are combusted or 

used). The applicability threshold 

determination is separately assessed for 

suppliers (fossil fuel suppliers and 

industrial GHG suppliers) and 

downstream source categories (facilities 

with direct GHG emissions). 

The required GHG information must 

be reported for all source categories at 

the facility for which there are 

measurement methods provided. For 

suppliers (facilities or corporations) that 

trigger only the applicability criteria for 

upstream fossil fuel or industrial GHG 

supply (40 CFR part 98, subparts KK 

through PP), reporters need only follow 

the methods and report the information 

specified in those respective subparts. 

For downstream facilities that contain 

exclusively direct emitting source 

categories covered in 40 CFR part 98, 

subparts C through JJ, and are not 

suppliers, reporters must monitor and 

report GHG emissions the methods 

presented in each applicable subpart. 

Some reporters will need to report 

under multiple subparts because 

multiple source categories are 

collocated at their facility. For example, 

a facility with petrochemical production 

processes (described in Section III.X of 

the preamble), should also review 

Sections III.C (general stationary fuel 

combustion), III.G (ammonia 

manufacturing) and III.Y (petroleum 

refineries) of this preamble. In some 

cases, such as petroleum refineries that 

supply petroleum products and also 

meet applicability criteria for direct 

emissions from the refinery, reporters 

will have to report on both supply 

operations and direct facility emissions. 

Table 2 of this preamble (in the 

SUPPLEMENTARY INFORMATION section of 

this preamble) provides a cross walk to 

aid facilities and suppliers in 

identifying potentially relevant source 

categories. The cross-walk table should 

only be seen as a guide as to the types 

of source categories that may be present 

in any given facility and therefore the 

methodological guidance in Section III 

of this preamble that should be 

reviewed. Additional source categories 

(beyond those listed in Table 2 of this 

preamble) may be relevant to a given 

reporter. Similarly, not all listed source 

categories will be relevant to all 

reporters. 

Consistent with the requirements in 

the 40 CFR part 98, subpart A, reporters 

must report GHG emissions from all 

source categories located at their facility 

including stationary combustion 40 CFR 

part 98, subpart C) and process 

emissions (e.g., from adipic acid 

production, iron and steel production, 

and other source categories in 40 CFR 

subparts C through JJ), as well as the 

required data for any supplier source 

categories (KK through PP). The 

methods presented typically account for 

normal operating conditions, as well as 

startup, shutdown, or malfunction 

(SSM), where significant (e.g., HCFC–22 

production and oil and gas systems). 

Although SSM is not specifically 

addressed for many source categories, 

emissions calculation methodologies 

relying on CEMS or mass balance 

approaches would capture these 

different operating conditions. 

For many facilities, calculating 

facility-wide emissions will simply 

involve adding GHG emissions from 

combustion sources calculated under 

Section III.C of this preamble (General 

Stationary Fuel Combustion Sources) 

and process GHG emissions calculated 

under the applicable the source category 

subpart(s). The rule also clarifies 

reporting for more complex situations, 

such as where combustion and process 

emissions are comingled. See Section 

II.L of this preamble for a response to 

comments on the general monitoring 

and reporting approach for facilities 

with both combustion and process 

emissions. See sections III.C through PP 

of this preamble for discussion of the 

specific monitoring and reporting 

requirements for each source category. 

B. Electricity Purchases 

1. Summary of the Final Rule 

The final rule does not require 

facilities to report their electricity 

purchases or indirect emissions from 

electricity consumption. 

2. Summary of Major Changes Since 

Proposal 

There have been no changes since 

proposal. The proposed rule did not 

require reporting of electricity 

purchases and neither does the final 

rule. 

3. Summary of Comments and 

Responses 

The proposal preamble (74 FR 16479, 

April 10, 2009) requested comments on 

the value of collecting information on 

electricity purchases under this rule. It 

also outlined three options for reporting 

and requested comments on these 

options: 

• Option 1: Do not require any 

reporting on electricity purchases or 

associated indirect emissions from 

purchased electricity as part of this rule. 

• Option 2: Require reporting of 

purchased electricity from all facilities 

that are already required to report their 

GHG emissions under this rule. 

• Option 3: Require reporting of 

indirect emissions from purchased 

electricity for facilities that exceed a 

prescribed total facility emission 

threshold (including indirect emissions 

from the purchased electricity). 

Reporting under this option could be 

either in terms of electricity purchases 

or calculated CO2e emission based on 

purchased electricity. 

While EPA is not including reporting 

requirements for electricity purchases in 

the final rule at this time, below we 

have provided a brief summary of major 

comments and our initial responses. As 

EPA considers next steps, we will be 

reviewing the public comments and 

other relevant information. 

In Favor of Collecting Data on 

Electricity Purchases 

Comment: Commenters in favor of 

collecting data on purchased electricity 

stated that collection of this data, in 

conjunction with data on direct 

emissions from facilities, will present a 

more comprehensive picture of 

emissions nationwide. They argued that 

collection of this data will also serve to 

spur investment in energy efficiency 

and renewable energy since companies 

will want to improve their emissions 

numbers once the information is made 

public. Several commenters noted that 

while this reporting should occur, it 

should happen at the corporate level, 


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rather than at the facility level. Others 

stated that the collection should begin at 

a later time, perhaps in a second phase 

of this rule. 

Response: While EPA is not collecting 

data on electricity purchases in this 

rule, we understand that acquiring such 

data may be important in the future. 

Therefore, we are exploring options for 

possible future data collection on 

electricity purchases and indirect 

emissions, and the uses of such data. 

Such a future data collection on indirect 

emissions would complement EPA’s 

interest in spurring investment in 

energy efficiency and renewable energy. 

Energy efficiency is a low cost, vital first 

step toward reducing GHG emissions. 

To this end, EPA has in place several 

programs in which corporations and 

individual facilities can participate to 

reduce their contribution to GHG 

emissions through increased energy 

efficiency of buildings and industry. 

These include EPA’s ENERGY STAR 

and Climate Leaders programs. 

EPA has been working for more than 

a decade through the ENERGY STAR 

program to help companies reduce their 

energy use through cost-effective energy 

efficiency investments and practices. 

ENERGY STAR provides nonresidential 

building owners and operators and 

energy intensive industries with a wide 

variety of tools and resources to assist 

in their efforts to reduce building energy 

use. These include an online energy 

benchmarking and tracking tool called 

Portfolio Manager, Guidelines for 

Energy Management, technical 

resources to assist in assessing building 

upgrades, and many others. 

Through the Climate Leaders 

Program, EPA works corporate-wide 

with companies to develop 

comprehensive climate change 

strategies. Partner companies commit to 

reducing their impact on the global 

environment by completing a corporatewide inventory of their GHG emissions 

based on a quality management system, 

setting aggressive reduction goals to be 

achieved over 5 to 10 years, and 

annually reporting their progress to 

EPA. Through program participation, 

companies create a credible record or 

audit of their accomplishments and 

receive EPA recognition as corporate 

environmental leaders. 

In addition to these programs that 

support GHG emissions reductions in 

both the private and public sectors, 

EPA’s Climate and Energy State and 

Local Program assists governments in 

their clean energy efforts by providing 

technical assistance, analytical tools, 

and outreach support. While EPA assists 

States in this way, we also have much 

to learn from their efforts. Throughout 

the country, States are engaged in 

activities on energy efficiency, energy 

auditing, and some collect data on 

electricity purchases for use in 

inventories and in energy efficiency 

programming. 

Since the goal of today’s rule is to 

collect data on emissions from 

downstream direct emitters and 

upstream production, the collection of 

indirect emissions will not be included 

at this time. In exploring the possibility 

of collecting data on electricity 

purchases nationwide, EPA will be 

looking to the States as examples. While 

facility level collection is a possibility, 

collection from other sources, such as 

load serving entities will also be 

explored. Moreover, the collection of 

indirect emissions data from the types 

of facilities covered by this rule (e.g., 

facilities and suppliers with emissions 

over 25,000 metric tons of CO2e) would 

not provide the complete picture or 

focus on the types of facilities that likely 

have large indirect emissions. Reports 

from additional facilities could be 

required in any future data collection. 

Against Collecting Data on Electricity 

Purchases 

Comment: Many commenters were 

against the collection of data on 

purchased electricity for several 

reasons. Primarily they felt it would 

constitute double counting if electricity 

data are collected from electric utilities 

and EPA also collects the same data 

from facilities and adds it together. 

Others stated that collecting information 

on electricity purchases was outside the 

scope of the rule, that it is not useful 

information in attempting to quantify 

emissions, that it would be burdensome 

for facilities, and that it is CBI that 

companies are not able to share with 

EPA. Those commenters suggested 

instead the data should come from 

utilities, as EPA proposed. 

Response: The final rule does not 

require facilities to report their 

electricity purchases or indirect 

emissions from electricity consumption. 

While EPA is not collecting data on 

electricity purchases in this rule, we 

understand that acquiring such data 

may be important in the future. 

Therefore, we are exploring options for 

possible future data collection on 

electricity purchases and indirect 

emissions, and the uses of such data. In 

the event that a future data collection 

effort is pursued, EPA will consider the 

issues raised by these commenters with 

regard to the most effective source for 

this data, and methods to reduce burden 

on reporting entities. 

With regard to, double reporting and/ 

or double counting of the same data, the 

data collected under this rule is 

consistent with the appropriations 

language, and provides valuable 

information to EPA and stakeholders in 

the development of climate change 

policy and programs. Policies such as 

low carbon fuel standards can only be 

applied upstream, whereas end use 

emission standards can only be applied 

downstream. Data from upstream and 

downstream sources would be necessary 

to formulate and assess the impacts of 

such potential policies. Eliminating 

reporting by either upstream or 

downstream sources would not satisfy 

EPA’s data needs and policy objectives 

of this rule. Any future rule makings to 

collect data on electricity purchases and 

indirect emissions will follow a similar 

approach in order to inform policy 

decisions. 

With regard to CBI, EPA recognizes 

the importance of this issue to both 

reporters and the public. EPA’s public 

information regulations contain a 

definition of ‘‘emissions data’’ at 40 CFR 

2.301, and EPA has discussed in an 

earlier Federal Register notice what 

data elements constitute emissions data 

that cannot be considered CBI (56 FR 

7042–7043, February 21, 1991). 

As explained in Section II.R. of this 

preamble, EPA intends to undertake a 

similar effort regarding the data 

elements collected in this rule, and any 

subsequent rules. Through a notice and 

comment process, we will establish 

those data elements that are ‘‘emissions 

data’’ and therefore will not be afforded 

the protections of CBI. 

C. General Stationary Fuel Combustion 

Sources 

1. Summary of the Final Rule 

Source Category Definition. Stationary 

fuel combustion sources are devices that 

combust any solid, liquid, or gaseous 

fuel to: 

• Produce electricity, steam, useful 

heat, or energy for industrial, 

commercial, or institutional use; or 

• Reduce the volume of waste by 

removing combustible matter. 

These devices include, but are not 

limited to, boilers, combustion turbines, 

engines, incinerators, and process 

heaters. 

Portable equipment, emergency 

generators, and emergency equipment 

are excluded from this source category. 

Stationary combustion devices that 

combust hazardous waste must report 

emissions only from the co-firing of any 

fuels that are covered by 40 CFR part 98, 

subpart C. Flares are also excluded from 

subpart 40 CFR part 98, subpart C. Flare 

emissions must be reported only if 


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required by the provisions of another 

subpart of part 98. 

Reporters must submit annual GHG 

reports for stationary fuel combustion 

units if the facility meets the 

applicability criteria in the General 

Provisions (40 CFR 98.2) as summarized 

in Section II.A of this preamble. 

EGUs that are subject to the ARP and 

other EGUs that are required to monitor 

and report to EPA CO2 mass emissions 

year-round according to 40 CFR part 75, 

are covered under 40 CFR part 98, 

subpart D (Electricity Generation). 

GHGs to Report. For stationary fuel 

combustion, report: 

• CO2, CH4, and N2O emissions from 

each stationary fuel combustion unit. 

For each unit, CO2, CH4, and N2O 

emissions must be reported for each fuel 

combusted (including biomass). 

Reporters can aggregate emissions from 

multiple units in certain cases. 

• Facility-level CO2 emissions from 

combustion of biomass (in addition to 

unit-level reporting). 

GHG Emissions Calculation and 

Monitoring. Reporters must use the 

following methodologies to calculate 

emissions: 

• Calculating CO2 Emissions from 

Combustion: Calculate CO2 emissions 

using one of four methodological tiers, 

subject to certain restrictions based on 

unit size, type of fuel burned, and other 

factors. For each Tier, CO2 mass 

emissions are determined as follows: 

—Tier 1: Use annual fuel consumption 

(from company records) together with 

fuel-specific default high heat values 

and default CO2 emission factors. 

—Tier 2: Use annual fuel consumption 

(from company records) together with 

measured fuel-specific high heat 

values and default CO2 emission 

factors. 

—Tier 3: Use annual fuel consumption, 

either from company records (for 

solid fuels) or directly measured with 

fuel flow meters (for liquid and 

gaseous fuels) together with periodic 

measurements of fuel carbon content. 

—Tier 4: Use CEMS. Use Tier 4 only for 

combustion units that have certain 

types of existing CEMS in place and 

that meet several other specific 

criteria, such as fuel type and hours 

of operation. Sources that have all of 

the necessary CEMS installed and 

certified by January 1, 2010 are 

required to use Tier 4 in 2010. 

However, for sources that need 

additional time to upgrade their 

CEMS, the use of CEMS can begin on 

January 1, 2011; and a lower tier 

calculation methodology may be used 

in 2010. 

—As an alternative to any of the four 

tier methods, the rule provides that 

units that report to EPA year-round 

heat input data under 40 CRF part 75 

can calculate CO2 mass emissions 

using part 75 calculation methods. 

• Calculating CO2 Emissions From 

Sorbent Use. For fluidized bed boilers 

that use sorbent injection and units 

equipped with wet flue gas 

desulfurization systems, calculate CO2

emissions from sorbent use using 

methods provided in the rule, except 

when CO2 emissions are measured with 

CEMS. 

• Calculating CO2 Emissions From 

Biomass Fuel Combustion. Calculate 

CO2 emissions from biomass 

combustion for only the specific types 

of biomass that are listed in the rule. 

The approach used for most units is to 

use a default high heat value and default 

CO2 emission factor to estimate 

emissions. For determining the biomass 

fraction of CO2 emissions from units 

that burn MSW or mixed fuels, and from 

units that co-fire biomass with fossil 

fuels and measure CO2 emissions using 

CEMS, use the specific methods 

provided in the rule. 

• Calculating N2O and CH4 Emissions 

From Combustion. Calculate N2O and 

CH4 emissions only for units that are 

required to report CO2 emissions under 

this subpart and only for fuels for which 

default emission factors are provided in 

40 CFR part 98, subpart C. 

• Fuel Sampling and Analysis. The 

Tier 2 and Tier 3 calculation 

methodologies require periodic 

measurements of fuel heating value and 

carbon content. The minimum required 

frequency of these measurements is 

daily, weekly, monthly, quarterly, or 

semiannually, depending on the type of 

fuel combusted and other factors. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are needed for EPA 

verification of the reported GHG 

emissions from stationary combustion. 

The specific data to be reported are 

found in 40 CFR part 98, subpart C. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. These records are described 

in 40 CFR part 98, subpart C. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart C: General 

Stationary Fuel Combustion Sources.’’ 

• Exemptions to GHG emissions 

reporting have been added for 

unconventional types of fuel. Reporters 

are required to calculate GHG emissions 

only for fuels that are listed in Table C– 

1 of subpart C, except that units larger 

than 250 mmBtu/hr, also must calculate 

GHG emissions for any other fuels that 

provide, on average, at least 10 percent 

of the annual heat input to the unit. 

• The use of the Tier 2 calculation 

method for CO2 emissions has been 

expanded to include units greater than 

250 mmBtu/hr that combust only 

pipeline natural gas and/or distillate oil. 

• Two new alternative methods have 

been added, allowing sources that 

monitor and report heat input according 

to 40 CFR part 75, but are not required 

to report CO2 mass emissions, to use 

established Part 75 CO2 emissions 

calculation methods to meet the 40 CFR 

part 98 reporting requirements. 

• A definition of ‘‘company records’’, 

as it pertains to quantifying fuel 

consumption in Tiers 1, 2, and 3, has 

been added to 40 CFR 98.6. 

• The required fuel sampling 

frequency in Tiers 2 and 3 has been 

reduced for many fuels, particularly 

those that are homogeneous or that are 

delivered in shipments or lots. 

• Averaging of fuel sampling results 

is allowed for many fuels when the 

frequency of sampling and analysis is 

less than the minimum monthly 

frequency. 

• The rule has been clarified to affirm 

that the use of fuel sampling results 

provided by the fuel supplier is 

permissible, and that the use of fuel 

billing records to quantify fuel 

consumption is also allowed. 

• Additional deadline extensions for 

calibrating the fuel flow meters are 

provided in certain situations. 

• The use of Tier 4 has been clarified; 

i.e., all of the conditions listed in 40 

CFR 98.33(b)(4)(ii) and all of the 

conditions listed in 40 CFR 

98.33(b)(4)(iii) must be met before Tier 

4 is required. 

• Units that must upgrade their 

existing CEMS to meet Tier 4 

requirements may use either Tier 2 or 

Tier 3 in 2010. 

• The methods for calculating CH4

and N2O emissions have been clarified. 

• An expanded list of default 

emission factors are provided for certain 

solid, gaseous, and liquid biomass fuels. 

• The use of steam production and 

combustion unit efficiency to calculate 

CO2 emissions is extended to other solid 

fuels in addition to MSW. These 


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parameters may also be used to quantify 

the amount of biomass combusted in a 

unit. 

• The use of American Society for 

Testing and Materials (ASTM) Methods 

D7459–08 and D6866–06a to determine 

CO2 emissions from combustion of 

mixed biomass fuels has been expanded 

to include the combustion of other 

biomass fuels in addition to those mixed 

with MSW. 

• The missing data provisions have 

been made more flexible. 

• The limit of 250 mmBtu/hr total 

heat input for aggregating units into 

groups for reporting purposes has been 

lifted. 

• The reporting of combined units 

served by a common supply line, or 

common pipe configuration, has been 

clarified. 

• The amount of required unit-level 

data and emissions verification 

information has been reduced for some 

of the measurement Tiers. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Many comments on general stationary 

fuel combustion were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart C: General 

Stationary Fuel Combustion Sources.’’ 

Definition of Source Category 

Comment: Several commenters asked 

EPA to clarify whether sources such as 

flares, hazardous waste incinerators, 

thermal oxidizers, pollution control 

devices, fume incinerators, burnout 

furnaces, and small equipment such as 

stoves and space heaters are included in 

the stationary combustion source 

category. Others suggested that EPA 

should consider requiring that only the 

GHG emissions from combustion of 

traditional fossil fuels (if any) in these 

types of sources be reported. 

Comments were also received on the 

proposed language for excluding 

emergency generators and the associated 

definitions. 

Response: The final rule retains the 

broad definition of a stationary fuel 

combustion source, which is any device 

that combusts fuel. Fuel is defined very 

broadly to mean any combustible 

material. However, in evaluating public 

comments, we agree that in some cases 

the reporting of GHG emissions is 

unreasonable given the cost of 

monitoring and the relative level of 

GHG emissions. Monitoring can be 

particularly burdensome for vents with 

highly variable gas characteristics (e.g., 

carbon content and heat value). 

Accordingly, the final rule expands the 

list of combustion sources and fuels that 

are exempted from GHG emissions 

reporting under 40 CFR part 98, subpart 

C, as summarized below: 

• Flares are exempted from 40 CFR 

part 98, subpart C. However, flares at 

some facilities might be covered by 

other subparts of the rule. 

• Stationary combustion units that 

combust hazardous waste, as defined in 

40 CFR 261.3, are also exempted. These 

units would report only the emissions 

from combustion of any fuels covered 

by subpart C that are co-fired with 

hazardous wastes. 

• For calculations at the unit level, 

units less than 250 mmBtu/hour heat 

input are required to report GHG 

emissions only for fuels for which EPA 

has provided default emission factors in 

the rule. 

• Units larger than 250 mmBtu/hour 

heat input GHG that combust 

miscellaneous, non-traditional fuels 

such as refinery gas, process gas, vent 

gases, waste liquids, and others must 

report only if CEMS are used or if these 

fuels contribute 10 percent or more of 

the annual unit heat input to the unit. 

With this exclusion, we have concluded 

that devices such as thermal oxidizers, 

pollution control devices, fume 

incinerators, burnout furnaces, and 

other such equipment would report only 

GHG emissions from the firing of 

supplemental fossil fuels. 

In response to comments on the 

exclusion of emergency generators, EPA 

removed proposed language that would 

have required emergency generators to 

be identified as such in the facility’s 

State or local air permit in order to 

qualify for an exemption. We also added 

language to exclude other emergency 

equipment. See Section III.D of this 

preamble for the response to the 

comments on exclusion of emergency 

generators from 40 CFR part 98, 

subparts C and D. See ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

A: Definitions, Incorporation by 

Reference, and Other Subpart A 

Comments’’ for responses to comments 

on definitions, including changes to the 

emergency generator definition and the 

addition of a definition for emergency 

equipment. 

Comment: Multiple commenters 

asked EPA to institute a ‘‘de minimis’’ 

provision in the rule to exclude 

stationary combustion sources other 

than the largest units at a facility. 

Response: The final rule contains no 

de minimis exclusions. However, to 

simplify reporting, the rule allows small 

units to be aggregated and reported as a 

single emissions value, if certain 

conditions apply. The final rule has 

expanded the availability of this 

provision. The proposed rule limited 

the aggregation of any one group to a 

combined maximum capacity of 250 

mmBtu/hour heat input. The final rule 

removes this limit and allows grouping 

of any units that individually are less 

than 250 mmBtu/hour heat input. EPA 

has also clarified the use of the common 

pipe metering option, so that all 

stationary combustion units at a facility 

using the same fuel that is metered 

through a common supply line may 

report a single emissions value under 

this rule. In addition, the changes listed 

above in Section III.C.2 of this preamble 

will simplify emissions calculations for 

many combustion units. 

Method for Calculating GHG Emissions 

Comment: EPA received numerous 

comments on the proposed GHG 

calculation methods for stationary 

combustion sources. Most of the 

comments centered on the use of the 

four-tiered approach for calculating CO2

emissions. Several commenters 

requested that EPA remove the 250 

mmBtu/hr unit size restriction on the 

use of Tier 1 and 2 calculation methods, 

especially for the combustion of 

relatively homogeneous fuels such as 

natural gas and fuel oil. Objections were 

raised to the specified frequency of fuel 

sampling under Tiers 2 and 3, as being 

excessive and unnecessary. Two 

commenters recommended that annual 

sampling be allowed for natural gas and 

fuel oil. A number of commenters asked 

the Agency to allow averaging of fuel 

sampling results (to simplify the CO2

emissions calculations) and to affirm 

that the use of fuel sampling results 

provided by the fuel supplier is 

permissible. Others sought confirmation 

that fuel billing meters could be used to 

quantify fuel usage. Multiple 

commenters asked EPA to clarify who 

must use the Tier 4 calculation method, 

which requires the use of continuous 

emission monitoring systems (CEMS) to 

measure stack gas flow rate and CO2

concentration. A number of comments 

were received requesting that sources 

currently monitoring and reporting heat 

input data under 40 CFR Part 75, but not 

reporting CO2 mass emissions, be 

allowed to implement established Part 

75 CO2 emissions calculation methods 

in lieu of using Tiers 1 through 4. 

Finally, EPA received diverse comments 

on the proposed calculation method for 

CH4 and N2O emissions. Several 

commenters recommended that these 

emissions either not be reported at all, 

or that emissions reporting should be 


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excluded for certain fuel types. Others 

asked for flexibility in determining the 

appropriate emission factors for CH4

and N2O. Some suggested that the use 

of operator-defined emission factors or 

factors from other GHG registries should 

be allowed. 

Response: The final rule significantly 

expands the use of Tier 1 and Tier 2 

calculation methodologies. All units 

rated at 250 mmBtu/hr or less are 

allowed to use the Tier 1 or Tier 2 

calculation methodologies, depending 

on fuel sampling provisions at either the 

facility or by the supplier of the fuel. In 

addition, units rated at over 250 

mmBtu/hr that combust pipeline quality 

natural gas and distillate oil are allowed 

to use the Tier 2 calculation 

methodology, because of the 

homogeneous nature and low variability 

in the characteristics of these fuels. 

However, the 250 mmBtu/hr unit size 

cutoff remains for units that combust 

residual oil, other gaseous fuels, and 

solid fossil fuel. 

The mandatory monthly fuel 

sampling and analysis requirements for 

traditional fossil fuels have been 

dropped from Tiers 2 and 3. EPA agrees 

with the commenters that for a 

homogeneous fuel such as pipeline 

natural gas, monthly sampling is not 

necessary. Therefore, 40 CFR 98.34 has 

been revised to require that natural gas 

be sampled semiannually. For other 

fuels such as oil and coal, which are 

delivered in shipments or lots, requiring 

monthly sampling may be impractical, 

because new fuel lots or deliveries may 

not be received on a monthly basis. For 

fuel oil and coal, a representative 

sample is required for each fuel lot, i.e., 

for each shipment or delivery. For other 

liquid fuels and biogas, quarterly 

sampling is required. For solid fuels 

other than coal, excluding MSW, weekly 

composite sampling with monthly 

analysis is required. For gaseous fuels 

other than natural gas and biogas, the 

daily sampling requirement has been 

retained, but only for facilities with 

existing equipment in place that is 

capable of providing the data. 

Otherwise, weekly sampling is required 

if such equipment for daily sampling is 

not installed. 

The final rule clarifies that fuel 

sampling and analysis data provided by 

the supplier may be used in the 

emission calculations, and that fuel 

billing meters may be used to quantify 

fuel consumption. To simplify the 

emission calculations in Tiers 2 and 3, 

arithmetic averaging of higher heating 

value and carbon content data over the 

reporting year is permitted if these data 

are collected less frequently than 

monthly (see Equation C–2b in 40 CFR 

98.33). However, regardless of the 

sampling frequency required by the 

rule, reporters must use the results of all 

available valid fuel analyses in the 

emissions calculations. 

Today’s rule clarifies the applicability 

of the Tier 4 methodology. Many 

commenters were unsure whether only 

one or all six of the conditions listed in 

proposed 40 CFR 98.33(b)(4)(ii) and all 

three of the conditions listed in 

proposed 40 CFR 98.33(b)(4)(iii) must be 

met to trigger the requirement to use 

CEMS. EPA’s intent has always been 

that a source must meet all conditions 

listed in those sections to require the 

use of Tier 4. This has been made clear 

in the final rule text. 

The final rule adds two methods that 

can be used as alternatives to any of the 

four tier calculation methods. These 

alternative methods apply to sources 

that are currently required to monitor 

and report heat input data according to 

40 CFR part 75, but are not required to 

report CO2 mass emissions. Many units 

subject to the Clean Air Interstate 

Regulation (CAIR) are in this category. 

These alternative methods allow these 

sources to use their 40 CFR part 75 heat 

input data together with one of the CO2

emissions calculation methodologies in 

part 75 to meet 40 CFR part 98 CO2

emissions reporting requirements. For 

instance, sources monitoring hourly 

heat input according to Appendix D of 

40 CFR part 75 may use Equation G–4 

in Appendix G of 40 CFR part 75 to 

calculate CO2 emissions. Similarly, low 

mass emitting sources monitoring heat 

input under 40 CFR 75.19 may use 

Equation LM–11 in 40 CFR 75.19 to 

calculate CO2 emissions. Sources using 

40 CFR part 75 flow rate and CO2 CEMS 

to continuously monitor heat input may 

use the CEMS measurements together 

with an appropriate equation from 

Appendix F of 40 CFR part 75 to 

determine CO2 mass emissions. 

The methodology for calculating CH4

and N2O emissions has been clarified in 

the final rule. Reporting of these 

emissions is required only for the fuels 

listed in Table C–2 of 40 CFR part 98, 

subpart C. Further, reporting of CH4 and 

N2O emissions is required only for units 

that are required to report CO2

emissions under 40 CFR part 98, subpart 

C and only for fuels for which default 

emission factors are provided in subpart 

C. The emission factors in Table C–2 of 

40 CFR part 98, subpart C are both fuelspecific and heat input-based. 

Therefore, when more than one type of 

fuel is combusted in a unit, direct 

measurements or engineering estimates 

of the annual heat input from each fuel 

are needed to calculate the CH4 and N2O 

emissions. Consequently, when CEMS 

(which are not fuel-specific) are used to 

monitor the CO2 emissions and heat 

input for a multi-fuel unit, the total heat 

input measured by the CEMS must be 

apportioned to each fuel type. The 

owner or operator should use the best 

available information (e.g., fuel feed 

rates, high heat values) to do the 

necessary heat input apportionment. To 

provide greater consistency in reporting, 

EPA has chosen to retain the 

requirements for using the default 

factors in Table C–2 of 40 CFR part 98, 

subpart C, rather than allow reporters to 

select their own emission factors. 

Procedures for Estimating Missing Data 

Comment: EPA received several 

requests to modify the proposed missing 

data substitution procedures in 40 CFR 

part 98, subpart C. One commenter 

recommended that a minimum data 

capture requirement should be specified 

rather than requiring the use of 

substitute data to fill in missing data 

gaps. Another commenter suggested that 

only the ‘‘before’’ value be used for data 

substitution, rather than the average of 

the quality-assured values before and 

after the missing data period. Others 

favored using emission factors or the 

‘‘best available estimates’’ for all 

parameters, rather than following a 

prescriptive missing data algorithm. 

Finally, several commenters asserted 

that 40 CFO part 75 missing data 

procedures for CO2 are too conservative 

(i.e., may overestimate emissions 

significantly) and seem to be contrary to 

the objectives of 40 CFR part 98. 

Response: The final rule provides 

additional flexibility to the missing data 

provisions of 40 CFR part 98, subpart C. 

The rule requires the use of ‘‘before and 

after’’ average values for only three 

parameters (fuel HHV, carbon content, 

and molecular weight). If the ‘‘after’’ 

value is not yet available when the GHG 

emissions report is due, the ‘‘before’’ 

value may be used for missing data 

substitution. For all other parameters, 

the reporter can substitute data values 

that are based on the best available 

estimates, based on all available process 

information. 

EPA does not agree with the 

commenters who believe that the 40 

CFR part 75 CO2 missing data 

procedures are too conservative and 

contrary to 40 CFR part 98 program 

objectives. Nearly all 40 CFR part 75 

sources maintain very high monitor data 

availability (95 percent or better) and 

use very little substitute data. Only 

when the data availability drops below 

80 percent (which very seldom occurs) 

are the substitute data values 

significantly higher than the true CO2

concentrations. Therefore, sources that 


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monitor CO2 emissions according to 40 

CFR part 75 should continue to use the 

standard part 75 missing data 

provisions, and no adjustments to those 

substitute data values are deemed 

necessary for 40 CFR part 98 reporting 

purposes. 

Data Reporting Requirements 

Comment: A number of commenters 

objected to the amount of unit-level data 

and emissions verification information 

that is required to be reported 

electronically under 40 CFR 98.36 as 

‘‘burdensome’’, ‘‘unnecessary,’’ and 

‘‘excessive.’’ The commenters 

recommended that the auxiliary 

information should instead be kept on 

file and made available to EPA upon 

request. Several commenters 

recommended that EPA remove the 250 

mmBtu/hr limit on the cumulative heat 

input capacity of units that can be 

aggregated into groups for reporting 

purposes. Other commenters asserted 

that EPA should consider the 40 CFR 

part 75 emissions data submitted under 

the ARP to be sufficient to satisfy 40 

CFR part 98 requirements, and that 

there is no need to submit the same data 

twice. 

Response: EPA does not agree with 

the assertion that the amount of unitlevel data to be reported is excessive, 

burdensome, or unnecessary. For this 

mandatory GHG emissions reporting 

rule, two approaches to emissions data 

verification were considered, EPA 

verification and third-party verification. 

The Agency decided on EPA emissions 

verification. To verify GHG emissions 

estimates, EPA needs supporting data 

that are reported at the same level as the 

emissions are calculated. Because the 

rule requires that emissions be 

calculated at the unit level, it is 

imperative for EPA to obtain unit level 

verification data, particularly given the 

variety of requirements for estimating 

fuel combustion emissions under 40 

CFR part 98, subpart C. Subpart C 

provides four different methods of 

estimating CO2 emissions. The four 

methods require measurement of 

different parameters to estimate 

emissions, and the use of the methods 

is conditioned on a variety of operating 

factors. In addition, facilities use fuel 

combustion units of a variety of 

different sizes, types, and fuel firing 

scenarios. Under these circumstances, 

EPA could not verify that the correct 

methods were selected or applied 

correctly without unit-level data. If unitlevel data were not submitted or were 

aggregated at a gross level, EPA could 

not reasonably verify the accuracy of 

reported facility-wide GHG emissions 

data, because EPA could not evaluate 

the relationship between unit capacity, 

fuel characteristics, fuel consumption, 

and emissions. However, as explained 

below, in the final rule EPA has made 

a number of significant adjustments to 

the data reporting requirements to 

clarify requirements and to reduce the 

reporting burden. 

First, for units that use Tiers 1, 2 and 

3 to calculate CO2 mass emissions, the 

cumulative 250 mmBtu/hr heat input 

capacity limit on the aggregation of 

units into groups has been dropped. 

Rather, the 250 mmBtu/hr restriction 

applies only to the individual units in 

a group. Therefore, for reporting 

purposes, individual units with 

maximum rated heat input capacities of 

250 mmBtu/hr or less may be aggregated 

without limit into a single group, 

provided that the Tier 4 methodology is 

not required for any of the units, and all 

units in the group use the same 

calculation methodology for any 

common fuels that they combust. Units 

with maximum rated heat inputs greater 

than 250 mmBtu/hr using Tiers 1, 2, and 

3 must report as individual units, unless 

they burn the same type of fuel and the 

fuel is provided by a common pipe or 

supply line. In that case, the owner or 

operator may opt to aggregate emission 

for all units fed by the common fuel 

line. Units using Tier 4 must report as 

individual units unless they share a 

monitored common stack. 

Second, the rule requires minimal 

data to be reported for units that 

monitor and report emissions and heat 

input data according to 40 CFR part 75. 

Units that meet these criteria include 

units that are subject to the ARP, and 

potentially units that are subject to 

CAIR, and other programs. The final 

rule clarifies that 40 CFR part 75 sources 

must report 40 CFR part 98 GHG 

emissions data under the exact same 

unit, stack, or pipe ID numbers that are 

used for electronic reporting in the part 

75 programs (e.g., 1, 2, CT5, CS001, 

MS1A, CP001, etc.). Even though most 

40 CFR part 75 sources report CO2 mass 

emissions data to EPA year-round, these 

data alone are not sufficient to satisfy 

the Part 98 reporting requirements for 

the following reasons. The emissions 

reports required under 40 CFR part 98 

are facility-wide reports that require 

GHG emissions from all stationary 

combustion units at the facility, whether 

or not the units are subject to a 40 CFR 

part 75 program. Many electricity 

generating facilities have both ARP 

units and non-ARP units on site. 

Further, the CO2 emissions data 

reported under 40 CFR part 75 are in 

units of short tons; Part 98 requires 

reporting in metric tons. Finally, 40 CFR 

part 98 also requires CH4 and N2O 

emissions to be reported, neither of 

which are reported under any 40 CFR 

part 75 program. 

Third, the required verification data 

have been clarified and, in some cases, 

differ substantively from the proposed 

rule. No additional verification 

information is required for sources that 

monitor and report emissions and heat 

input data using 40 CFR part 75. This 

includes sources that elect to use the 

new alternative calculation 

methodologies for units monitoring heat 

input year round according to 40 CFR 

part 75 programs. For sources using 

Tiers 1, 2, 3, and 4, the final rule 

streamlines some of the reporting. 

Sources using Tier 3 are required to 

report only monthly averages of fuel 

carbon content and molecular weight 

rather than the proposed requirement to 

submit the results of each individual 

determination. Sources that use Tier 4 

are required to report quarterly 

cumulative CO2 mass emissions, rather 

than daily CO2 emissions, as proposed. 

Also, to address concerns raised by 

some of the commenters, certain data 

elements need only be retained on file 

and provided to EPA upon request. 

These data elements include the 

methods used for fuel sampling and 

analysis, the methods used to calibrate 

fuel flow meters, the dates and results 

of fuel flow meter calibrations, and the 

dates and results of CEMS certification 

tests and on-going QA tests of the 

CEMS. 

D. Electricity Generation 

1. Summary of the Final Rule 

Source Category Definition. This 

source category consists of EGUs that 

are subject to the ARP and any other 

EGUs that are required to monitor and 

report to EPA CO2 mass emissions yearround according to 40 CFR part 75. All 

other EGUs are part of the general 

stationary fuel combustion source 

category and report under 40 CFR part 

98 subpart C, if the facility meets the 

reporting rule applicability criteria. This 

source category excludes portable 

equipment, emergency generators, and 

emergency equipment. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Report annual CO2, 

N2O, and CH4 mass emissions from each 

EGU. 

GHG Emissions Calculation and 

Monitoring. For EGUs subject to the 

ARP and other EGUs that are required 

to monitor and report to EPA CO2 mass 

emissions year-round according to 40 


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CFR part 75, the reporter must continue 

to monitor CO2 emissions according to 

40 CFR part 75. The cumulative CO2

mass emissions reported in the fourth 

quarter electronic data reports must be 

converted from short tons to metric 

tons, for 40 CFR part 98 reporting 

purposes. The N2O and CH4 emissions 

must be calculated using fuel-specific 

default emission factors and heat input 

measurements in accordance with 40 

CFR 98.33(c) in subpart C (General 

Stationary Fuel Combustion Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit unitlevel data and other information that are 

used to verify the reported GHG 

emissions. The additional data and 

information to be reported for this 

source category are specified in 40 CFR 

98.46. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. The specific records that 

must be retained for this source category 

are identified in 40 CFR 98.47. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart D: Electricity 

Generation.’’ 

• The source category has been more 

precisely defined and includes only 

EGUs subject to the ARP and any other 

EGUs that are required to monitor and 

report to EPA CO2 mass emissions yearround according to 40 CFR part 75. 

• The proposed emergency generator 

exclusion language no longer requires 

that emergency generators be identified 

as such in State or local air permits. 

• A CO2 calculation methology was 

provided for units that are not in the 

ARP, but report CO2 mass emissions 

year-round using 40 CFR part 75 

methodologies. 

3. Summary of Comments and 

Responses 

Definition of Source Category 

Comment: Several commenters were 

concerned that covering non-ARP EGUs 

in both subparts C and D of proposed 40 

CFR part 98 was confusing and 

repetitive. Several commenters stated 

that the definition of an EGU is too 

inclusive and recommended that EPA 

revise it. The commenters were 

concerned that any unit, regardless of 

electrical output, could be identified as 

an EGU and place a facility in the 

electricity generation source category. 

One commenter suggested that a 25 

megawatts (MW) threshold should be 

added to the EGU definition in 40 CFR 

98.6 and to 40 CFR part 98, subpart D. 

A multitude of commenters objected to 

the language in proposed 40 CFR 98.40 

requiring emergency generators to be 

designated as such in a State or local air 

permit, in order for the generators to be 

exempted from GHG emissions 

reporting. Many of these same 

commenters recommended changes to 

the definition of ‘‘emergency generator’’ 

in 40 CFR 98.6, suggesting that the term 

‘‘generator’’ should be replaced with the 

term ‘‘reciprocating internal combustion 

engine (RICE)’’, to be consistent with 40 

CFR 63.6675, subpart ZZZZ. Others 

recommended that EPA should also 

exempt emergency equipment such as 

fire pumps, fans, etc. from GHG 

emissions reporting. 

Response: The electricity generation 

source category definition in subpart D 

(40 CFR 98.40) has been modified based 

on the comments received. The final 

rule limits the source category to EGUs 

that are subject to ARP and to other 

EGUs that monitor and report to EPA 

CO2 mass emissions year-round 

according to 40 CFR part 75. The final 

subpart D does not cover any other 

EGUs. The GHG emissions from other 

EGUs are covered under subpart C 

(General Stationary Fuel Combustion). 

The definition of an ‘‘emergency 

generator’’ in 40 CFR 98.6, the final rule 

has been changed to clarify that it 

includes both RICE and turbines. EPA 

has also added a definition of 

‘‘emergency equipment’’ to 40 CFR 98.6, 

and exempts such equipment from GHG 

emissions reporting under both 40 CFR 

part 98, subparts C and D. 

The proposed requirements in 40 CFR 

part 98, subparts C and D for emergency 

generators to be identified as such in 

State and local air permits in order to be 

exempt from GHG emissions reporting 

has been revised. There is considerable 

variation from State to State regarding 

the regulation of emergency generators, 

including whether or not permits are 

required. Some States specifically 

exempt emergency generators from 

permitting requirements. Other States 

use a permit by rule approach for 

emergency units. In view of this, the 

Agency has revised the wording of the 

exclusion for emergency generators to 

allow for situations where they are not 

specifically identified in a facility’s 

permit. 

Method for Calculating GHG Emissions 

Comment: Several commenters 

suggested that for units that are not in 

the ARP but are required by other 

regulatory programs to report part 75 

emissions and heat input data, EPA 

should expand the four-tiered 

calculation method for CO2 mass 

emissions in 40 CFR 98.33(a) to allow 

the use of CO2 emissions calculation 

methods based on Appendices D and G 

of part 75. 

Response: The electricity generation 

source category definition has been 

narrowed to only include EGUs that are 

subject to ARP and to other EGUs that 

monitor and report to EPA CO2 mass 

emissions year-round according to 40 

CFR part 75 (e.g., RGGI units). The final 

subpart D provides a CO2 calculation 

methodology for such EGUs that are not 

in the ARP, but report to EPA CO2 mass 

emissions year-round using part 75 

methodologies. For the purposes of part 

98, the CO2 emissions from these units 

are calculated and reported using the 

same methods as part 75. 

Other units that are not in the ARP 

but report data under part 75, subpart C 

are now covered by 40 CFR part 98, 

subpart C instead of subpart D, and 

subpart C has been revised to allow the 

use of part 75 calculation 

methodologies. The response to the 

comment on these units is contained in 

Section III.C of this preamble (General 

Stationary Fuel Combustion Sources). 

E. Adipic Acid Production 

1. Summary of the Final Rule 

Source Category Definition. The 

adipic acid production source category 

consists of all processes that use 

oxidation to produce adipic acid. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Report N2O process 

emissions from adipic acid production. 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. For example, 

report CO2, N2O, and CH4 emissions 

from each stationary combustion unit on 

site under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and 

Monitoring. Unless an alternative 

method of determining N2O emissions is 

requested, calculate N2O process 

emissions from adipic acid production 


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by multiplying a facility-specific 

emission factor by the annual adipic 

acid production level. Determine the 

facility-specific emission factor by an 

annual performance test to measure N2O 

emissions from the waste gas stream of 

each oxidation process and the 

production rate recorded during the test. 

When N2O abatement devices (such as 

nonselective catalytic reduction) are 

used, adjust the N2O process emissions 

for the amount of N2O removed using 

the destruction efficiency for the control 

device and the fraction of annual 

production for which the control device 

is operating. The destruction efficiency 

can be specified by the abatement 

device manufacturer or can be 

determined using process knowledge or 

another performance test. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart E. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

E. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found in this 

section or ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart E: Adipic 

Acid Production.’’ 

• The re-testing trigger was changed. 

Performance testing to determine the 

N2O emissions factor is required 

annually, whenever the ratio of 

cyclohexanone to cyclohexanol is 

changed, and when new abatement 

equipment is installed. 

• Equation E–2 was edited to correct 

a calculation error and to allow multiple 

types of abatement technologies. 

• 40 CFR 98.56 was reorganized and 

updated to improve the data reporting 

requirements as needed for the 

emissions verification process. Some 

data elements were moved from 40 CFR 

98.57 to 40 CFR 98.56, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.53 were added to 40 CFR 98.56 

for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments on adipic acid 

production were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart E: Adipic 

Acid Production.’’ 

GHGs To Report 

Comment: Multiple commenters 

asked that the language in 40 CFR 

98.52(b) be clarified to include 

emissions under 40 CFR part 98, subpart 

E only from units that are 100 percent 

dedicated to adipic acid production to 

avoid double counting of combustion 

emissions. 

Response: We reviewed this issue but 

decided not to make any changes to 40 

CFR part 98, subpart E. We do not 

foresee a potential for double counting 

of combustion emissions at the facility 

because all combustion unit emissions 

at adipic acid facilities are to be 

reported under 40 CFR part 98, subpart 

C. 40 CFR part 98, subpart E provides 

methods for reporting only the process 

N2O emissions. Also see Section III.C of 

this preamble for responses to 

comments related to 40 CFR part 98, 

subpart C (General Stationary 

Combustion). 

Selection of Proposed GHG Emissions 

Calculations and Monitoring Methods 

Comment: One commenter stated that 

emissions of N2O do not correlate with 

the production of adipic acid at their 

facility. A portion of the process off gas, 

which contains N2O, is sold to an offsite 

facility via dedicated piping. The 

amount sold depends on customer 

needs and the amount is metered. The 

commenter asked that the language in 

the final rule address this issue. 

Response: We agree that N2O emitted 

from the production of adipic acid that 

is sold or transferred offsite is not 

covered in the proposed rule. The final 

rule has been changed to require this 

amount of N2O to be reported. Allowing 

for this additional reporting requirement 

ensures that the reported N2O emissions 

attributed to the adipic acid facility are 

accurate. Reporting of the N2O sold or 

transferred offsite will help EPA 

improve methodologies for reporting of 

GHG emissions. 

Method for Calculating GHG Emissions 

Comment: Multiple commenters 

asked that the requirement to repeat the 

annual performance test be removed. In 

the proposal, re-testing was triggered 

whenever the adipic acid production 

rate changed by more than 10 percent. 

Commenters asserted that production 

depends on demand for adipic acid and 

often varies by 15 percent. 

Response: Upon review, we decided 

to eliminate re-testing. We believe that 

annual determination of the N2O 

emissions factor is sufficient to 

accurately calculate N2O emissions as 

long as the production equipment 

remains consistent over the year-long 

period (i.e. no new abatement 

technology). 

Comment: Multiple commenters 

asked that alternative methods be 

allowed for calculating N2O emissions 

from adipic acid production. 

Specifically the commenters asked that 

EPA allow the use of N2O and flow 

CEMS to directly measure N2O 

emissions and use the performance test 

to evaluate the CEMS accuracy. The 

commenters also asked that EPA allow 

the use of existing process flow meters 

and process N2O analyzers to determine 

the amount of N2O sent to control 

devices and use the performance test to 

measure control device destruction 

efficiency. 

Response: We agree that there are 

other means of determining site-specific 

N2O emissions. The final rule has been 

changed to allow alternative test 

methods. Any alternative must be 

approved by the Administrator before 

being used to comply with this rule. An 

implementation plan that details how 

the alternative method will be 

implemented must be included in the 

request for the alternative method. Until 

the method is approved facilities must 

use the alternatives proposed in the rule 

for a performance test. As one 

commenter noted, at minimum the 

performance test will help to QA/QC 

alternative methods currently used to 

monitor N2O emissions (such as N2O 

CEMS). 

EPA understands the need to further 

evaluate and establish alternative 

comparable methods for sources to use 

in accurately calculating N2O emissions 

from adipic production and will address 

in future rulemakings or amendments to 

rulemaking. 

The final rule does allow the use of 

existing process flow meters and 

process knowledge in the determination 

of the destruction factor of N2O 

abatement technologies. This parameter 

is often based on site-specific 

knowledge and operations. We believe 


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that using existing methods can also 

reduce the potential cost impacts of this 

rulemaking and that it is in the best 

interest of the facilities that process 

parameters be accurately measured. 

Comment: One commenter asked that 

Equation E–2 be edited to follow the 

summation format used in the IPCC Tier 

2 methodology. The current format does 

not allow for multiple abatement 

technologies (including no abatement). 

Response: We agree with the 

commenter. The equation in the 

proposed rule contained an error and 

did not allow for multiple abatement 

technologies. The final rule contains a 

corrected version of the equation. 

F. Aluminum Production 

1. Summary of the Final Rule 

Source Category Definition. The 

aluminum production source category 

consists of facilities that manufacture 

primary aluminum using the HallHe ́roult manufacturing process. The 

primary aluminum manufacturing 

process consists of the following 

operations: 

• Electrolysis in prebake and 

S<derberg cells. 

• Anode baking for prebake cells. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For aluminum 

production, report: 

• Perfluoromethane (CF4) emissions 

and perfluoroethane (C2F6) emissions 

from anode effects in all prebake and 

S<derberg electrolysis cells combined. 

• CO2 emissions from anode 

consumption during electrolysis in all 

prebake and S<derberg cells. 

• All CO2 emissions from anode 

baking. 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. For example, 

report CO2, N2O, and CH4 emissions 

from each stationary combustion unit on 

site under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and 

Monitoring. Reporters must calculate 

process emissions using the following 

methods: 

• CF4 from anode effects: Calculate 

annual CF4 emissions based on the 

frequency and duration of anode effects 

in the aluminum electrolytic reduction 

process for each prebake and S<derberg 

electrolysis cell using the following 

parameters: 

—Anode effect minutes (AEM) per cellday calculated monthly. 

—Aluminum metal production 

calculated monthly. 

—A slope coefficient relating CF4

emissions to anode effect minutes per 

cell-day and aluminum production. 

The slope coefficient is specific to 

each smelter and must be measured in 

accordance with the protocol 

specified in the rule at least once 

every 10 years. 

—Facilities are allowed to use historic 

smelter-specific slope coefficients for 

the first three years of reporting under 

the rule. Historic measurements 

include all those made under EPA’s 

Voluntary Aluminum Industry 

Partnership or at facilities owned or 

operated by companies participating 

in the Voluntary Aluminum Industry 

Partnership. Facilities without 

historic measurements are required to 

complete measurements by the end of 

first year of reporting. 

—Facilities which operate at less than 

0.2 anode effect minutes per cell day 

or, when overvoltage is recorded, 

operate with less than 1.4mV 

overvoltage, can use either smelterspecific measured slope coefficients 

or the technology-specific (Tier 2) 

default coefficients from Volume III, 

Chapter 4, Section 4.4 Metal Industry 

Emissions of the 2006 IPCC 

Guidelines for National Greenhouse 

Gas Inventories as specified in the 

rule. 

• C2F6 from anode effects: Calculate 

annual C2F6 emissions from anode 

effects from each prebake and S<derberg 

electrolysis cell using the calculated CF4

emissions and the mass ratio of C2F6 to 

CF4 emissions, as determined during the 

same test during which the slope 

coefficient is determined. 

• Process CO2 emissions—general 

approaches. Most reporters can elect to 

calculate and report process CO2

emissions from anode consumption 

during electrolysis and from anode 

baking by either (1) installing and 

operating CEMS and following the Tier 

4 methodology (in 40 CFR part 98, 

subpart C) or (2) using the calculation 

procedures specified below. 

• However, if process CO2 emissions 

from anode consumption during 

electrolysis or anode baking are emitted 

through the same stack as a combustion 

unit or process equipment that uses a 

CEMS and follows Tier 4 methodology 

to report CO2 emissions, then the CEMS 

must be used to measure and report 

combined CO2 emissions from that 

stack, instead of using the calculation 

procedures specified below. 

• CO2 emissions from anode 

consumption in prebake cells: Calculate 

annual CO2 emissions at the facility 

level using a mass balance equation 

based on measurements of the following 

parameters: 

—Net prebaked anode consumption rate 

per metric ton of aluminum metal 

produced. 

—Ash and sulfur contents of the anodes. 

—Total mass of aluminum metal 

produced per year for all prebake 

cells. 

• CO2 emissions from S<derberg cells: 

Calculate CO2 emissions from paste 

consumption in S<derberg cells using a 

mass balance equation at the facility 

level based on the following parameters: 

—Paste consumption rate per metric ton 

of aluminum metal produced and the 

total mass of aluminum metal 

produced per year for all S<derberg 

cells. 

—Emissions of cyclohexane-soluble 

matter per metric ton of aluminum 

produced. 

—Binder content of the anode paste. 

—Sulfur, ash, and hydrogen contents of 

the coal tar pitch used as the binder 

in the anode paste. 

—Sulfur and ash contents of the 

calcined coke used in the anode paste. 

—Carbon in the skimmed dust from the 

cell, per metric ton of aluminum 

produced. 

• CO2 emissions from anode baking 

of prebake cells: Calculate CO2

emissions at the facility level separately 

for pitch volatiles combustion and for 

bake furnace packing material. 

• To calculate CO2 emissions from 

the pitch volatiles, use a mass balance 

equation based on the following 

parameters: 

—Initial weight of the green anodes. 

—Mass of hydrogen in the green anodes. 

—Mass of the baked anodes. 

—Mass of waste tar collected. 

• To calculate CO2 emissions from 

bake furnace packing material, use a 

mass balance equation based on the 

following parameters: 

—Packing coke consumption rate per 

metric ton of baked anode production. 

—Sulfur and ash contents of the packing 

coke. 

• The variables used to calculate CO2

emissions from anode and paste 

consumption (e.g., sulfur, ash, and 

hydrogen contents) can be determined 

for each facility, or the source can use 

default values from the 2006 IPCC 

Guidelines for National Greenhouse Gas 

Inventories as specified in 40 CFR 

98.64. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 


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additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart F. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

F. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart F: 

Aluminum Production.’’ 

• A new subsection was added in 40 

CFR 98.63 providing a new equation 

(Eq. F–1) to sum monthly PFC emission 

values into annual PFC emission value. 

• The equation for CO2 emissions 

from S<derberg cells (paste 

consumption) was corrected. 

• Language was updated to request 

reporting of all CO2 emissions from onsite anode baking. 

• Language was updated to request 

reporting of smelter-specific slope 

coefficients (plural). 

• A new equation was added in 40 

CFR 98.63 (Eq. F–3) to calculate CF4

emissions from overvoltage; and 

updated language in subsequent 

sections to accommodate the 

overvoltage method. 

• Language was added to permit 

facilities that operate with low anode 

effect minutes or low overvoltages to 

use IPCC Tier 2 default slope factors. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Three comments on aluminum 

production were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart F: 

Aluminum Production.’’ 

Comment: Several commenters 

suggested that smelters should be 

permitted to use International 

Aluminum Institute default slope 

coefficients which are based on global 

technology-specific averages to calculate 

PFC emissions, especially at high 

performance facilities. 

Response: The use of smelter-specific 

slope coefficients as required in the rule 

leads to significantly more precise PFC 

emission calculations than the use of 

default slope coefficients (95 percent 

confidence interval of ±15 compared to 

±50 percent). For a typical U.S. smelter 

emitting 175,000 metric tons of CO2-eq 

in PFCs, these errors result in absolute 

uncertainties of ±88,000 MTCO2e and 

±26,000 MTCO2e, respectively. The 

reduction in uncertainty associated with 

moving from default to smelter-specific 

slope coefficients, 62,000 MTCO2e, is as 

large as the emissions from many of the 

sources that would be subject to the 

rule. However, for ‘‘high performance’’ 

facilities, which are defined by the 2006 

IPCC Guidelines as those at or below 0.2 

anode effect minutes per cell day or less 

than 1.4 mV overvoltage, the IPCC 

analysis indicates that impact of moving 

from a Tier 2 to a Tier 3 slope 

coefficient would not result in a 

significant improvement in PFC 

emissions. Therefore, EPA agrees that 

high performance facilities should be 

allowed to use technology specific (Tier 

2) default values from Volume III, 

Chapter 4, Section 4.4 Metal Industry 

Emissions of the 2006 IPCC Guidelines 

for National Greenhouse Gas 

Inventories. These values are identical 

to the ‘‘Aluminum Sector Greenhouse 

Gas Protocol (Addendum to the WRI/ 

WBCSD Greenhouse Gas Protocol),’’ 

October 2006 default coefficients. 

Comment: Several commenters argued 

the requirement to re-measure smelterspecific slope coefficients every three 

years is expensive and unnecessary. 

Response: While the cost to require 

smelter-specific slope coefficients is 

significantly greater than the cost to use 

default slope coefficients, the benefit of 

reduced uncertainty is considerable, as 

noted above. The costs that would be 

incurred by smelters measuring slope 

factors are discussed in the Regulatory 

Impact Analysis (RIA) for the proposed 

rulemaking (EPA–HQ–OAR–2008– 

0508–002). 

Of the currently operating U.S. 

smelters, all but one has measured a 

smelter specific coefficient at least once; 

and at least three used the 2003 EPA/IAI 

protocol for measuring smelter-specific 

slope coefficients. 

The USEPA/IAI Protocol for 

Measurement of Tetrafluoromethane 

and Hexafluoroethane from Primary 

Aluminum Production establishes 

guidelines to ensure that measurements 

of smelter-specific slope-coefficients are 

consistent and accurate (e.g., 

representative of typical smelter 

operating conditions and emission 

rates). The Protocol currently 

recommends that smelter operators remeasure their slope coefficients at least 

every three years, and more frequently 

if they adopt changes to process control 

algorithms or observe changes to typical 

anode effect duration. Specifically, the 

Protocol recommends that operators 

repeat measurements of slope 

coefficients for CF4 and C2F6 if one or 

more of the following apply: (1) Thirtysix months have passed since the last 

measurements (i.e., triennial 

measurements are recommended); (2) a 

change occurs in the control algorithm 

that affects the mix of types of anode 

effects or the nature of the anode effect 

termination routine; and, (3) changes 

occur in the distribution of duration of 

anode effects (e.g. when the percentage 

of manual kills changes or if, over time, 

the number of anode effects decreases 

and results in a fewer number of longer 

anode effects). 

Changes to process control algorithms 

or to the typical duration of anode 

effects can change the relationship 

between anode effect minutes, 

production, and emissions, that is, they 

can change slope coefficients. In 

addition, more subtle changes can also 

change slope coefficients over time. 

According to industry experts, the rate 

of these more subtle changes has not 

been sufficiently studied to specify a 

frequency for re-measurement nor have 

there been a sufficient number of 

facilities that have been measured 

repeatedly to document the benefit of 

the additional incremental cost of 

measurement once every three years. 

During the past few years, multiple 

U.S. smelters have adopted changes to 

their production process which are 

likely to have changed their slope 

coefficients. These include the adoption 

of slotted anodes and improvements to 

process control algorithms. Although 

some U.S. smelters have recently 

updated their measurements of smelterspecific coefficients, others may not 

have. 

In view of these recent process 

changes, EPA is requiring smelters that 

have not already measured their slope 

factors under the ‘‘2008 USEPA/IAI 

Protocol for Measurement of 

Tetrafluoromethane and 

Hexafluoroethane from Primary 

Aluminum Production,’’ to do so in 

time for the 2013 reporting year. EPA 

believes that this will ensure that slope 

factors are appropriately updated while 

providing sufficient lead-time for 

smelters to perform the measurements 

without encountering excessive costs or 

logistical barriers. However, after this 

initial update, EPA agrees that every 

three years is burdensome, therefore, 


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further updates are required only every 

ten years unless there are major 

technological or process changes at a 

facility such as changes to the control 

algorithm that affect the mix of types of 

anode effects or the nature of the anode 

effect termination routine; or changes 

occur in the distribution of duration of 

anode effects (e.g. when the percentage 

of manual kills changes or if, over time, 

the number of anode effects decreases 

and results in a fewer number of longer 

anode effects). 

Comment: Several commenters 

suggested that the rule should include 

the overvoltage measurement method, 

which is specific to use with Pechiney 

technology, in case one or more U.S. 

smelters decide to adopt this technology 

in the future. 

Response: The Overvoltage Method 

relates PFC emissions to an overvoltage 

coefficient, anode effect overvoltage, 

current efficiency, and aluminum 

production. The overvoltage method 

was developed for smelters using the 

Pechiney technology. While it is EPA’s 

understanding that no U.S. smelters 

have used the Pechiney technology for 

at least a decade, if one or more U.S. 

smelters decide to adopt this 

internationally accepted technology in 

the future they would be expected to 

use the overvoltage method which 

follow the established guidelines in the 

‘‘USEPA/IAI Protocol for Measurement 

of Tetrafluoromethane and 

Hexafluoroethane from Primary 

Aluminum Production.’’ 

G. Ammonia Manufacturing 

1. Summary of the Final Rule 

Source Category Definition. The 

ammonia manufacturing source category 

consists of process units in which 

ammonia is manufactured from a fossilbased feedstock via steam reforming of 

the hydrocarbon. It also includes 

ammonia manufacturing processes in 

which ammonia is manufactured 

through the gasification of solid and 

liquid raw material. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For ammonia 

manufacturing, report the following 

emissions: 

• CO2 process emissions from steam 

reforming of a hydrocarbon or the 

gasification of solid and liquid raw 

material, reported for each ammonia 

manufacturing process unit following 

the requirements of this part. 

• CO2, CH4, and N2O emissions from 

each stationary combustion unit. Report 

these emissions under 40 CFR 98, 

subpart C (General Stationary Fuel 

Combustion Sources) by following the 

requirements of 40 CFR part 98, subpart 

C. 

• For CO2 collected and transferred 

off site, report these emissions under 40 

CFR part 98, subpart PP (Suppliers of 

CO2) following the requirements of 40 

CFR part 98, subpart PP. 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. Reporters must use one of 

two methods to calculate CO2 process 

emissions, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions from 

each ammonia manufacturing process 

unit by either (1) installing and 

operating CEMS and following the Tier 

4 methodology (in 40 CFR part 98, 

subpart C) or (2) using the calculation 

procedures contained in the rule and 

summarized below. 

• However, if process CO2 emissions 

from an ammonia manufacturing 

process unit are emitted through the 

same stack as CO2 emissions from a 

combustion unit or process equipment 

that uses a CEMS and follows Tier 4 

methodology to report CO2 emissions, 

then the CEMS must be used to measure 

and report combined emissions from 

that stack, instead of using the 

calculation procedures described below. 

• To calculate process CO2 emissions, 

use the equations provided in 40 CFR 

part 98, subpart G for solid, liquid, and 

gaseous feedstock and the following 

measurements: 

—Continuous measurement of gaseous 

or liquid feedstock consumed using a 

flowmeter, or monthly aggregate of 

solid feedstock consumed. 

—Carbon content of the feedstock 

(required to be measured monthly 

using supplier data or analysis using 

the appropriate test methods). If 

supplier data are used, facilities must 

QA/QC the supplier analysis on an 

annual basis using the appropriate 

test methods. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart G. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

G. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart G: Ammonia 

Manufacturing.’’ 

• Monitoring and QA/QC 

requirements were revised to allow for 

obtaining carbon content of feedstock 

used in ammonia manufacturing from 

the feedstock supplier. Facilities that 

obtain monthly carbon content 

information from their supplier are 

required to QA/QC supplier information 

through annual sampling and analysis 

of the feedstock. 

• Missing data procedures were 

added under 40 CFR 98.75 for 

parameters that facilities must measure 

such as feedstock consumption, the 

quantity of the waste recycle stream, 

and the monthly carbon content of both 

the feedstock consumption and waste 

recycle stream quantity. 

• Reporting requirements were added 

for the quantity of urea produced and 

the emissions associated with waste 

recycle streams commonly found at 

ammonia manufacturing facilities. 

• 40 CFR 98.76 was reorganized and 

updated to improve the emissions data 

verification process. Some data 

elements were moved from 40 CFR 

98.77 to 40 CFR 98.76, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.73 were added to 40 CFR 98.76 

for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments on ammonia 

manufacturing were received covering 

numerous topics. Several of these 

comments were directed at the 

requirements for 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources), and responses to 

those comments are provided in Section 

III.C of this preamble. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 


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Public Comments, Subpart G: Ammonia 

Manufacturing.’’ 

Method for Calculating GHG Emissions 

Comment: Several commenters asked 

EPA to clarify that ammonia production 

units must use Tier 4 calculation only 

if all of the conditions under proposed 

40 CFR 98.33(b)(5)(ii)(A) through (F) 

apply to the unit and only where the 

ammonia manufacturing unit already 

has installed a stack gas volumetric flow 

rate monitor and a CO2 concentration 

monitor. 

Response: We agree with the 

comment and have modified the text 

under 40 CFR 98.73(a) and (b) to state 

that if a facility operates and maintains 

CEMS that meet the requirements of 40 

CFR 98.33(b)(4)(ii) or (iii), then process 

or combined process and combustion 

CO2 emissions shall be calculated and 

reported under this subpart by following 

the Tier 4 Calculation Methodology 

specified in 40 CFR 98.33(a)(4) and all 

associated requirements for Tier 4 in 40 

CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources). If 

CEMS are not used to determine CO2

emissions from ammonia processing 

units, then facilities must calculate and 

report process CO2 emissions under this 

subpart by using equations provided in 

40 CFR 98.73(b)(1) through (b)(4). CO2

combustion emissions from ammonia 

processing units must be reported under 

40 CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources). 

For additional clarification on the 

requirements on use of CEMS see 40 

CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources), 

and Section III.C of this preamble. 

Comment: One commenter noted that 

most ammonia facilities utilize natural 

gas combustion combined with 

approximately five percent recycle flow 

of gas containing methane from the 

process. The carbon content of the 

recycle stream is already accounted for 

when measuring the feedstock flow rate 

and carbon content to the process. EPA 

should allow ammonia manufacturers to 

exclude this recycle stream in 

calculating combustion emissions, as 

the carbon in the recycle stream would 

be double counted. 

Response: We agreed with 

commenters that it is important to 

account for use of the waste process 

stream in the case that it is recycled 

since carbon in the recycle stream is not 

actually emitted. In response to this 

comment we have added reporting 

requirements for quantifying emissions 

associated with the recycle stream. This 

will help EPA improve methodologies 

for calculating emissions from ammonia 

manufacturing in the future. 

Monitoring and QA/QC Requirements 

Comment: Several commenters stated 

that monthly carbon content sampling 

and analysis requirement is overly 

burdensome. Some commenters asked 

that EPA allow the use of a default value 

for carbon content while one commenter 

suggested use of carbon content data 

generated by the feedstock supplier. 

Response: We agreed with 

commenters that flexibility should be 

added to the rule to allow for use of 

supplier data. This information is 

readily available from the feedstock 

supplier in most cases. The most 

common feedstock for ammonia 

production is pipeline quality natural 

gas. Supplier data on carbon contents of 

feedstock will have sufficient or 

comparable accuracy for the purposes of 

calculating CO2 emissions. We modified 

the monitoring and QA/QC procedures 

in the rule to allow use of carbon 

content data obtained from the 

feedstock supplier(s). Facilities that 

obtain monthly carbon content 

information from their supplier are 

required to QA/QC supplier information 

through annual sampling and analysis 

of the feedstocks consumed. 

Procedures for Missing Data 

Comment: Two commenters suggested 

that the proposed procedures for 

calculating emissions in the event of 

missing feedstock data would yield 

significant overstatements of GHG 

emissions. As proposed, if feedstock 

supply rate data are missing for a 

specific day or days (e.g., if a meter 

malfunctions during unit operation), the 

reporting entity must use the lesser of 

the maximum supply rate that the 

production unit is capable of processing 

or the maximum supply rate that the 

meter can measure. If this substitution 

is applied to the feedstock for reformers 

used in ammonia production, either of 

these proposed approaches would likely 

result in significant over reporting of 

carbon emissions. The commenter 

proposed two alternatives that a 

reporting facility could use: Either 

(1) substitute an estimated value for 

feedstock supply rate, based on the 

arithmetic average of the previous thirty 

days of available feedstock supply rate 

data; or (2) utilize missing data 

estimating procedures similar to the 

procedure under 40 CFR 98.35(b)(2), 

based upon all available process data. 

These approaches would result in much 

more accurate estimates of emissions 

derived from the true historical 

operation of a specific ammonia 

manufacturing source. 

Response: We agreed with 

commenters that the proposed missing 

data procedures would overestimate 

emissions when applied. While some of 

feedstock should be readily available 

and collected as a part of normal 

business practices, circumstances could 

arise where data could be missing. We 

added procedures consistent with the 

commenter’s second recommendation, 

referencing the missing data procedures 

in 98.35(b)(2). Ammonia facilities with 

missing data on feedstock supply rate 

must provide the best available estimate 

from all available process data. 

Facilities must document and keep 

records of missing data procedures 

applied. We find that these revised 

procedures will provide accurate 

information for the purposes of this 

rulemaking. 

Data To Be Reported 

Comment: One commenter noted that 

the CO2 produced through ammonia 

manufacturing can be utilized and that 

much of it is in the manufacture of urea. 

The commenter stated that EPA makes 

unsubstantiated assumptions that all 

CO2 in urea will be released into the 

atmosphere. The commenter asked EPA 

not to tie emissions from applied urea, 

or emissions that result from urea once 

the product has been sold, to the 

producing industry. 

Response: We added reporting 

requirements for annual urea 

production under 40 CFR 98.76. 

Information on urea production will 

help us improve our understanding of 

the quantity of CO2 consumed from 

ammonia production that is used in the 

manufacture of urea. We know from the 

US GHG inventory and subsequent 

conversations with ammonia producers 

that on average it takes 0.733 tons of 

CO2 to produce one ton of urea. We 

have also requested that producers 

report, if known, the uses of the urea 

sold. Collecting information on urea 

production and its uses will help EPA 

to improve methodologies for 

calculating emissions from ammonia 

manufacturing, urea production, and 

urea consumption in the future. 

H. Cement Production 

1. Summary of the Final Rule 

Source Category Definition. The 

cement production source category 

consists of each kiln and each inline 

kiln/raw mill at any Portland cement 

manufacturing facility, including alkali 

bypasses and kilns and inline kilns/raw 

mills that burn hazardous waste. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 


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GHGs to Report. For cement 

production, report the following 

emissions: 

• CO2 process emissions from 

calcination, reported for each kiln. 

• CO2 combustion emissions from 

each kiln. 

• N2O and CH4 emissions from fuel 

combustion at each kiln under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources) using the 

methodologies in subpart C. 

• CO2, N2O, and CH4 emissions from 

each stationary combustion unit other 

than kilns under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources). 

• In addition, report GHG emissions 

for any other source categories for 

which calculation methods are provided 

in other subparts of the rule, as 

applicable. 

GHG Emissions Calculation and 

Monitoring. For CO2 emissions from 

kilns, reporters must select one of two 

methods, as appropriate: 

• For kilns with certain types of 

CEMS in place, reporters must use the 

CEMS and follow the Tier 4 

methodology (in 40 CFR part 98, subpart 

C) to measure and report under the 

Cement Production subpart (40 CFR part 

98, subpart H) combined calcination 

and fuel combustion CO2 emissions. 

• For other kilns, the reporter can 

elect to either (1) install or operate a 

CEMS and follow the Tier 4 

methodology to measure and report 

combined calcination and fuel 

combustion CO2 emissions or (2) 

calculate process CO2 emissions as the 

sum of clinker emissions and emissions 

from raw materials. If using approach 

(2): 

—Calculate clinker emissions monthly 

from each kiln using monthly clinker 

production (required to be measured); 

a kiln-specific, monthly clinker 

emission factor calculated from the 

monthly CaO and MgO content of the 

clinker (required to be measured); 

quarterly cement kiln dust not 

recycled to the kiln (required to be 

measured); and a quarterly kilnspecific factor of calcined material in 

the cement kiln dust not recycled to 

the kiln (measured or default values 

can be used). 

—Calculate raw material emissions 

annually from the annual 

consumption of raw materials and the 

organic carbon content in the raw 

material (measured annually for each 

type of raw material, or a default 

value of 0.2 percent may be used). 

—Report process CO2 emissions from 

each kiln under 40 CFR part 98, 

subpart H (Cement Production), and 

report combustion CO2 emissions 

from each kiln under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

Subpart H (Cement Production). 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

H (Cement Production). 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart H: Cement 

Production.’’ 

• The CO2 calculation equations in 40 

CFR 98.83 were revised to account for 

non-carbonate sources of calcium and 

magnesium in the kiln feed and 

uncalcined carbonates in the product. 

• Methods for monitoring CaO and 

MgO in clinker and CKD were changed 

from XRF to ASTM c114–07, Standard 

Test Methods for Chemical Analysis of 

Hydraulic Cement. 

• 40 CFR 98.84 was revised to clarify 

required monitoring frequency and to 

allow for alternative monitoring 

methods for raw materials and CKD. 

• Missing data procedures were 

added to 40 CFR 98.85 for parameters 

reporters must measure, clinker, CKD 

not recycled to the kiln, raw material 

consumption, carbonate contents of 

clinker CKD, non-calcined content of 

clinker and CKD, and organic carbon 

content of raw materials. 

• Requirements in 40 CFR 98.81 

through 40 CFR 98.87 were revised to 

clarify which requirements apply to 

reporters who elect to report CO2

emissions using CEMS. 

• 40 CFR 98.86 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.87 to 40 CFR 98.86, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.83 were added to 40 CFR 98.86 

for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. We 

received several comments on cement 

production covering a number of topics. 

Many of these comments were directed 

at the requirements for 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources), and responses to 

those comments are provided in Section 

III.C of this preamble dealing with that 

source category. Also see Section II.N of 

this preamble for the response to 

comments on the emissions verification 

approach. 

Responses to significant comments 

received related to process emissions 

from cement production can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart H: Cement 

Production.’’ 

Selection of Threshold 

Comment: One commenter suggested 

that EPA could reduce the burden 

presented by the Proposed Rule by 

reducing the number of facilities 

required to report (i.e., raise the 

reporting thresholds). The commenter 

further noted that by requiring GHG 

reporting for all cement plants, 

regardless of the magnitude of the 

plant’s emissions, EPA removes an 

incentive for those plants to reduce 

GHG emissions to get below a threshold 

in order to avoid the burden of 

monitoring and reporting. 

Response: In considering the 

comment, we acknowledge the potential 

benefit of a reporting threshold 

providing cement plants with incentive 

to reduce their GHG emissions. The 

‘‘once in, always in’’ provision has been 

removed. The final rule now contains 

provisions to cease reporting if annual 

reports demonstrate emissions less than 

specified levels for multiple years. 

These provisions apply to all reporting 

facilities. See Section II.H of this 

preamble for the response on provisions 

to cease reporting. See Section II.D of 

this preamble for the response on 

selection of source categories to report. 

In developing the Proposed Rule, we 

considered emission-based thresholds of 

1,000 metric tons CO2e, 10,000 metric 

tons CO2e, 25,000 metric tons CO2e, and 

100,000 metric tons CO2e. All of these 

emission thresholds covered more than 

99.9 percent of CO2e emissions from 

cement facilities. Only one plant out of 

107 in the dataset would be excluded by 

the highest considered thresholds of 

100,000 metric tons CO2e. Therefore, we 


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determined that it was appropriate to 

include all cement production facilities 

in the reporting requirements. 

Method for Calculating GHG Emissions 

Comment: Two commenters stated 

that the cement industry already has an 

established, proven protocol for 

calculating and reporting GHG 

emissions, and requested that EPA use 

the existing Cement CO2 Protocol as the 

basis for the Proposed Rule. 

Commenters further stated that the 

Cement CO2 Protocol already provides 

many of the benefits that EPA ascribes 

to the Proposed Rule, including 

uniformity of reported data from one 

facility to another; availability of 

verifiable data to provide to the public, 

investors, and others; and other 

suggested benefits. 

Both commenters stated that EPA 

needs to revise its clinker-based 

calculation to account for any noncarbonated CaO or MgO in the raw 

materials. 

Response: In developing the proposed 

Rule, we considered many domestic and 

international GHG monitoring 

guidelines and protocols, including the 

Cement Sustainability Initiative 

Protocol referenced in the cement 

industry’s comments. We combined 

elements of the Cement CO2 Protocol 

with elements of other protocols 

including the 2006 IPCC Guidelines, 

U.S. Inventory, DOE 1605(b), CARB 

mandatory GHG emissions reporting 

program, EPA’s Climate Leaders 

program, and the EU Emissions Trading 

System to develop two proposed 

methods for quantifying GHG emissions 

from cement manufacturing. These 

proposed methods include the use of 

CEMS to directly measure emissions 

and the use of calculation methods to 

determine emissions. 

While finalizing today’s rule, we 

revisited the Cement CO2 Protocol and 

compared its requirements to our 

requirements. We feel that the rule 

closely mirrors the GHG calculation 

methods and requirements of the 

Cement CO2 Protocol with some minor 

differences. For example, our rule 

requires cement plants to use plantspecific emission factors to calculate 

CO2 emissions and does not allow the 

use of default emission factors. As 

stated in the proposal, we have 

determined that applying default 

emission factors to clinker production is 

more appropriate for national-level 

emissions estimates than facilityspecific estimates, where data are 

readily available to develop site-specific 

emission factors. Default approaches 

would not provide site-specific 

calculation of emissions that reflect 

differences in inputs, operating 

conditions, fuel combustion efficiency, 

variability in fuels, and other 

differences among facilities. Further, it 

is our understanding that facilities 

analyze data relevant for site-specific 

determinations such as the carbonate 

contents of their raw materials to the 

kiln and products on a frequent basis, 

either on a daily basis or every time 

there is a change in the raw material 

mix. Using data from direct 

measurements will provide a more 

accurate representation of site specific 

emissions rates. 

We also note that the Cement CO2

Protocol does not specify measurement 

methods. Our rule specifies methods for 

measuring CaO, MgO, and clinker 

weight. We selected these methods to be 

consistent with measurement 

techniques that are common within the 

cement industry. Prescribing 

standardized measurement procedures 

ensures the uniformity and consistency 

in the results and quality of data 

reported that the commenters agree is 

important for comparability of 

emissions. 

We also used the Cement CO2

Protocol as a model for revising our 

equations in 40 CFR 98.83 to account for 

non-carbonate sources of calcium and 

magnesium that may be present in the 

kiln feed. 

Monitoring and QA/QC Requirements 

Comment: One commenter expressed 

concern that 40 CFR 98.84(e) and (f) 

seem to require continuous, direct 

weight measurement of CKD discarded 

and raw materials used, by category of 

material. The commenter stated that 

most cement plants do not have that 

capability, and that the proposed rule 

does not clearly state whether 

installation of additional measurement 

equipment will be required if not 

already installed. 

One industry representative further 

recommended that EPA add truck 

weight scales as an acceptable option for 

raw material weight measurement to 

address certain limited cases in which 

this method may be more appropriate to 

use. In addition, the commenter 

recommended that EPA allow CKD 

samples to be taken either as CKD exits 

the kiln or from bulk storage. 

Response: We revised the text in 40 

CFR 98.84(e) and (f) to more clearly 

state that CKD quantities are required to 

be measured on a quarterly basis and 

raw material quantities are required to 

be measured on a monthly basis. 

Furthermore, the Proposed Rule was 

never intended to require installation of 

new monitoring equipment for this 

purpose. We agree with the commenter 

that continuous, direct weight 

measurement of these materials and 

installation of additional measurement 

equipment would be unnecessary. The 

proposed rule clearly stated that the 

quantity of CKD produced and raw 

materials consumed must be determined 

using the same plant instruments that 

the cement plant currently uses for 

accounting purposes. Moreover, because 

the quantities of raw materials and CKD 

do not greatly impact the CO2

calculation, we added further 

clarification to this section to allow 

cement plants to use potentially less 

accurate, but commonly used, methods 

of measurement, such as truck weigh 

scales, to determine quantities of CKD 

and raw materials. We also added 

clarification to 40 CFR 98.84 to allow 

facilities to collect CKD samples either 

as CKD exits the kiln or from bulk 

storage. 

Data Reporting Requirements 

Comment: Two commenters asserted 

that EPA needs to provide clarifying 

language within 40 CFR part 98, subpart 

H (Cement Production) to define which 

requirements apply to facilities using 

CEMS to monitor CO2 emissions. One 

commenter noted that the Proposed 

Rule, as written, appears to require 

cement plants using CEMS to collect 

maintain, and report process data 

related to calculating CO2 process 

emissions for kilns pursuant to 

proposed 40 CFR 98.84 through 98.87. 

This commenter claimed that requiring 

plants to collect and report such process 

data are redundant if the facility is 

continuously monitoring CO2 emissions. 

Another commenter recommended that 

EPA state within 40 CFR part 98, 

subpart H (Cement Production) that all 

of the requirements detailed in the 

subpart do not apply to cement kilns 

using Tier 4 (CEMS) method. 

Response: We agree with the 

comment that reporters who are using 

CEMS to monitor CO2 do not need to 

collect, report, and maintain all of the 

process data required in proposed 40 

CFR 98.84 through 98.87. However, we 

determined that some of the process 

data are necessary for emissions 

verification purposes, and therefore, 

plants using CEMS are not completely 

excluded from the requirements in 40 

CFR part 98, subpart H (Cement 

Production). We added clarifying 

language throughout the Subpart to 

clearly state which requirements will 

apply to facilities that use CEMS to 

measure CO2 emissions. Specifically, we 

created separate lists of reporting 

requirements and recordkeeping 

requirements for cement plants using 

CEMS. 


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Comment: One commenter noted that 

the data reporting requirements for 

cement plants, set forth in proposed 40 

CFR 98.86, are expressed in different 

terms that those used for the specified 

procedures for calculating emissions. 

For example, the commenter stated that 

it is unclear what emission sources go 

into the ‘‘site-specific emission factor 

(metric tons CO2/metric ton clinker 

produced)’’ required to be reported 

under proposed 40 CFR 98.86(h), and 

how that factor would be calculated. 

Response: We agree with the 

commenter that there were 

inconsistencies between 40 CFR 98.83 

and 98.86. We updated reporting 

requirements in 40 CFR 98.86 to be 

consistent with the terms used in the 

emission calculation procedures in 40 

CFR 98.83 and provide clarification in 

40 CFR 98.83 for terms if needed. As a 

result, some calculations that are 

performed on a kiln-specific basis, such 

as CO2 emission factors, will be required 

to be reported on a kiln-specific basis in 

40 CFR 98.86. Also see the Section II.N 

of this preamble for the response to 

comments on the emissions verification 

approach. 

I. Electronics Manufacturing 

At this time EPA is not going final 

with the electronics manufacturing 

subpart. As we consider next steps, we 

will be reviewing the public comments 

and other relevant information. 

The Agency received a number of 

lengthy, detailed comments regarding 

the electronics manufacturing subpart. 

Commenters generally opposed the 

proposed reporting requirements and 

stated the proposal required excessive 

detail. For example, commenters 

asserted that they currently do not 

collect the data required to report using 

an IPCC Tier 3 approach and that to 

collect such data would entail 

significant burden and capital costs. In 

most cases, commenters provided 

alternative approaches to each of the 

reporting requirements proposed by 

EPA. 

Commenters also requested 

clarification from EPA on a number of 

the proposed reporting provisions. 

Based on careful review of comments 

received on the proposal preamble, rule, 

and technical support documents 

(TSDs) under proposed 40 CFR part 98, 

subpart I, EPA will perform additional 

analysis and evaluate a range of data 

collection procedures and 

methodologies. EPA’s goal is to 

optimize methods of data collection to 

ensure data accuracy while considering 

industry burden. 

J. Ethanol Production 

At this time, EPA is not finalizing the 

Ethanol Production Subpart. The 

sources of GHG emissions at ethanol 

production facilities that were to be 

reported under the proposed rule were 

stationary fuel combustion, onsite 

landfills, and onsite wastewater 

treatment. EPA has decided not to 

finalize the portion of 40 CFR part 98, 

subpart HH (Landfills) that addresses 

industrial landfills nor 40 CFR part 98, 

subpart II (Wastewater Treatment). 

Stationary fuel combustion sources at 

ethanol production facilities are subject 

to the requirements of 40 CFR part 98, 

subpart C if general stationary fuel 

combustion emissions exceed the 

25,000 metric tons CO2e threshold. 

As EPA considers next steps, we will 

be reviewing the public comments and 

other relevant information. Based on 

careful review of comments received on 

the proposal preamble, rule and TSDs 

under proposed 40 CFR part 98, 

subparts J, HH, and II, EPA will perform 

additional analysis and consider 

alternatives to data collection 

procedures and methodologies 

contained in those subparts. 

K. Ferroalloy Production 

1. Summary of the Final Rule 

Source Category Definition. The 

ferroalloy production source category 

consists of facilities that use 

pyrometallurgical techniques to produce 

any of the following metals: 

ferrochromium, ferromanganese, 

ferromolybdenum, ferronickel, 

ferrosilicon, ferrotitanium, 

ferrotungsten, ferrovanadium, 

silicomanganese, or silicon metal. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For ferroalloy 

production, report the following 

emissions. 

• Annual process CO2 emissions from 

each EAF used for production of any 

ferroalloy listed in the source category 

definition. 

• Annual process CH4 emissions for 

those EAFs used for the production of 

silicon metal, ferrosilicon 65 percent, 

ferrosilicon 75 percent, or ferrosilicon 

90 percent. 

• CO2, N2O, and CH4 emissions from 

each stationary combustion unit on site 

under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

• In addition, report emissions from 

any other source categories for which 

calculation methodologies are specified 

in the rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. To calculate process CO2

emissions from EAFs, reporters can use 

one of two methods, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions from 

each EAF by either (1) installing and 

operating a CEMS and following the 

Tier 4 methodology (in 40 CFR part 98, 

subpart C) or (2) using the carbon mass 

balance calculation procedure specified 

in the rule and summarized below. 

• However, if CO2 process emissions 

from an EAF are emitted through the 

same stack as CO2 emissions from a 

combustion unit or process equipment 

that uses a CEMS and follows Tier 4 

methodology to report CO2 emissions, 

then the CEMS must be used to measure 

and report combined emissions from 

that stack, instead of using the carbon 

mass balance calculation procedure 

described below. 

• If using the carbon mass balance 

procedure, perform a once per year 

calculation using equations in the rule 

and: 

—Recorded monthly production data, 

and 

—The average carbon content for each 

EAF input and output material 

determined by either using material 

supplier information or by annual 

analysis of representative samples of 

the material. 

• For those EAF’s for which the 

reporter must report annual CH4

emissions, annual ferroalloy production 

data are used with an applicable 

emissions factor provided in the rule. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart K. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, 

subpart K. 

2. Summary of Major Changes Since 

Proposal 

The major changes to the rule since 

proposal for ferroalloy production 

facilities were revisions to the carbon 


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mass balance calculation procedure for 

calculating process CO2 emissions from 

EAFs. These changes reduce the 

reporting burden and are consistent 

with revisions made to other similar 

industries. The rationale for these and 

any other significant changes can be 

found below or in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

K: Ferroalloy Production.’’ 

• Frequency of performing the carbon 

mass balance calculations was revised 

to be required on an annual basis 

instead of the proposed monthly basis. 

• Frequency of material carbon 

content sampling and analysis of each 

EAF input and output material used for 

the material balance was revised to be 

performed by annual analysis of 

representative samples of the material 

instead of the proposed monthly basis. 

• Materials contributing less than one 

percent of the total carbon into or out 

of the EAF do not need to be included 

carbon mass balance calculations. 

• 40 CFR 98.116 and 98.117 were 

reorganized and updated to improve the 

emissions verification process. Some 

data elements were moved from 40 CFR 

98.117 to 40 CFR 98.116, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.173 were added to 40 CFR 

98.116 for clarity. See Section II.N of 

this preamble for the response to 

comments on the emissions verification 

approach. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Other comments on ferroalloy 

production were received covering 

various topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart K: Ferroalloy 

Production.’’ 

Comment: One comment was received 

on the proposed rule specific to 

ferroalloy production facilities. The 

commenter requested that EPA allow 

ferroalloy production facilities to use 

alternative methods for determining 

EAF process CO2 emissions other than 

those proposed, and specifically a 

protocol for silicon metal production 

facilities developed for use by the 

Chicago Climate Exchange. This 

smelting protocol was developed a 

protocol for calculating the CO2

emissions from based on the World 

Resources Institute (WRI) aluminum 

smelting protocol. 

Response: We reviewed the WRI 

aluminum smelting protocol, which was 

publicly available and we tried to obtain 

a copy of the specific protocol that the 

commenter mentions to fully evaluate 

whether it is an appropriate alternative. 

However, we never received it in the 

long run. The commenter did not 

provide additional or more specific 

recommendations beyond the reference 

to improve or revise the proposed 

methodology. At this time, given 

insufficient information, we have 

decided not to include additional 

alternative methods in the final rule for 

ferroalloy production facilities. As we 

stated at proposal, the selected 

methodology was based on review of 

several existing methodologies used by 

the 2006 IPCC Guidelines for National 

Greenhouse Gas Inventories, Canadian 

Mandatory Greenhouse Gas Reporting 

Program, the Australian National 

Greenhouse Gas Reporting Program, and 

EU Emissions Trading System. 

However, we have revised the 

frequency of sampling and analysis of 

carbon contents for carbon containing 

input and output materials monthly to 

annual consistent with revisions made 

in response to comments for similar 

production processes (e.g. emissions 

from metal production). These revisions 

reduce the reporting burden for 

ferroalloy production facilities. We 

understand that the carbon content of 

material inputs and outputs does not 

vary widely at a given facility for the 

significant process inputs that contain 

carbon, and we continue to account for 

variations due to changes in production 

rate, which is likely a more significant 

source of variability. The response to 

the comment can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart K: Ferroalloy 

Production.’’ 

L. Fluorinated GHG Production 

At this time EPA is not going final 

with the subpart for emissions from 

fluorinated GHG production. As we 

consider next steps, we will be 

reviewing the public comments and 

other relevant information. 

The Agency received a number of 

lengthy, detailed comments regarding 

the fluorinated GHG production 

subpart. Commenters generally opposed 

the proposed reporting requirements. 

Several commenters stated that facilities 

could not meet the proposed accuracy, 

precision, and frequency requirements 

using existing equipment and practices. 

These commenters stated that they 

would need to expend significant funds 

(millions of dollars in some cases) and 

time to install Coriolis flowmeters in 

multiple streams and to implement 

daily sampling protocols to analyze the 

contents of these streams. Some 

commenters stated that even after such 

equipment was installed, the proposed 

mass-balance approach was likely to be 

inaccurate, particularly for batch 

processes. In most cases, commenters 

provided alternative approaches, such 

as emission-factor based approaches, to 

the proposed mass-balance approach. 

Based on careful review of comments 

received on the proposal preamble, rule, 

and TSDs under proposed 40 CFR part 

98, subpart L, EPA will perform 

additional analysis and evaluate a range 

of data collection procedures and 

methodologies. EPA’s goal is to 

optimize methods of data collection to 

ensure data accuracy while considering 

industry burden. 

M. Food Processing 

At this time, EPA is not going final 

with the Food Processing Subpart. The 

sources of GHG emissions at food 

processing facilities that were to be 

reported under the proposed rule were 

stationary fuel combustion, onsite 

landfills, and onsite wastewater 

treatment. EPA has decided not to 

finalize the portion of 40 CFR part 98, 

subpart HH (Landfills) that addresses 

industrial landfills nor 40 CFR part 98, 

subpart II (Wastewater Treatment). Note, 

however, that Stationary fuel 

combustion sources at food processing 

facilities are subject to the requirements 

of 40 CFR part 98, subpart C if general 

stationary fuel combustion emissions 

exceed the 25,000 metric ton CO2e 

threshold. As EPA considers next steps, 

we will be reviewing the public 

comments and other relevant 

information. 

Based on careful review of comments 

received on the proposal preamble, rule 

and TSDs under proposed 40 CFR part 

98, subparts M, HH, and II, EPA will 

perform additional analysis and 

consider alternatives to data collection 

procedures and methodologies 

contained in those subparts. 

N. Glass Production 

1. Summary of the Final Rule 

Source Category Definition. The glass 

production source category consists of 

facilities that manufacture glass 

(including flat, container, pressed, or 

blown glass) or wool fiberglass using 

one or more continuous glass melting 

furnaces. Experimental furnaces and 

research and development process units 

are excluded. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 


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GHGs to Report. For glass production 

facilities, report the following 

emissions: 

• CO2 process emissions from each 

continuous glass melting furnace. 

• CO2 combustion emissions from 

each continuous glass melting furnace, 

• CH4 and N2O emissions from fuel 

combustion at each continuous glass 

melting furnace under 40 CFR part 98, 

subpart C (General Stationary 

Combustion Sources) using the 

methodologies in subpart C. 

• CO2, CH4, and N2O emissions and 

from each onsite stationary fuel 

combustion unit other than continuous 

glass melting furnaces under 40 CFR 

part 98, subpart C (General Stationary 

Combustion Sources). 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. For CO2 process emissions 

from glass melting furnaces, reporters 

must use one of two methods, as 

appropriate: 

• For glass melting furnaces with 

certain types of CEMS in place, 

reporters must use the CEMS and follow 

the Tier 4 methodology (in 40 CFR part 

98, subpart C) to measure and report 

under the glass production subpart (40 

CFR part 98, subpart N) combined 

process and combustion CO2 emissions. 

• For other glass melting furnaces, the 

reporter can elect to either (1) install 

and operate a CEMS and follow the Tier 

4 methodology to measure and report 

combined process and combustion CO2

emissions or (2) calculate process CO2

emissions for each furnace using an 

emission factor and process data. If 

using approach (2), multiply a default 

emission factor appropriate for the 

carbonate raw material by: 

—The annual mass of carbonate-based 

raw material charged to the furnace 

(required to be measured); and 

—The mass-fraction of carbonate in the 

raw material (based on data supplied 

by the raw material supplier and 

verified by an annual measurement). 

—Under approach (2), report process 

CO2 emissions from each glass 

melting furnace under 40 CFR part 98, 

subpart N (Glass Production), and 

report combustion CO2 emissions 

from each glass furnace under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart N. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

N. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart N: Glass 

Production.’’ 

• The definition of the term ‘‘glass 

produced’’ was added to the definitions 

in 40 CFR part 98, subpart A. 

• 40 CFR 98.146 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.147 to 40 CFR 98.146, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.143 were added to 40 CFR 

98.146 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments on glass production 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart N: Glass 

Production.’’ 

Definition of Source Category 

Comment: One commenter stated that 

EPA should exempt from the rule all 

fiber glass and rock and slag wool 

insulation facilities within the glass 

production source category because 

glass production facilities subject to the 

proposed rule are a miniscule portion of 

the total national emissions of CO2e, 

and amount to less than 0.1 percent of 

total GHG emissions in the U.S. and the 

subset of fiber glass and rock and slag 

wool insulation facilities is an even 

smaller portion. The commenter stated 

that there is virtually no benefit to 

having the glass production source 

category subject to the proposed rule, 

and any benefit is outweighed by the 

burden imposed on these facilities. The 

commenter also pointed out the 

importance of the fiber glass and rock 

and slag wool insulation industry’s 

products in meeting the nation’s energy 

needs and reducing GHG emissions. 

Exempting the industry from the 

proposed rule’s reporting requirements 

will help the industry focus more of its 

scarce resources on producing 

insulation. 

Response: We recognize that the glass 

manufacturing industry is comprised of 

a wide range of facilities, many of which 

are small in size and have relatively low 

levels of emissions. However, the data 

we have collected on the industry 

indicate that there are several large glass 

manufacturing plants with significant 

GHG emissions. These plants include 

some that produce glass fiber, flat glass, 

and container glass, as well as other 

types of pressed and blown glass 

products. As a result, we do not agree 

with the commenter that fiber glass and 

other types of insulation facilities 

should be exempt from reporting. 

However, we tried to reduce the burden 

on the glass manufacturing industry by 

incorporating into the proposed rule a 

25,000 metric ton CO2e threshold, 

which should preclude small facilities 

from having to report GHGs. This 

threshold remains in the final rule. 

Thus, any small fiber glass and rock and 

slag wool insulation facilities with low 

GHG emissions will fall under the 

threshold and will be exempt from 

reporting. To further minimize the 

burden on the industry, we have tried 

to limit recordkeeping and reporting 

requirements to the types of data that 

glass production facilities already 

collect as part of normal business 

operations. 

Commenters may also be interested in 

reviewing Section II.H of this preamble 

for the response on provisions to cease 

reporting. The final rule contains 

provisions to cease reporting if annual 

reports demonstrate emissions less than 

specified levels for multiple years. 

Selection of Threshold 

Comment: One commenter remarked 

that EPA should raise the threshold for 

reporting for fiberglass and rock and 

slag wool insulation entities. Doing so 

would reduce the number of entities 

reporting with only a minimal impact 

on the amount of emissions covered. 

The commenter stated that EPA’s 

analysis did not address reasonable 

alternative thresholds between 25,000 

and 100,000 metric tons. 

Response: When evaluating potential 

thresholds for reporting GHG emissions, 

we considered several thresholds 


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between 1,000 and 100,000 metric tons 

CO2e. We selected the 25,000 metric 

tons CO2e threshold for reporting GHG 

emissions in order to achieve a balance 

between quantifying the majority of the 

emissions and minimizing the number 

of facilities impacted. For example, at a 

1,000 metric tons CO2e threshold, 98 

percent of emissions would be covered, 

with about 58 percent of facilities being 

required to report. Compared to the 

100,000 metric tons CO2e threshold, the 

proposed 25,000 metric tons CO2e 

threshold achieves reporting of 11 times 

more emissions while requiring less 

than 15 percent of the facilities to 

report. Compared to the 10,000 metric 

tons CO2e threshold, the 25,000 metric 

tons CO2e threshold captures more than 

half of those emissions, but only 

requires a third of the facilities in the 

industry to report. This threshold offers 

significant coverage of the GHG 

emissions while impacting a relatively 

small portion of the industry. Although 

a threshold of 50,000 metric tons CO2e 

would greatly reduce the number of 

facilities reporting, it would capture less 

than 20 percent of total emissions for 

the industry. We believe the proposed 

threshold of 25,000 metric tons CO2e 

represents the best option for ensuring 

that the majority of emissions are 

reported without imposing an 

unreasonable burden on the industry. 

Section II.E of this preamble contains 

a general discussion of the selection of 

the 25,000 metric tons CO2e threshold. 

Method for Calculating GHG Emissions 

Comment: One commenter fully 

supports EPA’s proposed rule for 

measuring, calculating, monitoring, and 

reporting emissions from the glass 

melting process. They agree that 40 CFR 

part 98, subpart N represents a good 

balance between site reporting burden, 

cost, and data accuracy and consistency. 

Specifically, the commenter supports 

using raw-material emissions factors 

and usage rates, as proposed, to 

calculate emissions from glass 

production in lieu of requiring installing 

CEMs on sources that another regulation 

does not currently require to be 

installed. 

Response: We acknowledge this 

support for the proposal and appreciate 

these comments. We have retained the 

proposed calculation methodology in 

the final rule. 

Data Reporting Requirements 

Comment: One commenter stated that, 

at various places in the preamble and 

proposed rule, EPA uses the phrase 

‘‘glass produced,’’ but has not defined 

this phrase in the rule. The commenter 

noted that the phrase could be 

interpreted to mean either glass melted 

or glass product produced. The 

commenter assumed that the phrase 

refers to the amount of glass melted, but 

requested clarification. 

Response: We agree that the term 

glass produced is subject to 

interpretation. We have added a 

definition of the term to 40 CFR part 98, 

subpart A of the final rule. ‘‘Glass 

produced’’ means the weight of glass 

exiting a glass melting furnace. 

Comment: One commenter remarked 

that some of the information that would 

have to be reported under the proposed 

rule, such as annual quantity of glass 

produced, is considered to be company 

confidential and could be used by 

competitors to back-calculate product 

formulas. The commenter requested that 

EPA remove these reporting 

requirements from the rule and instead, 

require that the data be retained by the 

facility and made available for review 

by EPA. Should EPA require the 

reporting of all of this information in the 

final rule, the commenter requests that 

EPA explicitly state in the final rule and 

confirm in the preamble to the final rule 

that all information provided under 40 

CFR part 98, subpart N, other than the 

annual process emissions of CO2, is 

considered confidential information and 

would not be considered ‘‘emission 

data’’ under this reporting rule. The 

commenter requests that a new 

paragraph (e) be added to 40 CFR 98.146 

that reads: ‘‘No information required to 

be reported by this section, other than 

the information required by 40 CFR 

98.146(a), is considered to be emission 

data under 40 CFR 2.301(a)(2)(i) and 

(ii).’’ 

Response: We acknowledge the 

commenter’s concerns. However, the 

quantity of glass produced is an 

important variable for EPA to verify 

whether reported emissions are within a 

reasonable range and therefore is a 

required reporting parameter under 40 

CFR part 98, subpart N. 

We have reviewed CBI comments 

received across the rule (both general 

and subpart-specific comments) and our 

response is discussed in Section II.R of 

this preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

O. HCFC–22 Production and HFC–23 

Destruction 

1. Summary of the Final Rule 

Source Category Definition. This 

source category consists of: 

• Processes that produce HCFC–22 

(chlorodifluoromethane or CHClF2) 

using chloroform and hydrogen 

fluoride. 

• HFC–23 destruction processes 

located at HCFC–22 production 

facilities. 

• HFC–23 destruction processes that 

destroy more than 2.14 metric tons of 

HFC–23 per year and that are not 

located at HCFC–22 production 

facilities. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For facilities that 

produce HCFC–22 or that destroy HFC– 

23, report the following emissions: 

• HFC–23 emissions from all HCFC– 

22 production processes at the facility. 

• HFC–23 emissions from each 

destruction process. 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. For example, 

report CO2, N2O, and CH4 emissions 

from each stationary combustion unit on 

site by following the requirements of 40 

CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources). 

GHG Emissions Calculation and 

Monitoring. Reporters must calculate 

HFC–23 emissions as follows: 

• For HCFC–22 production processes 

that do not use a thermal oxidizer or 

that have a thermal oxidizer that is not 

connected to the production equipment, 

calculate annual HFC–23 emissions at 

the facility level using a mass balance 

equation and the following information: 

annual HFC–23 generated, the annual 

HFC–23 sent off site for sale, the annual 

HFC–23 sent off site for destruction, the 

annual increase in the HFC–23 

inventory, and the annual HFC–23 

destroyed on site (calculated by 

multiplying the mass of HFC–23 fed to 

the destruction device by the 

destruction efficiency). 

• For HCFC–22 production processes 

with a thermal oxidizer that is 

connected to the production equipment, 

calculate annual HFC–23 emissions at 

the facility level by summing the 

following emissions: 

—Annual HFC–23 emissions from 

equipment leaks (calculated using 

default emission factors and the 

measured number of leaks in valves, 

pump seals, compressor seals, 

pressure relief valves, connectors, and 

open-ended lines). 

—Annual HFC–23 emissions from 

process vents (calculated for each 

vent using the HFC–23 emission rate 

from the most recent emission test 

and the ratio of the actual production 


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rate and the production rate during 

the emission test). 

—Annual HFC–23 from the thermal 

oxidizer (calculated by subtracting the 

amount of HFC–23 destroyed by the 

destruction device from the measured 

mass of HFC–23 fed to the destruction 

device). 

• For other HFC–23 destruction 

processes, calculate HFC–23 emissions 

based on the mass of HFC–23 fed to the 

destruction device and the destruction 

efficiency. 

• For the destruction efficiency, 

conduct a performance test or use the 

destruction efficiency determined 

during a previous performance test. To 

confirm the destruction efficiency, 

measure the fluorinated GHG 

concentration at the outlet to the 

destruction device annually. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart O. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

O. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart O: HCFC–22 

Production and HFC–23 Destruction.’’ 

• The minimum required frequency 

of mass flow and concentration 

measurements has been decreased from 

daily to weekly. 

• The required frequency of 

emissions tests at process vents has 

been decreased to once every five years. 

A test is also required after a significant 

change is made to the process. 

• The required annual measurements 

at the outlet of the thermal oxidizer now 

omit measurements of mass flow. Three 

samples are required to be taken; the 

average of these is compared to the 

concentration at the outlet of the 

oxidizer that was measured during the 

initial performance test that established 

the destruction efficiency. 

• A term has been added to the massbalance equation for HCFC–22 

production facilities that do not have a 

thermal oxidizer that is directly 

connected to the HCFC–22 production 

equipment. This term accounts for 

increases in the inventory of stored 

HFC–23 that can occur during the year. 

• EPA has added an additional 

method for estimating missing mass 

flow data in the event that a secondary 

mass measurement for that stream is not 

available. 

• The option for reporters to develop 

their own methods for estimating 

missing data if they believe that the 

prescribed method will over- or underestimate the data has been removed. 

• Some reporting requirements have 

been added to be consistent with the 

changes to the calculations and 

monitoring sections and to permit 

verification of emissions calculations. 

EPA decreased the minimum 

frequency of gas flow and concentration 

measurements from daily to weekly 

because EPA’s research indicates that 

HFC–23 concentrations are not likely to 

vary significantly over a one week 

period. This change also makes the 

required measurement frequency more 

consistent with current industry 

practice. 

As noted above, EPA removed the 

option for reporters to develop their 

own methods for estimating missing 

data if they believe that the prescribed 

method will over- or underestimate the 

data. EPA removed this option for two 

reasons. First, the proposed provision 

lacked clear guidance on when 

alternative methods should be used 

(e.g., on the size of an underestimate 

that would justify use of an alternative 

method) and on how they should be 

developed. Second, the proposed 

provision was redundant with the new 

provision that permits reporters to 

estimate missing data using a related 

parameter and the historical 

relationship between the related 

parameter and the missing parameter. 

This new option provides reporters with 

flexibility in substituting for missing 

data in the event that a secondary mass 

measurement is not available, but sets 

out general guidance on how to select 

the substitute data. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

number of comments on HCFC–22 

production and HFC–23 destruction 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart O: HCFC–22 

Production and HFC–23 Destruction.’’ 

Monitoring and QA/QC Requirements 

Comment: EPA received a comment 

that the requirement to annually 

conduct emissions tests at process vents 

is overly burdensome and unnecessary 

because it is unlikely that the emissions 

rate would deviate from an initial 

process vent test unless there were a 

significant change in the process. This 

commenter argued that testing should 

be required at least every five years or 

after a significant change in the process. 

Response: In response to this 

comment, EPA has reduced the required 

frequency of emissions tests at process 

vents to once every five years, or after 

a significant change to the process. EPA 

has also clarified that the requirement 

applies only to HCFC–22 production 

facilities that use a thermal oxidizer 

connected to the HCFC–22 production 

equipment. These are the only facilities 

that use process vent emission estimates 

in their calculation of facility-wide 

HFC–23 emissions. 

EPA is decreasing the frequency of 

emissions tests at process vents for two 

reasons. First, EPA agrees with the 

commenter that, in the absence of a 

significant process change, the process 

vent emission rate is not likely to vary 

much (in percentage terms) from year to 

year. Second, although small variations 

in the emission rate could still lead to 

significant absolute errors for facilities 

with large process vent emissions, the 

facilities that are required to test their 

process vent emissions are likely to 

have small process vent emissions 

(because they use thermal oxidizers 

connected to the production 

equipment). (Facilities that do not use 

thermal oxidizers connected to the 

equipment would be expected to have 

larger process vent emissions, but they 

are required to use a mass-balance 

approach to calculate emissions rather 

than summing emissions across process 

vents, equipment leaks, and thermal 

oxidizers.) Together, these 

considerations lead to the conclusion 

that testing process vent emissions 

every five years should sufficiently 

minimize errors in the overall HFC–23 

emission calculations of the facilities 

affected by the testing requirement. 

Comment: EPA should add a term to 

Equation O–4 (the mass-balance 

equation for HCFC–22 production 

facilities that do not have a thermal 

oxidizer that is directly connected to the 

HCFC–22 production equipment) to 

account for increases in the inventory of 


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stored HFC–23 that can occur during the 

year. 

Response: EPA added a term to 

Equation O–4 for increases in the 

inventory of stored HFC–23. EPA agrees 

that the equation should account for 

changes in the inventory of HFC–23 that 

is stored on site. It is important to track 

all reservoirs of HFC–23 at the facility; 

mass-balance approaches used to track 

emissions from other sources (e.g., from 

electrical equipment) frequently include 

terms to account for the increase in 

inventory. 

Definition of Source Category 

Comment: EPA received a comment 

that the measurement of HFC–23 

emissions from HCFC–22 production 

should be moved to Subpart L, which 

covers the reporting of fluorinated GHG 

production. 

Response: EPA proposed provisions 

for facilities producing fluorinated gases 

in three separate subparts: 40 CFR part 

98, Subpart L, Subpart O, and Subpart 

OO. Although there are many 

similarities across the chemicals and 

processes covered by the three subparts, 

the subparts were deliberately tailored 

to different sources and types of 

emissions. Subpart L was intended to 

address emissions of fluorinated GHGs 

from fluorinated GHG production. 40 

CFR part 98, subpart O was intended to 

address HFC–23 generation and 

emissions from HCFC–22 production. 

40 CFR part 98, subpart OO was 

intended to address flows affecting the 

U.S. industrial gas supply, including 

production, transformation, and 

destruction. 

EPA determined that 40 CFR part 98, 

subpart O was necessary because 

HCFC–22 production and HFC–23 

destruction facilities differ from other 

fluorinated gas production facilities in 

two key respects. First, the primary 

fluorinated GHG that they generate 

(HFC–23) is made as a byproduct to the 

production of a substance that is not 

defined as a fluorinated GHG (HCFC– 

22). Second, due to the very high GWP 

of HFC–23, each HCFC–22 facility 

generates very large quantities of CO2- 

equivalent. For the second reason, EPA 

has worked with HCFC–22 producers 

for over ten years to understand and 

reduce HFC–23 emissions. The 

requirements for HCFC–22 producers 

are therefore based on a close 

knowledge of their production processes 

and methods for accounting for 

emissions. These methods are also 

comprehensive (e.g., accounting for 

emissions from equipment leaks and 

losses during transport of HFC–23 that 

is shipped off-site for destruction). 

These requirements may not be 

appropriate for other fluorinated gas 

producers, and, at the same time, the 

requirements for fluorinated gas 

producers may not be appropriate for 

HCFC–22 producers. 

P. Hydrogen Production 

1. Summary of the Final Rule 

Source Category Definition. The 

merchant hydrogen production source 

consists of process units that produce 

hydrogen by reforming, gasification, or 

other transformation of feedstock and 

transfer the hydrogen produced off site. 

Hydrogen production facilities located 

at petroleum refineries or other large 

facilities are included in this source 

category only if they are not owned by 

or under the direct control of the 

refinery owner. Otherwise, they are 

considered to be a captive hydrogen 

production source that reports 

emissions under the subpart applicable 

to the larger facility, e.g., 40 CFR part 

98, subpart Y (Petroleum Refineries). 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For hydrogen 

production, report the following 

emissions: 

• CO2 process emissions from 

hydrogen production. 

• CO2, N2O, and CH4 emissions from 

each stationary combustion unit on site 

by following the requirements of 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources). 

• CO2 collected and transferred off 

site under 40 CFR part 98, subpart PP 

(Suppliers of Carbon Dioxide). 

• In addition, report GHG emissions 

for other source categories for which 

calculation methods are provided in the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. 

• To calculate and report process CO2

emissions from hydrogen production, 

most reporters can elect to either (1) 

install and operate CEMS and follow the 

Tier 4 methodology (in 40 CFR part 98, 

subpart C) or (2) calculate process CO2

emissions using equations in the 40 CFR 

part 98, subpart P and the following 

data: 

—Measurements of monthly feedstocks 

and fuel consumed. 

—Carbon content of the feedstock 

measured monthly. 

—Molecular weight of the feedstock 

(gaseous fuels only). 

• However, if process CO2 emissions 

from hydrogen production are vented 

through the same stack as a combustion 

unit or process equipment that uses a 

CEMS to follow Tier 4 methodology to 

report CO2 emissions, then the CEMS 

must be used to measure and report 

combined CO2 emissions from that stack 

instead of the calculation procedure 

described in approach 2 above. 

Monitoring and QA/QC Requirements. 

The methods for the initial calibration 

and annual recalibration of flow meters 

are defined in a prescriptive list of 

industry standard test methods 

incorporated by reference in the Tier 3 

method in 40 CFR part 98, subpart C, 

while the methods for determining 

carbon content of fuels and feedstocks 

are defined in a prescriptive list of an 

assortment of industry standard test 

methods incorporated by reference. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart P. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

P. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart P: Hydrogen 

Prodution.’’ 

• 40 CFR 98.160 was reworded to 

clarify the definition of reporting entity. 

• 40 CFR 98.162 was revised to allow 

reporting of combined process and 

combustion CO2, CH4, and N2O 

emissions. 

• In 40 CFR 98.163(b), ‘‘feedstock’’ 

was changed to ‘‘fuel and feedstock’’. 

• 40 CFR 98.164 was restructured to 

clarify between CEMS measurements 

and QA/QC and feedstock method 

measurements and QA/QC. 

• 40 CFR 98.164 was reworded to 

allow the characterization of feedstocks 

to be conducted by either the consumer 

or the supplier, to allow standard 

gaseous hydrocarbon fuels of commerce 

to be characterized annually, and to 

allow liquid and solid hydrocarbon 

fuels of commerce to be characterized 


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upon delivery if delivered by bulk 

transport. 

• The recalibration requirements in 

40 CFR 98.164 were changed to reduce 

economic impact. 

• The list of standards incorporated 

by reference in 40 CFR 98.164 was 

broadened. 

• The missing data procedures in 

40 CFR 98.165 were revised to be 

consistent with 40 CFR 98.35(b). 

• 40 CFR 98.166 and 98.167 were 

restructured to distinguish between 

CEMS recordkeeping and feedstock 

method recordkeeping. 

• 40 CFR 98.166 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.167 to 40 CFR 98.166, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 

40 CFR 98.163 were added to 40 CFR 

98.166 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on hydrogen 

production were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart P: Hydrogen 

Production.’’ 

Definition of Source Category 

Comment: Multiple commenters 

pointed out the lack of clarity regarding 

the definition of the reporting entity, 

and suggested defining the entity 

holding the air permit for an affected 

facility as the reporting entity. For 

example, ‘‘If the owner/operator of the 

facility is the holder of the air permit for 

an affected facility, then the operator 

should be responsible for reporting GHG 

emissions. If not, then EPA should 

clarify the responsibility for reporting.’’ 

Response: EPA reviewed this complex 

issue. First, a facility is defined in 40 

CFR 98.6: ‘‘Facility means any physical 

property, plant, building, structure, 

source, or stationary equipment located 

on one or more contiguous or adjacent 

properties in actual physical contact or 

separated solely by a public roadway or 

other public right-of-way and under 

common ownership or common control, 

that emits or may emit any greenhouse 

gas.’’ Therefore, any hydrogen 

production process unit that is not part 

of a larger facility covered by another 

subpart of this rule is a merchant 

hydrogen production facility which 

reports emissions under 40 CFR part 98, 

subpart P. On the other hand, a 

hydrogen production process unit that 

is part of a larger facility covered by 

another subpart of this rule is a captive 

hydrogen production facility that does 

not report emissions under 40 CFR part 

98, subpart P. Their emissions, 

including those emissions from the 

captive hydrogen production facility, 

are reported under the subpart 

applicable to the larger facility. Second, 

in answer to the question, ‘‘Do I need to 

report?’’, 40 CFR 98.2 states that the rule 

applies to a facility that contains any 

source category listed in 40 CFR 

98.2(a)(2) (which includes hydrogen 

production) and that emits 25,000 

metric tons CO2e or more per year in 

combined emissions from stationary 

fuel combustion units, miscellaneous 

uses of carbonates, and all source 

categories listed in 40 CFR 98.2(a)(2). 

EPA has concluded that the rule 

explains this clearly in 40 CFR 98.2 and 

98.6, and that it is not necessary to 

change the rule. To add clarity, 

however, EPA has revised 40 CFR 

98.160(c) as follows: ‘‘This source 

category includes merchant hydrogen 

production facilities located within a 

petroleum refinery if they are not owned 

by, or under the direct control of, the 

refinery owner and operator.’’ 

GHGs To Report 

Comment: Multiple commenters 

requested clarification on the CO2

emission reporting obligation as 

combined ‘‘process’’ and ‘‘combustion’’ 

CO2 emissions, regardless of the 

calculation method employed. If 

separate, discrete reporting of such 

emissions is actually required, 

commenters asked EPA to provide 

explicit protection for this information 

which they stated was very critical CBI. 

Response: In response to these 

multiple commenters, EPA has clarified 

the rule in 40 CFR 98.162 to provide 

operators the option of providing 

combined process and combustion CO2

emissions for each hydrogen production 

process unit whether or not it meets the 

conditions in 40 CFR 98.33(b)(4)(ii) and 

(iii) for CEMs. Under 40 CFR 98.166, 

facilities must report additional 

parameters for emissions verification. 

See Sections II.I and II.N of this 

preamble for responses to the comments 

received on the general content of the 

annual GHG report and the emissions 

verification approach, respectively. EPA 

reviewed CBI comments received across 

the rule (both general and subpartspecific comments) and our response is 

discussed in Section II.R of this 

preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

Method for Calculating GHG Emissions 

Comment: Multiple commenters 

pointed out the need for a calculation 

method to account for feedstock carbon 

that does not exit the hydrogen 

production facility as CO2, but rather in 

the form of other products or coproducts that contain carbon (such as 

synthesis gas, CO, CH4). Many argued in 

favor of correcting equations P–1, P–2 

and P–3 to account for feedstock carbon 

that does not exit the hydrogen 

production facility as CO2, but rather as 

products (such as synthesis gas, CO, 

CH4) that are manufactured which 

contain carbon. 

Response: EPA generally concurs with 

the need to account for ‘‘carbon other 

than CO2’’ that exits the facility. EPA 

considered several options for reporting 

such carbon and chose to have facilities 

report CO2 and ‘‘carbon other than CO2’’ 

as separate data reporting elements in 

40 CFR 98.166 rather than including 

this carbon in equations P–1, P–2, and 

P–3. As a result, EPA has added data 

reporting elements under 40 CFR 98.166 

for (1) quarterly quantity of CO2

collected and transferred off site in 

either gas, liquid, or solid forms (metric 

tons), following the requirements of 40 

CFR part 98, subpart PP of this part, and 

(2) annual quantity of carbon other than 

CO2 collected and transferred off site in 

either gas, liquid, or solid forms (metric 

tons). 

Monitoring and QA/QC Requirements 

Comment: Multiple commenters 

recommended that EPA should allow 

the characterization of feedstocks 

(sampling and analysis) to be conducted 

by either the feedstock consumer (the 

regulated source) or the feedstock 

supplier. They state that the 

characterization of standard fuels of 

commerce used as hydrogen production 

feedstocks, such as natural gas, should 

not be required since default values will 

yield a sufficiently accurate emission 

estimate. Commenters recommend that 

characterization of such standard fuels 

of commerce used as feedstocks be 

optional, at the source’s discretion. 

Response: EPA concurs with this 

comment, since feedstock suppliers 

regularly monitor the carbon content of 

their fuels and also, the carbon content 

of standard fuels of commerce are quite 

consistent month to month. EPA has 

revised this section to allow the 

characterization of feedstocks to be 

conducted by either the consumer or the 

supplier, to allow standard gaseous 

hydrocarbon fuels of commerce to be 

characterized annually, and allow liquid 


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and solid hydrocarbon fuels of 

commerce to be characterized upon 

delivery if delivered by bulk transport 

(e.g., by truck or rail). Other nonstandard gaseous fuels and feedstocks 

must still be subjected to weekly 

sampling and analysis to determine the 

carbon content and molecular weight. 

Comment: Commenters recommended 

that EPA limit the requirement for 

sampling non-gaseous fuels to new 

deliveries rather than monthly in order 

to pinpoint the onset of fuel parameter 

variations. 

Response: EPA concurs that the 

carbon content of a liquid or solid 

hydrocarbon fuel delivered in bulk will 

remain constant as the stock on hand 

from the delivery is consumed, and 

therefore periodic testing during the 

interim is not needed. EPA has revised 

this section to allow the characterization 

of feedstocks to be conducted by either 

the consumer or the supplier, to allow 

standard gaseous hydrocarbon fuels of 

commerce to be characterized annually, 

and allow liquid and solid hydrocarbon 

fuels of commerce to be characterized 

upon delivery if delivered by bulk 

transport (e.g., by truck or rail). On the 

other hand, other non-standard gaseous 

fuels and feedstocks must still be 

subjected to weekly sampling and 

analysis to determine the carbon content 

and molecular weight since their carbon 

content can vary significantly from 

week to week. 

Comment: Multiple commenters 

recommended that EPA should include 

provisions for an extension of the 

required meter/monitor calibration 

deadline (as well as the initial 

calibration, if appropriate) when the 

calibration would require removing the 

process line from service. They 

recommend that the calibration 

requirement be extended to the next 

scheduled maintenance shutdown for 

the impacted unit/process. 

Response: EPA concurs that requiring 

the facility to remove the process line 

from service represents an undue 

hardship and has therefore revised 40 

CFR part 98, subpart P to refer to the 

less stringent monitoring and QA/QC 

requirements for the Tier 3 methodology 

included in 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

Comment: One commenter suggested 

adding ISO 5167–1 through ISO 5167– 

4 (Measurement of Fluid Flow by Means 

of Pressure Differential Devices) to list 

of standards incorporated by reference. 

Response: EPA agrees ISO 5167–1 

through ISO 5167–4 are suitable 

calibration standards and would be 

good additions to the list of standards. 

However, given that the issues covered 

by these standards (Venturi and orifice 

plate differential pressure flow meters) 

are covered by two American Society of 

Mechanical Engineers (ASME) 

standards, one ASHRAE standard, and 

one AGA report which are already 

included in 40 CFR 98.164, EPA has not 

explicitly added these references to the 

list of standards incorporated by 

reference. 

Procedures for Missing Data 

Comment: Multiple commenters 

recommended that the data substitution 

method for missing feedstock supply 

rate data should be changed to be 

consistent with 40 CFR 98.35(b)(2), 

allowing use of the ‘‘best available 

estimate’’, and that the data substitution 

method for missing feedstock carbon 

content data should be changed to be 

consistent with 40 CFR 98.35(b)(1), 

allowing use of the average before/after 

values. 

Response: EPA concurs that the 

required level of accuracy for hydrogen 

production is similar to that required for 

stationary combustion, and that the less 

stringent ‘‘best available estimate’’ 

approach is appropriate for hydrogen 

production. Therefore, EPA has changed 

40 CFR 98.165 to follow the data 

substitution method for missing fuel 

carbon content data prescribed in 40 

CFR 98.35 and the data substitution 

method for missing fuel usage data 

prescribed in 40 CFR 98.35. 

Data Reporting Requirements 

Comment: Multiple commenters 

stated that annual feedstock 

consumption, annual hydrogen 

production, and feedstock carbon 

content are confidential business 

information (CBI) and should not be 

reported. The commenters asked that 

this information be maintained by the 

facility and be made available to the 

Agency upon request. One commenter 

further stated that if data must be 

reported, the reporting rules must 

provide explicit protection for this very 

critical confidential business 

information. 

Response: Feedstock consumption 

and feedstock carbon content are 

parameters used to calculate emissions. 

Since annual CO2 emissions are 

calculated from the sum of the products 

of monthly feedstock consumption 

multiplied by the monthly average 

carbon content of the feedstock, all of 

these parameters are required for 

emissions data verification purposes. 

Annual hydrogen production is an 

additional parameter which is necessary 

for EPA to effectively verify emissions, 

since the ratio of carbon emissions to 

hydrogen production is relatively 

consistent for each hydrogen production 

facility. See Section II.N of this 

preamble for information on emissions 

verification. EPA reviewed CBI 

comments received across the rule (both 

general and subpart-specific comments) 

and our response is discussed in Section 

II.R of this preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

Q. Iron and Steel Production 

1. Summary of the Final Rule 

Source Category Definition. The iron 

and steel production source category 

consists of facilities with any of the 

following processes: 

• Taconite iron ore processing. 

• Integrated iron and steel 

manufacturing. 

• Cokemaking not co-located with an 

integrated iron and steel manufacturing 

process. 

• EAF steelmaking not co-located 

with an integrated iron and steel 

manufacturing process. 

Integrated iron and steel 

manufacturing means the production of 

steel from iron ore or iron ore pellets. 

At a minimum, an integrated iron and 

steel manufacturing process has a basic 

oxygen furnace for refining molten iron 

into steel. Each cokemaking process and 

EAF process located at a facility with an 

integrated iron and steel manufacturing 

process is part of the integrated iron and 

steel manufacturing facility. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Report the following 

emissions annually: 

• CO2, CH4, and N2O emissions from 

fuel combustion at each stationary 

combustion unit according to the 

requirements in 40 CFR part 98, subpart 

C (General Stationary Fuel Combustion 

Sources). Stationary combustion units 

include, but are not limited to, 

byproduct recovery coke oven battery 

combustion stacks, blast furnace stoves, 

boilers, process heaters, reheat furnaces, 

annealing furnaces, flame suppression, 

ladle reheaters, and any other 

miscellaneous combustion sources 

(except flares). 

• CO2 emissions from flares according 

to the requirements in 40 CFR part 98, 

subpart Y (Petroleum Refineries) and 

CH4 and N2O emissions from flares 

using the default emission factors for 

coke oven gas and blast furnace gas. 

• CO2 process emissions from each 

taconite indurating furnace, basic 

oxygen furnace, nonrecovery coke oven 


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battery combustion stack, coke pushing 

process, sinter process, EAF, argonoxygen decarburization vessel, and 

direct reduction furnace. 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. For CO2 process emissions 

at each taconite indurating furnace, 

basic oxygen furnace, nonrecovery coke 

oven battery, sinter process, EAF, argonoxygen decarburization vessel, and 

direct reduction furnace, reporters must 

calculate emissions using one of the 

following methods, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions by 

either: (1) Installing and operating a 

CEMS and following the Tier 4 

methodology (in 40 CFR part 98, subpart 

C) or (2) using one of the following two 

calculation procedures: 

—Use a carbon balance method 

described in 40 CFR part 98, subpart 

Q to calculate the annual mass 

emissions rate of CO2 for each 

process, based on the annual mass of 

inputs and outputs and an annual 

analysis of the respective weight 

fraction of carbon in each process 

input or output that contains carbon. 

Use separate procedures and 

equations for taconite indurating 

furnaces, basic oxygen process 

furnaces, nonrecovery coke oven 

batteries, sinter processes, EAFs, 

argon-oxygen decarburization vessels, 

and direct reduction furnaces, or 

—Use a site-specific emission factor 

determined from a performance test 

that measures CO2 emissions from all 

exhaust stacks and also measures 

either the feed rate of materials into 

the process or the production rate 

during the test for taconite indurating 

furnaces, basic oxygen process 

furnaces, nonrecovery coke oven 

batteries, sinter processes, EAFs, 

argon-oxygen decarburization vessels, 

and direct reduction furnaces. 

• However, if process CO2 emissions 

from a taconite indurating furnace, basic 

oxygen furnace, nonrecovery coke oven 

battery, sinter process, EAF, argonoxygen decarburization vessel, and 

direct reduction furnace are emitted 

through the same stack as CO2

emissions from a combustion unit or 

process equipment that uses a CEMS 

and follows the Tier 4 methodology to 

report CO2 emissions, then the CEMS 

must be used to measure and report 

combined CO2 emissions from that 

stack. In such cases, the reporter cannot 

use the other process CO2 calculation 

approaches outlined above. 

• For coke oven pushing, facilities 

must use a CO2 emission factor 

provided in the rule. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart Q. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

Q. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart Q: Iron and 

Steel Production.’’ 

The major changes made since 

proposal include: 

• The carbon mass balance method 

was revised to require an annual 

analysis of all process inputs and 

outputs for carbon content rather than 

weekly sampling and monthly analysis. 

• The site-specific emission factor 

method was revised to: (1) Require 

testing based on representative 

performance rather than at 90 percent of 

capacity, (2) sampling for a minimum of 

three hours or production cycles rather 

than nine, (3) conducting separate tests 

for each different process condition that 

is a part of normal operation if the 

change in CO2 emissions at the different 

conditions is more than 20 percent, and 

(4) adding a provision to clarify testing 

requirements when the EAF and argonoxygen decarburization vessel are 

ducted to the same control device and 

stack. 

• To improve the emissions 

verification process, 40 CFR 98.176 was 

reorganized and updated. Some data 

elements were moved from 40 CFR 

98.177 to 40 CFR 98.176, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.173 were added to 40 CFR 

98.176 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses 

related to the requirements for iron and 

steel processes. A large number of 

comments on iron and steel production 

were received covering numerous 

topics. Many of these comments were 

directed at the requirements for 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources), and 

responses to those comments are 

provided in Section III.C of this 

preamble. Also see the Section II.N of 

this preamble for the response to 

comments on the emissions verification 

approach. Responses to other significant 

comments received related to process 

emissions from iron and steel 

production can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

Q: Iron and Steel Production.’’ 

Method for Calculating GHG Emissions 

Comment: Several industry 

representatives and their three trade 

associations requested that EPA allow 

the use of a simplified facility-wide 

carbon balance approach developed by 

the American Iron and Steel Institute 

(AISI) to calculate CO2 emissions from 

iron and steel production facilities. 

According to the commenters, the AISI 

methodology has recently been adapted 

to facility-wide reporting and is 

emerging as the preferred reporting 

protocol internationally. The 

commenters described the approach as 

based on determining the mass of 

carbon in the most significant carboncontaining inputs entering the plant and 

in the most significant carboncontaining outputs that leave as 

products or byproducts (excluding, for 

example, iron ore, scrap, steel). The 

difference between the mass of carbon 

entering the facility and leaving the 

facility is assumed to be converted to 

CO2. The annual mass rates of 

significant inputs and outputs are 

determined from company records, and 

their carbon contents are based on 

typical or default values. The 

commenters noted that the AISI 

approach provides a single estimate of 

the combined total CO2 emissions from 

all processes and combustion sources at 

the facility. The commenters claimed 

that the approach would provide a more 

accurate and complete accounting of 

facility-wide emissions at a much lower 

cost than that of the proposed EPA 

process-specific methods. 

Response: As we explained at 

proposal (74 FR 16517), we considered 

the many domestic and international 


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monitoring guidelines and protocols for 

process and combustion sources at iron 

and steel production facilities, 

including the AISI facility-wide 

approach. The vast majority of these 

guidelines and protocols are processspecific rather than facility-wide 

approaches (e.g., 2006 IPCC Guidelines, 

U.S. Inventory, the World Business 

Council for Sustainable Development 

(WBCSD)/WRI GHG protocol, DOE 

1605(b), TCR, European Union 

Emissions Trading System, and 

Environment Canada’s mandatory 

reporting guidelines). In addition, the 

‘‘higher tier’’ (more accurate) sitespecific methods use process-specific 

approaches. We explained at proposal 

(74 FR 16517) that we did not choose to 

propose these approaches based on the 

use of default values in general (such as 

the AISI approach) because the use of 

default values and lack of direct 

measurements results in a very high 

level of uncertainty (greater than ±25 

percent), and default approaches would 

not provide site-specific estimates of 

emissions that reflect differences in 

feedstocks, operating conditions, fuel 

combustion efficiency, variability in 

fuels, and other differences among 

facilities. 

We also stated at proposal that we 

decided not to finalize the proposal 

using methodologies that relied on 

default emission factors or default 

values for carbon content of materials 

because the differences among facilities 

described above could not be discerned, 

such default approaches are inherently 

inaccurate for site-specific 

determinations, and the use of default 

values is more appropriate for sector 

wide or national total estimates from 

aggregated activity data than for 

determining emissions from a specific 

facility. 

We further note here that the AISI 

approach is not adequate for our 

reporting needs because it provides only 

a single emissions number aggregated 

from the numerous individual processes 

and combustion units at the iron and 

steel facility. In contrast, the approaches 

we are promulgating today for 

determining CO2 emissions provide 

information at the process level and 

distinguish between combustion 

emissions and process emissions. 

Information at the process level is 

needed for many reasons, such as 

verification of the reported emissions 

from comparison with known ranges 

expected from various types of 

processes for a given production rate 

and emissions verification based on data 

for different plants for similar processes. 

Process-level reporting also provides 

information that will be useful in 

identifying processes that have reduced 

emissions over time and processes at 

specific plants that have the most 

potential for future reductions in 

emissions. In addition, the process-level 

reporting may provide information that 

can be used to improve methodologies 

for specific processes under future 

programs and to identify processes that 

may use a technology that could be the 

basis for an emission standard at a later 

time. 

We developed estimates of costs for 

the proposed options for determining 

CO2 emissions and concluded that the 

costs were reasonable. However, as 

explained below, we have revised the 

proposed options in response to 

comments, and these revisions 

significantly reduce the burden and 

costs of the carbon mass balance and 

site-specific emission factor methods 

while maintaining a similar level of 

accuracy. 

Comment: Several commenters 

claimed that the proposed carbon mass 

balance method is unnecessarily 

burdensome because it requires weekly 

sampling, monthly analyses, and 

determining the monthly mass 

quantities of all process inputs and 

outputs. The commenters suggested that 

EPA allow the use of default values for 

carbon content, neglect streams that 

have very little or no carbon, drop the 

requirement for analysis by an 

‘‘independent certified laboratory,’’ and 

allow the use of analyses from 

suppliers. One commenter 

recommended sampling and analysis for 

carbon content no more frequently than 

annually. The commenters stated that 

lime, dolomite and slag contain no 

appreciable carbon and do not need to 

be tracked, and that it is not necessary 

to account for the carbon in scrap that 

is charged to the furnace or in the steel 

product because they offset each other. 

One commenter noted that 

‘‘independent certified laboratory’’ is 

not defined or explained, and another 

claimed that it is an unnecessary 

complication and expense because these 

carbon analyses are typically done in an 

in-house laboratory. 

One commenter stated that the carbon 

mass balance equations were 

incomplete because they did not 

account for carbon removed by 

pollution control devices. Another 

commenter recommended that EPA use 

default carbon contents for different 

grades of steel scrap and noted that 

because companies already track the 

chemical content of each grade of scrap, 

highly accurate carbon calculations 

could be made with minimal additional 

burden. 

Response: We received several useful 

suggestions for improving the carbon 

mass balance method without 

significantly decreasing the accuracy in 

the estimates. After a close review of the 

sampling and analysis requirements and 

comparing them to the requirements 

applied to other source categories in 

other subparts of this reporting rule, we 

concluded that the weekly sampling and 

monthly analysis of carbon content 

could be reduced in frequency to an 

annual analysis of all inputs and 

outputs at each facility. We also revised 

the rule to allow the use of carbon 

content analyses from the material 

supplier, which is consistent with what 

is required in other subparts using the 

carbon balance method. Carbon content 

does not vary widely at a given facility 

for the significant process inputs and 

outputs that contain carbon, and we 

continue to account for variations due to 

changes in production rate, which is 

likely a more significant source of 

variability. We continue to choose not to 

use default values for the reasons given 

in the previous comment response, and 

we have determined that an annual 

analysis of carbon content to provide 

plant-specific values is not burdensome 

because facilities already perform many 

such analyses. We agree that the 

analysis does not have to be performed 

by an independent certified laboratory, 

especially since we specify the 

analytical procedures that must be used 

by any laboratory, and we note that inhouse laboratories may have more 

applicable experience in analyses of 

their particular process inputs and 

outputs. 

We agree with the suggestion to 

evaluate carbon content by the grade or 

type of ferrous material charged to the 

furnace, and we incorporated a 

provision to calculate an average carbon 

content of ferrous materials charged 

based on the average weight percent of 

each type that is used. In addition, we 

have corrected the equations as 

suggested to account for carbon in the 

residue collected by emission control 

equipment. Finally, we agree that inputs 

and outputs that contain no carbon or 

an insignificant amount (i.e., 

contributing to less than one percent of 

the carbon in or out) do not need to be 

tracked in the carbon balance method. 

Comment: Several commenters 

claimed that the site-specific emission 

factor method is not a viable option as 

proposed and should be streamlined to: 

(1) Eliminate annual re-testing, (2) 

reduce the test length from nine hours 

(or from nine production cycles for 

batch processes), (3) clarify that a 

separate test is not required for each 

grade of steel, and (4) remove the 


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requirement to operate at 90 percent of 

capacity. One commenter stated that the 

most frequent re-testing currently 

required in operating permits is once 

every 2.5 years rather than annually. 

Another commenter noted that nine 

production cycles for certain small 

specialty steel producers would require 

27 hours of testing for each grade of 

steel because each production cycle is 

three hours. Commenters stated that 

testing at 90 percent of production is 

problematic and is beyond their control 

because it is dictated by upstream and 

downstream production levels as well 

as economic conditions. In addition, 

capacity is difficult to determine 

because steelmaking furnaces do not 

have a nameplate capacity since it is 

determined by the iron production rate, 

how fast downstream processes (such as 

the caster) operate, process inputs, and 

product specifications that may require 

different operating cycle times. 

One commenter questioned the value 

of the requirement to re-test if the 

carbon content of feed materials changes 

by more than 10 percent because this 

type of change could occur on a daily 

or weekly basis when the grade of steel 

being produced changes. Another 

commenter noted that EPA did not 

define what constituted a significant 

change in fuel type or mix and 

recommended that the provision be 

changed to 20 percent to allow for 

environmentally beneficial process 

improvements. Two commenters stated 

that the 10 percent threshold for retesting is infeasible for steelmaking and 

sinter processes because of routine 

changes in the type of steel produced 

and the types of materials recycled to 

the sinter plant. The commenters 

requested that they be permitted to 

develop separate emission factors based 

on various modes that represent 

different operating scenarios or product 

categories. The commenters also 

recommended that EPA eliminate the 10 

percent change threshold for re-testing 

and require that testing be conducted 

under conditions that are representative 

of normal operation. One commenter 

noted that the rule did not address how 

a site-specific emission factor would be 

developed when emissions from the 

EAF and argon-oxygen decarburization 

vessel are combined and routed to a 

single emission control device and 

stack. 

Response: We further reviewed the 

testing requirement in other rules and 

those in operating permits and found 

that typical requirements (such as test 

requirements for particulate matter) 

include 3 one-hour runs or production 

cycles for representative testing of 

process emissions. Consequently, we are 

revising the testing requirements to 

three hours or three production cycles. 

We also agree with the commenters who 

noted that different routine operating 

modes may result in different levels of 

CO2 emissions, and it is necessary to 

develop separate emission factors for 

these different operating conditions. 

Consequently, we have dropped the 10 

percent re-testing threshold and instead 

require that separate emission factors be 

developed for each of different routine 

operating conditions that result in a 

change in CO2 emissions by 20 percent 

or more. 

We disagree that annual re-testing is 

excessive because testing for CO2

emissions is much simpler and less 

costly than sampling for hazardous 

pollutants or for particulate matter, and 

annual sampling is consistent with our 

requirement for annual reporting. We 

agree that it is not necessary or always 

possible to test while operating at 90 

percent of capacity for the reasons 

identified by the commenters. Instead, 

we are requiring that the test be 

performed based on representative 

performance, i.e., under normal 

operating conditions. We have revised 

the rule to clarify and provide options 

for testing when emissions from the 

EAF and argon-oxygen decarburization 

vessel are combined. 

Comment: Several commenters asked 

EPA to clarify that CH4 and N2O 

emissions do not have to be reported for 

iron and steel production processes, and 

other commenters requested that CH4

and N2O emissions reporting not be 

required for the combustion of coke 

oven gas and blast furnace gas. 

Commenters noted that default emission 

factors for CO2, CH4, and N2O were not 

provided in the tables in 40 CFR part 98, 

subpart C, and in the absence of such 

emission factors, asked if they would be 

required to test for these minor 

emissions. 

Response: We have clarified that 40 

CFR part 98, subpart Q does not require 

reporting of CH4 and N2O emissions 

from the iron and steel production 

processes because we expect these 

emissions (if any) to be very low, and 

we have no protocols for calculating 

them. However, emission factors are 

available in the 2006 IPCC guidelines 

for combustion sources, including the 

combustion of coke oven gas and blast 

furnace gas. We have added the IPCC 

default emission factors for CO2 and 

N2O for these process gases to the tables 

in 40 CFR part 98, subpart C, and we 

developed new emission factors for CH4

based on the typical CH4 content of coke 

oven gas (28 percent) and blast furnace 

gas (0.2 percent). 

R. Lead Production 

1. Summary of the Final Rule 

Source Category Definition. The lead 

production source category consists of 

primary lead smelters and secondary 

lead smelters. A primary lead smelter is 

a facility engaged in the production of 

lead metal from lead sulfide ore 

concentrates through the use of 

pyrometallurgical techniques (smelting). 

A secondary lead smelter is a facility at 

which lead-bearing scrap materials 

(including but not limited to lead-acid 

batteries) are recycled by smelting into 

elemental lead or lead alloys. 

Reporters must submit annual GHG 

reports for primary lead smelters and 

secondary lead smelters that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For lead production, 

report the following emissions: 

• CO2 process emissions from each 

smelting furnace used for lead 

production. 

• CO2 combustion emissions from 

each smelting furnace used for lead 

production. 

• N2O and CH4 emissions from each 

smelting furnace under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources) using the 

methodologies in subpart C. 

• CO2, N2O, and CH4 emissions from 

each on-site stationary combustion unit 

other than smelting furnaces under 40 

CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources). 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. To calculate annual process 

CO2 emissions from an affected smelting 

furnace, the reporter must use the 

following methods, as applicable to the 

affected smelting furnace. 

• For each affected smelting furnace 

with certain types of CEMS in place, the 

reporter must use the CEMS and follow 

the Tier 4 methodology (in 40 CFR part 

98, subpart C) to measure and report 

under the Lead Production subpart (40 

CFR part 98, subpart R) combined 

process and combustion CO2 emissions. 

• For other affected smelting 

furnaces, the reporter can elect to either 

(1) install and operate a CEMS and 

follow the Tier 4 methodology to 

measure and report combined process 

and combustion CO2 emissions or (2) 

calculate annual process CO2 emissions 

using a carbon mass balance procedure 

specified in 40 CFR part 98, subpart R. 

If using approach (2): 


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—Calculate emissions once per year 

using recorded monthly production 

data and the average carbon content 

for each smelting furnace input 

material determined by either using 

material supplier information or by 

annual analysis of representative 

samples of the material. 

—Report process CO2 emissions from 

each smelting furnace under 40 CFR 

part 98, subpart H (Cement 

Production), and report combustion 

CO2 emissions from each kiln under 

40 CFR part 98, subpart C (General 

Stationary Fuel Combustion Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart R. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

R. 

2. Summary of Major Changes Since 

Proposal 

The major changes to the rule since 

proposal for lead production facilities 

were revisions to the carbon mass 

balance calculation procedure used by 

reporters for calculating process CO2

emissions from affected smelting 

furnaces. The rationale for these and 

any other significant changes can be 

found below or in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

R: Lead Production.’’ 

• The frequency of performing the 

carbon mass balance calculations was 

revised to be required on an annual 

basis instead of the proposed monthly 

basis. 

• The frequency of material carbon 

content sampling and analysis of each 

smelting furnace input material used for 

the carbon mass balance was revised to 

be performed by annual analysis of 

representative samples of the material 

instead of the proposed monthly basis. 

• A de minimis carbon content level 

was added to exclude the need to 

account for carbon-containing materials 

contributing less than one percent of the 

total carbon into the smelting furnace in 

the carbon mass balance calculations. 

• Data reporting procedures (40 CFR 

98.186) were reorganized and updated 

to consolidate and clarify the emissions 

verification process. Some data 

elements for the carbon mass balance 

calculation were moved from 40 CFR 

98.187 to 40 CFR 98.186, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.183 were added to 40 CFR 

98.186 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses 

specific to the lead production source 

category. Comments were received from 

one commenter regarding several topics. 

Responses to significant comments 

received are presented in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

R: Lead Production.’’ 

Selection of Threshold 

Comment: The commenter stated that 

Lead Production is not a source of 

significant GHG emissions and that EPA 

cannot assert that the Lead Production 

sector is a significant part of the 

stationary source combustion sector. 

The commenter notes that based on 

EPA’s estimates in the TSDs for the 

proposal, estimated emissions from the 

Lead Production sector are 0.02 percent 

of the total estimated nationwide 

emissions from stationary fossil fuel 

combustion. Moreover, they argue that 

the combustion-related emissions from 

lead production are overstated by 

incorrect assumptions in the TSD. The 

commenter states that given Lead 

Production’s relative contribution, it is 

not a significant source of emissions and 

should be eliminated from further 

consideration. The commenter further 

states that Lead Production is the only 

category evaluated where raising the 

threshold to the 100,000 ton level would 

results in zero facilities being covered. 

Accordingly, when the analysis shows 

that all facilities in a particular source 

category are not covered at the 100,000 

ton threshold level, no insignificant 

GHG emitters in the category should be 

required to report under the Proposed 

Rule. The commenter noted that using 

the 100,000 threshold would not 

significantly reduce the coverage of 

emissions of EPA’s rule, as the majority 

of sources identified would still have 

well over 90 percent of emissions from 

that source category covered under the 

100,000 threshold. EPA provides no 

justification for imposing substantially 

more costs on industry for limited 

estimated benefits and small likelihood 

for regulation under the CAA. For these 

reasons, the Lead Production sector 

should be eliminated as a source 

category, and EPA should raise the 

threshold to 100,000 for non-source 

category facilities. 

Response: We acknowledge this 

comment and concerns; however, the 

final rule retains the applicability 

requirement for this source category. We 

used information available to us for 

estimating GHG emissions from this 

industry which involved several 

assumptions related to the emission 

factors in the IPCC Guidance and other 

sources. As noted by the commenter, 

many of the underlying assumptions 

were based on an international 

perspective as opposed to the primary 

and secondary lead production industry 

in the U.S. The final rule contains a 

threshold of 25,000 metric tons CO2e 

and only lead production facilities with 

emissions that equal or exceed 25,000 

metric tons CO2e will have to report 

emissions. In addition, the final rule 

now contains provisions allowing a 

reporter to cease reporting if the annual 

reports for a given facility demonstrate 

emissions less than specified levels for 

multiple years. These provisions apply 

to all reporting facilities, including 

those with lead production processes. 

See Section II.H of this preamble for the 

response on provisions to cease 

reporting. 

We have further simplified the 

reporting requirement to further reduce 

burden for lead and similar industries 

by requiring annual as opposed to 

monthly sampling of carbon inputs. The 

purpose of this rule is to collect 

information on emissions sources for 

future policy development. Requiring 

reporting for these sources will provide 

EPA with valuable data to better 

characterize them and provide a more 

credible position if EPA elects to 

exclude these sources from future GHG 

policy analyses. Additionally, while 

some of these sources are currently 

believed to be small compared to the 

larger sources, they are not necessarily 

insignificant. The inclusion of reporting 

data for these sources is critical to 

support analysis of future policy 

decisions for lead production facilities. 

When evaluating potential thresholds 

for reporting GHG emissions, we 

considered several thresholds between 

1,000 and 100,000 metric tons CO2e. We 

selected the 25,000 metric tons CO2e 

threshold for reporting GHG emissions 

in order to achieve a balance between 

quantifying the majority of the 

emissions, while minimizing the 

number of facilities impacted. For 

example, at a 1,000 metric tons CO2e 

threshold, 99 percent of emissions 

would be covered, with about 63 


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percent of facilities being required to 

report. The 100,000 metric tons CO2e 

threshold captures no emissions or 

facilities while the proposed 25,000 

metric tons CO2e threshold achieves 

reporting of 92 percent of the GHG 

emissions while requiring less than 50 

percent of the facilities to report. We 

consider this a significant coverage of 

the emissions, while impacting a 

relatively small portion of the industry. 

We believe the proposed threshold of 

25,000 metric tons CO2e represents the 

best option for ensuring that the 

majority of emissions are reported 

without imposing an unreasonable 

burden on the industry. See also Section 

II.E of this preamble and ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, 

Selection of Reporting Thresholds, 

Greenhouse Gases, and De Minimis 

Provisions.’’ 

Method for Calculating GHG Emissions 

Comment: The commenter made 

several comments regarding the 

proposed procedures used to calculate 

process CO2 emissions from smelting 

furnaces at secondary lead smelters. 

First, use of default emission factors 

should be allowed as a calculation 

method alternative because the smelting 

furnaces operated at used lead battery 

recycling facilities consistently process 

furnace feed materials with low carbon 

content variability. For affected sources 

using the carbon mass balance 

procedure, the frequency required for 

monitoring carbon content of the 

smelting furnace input materials should 

be reduced to reflect consistency and 

low carbon content variability of these 

materials. 

Response: We decided not to finalize 

the proposal using methodologies for 

calculating CO2 emissions from lead 

production that relied on published 

default emission factors or default 

values for carbon content of materials 

because the differences among 

individual lead production facilities 

could not be discerned using these 

factors. Consequently, the available 

default factors for lead production 

facilities are inherently less accurate for 

calculating smelting furnace process 

CO2 emissions than using procedures 

that include use of site-specific material 

carbon data. Default approaches do not 

provide site-specific estimates of 

emissions that reflect differences in use 

of and variability in feedstocks, 

variability in fuels, operating 

conditions, fuel combustion efficiency, 

and other differences among facilities. 

For some carbon-containing input 

materials, such as lead scrap, 

representative published defaults do not 

exist. Therefore, the use of default 

values is more appropriate for sector 

wide or national total estimates from 

aggregated production data for multiple 

facilities rather than for providing an 

accurate representation of CO2

emissions from a specific facility. 

For the final rule, we did reduce the 

monitoring frequency for determining 

carbon contents of the smelting furnace 

input materials used for the carbon mass 

balance to be determined on annual 

rather than monthly basis. Facilities can 

determine carbon contents either by 

using material supplier information or 

by annual analysis of representative 

samples of the input materials. We agree 

that the carbon content for the 

significant input materials typically 

does not vary widely at a given lead 

production facility. Annual carbon 

content determinations will still provide 

representative carbon content data for 

the smelting furnace process CO2

emissions calculations while 

minimizing the monitoring burden on 

reporters. We continue to account for 

process variations due to changes in 

production rate, which is likely a more 

significant source of variability in the 

CO2 emissions from an affected smelting 

furnace during the year, by maintaining 

the requirement to measure and record 

monthly carbon containing input 

materials. 

S. Lime Manufacturing 

1. Summary of the Final Rule 

Source Category Definition. Lime 

manufacturing plants (LMPs) engage in 

the manufacture of a lime product (e.g., 

calcium oxide, high-calcium quicklime, 

calcium hydroxide, hydrated lime, 

dolomitic quicklime, dolomitic hydrate, 

or other products) by calcination of 

limestone, dolomite, shells or other 

cacareous substances. This source 

category includes all LMPs unless the 

LMP is located at a kraft pulp mill, soda 

pulp mill, sulfite pulp mill, or only 

processes sludge containing calcium 

carbonate from water softening 

processes. 

Lime kilns at pulp and paper 

manufacturing facilities need to report 

emissions under 40 CFR part 98, subpart 

AA (Pulp and Paper Manufacturing). 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble and meet 

the definition of lime manufacturing 

plants in 40 CFR 63.7081(a)(1). 

GHGs to Report. For lime 

manufacturing, report the following 

emissions: 

• Total CO2 process emissions from 

all lime kilns combined. 

• CO2 combustion emissions from 

lime kilns. 

• N2O and CH4 emissions from fuel 

combustion at each kiln under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources) using the 

methodologies in subpart C. 

• CO2, N2O, and CH4 emissions from 

each stationary combustion unit other 

than kilns under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources). 

• CO2 collected and transferred off 

site under 40 CFR part 98, subpart PP 

(Suppliers of CO2). 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. For CO2 emissions from 

kilns, facilities must use one of two 

methods, as appropriate: 

• If all lime kilns at a facility have 

certain types of CEMS in place, the 

reporter must use the CEMS and follow 

the Tier 4 methodology (in 40 CFR part 

98, subpart C) to measure and report 

under the Lime Manufacturing subpart 

(40 CFR part 98, subpart S) combined 

process and combustion CO2 emissions. 

• If CEMS meeting the specifications 

above are not in place for all kilns at the 

facility, the reporter can elect to either 

(1) install and operate a CEMS and 

follow the Tier 4 methodology to 

measure and report combined process 

and combustion CO2 emissions from all 

lime kilns or (2) calculate CO2 process 

emissions for each lime type using an 

emission factor for each lime type, the 

mass of lime produced, an emission 

factor for byproduct/waste (such as lime 

kiln dust and scrubber sludge), and the 

mass of byproduct/waste. If using 

approach (2): 

—Each emission factor must be 

determined monthly for each lime 

type from monthly measurements of 

the calcium oxide and magnesium 

oxide content of the lime and 

stoichiometric ratios of CO2 to each 

oxide in the lime. 

—The emission factor for each lime 

byproduct/waste sold (such as lime 

kiln dust) must be determined 

monthly. 

—The emissions from lime byproducts/ 

wastes that are not sold (such as lime 

kiln dust and scrubber sludge) must 

be determined annually. 

—The mass of each lime type produced 

and lime byproduct/waste sold (such 

as lime kiln dust) must be recorded on 

a monthly basis. 


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—The mass of each lime byproduct/ 

waste not sold (such as lime kiln dust 

and scrubber sludge) must be 

recorded annually. 

—Report process CO2 emissions from all 

kilns combined under 40 CFR part 98, 

subpart S (Lime Manufacturing), and 

report combustion CO2 emissions 

from each kiln under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart S. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

S. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart S: Lime 

Manufacturing.’’ 

• The definition of lime 

manufacturing was revised to be similar 

to the definition in the Lime NESHAP 

at § 63.7081(a) and (a)(1). 

• Reporting requirements were 

revised from a ‘‘per kiln’’ basis to ‘‘all 

kilns combined’’. 

• The emissions calculations were 

revised to determine monthly emissions 

factors for each lime type and 

byproduct/waste type rather than for 

each kiln. 

• Emission calculations for 

byproducts/wastes were added. 

• The requirement to measure the 

calcium oxide and magnesium oxide 

content of byproducts/wastes on a 

monthly basis was changed to an annual 

basis for byproducts/wastes that are not 

sold. 

• The correction factor for 

byproducts/wastes was removed from 

the rule. 

• Additional direct measurement 

devices/methods are being allowed to 

include those currently in use by the 

industry. 

• 40 CFR 98.196 was reorganized and 

updated. Some data elements were 

moved from 40 CFR 98.197 to 40 CFR 

98.196, and some data elements that a 

reporter must already use to calculate 

GHGs as specified in 40 CFR 98.193 

were added to 40 CFR 98.196 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on lime 

manufacturing were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart S: Lime 

Manufacturing.’’ 

Definition of Source Category 

Comment: Multiple commenters 

requested more clarification in defining 

which sources and equipment are 

covered by the proposed rule. The rule 

defines the source category as a facility 

that contains ‘‘a rotary lime kiln to 

produce a lime product.’’ In addition, 

proposed 40 CFR 98.192(b) required 

sources to report emissions from ‘‘each 

lime kiln and any other stationary 

combustion unit.’’ 

Response: We have reviewed the rule 

language and decided the source 

category definition should provide more 

clarity. The source category is meant to 

include all kiln types used in the lime 

manufacturing industry; therefore, 

language in the final rule has been 

changed to be similar to the definition 

from the Lime NESHAP in 40 CFR 

63.7081(a) and (a)(1). This Lime 

NESHAP effectively characterizes lime 

plants as those engaging in the 

manufacture of a lime product by 

calcination. The final rule requires all 

stationary combustion units to report 

under 40 CFR part 98, subpart C of the 

final rule. 

Final rule language under 40 CFR 

98.192 requires facilities to report CO2, 

CH4, and N2O emissions from kilns used 

in the lime manufacturing process and 

all other combustion units at the lime 

manufacturing facility other than kilns. 

The language has also been clarified in 

40 CFR 98.193. Facilities using CEMS 

for all lime kilns report combined 

process and combustion emissions from 

kilns under 40 CFR part 98, subpart S, 

according to the Tier 4 methodology in 

40 CFR part 98 subpart C (General 

Stationary Fuel Combustion Sources). 

Facilities must follow the requirements 

of subpart C for estimating and reporting 

combustion related emissions for all 

other combustion units and report these 

emissions under subpart C. See Section 

III.C of this preamble for an overview of 

the requirements for stationary 

combustion units. 

Selection of Proposed GHG Emissions 

Calculation and Monitoring Methods 

Comment: Multiple commenters 

requested the language in 40 CFR part 

98, subpart S be changed to allow 

emissions to be reported by ‘‘all kilns 

combined’’ instead of the proposed 

rule’s request to report emission for 

each kiln. Multiple commenters further 

recommended that the process 

emissions calculations be changed to 

calculate emissions by the lime type 

produced as opposed to the current rule 

calculations which use a kiln specific 

emission factor. Two commenters stated 

that lime products are commonly 

aggregated at the plant making it 

difficult to estimate the amount of 

product produced at an individual kiln. 

These commenters stated that current 

lime plant configuration do not allow 

accurate kiln specific calculations. 

Response: We have reviewed the 

common lime plant configuration and 

the currently proposed rule language 

and have decided that it is not necessary 

to require kiln-specific emissions 

reporting. We have observed that some 

kilns would have to retrofit weigh belt 

scales in the production line between 

kilns and storage silos, since they do not 

currently exist. Calculating emissions by 

kiln could increase the reporting burden 

for these facilities. According to one 

commenter, when kiln-specific 

emissions have been reported in the 

past, the data are usually derived by 

distributing the aggregated emissions 

among the kilns. Accurate 

measurements at the kiln level are rarely 

achieved. If this is true for most lime 

manufacturing facilities, the data does 

not necessarily provide a better estimate 

of emissions. 

For the purposes of this rulemaking, 

reporting for all kilns combined will 

simplify and minimize the reporting 

burden without significant loss in 

accuracy because: (1) Kilns may 

produce more than one type of lime in 

a given reporting period, (2) emission 

factors are based on lime type, and (3) 

lime plants collect products in 

combined bagging areas (separated by 

lime type). The final rule language has 

been changed to require reporting by 

lime type from all kilns combined rather 

than all lime types for each kiln. This 

final rule language is consistent with the 

National Lime Association (NLA) 

Protocol, which was used as the basis 

for the methodology in the proposed 

rule. Information collected under this 

rule will help to inform future 

methodologies and determine whether 


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kiln level reporting could be more 

appropriate for future reporting. 

Comment: The proposed rule used a 

default correction factor in calculating 

lime product and byproduct/waste 

emissions. Multiple commenters 

suggested using the National Lime 

Association Protocol to determine lime 

product and by-product/waste process 

emissions. According to the 

commenters, this method is more 

precise due to the use of measured 

oxide values and stoichiometric ratios 

rather than correction factors. 

Response: We have reviewed the 

proposed rule and NLA Protocol 

calculation methods and noted that the 

use of actual oxide measurements in 

calculating emissions from lime plants 

does not cause an additional burden to 

the reporter since this is a currently 

used practice. We also agree that the use 

of actual measurements is more 

accurate. Therefore, we have decided to 

remove the use of a correction factor in 

the final rule equations; emissions will 

be calculated from actual oxide 

measurements of each type of lime and 

calcined byproducts/wastes. 

Monitoring and QA/QC Requirements 

Comment: Multiple commenters 

asked that the language pertaining to 

allowable measurement devices for lime 

products and byproducts/wastes sold, 

be changed to include measurement 

devices commonly used in the lime 

industry. The current rule language 

requires weigh hoppers and belt weigh 

feeders as the measurement devices; the 

aforementioned commenters have 

identified bag, truck and rail scales as 

reliable (annually calibrated) direct 

measurement methods commonly used 

in the lime industry. In addition, 

commenters have requested lime 

byproducts/wastes not sold be 

calculated by a facility generation rate. 

Response: After reviewing the rule 

language and common industry 

practices, we have decided to include 

other direct measurement devices used 

for accounting purposes, including but 

not limited to, weigh feeders, calibrated 

bag, rail or truck scales, and barge 

measurements. These methods are 

consistent with the original intent of the 

rule and add further clarification on 

measurement methods applicable to 

determine quantities of both lime 

produced and byproducts/waste 

generated. 

In addition, reporters are required to 

perform an annual cross check by 

measuring lime products at the 

beginning and end of the year. For 

calcined byproducts/wastes not sold, a 

material balance approach that 

indirectly measures the generation rate 

should be used. 

Comment: Multiple commenters 

asked that the language in 40 CFR part 

98, subpart S pertaining to testing the 

chemical composition of each type of 

lime (including the byproducts and 

waste) be changed to allow testing by 

onsite lab facilities. Currently the rule 

specifies an ‘‘off-site laboratory 

analysis’’ but according to the 

commenter, commercial lime plants 

normally have onsite lab facilities. 

Response: We agree that the analysis 

does not have to be performed by an 

independent certified laboratory, 

especially since we specify the 

analytical procedures that must be used 

by any laboratory, and we note that inhouse laboratories may have more 

applicable experience in determining 

chemical composition. Reporters can 

determine whether to perform the test 

onsite or send the samples to offsite 

laboratory facilities. Therefore the 

language in the final rule has been 

changed. 

Data Reporting Requirements 

Comment: Multiple commenters 

requested the language in 40 CFR part 

98, subpart S pertaining to reporting 

information to EPA be changed so that 

business sensitive information is kept in 

company records. Commenters agree 

that the production capacity, product 

quality (i.e., oxide content), emission 

factors and operating hours and days for 

each kiln, are required for emissions 

calculations but are concerned that 

making this information public would 

give information about their efficiency, 

productivity and capacity of kilns and 

facility. 

Response: EPA reviewed CBI 

comments received across the rule (both 

general and subpart-specific comments) 

and our response is discussed in Section 

II.R of this preamble for legal issues. 

Also, see Section II.N of this preamble 

for the response to comments on the 

emissions verification approach. 

We agree that annual operating hours 

and capacities are not used in the 

calculation of CO2 emissions and these 

parameters have been moved to 

recordkeeping. This information can 

help to verify anomalies in emissions 

data if there were temporary shutdowns, 

etc. 

We disagree that emission factors and 

product quality be maintained as 

records rather than be reported. 

Emission factors and product quality are 

used in calculations to establish the site 

specific rate of CO2 emissions generated 

for each type of lime produced. 

Therefore these data are required in 

order to verify the CO2 emissions that 

are being reported. This internal 

verification system ensures that the 

GHG emissions reported are accurate. 

T. Magnesium Production 

At this time EPA is not going final 

with the magnesium production subpart 

(40 CFR part 98, subpart T). For the 

immediate future, EPA believes that 

emissions of GHGs from magnesium 

production are sufficiently covered by 

the reporting requirements under 40 

CFR part 98, subpart OO for Industrial 

Gas Supply. This information on U.S. 

production, imports, and exports of SF6

will provide at least a general, order-ofmagnitude check on consumption of SF6

by magnesium production and other 

uses of SF6. EPA will finalize the 

proposed reporting requirements for the 

magnesium production industry at a 

later date. 

U. Miscellaneous Uses of Carbonate 

1. Summary of the Final Rule 

Source Category Definition. The 

Miscellaneous Uses of Carbonate source 

category consists of any facility that 

uses carbonates listed in Table U–1 of 

40 CFR part 98, subpart U in 

manufacturing processes that emit 

carbon dioxide. The Table includes the 

following carbonates: Limestone, 

dolomite, ankerite, magnesite, siderite, 

rhodochrosite, or sodium carbonate. 

Facilities are considered to emit CO2 if 

they consume at least 2,000 tons per 

year of the carbonates listed above and 

that are heated to a temperature 

sufficient to allow calcination to occur. 

This source category does not include 

facilities processing carbonates or 

carbonate containing minerals 

consumed for producing cement, glass, 

ferroalloys, iron and steel, lead, lime, 

phosphoric acid, pulp and paper, soda 

ash, sodium bicarbonate, sodium 

hydroxide or zinc as CO2 emissions 

from these processes are covered 

elsewhere in this rule. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For miscellaneous 

uses of carbonates, report the following 

emissions: 

• Annual CO2 process emissions for 

all miscellaneous uses of carbonates as 

specified in this subpart. 

• CO2, N2O, and CH4 emissions from 

carbonates used in sorbent technology 

and each stationary combustion unit on 

site under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

In addition, report GHG emissions for 

other source categories at the facility for 


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which calculation methods are provided 

in the rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. Calculate process CO2

emissions using annual carbonate 

consumption. All reporters must 

calculate the annual mass of carbonates 

used in processes which are heated to 

temperatures that allow calcination. If 

the annual amount of carbonates 

consumed is greater than 2,000 tons, 

CO2 emissions must be calculated using 

either calcination fractions or the actual 

mass of input/output carbonates. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart U. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of analyses and calculations required for 

this source category. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart U: 

Miscellaneous Uses of Carbonates.’’ 

• The source category definition was 

revised to exclude non-emissive uses of 

carbonates. 

• A de minimis reporting threshold 

was added to exclude facilities with 

minor emissions based on annual 

carbonate consumption. 

• The GHG calculation methodology 

was changed to allow reporters to 

determine emissions from the mass of 

carbonate input/output or calcination 

fractions. 

• To improve the emissions 

verification process, 40 CFR 98.216 was 

reorganized and updated. Some data 

elements were moved from 40 CFR 

98.217 to 40 CFR 98.216, and some data 

elements that a reporter must already 

use to calculate GHG as specified in 40 

CFR 98.213 were added to 40 CFR 

98.216 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on 

miscellaneous uses of carbonates were 

received covering numerous topics. 

Most comments requested clarification 

on the definition of the source category 

and its applicability to affected sources. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

U: Miscellaneous Uses of Carbonates.’’ 

Definition of Source Category 

Comment: Multiple commenters 

requested that the source category be 

revised to exclude non-emissive uses of 

carbonates. Commenters stated that the 

source category is poorly defined, 

making it difficult to accurately assess 

its applicability to an industrial facility. 

Commenters noted a number of nonemissive uses as examples, such as the 

production of sodium bicarbonate and 

sodium hydroxide, during which 

sodium carbonates are used, but no 

carbon dioxide is released; onsite 

mixing of processed cement with 

aggregate, limestone used in poultry grit 

and as an asphalt filler; or adding 

sodium carbonate to a water softener 

system. 

Response: The rule language has been 

modified to exclude non-emissive uses 

of carbonates. Non-emissive uses do not 

result in CO2 emissions, such as adding 

sodium carbonate to a water softener 

system. Acid-induced releases of CO2

from the use of carbonates are addressed 

in other subparts, where they are 

significant, such as Phosphoric Acid 

Production. 

Selection of Threshold 

Comment: Multiple commenters 

requested that a de minimus reporting 

threshold be added to exclude facilities 

with minor emissions. One commenter 

noted that some facilities use limestone 

and other carbonate as refractory in 

furnaces, and it is unclear whether or 

not this use of carbonates triggers 40 

CFR part 98, subpart U, and at what 

level it is triggered. 

One commenter noted that at a 

pharmaceutical manufacturing facility 

there would also be a significant listing 

of small operations and activities which 

use carbonate compounds in trace 

quantities, including the creation of 

reagent solutions, and wastewater 

treatment operations employing 

carbonate compounds for buffering, 

chemical precipitation, or solids 

stabilization. This commenter 

recommended that EPA implement a 

threshold of 2,000 tons per year of 

carbonates per facility, which would 

correlate to CO2 emissions of about 

1,000 tons per year. 

One commenter requested that EPA 

incorporate a de minimis threshold to 

only include equipment where 

carbonate is present at greater than 10 

percent by weight and heated to a 

temperature that allows for 

decomposition. This commenter 

suggested an alternative threshold, 

where EPA would require facilities to 

calculate CO2 emissions from each type 

of carbonate used in quantities 

exceeding 2,000 tons per year. 

Response: The rule language has been 

modified to specify that GHG emissions 

from miscellaneous carbonate use are 

required to be reported only from 

processes that consume at least 2,000 

tons per year and, further, where the 

carbonates are heated to a temperature 

sufficient to allow the calcination 

reaction to occur. This modification to 

the definition of the source category 

allows facilities with minimal carbonate 

consumption and low amounts of GHG 

emissions to be excluded from reporting 

emissions. 

Method for Calculating GHG Emissions 

Comment: Multiple commenters 

requested that EPA allow emission 

calculations to be based on carbonate 

fraction of the product instead of 

calcination fractions. 

Response: The rule has been changed 

to allow emission calculations by either 

the mass of carbonate input/output or 

calcination fraction. These methods 

should provide comparable estimates of 

emissions. 

The calcination fraction method 

calculates the amount of CO2 emissions 

based on the amount of each carbonate 

that is calcined during the process. The 

mass and calcination fraction of each 

carbonate are measured and used with 

a default CO2 emission factor to 

determine CO2 emissions. 

The carbonate fraction method 

calculates the amount of CO2 emissions 

as a mass balance between the input and 

output amount of each type of 

carbonate. The masses are measured and 

used with a default CO2 emission factor 

to determine CO2 emissions. 

The mass of carbonate input/output is 

determined by use of the same plant 

instruments used for accounting 

purposes or by direct measurement. 

Calcination fractions can be measured 

by the appropriate industry consensus 

standards that require laboratory 

analysis of each carbonate type. 

Alternatively, a default value of one can 

be used as the calcination fraction. 

Data Reporting Requirements and 

Records That Must Be Retained 

Comment: One commenter requested 

that recordkeeping and reporting 


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requirements be exempted for 

carbonates kept on-site for emergency 

purposes (not manufacturing or 

equipment), such as for neutralizing a 

chemical spill. This commenter 

explained that when used, these 

emergency reserves of carbonate 

material typically generate insignificant 

amounts of CO2 and should therefore be 

excluded from reporting requirements. 

Response: The final rule does not 

cover carbonates that are used in 

quantities of less than 2,000 tons per 

year and that are not heated to the point 

of calcination. Also, this subpart does 

not include requirements for calculating 

and reporting CO2 emissions from acid 

neutralization. Therefore, the use of 

carbonates in the manner described is 

not covered by the final rule. 

Comment: One commenter noted that 

the required records are duplicated in 

proposed 40 CFR 98.217(a) and 

98.217(c), and requested that EPA revise 

this so as not to place unnecessary costs 

on facilities. 

Response: EPA agrees that asking 

facilities to maintain records on 

procedures used to ensure the accuracy 

of monthly carbonate consumption will 

be duplicative with maintaining records 

of all carbonate purchases and 

deliveries. This is especially true if 

purchase records are used to determine 

monthly carbonate consumption. We 

removed this duplicative recordkeeping 

requirement from the rule. 

To improve the emissions verification 

process, 40 CFR 98.216 was reorganized 

and updated. Some data elements were 

moved from 40 CFR 98.217 to 40 CFR 

98.216, and some data elements that a 

reporter must already use to calculate 

GHG as specified in 40 CFR 98.213 were 

added to 40 CFR 98.216 for clarity. All 

affected sources must follow the general 

recordkeeping provisions under 40 CFR 

part 98.3(g) in subpart A. 

Commenters may also want to review 

Section II.M for the response on the 

general recordkeeping requirements and 

Section II.N of this preamble for the 

response on the emissions verification 

approach. 

V. Nitric Acid Production 

1. Summary of the Final Rule 

Source Category Definition. The nitric 

acid production source category consists 

of facilities that use one or more trains 

to produce weak nitric acid (30 to 70 

percent in strength) through the 

catalytic oxidation of ammonia. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For nitric acid 

production facilities, report N2O process 

emissions from each nitric acid train. 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. For example, 

report CO2, N2O, and CH4 emissions 

from each stationary combustion unit on 

site under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and 

Monitoring. Reporters must calculate 

N2O process emissions for each nitric 

acid train. Calculate the emissions by 

multiplying the site-specific emission 

factor for each train by the measured 

annual nitric acid production for that 

train. Determine the site-specific 

emission factor for each train through an 

annual performance test to measure N2O 

from the absorber tail gas vent and the 

production rate for that train. 

When N2O abatement devices (such as 

nonselective catalytic reduction) are 

used, adjust the N2O process emissions 

for the amount of N2O removed using a 

destruction efficiency factor. The 

destruction factor is the destruction 

efficiency and can be specified by the 

abatement device manufacturer or can 

be determined using process knowledge 

or another performance test. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart V. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, 

subpart V. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart V: Nitric 

Acid Production.’’ 

• The re-testing trigger was changed. 

Performance testing to determine the 

N2O emissions factor is required 

annually and whenever new abatement 

technology is installed. The 

performance test should be conducted 

under normal operating parameters. 

• Equation V–2 was edited to correct 

a calculation error and to allow multiple 

types of abatement technologies. 

• Reorganized and updated 40 CFR 

98.226 to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.227 to 40 CFR 98.226, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.223 were added to 40 CFR 

98.226 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on nitric acid 

production were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart V: Nitric 

Acid Production.’’ 

GHGs To Report 

Comment: Multiple commenters 

asked that the language in 40 CFR 

98.222(b) be clarified to include 

emissions under 40 CFR part 98, subpart 

V only from units that are 100 percent 

dedicated to nitric acid production to 

avoid double counting of combustion 

emissions. 

Response: We appreciate the 

comments but have decided not to make 

any changes to 40 CFR part 98, subpart 

V. According to the applicability criteria 

in subpart C, all combustion unit 

emissions from nitric acid facilities 

(regardless of whether or not the 

combustion units are associated with 

nitric acid production operations) are to 

be reported under subpart C. There will 

be no potential for double counting of 

combustion emissions at the facility 

because Subpart V provides methods for 

reporting only the process emissions. 

Also see the preamble for responses on 

comments related to Subpart C (General 

Stationary Combustion). 

Method for Calculating GHG Emissions 

Comment: Multiple commenters 

asked that the requirement to repeat the 

annual performance test be removed. In 

the proposal, re-testing was triggered 

whenever the nitric acid production rate 

changed by more than 10 percent. 

Commenters asserted that production 

depends on demand for nitric acid and 

often varies by up to 20 percent. 

Response: We appreciate the 

comments and have decided to 

eliminate re-testing. We believe that 


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annual determination of the N2O 

emissions factor is sufficient to 

accurately calculate N2O emissions as 

long as the train equipment remains 

consistent over the year-long period 

(i.e., no installation of abatement 

technology). 

Comment: Multiple commenters 

asked that alternative methods be 

allowed for calculating N2O emissions 

from nitric acid production. Specifically 

the commenters asked that EPA allow 

the use of N2O and flow CEMS to 

directly measure N2O emissions and use 

the performance test to evaluate the 

CEMS accuracy. They also requested 

that EPA allow use of existing process 

flow meters, process N2O analyzers to 

determine the amount of N2O sent to 

control devices and conduct a 

performance test measuring control 

device destruction efficiency for each 

control device and then calculate N2O 

emissions. 

Commenters also asked that finalizing 

a methodology for N2O stack testing for 

nitric acid units be delayed until EPA 

can coordinate with the commenters in 

formulating a more accurate means of 

measurement from these sources. 

Response: We agree that there are 

other accurate means of determining 

N2O emissions, such as N2O CEMS. The 

final rule has been changed to allow 

alternative test methods, in addition to 

the proposed methods. Any alternative 

must be approved by the Administrator 

before being used to comply with this 

rule. An implementation plan that 

details how the alternative method will 

be implemented must be included in the 

request for the alternative method. 

Currently there is no EPA method for 

using N2O CEMS. EPA understands the 

need to further evaluate and establish 

alternative comparable or potentially 

more accurate methods for sources to 

use in calculating N2O emissions from 

nitric acid production and will address 

this in future rulemakings or 

amendments to rulemaking. Until the 

method is approved, facilities must use 

the alternatives proposed in the rule for 

a performance test. At minimum the 

performance test will help to QA/QC 

alternative methods currently used to 

monitor N2O emissions (including N2O 

CEMS). 

The final rule allows the use of 

existing process flow meters and 

process knowledge in the determination 

of the destruction efficiency of N2O 

abatement technologies. This parameter 

is often based on site-specific 

knowledge of operations in combination 

with manufacturer specifications. We 

believe that using existing methods 

reduces the potential cost impacts of 

this rulemaking and that it is in the best 

interest of the facilities that required 

parameters be accurately measured. 

Comment: Multiple commenters 

asked that Equation V–2 be edited to 

follow the summation format used in 

the IPCC Tier 2 methodology. The 

current format does not allow for 

multiple abatement technologies 

(including no abatement). 

Response: We agree with this 

comment. The equation in the proposed 

rule contained an error and did not 

allow for multiple abatement 

technologies. The final rule contains a 

corrected version of the equation. 

Data Reporting Requirements 

Comment: Multiple commenters 

argued that the annual production rates, 

capacity and operating hours are 

considered CBI and should not be 

reported. The commenters asked that 

this information be maintained by the 

facility and made available to the 

Agency upon request. 

Response: We reviewed CBI 

comments received across the rule (both 

general and subpart-specific comments) 

and our response is discussed in Section 

II.R of this preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ See also Section II.N of this 

preamble for the response on the 

emissions verification approach. 

We agree that annual operating hours 

are not used in the calculation of N2O 

emissions and this parameter has been 

moved to recordkeeping. However, this 

parameter is still important for 

emissions verification. This information 

can help to verify anomalies in 

emissions data if there were temporary 

shutdowns, etc. 

We disagree that production be 

maintained as records rather than be 

reported. Nitric acid production is a 

parameter in the method for 

determining annual N2O emissions so 

we need production rate in order to 

verify the N2O emissions that are being 

reported. The internal verification 

system ensures that the GHG emissions 

reported are as accurate as possible. 

We disagree that capacities be 

considered confidential information. 

During the data gathering process, we 

located multiple publicly available 

sources that included production 

capacities for nitric acid production 

facilities. Capacity information can help 

EPA determine a reasonable range 

within which reported emissions should 

be. We agree that capacities are not used 

in the calculation of N2O emissions; 

however, this is still an important 

parameter for verifying emissions. 

Therefore, this parameter has been 

moved to recordkeeping. 

W. Oil and Natural Gas Systems 

At this time, EPA is not going final 

with the fugitive and vented methane 

emissions from the oil and gas sector 

under 40 CFR part 98, subpart W. As 

EPA considers next steps, we will be 

reviewing the public comments and 

other relevant information. 

EPA received a number of lengthy, 

detailed comments regarding 40 CFR 

part 98, subpart W. Commenters 

generally opposed the proposed 

reporting requirements and thought they 

would entail significant burden and 

cost. For example, many commenters 

asserted that use of direct measurement 

to collect data required under 40 CFR 

part 98, subpart W would entail 

significant burden and that the proposal 

lacked standards for leak detection and 

measurement equipment. In many cases, 

commenters provided alternative 

approaches to the reporting 

requirements proposed by EPA such as 

the use of emission factors and/or 

reducing the number of sources and 

sites requiring direct measurement e.g., 

through statistical sampling. In addition 

to comments on burden, commenters 

requested clarification from EPA on a 

number of proposed reporting 

provisions. 

As EPA received extensive comments 

on this subpart, EPA plans to take 

additional time to perform additional 

analysis and consider alternatives to 

data collection procedures and 

methodologies. These alternatives will 

provide similar coverage of vented and 

fugitive methane and other GHG 

emissions in the oil and gas sector, 

while concurrently taking into account 

industry burden. As stated in Section 

V.W of the preamble to the proposed 

rule (74 FR 166606, April 10, 2009), 

EPA will also consider the inclusion of 

GHG reporting from other sectors of the 

oil and gas industry. 

Where applicable, EPA will also 

consider the applicability of engineering 

estimates, emissions modeling software 

and emissions factors rather than 

relying so extensively on the use of 

direct measurement. EPA will consider 

optimal methods of data collection in 

order to maximize data accuracy, while 

considering industry burden. 

X. Petrochemical Production 

1. Summary of the Final Rule 

Source Category Definition. The 

petrochemical production source 

category consists of all processes that 

produce acrylonitrile, carbon black, 

ethylene, ethylene dichloride, ethylene 

oxide, or methanol, with certain 

exceptions. Exceptions include 

processes that produce a petrochemical 


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as a byproduct, processes that produce 

methanol from synthesis gas when the 

annual mass production of hydrogen or 

ammonia exceeds the annual mass of 

methanol produced, direct chlorination 

processes operated independently of 

oxychlorination processes to produce 

ethylene dichloride, processes that 

produce bone black, and processes that 

produce a petrochemical from bio-based 

feedstock. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For petrochemical 

production facilities, report CO2, CH4, 

and N2O process emissions from each 

petrochemical production unit. Process 

emissions include CO2 generated by 

reaction in the process. Process 

emissions also include CO2, CH4, and 

N2O emissions generated by combustion 

of off-gas from the process in stationary 

combustion units and flares. For some 

of the GHG emission calculation and 

monitoring options, 40 CFR part 98, 

subpart X references procedures in 40 

CFR part 98, subpart C for calculating 

emissions from stationary combustion 

sources, and it references procedures in 

40 CFR part 98, subpart Y for 

calculating emissions from flares. 

In addition, report GHG emissions for 

other source categories at the facilities 

for which calculation methods are 

provided in the rule, as applicable. For 

example, report CO2, N2O, and CH4

emissions from each stationary 

combustion unit on site that does not 

burn process off-gas under 40 CFR part 

98, subpart C (General Stationary Fuel 

Combustion Sources). The quantity of 

CO2 captured must also be reported by 

following the requirements of 40 CFR 

part 98, subpart PP. 

GHG Emissions Calculation and 

Monitoring. CO2 process emissions from 

petrochemical production must be 

determined by one of three methods. 

Process emissions include emissions 

from CO2 generated by chemical 

reactions in the process and from the 

combustion of process off-gas and liquid 

wastes. 

One emission calculation option is to 

route all process vent emissions to one 

or more stacks and use CEMS to 

measure the CO2 emitted from each 

stack (except flare stacks). For each 

stack that includes emissions from 

combustion of process off-gas, reporters 

must calculate CH4 and N2O emissions 

by the procedures specified in 40 CFR 

part 98, subpart C. For each flare, the 

final rule requires CO2, CH4, and N2O 

emissions to be calculated using the 

procedures in 40 CFR 98.253(b) 

(Petroleum Refineries). If CO2 CEMS are 

used on all subject stacks, even if the 

CEMS were installed for reasons other 

than compliance with this rule, then the 

rule requires the use of this reporting 

option. 

A second emission calculation option 

is to use a mass balance. Under this 

option, the quantity of each carboncontaining feedstock added to the 

process and the quantity of each carboncontaining product produced by the 

process must be measured for each 

calendar month, or it may be calculated 

based on measured changes in the 

liquid level in storage tanks. The carbon 

content of each feedstock and product 

also must be determined at least once 

per month. The carbon content may be 

measured directly, or it may be 

calculated based on measurements of 

the composition and known compound 

molecular weights. Under this option, 

the procedures for products also apply 

to byproducts and liquid organic wastes 

that are not combusted onsite. To 

prevent double-counting of combustion 

emissions, this option specifies that the 

procedures for stationary combustion 

sources in 40 CFR part 98, subpart C 

apply only to the supplemental fuel 

(e.g., natural gas) burned in combustion 

units that supply energy needs for 

petrochemical processes. The final rule 

specifies numerous measurement 

method options and related calibration 

requirements in 40 CFR 98.244. To 

potentially minimize the sampling and 

analysis burden, the final rule, like the 

proposed rule, includes an option that 

allows reporters to assume a feedstock 

or product is always 100 percent pure 

if they determine that the specified 

compound is always present at greater 

than 99.5 percent. 

A third emission calculation option is 

available only for ethylene processes. 

Because nearly all process emissions 

from this process are from combustion 

of process off-gas, the final rule allows 

calculation of emissions from all 

stationary combustion units that burn 

process off-gas (with or without 

supplemental fuel) in accordance with 

the Tier 3 or Tier 4 procedures in 40 

CFR part 98, subpart C. In addition, this 

option requires CO2, CH4, and N2O 

emissions from each flare to be 

calculated using the procedures in 40 

CFR 98.253(b) (Petroleum Refineries). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR 98.246. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR 98.247. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart X: 

Petrochemical Production.’’ 

• The definition of the source 

category was changed to exclude 

ethylene dichloride production by the 

direct chlorination process alone from 

the petrochemical production source 

category because the only GHG 

emissions from this process are from the 

combustion of supplemental fuel and 

the combustion of hydrocarbon 

emissions in air pollution control 

devices. Ethylene dichloride produced 

by both direct chlorination and 

oxychlorination in the ‘‘balanced 

process’’ is still part of the source 

category. 

• For the mass balance option, the 

measurement and emission calculation 

frequency was changed from weekly to 

monthly. 

• For ethylene processes, an 

alternative was added to the mass 

balance option that allows reporters to 

calculate emissions from stationary 

combustion sources that burn ethylene 

process off-gas (with or without 

supplemental fuel) using the Tier 3 or 

Tier 4 procedures in 40 CFR part 98, 

subpart C. This includes all such 

combustion units, including units that 

supply energy to processes other than 

the ethylene process. This option does 

not affect requirements for stationary 

combustion sources related to ethylene 

processes that burn no process off-gas; 

emissions from these combustion units 

still must be calculated using the 

methods in any applicable Tier in 40 

CFR part 98, subpart C. 

• The reporting requirements in 40 

CFR 98.246 were reorganized and 

updated to facilitate the emissions 

verification process, simplify and clarify 

requirements, and address requirements 

for the new monitoring option for 

ethylene processes. 


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3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Many comments on petrochemical 

production were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart X: 

Petrochemical Production.’’ 

Definition of Source Category. 

Comment: Several commenters stated 

that ethylene production should be 

removed from the petrochemical 

production source category because 

essentially all GHG emissions from such 

processes are from combustion sources, 

which would be subject to reporting 

under 40 CFR part 98, subpart C 

regardless of whether the process is 

included in the petrochemical 

production source category. According 

to two commenters, using a mass 

balance approach is irrelevant and 

confusing because ethylene processes 

have no normal process vents. One 

commenter noted that methane is 

produced in ethylene processes, but the 

vast majority is returned as fuel within 

the plant or another plant at the same 

site and thus would produce CO2

emissions only when combusted. 

Another commenter noted that off-gas 

from ethylene processes that are colocated with a petroleum refinery or 

other chemical plants is sent to the fuel 

gas system where it is mixed with other 

process gases from non-ethylene units 

in a fuel gas blend drum and then 

distributed to combustion units 

throughout the refinery and/or chemical 

plant. According to two commenters, 

the mass balance approach is onerous 

due to the number of product streams 

that would have to be measured, and the 

results of a mass balance most likely 

would be less accurate than a fuel 

combustion methodology. These two 

commenters also noted that calculating 

GHG emissions based on fuel 

combustion is the methodology used 

currently by most ethylene units. One 

commenter suggested that as an 

alternative to excluding ethylene units 

from the petrochemical production 

source category, EPA could add an 

emission calculation methodology to 40 

CFR part 98, subpart X that would allow 

facilities to calculate combustion 

emissions based on fuel consumption. 

Response: As one commenter noted, 

methane (and other light ends) are 

generally burned in combustion units to 

supply energy needs for the ethylene 

process itself and possibly other 

processes. Emissions from combustion 

of these process off-gases are process 

emissions that are intended to be 

reported under 40 CFR part 98, subpart 

X. At facilities where the ethylene 

process off-gases are not mixed with offgas from other processes, we do not 

believe that the mass balance approach 

is illogical; the flows and carbon 

contents of feedstocks and products can 

be determined for an ethylene process, 

and the resulting values can be used in 

the mass balance equations, just as they 

can for any other petrochemical process. 

Furthermore, we do not know if the 

views of the commenters reflect the 

views of all ethylene manufacturers. 

Therefore, we have retained ethylene in 

the petrochemical production source 

category, and we have retained the mass 

balance option in the final rule. 

Although we still think a mass 

balance approach is appropriate and 

valid for ethylene processes, we have 

also evaluated combustion-based 

methodology options for the final rule. 

Given that the cracking and separation 

operations generate negligible CO2, we 

agree with the commenters that the only 

significant source of emissions in 

ethylene production is from combustion 

operations. One concern we have with 

using the Tier 1 and Tier 2 

methodologies in 40 CFR part 98, 

subpart C is that they rely on default 

emission factors and company records 

(rather than measurements) of fuel flow. 

Given the variety of feedstocks and the 

corresponding variety in process off-gas, 

we do not believe default emission 

factors or fuel flow based on company 

records are appropriate. Therefore, we 

rejected the Tier 1 and Tier 2 

methodologies. On the other hand, Tier 

3 requires measurement of the total fuel 

flow and relatively frequent 

measurement of the carbon content of 

the fuel. Using CEMS to measure CO2

emissions (i.e., the Tier 4 methodology 

in 40 CFR part 98, subpart C) is also a 

good way to measure CO2 emissions 

from any combustion unit. Therefore, 

we determined that use of the Tier 3 or 

Tier 4 methodology is acceptable for 

calculating emissions from combustion 

units that burn ethylene process off-gas 

(with or without mixing with 

supplemental fuel), and these options 

are included in the final rule. In 

addition, because the methodology used 

for calculating emissions from one 

combustion unit has no bearing on the 

emissions from any other combustion 

unit, the final rule states that a facility 

is not required to use the same Tier for 

each stationary combustion unit. 

Comment: One commenter requested 

that EPA remove ethylene dichloride 

(EDC) from the petrochemical source 

category because EDC is not 

manufactured using a fossil fuel-based 

feedstock (e.g., crude oil, naphtha, 

natural gas condensate, methane, or 

other fossil fuel-based chemicals), no 

GHGs are used in the manufacturing 

process, and only a trace amount of CO2

is generated in the process. Another 

commenter requested clarification that 

EDC produced as an intermediate in the 

production of vinyl chloride monomer 

is not part of the petrochemical source 

category because the entire process is 

considered to be an ‘‘integrated 

process’’, and the primary product of 

the process is not EDC. The commenter 

noted that the term ‘‘primary product’’ 

is also used in the Hazardous Organic 

NESHAP (HON) (40 CFR part 63, 

subpart F), but it has a different 

definition. To avoid confusion created 

by multiple definitions for the same 

term, the commenter urged EPA to 

consider alternatives to the concept of 

primary product for determining 

applicability of an integrated process. 

Response: EDC is produced by two 

processes. In one process, the direct 

chlorination process, ethylene is reacted 

with chlorine to create EDC. As the 

commenters noted, reactions in this 

process produce negligible CO2

emissions and no other GHG emissions. 

The only GHG emissions associated 

with this process are from the 

combustion of process off-gas and 

supplemental fuel. We have determined 

that monitoring and reporting of these 

emissions will be required under 40 

CFR part 98, subpart C. Therefore, we 

have removed this process from the 

petrochemical source category. 

In the second EDC process, the 

oxychlorination process, ethylene is 

reacted with hydrochloric acid to create 

EDC and water. Some of the ethylene, 

however, oxidizes to CO2 and water in 

a competing side reaction. All facilities 

in the United States (U.S.) that operate 

this process operate it as part of an 

integrated process that includes vinyl 

chloride monomer production and a 

direct chlorination process. This 

integrated process is called a ‘‘balanced 

process’’. Although available estimates 

suggest the amount of CO2 emitted is 

small relative to emissions from 

combustion, we do not have data to 

support such estimates. Furthermore, 

even if small relative to other sources, 

the total amount is not necessarily 

insignificant. We continue to believe 

information about these emissions is 

needed in order to support future policy 

decisions regarding petrochemical 

processes. Therefore, we have not 

removed EDC production by the 

balanced process from the 

petrochemical production source 

category. 


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In the proposed rule, an ‘‘integrated 

process’’ was defined as ‘‘a process that 

produces a petrochemical as well as one 

or more other chemicals that are part of 

other source categories’’ subject to 

reporting under 40 CFR part 98. This 

concept does not apply to production of 

EDC as an intermediate that is used in 

the onsite production of vinyl chloride 

monomer because vinyl chloride 

monomer production is not a source 

category that is subject to reporting 

under 40 CFR part 98. We used general 

language in the proposed rule that 

would apply to various integrated 

process scenarios, but the only scenario 

we know of that meets these conditions 

is methanol production from synthesis 

gas that is sometimes also used to 

produce hydrogen and/or ammonia 

(both of which are subject to reporting 

under other subparts in 40 CFR part 98). 

Because this is the only situation where 

the ‘‘integrated process’’ concept would 

apply, we decided to replace it in the 

final rule with language in 40 CFR 

98.240 that explicitly states the 

applicability determination procedures 

for a process that produces methanol, 

hydrogen, and/or ammonia from 

synthesis gas. Thus, the term ‘‘primary 

product’’ has also been removed from 

the final rule, which eliminates the 

potential conflict with the definition in 

the HON. 

Method for Calculating GHG Emissions 

Comment: Two commenters stated 

that the proposed CEMS requirements 

are overly restrictive. According to these 

commenters, a facility should have the 

option to install a CEMS on one or more 

sources without being required to have 

a CEMS on all sources associated with 

a petrochemical production process. For 

example, the commenters suggested that 

a facility should have the flexibility to 

use a CEMS on a large emission point 

while being allowed to use the 

combustion equations and/or the mass 

balance approach for smaller emission 

points in the process (e.g., start-up 

heaters and steam jet exhausts from 

distillation columns operating under 

vacuum). 

Response: If some emissions were 

from stacks monitored with CEMS and 

all other emissions were from 

combustion units without CEMS, it 

would be possible to use a combination 

of CEMS and the combustion equation 

methodology to calculate the total GHG 

emissions from a petrochemical process. 

However, this scenario is unlikely, 

which means other methodology would 

be needed to estimate emissions from 

other emission points (e.g., the steam jet 

exhausts cited by the commenters). It is 

not clear to us how the mass balance 

methodology would be used to estimate 

these other emissions because the mass 

balance relies on knowledge of the total 

carbon input to the process and the total 

amount of carbon in all products (and 

organic liquid wastes); the difference is 

assumed to be the total CO2 emissions. 

Theoretically, other methodology could 

be developed to calculate emissions 

from specific other emission points, but 

the commenter has not suggested other 

techniques. Therefore, the final rule 

does not include an option to mix CEMS 

with other methodology for a given 

process unit. 

Comment: According to several 

commenters, weekly measurements of 

feedstocks and products are 

burdensome or unwarranted. Two 

commenters suggested changing the 

frequency to monthly because monthly 

accounting would align better with 

existing industry accounting 

procedures, reduce the burden, and 

provide 12 high-quality estimates per 

year. One commenter suggested 

monthly mass balance calculations for 

carbon black facilities because the 

emissions from a carbon black 

manufacturing facility do not vary 

significantly from week to week. 

Another commenter requested a 

provision to allow the reporter to 

determine a sampling frequency that is 

consistent with the variability of the 

stream. 

Response: We are sensitive to the 

burden imposed by the rule and want to 

minimize it when possible. Based on the 

results of an uncertainty analysis (see 

memorandum entitled ‘‘Monte Carlo 

Simulation of Uncertainty in Monitoring 

Frequency for Mass Balance Option for 

Petrochemical Production Facilities’’ in 

the docket) we believe longer 

monitoring periods will not 

significantly compromise the 

monitoring results for the mass balance 

option. Therefore, the mass balance 

option in the final rule requires monthly 

monitoring instead of the proposed 

weekly monitoring. 

Data Reporting Requirements 

Comment: Two commenters stated 

that the proposed reporting 

requirements are excessive, particularly 

information such as each carbon content 

measurement and information on the 

calibration of each flow meter. 

According to the commenters, 

submitting this information will not 

improve the overall quality of the GHG 

emission calculation, and it is not 

necessary because the facilities are 

required to certify that the submitted 

information is true, accurate, and 

complete. Therefore, the commenters 

recommended that facilities be required 

to retain records of such information 

rather than submit it in reports. 

Response: A primary reason that 

additional information beyond annual 

emissions must be reported is so that 

EPA can verify the results. To facilitate 

the emissions verification process, 40 

CFR 98.246 was reorganized and 

updated. For example, the final rule 

requires reporting of all input data used 

in the emission calculation equations, 

not just the carbon content values and 

the annual quantities, because this 

information is needed so the 

calculations can be reproduced and 

confirmed as part of the emissions 

verification process. Note, however, that 

any increase in the burden to report 

flow measurements has been offset by 

the reduction in monitoring frequency 

from weekly to monthly. The reporting 

requirements in the final rule for the 

mass balance option also have been 

simplified and clarified by replacing the 

requirement to submit all information 

related to uncertainty estimates with a 

requirement to submit only the dates 

and summarized results of measurement 

device calibrations. The estimated 

accuracy of measurement devices and 

the technical basis for such 

measurements must also be documented 

as part of the monitoring plan that is 

maintained onsite. The reporting section 

also was updated to include reporting 

requirements for the new monitoring 

option for ethylene processes. 

Y. Petroleum Refineries 

1. Summary of the Final Rule 

i. Source Category Definition 

Petroleum refineries are facilities that 

produce gasoline, gasoline blending 

stocks, naphtha, kerosene, distillate fuel 

oils, residual fuel oils, lubricants, or 

asphalt (bitumen) by the distillation of 

petroleum or the redistillation, cracking, 

or reforming of petroleum derivatives. 

The definition of petroleum refineries 

excludes facilities that distill only 

pipeline transmix (off-spec material 

created when different specification 

products mix during pipeline 

transportation), regardless of the 

products produced. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

ii. GHGs to Report 

The refinery processes and gases that 

must be reported are listed in Table Y– 

1 of this preamble along with the rule 

subpart that specifies the calculation 

methodology that must be used. 


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TABLE Y–1—GHGS TO REPORT

For this refinery process . . . 

Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, 

subpart indicated . . . 

CO2 CH4 N2O 

Stationary combustion ................................................................................................................. C C C 

Flares ........................................................................................................................................... Y Y Y 

Catalytic cracking ......................................................................................................................... Y Y Y 

Traditional fluid coking ................................................................................................................. Y Y Y 

Fluid coking with flexicoking design ............................................................................................ C/Y C/Y C/Y 

Delayed coking ............................................................................................................................ — Y — 

Catalytic reforming ....................................................................................................................... Y Y Y 

Onsite and offsite sulfur recovery ................................................................................................ Y — — 

Coke calcining ............................................................................................................................. Y Y Y 

Asphalt blowing ............................................................................................................................ Y Y — 

Equipment leaks .......................................................................................................................... — Y — 

Storage tanks ............................................................................................................................... — Y — 

Other process vents .................................................................................................................... Y Y Y 

Uncontrolled blowdown systems ................................................................................................. — Y — 

Loading operations ...................................................................................................................... — Y — 

Hydrogen plants (nonmerchant) .................................................................................................. P P — 

Key: 

C = 40 CFR part 98, subpart C (General Stationary Combustion Sources). 

P = 40 CFR part 98, subpart P (Hydrogen Production). 

Y = 40 CFR part 98, subpart Y (Petroleum Refineries). 

— = Reporting from this process is not required. 

iii. GHG Emissions Calculation and 

Monitoring 

Under 40 CFR part 98, subpart Y, 

petroleum refineries must calculate CO2, 

CH4 and N2O emissions using the 

calculation methods described below for 

each refinery process. 

For CO2 emissions, reporters must use 

CEMS or specified calculation methods 

as follows: 

• For refinery units with certain types 

of CEMS in place, reporters must use 

the CEMS and follow the Tier 4 

methodology of 40 CFR part 98, subpart 

C to report combined process and 

combustion CO2 emissions. 

• For refinery units without CEMS in 

place, reporters can elect to either (1) 

install and operate a CEMS to measure 

combined process and combustion CO2

emissions according to the requirements 

specified in 40 CFR part 98, subpart C 

or (2) calculate CO2 emissions using the 

methods summarized below. 

Flares. CO2 emissions from flares 

must be calculated using the gas flow 

rate (either measured with a continuous 

flow meter or calculated using 

engineering calculations) and either: (1) 

At least weekly measured carbon 

content of the flare gas, or (2) at least 

weekly measured heat content of the 

flare gas and an emission factor 

provided in the rule. If the carbon 

content and heat content of the gas are 

not measured at least weekly, 

engineering estimates of heat content 

during normal flare use is allowed, but 

CO2 emissions for each startup, 

shutdown, and malfunction event 

exceeding 500,000 standard cubic feet 

(scf) per day of flare gas must be 

calculated separately using engineering 

estimates of the quantity of gas 

discharged and the carbon content of 

the flared gas. CH4 and N2O emissions 

from flares must be calculated using the 

methods specified in 40 CFR part 98, 

subpart Y. 

Catalytic Cracking Units, Fluid 

Coking Units, and Catalytic Reforming 

Units. CO2 emissions must be calculated 

using the volumetric flow rate of the 

exhaust gas (measured or calculated) 

and hourly measured carbon monoxide 

(CO) and CO2 concentrations in the 

exhaust stacks from the catalytic 

cracking unit regenerator and fluid 

coking unit burner from units exceeding 

10,000 barrels per stream day. Catalytic 

cracking and fluid coking units below 

this threshold must use the required 

flow and gas monitors if they are inplace, but may use engineering 

estimates for determining CO2 emissions 

if the required flow and gas monitors are 

not in place. Similarly, catalytic 

reforming units may use the flow and 

gas monitors required for large catalytic 

cracking and fluid coking units; 

alternatively, reporters may use 

engineering estimates based on the 

quantity of coke burned off, the carbon 

content of the coke (using either a 

measured or a default value), and the 

number of regeneration cycles. CH4 and 

N2O emissions may be measured or may 

be calculated using the CO2 emissions 

and default emission factors. Fluid 

coking units that use the flexicoking 

design may account for their GHG 

emissions either by using the methods 

specified for traditional fluid coking 

units, or by using the methods for 

stationary combustion specified in 40 

CFR part 98, subpart C. 

Onsite and Off Site Sulfur Recovery. 

CO2 emissions must be calculated using 

the volumetric flow rate of the sour gas 

(measured continuously or calculated 

from engineering calculations) and the 

carbon content of the sour gas stream 

(using a measured or a default value). 

Coke Calcining Units. CO2 emissions 

must be calculated from the difference 

between the carbon input as green coke 

and the carbon output as marketable 

petroleum coke and as coke dust 

collected in the dust collection system. 

The CH4 and N2O emissions from coke 

calcining units may be measured or 

calculated using the calculated CO2

emissions and default emission factors. 

Asphalt Blowing Operations. For 

uncontrolled asphalt blowing operations 

or asphalt blowing operations controlled 

by vapor scrubbing, CH4 and CO2

emissions must be calculated using a 

facility-specific emission factor based 

on test data or, where test data are not 

available, a default emission factor 

provided in the rule. For asphalt 

blowing operations controlled by a 

thermal oxidizer or flare, CH4 and CO2

emissions must be calculated by 

assuming 98 percent of the CH4 and 

other hydrocarbons generated by the 

asphalt blowing operation are converted 

to CO2. 

Delayed Coking Units. CH4 emissions 

from the depressurization of delayed 


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coking vessels must be calculated using 

the method outlined below for other 

process vents. The emissions released 

during the opening of vessels for coke 

cutting operations must be calculated 

using the vessel parameters (height and 

diameter), vessel pressure, the number 

of times the vessel was opened, the void 

fraction of the coking vessel prior to 

steaming, and the mole fraction of CH4

in the gas released (using a measured or 

a default value provided in the rule). 

The rule provides an alternative of using 

only the vessel parameter equation if no 

water or steam is added to the vessel 

after the vessel is vented to the 

atmosphere. 

Other Process Vents. GHG emissions 

from other process vents that contain 

CO2, CH4, or N2O exceeding 

concentration thresholds specified in 

the rule must be calculated using the 

volumetric flow rate, the mole fraction 

of the GHG in the exhaust gas, and the 

number of hours during which venting 

occurred. 

Uncontrolled Blowdown Systems. CH4

emissions from uncontrolled blowdown 

systems must be calculated using either 

the method specified for process vents 

or a default emission factor and the sum 

of crude oil and intermediate products 

received from off site and processed at 

the facility. 

Equipment Leaks. CH4 emissions from 

equipment leaks must be calculated 

using either default emission factors or 

process-specific CH4 composition data 

and leak data collected using the leak 

detection methods specified in EPA’s 

Protocol for Equipment Leak Emission 

Estimates. 

Storage Tanks. For storage tanks 

covered by the requirements of this rule, 

the methodology used to calculate the 

CH4 emissions depends on the material 

stored. For storage tanks used to store 

unstabilized crude oil, facilities must 

use either: (1) The CH4 composition of 

the unstabilized crude oil (based on 

direct measurement or product 

knowledge) and the measured gas 

generation rate; or (2) an emission 

factor-based method using the quantity 

of unstabilized crude oil received at the 

facility, the pressure difference between 

the previous storage pressure and 

atmospheric pressure, the mole fraction 

of CH4 in the vented gas (using either a 

measured or a default value), and an 

emission factor provided in the rule. For 

storage tanks used to store material 

other than unstabilized crude oil with a 

vapor-phase CH4 concentration of 0.5 

percent by volume or more, facilities 

must use either tank-specific methane 

composition data and applicable 

correlations in AP–42, Section 7.1 (as 

implemented in the TANKS Model 

(Version 4.09D) or similar models) or a 

default emission factor provided in the 

rule. 

Loading Operations. CH4 emissions 

from loading operations must be 

calculated using vapor-phase methane 

composition data and the method in 

Section 5.2 of AP–42: ‘‘Compilation of 

Air Pollution Emission Factors.’’ 

Facilities must calculate CH4 emissions 

only for loading materials that have an 

equilibrium vapor-phase CH4

concentration equal to or greater than 

0.5 percent by volume. Other facilities 

may assume zero CH4 emissions. 

iv. Data Reporting 

In addition to the information 

required to be reported by the General 

Provisions (40 CFR 98.3(c)) and 

summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart Y. 

v. Recordkeeping 

In addition to the records required by 

the General Provisions (40 CFR 98.3(g)) 

and summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

Y. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart Y: Petroleum 

Refineries.’’ 

• The minimum monitoring 

frequency for flare gas heat value or 

carbon content was changed to weekly 

from daily. (For background on the 

selection of a weekly frequency, see 

memorandum entitled: ‘‘Uncertainty in 

Flare Estimates Based on Sampling 

Frequency’’ in the docket.) Engineering 

calculations are allowed in the final rule 

for reporters that do not monitor flare 

gas flow continuously or flare heating 

value or carbon content at least weekly. 

• The minimum monitoring 

frequency for refinery fuel gas carbon 

content and molecular weight was 

changed to weekly from daily in 40 CFR 

part 98, subpart C for reporters that do 

not have continuous monitoring 

equipment, and we clarified in 40 CFR 

part 98, subpart Y that common (fuel) 

pipe monitoring is allowed for 

petroleum refineries. 

• We added a flare combustion 

efficiency of 98 percent, and we revised 

the equation for flare CH4 emissions to 

account for uncombusted methane. 

• The final rule allows engineering 

calculations to determine CO2 emissions 

for catalytic cracking units and fluid 

coking units below 10,000 bbl/stream 

day that do not have CO2/CO/O2

monitors already installed. 

• The delayed coking unit 

depressurization emission equations 

and asphalt blowing equations were 

amended to address comments received. 

• We added concentration thresholds 

for CO2, CH4 and N2O from process 

vents below which GHG emissions are 

not required to be calculated and 

reported. 

• The reporting requirements were 

updated to facilitate the emissions 

verification process. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on petroleum 

refineries were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart Y: Petroleum 

Refineries.’’ 

Definition of Source Category 

Comment: Several commenters 

expressed concern that EPA defined a 

Petroleum Refinery so broadly that it 

could be interpreted to include 

chemical facilities that use petroleumbased materials as raw materials. Of 

particular concern was the term ‘‘* * * 

and other products * * *’’ which many 

commenters interpreted to include the 

manufacture of chemicals, synthetic 

rubber, and a variety of plastics. One 

commenter also requested clarification 

that ‘‘other products’’ did not include 

sulfur, ammonia, or hydrogen sulfide. 

Several commenters requested 

clarification that the definition of 

petroleum refineries did not include 

lube oil production or fuel blending 

operations if the products were 

produced without distilling, redistilling, 

cracking, or reforming of the petroleum 

derivatives. 

Response: We have revised and 

clarified the definition of petroleum 

refinery to list a few additional refinery 

products (specifically gasoline blending 

stocks and naphtha) and deleted the 

term ‘‘or other products.’’ We believe 

that this change clarifies that companies 

that use petroleum derivatives to make 


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only petrochemicals, plastics, synthetic 

rubber, sulfur, or any other product 

other than those specifically listed are 

not considered petroleum refineries. We 

feel the definition also clearly excludes 

lube oil manufacturing provided the 

lube oil manufacturer does not distill, 

redistill, crack, or reform the petroleum 

derivatives at the facility. 

Comment: Numerous commenters 

requested that many of the emission 

sources for which 40 CFR part 98, 

subpart Y required reporting were small 

and should not have to be reported. 

Several commenters noted that EPA’s 

TSD for the Petroleum Refining Sector: 

Proposed Rule for Mandatory Reporting 

of Greenhouse Gases, indicates that 92.9 

percent of the refining sector’s GHG 

emissions come from two sources, 

combustion and catalytic coke 

operations. The remaining 7.1 percent of 

emissions come from eight distinct 

categories, including: Hydrogen plants 

(2.7 percent); Sulfur Plants (1.9 percent); 

Flaring (1.6 percent); Wastewater 

Treatment (0.43 percent); Blowdown 

(0.18 percent); Asphalt Blowing (0.10 

percent); Delayed Coking (0.058 

percent); Equipment Leaks (0.014 

percent); Storage Tanks (0.007 percent); 

and Cooling Towers (0.003 percent). 

The commenters argued that the burden 

associated with the collection of data as 

prescribed in the proposed rule is not 

warranted for small sources and/or not 

consistent with EPA’s stated intended 

purpose of the rule which is to support 

analysis of future policy decisions. 

Response: The TSD estimates are 

based largely on engineering estimates 

without significant supporting data. For 

the smaller sources, we have provided 

very simple methods to calculate the 

GHG emissions from these sources to 

minimize the monitoring, 

recordkeeping, and reporting burden 

associated with these sources when no 

measurement data are available. 

However, requiring reporting for these 

sources will provide EPA with valuable 

data to better characterize them and 

provide a better record upon which to 

formulate decisions regarding whether 

to include or exclude these sources from 

future GHG policy decisions. 

Additionally, while some of these 

sources are currently believed to be 

small compared to the larger sources 

present at petroleum refineries, they are 

not necessarily insignificant. The 

inclusion of reporting data for these 

sources is critical to support analysis of 

future policy decisions for petroleum 

refineries. 

Comment: Several commenters 

objected to the mandatory reporting of 

CH4 and N2O emissions within the 

Petroleum Refinery source category. 

Many commenters cited the TSD, which 

indicated that N2O emissions account 

for 0.09 percent of the GHG emissions 

and CH4 account for only 0.87 percent 

of the GHG emissions. The commenters 

argued that the measurement error for 

the larger sources (stationary 

combustion sources and catalytic 

cracking unit coke burn-off) exceeds the 

contributions of these sources. As such, 

the commenters stated that the burden 

associated with reporting these 

emissions is not warranted and/or not 

consistent with EPA’s stated intended 

purpose of the rule which is to support 

analysis of future policy decisions. 

Response: The TSD estimates for CH4

and N2O are based largely on 

engineering estimates without 

significant supporting data. We 

specifically require reporting of these 

various GHGs to obtain better data by 

which to support future policy analysis. 

Moreover, EPA has pending before it a 

petition to reconsider the recently 

revised New Source Performance 

Standard (NSPS) for petroleum 

refineries asking EPA to reconsider, 

among other things, whether to establish 

GHG standards under section 111 for 

refineries. As such, we have a keen 

interest in obtaining improved GHG 

emissions data in order to better analyze 

policy options. For instance, refineries 

are a significant source of NOX

emissions, but we have no data to 

determine the fraction of NOX that is 

N2O. With the increased use at 

refineries of NOX control devices, such 

as low-NOX burners, low excess air, 

selective catalytic reduction (SCR) 

systems, and selective non-catalytic 

reduction (SNCR) systems, it seems 

plausible that N2O may be a more 

significant portion of a refinery’s NOX

emissions. Thus, if a facility has 

measurement data for a source, the 

reporting of these data are important for 

better understanding the impact of 

current and future policy options. 

Consequently, we have provided 

additional alternatives that allow the 

use of measured N2O (and CH4) 

emissions or site-specific emission 

factors in addition to the default factors. 

Nonetheless, we have provided very 

simple default methods to calculate the 

emission of these GHGs when 

measurement data are not available. 

While emissions of CH4 and N2O may 

not be large comparatively, the reporting 

method for these pollutants is 

straightforward and commensurate with 

the anticipated emissions contribution. 

Method for Calculating GHG Emissions 

Comment: Several comments objected 

to the requirements for flares, 

particularly the requirements for SSM 

events. Some commenters also stated 

that daily sampling was too 

burdensome. The commenters suggested 

that flare emissions be dropped from the 

rule or that refineries be allowed to 

perform a one-time calculation. One 

commenter noted that the proposed 

equation did not account for flare 

combustion efficiency, which was 

inconsistent with other subparts, and 

recommended that a flare efficiency 

factor be added to the equation to 

calculate the CO2 emissions from flares. 

Response: EPA needs accurate data on 

flare emissions to better understand this 

emission source, as flare use can vary 

significantly from day-to-day and yearto-year. Use of flares is too episodic and 

variable to allow a one-time calculation. 

However, we recognize that flares may 

contribute about two percent of a 

refinery’s GHG emissions. Therefore, we 

sought to reduce the burden associated 

with the flare monitoring and reporting 

requirements. As proposed, special 

calculations for SSM events were only 

required if daily measurement data were 

not available. In this final rule, we allow 

weekly monitoring of flare use without 

triggering special SSM event 

calculations, which should lessen the 

burden associated with calculating flare 

emissions while not significantly 

changing the accuracy of the data. 

Additionally, we included a threshold 

flaring rate of 500,000 scf/day for SSM 

events. Only SSM events exceeding this 

gas flare rate require special SSM 

calculations in the final rule. Some 

consent decree requirements and State 

rules require root cause analysis and 

quantification of emission events 

exceeding 500,000 scf/day. We consider 

events of this magnitude to be 

significant and believe a separate 

analysis is justified in addition to the 

procedures that apply to routine 

operation. We have also revised the 

equations for CO2 and CH4 to account 

for flare combustion efficiency. 

Monitoring and QA/QC Requirements 

Comment: Several commenters argued 

that the monitoring and QA/QC 

requirements were excessive and that 

EPA significantly underestimated the 

costs associated with complying with 

the reporting requirements under 40 

CFR part 98, subpart Y. One commenter 

noted that existing facility CO2 CEMS, 

HHV monitors, carbon content 

monitors, and flow meters are not 

necessarily for ‘‘regulatory’’ purposes 

and thus may not meet the accuracy 

requirements of the rule. The 

commenter suggested many more 

refineries would have to add or replace 

monitors as a result of the rule. Many 

commenters suggested EPA significantly 


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underestimated the labor hours required 

to collect and analyze daily samples as 

well as to develop and implement a QA 

plan. Various commenters supplied 

labor or cost estimates for various 

requirements in the rule, including costs 

of implementing an LDAR program and 

flare SSM calculations. Several 

commenters stated that the requirement 

to use a CEMS for monitoring CO2 from 

the catalytic cracking unit was 

expensive and burdensome, especially 

for small refineries that do not have a 

CEMS infrastructure. 

Response: We have significantly 

revised our rule requirements for 

petroleum refineries and stationary 

combustion sources to reduce burden to 

the industry. We have provided in the 

final rule (in 40 CFR part 98, subpart C) 

a default emission factor for refinery 

(still) gas to allow combustion sources 

that combust refinery gas and meet the 

applicability requirements in 40 CFR 

part 98, subpart C to use Tier 2 methods. 

For sources that do not meet the Tier 2 

requirements, weekly monitoring for 

refinery fuel gas under Tier 3 (40 CFR 

part 98, subpart C) and for flare gas (40 

CFR part 98, subpart Y) is allowed. We 

have also re-assessed our costs based on 

the comments received and increased 

the labor hours estimated to collect and 

analyze samples, develop QA plans, and 

to perform QA/QC of existing 

equipment. We did review our QA/QC 

requirements and see no validity to the 

argument that our QA/QC requirements 

are so stringent that refineries will have 

to replace existing monitors to comply 

with the rule. While we note that some 

cost elements suggested by commenters 

are relevant and have been addressed in 

the changes in the labor estimates for 

sampling, analysis, and QA/QC as 

described above, other cost elements 

suggested by commenters are not 

relevant. For example, revisions of 

LDAR programs are not required under 

the rule; the proposed and final rule 

specifically provides a simple processbased emission factor approach for 

estimating CH4 emissions from 

equipment leaks. We are cognizant that 

refineries with small catalytic cracking 

units are most likely to elect a 

compliance option under 40 CFR part 

63, subpart UUU that does not require 

monitoring of coke burn-off, so these 

small refineries are most likely the 

facilities that would have been required 

to install monitoring equipment under 

the proposed rule. After reviewing these 

costs and impacts on the small 

refineries, we have allowed engineering 

calculations to determine CO2 emissions 

for catalytic cracking units below 10,000 

bbl/stream day that do not have CO2/ 

CO/O2 monitors already installed. 

Even though we have reduced the 

stringency of the rule in many places, 

our revised cost estimates indicate that 

the average cost per refinery is 

approximately 60 percent higher than 

projected at proposal. We believe our 

revised refinery costs accurately portray 

the burden associated with the final 

reporting requirements in 40 CFR part 

98, subpart Y. Nonetheless, we continue 

to believe that the costs are reasonable 

for this rule, especially considering that 

petroleum refineries are among the 

larger sources of GHG emissions in the 

U.S. 

Z. Phosphoric Acid Production 

1. Summary of the Final Rule 

Source Category Definition. The 

phosphoric acid production source 

category consists of facilities that use a 

wet-process phosphoric acid process to 

produce phosphoric acid. A wet-process 

phosphoric acid process line is any 

system that manufactures phosphoric 

acid by reacting phosphate rock and 

acid and is usually identified by an 

individual identification number in a 

CAA operating permit. 

Reporters must submit annual GHG 

reports for Facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Report CO2

emissions from each wet-process 

phosphoric acid process line. 

In addition, report GHG emissions at 

each facility for other source categories 

for which calculation methods are 

provided in the rule, as applicable. For 

example, report CO2, N2O, and CH4

emissions from each stationary 

combustion unit on site under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources). 

GHG Emissions Calculation and 

Monitoring. Calculate process emissions 

of CO2 using one of two methods, as 

appropriate: 

• Most reporters can elect to either (1) 

install and operating CEMS and follow 

the Tier 4 methodology (in 40 CFR part 

98, subpart C) or (2) calculate CO2

emissions based on monthly 

measurements of the mass of phosphate 

rock consumed and inorganic carbon 

content of each grab sample of 

phosphate rock. 

• However, if process CO2 emissions 

from phosphoric acid production are 

emitted through the same stack as a 

combustion unit or process equipment 

that uses a CEMS and follows Tier 4 

methodology to report CO2 emissions, 

then the CEMS must be used to measure 

and report combined CO2 emissions 

from that stack. In such cases, the 

reporter cannot use the CO2 calculation 

methodology outlined in approach (2) in 

the previous bullet. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart Z. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

Z. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart Z: 

Phosphoric Acid Production.’’ 

• The rule was revised to allow the 

use of techniques from Part 60 and Part 

63 for calculating the weight of 

phosphorous-containing rock. 

• The missing data provisions were 

revised to allow the use of default 

inorganic carbon content values based 

on the origin of the phosphorouscontaining rock, in addition to 

determining missing inorganic carbon 

contents of phosphate rock consumed 

using an arithmetic average of measured 

values from of inorganic carbon 

contents of phosphate rock of the 

appropriate origin preceding and 

following the missing data incident. 

• 40 CFR 98.266 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.267 to 40 CFR 98.266, and some data 

elements that are already used to 

calculate GHG emissions as specified in 

40 CFR 98.263 were added to 40 CFR 

98.266 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. 

Several comments on phosphoric acid 

production were received covering 

numerous topics shown below. 


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Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

Z: Phosphoric Acid Production.’’ 

Selection of Threshold 

Comment: Multiple commenters 

asked that phosphoric acid production 

units not be included as an ‘‘all-in’’ 

category. According to the commenters, 

the facilities are very minor sources of 

GHG emissions. The commenter 

conceded that most (if not all) would 

still fall within the reporting threshold 

requirement, but asserted that it was 

unnecessary to include all phosphoric 

acid production units as regulated 

facilities regardless of the amount of 

emissions. The commenters stated that 

EPA inaccurately suggests that these 

units are major emitters of GHGs which 

could have significant impacts on these 

minor sources. 

Response: We acknowledge the 

comments and concerns; however the 

final rule retains the ‘‘all-in’’ 

applicability requirement for this source 

category. The ‘‘once in, always in’’ 

provision has been removed. The final 

rule now contains provisions to cease 

reporting if annual reports demonstrate 

emissions less than specified levels for 

multiple years. These provisions apply 

to all reporting facilities, including 

those with phosphoric acid production 

processes. The purpose of this rule is to 

collect information on emissions 

sources for future policy development. 

Requiring reporting for these sources 

will provide EPA with valuable data to 

better characterize GHG emissions from 

phosphoric acid production and provide 

a more credible position if EPA elects to 

exclude these sources from future GHG 

policy analyses. We also believe that the 

accurate assessment of the emissions 

from phosphoric acid production will 

address the commenters’ concerns about 

potential future impacts. 

Commenters may also be interested in 

reviewing Section II.H of this preamble 

for the response on provisions to cease 

reporting. 

Method for Calculating GHG Emissions 

and Monitoring and QA/QC 

Requirements 

Comment: Multiple commenters 

asked that production measurements in 

this rule be consistent with the existing 

MACT and NSPS regulations for the 

phosphate industry. In these 

regulations, production measurement is 

determined by the mass of phosphate 

feed (as P2O5). Two commenters stated 

that the change would provide 

consistency, and ensure a reporting 

structure that fits with the actual 

practices of the industry. 

Response: We agree with the 

commenters that consistency among 

EPA regulations is important. Therefore, 

the final rule allows for techniques from 

part 60 and part 63 to calculate the 

weight of phosphorous-containing rock. 

This request is consistent with the 

intent of the proposed rule. Under 

existing regulations in part 60 and part 

63, phosphoric acid manufacturing 

facilities already measure the mass of 

phosphorous bearing feed on a ton/hour 

basis. This feed rate can be used to 

determine monthly phosphate rock 

consumption. Process CO2 emissions 

from phosphoric acid production are 

calculated from the total phosphate rock 

consumption multiplied by the 

inorganic carbon content of that rock. 

Further, part 60 and part 63 establish 

the appropriate monitoring and QA/QC 

procedures for determining this feed 

rate. 

Procedures for Estimating Missing Data 

Comment: Multiple commenters 

asked that the final rule allow options 

for missing data. The commenters asked 

that the use of default carbon content 

values based on the origin of the rock be 

allowed if analytical data are 

unavailable. In addition, commenters 

requested that procedures be added for 

measurement of the mass of phosphate 

rock consumed, suggesting procedures 

similar to those in 40 CFR part 98, 

subpart C, the lesser of the maximum 

capacity of the system, the maximum 

rate the meter can measure, or best 

available estimate based on available 

process data. 

Response: We agree with the 

commenters on this point. The final rule 

has been changed to allow the use of a 

default factor (by origin of the 

phosphate rock) for each missing value 

of the inorganic carbon content of 

phosphate rock. Use of a default carbon 

value in place of the missing data will 

provide a reasonable estimate of the 

total emissions from the facility and will 

avoid assuming the maximum possible 

facility emissions when no data are 

available. These default values have 

been added to the final rule in Table Z– 

1 of 40 CFR part 98, subpart Z. 

Missing data procedures have also 

been added as suggested for missing 

monthly estimates of the mass of 

phosphate rock consumed consistent 

with the later recommendation. Again 

use of the best available data based on 

all available process data will avoid 

assuming the maximum possible facility 

emissions when no data are available. 

Facilities must document and keep 

records of the procedures used for all 

such estimates. 

AA. Pulp and Paper Manufacturing 

1. Summary of the Final Rule 

Source Category Definition. This 

source category consists of facilities that 

produce market pulp (i.e., stand-alone 

pulp facilities), manufacture pulp and 

paper (i.e., integrated mills), produce 

paper products from purchased pulp, 

produce secondary fiber from recycled 

paper, convert paper into paperboard 

products (e.g., containers), or operate 

coating and laminating processes. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Table AA–1 of this 

preamble lists the GHG emission 

sources at pulp and paper 

manufacturing facilities for which GHG 

emissions must be reported along with 

the rule subpart that specifies the 

calculation methodology. 

TABLE AA–1—GHGS TO REPORT

For pulp and paper mills ... 

Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ... 

CO2 Biogenic 

CO2 CH4 N2O Biogenic 

CH4

Biogenic 

N2O 

Chemical recovery furnace at kraft and soda facilities ..................................... C AA C C AA AA 

Chemical recovery combustion units at sulfite facilities .................................... C AA C C AA AA 

Chemical recovery combustion units at stand alone semi-chemical facilities .. C AA C C AA AA 

Lime kilns of kraft and soda facilities ................................................................ AA/C AA AA/C AA/C AA AA 

Makeup chemicals used in pulp mills ............................................................... AA 


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21Biogenic CO2 from the conversion of CaCO3 to 

CaO in kraft or soda pulp mill lime kilns is 

accounted for in the biogenic CO2 emission factor 

for the recovery furnace. 

TABLE AA–1—GHGS TO REPORT—Continued 

For pulp and paper mills ... 

Report emissions of the listed GHGs by following the requirements of the 40 CFR part 98, subpart indicated ... 

CO2 Biogenic 

CO2 CH4 N2O Biogenic 

CH4

Biogenic 

N2O 

Stationary combustion units .............................................................................. C C C C C C 

Key: 

C = 40 CFR part 98, subpart C (General Stationary Fuel Combustion Sources). 

AA = 40 CFR part 98, subpart AA (Pulp and Paper Manufacturing). 

AA/C = use 40 CFR part 98, subpart AA for GHG emission factor and subpart C to determine default High Heating Values. 

GHG Emissions Calculation and 

Monitoring. Under 40 CFR part 98, 

subpart AA, reporters must calculate 

emissions from pulp and paper 

manufacturing facilities as follows: 

• Chemical recovery furnaces: 

Calculate biogenic CO2 emissions from 

combustion of biomass in spent pulping 

liquor using: 

—Measured quantities of spent liquor 

solids fired, site-specific high heating 

value (HHV), and default or sitespecific emission factors for each 

chemical recovery furnace located at 

kraft or soda facilities. 

—Measured quantities of spent liquor 

solids fired and the carbon content of 

the spent liquor solids for each 

chemical recovery unit at sulfite or 

stand-alone semichemical facilities. 

• Calculate CO2 emissions from fossil 

fuels used in chemical recovery 

furnaces using direct measurement of 

fossil fuels consumed and default 

emission factors according to the Tier 1 

methodology for stationary combustion 

sources in 40 CFR part 98, subpart C. 

• Calculate CH4 and N2O emissions as 

the sum of emissions from the 

combustion of fossil fuels and the 

combustion of biomass in spent 

pulping liquor, as follows: 

—For fossil fuel emissions, use direct 

measurement of fuels consumed, a 

default HHV, and default emission 

factors according to the methodology 

for stationary combustion sources in 

40 CFR 98.33(c). 

—For biomass emissions, use measured 

quantities of spent liquor solids fired, 

site-specific HHV, and default or sitespecific emission factors. 

—Lime kilns at kraft and soda facilities. 

• Lime kilns: Calculate CO2, CH4, and 

N2O emissions from combustion 21 of 

fossil fuels in pulp mill lime kilns using 

direct measurement of fossil fuels 

consumed and default emission factors 

and HHV found in 40 CFR part 98, 

subparts AA and C, respectively. 

• Makeup chemicals: Calculate CO2

emissions from the use of makeup 

chemicals using direct or indirect 

measurement of the quantity of 

chemicals added and ratios of the 

molecular weights of CO2 and the 

makeup chemicals. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart AA. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

AA. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart AA: Pulp 

and Paper Manufacturing.’’ 

• Language was added to clarify that 

40 CFR part 98, subpart AA GHG 

emissions are to be reported for makeup 

chemicals added in the chemical 

recovery areas of pulp mills (as opposed 

to makeup chemicals used at paper 

coating and laminating facilities). 

• The frequency of measurements for 

the spent liquor solids mass fired 

(TAPPI Test Method T 650), heating 

value (TAPPI Test Method T 684), and 

carbon content (ASTM D5373–08) was 

reduced from monthly to annually. 

• An option to use data from existing 

online solids meters to determine the 

annual mass of spent liquor solids fired 

is provided (in lieu of conducting an 

annual TAPPI Test Method T 650). 

• The requirement to report quarterly 

data was eliminated. 

• The reporting requirements were 

revised to specify units to standardize 

inputs into the data reporting system. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

number of comments on pulp and paper 

manufacturing were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart AA: Pulp 

and Paper Manufacturing.’’ 

Definition of Source Category 

Comment: Two commenters stated 

that literal interpretation of 40 CFR part 

98, subpart AA could require any 

facility operating paper coating and 

laminating processes to report emissions 

for any system used to add makeup 

chemicals. The commenters requested 

that language be added to 40 CFR part 

98, subpart AA to clearly exclude 

facilities not intended to be covered and 

which have not traditionally been part 

of the pulp and paper source category. 

Response: Definitions of terms used in 

40 CFR part 98, subpart AA are 

provided in 40 CFR 98.6 (in subpart A 

of part 98). The definition of ‘‘makeup 

chemicals’’ is specific to the chemical 

recovery areas of pulp mills and serves 

to limit the scope of the pulp and paper 

subcategory. As defined in § 98.6 

(emphasis added): 

‘‘Chemical recovery combustion unit 

means a combustion device, such as a 

recovery furnace or fluidized-bed reactor 

where spent pulping liquor from sulfite or 

semi-chemical pulping processes is burned to 

recover pulping chemicals.’’ 

‘‘Makeup chemicals means carbonate 

chemicals (e.g., sodium and calcium 

carbonates) that are added to the chemical 

recovery areas of chemical pulp mills to 

replace chemicals lost in the process.’’ 


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Thus, we disagree that the rule could 

be interpreted to require any facility 

operating coating and laminating 

processes to report emissions for any 

system used to add makeup chemicals. 

This was not the intent of the rule. 

Nevertheless, we have added language 

consistent with the definition of 

‘‘makeup chemicals’’ to 40 CFR 

98.270(b)(5) and 98.272(e) to further 

clarify that GHG emissions are to be 

reported for systems adding makeup 

chemicals (CaCO3 and Na2CO3) in the 

chemical recovery areas of pulp mills. 

Comment: Commenters stated the rule 

should include categorical exemptions 

for emissions from the combustion of 

non-condensable gases (NCG), stripper 

off gases (SOG), tall oil and turpentine 

(small sources of GHG that are difficult 

to measure). The commenters noted that 

these streams are of biogenic origin. One 

commenter described safety issues 

associated with sampling these gas 

streams. 

Response: Pulp mill NCG, SOG, tall 

oil and turpentine were discussed in the 

Proposed Rule TSD for the pulp and 

paper manufacturing sector. The 

Proposed Rule TSD noted that process 

vent gases such as NCG and SOG and 

the byproducts tall oil and turpentine 

are derived from biomass. We 

acknowledge the safety and 

measurement issues described by 

commenters regarding sampling of NCG 

and SOG streams. No methods are 

specified in the rule for calculation of 

GHG associated with combustion of 

NCG, SOG, tall oil and turpentine. Thus, 

calculation of these emissions is not 

required and there is no need for 

categorical exemptions. 

Method for Calculating GHG Emissions 

Comment: Commenters stated that 

monthly measurements of the mass of 

spent liquor solids, HHV, and carbon 

content of spent liquor solids are 

unnecessary. The commenters requested 

that EPA either allow default fuel 

carbon content and heating value for 

spent pulping liquor, or reduce the 

frequency of measurements to annually 

or every two years. Commenters noted 

that spent liquor HHV and carbon 

content are measured from time to time 

but less frequently than monthly. In 

addition, one commenter pointed out 

that chemical recovery furnaces often 

have online solids meters installed to 

provide continuous measurement of the 

mass of spent liquor solids entering the 

furnace for safety and process control 

reasons. This commenter requested that 

EPA allow use of such continuous 

measurement devices instead of 

requiring monthly measurement of the 

mass of spent liquor solids with TAPPI 

Test Method T 650. 

Response: We disagree with 

commenters that default fuel carbon 

content and high heating values should 

be allowed instead of measured values. 

These parameters are already measured 

by mills (though less frequently than 

monthly) and thus are available for use 

and more accurate than default values. 

We are reducing the frequency of fuel 

property measurements from monthly to 

annual. There is little monthly variation 

in fuel properties over the course of a 

year. Therefore, annual measurements 

are sufficient to develop site specific 

emission factors. This change also 

reduces the burden associated with 

complying with the rule. These changes 

have been incorporated throughout the 

text and equations of 40 CFR part 98, 

subpart AA. 

In addition, the final rule allows use 

of either an annual measurement of the 

mass of spent liquor solids fired (with 

TAPPI Test Method T 650) or use of 

annual spent liquor solids data 

calculated from continuous 

measurements already performed for 

process control purposes (e.g., with 

existing online solids meters). If the 

annual spent liquor solids fired is 

determined using existing measurement 

equipment, then reporters must retain 

records of the calculations used to 

determine the annual mass of spent 

liquor solids fired from the continuous 

measurements in order to demonstrate, 

if necessary, that calculations where 

done correctly. Reporters must also 

document that these measurement 

devices have been regularly and 

properly calibrated according to the 

manufacturer’s specifications. 

Data Reporting Requirements 

Comment: One commenter noted that 

presenting quarterly data in annual 

reports for pulp and paper 

manufacturing annual emissions, 

consumption of biomass fuels, and 

quantity of spent liquor solids fired is 

unnecessary for an annual reporting 

system. 

Response: We have revised 40 CFR 

98.276 and 98.277(a) to remove the 

requirement for providing quarterly 

details in the annual report. EPA agrees 

that requiring quarterly details was not 

necessary for ensuring the accuracy of 

data reported annually. 

Comment: One commenter requested 

that the spreadsheets developed by the 

National Council for Air and Stream 

Improvement (NCASI) for the 

International Council of Forest and 

Paper Associations (ICFPA) be allowed 

as an option for facilities subject to the 

Rule to determine emissions. These 

spreadsheets segregate calculated GHG 

emissions into fossil fuel and biogenic 

categories. The commenter believes that 

tools like those developed by NCASI 

and others should be allowed as an 

option for facilities subject to the 

emission calculation requirements 

imposed by 40 CFR 98.3. This 

streamlined approach will provide the 

Agency with valid GHG emission data 

without imposing extraordinary capital 

and labor burdens on the industry. 

Response: The ICFPA/NCASI tools 

were considered in developing the 

requirements of the GHG reporting rule. 

However, the ICFPA/NCASI 

spreadsheets, though valuable tools, are 

not broadly applicable to all industrial 

sectors covered under the GHG 

reporting rule, as are the monitoring, 

reporting, recordkeeping, and emissions 

verification requirements specified in 40 

CFR 98.3. Additionally, these tools often 

use default factors and estimates, which 

differs from the approach proposed by 

EPA. The data collected from all 

subparts of the GHG reporting rule will 

be tabulated in EPA’s electronic 

reporting system. This system will be 

used to verify emission calculations and 

will require specific data be reported in 

order to run the calculations used for 

verification. The tools suggested by the 

commenter, however, would only 

provide a total emission number. 

Consequently, EPA would not be able to 

check the underlying calculations for 

accuracy. The final GHG reporting rule 

reflects the data reporting requirements 

necessary for emissions verification by 

EPA. Edits to the reporting and 

recordkeeping language (40 CFR 98.276 

and 98.277) of 40 CFR part 98, subpart 

AA were made to clarify calculation 

inputs and units of measure to be 

reported. As part of the implementation 

phase of today’s final rule, EPA intends 

to prepare guidance documents to assist 

the industry in complying with the 

rule’s requirements. In recognition of 

the fact that the pulp and paper industry 

has been using the ICFPA/NCASI 

spreadsheets, EPA will consider 

including in the guidance materials a 

comparison between these spreadsheets 

and EPA’s electronic reporting system to 

reduce the burden on the industry and 

minimize confusion. 

BB. Silicon Carbide Production 

1. Summary of the Final Rule 

Source Category Definition. The 

silicon carbide production source 

category consists of any process that 

produces silicon carbide for abrasive 

purposes. 

Reporters must submit annual GHG 

reports for facilities that meet the 


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applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. Report process CO2

and CH4 emissions from all silicon 

carbide production furnaces or process 

units at the facility combined. 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. For example, 

report CO2, N2O, and CH4 emissions 

from each stationary combustion unit on 

site under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

GHG Emissions Calculation and 

Monitoring. For CO2 emissions, 

reporters must use one of the following 

methods, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions from 

silicon carbide production processes by 

either (1) installing and operating CEMS 

and following the Tier 4 methodology 

(in 40 CFR part 98, subpart C) or (2) 

calculating emissions using the 

measured petroleum coke consumption 

and a monthly facility-specific emission 

factor. The facility-specific emission 

factor is the carbon content of the 

petroleum coke (provided monthly by 

the supplier or measured monthly using 

the appropriate test methods) adjusted 

for carbon in the silicon carbide 

product. 

• However, if process CO2 emissions 

from silicon carbide production are 

vented through the same stack as a 

combustion unit or process equipment 

that uses a CEMS and follows Tier 4 

methodology to report process CO2

emissions, then the CEMS must be used 

to measure and report combined CO2

emissions from that stack. In such cases, 

the reporter cannot use the CO2

calculation approach (2) outlined in the 

above bullet. 

For CH4 emissions, reporters must use 

the measured petroleum coke 

consumption and a default emission 

factor of 10.2 kilograms (kg) per metric 

ton of coke consumed. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart BB. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

BB. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart BB: Silicon 

Carbide Production.’’ 

• The emissions calculation method 

under 40 CFR 98.283(b) was revised to 

require data on monthly petroleum coke 

consumption and monthly petroleum 

coke carbon contents rather than 

quarterly determinations. 

• Missing data procedures were 

added under 40 CFR 98.285 for monthly 

parameters used to calculate emissions, 

including mass of petroleum coke, and 

carbon contents of petroleum coke. 

• 40 CFR 98.286 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.287 to 40 CFR 98.286, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.283 were added to 40 CFR 

98.286 for clarity. 

3. Summary of Comments and 

Responses 

No specific comments were received 

pertaining to the proposed reporting 

requirements for silicon carbide 

production facilities. However, the 

proposed rule did not clearly specify 

how quarterly carbon contents should 

be determined. This determination 

should be made on a monthly basis as 

proposed for other chemical production 

processes where process emissions arise 

from use of petroleum coke, such as 

titanium dioxide production. Quarterly 

reporting of carbon contents of 

petroleum coke consumed for the 

quarter would have to be averaged from 

monthly data. For verification, EPA 

would require reporting of the monthly 

carbon contents of the petroleum coke. 

Therefore, we revised the emissions 

calculation method to directly require 

monthly petroleum coke consumption 

and monthly petroleum coke contents, 

rather than quarterly based on an 

arithmetic average of the monthly 

estimates to improve accuracy of 

emissions calculations. We have 

retained the flexibility in use of supplier 

data to determine carbon contents. We 

understand that most supplier data on 

carbon contents of petroleum coke is 

readily available and that businesses 

track production inputs and outputs on 

a monthly basis as a part of normal 

business practice or existing accounting 

procedures. The increased frequency of 

data collection from quarterly to 

monthly provides greater clarity and 

accuracy without significantly 

increasing burden. In addition, see the 

Section II.N of this preamble for an 

explanation of the emissions 

verification approach. 

CC. Soda Ash Manufacturing 

1. Summary of the Final Rule 

Source Category Definition. A soda 

ash manufacturing facility is any facility 

with a manufacturing line that produces 

soda ash by either: calcining trona or 

sodium sesquicarbonate; or by using a 

liquid alkaline feedstock process that 

directly produces CO2. In the context of 

the soda ash manufacturing sector, 

‘‘calcining’’ means the thermal/chemical 

conversion of the bicarbonate fraction of 

the feedstock to sodium carbonate. 

Soda ash produced from a liquid 

alkaline feedstock using sodium 

hydroxide does not emit process CO2

and therefore is not subject to the 

requirements of Subpart CC. However, 

such facilities may be covered under 

Subpart C (General Stationary 

Combustion) if they meet the 

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

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For soda ash 

manufacturing, report the following 

emissions: 

• CO2 process emissions from soda 

ash manufacturing, reported for each 

manufacturing line. 

• CO2 combustion emissions from 

each soda ash manufacturing line. 

• N2O and CH4 emissions from fuel 

combustion at each soda ash 

manufacturing line under 40 CFR part 

98, subpart C (General Stationary Fuel 

Combustion Sources) using the 

methodologies in subpart C. 

• CO2, N2O, and CH4 emissions from 

each stationary combustion unit other 

than soda ash manufacturing lines 

under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

In addition, report GHG emissions for 

any other source categories at the 

facility for which calculation methods 

are provided in other subparts of the 

rule, as applicable. 

GHG Emissions Calculation and 

Monitoring. For CO2 emissions from 

soda ash manufacturing lines, reporters 

must select one of the following 

methods, as appropriate: 


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• For each soda ash manufacturing 

line with certain types of CEMS in 

place, reporters must use the CEMS and 

follow the Tier 4 methodology (in 40 

CFR part 98, subpart C) to report under 

the Soda Ash Manufacturing subpart (40 

CFR part 98, subpart CC) combined 

process and combustion CO2 emissions. 

• For other soda ash manufacturing 

lines, reporters can elect to either (1) 

install and operate a CEMS and follow 

Tier 4 methodology to measure and 

report combined process and 

combustion CO2 emissions or (2) 

calculate CO2 process emissions using 

the procedures specified in 40 CFR part 

98, subpart CC and summarized below. 

• If using approach 2, calculate 

process CO2 emissions using one of 

three alternative methods, as 

appropriate for each manufacturing line: 

—The trona input method calculates the 

calcination emissions using: Monthly 

mass of trona input (required to be 

measured), the average monthly massfraction of inorganic carbon in the 

trona (required to be measured 

weekly), and the ratio of CO2 emitted 

for each ton of trona consumed (a 

default value is provided). 

—The soda ash output method 

calculates the calcination emissions 

using: Monthly mass of soda ash 

produced (required to be measured), 

the monthly average mass-fraction of 

inorganic carbon in the soda ash 

(required to be measured weekly), and 

the ratio of CO2 emitted for each ton 

of soda ash produced (a default value 

is provided). 

—The site-specific emission factor 

method calculates emissions from 

production of soda ash using liquid 

alkaline feedstock through an annual 

performance test using: The average 

process vent flow rate from the mine 

water stripper/evaporator for each 

manufacturing line, direct 

measurements of hourly CO2

concentration, the hourly stack gas 

volumetric flow rate, the annual 

process vent flow rate from mine 

water stripper/evaporator, and annual 

operating hours. 

—Report process CO2 emissions from 

each soda ash manufacturing line 

under 40 CFR part 98, subpart CC 

(Soda Ash Manufacturing), and report 

combustion CO2 emissions from each 

calciner (kiln) in each manufacturing 

line under 40 CFR part 98, subpart C 

(General Stationary Fuel Combustion 

Sources). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart CC. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

CC. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart CC: Soda 

Ash Manufacturing.’’ 

• A site-specific emission factor 

method has been added for production 

of soda ash using liquid alkaline 

feedstock or mine water. This method 

was not included in the proposed rule. 

• The frequency of inorganic carbon 

content determination of either trona or 

soda ash has been revised from daily to 

monthly based on a weekly composite. 

• Procedures were added to 40 CFR 

98.295 for estimating missing data for 

monthly values of inorganic carbon 

content of trona and monthly values of 

trona consumption or soda ash 

production. We also added missing data 

procedures for parameters specific to 

calculating emissions from soda ash 

produced from liquid alkaline feedstock 

(i.e. site-specific emission factor 

method). 

• 40 CFR 98.296 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.297 to 40 CFR 98.296, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.293 were added to 40 CFR 

98.296 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. Two 

sets of comments on soda ash 

manufacturing were received covering 

several topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart CC: Soda Ash 

Manufacturing.’’ 

Method for Calculating GHG Emissions 

Comment: Both commenters noted 

that facilities produced soda ash using 

alternative methods to calcining trona or 

other carbonate containing minerals. 

Facilities also produce soda ash from 

mine water, a liquid alkaline feedstock; 

this is a ‘‘process’’ emissive production 

process, but was not addressed in the 

proposal. The methods in the proposal 

did not include methods appropriate for 

calculating process CO2 from the liquid 

alkaline feedstock production process. 

One commenter using this production 

method recommended that the 

appropriate method for calculating 

emissions from this process would be an 

annual performance test and described 

the appropriate parameters that would 

be measured during the annual 

performance test to establish an 

emission factor for calculating annual 

emissions based on concentration of the 

CO2 in the evaporated stripped mine 

water and the annual flow from the 

mine water stripper/evaporator. 

Response: We agree that the final rule 

should address process CO2 emissions 

generated from this relatively new 

alternative production process which 

produces soda ash from liquid alkaline 

feedstock or mine water. From 

additional information provided by the 

commenter, process CO2 emissions from 

this production method are likely to be 

significant and exceed 25,000 metric 

tons CO2e. This process is currently 

used by a single company, but could 

become more widespread within the 

industry in the future as it makes more 

efficient use of raw materials previously 

not used. We have updated all sections 

of 40 CFR part 98, subpart CC for 

calculating, monitoring and QA/QC, and 

reporting of process CO2 emissions 

specific to production of soda ash from 

liquid alkaline feedstock or minewater. 

We added procedures for developing 

site-specific emission factor based on an 

annual performance test consistent with 

the recommendations provided by the 

commenter. 

Comment: One commenter noted that 

using the total alkalinity of either trona 

or soda ash as prescribed in Equations 

CC–2 and CC–3 is inappropriate given 

that the ratio of carbon dioxide to 

carbon is a factor in the equations. The 

equations’ results artificially inflated the 

CO2 level by 3.67 times the actual 

amount. 

Response: Upon further review, we 

agree with the commenter’s analysis 

that the ratio 44/12 will overestimate 

emissions and have removed this 

fraction, which is the ratio of carbon 

dioxide to carbon, from Equations CC– 

2 and CC–3. Equations CC–2 and CC–3 


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provide results directly for CO2

therefore it is not necessary to use a 

conversion factor to convert the carbon 

to carbon dioxide. 

Comment: One commenter noted that 

Equation CC–3 does not address plant 

inefficiency specific to each 

manufacturing line. The commenter 

suggested that an efficiency factor 

should be added to Equations CC–3 to 

account for these inefficiencies. 

Response: The commenter has not 

suggested an efficiency factor or 

otherwise provided data with enough 

specificity to modify the equations and 

modify the calculation methods as 

suggested; therefore, we have decided 

not to add efficiency factors to 

Equations CC–3. 

EPA needs more information to 

effectively evaluate this comment and 

update the equations noted, if 

appropriate. Efficiency factors can relate 

to a number of factors including 

combustion and also kiln conditions, 

which may vary. We need more 

information to understand how this 

factor would be derived for each kiln or 

manufacturing line. The comment was 

specific to CC–3, and we suggest the use 

of Equation CC–2 as an alternative 

calculation method. 

Monitoring and QA/QC Requirements 

Comment: One commenter stated that 

daily sampling of inorganic carbon 

content of each manufacturing line is an 

unnecessary and potentially extremely 

costly requirement. They suggested that 

instead of daily testing, testing should 

be completed as a weekly composite 

analysis which would then be used in 

calculating the monthly average. 

Response: We concur that testing of 

the inorganic carbon content can be 

done on a weekly schedule and used to 

calculate a monthly composite without 

significant loss in accuracy. The weekly 

composite would still be based on 

several daily tests. We have updated the 

monitoring and QA/QC requirements 

accordingly in the rule under 40 CFR 

98.294. 

Comment: One commenter stated that 

the prescribed ASTM method, ASTM 

E359–00(2005), for determining the 

inorganic carbon content of trona or 

soda ash describes a manual titration 

method using a methyl orange endpoint. 

They stated that procedures that use 

autotitrators with fixed endpoint 

titration are commonly used in the soda 

ash manufacturing industry and should 

be allowed as an acceptable equivalent 

alternative. 

Response: We agree that methods 

using autotitration to determine 

inorganic carbon content of trona or 

soda ash expressed as total alkalinity are 

acceptable equivalent methods for 

determining the inorganic carbon 

content of trona or soda ash. We 

understand that manual titration offers 

good levels of accuracy but are labor 

and time intensive. From our 

understanding, autotitration methods 

provide comparable or improved levels 

of accuracy and are less labor and time 

intensive by ‘‘automating’’ the analysis 

process. Autotitration methods could 

provide more consistency in results 

across the industry. We have updated 

the procedures in 40 CFR 98.294 for 

monitoring and QA/QC in the rule to 

allow for such comparable methods. 

DD. Sulfur Hexafluoride (SF6) From 

Electrical Equipment 

At this time EPA is not going final 

with the electrical equipment subpart. 

As we consider next steps, we will be 

reviewing the public comments and the 

relevant information. 

Based on careful review of comments 

received on the preamble, rule, and 

TSDs under 40 CFR part 98, subpart DD, 

EPA will perform additional analysis 

and evaluate a range of data collection 

procedures and methodologies. EPA’s 

goal is to optimize methods of data 

collection to ensure data accuracy while 

considering industry burden. In 

addition, EPA will further evaluate the 

scope of coverage of electric power 

systems and the reporting boundaries in 

other subparts. 

EE. Titanium Dioxide Production 

1. Summary of the Final Rule 

Source Category Definition. The 

titanium dioxide production source 

category consists of any facility that 

uses the chloride process to produce 

titanium dioxide. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For titanium dioxide 

production, report CO2 process 

emissions from each chloride process 

line. 

In addition, report GHG emissions for 

other source categories for which 

calculation methods are provided in the 

rule, as applicable. For example, 

facilities must report CO2, N2O, and CH4

emissions from each stationary 

combustion unit on site under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources). 

GHG Emissions Calculation and 

Monitoring. Reporters must calculate 

CO2 process emissions using one of two 

methods, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions from 

titanium dioxide process lines by either 

(1) installing and operating CEMS and 

following the Tier 4 methodology (in 40 

CFR part 98, subpart C) or (2) using the 

calculation procedures specified below. 

• However, if process CO2 emissions 

from titanium dioxide production are 

emitted through the same stack as a 

combustion unit or process equipment 

that uses a CEMS and follows Tier 4 

methodology to report CO2 emissions, 

then the reporter must use the CEMS to 

measure and report combined CO2

emissions from that stack instead of 

using the calculation procedures 

described below. 

• If using approach #2, calculate the 

process CO2 emissions using the 

equation provided 40 CFR part 98, 

subpart EE and monthly determination 

of the mass and carbon content of 

calcined petroleum coke consumed in 

each line and all lines combined. 

Determine petroleum coke consumption 

by either direct measurement or 

purchase records. Determine carbon 

content of petroleum coke using 

supplier data or measurement using 

appropriate test methods. If applicable, 

also determine the quantity of carbon 

containing waste generated and its 

carbon contents using direct 

measurement. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart EE. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

EE. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart EE: Titanium 

Dioxide Production.’’ 

• Requirements were added for 

reporting of carbon-containing waste 

generated from less than 100 percent 

oxidation of coke during the titanium 

production process. 40 CFR 98.316 


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allows for reporting of quantity of 

carbon-containing waste generated and 

associated carbon contents. 

• Missing data procedures were 

added under 40 CFR 98.315 for monthly 

parameters used to calculate emissions, 

including mass of calcined petroleum 

coke, mass of carbon-containing waste, 

and carbon contents of calcined 

petroleum coke. 

• 40 CFR 98.316 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.317 to 40 CFR 98.316, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.313 were added to 40 CFR 

98.316 for clarity. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. We 

received three sets of comments on 

titanium dioxide production covering 

several topics. Several of these 

comments were directed at the 

requirements for General Stationary 

Fuel Combustion Sources in subpart C, 

and responses to those comments are 

provided in the preamble section 

dealing with that source category. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

EE: Titanium Dioxide Production.’’ 

Method for Calculating GHG Emissions 

Comment: One commenter noted that 

the carbon oxidation factor for calcined 

petroleum coke is not always 100 

percent. They point out that the 

calcined petroleum coke comes with 

impurities, and a certain amount of the 

calcined coke is returned to the ground 

as landfill along with components such 

as the un-converted TiO2. Thus, they 

suggest that EPA should revise the 

carbon oxidation factor to allow 

facilities to use the most appropriate 

factor for their process, with supporting 

documentation of its derivation 

available for EPA review as needed. 

Response: EPA has considered the 

comment but maintains the assumption 

of 100 percent oxidation across all 

sectors in the final rule. Data reporting 

requirements have been added to 40 

CFR 98.316 to collect information on the 

quantity of carbon-containing waste 

generated that is landfilled and its 

carbon contents which are not emitted. 

This information will help inform future 

methods for calculating process 

emissions from titanium dioxide 

production (e.g., how to address 

oxidation rates). EPA interpreted that 

this comment may also be applicable to 

carbon content of calcined petroleum 

coke. EPA agrees that carbon content 

may not always be 100 percent and 

therefore has revised the rule to allow 

facilities to use supplier data or 

determine carbon contents using 

appropriate test methods as part of 

calculating emissions in 40 CFR 98.313. 

Procedures for Estimating Missing Data 

Comment: Two commenters noted 

there can be numerous reasons data may 

not be available, on time, or in the 

format EPA requires. In cases where a 

required record is found to be missing 

or determined to be incorrect, the 

commenters requested that EPA should 

provide a procedure for estimating 

missing data. 

Response: We concur that there may 

be circumstances where data on carbon 

contents of coke and petroleum coke 

consumption may be missing. Records 

could be misplaced or lost. Thus, we 

have revised the rule and added specific 

procedures for estimating missing data 

in 40 CFR 98.315. These procedures are 

consistent with those allowed across the 

rule for similar parameters. For 

example, if a facility is missing data on 

carbon contents of petroleum coke we 

allow facilities to allow sources to 

substitute the missing data with another 

quality assured parameter, such as the 

arithmetic average of the carbon 

contents from the month immediately 

preceding and the month immediately 

following the missing data incident. 

Data Reporting Requirements 

Comment: All commenters noted they 

are concerned that the level of 

information to be reported, which is 

considered available for public 

distribution, could put the domestic 

TiO2 producers at a disadvantage 

relative to international producers. The 

commenters do not believe that CBI 

provisions briefly outlined in the 

preamble are adequate to safeguard the 

proprietary technical and financial 

positions of titanium dioxide 

production facilities. The annual 

production of titanium dioxide, annual 

amount of petroleum coke consumed, 

and annual operating hours are 

considered CBI and are unnecessary to 

carry out the purposes of this proposed 

regulation. This data should only be 

available onsite or offsite (e.g., a 

centralized location), or as requested for 

security cleared EPA personnel and 

their security cleared contractors where 

a need is demonstrated for the purposes 

of this inventory. 

Response: EPA reviewed CBI 

comments received across the rule (both 

general and subpart-specific comments) 

and our response is discussed in Section 

II.R of this preamble and in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Legal 

Issues.’’ 

In addition, see the Section II.N of 

this preamble for the response on the 

emissions verification approach. The 

amount of petroleum coke consumed is 

necessary to calculate annual process 

CO2 emissions. Production capacity and 

annual production of titanium dioxide 

are required for EPA to verify annual 

CO2 process emissions. These 

parameters help EPA to determine 

whether reported emissions are within a 

reasonable range. EPA concurs that data 

on operating hours can be retained as a 

record and does not need to be reported 

to EPA. It is not a parameter used in 

calculating process CO2 emissions. 

However, operating hours would help to 

verify any anomalies in reported 

emissions or supporting parameters 

related to temporary closures for repairs 

or maintenance. This data has been 

moved to recordkeeping requirements in 

40 CFR 98.317. 

FF. Underground Coal Mines 

At this time, EPA is not finalizing the 

Underground Coal Mines Subpart (40 

CFR part 98, subpart FF). As EPA 

considers next steps, we will be 

reviewing the public comments on the 

proposal preamble, rule and TSDs for 

proposed 40 CFR 98 Subpart FF and 

other relevant information. EPA will 

perform additional analysis and 

consider alternatives to the monitoring 

requirements. 

GG. Zinc Production 

1. Summary of the Final Rule 

Source Category Definition. Zinc 

production facilities consist of zinc 

smelters and secondary zinc recycling 

facilities. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For zinc production, 

report the following: 

• CO2 process emissions from each 

Waelz kiln and electrothermic furnace 

used for zinc production. 

• CO2, N2O, and CH4 combustion 

emissions from each Waelz kiln and 

each other stationary combustion unit 

on site under 40 CFR part 98, subpart 

C (General Stationary Fuel Combustion 

Sources). 

In addition, report GHG emissions for 

other source categories at the facility for 

which calculation methods are provided 

in the rule, as applicable. 


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GHG Emissions Calculation and 

Monitoring. Facilities must calculate 

CO2 process emissions using one of two 

methods, as appropriate: 

• Most reporters can elect to calculate 

and report process CO2 emissions from 

each Waelz kiln and electrothermic 

furnace by either (1) installing and 

operating CEMS and following the Tier 

4 methodology (in 40 CFR part 98, 

subpart C) or (2) using the calculation 

procedures specified in the rule. 

• However, if process CO2 emissions 

from a Waelz kiln or electrothermic 

furnace are emitted through the same 

stack as a combustion unit or process 

equipment that uses a CEMS and 

follows Tier 4 methodology to report 

CO2 emissions, then the CEMS must be 

used to measure and report combined 

CO2 emissions from that stack, instead 

of the calculation procedure described 

below. 

• If using approach #2, calculate 

process CO2 emissions by determining 

on an annual basis the total mass 

(metric tons) of carbon-containing input 

materials (i.e., zinc-bearing material, 

flux, electrodes, and any other 

carbonaceous materials) introduced into 

each kiln and furnace and the carbon 

content of each material. Determine 

carbon content annually either by using 

supplier data, or by direct measurement 

using appropriate test methods. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart GG. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

GG. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these changes can be found 

below. 

• The carbon input method was 

revised to require an annual analysis of 

all process inputs and outputs for 

carbon content rather than monthly 

sampling and monthly analysis. 

• A de minimis was added to exclude 

accounting for carbon-containing 

materials contributing less than one 

percent of the total carbon into Waelz 

kiln or electrothermic furnaces. These 

materials do not need to be included in 

carbon mass balance calculations. 

• 40 CFR 98.336 was reorganized and 

updated to improve the emissions 

verification process. Some data 

elements were moved from 40 CFR 

98.337 to 40 CFR 98.336, and some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.333 were added to 40 CFR 

98.336 for clarity. 

3. Summary of Comments and 

Responses 

No comments specific to regulation of 

the zinc production sector were 

received. We revised the frequency of 

sampling and analysis of carbon 

contents for carbon containing input 

materials from monthly to annual 

consistent with revisions made in 

response to comments for similar 

production processes (e.g., emissions 

from metal production, see the preamble 

Section III.Q for iron and steel for 

specific responses to comments). These 

revisions reduce the reporting burden 

for zinc production facilities. We 

understand that the carbon content of 

material inputs does not vary widely at 

a given facility for the significant 

process inputs that contain carbon, and 

we continue to account for variations 

due to changes in production rate, 

which is likely a more significant source 

of variability. 

HH. Municipal Solid Waste Landfills 

1. Summary of the Final Rule 

Source Category Definition. This 

source category consists of municipal 

solid waste (MSW) landfills that 

accepted waste on or after January 1, 

1980. The source category includes the 

MSW landfill, landfill gas collection 

systems, and landfill gas destruction 

devices (including flares) at the landfill. 

This source category does not include 

hazardous waste, construction and 

demolition, or industrial landfills. 

Reporters must submit annual GHG 

reports for facilities that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble. 

GHGs to Report. For MSW landfills, 

report the following: 

• Annual CH4 generation and CH4

emissions from the landfill. 

• Annual CH4 destruction (for 

landfills with gas collection and control 

systems). 

• Annual CO2, CH4, and N2O 

emissions from stationary fuel 

combustion devices under 40 CFR part 

98, subpart C (General Stationary 

Combustion Sources). 

GHG Emissions Calculation and 

Monitoring. All facilities must calculate 

modeled annual CH4 generation based 

on: 

• Measured or estimated values of 

historic annual waste disposal 

quantities; and 

• Appropriate values for model 

inputs (i.e., degradable organic carbon 

fraction in the waste, CH4 generation 

rate constant). Default parameter values 

are specified for bulk municipal waste 

and individual waste categories. 

Facilities that do not collect and 

destroy landfill gas must adjust the 

modeled annual CH4 generation to 

account for soil oxidation (CH4 that is 

converted to CO2 as it passes through 

the landfill cover before being emitted) 

using a default soil oxidation factor. The 

resulting value must be reported and 

represents both CH4 generation and CH4

emissions. 

Facilities that collect and control 

landfill gas must calculate the annual 

quantity of CH4 recovered and destroyed 

based on either continuous or weekly 

monitoring of landfill gas flow rate, CH4

concentration, temperature, and 

pressure of the collected gas prior to the 

destruction device. 

Those facilities that collect and 

control landfill gas must then calculate 

CH4 emissions in two ways and report 

both results. Emissions must be 

calculated by: 

1. Subtracting the measured amount 

of CH4 recovered from the modeled 

annual CH4 generation (with 

adjustments for soil oxidation using the 

default value and destruction efficiency 

of the destruction device) using the 

equations provided; and 

2. Applying a gas collection efficiency 

to the measured amount of CH4

recovered to calculate CH4 generation, 

then subtracting the measured amount 

of CH4 recovered (with adjustments for 

soil oxidation using the default value 

and destruction efficiency of the 

destruction device) using the equations 

provided. Default collection efficiencies 

are specified, based on cover material 

and other factors. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart HH. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 


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summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

HH. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be founds below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart HH: 

Landfills.’’ 

• Industrial landfills were removed 

from the applicability provisions of 40 

CFR part 98, subpart HH. The 

applicability provisions were also 

modified to exempt landfills that did 

not accept any waste after January 1, 

1980. 

• Additional methods for estimating 

quantities of waste for prior (historic) 

years are provided. 

• The requirement to continuously 

monitor CH4 composition in the flare 

gas was removed. If a continuous 

monitoring system is in place, that data 

must be used, but weekly sampling of 

the gas is allowed if such a continuous 

system is not in place. 

• Direct flame ionization methods 

were added to the rule as an alternative 

to the gas chromatographic methods for 

determining methane concentrations. To 

use a direct flame ionization method, a 

correction factor must be determined at 

least once each reporting year and 

applied to adjust the analyzer’s total 

gaseous organic concentration to an 

unbiased methane concentration. 

• More detailed default values are 

provided for landfill gas collection 

efficiencies based on cover material and 

other factors. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on landfills 

were received covering numerous 

topics. Responses to significant 

comments received can be found in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart HH: Landfills.’’ 

Definition of Source Category 

Comment: Several commenters stated 

that EPA should limit the applicability 

of the industrial landfills to landfills 

located at food processing, pulp and 

paper, and ethanol production facilities 

(some also listed petroleum refineries) 

because these are the only industries for 

which landfills were specifically called 

out. Several commenters noted that 

impacts were only estimated for pulp 

and paper and food processing landfills, 

so EPA should limit the rule to those 

industries or correct the cost analysis to 

reflect the true burden of the rule on 

industrial landfills. Several commenters 

noted that the reporting requirements 

seemed tailored for MSW landfills and 

were generally inappropriate for 

industrial landfills (truck scales, etc.). 

One commenter also noted that, if 

reporting of GHG emissions from 

industrial landfills is not limited to the 

food processing, pulp and paper, and 

ethanol production facilities, then EPA 

should amend Table HH–1 of 40 CFR 

part 98, subpart HH and provide 

specific factors that are relevant to the 

regulated industry. Several commenters 

requested that EPA specifically exempt 

inorganic chemical manufacturing and 

mining landfills because they do not 

contain organic waste; other 

commenters suggested EPA delete 

requirements for landfills in 40 CFR part 

98, subpart Y because landfills are 

insignificant compared to other sources 

at a petroleum refinery. 

On the other hand, one commenter 

suggested that EPA may be overlooking 

an important source of methane 

emissions by excluding construction 

and demolition landfills as it seems 

possible that these landfills receive 

organic materials such as wood or yard 

waste that could degrade in an 

anaerobic environment. This commenter 

requested EPA provide information on 

the waste composition of construction 

and demolition landfills to explain more 

fully the basis for its decision to 

categorically exempt these sources from 

GHG reporting requirements. 

Response: At this time, EPA is not 

going final with the industrial landfills 

proposed requirements of this subpart. 

In response to the proposal, EPA 

received numerous detailed public 

comments on the preamble, rule and 

TSDs under 40 CFR part 98, subpart HH. 

Comments addressed the 

appropriateness, coverage, and 

methodology for addressing GHG 

emissions from industrial landfills. In 

particular, commenters questioned 

which industrial landfills should be 

covered by the rule and the need for 

industry specific factors and 

methodologies for calculating and 

reporting emissions. As EPA considers 

next steps, we will be reviewing the 

comments and other relevant 

information and will perform additional 

analysis and consider alternatives to the 

proposed monitoring and reporting 

requirements for industrial landfills. 

With regard to construction and 

demolition landfills, we note that the 

IPCC 2006 Guidelines for National 

Greenhouse Gas Inventories estimates 

that construction and demolition waste 

has a degradable organic content (DOC) 

of 0.04 kg/kg waste (see Table 2.5 in 

Volume 5: Waste), and most of this 

organic matter is expected to be wood, 

with slow degradation rates (k=0.02 

yr¥1). Based on the anticipated 

properties of construction and 

demolition wastes, we anticipated that 

methane generation at dedicated 

construction and demolition debris 

landfills would be small compared to 

MSW landfills. We will further review 

these assumptions as we review 

comments on industrial landfills. 

Comment: Several commenters stated 

that the reporting requirements for 

closed landfills are burdensome, and the 

rule should be limited to reporting for 

active landfills. Information on waste 

disposal quantities and waste 

composition data are usually not 

available for closed MSW facilities. 

Thus, it is impossible to retain or 

provide the agency with such records 

for many old landfill sites. Several 

commenters suggested that EPA should 

provide additional guidance and 

screening tools to identify landfills 

likely to be below the threshold. The 

commenters noted that small and closed 

landfills have to collect all of the data 

needed to report their emissions in 

order to determine if they are above the 

reporting threshold. 

Response: Closed MSW landfills 

account for approximately half of the 

nationwide methane emissions from 

MSW landfills. This is because landfills 

can continue to emit for decades after 

they are closed and because these 

landfills are older, and less likely to 

have been required to add landfill gas 

collection systems. However, we do 

agree that we can remove reporting 

requirements for a subset of closed 

landfills to lessen the burden on longclosed landfill facilities. We evaluated 

the various landfill characteristics and 

identified that a 30-year waste-in-place 

(i.e., the total quantity of waste added to 

the landfill in the past 30 years) 

provided the best correlation of the data 

to sites that account for the majority of 

the contribution to the nationwide GHG 

emissions from landfills (see 

memorandum entitled ‘‘Correlations 

with Landfill Methane Generation and 

Actual Emissions’’ in the docket EPA– 

HQ–OAR–2008–0508–2165). Providing 

an applicability date for closed landfills 

is essential to minimize the burden 

associated with obtaining data on old 

landfills that provide only a small 

contribution to the nationwide GHG 


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emissions for landfills, and landfills 

closed prior to 1980 would not be 

relevant for the purposes of policy 

analyses. Therefore, the final rule 

excludes MSW landfills that have not 

accepted waste since January 1, 1980. 

We have also expanded and clarified 

options for projecting waste disposal 

quantities that will help ease the burden 

associated with calculating emissions 

from landfills that have closed after 

1980. EPA remains committed to 

providing additional outreach materials, 

guidelines, and screening tools to help 

potential reporters determine whether 

the reporting rule applies to their 

landfill. 

Method for Calculating GHG Emissions 

Comment: Several commenters 

requested additional guidance on how 

to determine waste disposal rates for 

years prior to the first reporting year. 

One commenter noted that the 

population method provided in the rule 

was difficult for many landfills because 

of contract carriers that may haul waste 

to different landfills in different years, 

so that the population served by a 

landfill can be variable. Several 

commenters noted that the data needed 

to estimate waste disposal rates for past 

years was especially challenging for 

closed landfills and requested guidance 

on how to comply with the rule if the 

necessary data do not exist. 

Response: EPA acknowledges that the 

single proposed method of estimating 

past year disposal rates is limiting and 

may not provide the most accurate 

projection of waste disposal rates in all 

cases. We have provided a number of 

alternative approaches that could be 

used to estimate annual waste 

acceptance rates. These include using 

the current year’s annual waste 

acceptance rate for all past years of 

operation (for active landfills) and using 

the landfill capacity and the operating 

life of the landfill to calculate an 

average annual acceptance rate (for 

active and closed landfills). These 

methods provide a reasonable estimate 

of historic disposal quantities based on 

readily available information, even for 

older landfills. Furthermore, these 

alternative methods may be just as 

appropriate or more appropriate for 

MSW landfills that do not serve a fixed 

population area. 

Comment: A few commenters noted 

that the Solid Waste Industry for 

Climate Solution (SWICS) has 

developed protocols for calculating 

GHG emissions from landfills [see paper 

titled, Current MSW Industry Position 

and State-of-the-Practice on LFG 

Collection Efficiency, Methane 

Oxidation, and Carbon Sequestration in 

Landfills (July 2007)]. The commenters 

requested that the SWICS recommended 

defaults for gas recovery system 

efficiency, soil oxidation, and flare 

combustion efficiency be provided in 

the rule. They also stated that an 

accurate inventory should account for 

carbon sequestered in the landfill. 

Response: We again reviewed the 

SWICS methods in light of these 

comments. We agree that the SWICS 

default recommendations for gas 

recovery system efficiency (which vary 

from 60 to 95 percent for different types 

of soil covers) could provide more 

refined data than using the default 

values provided in the rule. Therefore, 

we have included these cover-specific 

gas recovery efficiencies (commensurate 

with the SWICS Protocol) as an 

alternative to the 75 percent default 

value for collection efficiency. We have 

also reviewed the SWICS protocol for 

soil oxidation, which provides 

suggested oxidation factors ranging from 

0.22 to 0.55 depending on the soil cover 

type. We have several concerns with 

these factors. First, the values were 

calculated using arithmetic means 

which appear to be biased high due to 

a few high oxidation factors; the median 

values were generally significantly 

lower than the average values suggested. 

Second, the recommended values 

included laboratory test values, which 

always yielded higher oxidation 

fractions. The percent of methane 

oxidized at the landfill surface is highly 

dependent on the velocity of gas flow. 

While areas of low flow are expected to 

have significant oxidation, areas of high 

flow will have little to no oxidation. 

Landfill gas will generally flow to the 

surface in fissures and channels that 

offer the least resistance to flow. 

Consequently, a significant portion of 

the landfill gas is likely to exit the 

landfill in a limited number of areas 

under much higher flow rates than other 

locations. These high volume flows will 

not have significant oxidation. 

Consequently, field test data tend to 

show lower oxidation factors than 

laboratory tests where flow is more 

uniform. Data for five field studies for 

clay covers (the predominant soil cover 

type used in the U.S.) were included in 

the SWICS report. Four of the five field 

studies had oxidation factors ranging 

from 0.08 to 0.21, and the median of all 

five field studies was 0.14. These data 

appear to support the default 0.10 

oxidation factor as provided in the final 

rule more than they do the 0.22 

oxidation factor suggested by SWICS. 

We will continue to assess the available 

data to improve soil oxidation estimates; 

however, we maintain that the use of 

the 10 percent default rate is 

appropriate for this final rule, and 

clarify that the site-specific oxidation 

factors (based on the SWICS method or 

other method) are not to be used. We 

also find that the SWICS Protocol 

recommended flare efficiency of 99.996 

percent appears unreasonably high. The 

combustion efficiency of flares is very 

difficult to assess and may be affected 

by wind speed and other variables that 

are not under the direct control of the 

landfill owner and operator. 

Consequently, we retained the proposed 

flare efficiency default. Finally, with 

respect to the suggested sequestration 

factors, since collecting data on carbon 

sequestration is not the purpose of this 

rule, we do not require facilities to 

calculate or report carbon storage in 

landfills. 

Monitoring and QA/QC Requirements 

Comment: Several commenters stated 

that EPA’s proposal to require landfills 

with gas collection systems to 

continuously measure the methane flow 

and concentration at the flare or energy 

device is financially burdensome. 

According to commenters, the capital 

costs as well as operation and 

maintenance costs of a continuous 

composition analyzer are prohibitive for 

many facilities, and EPA 

underestimated the number of facilities 

that would have to install the required 

monitors. The commenters also stated 

that the composition of landfill gas is 

not highly variable, so less frequent 

monitoring is justified. One commenter 

noted that the standard operating 

procedure at many landfills with gas 

collection systems is to collect monthly 

CH4, flow, and concentration data at the 

flare. Another commenter recommended 

that MSW landfills be allowed to 

calculate quarterly, by means of 

engineering formulae and/or modeling, 

the amount of methane present at the 

flare or energy device. The commenter 

further noted that, in many cases, it is 

not practical or even possible for the 

MSW facility to measure the amount of 

methane or even landfill gas at the 

energy device because this device is not 

owned, operated, or controlled by the 

facility. Several commenters also 

requested that EPA allow direct flame 

ionization analyzers in addition to the 

gas chromatography methods provided 

in the proposed rule. 

On the other hand, several 

commenters suggested that EPA should 

allow, require, or otherwise move 

towards direct measurement 

methodologies for characterizing 

landfill emissions. 

Response: Methane composition of 

landfill gas can be expected to vary 


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based on extreme barometric changes, 

rainfall event, etc. We expect diurnal 

variations as well (although not to the 

same extent as seasonal variations). We 

also expect variations if the gas 

collection system has a variable speed 

fan and the fan speed is adjusted. The 

commenters provided no data to 

support the claim that the anticipated 

fluctuations are not significant enough 

to warrant continuous monitoring. At 

proposal, we required continuous flow 

and composition monitors to improve 

the accuracy of the emissions estimate. 

However, after additional uncertainty 

analysis, we determined that the cost of 

continuous monitoring systems is not 

justified in relation to the relatively 

small improvement in certainty over 

somewhat less frequent monitoring, i.e. 

weekly. We do require landfill gas 

collection systems already equipped 

with continuous monitoring systems to 

determine daily average flow and 

concentrations and to use these data in 

their gas recovery calculations. For 

collection systems that do not have 

continuous gas monitors, weekly 

sampling is required. Weekly 

monitoring provides an adequate 

number of samples to evaluate the 

variability and uncertainty associated 

with methane generation. We did not 

select monthly monitoring because 

monthly monitoring would result in 

greater uncertainty and would not 

significantly reduce the costs compared 

to weekly monitoring. 

We did provide for direct flame 

ionization analyzers to be used as an 

alternative to the gas chromatography 

methods provided in the proposed rule. 

This alternative reduces the burden on 

landfills that do not have existing gas 

chromatography equipment. However, 

direct flame ionization analyzers will 

measure both methane and nonmethane organic compounds and, as 

such, will tend to overstate the methane 

concentration in the landfill gas and 

provide a high bias to the amount of 

methane recovered. To eliminate this 

bias, we also required a correction factor 

that must be determined at least 

annually, to arrive at the ratio of the 

methane concentration to the direct 

flame ionization analyzer response 

(calibrated with methane). Including 

this alternative method with the 

correction factor reduces the burden on 

landfills, but still ensures that the 

calculated methane recovery quantities 

are unbiased and comparable to the 

recovery quantities calculated when gas 

chromatographic methods are used to 

speciate methane specifically. 

With respect to direct measurement 

methods, we find that direct soil 

measurements have high uncertainties 

due to heterogeneity of the landfill and 

cover soils and are, therefore, less 

desirable than the methods provided in 

the rule (cost more and have higher 

uncertainty). Optical sensing methods, 

while potentially more accurate, are 

very expensive. If measurements were 

done for only a one-time performance 

test, the measured emissions would 

have rather high uncertainties due to 

variations in temperature and 

atmospheric pressure. If the 

measurements were conducted more 

often, they would be prohibitively 

expensive. At this time, we cannot 

justify requiring these types of 

monitoring systems for this rule. 

Furthermore, we find that the 

monitoring requirements in the final 

rule provide for accurate emission 

estimates at a reasonable cost burden to 

reporters. 

II. Wastewater Treatment 

At this time, EPA is not going final 

with the wastewater treatment subpart 

(40 CFR part 98, subpart II). As EPA 

considers next steps, we will be 

reviewing the public comments and 

other relevant information. Please note, 

as originally proposed for this rule, 

centralized domestic wastewater 

treatment plants continue to be 

excluded. 

The Agency received a number of 

comments regarding the applicability of 

this subpart as well as clarification of 

the definition of anaerobic wastewater 

treatment processes. In addition, 

commenters requested that EPA 

consider a de minimus exemption for 

emissions from wastewater treatment. 

The Agency also received a number of 

comments requesting redefinition of the 

monitoring requirements for this 

subpart. 

Based on careful review of comments 

received on the preamble, rule and 

TSDs under proposed 40 CFR part 98, 

subpart II, EPA will consider 

alternatives to data collection 

procedures and methodologies and 

examine additional study results that 

have been released since the proposal 

was issued. Specifically, EPA will 

consider requirements for the location 

of meters for taking flow measurements, 

the frequency of flow and chemical 

oxygen demand (COD) measurements 

taken, as well as the potential use of 

alternate parameters, such as BOD. EPA 

will also consider the inclusion of 

indirect or non-methane volatile organic 

compound emissions. Lastly, EPA will 

consider the acceptable methods for 

estimating missing data. EPA will 

consider optimal methods of data 

collection in order to maximize data 

accuracy, while considering industry 

burden. 

JJ. Manure Management 

1. Summary of the Final Rule 

Source Category Definition. A 

livestock facility that emits 25,000 

metric tons CO2e or more per year from 

manure management systems must 

report. A facility with an average annual 

animal population below those listed in 

Table JJ–1 of 40 CFR part 98, subpart JJ, 

does not need to calculate emissions or 

report. A facility with an average annual 

animal population that exceeds those 

listed in Table JJ–1 should conduct a 

more thorough analysis to determine 

applicability. Average annual animal 

populations for static populations (e.g., 

dairy cows, breeding swine, layers) are 

estimated by performing an animal 

inventory or review of facility records. 

Average annual animal populations for 

growing populations (meat animals such 

as beef and veal cattle, market swine, 

broilers, and turkeys) are estimated 

using the average number of days each 

animal is kept at the facility and the 

number of animals produced annually. 

The rule also contains procedures for 

facilities with more than one animal 

group present (e.g., swine and poultry) 

to determine if they must report. 

A manure management system 

stabilizes or stores livestock manure, or 

does both, in one or more of the 

following system components: 

• Uncovered anaerobic lagoons. 

• Liquid/slurry systems with and 

without crust covers (including but not 

limited to ponds and tanks). 

• Storage pits. 

• Digesters, including covered 

anaerobic lagoons. 

• Solid manure storage. 

• Drylots, including feedlots. 

• High-rise houses for poultry 

production (poultry without litter). 

• Poultry production with litter. 

• Deep bedding systems for cattle and 

swine. 

• Manure composting. 

• Aerobic treatment. 

GHG emissions from sources at 

livestock facilities unrelated to the 

stabilization and/or storage of manure 

are not covered under this rule and are 

not reported. Sources considered to be 

unrelated to the stabilization and/or 

storage of manure include daily spread 

or pasture/range/paddock systems or 

land application activities or other 

methods of manure utilization not listed 

above. In addition, manure management 

activities located off site from a 

livestock operation are not included in 

this rule. These off site activities 

include but are not limited to off site 


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land application of manure, other off 

site methods of manure utilization, or 

off site manure composting operations. 

Facilities that meet the applicability 

criteria in the General Provisions (40 

CFR 98.2) summarized in Section II.A of 

this preamble must report GHG 

emissions. 

GHGs to Report. For all livestock 

facilities with a manure management 

system that meets or exceeds the 

reporting threshold, the facility must 

report aggregate CH4 and N2O emissions 

from the system components listed 

above. For those manure management 

systems that include digesters, CH4

generated and destroyed, as well as any 

CH4 leakage, at the digester must also be 

reported. 

A facility that is subject to this rule 

only because of emissions from manure 

management systems is not required to 

report emissions under 40 CFR part 98 

subparts C through PP other than 

subpart JJ. 

GHG Emissions Calculation and 

Monitoring. Detailed methods for 

calculating GHG emissions are included 

in the rule and are briefly described 

below. For each manure management 

system component other than digesters, 

facilities must calculate emissions using 

the following inputs and data: 

• Type of system component. 

• Average annual animal population 

(by animal type) contributing manure to 

the manure management system 

component. 

• Typical animal mass (for each 

animal type). 

• Fraction of manure by weight for 

each animal type managed in each 

system component (assumed to be equal 

to the fraction of volatile solids/nitrogen 

handled in each system component). 

• Volatile solids excretion rates 

provided in look-up tables for the 

animal populations contributing manure 

to the manure management system 

component. 

• Maximum CH4-producing potential 

of the managed manure and CH4

conversion factors provided in look-up 

tables for the animal populations 

contributing manure to the manure 

management system component. 

• Methane conversion factor used (for 

each manure management system 

component). 

• Nitrogen excretion rates (by animal 

type) using values provided in look-up 

tables for the animal populations 

contributing manure to the manure 

management system component. 

• N2O emission factors (by animal 

type) provided in look-up tables for the 

animal populations contributing manure 

to the manure management system 

component. 

For anaerobic digesters, facilities must 

calculate CH4 emissions and the annual 

mass of CH4 generated and destroyed 

based on the following inputs and data: 

• Continuous monitoring of CH4

concentration, flow rate, temperature, 

and pressure of the digester gas. 

• CH4 destruction efficiency of the 

destruction device and fugitive (leakage) 

emissions. 

• The CH4 collection efficiency(ies) 

used (for each digester). 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, facilities must submit 

additional data that are used to calculate 

GHG emissions. A list of the specific 

data to be reported for this source 

category is contained in 40 CFR part 98, 

subpart JJ. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, facilities must keep records of 

additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

JJ. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified below. The rationale for these 

and any other significant changes can be 

found below or in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Subpart 

JJ: Manure Management.’’ 

• To assist facilities in determining if 

they are subject to this rule, a table has 

been provided that presents average 

annual animal population values for 

specific livestock operations (i.e., beef, 

dairy, swine, and poultry). Facilities 

that have average annual animal 

population values below those shown in 

the table will not be required to report 

or complete the calculations to 

determine whether they need to report. 

• Since proposal, the requirements 

for monthly manure sampling to 

determine volatile solids (VS) and 

nitrogen (N) content have been 

removed. Instead of obtaining VS and N 

content from manure sampling, facilities 

must use default VS and N excretion 

values as provided by EPA in look up 

tables. The default VS and N excretion 

values are consistent with the 1990– 

2008 U.S. GHG inventory for manure 

management and enteric fermentation. 

For beef and dairy cows, heifers, and 

steers, VS and N excretion rates were 

calculated using the IPCC Tier II 

methodology, based on the relationship 

between animal performance 

characteristics such as diet, lactation, 

and weight gain and energy utilization. 

In response to comments, EPA used the 

most up-to-date information on U.S. 

animal diets to calculate these excretion 

rates. For other animal groups, reference 

values from ASAE and USDA are used. 

• EPA has also adjusted the 

calculations for CH4 and N2O emissions 

from manure management systems to 

account for volatile solids and nitrogen 

removal through solid separation. If 

solid separation occurs prior to the 

manure management system 

component, facilities must use default 

removal efficiencies as provided by EPA 

in look up tables. The default values are 

consistent with those cited in the 

‘‘Development Document for the Final 

Revisions to the National Pollutant 

Discharge Elimination System 

Regulation and the Effluent Guidelines 

for Concentrated Animal Feeding 

Operations’’ (EPA–821–R–03–001), 

published in December 2002. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on manure 

management were received covering 

numerous topics. Responses to 

significant comments received can be 

found in the comment response 

document for manure management in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Subpart JJ: Manure 

Management.’’ 

Comment: A number of commenters 

supported EPA’s decision to include 

livestock facilities with manure 

management systems in the proposed 

rule. These commenters noted that the 

establishment of a mandatory GHG 

reporting rule is the next logical step in 

reducing and mitigating GHG emissions 

in the U.S., and that manure 

management is a significant source of 

GHG emissions in the U.S. that should 

be addressed. 

However, other commenters stated 

that livestock facilities should not be 

required to report GHG emissions. 

These commenters noted that a small 

number of facilities would be covered 

by the proposed rule, and these facilities 

would represent a very small percentage 

of the total number of livestock facilities 

in the U.S. which would not provide a 

large enough set of data to help improve 

or reduce uncertainties associated with 

GHG inventories. Several of the 

commenters stated that manure 

management is not a major source of 

GHG emissions in the U.S., and the 

environmental benefits from the rule 


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would be minimal compared to the 

effort required to report emissions. 

Response: EPA disagrees that the 

manure management source category be 

excluded from this rule. Manure 

management has been determined to be 

a key source of GHG emissions in the 

U.S., based on the key source category 

methodology developed by the 

Intergovernmental Panel on Climate 

Change (IPCC). The IPCC identifies key 

sources as those sources that have 

significant impacts on the total 

emissions or emission trends in a 

country. 

While livestock manure GHG 

emissions represent a relatively small 

fraction of the total U.S. GHG emissions, 

these emissions are large in absolute 

terms. According to the 2009 U.S. GHG 

Inventory, CH4 emissions from manure 

management systems totaled 44 million 

metric tons CO2e, and N2O emissions 

were 14.7 million metric tons CO2e in 

2007; manure management systems 

account for 7.5 percent of total 

anthropogenic CH4 emissions and 4.7 

percent of N2O emissions in the U.S. 

In addition, the collection of facility 

level GHG emission data, including the 

type of manure management systems in 

operation and the number and types of 

animals serviced by those systems, will 

help to inform future climate change 

policy decisions. While the actual 

number of facilities reporting will be 

quite small in comparison to the total 

number of facilities in the U.S., the data 

gathered through this effort is valuable. 

For example, these data will help to 

improve the understanding of emission 

rates and actions that facilities take to 

reduce emissions and may improve the 

effectiveness and design of voluntary 

and/or mandatory programs to reduce 

emissions. 

Comment: Multiple commenters 

stated that the monitoring requirements 

in the proposed rule would be too 

burdensome and expensive for industry 

to comply with. These commenters 

expressed concern that sampling 

manure for VS and N would require 

more time and effort and be more 

expensive than EPA estimated. Multiple 

commenters suggested that default 

values such as from the American 

Society of Agricultural and Biological 

Engineers (ASABE) be permitted for VS 

and N instead of measured values to 

eliminate some of the expense 

associated with the proposed rule. 

In addition, a number of commenters 

noted that there were some 

methodological issues associated with 

the monitoring requirements for VS and 

N. Multiple commenters noted that the 

requirements for manure sampling 

should be clarified. 

Response: EPA acknowledges these 

concerns and has removed the manure 

sampling requirements from the final 

rule. As discussed earlier, EPA used 

default values for VS and N excretion 

from USDA and ASAE for swine and 

poultry, and has calculated these rates 

for beef and dairy cows, heifers, and 

steers using the IPCC Tier II 

methodology, based on the relationship 

between animal performance 

characteristics such as diet, lactation, 

and weight gain and energy utilization. 

The use of these animal-specific default 

values for VS and N will greatly reduce 

the burden to comply with the reporting 

rule, while only minimally impacting 

the estimates of GHG emissions. The 

variation in sampling techniques from 

facility to facility when characterizing 

manure ‘‘as excreted’’ from the various 

animal populations on the facility (as 

would have been required by the 

proposal) would negate the benefit 

derived from this requirement. EPA 

considered designing a more complex 

and rigorous program to ensure 

consistency in the implementation of a 

manure sampling program and to ensure 

that manure samples represented ‘‘as 

excreted’’ manure (prior to any storage 

or treatment). However, after reviewing 

comments, we determined that the 

expected burden of such a program, in 

terms of time, effort, and expense, 

outweighed the merits at this time. 

Comment: A number of commenters 

noted that calculation errors caused 

threshold head numbers to be 

overestimated, which caused the 

amount of emissions from these 

operations and the number of operations 

that would need to report to be 

underestimated. 

Response: To estimate the number of 

facilities at each threshold, EPA first 

developed a number of model facilities 

to represent the manure management 

systems that are most common on large 

livestock operations and have the 

greatest potential to exceed the GHG 

reporting threshold. Next, EPA used the 

U.S. GHG inventory methodology for 

manure management to estimate the 

numbers of livestock that would need to 

be present to exceed the threshold for 

each model livestock operation type. 

Finally, EPA combined the numbers of 

livestock required on each model 

operation to meet the thresholds with 

U.S. Department of Agriculture (USDA) 

data on farm sizes to determine how 

many farms in the United States have 

the livestock populations required to 

meet the GHG thresholds for each model 

livestock operation. 

Since proposal, EPA made revisions 

to the threshold analysis spreadsheet 

calculations based on information and 

data provided by commenters. EPA 

corrected conversion factors used in the 

nitrous oxide emission calculations, and 

corrected spreadsheet cell reference 

errors along with using updated VS and 

N values. EPA now estimates that there 

will be approximately 107 livestock 

facilities that will need to report under 

the rule. 

Comment: Commenters also 

expressed concerns with the emission 

calculations. Multiple commenters 

noted that the maximum methane 

producing capacity (Bo) values used do 

not reflect variations in animal diet. 

Several commenters had concerns about 

the methodology used to estimate the 

methane conversion factors. In addition, 

some commenters suggested that other 

data sources should be considered, such 

as the ASABE manure standards. 

Response: After a thorough review of 

available information, EPA has 

determined that the methodologies and 

data sources used to calculate emissions 

in this rule represent the best available 

methods and data. EPA reviewed many 

protocols and approaches prior to 

selecting the proposed methodology. 

EPA’s selected methodology for 

reporting GHG emissions (methane and 

nitrous oxide) associated with manure 

management systems is based on EPA’s 

Inventory of U.S. Greenhouse Gas 

Emissions and Sinks, as well as the 

IPCC Guidelines for National 

Greenhouse Gas Inventories. These 

methodologies rely on the use of activity 

data, such as the number of head of 

livestock, operational characteristics 

(e.g., physical and chemical 

characteristics of the manure, type of 

management system(s)), and climate 

data, to calculate GHG emissions 

associated with traditional manure 

management systems. In addition, the 

selected methodology for the reporting 

rule uses measured values for those 

manure management systems (e.g., 

anaerobic digesters) that collect and 

combust biogas. 

EPA considered requiring direct 

measurement of GHG emissions from 

manure management systems, but 

rejected this approach due to the 

extreme expense and complexity of 

such a measurement program. EPA is 

promulgating an approach that allows 

the use of default factors, such as a 

system emission factor, for certain 

elements of the calculation, and 

encourages the use of some site-specific 

data. The cost of such an approach is 

significantly lower than a direct 

measurement program. In addition, this 

approach is consistent with the methods 

used in offset programs throughout the 

world, including the California Climate 

Action Registry’s (CCAR) Manure 


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Management Project Reporting Protocol. 

For these offset programs, livestock 

operations are required to complete 

calculations that establish their 

‘‘baseline’’ emissions (prior to the use of 

a biogas collection system). These 

baseline emission calculations use 

similar emissions calculations and 

default values as are in EPA’s Reporting 

Rule. 

The IPCC guidelines have been 

established by a recognized panel of 

experts and underwent significant peer 

review prior to their adoption. In 

addition, protocols for offset programs, 

such as CCAR, have gone through 

similar public review processes prior to 

their acceptance and use. 

Comment: Multiple commenters have 

requested more detailed look up tables 

and a tool to provide more clarity on 

which facilities are required to report 

under the final rule. 

Response: EPA agrees that additional 

tables and tools would facilitate 

compliance with the rule and ease the 

burden associated with reporting. In 

response to the comments, EPA has 

added a threshold table to the final rule 

(Table JJ–1) to help livestock facilities 

with manure management systems 

better determine if they might be subject 

to the requirements of the rule. EPA also 

intends to develop applicability tools 

that can assist facilities that could be 

covered by the rule, based on table JJ– 

1 in 450 CFR part 98, subpart JJ, in 

conducting a more detailed evaluation. 

These tools will include detailed lookup tables showing the estimated 

livestock head numbers that would be 

necessary in order to meet or exceed the 

threshold and a calculation tool to assist 

in performing the calculations in the 

proposed rule. 

KK. Suppliers of Coal 

At this time, EPA is not going final 

with a subpart for suppliers of coal. As 

EPA considers next steps, we will be 

reviewing the public comments and 

other relevant information. 

The Agency received a number of 

lengthy, detailed comments regarding 

the coal suppliers subpart. Commenters 

generally opposed the proposed 

reporting requirements and raised 

multiple issues with EPA’s legal 

authority for requiring coal suppliers to 

report CO2 emissions. Several 

commenters stated that reporting by 

coal suppliers would represent a 

duplication of the reporting by coal 

users. For example, electric utilities and 

industrial plants, which consume the 

vast majority of coal supplied, are 

already required to report data on 

emissions based on their coal purchases. 

Commenters also stated that the 

reporting requirement would entail 

significant burden and capital costs to 

coal suppliers. In most cases, 

commenters provided alternative 

approaches to the reporting 

requirements proposed by EPA. For 

example, commenters suggested that 

EPA exempt from reporting coal mines 

that supply coal to mine-mouth power 

plants, modify the required coal 

weighing and sampling standards, and 

eliminate the required statistical 

correlation between HHV and carbon 

content. 

Commenters raised other issues 

regarding the reporting of data such as 

concerns that coal suppliers and 

laboratories could not realistically 

purchase and install new coal testing 

and sampling equipment and provide 

training to meet the requirements of the 

proposed rule. 

Based on careful review of comments 

received on the preamble, rule and 

TSDs under proposed 40 CFR part 98, 

subpart KK, EPA will perform 

additional analysis and consider 

alternatives to data collection 

procedures and methodologies. These 

alternatives will provide coverage of 

coal supplied, imported, or exported 

while concurrently taking into account 

industry burden. 

LL. Suppliers of Coal-Based Liquid Fuels 

1. Summary of the Final Rule 

Source Category Definition. This 

source category consists of producers, 

importers, and exporters of products 

listed in Table MM–1 of 40 CFR part 98, 

subpart MM that are coal-based (coal-toliquid products). A producer of coal-toliquid products is any owner or operator 

who converts coal into liquid products 

(e.g., gasoline, diesel) using the FischerTropsch or an alternative process. 

Suppliers of coal-to-liquid products 

that meet the applicability criteria in the 

General Provisions (40 CFR 98.2) 

summarized in Section II.A of this 

preamble must report GHG emissions. 

GHGs to Report. Suppliers of coal-toliquid products must report the CO2

emissions that would result from the 

complete combustion or oxidation of the 

coal-to-liquid products. 

Suppliers of coal-to-liquid products 

are not required to report data on 

emissions of other GHGs that would 

result from the complete combustion or 

oxidation of their products, such as CH4

or N2O. 

GHG Emissions Calculation and 

Monitoring. For each type of coal-toliquid product, suppliers must calculate 

CO2 emissions that would result from 

the complete combustion or oxidation of 

the coal-to-liquid products by following 

the procedures in 40 CFR 98.393. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

GHG emissions that would result from 

the complete combustion or oxidation of 

their products. A list of the specific data 

to be reported for this source category is 

contained in 40 CFR 98.386. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions that would result from the 

complete combustion or oxidation of 

their products. A list of specific records 

that must be retained for this source 

category is included in 40 CFR 98.387. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below. 

• We replaced the procedures and 

calculations proposed in 40 CFR part 

98, subpart LL with references to the 40 

CFR part 98, subpart MM procedures 

and calculations. As a result of 

considerable comment and EPA 

analysis, 40 CFR part 98, subpart MM 

procedures and calculations were 

significantly updated. Since the 

procedures and calculations necessary 

for sampling, testing, and measuring 

coal-to-liquid products are intrinsically 

linked to the procedures and 

calculations used for petroleum 

products, we concluded that referencing 

40 CFR part 98, subpart MM in 40 CFR 

part 98, subpart LL would achieve 

consistency and completeness. 

• We reorganized and updated 40 

CFR 98.386 by mirroring 40 CFR 98.396 

in order to reflect the updates we made 

to procedures and calculations and to 

assist in EPA data verification. 

3. Summary of Comments and 

Responses 

EPA did not receive any specific 

comments on proposed 40 CFR part 98, 

subpart LL (suppliers of coal-based 

liquid fuels). Changes made to this 

subpart were implemented to ensure 

consistency with changes made to 40 

CFR part 98, subpart MM based on 

public comments provided and EPA 

analysis conducted. 


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MM. Suppliers of Petroleum Products 

1. Summary of the Final Rule 

Source Category Definition. Suppliers 

of petroleum products consist of: 

• Petroleum refineries that produce 

petroleum products through distillation 

of crude oil. 

• Importers who satisfy the same 

meaning given in 40 CFR 98.6, 

including any entity that imports 

petroleum products or NGLs as listed in 

Table MM–1 of 40 CFR part 98, subpart 

MM. Any blender or refiner of refined 

or semi-refined petroleum products 

shall be considered an importer if it 

otherwise satisfies the aforementioned 

definition. 

• Exporters who satisfy the same 

meaning given in 40 CFR 98.6, 

including any entity that exports 

petroleum products or NGLs as listed in 

Table MM–1 of 40 CFR part 98, subpart 

MM. Any blender or refiner of refined 

or semi-refined petroleum products 

shall be considered an exporter if it 

otherwise satisfies the aforementioned 

definition. 

Suppliers of petroleum products that 

meet the applicability criteria in the 

General Provisions (40 CFR 98.2) 

summarized in Section II.A of this 

preamble must report GHG emissions 

that would result from the complete 

combustion or oxidation of the 

product(s) they supply. 

GHGs to Report. Suppliers of 

petroleum products must report 

annually: 

• CO2 emissions that would result 

from the complete combustion or 

oxidation of each petroleum product 

and natural gas liquid produced, used as 

feedstock, imported, or exported during 

the calendar year. 

• CO2 emissions that would result 

from the complete combustion or 

oxidation of any biomass co-processed 

with petroleum feedstocks at a refinery. 

Suppliers of petroleum products are 

not required to report data on emissions 

of other GHGs that would result from 

the complete combustion or oxidation of 

their products, such as CH4 or N20. 

GHG Emissions Calculation and 

Monitoring. Suppliers of petroleum 

products must choose one of two 

methods to calculate CO2 emissions that 

would result from the combustion or 

oxidation of each petroleum product 

and natural gas liquid: 

• Method 1: Use the default CO2

emission factors provided in the 

regulations for a given petroleum 

product or NGL; or 

• Method 2: Develop an emission 

factor for a given petroleum product or 

natural gas liquid using direct 

measurements of density and carbon 

share. 

To calculate CO2 emissions that 

would result from the combustion or 

oxidation of biomass co-processed with 

petroleum feedstock, reporters must use 

a CO2 emission factor that is provided 

in the regulations for each type of 

biomass. 

In calculating total CO2 emissions that 

would result from the combustion or 

oxidation of all petroleum products and 

natural gas liquids that leave the 

refinery, refineries must subtract the 

emissions from petroleum products and 

natural gas liquids that enter the 

refinery to be further refined or used on 

site as well as biomass and biomassbased fuels that are co-processed or 

blended with petroleum feedstocks. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data used to calculate GHG 

emissions that would result from the 

complete combustion or oxidation of the 

product(s) supplied as well as 

information on the characteristics of 

crude oil used at a refinery. The specific 

list of data to be reported for this source 

category is contained in 40 CFR part 

98.396 and includes information to 

support the data verification process. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to determine the 

quantities and characteristics of 

product(s) reported under this subpart 

and to calculate GHG emissions that 

would result from the complete 

combustion or oxidation of the 

product(s) supplied. A list of specific 

records that must be retained for this 

source category is included in 40 CFR 

part 98.387. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart MM: 

Suppliers of Petroleum Products.’’ 

• We established a reporting 

threshold for importers and exporters of 

25,000 metric tons of CO2 per year. 

• We changed the source category 

definition of petroleum refinery for the 

purposes of 40 CFR part 98, subpart MM 

to only include facilities that process 

crude oil. As such, we are not requiring 

reporting from facilities that only 

handle intermediary petroleum 

products. 

• We refined the definition of 

importers and exporters of petroleum 

products to clarify reporting 

requirements for blenders. 

• We are not requiring reporters to 

rely on an exclusive list of standard 

methods for the measurement of the 

quantity of products or the calibration 

and recalibration of equipment. Instead, 

reporters must use an appropriate 

standard method published by a 

consensus-based standards organization. 

If no such standard exists, reporters are 

allowed to rely on industry standard 

practices. 

• We provide more flexibility in the 

frequency of equipment recalibration. 

Reporters must now comply with the 

frequency specified by the 

manufacturer’s directions or the 

selected quantity measurement method. 

• We removed the option for 

reporters to directly measure density but 

not carbon share under Calculation 

Method 2. We determined that using a 

measured density and a default carbon 

share factor will likely adversely affect 

the accuracy of the calculated emission 

factor since the density and carbon 

share of hydrocarbons are, in the 

absence of impurities, correlated. 

• We are not requiring reporters to 

rely on an exclusive list of standard 

methods for sampling products, 

measuring density, and measuring 

carbon share under Calculation Method 

2. Instead, reporters must use an 

appropriate standard method published 

by a consensus-based standards 

organization. 

• We added more specific 

requirements for the frequency of 

sampling under Calculation Method 2 

and now allow for mathematical 

composites of samples in addition to 

physical composites of samples. 

• To ensure consistent accounting of 

denaturant across reporters, we are 

requiring reporters to assume that 2.5 

percent of the volume of any ethanol 

product that is blended into a 

petroleum-based product is a 

petroleum-based denaturant. See below 

for further explanation. 

• For bulk NGLs, reporters must 

calculate the emissions that would 

result from the complete combustion or 

oxidation of the individual components 

that constitute the NGL (i.e., ethane, 

propane, butane, isobutane, and 

pentanes plus). 

• We updated the definition of 

petroleum products to be clear that no 

petroleum product supplier must report 

on plastics and plastic products and that 


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importers and exporters must report on 

asphalt, road oil, and lubricants. 

• We updated the default emissions 

factors based on technical research since 

the proposal. We updated certain factors 

to correct technical errors and to reflect 

more recent data. We expanded the 

factors to four significant digits to 

enhance precision. We also added 

grade-based sub-categories of finished 

motor gasoline and blendstocks, 

combined diesel and fuel oil categories 

into ‘‘distillate fuel’’ categories, and 

added sulfur-based subcategories of 

distillate fuel No. 1 and 2 to better 

distinguish between product categories 

with potentially different carbon 

contents. Full documentation of default 

emissions factors can be found in the 

TSD. 

• We updated 40 CFR 98.396. First, 

we made 40 CFR 98.396 more specific, 

in some cases breaking up one reporting 

requirement into two for clarity. 

Second, to allow for EPA verification of 

reporter calculations, we added 

reporting requirements for data that a 

reporter must already use to calculate 

GHGs as specified in 40 CFR 98.393 

through 98.396. Third, after removing 

the prescriptive list of allowable 

methods, we added data reporting 

requirements on the method selected to 

measure quantity, density, and carbon 

content and the method selected to 

sample in order to track the 

appropriateness of these methods. 

We require reporters to assume that 

ethanol contains 2.5 percent petroleumbased denaturant because we want to 

ensure that reporters account for the 

CO2 emissions that would result from 

the combustion or oxidation of the 

denaturant. All ethanol that is blended 

with petroleum products reported in 40 

CFR part 98, subpart MM should 

contain more than 1.96 percent 

petroleum-based denaturant by volume, 

per the requirements in 27 CFR Parts 20 

and 21 to make ethanol non-potable. We 

considered relying on reporters to 

estimate the percent volume of 

denaturant in their products, but we 

determined that, in many cases, 

reporters would not know this 

information. We have concluded that 

2.5 percent is a suitable assumption for 

the level of denaturant since, according 

to an Internal Revenue Service 

interpretation of Section 15332 in the 

Food, Conservation, and Energy Act of 

2008 in notice 2009–06, ethanol 

containing greater than 2.5 percent 

denaturant by volume would not be 

eligible for the full value of the 

Volumetric Ethanol Excise Tax Credit. 

There may be cases where ethanol 

containing less than 2.5 percent 

denaturant is blended with petroleumbased products, but we concluded that 

it is better to conservatively account for 

potential petroleum-based carbon 

emissions rather than arbitrarily pick a 

number between 1.96 percent and 2.5 

percent. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on suppliers 

of petroleum products were received 

covering numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart MM: 

Suppliers of Petroleum Products.’’ 

Selection of Threshold 

Comment: In the proposed rule, EPA 

sought comment on whether or not to 

establish a de minimis level of imported 

and exported petroleum products, either 

in terms of the quantity of products or 

the CO2 emissions associated with the 

combustion or oxidation of products, to 

eliminate any reporting burden for 

parties that may import or export a 

small amount of petroleum products on 

an annual basis. In response, EPA 

received several comments in support of 

establishing some type of de minimis 

value, including a threshold of 25,000 

metric tons of CO2 from the complete 

combustion or oxidation of all products 

from individual importers and 

exporters. EPA also received at least one 

comment in support of establishing a 

threshold value for refineries reporting 

under 40 CFR part 98, subpart MM. 

Response: In today’s rule, we are 

establishing a threshold of 25,000 metric 

tons of CO2 per year for importers and 

exporters of petroleum products and 

natural gas liquids; the threshold is 

based on a calculation of CO2 emissions 

that would result from complete 

combustion or oxidation of the imported 

or exported petroleum products and 

natural gas liquids. 

When we conducted the threshold 

analysis for the proposed rule, we 

estimated from EIA data that 224 

companies would be covered in 40 CFR 

part 98, MM as importers. Through this 

analysis, we found that at a threshold of 

25,000 metric tons CO2 per year, 175 

importers and 99.9 percent of total 

emissions that would result from the 

combustion or oxidation of imported 

products would be covered by the 

proposed rule. Therefore, establishing a 

25,000 metric ton CO2 threshold would 

drop 49 reporters in exchange for a 0.1 

percent drop in total emissions. 

Nonetheless, we decided to propose 

reporting for all importers because we 

felt the reporting burden would be 

minimal since importers already report 

the product quantity data to other 

Federal agencies. 

Since proposing the rule, EPA has 

learned new information, through 

comments and research, about importers 

that could be covered as reporters under 

40 CFR part 98, Subpart MM. EPA may 

have omitted some importers of small 

volumes of petroleum products or 

natural gas liquids from our original 

threshold analysis, due to lack of public 

data. We never intended to cover such 

small volume imports with this rule 

(e.g., importers of non-fossil fuel 

products that contain small quantities of 

petroleum or natural gas liquids, such as 

butane lighters). Therefore, for the final 

rule, EPA concludes that establishing a 

25,000 metric ton CO2 threshold for 

importers will relieve burden on 

importers of insignificant quantities of 

petroleum products and natural gas 

liquids that we never intended to cover 

with this rule without significantly 

diminishing the amount of information 

received by the agency. In addition, a 

25,000 metric ton CO2 threshold is 

consistent with other upstream fuel and 

industrial gas supplier thresholds for 

importers and exporters in today’s rule. 

When we conducted the threshold 

analysis for the proposed rule, we could 

not estimate the number of exporting 

companies that would be covered in 40 

CFR part 98, subpart MM because the 

necessary data was not publically 

available. Nonetheless, we decided to 

propose reporting for all exporters 

because we concluded that the reporting 

burden would be minimal given the 

type of information that exporters must 

maintain as part of their normal 

business operations. 

Since proposing the rule, based on 

analogous information learned on 

importers, EPA has concluded that some 

exporters of very small volumes of 

petroleum products or natural gas 

liquids could be covered as reporters 

under 40 CFR part 98, subpart MM. We 

never intended to cover such small 

volume exporters with this rule (e.g., 

exporters of non-fossil fuel products 

that contain small quantities of 

petroleum or natural gas liquids, such as 

butane lighters). Therefore, for the final 

rule, EPA has concluded that 

establishing a threshold for exporters 

will relieve burden on exporters of 

insignificant quantities of petroleum 

products and natural gas liquids that we 

never intended to cover with this rule. 

In today’s rule, we have selected a 

25,000 metric ton CO2 threshold 

because we conclude that it will not 

significantly diminish the amount of 

information received by the agency; 


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overall, exports of refined and semirefined products are lower than imports, 

so the threshold adopted for imports 

will be adequate for collecting data on 

exports. In addition, a 25,000 metric ton 

CO2 threshold is consistent with other 

upstream fuel and industrial gas 

supplier thresholds for importers and 

exporters in today’s rule. 

In today’s rulemaking, we require all 

refineries as defined in 40 CFR part 98, 

subpart MM to report, as was proposed. 

Our threshold analysis of refineries in 

the proposed rule indicated that all 

refineries would be covered even if we 

were to establish a 100,000 metric ton 

CO2 threshold. Furthermore, we have 

determined that all refineries covered by 

this subpart are already tracking the 

necessary data to comply with the 

reporting requirements so the 

requirements would not pose an undue 

burden. 

Monitoring and QA/QC Requirements 

Comment: EPA received several 

comments that the proposed approach 

to determining product quantity was too 

prescriptive. These comments indicated 

that the list of allowable methods and 

equipment types for determining the 

quantity of products in the proposed 

rule was incomplete, would result in 

significant costs for industry, and could 

adversely impact the quality of the 

measurements. Commenters noted that 

industry uses a much larger and evergrowing number of industry methods 

and equipment types to determine 

quantity for purposes of product 

transfers and financial records, 

including methods and equipment types 

used to comply with Internal Revenue 

Service, Securities and Exchange 

Commission, and Department of 

Homeland Security’s Bureau of U.S. 

Customs & Border Protection 

regulations. Commenters suggested that 

EPA’s ability to develop and maintain a 

comprehensive list of methods would 

require considerable resources, since 

companies and consensus-based 

standards organizations review quantity 

measurement methods regularly to 

ensure consistency with technological 

changes and advancements. 

Commenters also suggested that 

methods may improve over time for 

certain products as a direct result of this 

rulemaking. 

Response: In today’s rule, we are 

addressing these concerns by adopting 

an approach that recognizes the 

multitude of appropriate industry 

standard methods and practices and 

leaves open the possibility that industry 

may adopt better methods, equipment, 

and practices over time to determine 

quantities of products. EPA is requiring 

that petroleum product suppliers use an 

appropriate standard method developed 

by a consensus-based standards 

organization, when such a standard 

method exists. If no such standard 

method exists, reporters are allowed to 

follow industry standard practices. 

Consensus-based standards 

organizations include organizations 

such as ASTM International, the 

American National Standards Institute 

(ANSI), the American Gas Association 

(AGA), the American Society of 

Mechanical Engineers (ASME), the 

American Petroleum Institute (API), and 

North American Energy Standards 

Board (NAESB). Reporters must ensure 

that all equipment used for measuring 

quantity is calibrated and periodically 

recalibrated according to the 

manufacturer’s directions or 

specifications in the appropriate 

consensus-based industry standard 

method. 

In order to further EPA’s 

understanding of the methods and 

equipment that reporters use, and to 

help us better assess the appropriateness 

of the standard methods and industry 

practices that individual reporters 

select, we are requiring that all 

petroleum product suppliers report the 

standard method or industry standard 

practice they use to measure each 

distinct product quantity that they 

report to EPA. 

Comment: Several commenters 

recommended that EPA provide more 

flexible approaches to the direct 

measurement of carbon share and 

density under Calculation Method 2. 

Some noted that the proposed 

requirement to test samples at the end 

of the year could negatively impact the 

integrity and quality of those samples. 

These commenters suggested that EPA 

allow reporters to test samples monthly 

and create a mathematical composite of 

these test results at the end of the year. 

Some commenters suggested that EPA 

develop a mechanism whereby reporters 

could reduce the frequency of sampling 

once the reporter demonstrates that the 

variability in the density and carbon 

share of the product is sufficiently 

small, and even eliminate direct 

measurement requirements and allow 

reporters to use emissions factors 

developed in previous years. We also 

received comments requesting that we 

expand our list of acceptable carbon 

share measurement methods. 

Response: We have incorporated 

several of the suggestions to increase the 

flexibility of the Calculation Method 2 

approach in today’s rule. Reporters are 

now allowed to test their monthly 

samples throughout the year and 

conduct a mathematical composite of 

the test results at the end of the year. We 

have also expanded the list of 

acceptable sampling, density, and 

carbon share methods to include any 

appropriate standard method published 

by a consensus-based standards 

organization. 

We could not determine an adequate 

approach for allowing reporters to 

reduce the sampling frequency of 

products based on statistical evidence of 

low variability in the density and 

carbon share for a given product. We 

want to capture changes in product 

characteristics over time and have 

determined that taking monthly samples 

of an entire product category would not 

be overly burdensome. Furthermore, 

reporters are allowed to use default 

factors under Calculation Method 1 if 

they so choose. 

Data Reporting Requirements 

Comment: EPA received several 

comments requesting that we eliminate 

reporting requirements related to 

products that have potentially nonemissive uses, including plastics and 

plastic products, petrochemical 

feedstocks, petroleum coke sent to 

landfill, asphalt and road oil, and 

lubricants and waxes. One commenter 

questioned the incongruity in reporting 

requirements proposed for refiners, who 

would report on all products, and 

importers and exporters who would not 

be required to report on asphalt, road 

oil, lubricants, waxes, plastics, and 

plastic products. 

Response: Today’s rule requires 

reporting on products with potentially 

non-emissive uses. Comprehensive 

upstream data will provide EPA with a 

full accounting of the emissions that 

would result from the complete 

combustion or oxidation of all 

petroleum products and natural gas 

liquids introduced into the economy. 

Furthermore, comprehensive facilitylevel data can help us conduct a more 

robust mass balance assessment for data 

verification purposes. While we 

recognize that carbon in some 

petroleum products, such as asphalt, 

can remain un-oxidized for long 

periods, petroleum product supplier 

cannot always know with certainty 

whether or not the carbon in their 

products will be released into the 

atmosphere. Even asphalt can be burned 

as fuel or incinerated as waste. In the 

Inventory of US Greenhouse Gas 

Emissions and Sinks, EPA notes several 

areas of uncertainty surrounding the fate 

of carbon in petroleum products 

including those for which the Inventory 

assumes a 100 percent storage factor for 

the purposes of the national inventory 

(e.g., asphalt roofing, asphalt cement, 


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and asphalt paving materials). As 

discussed in the proposal, a 

comprehensive and rigorous system for 

tracking the fate of petroleum products 

that may have non-emissive uses is 

beyond the scope of this rule, and 

would require a much more 

burdensome reporting obligation for 

petroleum product suppliers and other 

downstream users of petroleum 

products and natural gas liquids. The 

data reported as a result of this 

rulemaking will allow EPA to conduct 

further research in the future on the 

pathways and ultimate fate of products 

with potential non-emissive uses. 

It was never EPA’s intention to 

require reporting on plastics and plastic 

products, so we made this explicit in 

the definition of petroleum products as 

well as our definition of a refinery in 40 

CFR part 98, subpart MM, which now 

excludes any facility (e.g. a plastics 

manufacturing plant) that does not 

process crude oil. Any CO2 emissions 

that would result from the combustion 

or oxidation of plastics and plastic 

products manufactured in the U.S. 

should already be accounted for when a 

petroleum product supplier introduces 

the petrochemical feedstock (e.g., 

propylene) into the economy. 

In response to comments on the 

incongruity of the reporting burden for 

refiners compared to importers and 

exporters, we have reevaluated the list 

of petroleum products with potentially 

non-emissive uses that importers and 

exporters do not have to report. In the 

proposed rule, this list included asphalt, 

road oil, lubricants, waxes, plastics, and 

plastic products. Our rationale for 

excluding these products for importers 

and exporters was our assessment that 

there is a much larger variety of these 

products entering and leaving the 

country than is produced at a petroleum 

refinery. Upon further consideration, 

however, we have concluded that only 

waxes, plastics, and plastic products 

would pose an undue administrative 

burden on importers and exporters. 

Waxes, plastics, and plastic products 

enter and leave the country in wideranging forms (e.g., cosmetics, candles, 

lawn furniture, plastic wear) making it 

difficult to accurately assess the 

petroleum-based carbon content of these 

products. We have concluded that the 

types of asphalt, road oil, and lubricants 

imported in and exported from the 

country is much less variable, and 

importers already track these products 

and report the quantities to EIA. We 

have also established a 25,000 metric 

ton CO2 annual reporting threshold for 

importers and exporters in today’s rule, 

which should reduce the number of 

reporters and minimize the reporting of 

products that are imported or exported 

in very low quantities. Therefore, we are 

requiring importers and exporters to 

report the volume and CO2 emissions 

that would result from the complete 

combustion or oxidation of the asphalt, 

road oil, and lubricants they supply. 

In response to comments that 

collecting data on products with 

potentially non-emissive uses will 

overestimate actual emissions released 

into the atmosphere, EPA has and will 

continue to characterize CO2 emissions 

data reported under 40 CFR part 98, 

subpart MM as emissions that would 

result from the complete combustion or 

oxidation of the reported product(s) and 

not as actual emissions. 

Comment: EPA received many 

comments urging us to leverage data 

that petroleum product suppliers 

already report to the Energy Information 

Administration (EIA) and to follow 

EIA’s data collection procedures and 

protocols. For example, one commenter 

urged EPA to require refiners on a 

facility-level and company-wide basis to 

report to EPA the same level of 

information on crude imports and 

processing that is currently reported to 

the EIA and to follow a process similar 

to the one used by the EIA; and another 

commenter urged us to align our 

reporting requirements with what the 

industry is already providing to the EIA. 

Some commenters, urged EPA to make 

use of data already reported to EIA or 

other Federal agencies instead of 

requiring reporting directly to EPA 

through this rulemaking. EPA also 

received comments recommending that 

EIA reporting remain separate from the 

reporting requirements of this rule. 

Response: In the proposed 

rulemaking, EPA stated that we 

considered, but did not propose, the 

option of obtaining data by accessing 

existing Federal government reporting 

databases and we sought comment on 

this decision. 

In today’s rulemaking, we are 

requiring reporters to report data 

directly to EPA. We have determined 

that in order to collect facility-level data 

from refineries (and company-level data 

from importers and exporters) that is 

consistent with other reporters in this 

rule, in terms of timing, reporting, and 

verification procedures, we are not able 

to rely upon EIA data. In addition, EIA 

relies on a number of legal authorities 

to pledge confidentiality to statistical 

survey respondents for company-level 

information. Some data are collected 

with legal authority from the 

Confidential Information Protection and 

Statistical Efficiency Act of 2002 

(CIPSEA), under which reported 

information must be held in confidence 

and must be used for statistical 

purposes only. Collection of data 

directly by EPA in a central system will 

allow EPA to electronically verify and 

publish the data quickly, to use the 

information for non-statistical purposes, 

and to handle confidential business 

information in accordance with the 

CAA (see the general provisions 

preamble for addition discussion on 

CBI). In today’s rulemaking we did not 

replicate EIA’s reporting requirements 

and methodologies if we did not 

consider them sufficient to achieve our 

objective, which is to collect 

comprehensive and accurate data on the 

CO2 emissions that would result from 

the complete combustion or oxidation of 

petroleum products introduced into the 

economy. For example, we provide a 

comprehensive list in Tables MM–1 and 

MM–2 of 40 CFR part 98, subpart MM, 

according to which reporters must 

categorize their products for reporting 

under today’s rulemaking. This list 

differs from EIA’s list of products, 

according to which reporters must 

report to EIA. Some of the products are 

the same on both lists (e.g., aviation 

gasoline and kerosene) while some 

products are classified differently on 

one list than on the other (i.e., EPA’s list 

breaks reformulated gasoline up by 

summer and winter varieties while EIA 

breaks reformulated gasoline up by type 

of oxygenate blended into it). We crafted 

EPA’s product list carefully and we feel 

that each category has the potential to 

have a unique carbon share and/or 

density. Overall, the items on our list 

are common products in commerce and 

are already tracked by refineries, 

importers, and exporters. Therefore, we 

estimate that the additional burden to 

comply with this rule will be minimal. 

NN. Suppliers of Natural Gas and 

Natural Gas Liquids 

1. Summary of the Final Rule 

Source Category Definition. Suppliers 

of natural gas and natural gas liquids 

are: 

• NGL fractionators, which are 

installations that fractionate NGLs into 

their constituent liquid products: 

ethane, propane, normal butane, 

isobutane or pentanes plus for supply to 

downstream facilities. 

• Local natural gas distribution 

companies (LDCs) that own or operate 

distribution pipelines that deliver 

natural gas to end users. Companies that 

operate interstate pipelines transmission 

or intrastate transmission pipelines are 

not part of this source category. 

Suppliers of natural gas and NGLs 

that meet the applicability criteria in the 

General Provisions (40 CFR 98.2) 


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summarized in Section II.A of this 

preamble must report GHG emissions 

that would result from complete 

combustion or oxidation of products 

they supply. 

GHGs to Report. Natural gas 

fractionators must report CO2 emissions 

that would result from the complete 

combustion or oxidation of the annual 

quantities of propane, butane, ethane, 

isobutene, and pentanes plus supplied. 

Local distribution companies must 

report CO2 emissions that would result 

from the complete combustion or 

oxidation of the annual volume of 

natural gas distributed to their 

customers. 

Suppliers of natural gas and NGLs are 

not required to report data on emissions 

of other GHGs that would result from 

the complete combustion or oxidation of 

their products, such as CH4 or N20. 

GHG Emissions Calculation and 

Monitoring. Reporters must use one of 

two methods to calculate the CO2

emissions that would result from the 

complete combustion or oxidation of 

natural gas supply or NGL supply: 

• One method uses either a measured 

or default fuel heating value and either 

a measured or default CO2 emissions 

factor. This method is most appropriate 

for liquid fuels. 

• The second method uses either a 

measured or default CO2 emissions 

factor. This method is most appropriate 

for gaseous fuels. 

• A NGL fractionator must then 

follow two additional equations, if 

applicable, to subtract the CO2

emissions that would result from the 

complete combustion or oxidation of 

NGL supply that are double-counted. A 

LDC must then follow up to four 

additional equations, if applicable, to 

subtract the CO2 emissions that would 

result from the complete combustion or 

oxidation of natural gas supply that is 

double-counted. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

natural gas or NGL supply. A list of the 

specific data to be reported for this 

source category is contained in 40 CFR 

part 98, subpart NN. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate 

natural gas or NGL supply. A list of 

specific records that must be retained 

for this source category is included in 

40 CFR part 98, subpart NN. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart NN: 

Suppliers of Natural Gas and Natural 

Gas Liquids.’’ 

• We changed the source category 

responsible for reporting NGL supply in 

40 CFR part 98, subpart NN from all 

natural gas processors to only facilities 

that fractionate natural gas liquids. 

• We eliminated the requirement to 

report bulk NGL since NGL fractionators 

do not supply bulk NGL. 

• We added equations to calculate 

emissions that would result from the 

oxidation or combustion of the 

following volumes of natural gas and 

NGLs because they should be subtracted 

from the reporter’s total emissions 

calculation, when applicable: 

fractionated NGLs received from other 

fractionators; natural gas injected for 

storage; natural gas delivered to 

individual customers already reporting 

under another Subpart of this rule; and 

natural gas delivered by an LDC to 

another LDC. 

• We clarified the points of 

measurements for reporting purposes. 

• We changed the rule to allow local 

distribution companies to use 

transmission pipeline metered volumes 

and calculated heating value where the 

local distribution companies do not 

perform their own measurements. 

• We provide flexibility in frequency 

of equipment calibration, requiring 

reporters to comply with standard 

industry practices for measurements 

used for billing purposes as audited 

under Sarbanes Oxley regulations. 

• We added a procedure for 

measuring the carbon content of blends 

of NGLs since NGL fractionators may 

supply blends of NGLs. 

• We updated 40 CFR 98.406. First, 

we made 40 CFR 98.406 more specific, 

in some cases breaking up one reporting 

requirement into two for clarity. 

Second, to allow for EPA verification of 

reporter calculations, we added 

reporting requirements for data that a 

reporter must already use to calculate 

GHGs as specified in 40 CFR 98.403 to 

40 CFR 98.406. This includes the 

addition of reporting requirements for 

new calculations introduced in the final 

rule to prevent supply double-counting. 

Third, after removing the prescriptive 

list of allowed standards and methods, 

we added data reporting requirements 

on the method selected to measure 

quantity, HHV, and carbon content. 

Fourth, we added a reporting 

requirement for the quantity of odorized 

propane. Fifth, we added data reporting 

requirements for inputs received by a 

NGL fractionator in order to conduct 

verification using a mass-balance 

approach. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on suppliers 

of natural gas and NGLs were received 

covering numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart NN: 

Suppliers of Natural Gas and Natural 

Gas Liquids.’’ 

Definition of Source Category 

Comment: EPA received many 

comments on the non-emissive use of 

natural gas liquids (NGLs). In general, 

these comments stated that NGLs such 

as ethane, butane, and isobutene, are 

either used as feedstocks in the 

petrochemical industry or as 

blendstocks that are reported by 

refineries in 40 CFR part 98, subpart 

MM, and should not be reported as 

though they are completely combusted 

or oxidized. Several commenters 

proposed that odorized propane should 

be the focus of 40 CFR part 98, subpart 

NN rather than all NGLs because 

odorized propane is the only NGL that 

is combusted as fuel. 

Response: Today’s rule still requires 

reporting on all NGL products, even 

those with potentially non-emissive 

uses. Comprehensive upstream data will 

provide EPA with a full accounting of 

the emissions that would result from the 

complete combustion or oxidation of all 

natural gas liquids introduced into the 

economy. 

As discussed in the proposal, a 

comprehensive and rigorous system for 

tracking the fate of natural gas liquids 

that may have non-emissive uses is 

beyond the scope of this rule, and 

would require a much more 

burdensome reporting obligation for 

NGL fractionators and downstream 

users of natural gas liquids. Based on 

the data available today, we do not 

believe that a NGL fractionator can 

know with certainty whether or not the 

carbon in their products will be released 

into the atmosphere. The data reported 

as a result of this rulemaking will allow 

EPA to conduct further research on the 

pathways and ultimate fate of NGL and 

to refine our understanding of and 


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policy on products with potential nonemissive uses. 

Therefore, EPA does not concur with 

the proposal to replace NGL reporting 

with propane odorizers. However, EPA 

concurs that odorized propane lines up 

closely with propane combusted 

downstream, and that data collection on 

odorized propane would help EPA 

decide if and how to carry out a wide 

variety of CAA provisions on emission 

sources, as authorized broadly under 

CAA sections 114 and 208. As a result, 

we have added reporting requirements 

on the volume of propane odorized on 

site in today’s rule. 

We do not concur that products 

reported under 40 CFR part 98, subpart 

NN, such as isobutane to be blended 

with fuel, will be double-counted as 

products reported under 40 CFR part 98, 

subpart MM. Subpart MM requires 

refineries to report all non-crude 

feedstocks that enter the facility in order 

to subtract the emissions that would 

result from the oxidation or combustion 

of those products from their 

calculations. Such methodology allows 

EPA to collect data on the entire 

petroleum and natural gas liquids 

system without any double-counting. 

Finally, in response to comments that 

collecting data on products with 

potentially non-emissive uses will 

overestimate actual emissions released 

into the atmosphere, EPA will continue 

to characterize CO2 emissions data 

reported under 40 CFR part 98, subpart 

NN as emissions that would result from 

the complete combustion or oxidation of 

the reported product(s) and not as actual 

emissions. 

Comment: Many commenters 

discouraged EPA from requiring 

reporting from natural gas processors. In 

general, these comments stated that 

processors do not know the constituents 

of the gas they process. They further 

stated that since bulk NGLs are often 

sent from one processor to another, 

reporting by processors on bulk NGLs 

would result in double-counting of 

supply. Ultimately, several commenters 

were confused by the multiple 

definitions provided in the rule for a 

natural gas processor and were not clear 

on the exact covered party in 40 CFR 

part 98, subpart NN. 

Response: In the final rule, we specify 

the source category as NGL fractionators 

rather than as natural gas processors, 

and we have removed the requirement 

to report bulk NGLs. To avoid any 

remaining potential for doublecounting, we provide an equation for a 

fractionator to subtract from its 

calculations any NGL constituents 

received from other fractionators that 

would report those products under this 

rule. 

By requiring reporting from NGL 

fractionators, we have removed the need 

for the term ‘‘natural gas processor’’ in 

40 CFR part 98, subpart NN. Multiple 

definitions for this term no long exist in 

the rule. 

Monitoring and QA/QC Requirements 

Comment: Many commenters 

interpreted EPA’s measurement and 

calibration requirements differently 

than we intended, and as a result 

pressed upon EPA the inability of 

industry to reasonably meet such 

requirements. Many commenters 

interpreted that EPA required meter 

reading and calibration of every 

customer meter. Other commenters 

interpreted that EPA required daily 

measurement totals of throughput. 

Response: In today’s rule, we provide 

precise language to remove any 

confusion about monitoring and QA 

requirements. First, we clarify that the 

point of measurement for natural gas 

supply is the city gate meter. If the LDC 

makes its own measurements at the city 

gate according to business as usual 

practices, then it must use its own 

measurements. If not, it must use the 

delivering pipeline invoices 

measurements. The only exceptions are 

that the point of measurement for 

natural gas delivered to large end-users 

is the customer meter and the point of 

measurement for natural gas stored or 

removed from storage is the appropriate 

storage meter. However, we clarify that 

customer meters and storage meters are 

not subject to the 40 CFR part 98, 

subpart NN calibration requirements. 

Second, we clarify that the minimum 

frequency of the measurements of 

quantities of NGLs and natural gas shall 

be based on the reporter’s standard 

practices for commercial operations. For 

NGL fractionators the minimum 

frequency of measurements shall be the 

measurements taken at custody transfers 

summed to the annual reportable 

volume. For natural gas the minimum 

frequency of measurement shall be 

based on the LDC’s standard 

measurement schedules used for billing 

purposes and summed to the annual 

reportable volume. If daily 

measurements are not standard practice 

for a reporter, then that reporter need 

not conduct daily measurements. 

EPA clarifies in the final rule that 

customer meters do not face calibration 

requirements under 40 CFR part 98, 

subpart NN. Other equipment used to 

measure quantities must be calibrated 

prior to their first use for reporting 

under this subpart, using a suitable 

standard test method published by a 

consensus based standards organization 

or according to the equipment 

manufacturer’s directions. Such 

equipment must also be recalibrated at 

the frequency specified by the standard 

test method used or by the 

manufacturer’s directions. EPA has 

concluded that initial calibration 

requirements are necessary to ensure 

consistency across all reporters and 

accuracy of data. Since such a wide 

variety of calibration methods is 

allowed and since commenters stated 

that industry already calibrates carefully 

as a result of State Utility Commission 

and other regulations, EPA concluded 

that industry is already following such 

calibration requirements for usual 

business operations. 

Data Reporting Requirements 

Comment: EPA received many 

comments on the requirement for LDCs 

to report information on individual 

customers. In general, commenters 

interpreted the reason for EPA to collect 

this data differently than was intended. 

Many commented on the CBI nature of 

customer-specific delivery information. 

Others commented that LDCs do not or 

may not have access to the EIA or EPA 

numbers of their customers. One 

commenter told us that a LDC can only 

attest to the gas volume delivered 

through a single particular meter at a 

single particular location, which is not 

necessarily an individual customer. 

Response: In the final rule, EPA has 

clarified that an LDC must report on 

customers that receive more than 

460,000 million standard cubic feet 

(Mscf) per year in order to subtract that 

volume out of its total calculations. 

EPA’s intention is to use this data to 

remove potential double-counting and 

to prevent a LDC from calculating and 

reporting an overstated supply volume. 

EPA can also use these data to verify 

that covered direct emitters are 

approximately reporting under the rule. 

In response to comments that LDCs do 

not or may not have access to 

customers’ EIA or EPA numbers, we 

have changed the reporting of this from 

required to voluntary, if known. We 

have further specified that LDCs must 

report large volumes delivered to a 

single meter rather than to a particular 

end-user. 

OO. Suppliers of Industrial GHGs 

1. Summary of the Final Rule 

Source Category Definition. Suppliers 

of industrial GHGs consist of the 

following: 

• Facilities producing any fluorinated 

GHG or N2O, except those that produce 


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only HFC–23 generated as a byproduct 

during HCFC–22 production. 

• Bulk importers of fluorinated GHGs 

or N2O, if the total combined imports of 

industrial GHGs and CO2 exceed 25,000 

metric tons of CO2e per year. 

• Bulk exporters of fluorinated GHGs 

or N2O, if the total combined exports of 

industrial GHGs and CO2 exceed 25,000 

metric tons CO2e per year. 

Suppliers of Industrial GHGs that 

meet the applicability criteria in the 

General Provisions (40 CFR 98.2) 

summarized in Section II.A of this 

preamble must report industrial GHG 

supply flows. 

GHGs to Report. Suppliers of 

industrial GHGs must report the amount 

of N2O and each fluorinated GHG 

produced, imported, exported, 

transformed, or destroyed during the 

calendar year. Importers and exporters 

of CO2 must calculate and report annual 

amounts of CO2 according to 40 CFR 

part 98, subpart PP. 

GHG Emissions Calculation and 

Monitoring. Suppliers must use the 

following methods to calculate annual 

industrial GHG supply flows: 

• The mass of each fluorinated GHG 

or N2O produced must be determined by 

measurements of gas production, less 

the mass of that GHG added to the 

process upstream (e.g., where used 

GHGs are added back to the production 

process for reclamation). 

• The mass of each fluorinated GHG 

transformed must be determined 

considering the mass of fluorinated 

GHG fed into the transformation process 

and the efficiency of that process (as 

indicated by yield calculations or 

quantities of unreacted fluorinated 

GHGs or nitrous oxide permanently 

removed from the process and 

recovered, destroyed, or emitted). 

• The mass of each fluorinated GHG 

destroyed must be determined by 

measurements of the mass of fluorinated 

GHG fed to the destruction device and 

a measurement of the destruction 

efficiency. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

industrial GHG supply flows or that can 

be used to verify industrial gas supply 

flows. A list of the specific data to be 

reported for this source category is 

contained in 40 CFR part 98, subpart 

OO. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate GHG 

emissions. A list of specific records that 

must be retained for this source category 

is included in 40 CFR part 98, subpart 

OO. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart OO: 

Suppliers of Industrial GHGs.’’ 

• EPA has elaborated on the 

definition of ‘‘produce’’ to clarify what 

it does and does not include. The 

definition now explicitly includes (1) 

the manufacture of a fluorinated GHG 

for use in a process that will result in 

the transformation of that GHG (either at 

or outside of the production facility) 

and (2) the creation of a fluorinated 

GHG (with the exception of HFC–23) 

that is captured and shipped off site for 

any reason, including destruction. The 

definition now explicitly excludes the 

creation of by-products that are released 

or destroyed at the production facility. 

• EPA has eased the accuracy and 

precision requirements for measuring 

production, transformation, and 

destruction. EPA is also permitting 

facilities flexibility in the frequency of 

measurements and calibration of 

measurement devices. Masses produced, 

fed into transformation processes, and 

fed into destruction devices must now 

be estimated to a precision and accuracy 

of one percent rather than 0.2 percent. 

Requirements to measure 

concentrations, which had previously 

been associated with the transformation 

and destruction provisions, have been 

changed to requirements to estimate 

concentrations or related quantities. 

• EPA has eliminated the requirement 

that fluorinated GHG production 

facilities that destroy fluorinated GHGs 

annually verify the destruction 

efficiency of their destruction devices. 

• EPA has added an additional 

method for estimating missing mass 

flow data in the event that a secondary 

mass measurement for that stream isn’t 

available. In that event, producers can 

use a related parameter and the 

historical relationship between the 

related parameter and the missing 

parameter to estimate the flow. 

• EPA has removed the option for 

reporters to develop their own methods 

for estimating missing data if they 

believe that the prescribed method will 

over- or under-estimate the data. 

• EPA has added some reporting 

requirements to be consistent with the 

changes to the calculations and 

monitoring sections and to permit 

verification of emissions calculations. 

• EPA has added an exemption from 

reporting requirements for import or 

export shipments containing less than 

250 metric tons of CO2e. 

• EPA has clarified that the criteria 

for imported container heels at 

paragraph 98.417(e) set forth the 

conditions under which importers do 

not need to report heels; they do not 

establish requirements for all containers 

containing residual gas. If importers 

import containers with residual gas that 

does not meet these conditions, they 

must simply report these imports under 

paragraph 98.416(c). In addition, EPA is 

adding another condition under which 

imported heels do not need to be 

reported; that is the case in which the 

heels are recovered and included in a 

future shipment. 

• EPA is requiring fluorinated GHG 

production facilities to submit a onetime report describing current 

measurement and estimation practices. 

EPA is requiring the one-time report 

on measurement practices because the 

Agency is providing some flexibility to 

reporters regarding the methods that 

they use to calculate industrial gas 

supply flows. This flexibility permits 

reporters to use a larger range of 

methods and measurement equipment 

than were proposed, and it is important 

for EPA to understand the methods and 

equipment and their accuracies. Similar 

reports are required under EPA’s 

Stratospheric Ozone Protection 

Regulations at 40 CFR part 82. 

As noted above, EPA removed the 

option for reporters to develop their 

own methods for estimating missing 

data if they believe that the prescribed 

method will over- or underestimate the 

data. EPA removed this option for two 

reasons. First, the proposed provision 

lacked clear guidance on when 

alternative methods should be used 

(e.g., on the size of an underestimate 

that would justify use of an alternative 

method) and on how they should be 

developed. Second, the proposed 

provision was redundant with the new 

provision that permits reporters to 

estimate missing data using a related 

parameter and the historical 

relationship between the related 

parameter and the missing parameter. 

This new option provides reporters with 

flexibility in substituting for missing 

data in the event that a secondary mass 

measurement is not available, but sets 

out general guidance on how to select 

the substitute data. 


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3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on suppliers 

of industrial GHGs were received 

covering numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart OO: 

Suppliers of Industrial GHGs.’’ 

Definition of Source Category 

Comment: EPA received a number of 

comments regarding the proposed 

definition of ‘‘fluorinated greenhouse 

gas.’’ Several commenters argued that 

the proposed definition was too broad 

because it would include nonvolatile 

materials that could not be emitted to 

the atmosphere and materials for which 

GWPs had not been calculated. One 

commenter suggested establishing a 

lower vapor pressure limit for 

fluorinated GHGs (heat transfer fluids) 

of 400 Pa (0.004 bar, or three mm Hg 

absolute) at 25 C. Some commenters 

expressed the concern that the lack of 

GWPs for some covered compounds 

would lead to incomplete or 

inconsistent reporting because facilities 

would assign their own GWPs to 

compounds for which GWPs were not 

provided in Table A–1 of 40 CFR part 

98, subpart A. 

Some commenters recommended that 

EPA address these concerns by 

requiring reporting of only those 

fluorinated compounds listed in Table 

A–1 of 40 CFR part 98, subpart A. 

However, one of these commenters 

noted that the list in A–1 is incomplete 

and inconsistent, excluding for 

example, some high-GWP compounds 

whose low-GWP alternatives are 

included. This commenter 

recommended that EPA establish a 

‘‘visible and participative process’’ to 

add other compounds as appropriate to 

Table A–1 of 40 CFR part 98, subpart A. 

Response: In today’s final rule, EPA is 

modifying the proposed definition of 

fluorinated GHG by adding an 

exemption for ‘‘substances with a vapor 

pressure of less than one mm of Hg 

absolute at 25 degrees C.’’ This 

modification ensures that non-volatile 

fluorocarbons such as fluoropolymers 

are excluded from reporting 

requirements, while requiring reporting 

of fluorocarbons (as well as SF6 and 

NF3) that could reasonably be expected 

to be emitted to the atmosphere. 

As noted by several commenters, this 

definition would require reporting of 

some fluorocarbons to which GWPs 

have not been assigned in either IPCC or 

World Meteorological Organization 

(WMO) Scientific Assessments (i.e., 

fluorocarbons for which Table A–1 of 40 

CFR part 98, subpart A does not provide 

GWPs). However, the lack of GWPs for 

some fluorocarbons will not impede 

reporting because EPA is requiring 

reporting of production and other 

quantities in tons of chemical rather 

than in tons of CO2e. For purposes of 

determining whether or not the 25,000 

metric ton CO2e import or export 

threshold is exceeded, EPA is requiring 

facilities to include only substances 

whose GWPs appear in Table A–1 of 40 

CFR part 98, subpart A. 

EPA believes that this approach is 

prudent and appropriate. As 

acknowledged by commenters, Table A– 

1 of 40 CFR part 98, subpart A is not a 

complete listing of current or potential 

fluorinated GHGs; the IPCC and WMO 

lists on which it is based reflect only the 

facts that the listed materials have been 

synthesized, their atmospheric 

properties investigated, the results 

published, and the publications found 

by the IPCC and WMO Assessment 

authors. Table A–1 is known to omit 

some existing fluorinated GHGs and it 

unavoidably omits future fluorinated 

GHGs that have not yet been 

synthesized. Given the radiative 

properties of the carbon-fluorine bond, 

any fluorocarbon emitted into the 

atmosphere may have a significant 

GWP. This is true even for some 

fluorocarbons with lifetimes of less than 

one year, including, for example, HFE– 

356pcc3, with a lifetime of four months 

and a 100-year GWP of 110. 

Reporting of fluorocarbons that do not 

appear in Table A–1 of 40 CFR part 98, 

subpart A will provide valuable 

information on the full range of volatile 

fluorocarbons entering U.S. commerce. 

This information can be used to assess 

the overall volume and importance of 

compounds for which GWPs have not 

been evaluated and to help identify 

which compounds should have their 

GWPs evaluated first. In addition, once 

GWPs have been identified for these 

compounds, historical reports in tons of 

chemical can be converted into CO2e. 

Without a comprehensive reporting 

requirement, such historical information 

could be lost. Ultimately, all of this 

information can be used to inform 

policy decisions regarding the 

appropriate type and scope of emission 

reduction measures for these gases. 

Considering the modest cost of reporting 

production, import, and export of such 

compounds, the potential value of this 

information justifies a comprehensive 

definition of fluorinated GHG. 

EPA agrees with commenters who 

noted that Table A–1 of 40 CFR part 98, 

subpart A should be periodically 

updated through a visible and 

participative process. EPA anticipates 

that as GWPs are evaluated or reevaluated by the scientific community, 

the Agency will update Table A–1 of 40 

CFR part 98, subpart A through notice 

and comment rulemaking. EPA may 

also, through rulemaking, establish a 

more proactive process for ensuring that 

GWPs are appropriately evaluated or reevaluated. 

Comment: EPA received comments 

both supporting and opposing a 

requirement to report imports of 

fluorinated GHGs contained in 

equipment and foams. Commenters 

supporting such a requirement noted 

that these imports comprised a 

significant fraction of U.S. consumption 

of fluorinated GHGs, that excluding 

these imports from reporting would put 

domestic manufacturers at a 

disadvantage and lead to leakage of 

manufacturing and increased emissions 

of GHGs, and that the burden of 

reporting these imports would be low, 

since there are relatively few importers 

and the reported information is easily 

accessible. Commenters opposing such a 

requirement stated that the benefit of 

reporting would be small because precharged equipment and foams are 

‘‘hermetically sealed systems that 

essentially emit no GHGs,’’ while the 

cost would be high due to the large 

number of importers. 

Response: EPA did not propose to 

require reporting of fluorinated GHGs 

contained in imported products because 

EPA was concerned that the 

administrative burden of such a 

requirement could be considerable, 

while the quantities imported in at least 

some types of products could be small. 

However, in the proposal EPA 

acknowledged that the quantities of 

fluorinated GHGs imported in precharged equipment and foams appeared 

significant, and that ascertaining the 

identity and quantity of fluorinated 

GHGs in these products might be 

relatively straightforward. EPA is 

continuing to research these issues, and 

is deferring the final decision on 

whether to include imports of 

equipment and foams containing 

fluorinated GHGs to a later rulemaking. 

Monitoring and QA/QC Requirements 

Comment: Several commenters stated 

that facilities could not meet the 

proposed accuracy, precision, and 

frequency requirements for their 

measurements of production, 

transformation, and destruction using 

existing equipment and practices. These 

commenters stated that they would need 

to expend significant funds (millions of 


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dollars in some cases) and time to 

install Coriolis flowmeters in multiple 

streams and to implement daily 

sampling protocols to analyze the 

contents of these streams. One 

commenter requested that EPA revise its 

precision and accuracy requirements to 

one percent for measurements of mass. 

Other commenters argued that instead 

of establishing strict accuracy, 

precision, and frequency requirements 

for measuring production, EPA should 

permit facilities to use existing 

measurement instruments and practices, 

such as NIST Handbook 44 and the trial 

HFC reporting program patterned on 

EPA’s reporting requirements for ozonedepleting substances. 

Response: Given the limited amount 

of time before 2010 data collection must 

begin, EPA agrees that it is appropriate 

to ease the accuracy and precision 

requirements proposed for measuring 

production, transformation, and 

destruction. EPA is therefore revising 

these requirements in the final rule. 

EPA is also permitting facilities 

flexibility in the frequency of 

measurements and calibration of 

measurement devices. 

This approach will permit facilities to 

begin measuring their production, 

transformation, and destruction for 

purposes of the rule beginning in 

January 2010, using their current 

practices and equipment. However, EPA 

is planning to revisit the precision and 

accuracy requirements for industrial gas 

supply as we review public comments 

and perform analyses related to 

proposed 40 CFR part 98, subpart L 

(fluorinated gas production), which is 

not included in today’s final rule. This 

is because the accuracy and precision 

with which production facilities track 

production, transformation, and 

destruction can have a profound 

influence on the accuracy and precision 

of these facilities’ fluorinated GHG 

emission estimates. For one method of 

monitoring F–GHG emissions under 

consideration, a one percent relative 

error in production mass measurements 

could result in a much higher relative 

error in the emissions estimate, e.g., 

over 90 percent at an emission rate of 

1.5 percent. For other methods of 

monitoring F–GHG emissions, however, 

a one percent relative error in 

production mass measurements would 

not lead to large errors in emission 

estimates. For both 40 CFR part 98, 

subpart OO and 40 CFR part 98, subpart 

L, EPA’s goal is to optimize methods of 

data collection to ensure data accuracy 

while considering industry burden. 

PP. Suppliers of Carbon Dioxide (CO2) 

1. Summary of the Final Rule 

Source Category Definition. Under the 

rule, suppliers of CO2 consist of the 

following: 

• Facilities with production process 

units that capture and supply CO2 for 

commercial applications or that capture 

and maintain custody of a CO2 stream 

in order to sequester or otherwise inject 

it underground. 

• Facilities with CO2 production 

wells that extract a CO2 stream for the 

purpose of supplying CO2 for 

commercial applications. 

• Importers of bulk CO2, if total 

combined imports of CO2 and other 

GHGs exceed 25,000 metric tons of CO2

equivalent (CO2e) per year. 

• Exporters of bulk CO2, if total 

combined exports of CO2 and other 

GHGs exceed 25,000 metric tons CO2e 

per year. 

This source category is focused on 

upstream supply. It does not cover: 

Storage of CO2 above ground or in 

geologic formations; use of CO2 in 

enhanced oil and gas recovery; 

transportation or distribution of CO2; or 

purification, compression, on-site use of 

CO2 captured on site, or processing of 

CO2. This source category does not 

include CO2 imported or exported in 

equipment, such as fire extinguishers. 

Suppliers of CO2 that meet the 

applicability criteria in the General 

Provisions (40 CFR 98.2) summarized in 

Section II.A of this preamble must 

submit GHG reports. 

GHGs to Report. Suppliers of CO2

must report the mass of CO2 in a stream 

captured from production process units 

and extracted from production wells, 

and the mass of CO2 in containers that 

is imported and exported. 

GHG Emissions Calculation and 

Monitoring. While this source category 

is focused on upstream supply of CO2, 

EPA recognizes that all CO2 supplied to 

the economy does not necessarily result 

in an emission. There are a variety of 

downstream applications for CO2—some 

applications are emissive and some are 

non-emissive. Under this rulemaking, a 

CO2 supplier facility must calculate the 

mass of CO2 supplied quarterly by 

measuring the mass or volumetric flow 

of gas and multiplying by the CO2

concentration, and density in the case a 

volumetric flow meter is used, of the gas 

or liquid, as specified below. EPA 

requires quarterly monitoring because 

EPA has concluded that the CO2

concentration of the stream varies 

throughout the year, and a quarterly 

concentration number multiplied by a 

quarterly volume will generate more 

accurate calculation of CO2 supply than 

annual measurements. EPA requires 

these quarterly numbers to be reported 

so that EPA can electronically verify the 

calculations. The CO2 supplier must 

also provide information on the 

downstream CO2 application, if known. 

Reporters must use the following 

methodologies, as applicable, for 

calculating CO2 supplied: 

• For suppliers that make 

measurements with mass flow meters, 

calculate quarterly for each meter the 

total mass of CO2 in a CO2 stream in 

metric tons, prior to any subsequent 

purification, processing, or 

compressing, according to Equation PP– 

1 of 40 CFR 98.423. Measure mass flow 

and concentration in accordance with 

40 CFR 98.424. 

• For suppliers that make 

measurements with volumetric flow 

meters, calculate quarterly for each 

meter the total mass of CO2 in a CO2

stream in metric tons, prior to any 

subsequent purification, processing, or 

compressing, according to Equation PP– 

2 of 40 CFR 98.423. Measure volumetric 

flow, concentration and density in 

accordance with 40 CFR 98.424. 

• For suppliers that have multiple 

flow meters, aggregate data according to 

methods specified in Equation PP–3 in 

40 CFR 98.423. 

• Importers or exporters that import 

or export CO2 in containers must 

calculate the total mass of CO2 supplied 

in metric tons, prior to any subsequent 

purification, processing, or 

compressing, according to equation PP– 

4 of 40 CFR 98.423. Use weigh bills, 

scales, or load cells to measure the mass 

of CO2 imported or exported in 

containers. 

Data Reporting. In addition to the 

information required to be reported by 

the General Provisions (40 CFR 98.3(c)) 

and summarized in Section II.A of this 

preamble, reporters must submit 

additional data that are used to calculate 

CO2 supply. A list of the specific data 

to be reported for this source category is 

contained in 40 CFR 98.426. 

Recordkeeping. In addition to the 

records required by the General 

Provisions (40 CFR 98.3(g)) and 

summarized in Section II.A of this 

preamble, reporters must keep records 

of additional data used to calculate CO2

supply. A list of specific records that 

must be retained for this source category 

is included in 40 CFR 98.427. 

2. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 


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Reporting Rule: EPA’s Response to 

Public Comments, Subpart PP: 

Suppliers of Carbon Dioxide.’’ 

• We added equations and QA 

requirements to allow reporters to 

determine CO2 quantity using 

volumetric flow meters, weigh bills, 

scales, or load cells, as appropriate. 

These additions supplement the 

proposed equations and quality 

assurance requirements to determine 

CO2 quantity using mass flow meters. 

• We revised the reporting 

procedures for missing data in 40 CFR 

98.425. Facilities must use quarterly 

values as substitute data as they can no 

longer use annual average values. We 

added missing data procedures to allow 

for more quarterly data points to be 

used, as appropriate. EPA concluded 

that quarterly missing data values will 

generate more accurate estimates than 

annual average values. 

• To improve the emissions 

verification process, we reorganized and 

updated 40 CFR 98.426. We moved 

some data elements from 40 CFR 98.427 

to 40 CFR 98.426, and added some data 

elements that a reporter must already 

use to calculate GHGs as specified in 40 

CFR 98.423 to 40 CFR 98.426 for clarity. 

• We revised the reporting and 

calculation procedures to require 

facilities using flow meters to determine 

annual mass for every flow meter used. 

To aggregate data at the facility level for 

CO2 being captured in production wells 

or production process units, we have 

added Equation PP–3. 

• To decrease unnecessary sampling 

burden, we have removed the 

requirement of quarterly concentration 

sampling for importers and exporters 

that use containers of CO2. 

3. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on suppliers 

of CO2 were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Subpart PP: 

Suppliers of Carbon Dioxide.’’ 

Definition of Source Category 

Comment: EPA received many 

comments about how we defined the 

source category in this Subpart. One 

group of comments stated that the CO2

supplied to the economy should not be 

characterized as an emission. Some in 

this group of comments specified that 

much of the supplied CO2 is stored at 

enhanced oil recovery (EOR) sites, 

which are ‘‘closed systems’’, rather than 

emitted. In general, these same 

commenters stated that any CO2

reporting requirements placed by EPA 

on industry should be placed on 

downstream CO2 users, such as EOR 

facilities, rather than CO2 suppliers and 

should be for actual emissions only. 

Other comments echoed that EPA needs 

to collect data from recipients of 

supplied CO2 such as EOR sites. This 

group pressed upon EPA the need to 

collect not only data on actual 

emissions but also data on injection, 

production, and geologic sequestration 

of CO2. Some of the benefits cited for 

collecting such comprehensive data 

include: Assisting in ensuring no more 

than negligible releases at a facility if it 

is properly sited, designed, and 

permitted; achieving full public 

accountability of CO2 geologic 

sequestration effectiveness; and tracking 

the CO2 throughout the entire carbon 

dioxide capture and sequestration (CCS) 

chain for the purposes of adjusting CO2

emissions reported or assigning offsets. 

Along those lines, some commenters 

urged EPA to rely on or expand the 

existing underground injection control 

(UIC) program to deal with CCS. 

Response: EPA did not intend to 

characterize all CO2 supplied to the 

economy as emissions and recognizes 

that there are a variety of applications 

for CO2, both emissive and nonemissive. CO2 supplied to the economy 

would result in an emission if the CO2

were used in an application which 

would ultimately result in release of the 

CO2 to the atmosphere. EPA is also 

collecting information from upstream 

suppliers in other subparts of this 

rulemaking such as natural gas supply 

and petroleum product supply. 

EPA recognizes that, in order to 

determine whether or not supplied CO2

has been or will be released to the 

atmosphere (e.g., emitted), the Agency 

needs information on the downstream 

CO2 end-use. In today’s final 

rulemaking, CO2 suppliers must provide 

information on the downstream CO2

application, if known. EPA believes 

information on the end-use will provide 

some idea of the amounts of CO2 which 

are emitted. Where that end-use is 

geologic sequestration (at EOR or other 

types of facilities), EPA will need 

additional information on the amount of 

CO2 that is permanently and securely 

sequestered and on the monitoring and 

verification methodologies applied. 

With respect to EOR, the geology of an 

oil and gas reservoir can create a good 

barrier to trap CO2 underground. 

Because these formations effectively 

stored oil or gas for hundreds of 

thousands to millions of years, it is 

believed that they can be used to store 

injected CO2 for long periods of time. 

However, EPA also recognizes that the 

requirements to identify a suitable GS 

site extend beyond geophysical trapping 

parameters alone and include: The 

evaluation and appropriate management 

of potential leakage pathways, 

appropriate rate and pressure of 

injection, appropriate monitoring, and 

other such features. While some amount 

of CO2 injected into oil and gas 

reservoirs for EOR purposes will be 

trapped in the subsurface, these and 

other site-specific elements influence 

the amount of CO2 securely sequestered 

and the potential for release of CO2

during EOR operations. 

Given the comments in support of 

downstream data collection, particularly 

with respect to EOR systems and CO2

geologic sequestration (at EOR or other 

types of facilities), EPA plans to issue a 

new proposal on geologic sequestration 

and will consider how to address 

emissions and sequestration at active 

EOR facilities. EPA will take action on 

this issue in the near future with the 

goal that data collection for these types 

of facilities can begin as quickly as 

possible. EPA will seek comment on 

monitoring, reporting, and verification 

methodologies which can be used to 

determine the amount of CO2 emitted 

and geologically sequestered at active 

EOR facilities and geologic 

sequestration sites where CO2 is injected 

(for long-term storage) into saline 

aquifers, oil and gas reservoirs, or other 

geologic formations. Furthermore, as 

stated in Section III.W of this preamble, 

EPA plans to take additional time to 

consider alternatives to data collection 

procedures and methodologies in the 

proposed 40 CFR part 98, subpart W and 

will consider inclusion of GHG 

reporting from other sectors of the oil 

and gas industry besides those proposed 

for reporting in proposed 40 CFR part 

98, subpart W. EOR surface facility 

operations may be part of those 

considerations. The data reported under 

subsequent regulatory actions and the 

data reported under today’s rulemaking 

will together enable EPA to understand 

the amount of CO2 supplied, emitted, 

and sequestered in the U.S., to carry out 

a wide variety of CAA provisions. The 

options that we will have considered 

and the resulting recommended 

approaches will be further fleshed out 

through a notice and comment process. 

See the next comment response for a 

discussion of why EPA still needs to 

collect CO2 supplier data in today’s 

rulemaking even though a new 

rulemaking on sequestration is planned. 

In response to comments that EPA 

should rely on or expand the UIC 

program to address emissions of CO2, 


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22 Dooley, JJ, CL Davidson, RT Dahowski, MA 

Wise, N Gupta, SH Kim, EL Malone, ‘‘Carbon 

Dioxide Capture and Geologic Storage: A Key 

Component of a Global Energy Technology Strategy 

to Address Climate Change.’’ Joint Global Change 

Research Institute, Battelle Pacific Northwest 

Division. May 2006. PNWD–3602. College Park, 

MD. 

that issue is outside the scope of this 

rulemaking. However, EPA agrees that 

the UIC program and EPA’s authority 

under the Safe Drinking Water Act 

(SDWA) will provide a foundation for 

ensuring safe and effective containment 

of CO2. However, SDWA is focused on 

permitting sites for protection of ground 

and drinking water; the new proposal 

discussed above will be designed to 

address issues related to the CAA. EPA 

intends to harmonize CCS requirements 

across relevant statutory or other 

programs in order to minimize any 

redundancy and any burden on 

reporters. The reporting requirements in 

today’s rulemaking for CO2 suppliers 

and the reporting requirements in new 

rulemaking for CO2 geologic 

sequestration sites will complement 

each other and together they can be 

harmonized with reporting 

requirements under the UIC proposed 

rulemaking. In a new CAA rulemaking 

on geologic sequestration reporting, EPA 

will rely on UIC permit requirements to 

the maximum extent possible. EPA will 

seek comment on these issues and will 

also endeavor to issue a geologic 

sequestration GHG reporting rule in the 

same time frame as it has planned for 

the stand-alone UIC GS rulemaking. 

Comment: EPA received comments 

requesting information on how CO2

supply will assist EPA in developing 

future climate policy. Commenters 

stated that they do not believe CO2

supply data will provide EPA with 

useful information. Commenters stated 

that data collection from CO2 suppliers 

does not fit within EPA’s mandate from 

Congress to measure upstream 

emissions only as appropriate. 

Response: As discussed in Sections 

I.C and II.Q of this preamble, EPA is 

collecting data from CO2 suppliers in 

today’s rule to carry out a wide variety 

of CAA provisions, as authorized 

broadly under CAA Sections 114 and 

208. For example, this data will enable 

EPA to evaluate the appropriate action 

to take under section 103 regarding nonregulatory strategies for pollution 

prevention. It will also inform 

evaluation of possible CAA regulation of 

the supplier and/or recipient of the CO2

Data on CO2 supply to the economy will 

allow EPA to make a well informed 

decision about whether and how to use 

the CAA to regulate facilities that 

capture, sequester, or otherwise receive 

CO2 as an end-user. 

Though CO2 capture and geologic 

sequestration are occurring now on a 

relatively small scale, CCS is expected 

to play a major role in mitigating GHG 

emissions from a wide variety of 

stationary sources. According to the 

Inventory of U.S. Greenhouse Gas 

Emissions and Sinks: 1990–2007 (EPA, 

April 2009), stationary sources 

contributed 67 percent of the total CO2

emissions from fossil fuel combustion in 

2007. The stationary sources represent a 

wide variety of sectors amenable to CO2

capture; electric power plants (existing 

and new), natural gas processing 

facilities, petroleum refineries, iron & 

steel foundries, ethylene plants, 

hydrogen production facilities, 

ammonia refineries, ethanol production 

facilities, ethylene oxide plants, and 

cement kilns. Furthermore, 95 percent 

of the 500 largest stationary sources are 

within 50 miles of a candidate CO2

reservoir.22

With this rule, EPA will begin 

building capacity to track the growth in 

CO2 supply and learn about its 

disposition throughout the economy. 

EPA has concluded that we need data 

now from CO2 suppliers—both 

industrial facilities and CO2 production 

wells—in order to effectively track how 

the supply sources will change over 

time. For example, we will need to track 

if and by how much CO2 captured from 

industrial facilities will offset or 

displace CO2 produced from natural 

formations. Even after EPA begins 

collecting data on CO2 geologic 

sequestration under the proposed new 

rulemaking (discussed above), EPA will 

continue to need data from CO2

suppliers in order to track any CO2 that 

is not sequestered. 

Comment: EPA received some 

comments asking whether a specific 

situation results in coverage under 40 

CFR part 98, subpart PP, and some 

comments requesting that their specific 

situation be exempt from coverage. For 

example, one commenter asked whether 

a facility separating CO2 that is not 

supplied to downstream customers is a 

covered facility. Another asked that a 

pulp and paper mill that transfers a CO2

stream to an adjacent facility by 

pipeline be exempt from 40 CFR part 98, 

subpart PP. Several commenters 

requested clarification on specific 

scenarios such as taking ownership of 

an already separated CO2 stream for 

further processing, separating CO2 for 

their own use, and operating versus 

owning the separation unit. 

Response: EPA did not intend for 40 

CFR part 98, subpart PP to cover 

facilities that take ownership of a CO2

stream that has already been separated 

and removed from a manufacturing 

process or that has already been 

extracted from CO2 production wells in 

order to do any of the following: Store 

it in above ground storage of CO2; 

transport or distribute it via pipelines, 

vessels, motor carriers, or other means; 

purify, compress, or process it; or sell it 

to other commercial applications. 40 

CFR part 98, subpart PP covers facilities 

that own or operate the equipment that 

physically separates and removes CO2

from an industrial or manufacturing 

process or physically extracts CO2 from 

production wells because we concluded 

that the entity with first touch of the 

CO2 supply was the most logical point 

of coverage. We wanted to minimize any 

unnecessary duplicative reporting of the 

same CO2 by being as specific as 

possible about who in the supply chain 

is responsible for reporting it. 

We did not intend for this source 

category to include facilities that 

capture CO2 for further processing or 

use within the fence line of the facility 

(e.g., for their own use). EPA proposed 

that 40 CFR part 98, subpart PP only 

cover CO2 that is captured or extracted 

for purposes of sequestration or supply 

to other facilities for commercial 

applications because we concluded that 

CO2 captured and used on-site is 

equivalent to an intermediary step in 

production rather than an actual supply 

of CO2. 

Comment: EPA received a comment 

requesting that ethanol plants and other 

facilities capturing CO2 from biomass be 

exempt from Subpart PP. 

Response: A long standing inventory 

convention adopted by the IPCC, the 

UNFCCC, the US GHG Inventory, and 

many other reporting programs is 

separate treatment of emissions of CO2

from the combustion of biomass and 

biomass-based fuels from emissions of 

CO2 from the combustion of fossil-based 

products. In national inventories, 

emissions from the combustion of 

biomass-based fuels are accounted for as 

part of a comprehensive system-wide 

tracking of carbon dioxide emissions 

and sequestration in the land-use, landuse change and forestry sector and the 

agriculture sector, rather than at the 

point of fuel combustion. Consistent 

with this approach, in the proposed and 

final rule, downstream emitters must 

only consider non-biogenic emissions 

when conducting a threshold analysis; 

however, downstream emitters must 

report both biogenic and non-biogenic 

emissions once they trigger the 

reporting threshold because data on 

non-biogenic emissions is useful and 

informative. 

For the final rule, EPA has decided 

not to apply the same approach to 


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56352 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

23Manufacturers of light-duty vehicles, light-duty 

trucks, and medium-duty passenger vehicles are not 

covered in this final rule. 

24The term ‘‘manufacturer,’’ as well as the term 

‘‘manufacturing company,’’ as used in this 

preamble, means companies that are subject to EPA 

emission certification requirements. This primarily 

includes companies that manufacture engines 

domestically and foreign manufacturers that import 

engines into the U.S. market. In some cases this also 

includes domestic companies that are required to 

meet EPA certification requirements when they 

import foreign-manufactured engines. 

25For aircraft engine manufacturers, reporting 

requirements will apply for the engine models in 

production in 2011. 

26Small business manufacturers will continue to 

be subject to measurement and/or reporting 

requirements for compliance with existing 

regulations. 

27But see Ford Motor Co. v. EPA, 604 F. 2d 685 

(D.C. Cir. 1979) (permissible for EPA to regulate 

CH4 under CAA section 202 (b)). In addition, 

although CH4 is not itself regulated, manufacturers 

subject to ‘‘non-methane hydrocarbon’’ standards 

have needed to determine CH4 emission levels, in 

some cases by using a default value and in many 

cases by way of testing. 

suppliers of CO2. We have concluded 

that data on capture of biogenic CO2

would be useful and informative 

because biogenic CO2 can potentially be 

stored in GS sites, or displace fossil CO2

applications. We need a full picture of 

the CO2 being supplied into the 

economy. Though CO2 capture and 

sequestration is occurring now on a 

relatively small scale, it is expected to 

play a major role in mitigating GHG 

emissions. Therefore information on all 

potential sources of CO2 for 

sequestration is necessary for a 

complete picture. Thus, a facility that 

captures CO2 from biomass and 

otherwise meets the applicability test is 

covered under 40 CFR part 98, subpart 

PP and is required to report all CO2

supplied along with the percentage of 

that supply that is biomass-based. 

Monitoring and QA/QC Requirements 

Comment: A large number of 

commenters requested that volumetric 

flow meters be allowed for purposes of 

calculating CO2 supply in place of or in 

addition to mass flow meters. These 

comments indicated that mass flow 

meters are not in operation at many 

covered facilities, and the cost to 

comply with such an equipment 

requirement would be unnecessarily 

high. Some commenters suggested that 

reporters should be allowed to use sales 

contracts to determine quantity of CO2

as long as the CBI is protected. Some 

commenters indicated that CO2

liquefaction and purification facilities 

do not operate flow meters for the 

course of usual business. One of these 

also commented that importers and 

exporters of CO2 do not operate flow 

meters for the course of usual business 

if they handle the product in containers 

and requested consideration of this 

incongruity. 

Response: As a result of these 

comments, EPA added two equations to 

the methodology section of 40 CFR part 

98, subpart PP in today’s rule in order 

to ensure that all covered CO2 can be 

reported, irrespective of technical or 

physical conditions. Therefore, a 

reporter that measures CO2 in a stream 

using a volumetric flow meter may use 

this volumetric flow meter to determine 

quantity rather than having to purchase 

and install a mass flow meter. EPA has 

concluded that providing this additional 

methodology reduces the burden on 

reporters without compromising the 

quality of data received by the agency. 

In addition, a reporter that imports or 

exports CO2 in containers may use 

weigh bills, scales, or load cells to 

determine quantity because applying a 

mass flow meter would be technically 

impossible. EPA has concluded that 

providing this additional methodology 

reduces the burden on reporters without 

compromising the quality of data 

received by the agency. 

The final rule does not require 

reporting from facilities that liquefy or 

purify CO2 that has already been 

separated or removed from a 

manufacturing process or already 

extracted from production wells. 

Therefore we did not give consideration 

to the types of equipment in operation 

at such facilities. 

Finally, the rule does not allow 

reporters to use sales contracts to 

determine quantity because EPA has 

concluded that reporters capturing or 

extracting CO2 already operate mass or 

volumetric flow meters, or already 

determine quantities of CO2 imported or 

exported in containers using weigh 

bills, scales, or load cells. EPA has 

concluded that mass and volumetric 

flow meters provide more accurate data 

than sales contracts. 

IV. Mobile Sources 

A. Summary of Requirements of the 

Final Rule 

For manufacturers of engines used in 

mobile sources outside of the light-duty 

sector,23 this rule includes new 

requirements for reporting emission 

rates of GHGs.24 Mobile source engine 

manufacturers have been measuring CO2

emission rates from their products for 

many years as a part of normal business 

practices and existing criteria pollutant 

emission certification programs, but 

they have not consistently reported 

these values to EPA. This final rule 

requires manufacturers to consistently 

measure and report CO2 for all engines 

beginning with model year 2011 and 

other GHGs in subsequent model 

years.25 Manufacturers meeting the 

definitions of ‘‘small business’’ or 

‘‘small volume manufacturer’’ under 

EPA’s existing mobile source emissions 

regulations will generally be exempt 

from any new GHG reporting 

requirements.26

In addition to CO2, most 

manufacturers will now be required to 

report on two other major GHGs emitted 

by mobile sources, nitrous oxide (N2O) 

and methane (CH4). Although most 

current engines have relatively low 

emission rates of these GHGs compared 

to CO2, these compounds have global 

warming potentials significantly higher 

than CO2. It is important that EPA 

improve its understanding of these 

emissions from today’s engines and 

monitor trends over time. The broad 

base of emission data that will begin to 

accrue from requirements in this rule 

will support emissions modeling by 

EPA and others, and will help guide 

future GHG policy. 

Emissions of N2O are related to 

catalytic treatment of engine exhaust, 

specifically aftertreatment of NOX

emissions. Therefore, we will require 

that manufacturers begin to measure 

and report N2O emissions, but only for 

engine models that incorporate NOX

aftertreatment technology (as shown in 

Table IV–1 of this preamble). The 

program will not require N2O reporting 

before model year 2013, and the 

requirements will only apply to new 

engines equipped with NOX

aftertreatment technology. 

(Manufacturers of some engine 

categories have employed aftertreatment 

for many years to meet NOX standards; 

for other engine categories, 

manufacturers are unlikely to introduce 

NOX aftertreatment technologies for 

some years to come.) 

Emissions of CH4 are a part of overall 

hydrocarbon emissions from mobile 

sources. Because CH4 is not very 

reactive in the atmosphere, EPA has 

often excluded CH4 from mobile source 

hydrocarbon regulations since it has not 

traditionally been a major determinant 

of ozone formation.27 The new reporting 

requirements are necessary to evaluate 

the magnitude of mobile source CH4

emissions from a GHG (rather than 

ozone precursor) perspective. 

As described above, we are finalizing 

manufacturer reporting requirements for 

N2O and CH4 emission rates in order to 

understand current emissions of these 

GHGs and to monitor potential changes 

as technologies and policies change in 

the future. However, we believe that 

manufacturers may be able to provide 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56353 

28Aerodyne, Rich Miake-Lye, AAFEX Methane 

presentation at the Seventh Meeting of Primary 

Contributors for the Aviation Emissions 

Characterization Roadmap, June 9–10, 2009. 

29 IPCC, Aviation and the Global Atmosphere, 

1999, at http://www.grida.no/climate/ipcc/aviation/ 

index.htm, and NOAA, Written Testimony of Dr. 

David W. Fahey, Hearing on ‘‘Aviation and the 

Environment: Emissions,’’ Before the Committee on 

Transportation and Infrastructure, Subcommittee on 

Aviation, U.S. House of Representatives, May 6, 

2008. 

alternative test data (and/or other 

information including engineering 

judgments based on test data) that 

would give EPA a reasonable basis for 

estimating the likely N2O and CH4

emission rates for each certified engine 

family. Therefore, we are including a 

provision in this final rule that would 

allow a manufacturer the opportunity to 

provide such alternative information in 

lieu of N2O and/or CH4 test data for each 

engine family. 

In assessing such alternative 

information, EPA would consider how 

well the information provided by the 

manufacturer allows EPA to reasonably 

anticipate the emission performance of 

each of the manufacturer’s engines. For 

example, we expect that in most cases 

a manufacturer wishing to omit engine 

testing will provide EPA with N2O test 

data from relevant testing programs (by 

such sources as industry collaboratives 

and/or from the suppliers of the 

catalytic NOX aftertreatment systems 

they are using on an engine. We would 

expect the manufacturer to also include 

an explanation of the manufacturer’s 

engineering judgment as to why the data 

should apply to the engine family in 

question. For CH4 emissions, our 

primary concern is the potential for 

unusually high emissions from natural 

gas fueled engines. Thus, we expect that 

in most cases a manufacturer of such an 

engine will provide test data on similar 

engines with similar catalyst systems for 

hydrocarbon control (with an 

explanation of their engineering 

judgment as to why the data should 

apply to that engine family). 

The reporting requirements related to 

C3 marine engines and turbofan and 

turbojet aircraft engines differ from 

other engine categories. As with other 

manufacturers, C3 marine engine and 

aircraft engine manufacturers will report 

CO2 emission rates beginning in 2011 

(for aircraft engines, they will report 

CO2 separately for each mode of the 

landing and take-off (LTO) cycle used in 

the certification test, as well as the 

entire LTO cycle). For aircraft engine 

manufacturers, however, the reporting 

requirements will apply not just to 

engines introduced in that year, but for 

all engines still in production. (This 

should not require manufacturers to 

conduct any new testing, only to report 

existing data.) We are not requiring 

manufacturers of C3 marine engines and 

aircraft engines to measure or report 

N2O or CH4 emission rates because of 

unique aspects of their industries and 

technologies. 

C3 marine engines are very large and 

manufacturers generally test them as 

they are installed into ships rather than 

in a laboratory setting. For this reason, 

we have determined that requiring the 

addition of new N2O and CH4

measurement equipment for C3 engines 

would not be practical, and, as 

proposed, are not requiring such 

reporting in this rule. 

Since aircraft engine manufacturers 

are unlikely to employ NOX after 

treatment devices in the foreseeable 

future, we did not propose requiring 

N2O reporting from aircraft engines and 

are not finalizing any requirements in 

this final rule. We are not finalizing our 

proposed requirement that aircraft 

engine manufacturers measure and 

report CH4, as we learned that aircraft 

jet turbine engines have been shown to 

consume CH4 from the ambient air 

during the dominant operating modes.28

However, unlike NOX emissions from 

most mobile sources, NOX emissions 

from aircraft have been shown to make 

a potential contribution to climate 

change.29 For this reason, we are 

requiring that aircraft engine 

manufacturers report the NOX emission 

data for the LTO modes and the overall 

LTO cycle for all engine models 

currently in production, and for new 

engines as they are introduced. 

Manufacturers are already measuring 

NOX as part of current criteria pollutant 

certification requirements. NOX

emissions rate data from LTO modes 

will support modeling of overall NOX

emissions from aircraft. 

For all engine categories, when a 

manufacturer certifies the engine in one 

year and then carries over the 

certification to subsequent years, EPA 

will not require re-testing of that engine 

model for reporting purposes. 

As proposed, we are not including 

any requirements for mobile source fleet 

operators or State and local 

governments to report in-use travel 

activity or other emissions-related data 

in this final rule. 

Table IV–1 of this preamble shows the 

basic reporting requirements we are 

finalizing in this notice for each engine 

category. We discuss in more detail how 

these reporting requirements will apply 

to manufacturers of each engine 

category in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Motor Vehicle and 

Engine Manufacturing.’’ 

TABLE IV–1—FIRST MODEL YEAR FOR GHG REPORTING REQUIREMENTS

Engine category CO2 N2Oa CH4

Highway Heavy-Duty (engine and vehicle) ............................................................ 2011 2013 or NOX AT ................. 2012 

Nonroad Diesel ....................................................................................................... 2011 2013 or NOX AT ................. 2012 

Marine Diesel (other than C3) ................................................................................ 2011 2013 or NOX AT ................. 2012 

C3 Marine ............................................................................................................... 2011 None ................................... None 

Locomotives ............................................................................................................ 2011 2013 or NOX AT ................. 2012 

Small Spark-Ignition ................................................................................................ 2011 2013 or NOX AT ................. 2012 

Large Spark-Ignition ............................................................................................... 2011 2013 or NOX AT ................. 2012 

Marine Spark-Ignition .............................................................................................. 2011 2013 or NOX AT ................. 2012 

Snowmobiles ........................................................................................................... 2011 2013 or NOX AT ................. 2012 

Highway Motorcycles .............................................................................................. 2011 2013 or NOX AT ................. 2012 

Off Highway Motorcycles/ATVs .............................................................................. 2011 2013 or NOX AT ................. 2012 

Aircraft b ................................................................................................................... 2011 None ................................... None 

a N2O reporting for new engines begins in 2013 or when the manufacturer introduces NOX aftertreatment technology, whichever is later. bApplies to all turbofan and turbojet engines in production in 2011 with a rated output greater than 26.7 kilonewtons. Reporting of NOX also 

required. 


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30Modes of the landing and takeoff cycle are taxi/ 

idle, takeoff, climb out, and approach. 

B. Summary of Major Changes Since 

Proposal 

The major changes since proposal are 

identified in the following list. The 

rationale for these and any other 

significant changes can be found below 

or in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Motor Vehicle and 

Engine Manufacturers.’’ 

• We are not finalizing the proposed 

requirements related to light-duty 

vehicles (including light-duty trucks 

and medium-duty passenger vehicles). 

EPA expects to propose a 

comprehensive light-duty GHG 

emission control program commencing 

in MY 2012 (see Notice of Upcoming 

Joint Rulemaking to Establish Vehicle 

GHG Emissions and CAFE Standards, 

74 FR 24007 (May 22, 2009)), which is 

likely to contain monitoring, reporting 

and GHG data retention requirements 

that would supersede any reporting 

requirements established in this rule. 

Eliminating light-duty reporting 

requirements from this final rule will 

avoid issues of inconsistency and 

duplication. 

• We have revised our proposal that 

all engine manufacturers measure and 

report N2O for all of their engines, and 

instead will require N2O reporting only 

for engines that use NOX exhaust 

aftertreatment technology. 

• We have delayed the proposed MY 

2011 start year for N2O reporting until 

MY 2013, and later for categories where 

the manufacturer has not applied NOX

aftertreatment technology. 

• We have added additional emission 

test methods that manufacturers can 

choose for measuring N2O, to assure that 

an appropriate method is available for 

any foreseeable circumstance (including 

the need to measure very low N2O 

emission rates). 

• The final rule incorporates an 

opportunity for a manufacturer to 

provide EPA with appropriate 

alternative information in lieu of N2O 

and/or CH4 testing, as described above. 

• We have added one year of lead 

time to the proposed start year for 

reporting of CH4 emissions, until 2012. 

• We are not finalizing our proposal 

to require reporting of CH4 for aircraft 

engines because, for the dominant 

operating modes, jet engines may 

consume CH4 in the air. 

• We are finalizing a requirement that 

we took comment on in the proposal to 

have aircraft engine manufacturers 

report NOX emissions data they already 

collect, since, at altitude, NOX

emissions from aircraft have been 

shown to make a potential contribution 

to climate change. 

• Since aircraft engines are not 

certified every year (there is no annual 

certification as is the case with other 

mobile sources), we have removed 

references to ‘‘model year’’ in the 

regulations and revised them to reflect 

the change to a January 1, 2011 start 

date for reporting CO2 and NOX

emissions. 

C. Summary of Comments and 

Responses 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on mobile 

source were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Motor Vehicle and 

Engine Manufacturers.’’ 

Comment: Light-duty vehicle 

manufacturers and their trade 

organizations raised several concerns 

about the timing and nature of the 

reporting requirements. 

Response: We agree in part with these 

comments. However, more 

fundamentally, we have concluded that 

the likelihood of GHG emission 

regulations affecting light-duty vehicles 

(including light-duty trucks and 

medium-duty passenger vehicles) in the 

near future argues for consolidating any 

new GHG reporting requirements into 

that upcoming rule. Therefore, we have 

elected to not finalize the proposed 

requirements relating to these vehicles 

at this time, and expect to incorporate 

similar provisions in a proposed rule on 

GHG standards for light-duty vehicles in 

the near future. 

Comment: Engine manufacturers and 

their trade organizations challenged the 

proposed rule in several ways. In 

general, they questioned the need for 

the data to be reported; expressed 

concern that the proposed timing of the 

requirements, especially for N2O and 

CH4, was too aggressive; and 

commented that the proposed test 

procedure for N2O was not adequate. 

Response: We still conclude that there 

is significant value to collecting CO2, 

N2O, and CH4 emissions rate data on the 

broad range of mobile sources being 

produced. As stated earlier, the 

domestic and international attention to 

GHGs and their effects will only grow, 

and the ability for EPA and the public 

to understand and monitor emissions 

from mobile sources will be increasingly 

important as policies relating to GHGs 

are considered. Collecting emissions 

rate data from engine manufacturers on 

their new engines can improve 

modeling of emissions for the entire 

mobile source sector since current 

modeling relies on assumptions about 

N2O and CH4 emissions based on a 

limited number of field surveys. The 

data from this rule will also help EPA 

track emissions impacts from changes in 

technologies and policies over time. 

For N2O and CH4, we agree that 

revisions in the proposed provisions are 

warranted. We have limited the 

reporting requirements for N2O to 

engines equipped with NOX

aftertreatment technology as a way to 

reduce the reporting burden on engine 

manufacturers without significantly 

diminishing the amount of information 

we receive. As discussed earlier, 

emissions of N2O are related to catalytic 

treatment of engine exhaust, specifically 

aftertreatment of NOX emissions, and 

we have concluded that collecting N2O 

emissions data from engines without 

NOX aftertreatment technology would 

provide marginal value to the agency. 

We expanded the number of approved 

test methods for N2O measurement 

since we learned from comments and 

our own technical research that our 

proposed test methods for N2O were not 

appropriate for every foreseeable 

circumstance, including measurement 

of very low levels of N2O. We also 

extended the lead time available to 

manufacturers before N2O and CH4

reporting is required. We are providing 

this flexibility based on our conclusion 

that we can reduce the burden of 

purchasing and installing the required 

CH4 and N2O emissions rate 

measurement equipment by extending 

the lead time, without significantly 

diminishing the amount of information 

we receive. Finally, as described above, 

the final rule includes an opportunity 

for a manufacturer to provide EPA with 

appropriate alternative information in 

lieu of N2O and/or CH4 testing. 

Comment: States and environmental 

organizations were generally supportive 

of the proposed reporting requirements, 

although some argued for earlier 

implementation, in 2010. 

Response: We believe that the lead 

times we are finalizing for each GHG 

and for each engine category represent 

the earliest feasible timing, taking into 

consideration existing test capabilities 

and past experience, or the lack thereof. 

Comment: Aircraft engine 

manufacturers commented that 

reporting of CO2 emissions from each 

mode of the LTO 30 cycle used in the 

emission certification test, as proposed, 

is acceptable as long as existing 

methods for CO2 are retained. In 

particular, commenters noted that 

reporting would result in minimal 


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burden as long as CO2 is calculated 

utilizing the engine fuel mass flow rate 

measurements, which are currently part 

of the test procedure requirements for 

the LTO cycle. However, an industry 

trade association expressed concern that 

reporting CO2 from the LTO cycle is 

unjustified because LTO measurements 

do not include CO2 emissions from an 

entire aircraft flight, which is affected 

by the propulsion system, drag, etc. 

Response: We determined that 

calculating aircraft engine CO2

emissions from fuel mass flow rate 

measurements is an appropriate method 

for reporting CO2 emissions. Therefore, 

for turbofan and turbojet engines of 

rated output greater than 26.7 

kilonewtons, we are finalizing that 

manufacturers report CO2 separately for 

each mode of the LTO cycle by 

calculation of CO2 from fuel mass flow 

rate measurements or, alternatively, 

according to the measurement criteria 

for CO2 in Appendices 3 and 5 to ICAO 

Annex 16, volume II. Comprehensive 

and consistent reporting of LTO CO2

emissions, along with knowledge of 

aircraft aerodynamic performance, will 

support modeling of full-flight CO2

emissions and help us to better 

understand overall contributions to 

global warming from aircraft operations. 

Comment: Aircraft engine 

manufacturers raised two major issues 

related to our proposed CH4 reporting. 

First, in response to EPA’s request for 

comment on the degree to which engine 

manufacturers now have the needed 

equipment in their certification test 

cells to measure CH4, manufacturers 

replied that test stands are not currently 

equipped to measure CH4, and thus, 

they would incur additional costs to 

measure CH4. Second, manufacturers 

noted that aircraft jet turbine engines 

have been shown to be consumers of 

CH4 from the ambient air during the 

dominant operating modes (CH4 is 

emitted at aircraft engine idle operation, 

but at higher power modes aircraft 

engines usually consume CH4. Over the 

range of engine operating modes— 

including cruise—aircraft engines are 

typically net consumers of CH4). 

Response: Given that aircraft engines 

are likely net consumers of CH4 and that 

manufacturers do not currently collect 

CH4 data as part of existing test 

procedures, we are not requiring CH4 to 

be measured and reported at this time. 

Comment: We received several 

responses to our request for comment on 

whether to require aircraft engine 

manufacturers to report NOX emissions 

in the four LTO test modes and for the 

overall LTO cycle. Manufacturers 

commented that NOX emissions do not 

need to be reported directly to EPA, 

since this information is already 

voluntarily reported to the International 

Civil Aviation Organization (ICAO) and 

provided to the Federal Aviation 

Administration (FAA), and redundancy 

of reporting is unnecessary. 

Environmental organizations 

commented that EPA should require 

manufacturers to report NOX since they 

currently do not report the data to EPA. 

In addition, environmental 

organizations commented that NOX at 

high altitude can contribute to global 

warming. 

Response: In this final rule, we are 

requiring that engine manufacturers of 

turbofan and turbojet engines of rated 

output greater than 26.7 kilonewtons 

record and report NOX emissions in the 

four LTO test modes and for the overall 

LTO cycles. As discussed in the 

proposal and earlier in this final rule, 

NOX from aircraft have been shown to 

make a potential contribution to climate 

change at high altitude. As required in 

40 CFR part 87, manufacturers must 

already measure and record NOX

emissions in each of the four LTO test 

modes in order to comply with the LTO 

NOX emission standard (for the entire 

LTO cycle). These data are not currently 

reported to EPA for public consideration 

as is the case with all other mobile 

sources. Manufacturers voluntarily 

report the data to ICAO, but there is no 

assurance that EPA will receive this 

information. Likewise, the information 

provided to FAA is not readily 

accessible to EPA, and it is not of the 

detail provided to ICAO. 

Comprehensive and consistent reporting 

of LTO NOX emissions rate data will 

support modeling of overall NOX

emissions from aircraft and help us to 

better understand overall contributions 

to global warming from aircraft 

operations. 

V. Collection, Management, and 

Dissemination of GHG Emissions Data 

This section of the preamble describes 

the general processes by which EPA 

intends to collect, manage, and 

disseminate data under the GHG 

reporting rule. Section A contains a 

brief description of the provisions in the 

final rule concerning these processes, 

and Section B summarizes public 

comments and responses on data 

collection, management, and 

dissemination. 

Major changes since proposal include 

revisions in 40 CFR 98.4 that provide 

flexibility for designated representatives 

to delegate their responsibility to agents, 

and to submit revisions to the certificate 

of representation within 90 days of a 

change in owners or operators (rather 

than 30 days). In addition, the final rule 

includes a requirement that the 

designated representative submit the 

certificate of representation at least 60 

days before the deadline of the facility 

or supplier’s initial GHG report. The 

rationale for these and any other 

significant changes can be found in 

Section V.B of this preamble or in 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments, Designated Representative, 

and Data Collection, Reporting, 

Management, and Dissemination.’’ 

A. Summary of Data Collection, 

Management and Dissemination for the 

Final Rule 

1. Designated Representatives, Alternate 

Designated Representatives, and Agents 

Each covered facility and each 

supplier must identify one and only one 

designated representative who is 

responsible for certifying, signing, and 

submitting all submissions to EPA. A 

designated representative must certify 

and sign a submission, in accordance 

with the final rule, before it is 

considered a complete submission. 

The designated representative also 

serves as a single point of contact for 

EPA to provide information about the 

program or a submission or to ask 

questions about a submission. Those 

facilities submitting any other emission 

report under 40 CFR part 75, for 

example, ARP facilities, must use the 

same designated representative for 

certifying, signing and submitting all 

submissions and reports under this rule. 

Each covered facility or supplier may 

also identify one alternate designated 

representative to act in lieu of the 

designated representative. The alternate 

designated representative can perform 

the same duties as the designated 

representative, but the designated 

representative is responsible for 

ensuring the appropriate information is 

submitted to EPA by the timelines 

specified in the rule. 

A designated representative or 

alternate designated representative may 

delegate the submission of information 

to one or more ‘‘agents.’’ The agent can 

make electronic submissions to EPA, 

but is not allowed to certify or sign a 

submission. By delegating to an agent 

the ability to make electronic 

submissions to EPA, a designated 

representative or alternate designated 

representative agrees that a submission 

to EPA by the agent is deemed to be a 

submission that is certified, signed, and 

submitted by such designated 

representative or alternate designated 

representative. 


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2. Certificate of Representation 

A designated representative must 

submit a certificate of representation 

that identifies the owners and operators 

of the facility or supplier, the designated 

representative, any alternate designated 

representative, and other information as 

specified in 40 CFR 98.4. EPA will 

establish an electronic data reporting 

system that provides for the submission 

of initial, as well as subsequently 

signed, certificates of representation. 

In order to ensure sufficient 

processing time before a facility or 

supplier’s initial GHG report under this 

part, EPA is requiring that the 

designated representative submit a 

certificate of representation at least 60 

days before the deadline for the initial 

GHG report. 

3. Data Collection 

Methods. If a reporting entity already 

reports GHG emissions data to an 

existing EPA program, the Agency will 

make efforts to minimize any additional 

burden on the reporter when developing 

the reporting system for the final rule. 

Some existing programs, however, have 

data collection and reporting 

requirements that are inconsistent with 

the requirements for the mandatory 

GHG reporting rule. When it is not 

feasible to adapt an existing program to 

collect the appropriate GHG data and 

supplemental data, EPA will require 

reporters to submit the data required by 

the mandatory GHG reporting rule to the 

new data reporting system for this rule. 

Such reporters would also continue to 

submit data to the existing reporting 

systems for other applicable programs as 

required by those programs. 

Reporters may fall into one or more 

categories: 

(1) Reporters that use existing data 

collection and reporting methods and 

will not be required to report separately 

to the new data reporting system for the 

GHG reporting rule. 

(2) Reporters that use existing data 

collection and reporting methods but 

will be required to report the data 

separately to the new data reporting 

system for the GHG reporting rule. 

(3) Reporters that are not currently 

required to collect and report GHG 

emissions data to EPA and will be 

required to report using the new data 

reporting system for the mandatory GHG 

reporting rule. 

For categories (2) and (3), EPA is 

developing a new system for reporters to 

submit the required data. The detailed 

data elements that must be reported are 

specified in the rule. In general, 

reporters using this new system must 

report annually to the Agency according 

to the schedule specified in 40 CFR 

98.3(b). 

Data Submission. The Designated 

Representative (described in 40 CFR 

98.4) must use an electronic signature 

device (for example, a personal 

identification number (PIN) or 

password) to submit a report. If the 

Designated Representative holds an 

electronic signature device that is 

currently used for valid electronic 

signatures accepted under another 

Agency program, we intend to design 

the new reporting system to also accept 

valid electronic signatures executed 

with that device where feasible. (See 40 

CFR 3.10 and the definitions of 

‘‘electronic signature device’’ and ‘‘valid 

electronic signature’’ under 40 CFR 3.3.) 

Unique Identifiers for Facilities and 

Units. The Agency’s reporting format for 

a given reporting year could make use 

of several ID codes—unique codes for a 

unit or facility. To ensure proper 

matching between databases, e.g., EPAassigned facility ID codes and the Office 

of Regulatory Information Systems 

(ORIS) (DOE) ID code, and consistency 

from one reporting year to the next, we 

plan for the reporting system to provide 

each facility with a unique 

identification code to be specified by 

the Administrator. 

Reporting Emissions in a Single Unit 

of Measure. To maintain consistency 

with existing State-level and Federallevel GHG programs in the U.S. and 

internationally, all emission 

measurements must be reported in the 

SI, also referred to as metric units. Data 

used in calculations and supplemental 

data for QA could still be submitted in 

English weights and measures (e.g., 

mmBtu/hr) but the specific units of 

measure must be included in the data 

submission. All emissions data must be 

submitted to the Agency in kg or metric 

tons per unit of time. 

Conversion of Emissions to CO2e. 

Reporters must submit the quantity of 

each applicable GHG emitted (or other 

metric such as quantities supplied for 

industrial GHG suppliers) in two forms. 

The data will be in the form of quantity 

of the gas emitted (e.g., metric tons of 

N2O) per unit of time and CO2e 

emissions per unit of time. 

Delegation of Authority to State 

Agencies to Collect GHG Data. Reporters 

must submit the emissions data and 

supplemental data directly to EPA. At 

this time, EPA does not intend to 

delegate the authority to collect data to 

State or local agencies. 

Submission Method. All entities 

covered by this rule must report in an 

electronic format to be specified by the 

Administrator. The electronic format, 

which will reflect the underlying 

electronic data reporting system, will be 

developed prior to the first reporting 

date. By specifying in the rule text the 

exact information that must be reported 

but not specifying the exact reporting 

format, EPA informs reporters about 

exactly what information they must 

report and has flexibility to modify the 

electronic reporting format and 

electronic data reporting system in a 

timely manner based on implementation 

experience and new technology. EPA 

has used this approach successfully in 

existing programs, such as the ARP and 

the Title VI Stratospheric Ozone 

Protection Program, facilitating the 

deployment of new reporting formats 

and reporting systems that take 

advantage of technologies such as, 

eXtensible Markup Language (XML), 

and reducing the burden on reporters 

and the Agency. The electronic reports 

submitted under this rule are subject to 

the provisions of 40 CFR part 3, 

specifying EPA systems to which 

electronic submissions must be made 

and the requirements for valid 

electronic signatures. 

4. Data Management 

QA Procedures. The new reporting 

system will include automated checks 

for data completeness, data quality, and 

data consistency. Such automated 

checks are used for many other Agency 

programs (e.g., ARP). 

Providing Feedback to Reporters. EPA 

has established a variety of mechanisms 

under existing programs to provide 

feedback to reporters who have 

submitted data to the Agency. EPA will 

consider the approaches used by other 

programs (e.g., electronic confirmations, 

results of QA checks) and develop 

appropriate mechanisms to provide 

feedback to reporters for the GHG 

reporting rule when we develop the 

electronic data reporting system. 

Regardless of data collection system 

specifics, the goal is to ensure 

appropriate transparency and timeliness 

when providing feedback to reporters 

who submitted data. 

5. Data Dissemination 

Public Access to Emissions Data. The 

Agency plans to publish data submitted 

or collected under this rulemaking 

through EPA’s Web site, reports, and 

other formats (e.g., XML), with the 

exception of any confidential business 

information (CBI) data. For further 

discussion of CBI, see Section II.R of 

this preamble. 

EPA will disseminate data after the 

reporting deadline. The Agency 

recognizes the high level of public 

interest in this data and plans to 

disclose it in a timely manner, while 


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also assuring completeness and 

accuracy. 

Sharing Emission Data with Other 

Agencies. There are a growing number 

of programs at the State, Tribe, 

Territory, and local level that require 

emission sources in their respective 

jurisdictions to monitor and report GHG 

emissions. In order to be consistent with 

and supportive of these programs and to 

reduce burden on reporters and program 

agencies, EPA plans to share emissions 

data, with the exception of any CBI data, 

with relevant agencies or approved 

entities using, where practical, common 

data exchange standards and 

infrastructure. 

B. Summary of Comments and 

Responses on Collection, Management, 

and Dissemination of GHG Emissions 

Data 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on data 

collection, management, and 

dissemination were received covering 

numerous topics. Responses to 

significant comments received can be 

found in ‘‘Mandatory Greenhouse Gas 

Reporting Rule: EPA’s Response to 

Public Comments, Designated 

Representative and Data Collection, 

Reporting, Management, and 

Dissemination.’’ 

1. Designated Representatives, 

Alternative Designated Representatives, 

and Agents 

Designated Representatives 

Comment: Several commenters 

requested that EPA use the ARP 

definition for designated representatives 

to maintain consistency across the two 

EPA programs and provide more 

flexibility regarding who can be a 

designated representative. Other 

commenters requested that EPA use the 

responsible official definition from Title 

V or senior management official from 

TRI to maintain consistency with those 

programs. Other commenters raised 

concerns over the employment status of 

designated representatives. 

Comment: A commenter noted that 

rule language was inconsistent in 

defining the relationships between 

designated representatives, facilities and 

suppliers, and owners and operators. 

Response: EPA agrees that owners and 

operators should have more flexibility 

to identify a designated representative, 

including third-party representatives. 

EPA is striking the language requiring 

the designated representative to be a 

person responsible for the overall 

operation of the facility or supplier. 

Further, EPA is not requiring the use of 

a responsible official or senior 

management official because either 

approach would be more restrictive than 

the designated representative definition 

of the final rule. EPA believes that the 

proposed rule was neutral with respect 

to the employment status of the 

designated representative. The final rule 

provides flexibility for the owners and 

operators to choose any individual, 

employee or non-employee, to represent 

them. EPA modified the rule to clarify 

that each facility and each supplier shall 

have one and only one designated 

representative and that the designated 

representative must be authorized by 

binding agreement of the owners and 

operators. 

Agents 

Comment: Several commenters 

requested that EPA allow designated 

representatives and alternate designated 

representatives the option of delegating 

their responsibility to prepare and 

submit reports to EPA to a preparer or 

agent. Commenters also stated that the 

designated representative requirement is 

inconsistent with Title V reporting. 

Response: EPA agrees that it is 

beneficial to give the designated 

representatives and alternate designated 

representatives flexibility concerning 

who prepares the reports that they are 

responsible for submitting. The final 

rule does not specify who must prepare 

reports, but only specifies who must 

certify, sign, and submit them. EPA also 

agrees that flexibility should be 

provided concerning who actually 

submits the reports, similar to the 

flexibility provided in the ARP. This 

flexibility was implied in the provision 

in the proposed rule that reports be 

submitted ‘‘in a format specified by the 

Administrator,’’ which format has 

included, in other programs such as the 

ARP, the ability to use agents. However, 

EPA decided to make this flexibility 

explicit by including in the rule 

provisions allowing and setting 

requirements for agents selected by 

designated representatives or alternate 

designated representatives. The 

structure of designated representative, 

alternate designated representative and 

agent fits a wide range of circumstances 

from large companies to small, 

including those accustomed to reporting 

under Title V. 

Certification Statement 

Comment: Several commenters 

described the self-certification 

procedures in the proposed rule as too 

restrictive or suggested that the rule 

should be consistent with requirements 

of the Title V or TRI program. For 

example, the rule’s requirement that the 

designated representative certify that 

they have ‘‘personally examined’’ the 

data should be replaced by the Title V 

requirement that a responsible official 

certify that they have made a 

‘‘reasonable inquiry’’ as to the accuracy 

of the data. 

Response: EPA believes that the high 

level of public interest in the data 

collected under this rule, as well as its 

importance to future policy, warrants 

establishment, by rule pursuant to CAA 

Sections 114, 208, and 301(a)(1), of a 

high standard for data quality and 

consistency and a high level of 

accountability for reported data, which 

will help ensure that the data quality 

and consistency standard is met. The 

certification requirements set forth in 

this rule are similar to the ARP (Title 

IV). EPA has successfully implemented 

this approach in the ARP and found that 

it provides a high degree of both data 

quality and consistency and 

accountability. 

2. Certificate of Representation 

Comment: One commenter requested 

that EPA designate a deadline for the 

submission of the certificate of 

representation to ensure sufficient time 

to process the submissions. 

Response: EPA agrees that an earlier 

deadline for submitting certificates of 

representation is advisable to provide 

additional lead time to process the 

certificates and, if necessary, verify 

identities and resolve issues. Because 

any delay in processing a certificate of 

representation could delay the 

submission of data, EPA is requiring 

that the designated representative 

submit the initial certificate of 

representation at least 60 days prior to 

the deadline for a facility or supplier’s 

initial GHG report. 

Comment: Several commenters noted 

that a certificate of representation for 

each facility and supplier is 

burdensome either due to timing with 

the annual report, the need to maintain 

current information, or ambiguities as to 

whether the certificate is complete. 

Commenters also requested that 

reporters be allowed more than 30 days 

to submit a revised certificate of 

representation in the event of a change 

in operators or owners. 

Comment: Several commenters 

requested that EPA provide an 

electronic system for submitting and 

processing certificates of representation. 

Response: EPA does not agree that 

certificates of representation are 

unnecessary or overly burdensome or 

that there should be any uncertainty as 

to whether a certificate of representation 

is complete. The information required 

on the certificate of representation is 


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listed in the rule and should be well 

known to the owners and operators of 

the facility or supplier. It is the 

responsibility of the individual 

submitting the certificate to ensure its 

completeness. This certificate of 

representation has been used 

successfully for over a decade in the 

ARP. 

To minimize burden, the electronic 

data reporting system will provide the 

means to electronically submit both the 

initial and any subsequent certificate of 

representation. EPA agrees that 

reporters should be allowed more time 

to update changes in owners or 

operators but does not agree that doing 

so in the annual report is sufficient. The 

designated representative is the primary 

point of contact between the owners and 

operators and the EPA. However, the 

owners and operators are ultimately 

responsible for compliance with the 

requirements of reporting rule, and it is 

therefore essential that the information 

in the certificate of representation be 

timely and accurate in the event EPA 

finds it necessary to contact the owners 

and operators of the facility or supplier 

during periods in between the 

submission dates of the annual reports, 

for example, to perform an audit. The 

final rule allows reporters up to 90 days 

to submit a revised certificate of 

representation when a change in owners 

or operators occurs. In addition, EPA 

modified both the owner definition and 

rule to clarify that the certificate of 

representation does not need to list 

persons whose legal or equitable title to 

or leasehold interest in a facility or 

supplier arises solely because they are 

limited partners in a partnership with 

legal or equitable title to, a leasehold 

interest in, or control of, the facility or 

supplier. 

3. Data Collection Methods 

Comment: Several commenters 

requested that EPA use current emission 

inventory reporting programs (e.g., NEI) 

to handle data collection or to sunset 

the GHG reporting rule, and instead use 

such programs, after five years. 

Response: EPA is requiring electronic 

reports to be submitted directly to EPA 

using a new data reporting system for 

the GHG reporting rule. The rationale 

for the decision to report directly to EPA 

is contained in Sections II.N (emissions 

verification) and VI.B (compliance and 

enforcement) of this preamble. EPA 

recognizes the value of integrating the 

GHG data reported under this rule with 

other emission reporting programs. NEI, 

for example, plans to incorporate the 

GHG emissions data from this 

collection, as feasible. 

Comment: Commenters requested that 

the design of the new data system be 

modeled on existing electronic reporting 

programs, incorporate measures to 

handle system errors, and provide 

opportunities for testing and user 

training. 

Response: EPA agrees that a national 

electronic emissions database should be 

the basis for receiving GHG data, and 

that the ARP database provides a useful 

model for a future GHG emissions 

database. Data would be provided to 

EPA electronically to reduce the burden 

on the reporters and EPA, and to 

increase the accuracy of the reported 

emissions, among other reasons. The 

issue of transmission failures and 

transmission errors will be addressed in 

the development of the electronic 

reporting system. EPA agrees that is it 

important for data reporters to be able 

to confirm that their data were accepted 

by the system and to compare the data 

in the system to the data that they 

reported to ensure it was accurately 

incorporated into the database. The new 

data system will meet Agency 

requirements for security and hosting. 

EPA acknowledges comments 

supporting a ‘‘user friendly’’ reporting 

system. EPA plans to follow well known 

design practices within the constraints 

of security, accessibility and Agency 

design requirements. 

EPA agrees with commenters on the 

need for testing and user training. We 

will continue the outreach effort 

undertaken during this rulemaking to 

encourage stakeholder participation in 

‘beta’ testing and training opportunities. 

Unique Identifiers for Facilities and 

Units 

Comment: Several commenters 

requested that EPA assign and track 

corporate identifiers for reporting 

facilities to facilitate corporate-level 

analysis of emission data. Commenters 

also requested that EPA publish a list of 

identifiers for all EPA programs that a 

covered facility may report to. 

Response: EPA is collecting owner 

and operator information through the 

Certificate of Representation (40 CFR 

98.4). At this time, EPA is not proposing 

to assign unique identifiers to the 

owners and operators because of the 

complexity of ownership structures 

(including percentage shares of owners, 

subsidiaries, holding companies, and 

limited liability partnerships) that can 

be used in the multiplicity of industrial 

sectors required to report emission data 

under this rule. Although as explained 

earlier in the preamble, we are exploring 

options for adding additional data 

elements to the reports, such as name of 

parent company and NAICS code(s), to 

allow easier aggregation of facility-level 

data to the corporate level under this 

program. EPA expects to subject any 

additional requests to notice and 

comment rulemaking. 

EPA’s Facility Registry System (FRS) 

links EPA program identification 

numbers under a unique facility record. 

The FRS database is publicly available 

to queries from the EPA.GOV Web site 

under the Envirofacts Data Warehouse 

home page: http://www.epa.gov/enviro/ 

html/fii/fii_query_java.html. Descriptive 

information about FRS can be found at: 

http://www.epa.gov/enviro/html/fii/ 

index.html. FRS may be searched by 

program identification, facility name or 

geographic location. The Agency will 

continue to make FRS and all program 

identification numbers readily available 

and will include the facilities reporting 

under this rule in the FRS collection of 

program ID’s once public release of the 

data is authorized. 

Submission Method 

Comment: Several commenters 

requested that EPA specify the format of 

the data collection methods and subject 

it to public comment before finalizing 

the rule. These commenters indicated 

that without the details of the data 

collection methods it was not possible 

to evaluate the GHG reporting rule, 

including implementation costs and 

reporting burden. 

Response: The final rule requires 

reports to be submitted ‘‘in a format 

specified by the Administrator.’’ EPA is 

thereby retaining the flexibility to 

specify the electronic format, and the 

underlying electronic reporting system 

reflected in the format, after 

promulgation of this rule but well before 

the first reporting deadline and, if 

necessary, to change the electronic 

format and electronic reporting system 

based on implementation experience 

and new technology. Several other 

reporting programs (e.g., ARP) use a 

similar approach where the specific 

electronic reporting system is not 

included within the rule or subjected to 

formal notice and comment. The 

relevant subparts of the proposed GHG 

reporting rule specified the data 

elements that each entity must report, 

and therefore parties could evaluate the 

reporting burden and costs under the 

proposed rule and had an opportunity 

to comment on that aspect of the 

proposed rule. In addition, before 

specifying the electronic format and 

underlying electronic reporting system, 

EPA will conduct outreach and provide 

opportunities for stakeholder feedback 

on the specific reporting format and 

reporting system. 


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Comment: Several commenters 

requested that EPA provide alternative 

methods to report emission data, 

including paper submissions, scanned 

documents, and direct data upload. 

Response: EPA is requiring electronic 

reporting of the GHG and supplemental 

data to increase the accuracy and 

timeliness of the reported emission data 

and is not providing options for paper 

or scanned GHG reports. Requiring 

electronic submission of data allows 

EPA to conduct electronic QA testing of 

all such data when it is received and to 

provide electronic feedback to the 

reporters almost instantaneously. This 

gives reporters the opportunity to 

correct any errors, or to provide 

explanations of potentially problematic 

data, within a short time frame, thereby 

increasing the accuracy and timeliness 

of the data. Moreover, electronically 

submitted data can be readily sorted and 

analyzed by EPA and members of the 

public. In contrast, submission of 

hardcopy data (whether in paper or 

scanned documents) would make audit 

and correction, as well as sorting and 

analysis, of the data much more 

cumbersome, inefficient, and time 

consuming. Indeed, particularly in light 

of the large number of facilities and 

suppliers that will be reporting and the 

large amounts of reported data that will 

be received as a result, the ability to 

audit and analyze the data received in 

hardcopy format would likely be 

significantly limited. This would 

adversely affect the usefulness, as well 

as the accuracy and timeliness of the 

data. 

In requiring electronic data 

submission, EPA will provide a Webbased reporting system to guide 

reporters through the data entry, 

emission calculation, and submission 

process. This reporting system will 

conform to EPA information technology 

standards and 40 CFR part 3. In 

addition, EPA will provide a 

mechanism for reporters to submit data 

files directly to EPA using a standard 

format (e.g., XML) to be prescribed by 

the Administrator before the first 

reporting date. To reduce the burden on 

reporters and reduce errors, EPA will 

conduct outreach and training for 

reporters on the reporting format and 

underlying reporting systems. EPA will 

also provide a hotline to answer 

questions about the program and 

reporting format and reporting systems. 

EPA expects that most reporters affected 

by this rule are already familiar with 

Web-based or electronic reporting 

systems through other EPA programs. 

Delegation of Authority to State 

Agencies To Collect GHG Data 

Comment: Several commenters 

requested that EPA delegate rule 

implementation, including data 

collection, to State and local agencies. 

These commenters indicated that 

several States already have GHG 

reporting requirements and have 

systems in place to collect and verify 

this data, and suggested that delegation 

of the rule could help reduce 

inconsistency or duplication of effort 

between State programs and this Federal 

mandatory GHG reporting rule. Other 

commenters supported requiring 

facilities to submit data directly to EPA, 

without delegation of data collection to 

State and local agencies, in order to 

provide national consistency. 

Response: EPA is requiring electronic 

reports to be submitted directly to EPA, 

and is not delegating data collection to 

State and local agencies. The rationale 

for this decision is provided in Section 

VI.B of this preamble. 

5. Data Dissemination 

Public Access to Emissions Data 

Comment: Several commenters 

supported EPA’s proposal to make the 

data submitted under the reporting rule 

available to the public. Some requested 

that data be published in real time, 

while others requested the data be 

released in a timely manner. 

Response: With the exception of CBI, 

EPA intends to make data submitted 

under this program available to the 

public in a timely manner after the 

reports have been submitted and EPA 

has completed QA/QC of the data. To 

that end, EPA intends to establish a new 

reporting system that will accept 

electronic submissions of GHG 

emissions and supporting data and 

facilitate EPA’s verification of the 

submissions. EPA plans to provide 

public access to the data by posting 

electronic data on a Web site in a timely 

manner after the reporting deadline. 

This level of transparency is important 

to public participation in future policy 

development and for building public 

confidence in the quality of the data 

collected. 

Sharing Emissions Data With Other 

Agencies 

Comment: Some commenters stressed 

that electronic data reporting systems 

need to be consistent and inter-operable 

and allow data exchange between TCR, 

State rules, NEI, ARP, other 

stakeholders and EPA. 

Response: EPA will continue to 

coordinate with other Federal, State, 

and regional programs and will make 

efforts to facilitate data exchange when 

designing the data reporting system that 

will be used for the GHG reporting rule. 

EPA intends to employ inter-operable 

data exchange standards. EPA intends to 

design and manage the GHG data 

collection to take advantage of existing 

efforts on data exchange standards and 

to work with stakeholder groups to 

promote the easy exchange and sharing 

of the data collected under this rule. For 

example, EPA is extending the 

Consolidated Emissions Reporting 

Schema (CERS), currently in use by the 

EPA’s NEI program, to support data 

reporting and publication under this 

rule. EPA also intends to use existing 

tools, such as FRS and SRS, to ensure 

data consistency. 

To the extent possible, EPA will 

consider existing reporting systems and 

work with those programs and systems 

to develop a reporting scheme that 

facilitates data exchange. EPA 

anticipates that this coordination will 

reduce the burden of reporting for both 

reporters and government agencies. 

However, as explained in Section II.O of 

this preamble, the various reporting 

programs do not have identical data 

needs and requirements. Therefore, at 

this time, it is not possible for 

companies reporting under State and 

Federal rules and voluntary programs to 

file a single report that will satisfy all 

reporting requirements. 

Comment: Commenters requested that 

the data system utilize common 

standards, such as XML and geographic 

identifiers, and provide descriptive text 

wherever codes or abbreviations are 

used. 

Response: EPA agrees that publishing 

the results of this data collection using 

common, standards-based schemas and 

formats will promote the exchange of 

data between EPA, States and other 

entities. The published results will 

include the latitude and longitude of 

facilities as well as help text with 

definitions of codes and abbreviations. 

VI. Compliance and Enforcement 

This section of the preamble generally 

describes the compliance assistance and 

enforcement activities EPA intends to 

implement for the GHG reporting rule 

and summarizes public comments and 

responses on compliance assistance, 

role of the States, and enforcement. 

A. Compliance and Enforcement 

Summary 

1. Compliance Assistance 

EPA plans to conduct an active 

outreach and technical assistance 

program following publication of the 

final rule. The primary audience is 


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31The Federal Civil Penalties Inflation 

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

Stat. 890, 28 U.S.C. 2461, note, as amended by 

Section 31001(s)(1) of the Debt Collection 

Improvement Act of 1996, Public Law 104–134, 110 

Stat. 1321–373, April 26, 1996, requires EPA and 

other agencies to adjust the ordinary maximum 

penalty that it will apply when assessing a civil 

penalty for a violation. Accordingly, EPA has 

adjusted the CAA’s provision in Section 113(b) and 

(d) specifying $25,000 per day of violation for civil 

violations to $37,500 per day of violation. 

potentially affected industries. We 

intend to develop implementation and 

outreach materials and training to help 

potential reporters understand whether 

the rule applies to them and explain the 

reporting requirements and timetables. 

The program particularly will target 

industrial, commercial, and institutional 

sectors that do not routinely deal with 

air pollution regulations. 

Compliance materials will be tailored 

to the needs of various sectors. These 

materials might include, for example, 

fact sheets, information sheets, plain 

English guides, frequently asked 

question and answer documents, 

applicability tools, monitoring and 

recordkeeping checklists, and training 

on rule requirements and the electronic 

reporting system. We also expect to 

implement a compliance assistance 

e-mail and telephone hotline for 

answering questions and providing 

technical assistance. Note that while 

EPA plans to issue compliance 

assistance materials, reporters should 

always consult the final rule to resolve 

any ambiguities or questions. 

2. Role of the States 

While EPA does not intend to 

formally delegate data collection and 

enforcement of the GHG reporting rule 

to State agencies, EPA will likely enlist 

State assistance, when it is available, for 

outreach and compliance assistance 

with the final rule. (However, State and 

local agencies will not be required to 

provide EPA any assistance with these 

activities, given State and local agency 

resource constraints and priorities.). 

State and local air pollution control 

agencies routinely interact with many of 

the sources that would report under this 

rule. Further, several States have 

experience implementing State 

mandatory GHG reporting and reduction 

programs. Therefore, we plan to work 

with those State and local agencies that 

are able to assist EPA to define their role 

in communicating the requirements of 

the rule and providing compliance 

assistance. In concert with their routine 

inspection and other compliance and 

enforcement activities for other CAA 

programs, State and local agencies may 

also be able to assist with educating 

facilities and assuring compliance at 

facilities subject to this rule. 

3. Enforcement 

Facilities or suppliers that fail to 

monitor or report GHG emissions, 

quantities supplied, or other data 

elements according to the requirements 

of the applicable rule subparts could 

potentially be subject to enforcement 

action by EPA under CAA sections 113 

and 203–205. The CAA provides for 

several levels of enforcement that 

include administrative, civil, and 

criminal penalties. The CAA allows for 

injunctive relief to compel compliance 

and civil and administrative penalties of 

up to $37,500 per day per violation.31

Actions (or inactions) that could 

ultimately be considered violations 

include but are not limited to the 

following: 

• Failure to report GHG emissions 

(for suppliers, the emissions that would 

result from combustion or use of the 

products they supply). 

• Failure to collect data needed to 

calculate GHG emissions. 

• Failure to continuously monitor 

and test as required. Note that merely 

filling in missing data as specified does 

not excuse a failure to perform the 

monitoring or testing. 

• Failure to calculate GHG emissions 

according to the methodology(s) 

specified in the rule. 

• Failure to keep required records 

needed to verify reported GHG 

emissions. 

• Falsification of reports. 

B. Summary of Public Comments and 

Responses on Compliance and 

Enforcement 

This section contains a brief summary 

of major comments and responses. A 

large number of comments on 

compliance and enforcement were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, 

Compliance and Enforcement.’’ 

1. Role of States in Compliance and 

Enforcement 

Comment: Several commenters 

requested that EPA delegate rule 

implementation, including data 

collection, emissions verification, and 

enforcement of the rule to State and 

local agencies. These commenters 

indicated that several States already 

have GHG reporting requirements and 

have systems in place to collect and 

verify these data, and they suggested 

that delegation of the rule could help 

reduce inconsistency or duplication of 

effort between State programs and this 

Federal mandatory GHG reporting rule. 

However the majority of commenters, 

including industry, environmental 

organizations, and many public citizens 

supported requiring facilities to submit 

data directly to EPA, without delegation 

of data collection or emissions 

verification to State and local agencies, 

in order to provide national consistency. 

Response: Section 114(b) of the CAA 

allows EPA to delegate to States the 

authority to implement and enforce 

Federal rules. At this time, however, 

EPA does not propose to formally 

delegate implementation of the rule 

(such as data collection and 

enforcement activities) to State and 

local agencies, as discussed in Section 

II.O of this preamble. The goal of data 

collection under this rule is to establish 

a consistent, verified, national data set 

that is available to EPA, States, other 

agencies, policy makers, and the public 

for use in developing and implementing 

future GHG policies and reduction 

programs. To meet these data 

consistency and timeliness constraints, 

and to serve policy objectives, it is most 

efficient to have the data submitted 

directly into one central EPA system 

and have centralized emissions data 

verification. Direct reporting to EPA will 

also help us better understand and 

address common compliance problems 

that may arise from the GHG reporting 

rule. 

EPA recognizes that several States 

already have mandatory GHG reporting 

programs that are broader in scope, in 

a more advanced state of development, 

and have different policy objectives 

than this rulemaking. These are 

important programs that not only led 

the way in reporting of GHG emissions 

before the Federal government acted but 

also have catalyzed important GHG 

reductions. 

As discussed in Section II.O of this 

preamble, we are committed to working 

with States and other groups (e.g, TCR, 

Environmental Council of the States 

(ECOS)) to develop electronic reporting 

tools that can both collect and share 

data in an efficient and timely manner. 

At this time, EPA is in the process of 

developing the reporting format and 

tools and therefore has not specified the 

exact reporting format, other than it will 

be electronic, in order to maintain 

flexibility to modify the reporting 

format and tools in a timely manner. To 

the extent possible, EPA will work with 

existing reporting programs and systems 

to develop a reporting scheme that 

minimizes the burden on sources. 

While EPA is not delegating authority 

to the States, we will work with States 

as we develop rule implementation 

plans to determine appropriate 


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implementation roles, such as assisting 

with outreach efforts and site visits to 

audit facility reports. For related 

comments and responses, please see the 

following sections of this preamble: II.N 

(verification approach), II.O (role of 

States) and II.R (CBI). 

2. Enforcement 

Comment: Some commenters 

suggested that States should be allowed 

to participate in the enforcement of the 

GHG reporting rule, perhaps through 

delegated enforcement authority. 

Response: EPA welcomes States’ 

interest in helping EPA enforce this or 

any other Federal rule and we will work 

with States to determine appropriate 

roles as described above. We do not 

plan to delegate the enforcement of this 

rule in the same sense that we do under 

other CAA programs such as the 

NESHAP program in which, for 

example, notices may be sent only to the 

delegated States. If a State would like 

the authority to enforce this rule, then 

the State may adopt the provisions of 

this GHG reporting rule into State laws 

or regulations by reference. This would 

make the provisions enforceable as a 

matter of State law which can be 

enforced in a State court. 

Comment: Some commenters stated 

that they should be able to petition EPA 

to enforce against violators where they 

have evidence of or suspect violations. 

Response: EPA welcomes any tips 

from citizens about suspected violations 

of this or any rule through our tips Web 

site, http://www.epa.gov/tips. However, 

we are not including a formal petition 

process in the rule because such a 

process was not proposed. We do not 

favor a formal petition process because 

a formal petition is not necessary for us 

to investigate concerns raised by 

citizens and such a process might take 

extra time or divert resources from other 

priorities. 

Comment: Some commenters stated 

that a flexible enforcement policy is 

needed. They noted that the proposed 

rule cited the CAA for the authority for 

the GHG reporting rule and stated that 

a violation of the reporting rule is a 

violation of the CAA and subject to 

maximum daily penalties allowed under 

the CAA. However, the commenters 

were concerned that the maximum 

penalty should not be applied in most 

cases and argued that there are many 

instances when a less severe action is 

appropriate. 

Response: EPA agrees with the 

commenters that flexibility is needed in 

enforcing the rule. The penalty cited in 

the proposal preamble and rule is a 

statutory maximum, and would not be 

applied in every case. EPA’s objective 

with the reporting rule is to collect 

accurate GHG data in a timely manner. 

In order to achieve that objective, EPA 

will generally work with sources that 

must submit GHG reports in order to 

facilitate compliance and provide the 

needed data to EPA. The CAA allows 

EPA discretion to pursue a variety of 

informal and formal actions in order to 

achieve compliance. While EPA is 

committed to working with reporters to 

ensure accuracy, this does not relieve 

reporters from their obligation to report 

data that are complete, accurate, and in 

accordance with the requirements of 

this rule. 

In many instances, based on past 

enforcement experience, less punitive 

enforcement actions are exhausted 

before more punitive fines and penalties 

are imposed on a non-complying source. 

These less punitive actions may include 

a warning to the source that it is in noncompliance along with advice on what 

needs to be done to comply and a 

request for response from the facility. 

Initial actions may also include a formal 

legal notification from EPA that defines 

the violation, provides evidence, and 

requires (orders) corrective actions by 

specific dates. The EPA enforcement 

office always uses discretion and takes 

case-specific circumstances into account 

when determining the appropriate 

actions to address violations of CAA 

rules. We will continue to do so in 

enforcing the reporting rule, and we are 

not laying out a specific enforcement 

policy or hierarchy in order to maintain 

the necessary flexibility. 

VII. Economic Impacts on the Rule 

This section of the preamble examines 

the costs and economic impacts of the 

GHG reporting rule, including the 

estimated costs and benefits of the rule, 

and the estimated economic impacts of 

the rule on affected entities, including 

estimated impacts on small entities. 

Complete detail of the economic 

impacts of the final rule can be found 

in the text of the Regulatory Impact 

Analysis (RIA) for the final rule (EPA– 

HQ–OAR–2008–0508). 

This section also contains a brief 

summary of major comments and 

responses. A large number of comments 

on economic impacts of the rule were 

received covering numerous topics. 

Responses to significant comments 

received can be found in ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments, Cost and 

Economic Impacts of the Rule.’’ 

A. How were compliance costs 

estimated? 

1. Summary of Method Used To 

Estimate Compliance Costs 

EPA estimated costs of complying 

with the rule for reporting process 

emissions of GHGs in each affected 

industrial facility, as well as emissions 

from stationary combustion sources at 

industrial facilities and other facilities, 

GHG and supply data from fuel 

suppliers and industrial gas suppliers, 

and GHG data for mobile sources. 2006 

is the representative year of the analysis 

in that the annual costs were estimated 

using the 2006 population of emitting 

sources. EPA used available industry 

and EPA data to characterize conditions 

at affected sources. Incremental 

monitoring, recordkeeping, and 

reporting activities were then identified 

for each type of facility and the 

associated costs were estimated. 

The costs of complying with the rule 

will vary from one facility to another, 

depending on the types of emissions, 

the number of affected sources at the 

facility, existing monitoring, 

recordkeeping, and reporting activities 

at the facility, etc. The costs include 

labor costs for performing the 

monitoring, recordkeeping, and 

reporting activities necessary to comply 

with the rule. For some facilities, costs 

include costs to monitor, record, and 

report emissions of GHGs from 

production processes and from 

stationary combustion units. For other 

facilities, the only emissions of GHGs 

are from stationary combustion. EPA’s 

estimated costs of compliance are 

discussed in greater detail below: 

Labor Costs. The costs of complying 

with and administering this rule include 

time of managers, technical, and 

administrative staff in both the private 

sector and the public sector. Staff hours 

are estimated for activities, including: 

• Monitoring (private): Staff hours to 

operate and maintain emissions 

monitoring systems. 

• Reporting (private): Staff hours to 

gather and process available data and 

reporting it to EPA through electronic 

systems. 

• Assuring and releasing data 

(public): Staff hours to quality assure, 

analyze, and release reports. 

Staff activities and associated labor 

costs will potentially vary over time. 

Thus, cost estimates are developed for 

start-up and first-time reporting, and 

subsequent reporting. Wage rates to 

monetize staff time are obtained from 

the Bureau of Labor Statistics (BLS). 

Equipment Costs. Equipment costs 

include both the initial purchase price 

of monitoring equipment and any 


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facility/process modification that may 

be required. For example, the cost 

estimation method for mobile sources 

involves upstream measurement by the 

vehicle manufacturers. This may require 

an upgrade to their test equipment and 

facility. Based on expert judgment, the 

engineering costs analyses annualized 

capital equipment costs with 

appropriate lifetime and interest rate 

assumptions. Cost recovery periods and 

interest rates vary by industry, but 

typically, one-time capital costs are 

amortized over a 10-year cost recovery 

period at a rate of seven percent. 

2. Summary of Comments and 

Responses 

Comment: A majority of the 

comments received on the compliance 

costs of the reporting rule focused on 

facility level costs for monitoring and 

reporting. Commenters noted that costs 

estimated for a representative facility 

may differ from actual facility level 

costs. Some commenters specifically 

referred to the costs associated with 

installing and maintaining capital 

equipment. Other commenters noted 

that some source categories had higher 

estimated compliance costs than others. 

Several commenters expressed 

confusion over how combustion related 

monitoring costs are added to process 

related monitoring costs. 

Response: EPA recognizes that the 

costs presented for facilities represent 

costs that would be incurred by a 

representative facility, and may not 

reflect the costs that would be incurred 

by each individual facility in each 

industry because facilities affected by 

each subpart vary. 

Nevertheless, after reviewing the 

comments received, EPA has 

determined that its analysis provides a 

reasonable characterization of costs for 

facilities affected by each subpart and 

that its documentation provides 

adequate documentation of how the 

costs were estimated. As described in 

the next section, EPA collected and 

evaluated cost data from multiple 

sources, and weighed the analysis 

prepared at proposal against the input 

received through public comments. In 

any analysis of this type, there will be 

variations in costs among facilities, and 

after thoroughly reviewing the available 

information, we have concluded that the 

costs developed for this rule 

appropriately reflect a ‘‘representative 

facility’’ in the sector. 

The costs facing facilities in some 

sectors include not only process costs 

but additional costs associated with 

other subparts of the rule. While these 

costs are presented individually in 

Section 4 of the RIA for the final rule, 

where these conditions apply the costs 

are summed across applicable subparts 

and compared to revenues in the 

economic and small entity impact 

analyses. 

B. What are the costs of the rule? 

1. Summary of Costs 

For the cost analysis, EPA gathered 

existing data from EPA, industry trade 

associations, States, and publicly 

available data sources (e.g., labor rates 

from the BLS) to characterize the 

processes, sources, sectors, facilities, 

and companies/entities affected. EPA 

also considered cost data submitted in 

public comments on the proposed rule, 

as further discussed in Section VII.B.2 

of this preamble. Costs were estimated 

on a per entity basis and then weighted 

by the number of entities affected at the 

25,000 metric tons CO2e threshold. 

To develop the costs for the rule, EPA 

estimated the number of affected 

facilities in each source category, the 

number and types of combustion units 

at each facility, the number and types of 

production processes that emit GHGs, 

process inputs and outputs (especially 

for monitoring procedures that involve 

a carbon mass balance), and the 

measurements that are already being 

made for reasons not associated with the 

rule (to allow only the incremental costs 

to be estimated). Many of the affected 

source categories, especially those that 

are the largest emitters of GHGs (e.g., 

electric utilities, industrial boilers, 

petroleum refineries, cement plants, 

iron and steel production, pulp and 

paper) are subject to national emission 

standards and we use data generated in 

the development of these standards to 

estimate the number of sources affected 

by the reporting rule. 

Other components of the cost analysis 

included estimates of labor hours to 

perform specific activities, cost of labor, 

and cost of monitoring equipment. 

Estimates of labor hours were based on 

previous analyses of the costs of 

monitoring, reporting, and 

recordkeeping for other rules; 

information from the industry 

characterization on the number of units 

or process inputs and outputs to be 

monitored; and engineering judgment 

by industry and EPA industry experts 

and engineers. Labor costs were taken 

from the BLS and adjusted to account 

for overhead. Monitoring costs were 

generally based on cost algorithms or 

approaches that had been previously 

developed, reviewed, accepted as 

adequate, and used specifically to 

estimate the costs associated with 

various types of measurements and 

monitoring. 

A detailed engineering analysis was 

conducted for each subpart of the rule 

to develop unique unit costs. This 

analysis is documented in the RIA for 

the final rule. The TSDs for each source 

category provide a discussion of the 

applicable measurement technologies 

and any existing programs and 

practices. The appropriate volume of 

‘‘Mandatory Greenhouse Gas Reporting 

Rule: EPA’s Response to Public 

Comments’’ for each source category 

provide responses to any public 

comments on these source category 

engineering and cost analyses. Section 4 

of the RIA for the final rule contains a 

description of the engineering cost 

analysis. 

Table VII–1 of this preamble presents 

by subpart: The number of entities, the 

downstream emissions covered, the first 

year capital costs and the first year 

annualized costs of the rule. EPA 

estimates that the total national 

annualized cost for the first year is $132 

million, and the total national 

annualized cost for subsequent years is 

$89 million (2006$). Of these costs, 

roughly 13 percent fall upon the public 

sector for program administration in the 

first year, while 87 percent fall upon the 

private sector. General stationary 

combustion sources, which are widely 

distributed throughout the economy, are 

estimated to incur approximately 26 

percent of costs in the first year; other 

sectors incurring relatively large shares 

of costs are pulp and paper 

manufacturing (9 percent) and vehicle 

and engine manufacturers (9 percent). 

The threshold, in large part, 

determines the number of entities 

required to report GHG emissions and 

hence the costs of the rule. The number 

of entities excluded increases with 

higher thresholds. Table VII–2 of this 

preamble provides the cost-effectiveness 

analysis for various thresholds 

examined. Two metrics are used to 

evaluate the cost-effectiveness of the 

emissions threshold. The first is the 

average cost per metric ton of emissions 

reported ($/metric ton CO2e). The 

second metric for evaluating the 

threshold option is the incremental cost 

of reporting emissions. The incremental 

cost is calculated as the additional 

(incremental) cost per metric ton 

starting with the least stringent option 

and moving successively from one 

threshold option to the next. For more 

information about the first year capital 

costs (unamortized), project lifetime and 

the amortized (annualized) costs for 

each subpart, please refer to section 4 of 

the RIA for the final rule and the RIA 

cost appendix. Not all subparts require 

capital expenditures but those that do 


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are clearly documented in the RIA for 

the final rule. 

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

Subpart 

Number 

covered of 

entities 

Downstream emissions First year capital costs First year total 

annualized costs 2

(Million 

of MtCO2e) 

Share 

(percent) (Million) Share (percent) (Million) Share 

(percent) 

Subpart A—General Provisions ............................. 0 0.0 0 $0.0 0 $0.0 0 

Subpart B—Reserved ............................................ 0 0.0 0 0.0 0 0.0 0 

Subpart C—General Stationary Fuel Combustion 

Sources .............................................................. 3,000 220.0 6 10.5 27 25.8 20 

Subpart D—Electricity Generation ......................... 1,108 2262.0 59 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 0.2 0 

Subpart G—Ammonia Manufacturing .................... 23 12.9 0 0.0 0 0.4 0 

Subpart H—Cement Production ............................ 107 86.8 2 5.4 14 6.8 5 

Subpart K—Ferroalloy Production ......................... 9 2.3 0 0.0 0 0.1 0 

Subpart N—Glass Production ................................ 55 2.2 0 0.0 0 0.5 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 0.4 0 

Subpart Q—Iron and Steel Production .................. 121 85.0 2 0.0 0 3.7 3 

Subpart R—Lead Production ................................. 13 0.8 0 0.0 0 0.1 0 

Subpart S—Lime Manufacturing ............................ 89 25.4 1 4.9 12 5.3 4 

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 1 0.9 1 

Subpart X—Petrochemical Production .................. 80 54.4 1 0.0 0 2.2 2 

Subpart Y—Petroleum Refineries .......................... 150 204.7 5 1.6 4 6.1 5 

Subpart Z—Phosphoric Acid Production ............... 14 3.8 0 0.8 2 0.8 1 

Subpart AA—Pulp and Paper Manufacturing ........ 425 57.7 2 14.8 37 8.6 7 

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 0.1 0 

Subpart EE—Titanium Dioxide Production ............ 8 3.7 0 0.0 0 0.1 0 

Subpart GG—Zinc Production ............................... 5 0.8 0 0.0 0 0.1 0 

Subpart HH—Landfills ........................................... 2,551 91.1 2 1.3 3 12.4 9 

Subpart JJ—Manure Management ........................ 107 4.5 0 0.0 0 0.3 0 

Subpart LL -Suppliers of Coal & Subpart MM— 

Suppliers of Petroleum Products ....................... 315 0.0 0 0.0 0 3.7 3 

Subpart NN—Suppliers of Natural Gas and Natural Gas Liquids ................................................. 1,502 0.0 0 0.0 0 6.8 5 

Subpart OO—Suppliers of Industrial Greenhouse 

Gases ................................................................. 167 643.4 17 0.0 0 0.5 0 

Subpart PP—Suppliers of Carbon Dioxide (CO2) 13 0.0 0 0.0 0 0.0 0 

Subpart QQ—Motor Vehicle and Engine Manufacturers .............................................................. 317 NA NA 0.0 0 8.6 7 

Coverage Determination Costs for Non-Reporters NA NA NA NA NA 17.2 13 

Private Sector, Total .............................................. 10,152 3,827 100 39.6 100 115.0 87 

Public Sector, Total ................................................ NA NA NA NA NA 17.0 13 

Total ................................................................ 10,152 3,827 100 39.6 100 132.0 100 

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

2 Total costs include labor and capital costs incurred in the first year. Capital Costs are annualized using appropriate equipment lifetime and interest rate (see additional details in section 4 of the RIA for the final rule). 

TABLE VII–2—THRESHOLD COST-EFFECTIVENESS ANALYSIS (2006$) 

Threshold 

(tons CO2e) 

Facilities 

required 

to report 

Total 

costs 

(million 

$2006) 

Downstream 

emissions 

reported 

(MtCO2e/ 

year) 

Percentage of 

total 

downstream 

emissions 

reported 

(percent) 

Average 

reporting 

cost 

($2006/ 

ton) 

Incremental 

cost 

($/metric 

ton) 

100,000 .................................................................................................... 6,269 $89 3,738 53 $0.02 

25,000 ...................................................................................................... 10,152 132 3,827 54 0.03 0.49 

10,000 ...................................................................................................... 16,718 160 3,861 55 0.04 0.83 

1,000 ........................................................................................................ 54,229 398 3,926 56 0.10 3.67 

* Cost per metric ton relative to the selected option. 

Note: Does not include emissions for Motor Vehicle and Engine Manufacturers (Subpart QQ). 


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Table VII–3 of this preamble presents 

costs broken out by upstream and 

downstream sources. Upstream sources 

include the fuel suppliers and industrial 

GHG suppliers. Downstream suppliers 

include combustion sources, industrial 

processes, and biological processes. 

Most upstream facilities (e.g., refineries) 

are also direct emitters of GHGs and are 

included in the downstream side of the 

table. As shown in Table VII–3 of this 

preamble, over 99 percent of industrial 

processes emissions are covered at the 

25,000 metric tons CO2e threshold for a 

cost of approximately $36 million. 

However, it should be noted that due to 

data limitations the coverage estimates 

for upstream and downstream source 

categories are approximations. 

TABLE VII–3—UPSTREAM VERSUS DOWNSTREAM COSTS

Upstream 1 Downstream 234

Source category No. of reporters 

Emissions 

coverage 

(%) 10

First year 

cost 

(millions) 

Source category No. of reporters 2

Emissions 

coverage 3 7 10

(%) 

First year 

cost 3

(millions) 

Coal Supply ................................. 0 0 $0.00 Coal 5 6 Combustion .................... N/A 99 .0 N/A 

Petroleum Supply ........................ 315 100 3.66 Petroleum 5 Combustion 9 ........... N/A 20 .0 N/A 

Natural Gas Supply ..................... 1,502 68 6.76 Natural Gas 5 Combustion .......... N/A 23 .0 N/A 

Sub Total Combustion ................ 4,108 N/A $29 .04 

Industrial Gas Supply .................. 167 100 0.52 Industrial Gas Consumption ....... 17 14 0 .24 

Industrial Processes ................... 1,068 99 .6 36 .2 

Fugitive Emissions (coal, oil and 

gas).

0 0 0 .00 

Biological Processes .................. 2,658 58 12 .77 

Vehicle 8 and Engine Manufacturers.317 80 8 .61 

Notes 

1 Most upstream facilities (e.g., refineries) are also direct emitters of greenhouse gases, and are included in the downstream side of the table. 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 threshold (e.g., 25,000 metric tons of CO2e/yr). 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 ARP. 7 Due to data limitations, the coverage for downstream sources for fuel and industrial gas consumption in this table does not take into account 

thresholds. Assuming full emissions coverage for each source slightly over-states the actual coverage that will result from this rule. To estimate 

total emissions coverage downstream, by fuel, we added total emissions resulting from the respective fuel combusted in the industrial and electricity generation sectors and divided that by total national GHG emissions from the combustion of that fuel. 8The percent of coverage here is percentage of total heavy-duty highway vehicles and engines, motorcycles, and nonroad engine sales covered by manufacturer reporting in this proposal rather than emissions coverage. The ‘‘threshold’’ for mobile sources is based on manufacturer 

size rather than total emissions. In this rule, all heavy-duty highway and nonroad vehicle and engine manufacturers, except those that meet 

EPA’s definition of ‘‘small business’’ or ‘‘small volume manufacturers’’, would report emissions rates of CO2, CH4, and N2O from the products 

they supply. This source category is neither upstream nor downstream, but is included in the downstream column for illustrative purposes. 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 one percent 

of the total emissions. 

2. Summary of Comments and 

Responses 

Comment: EPA received comments on 

source specific cost data reflected in the 

engineering cost analysis presented in 

section 4 of the RIA for the proposed 

rule (EPA–HQ–OAR–2008–0318–002). 

Some commenters asked EPA to not 

overly burden entities that may be 

required to report and to balance 

reporting costs with the need for 

accurate reporting of GHG emissions. 

Additional comments received 

questioned EPA’s estimate of the costs 

associated with third party verification, 

as well as the estimated burden to the 

Federal government for self certification 

with EPA verification. 

Response: EPA considered all relevant 

comments regarding source specific cost 

data developed in the engineering cost 

analysis and used in the RIA for the 

proposed rule. In some cases, we 

revised our cost estimates, and in some 

cases we revised monitoring and 

reporting requirements in ways which 

reduced burden. Please see source 

specific comments and responses in 

Section III of this preamble and the 

relevant volume of ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments’’. 

EPA believes the selected option for 

the mandatory GHG reporting rule 

strikes a balance between impacts on 

small entities, consistency with other 

programs, costs incurred by the 

reporting entities, and emissions 

coverage. Section 5 of the RIA for the 


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final rule provides cost comparisons for 

each alternative evaluated. 

In evaluating the costs of self 

certification with EPA verification and 

third party verification, EPA conducted 

a thorough review of relevant cost 

information available. EPA also 

considered cost data submitted in 

public comments on the proposed rule. 

EPA’s review of verification costs 

included examining estimated Agency 

costs for other EPA based reporting 

programs, as well as a study conducted 

by the California Air Resources Board 

(CARB). The results of EPA’s review of 

verification costs can be found in the 

Memo on Verification Costs in the 

docket. The final rule retains selfcertification with EPA verification. 

EPA’s estimated cost for verification 

activities is $7 million per year. 

Additional comments and responses on 

third party verification can be found in 

Section II.N of this preamble. Section 

5.1.6 of the RIA for the final rule 

contains the full economic analysis of 

verification costs and options. 

C. What are the economic impacts of the 

rule? 

1. Summary of Economic Impacts 

EPA prepared an economic impact 

analysis to evaluate the impacts of the 

rule on affected industries and 

economic sectors. In evaluating the 

various reporting options considered, 

EPA conducted a cost-effectiveness 

analysis, comparing the cost per metric 

ton of GHG emissions across reporting 

options. EPA used this information to 

identify the preferred options described 

in today’s rule. 

To estimate the economic impacts of 

the rule, EPA first conducted a 

screening assessment, comparing the 

estimated total annualized compliance 

costs by industry, where industry is 

defined in terms of North American 

Industry Classification System (NAICS) 

code, with industry average revenues. 

Overall national costs of the rule are 

significant because there is a large 

number of affected entities, but 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 rule is unlikely to 

result in significant changes in firms’ 

production decisions or other 

behavioral changes, and thus unlikely to 

result in significant changes in prices or 

quantities in affected markets. Thus, 

EPA followed its Guidelines for 

Preparing Economic Analyses (EPA, 

2002, p.124–125) and used the 

engineering cost estimates to measure 

the social cost of the rule, rather than 

modeling market responses and using 

the resulting measures of social cost. 

Table VII–4 of this preamble 

summarizes cost-to-sales ratios for 

affected industries. 

TABLE VII–4—ESTIMATED COST-TO-SALES RATIOS FOR AFFECTED ENTITIES

NAICS NAICS description 

Average cost 

per entity 

($1,000/entity) 

Average entity 

cost-to-sales 

ratio 1

(percent) 

211 ............................................ Oil and Gas Extraction ..................................................................................... $2 <0.1 

221 ............................................ SF6 from Electrical Systems ............................................................................ 5 <0.1 

322 ............................................ Pulp & Paper Manufacturing ............................................................................ 20 <0.1 

324 ............................................ Petroleum and Coal Products .......................................................................... 21 <0.1 

325 ............................................ Chemical Manufacturing ................................................................................... 14 <0.1 

327 ............................................ Cement & Other Mineral Production ................................................................ 50 0.8 

331 ............................................ Primary Metal Manufacturing ........................................................................... 26 <0.1 

486 ............................................ Oil & Natural Gas Transportation ..................................................................... 4 <0.1 

562 ............................................ Waste Management and Remediation Services .............................................. 5 0.2 

325199 ...................................... Adipic Acid ........................................................................................................ 24 <0.1 

325311 ...................................... Ammonia .......................................................................................................... 17 <0.1 

327310 ...................................... Cement ............................................................................................................. 63 0.2 

331112 ...................................... Ferroalloys ........................................................................................................ 9 <0.1 

3272 .......................................... Glass ................................................................................................................ 8 <0.1 

325120 ...................................... Hydrogen Production ........................................................................................ 3 <0.1 

331112 ...................................... Iron and Steel ................................................................................................... 30 <0.1 

3314 .......................................... Lead Production ............................................................................................... 10 <0.1 

327410 ...................................... Lime Manufacturing .......................................................................................... 60 0.4 

325311 ...................................... Nitric Acid ......................................................................................................... 20 <0.1 

324110 ...................................... Petrochemical ................................................................................................... 27 <0.1 

325312 ...................................... Phosphoric Acid ............................................................................................... 60 <0.1 

322110 ...................................... Pulp and Paper ................................................................................................ 20 <0.1 

324110 ...................................... Refineries ......................................................................................................... 41 <0.1 

327910 ...................................... Silicon Carbide ................................................................................................. 10 <0.1 

3251 .......................................... Soda Ash Manufacturing .................................................................................. 16 <0.1 

325188 ...................................... Titanium Dioxide ............................................................................................... 10 <0.1 

3314 .......................................... Zinc Production ................................................................................................ 13 <0.1 

1This ratio reflects first year costs. Subsequent year costs will be slightly lower because they do not include initial start-up activities. 

2. Summary of Comments and 

Responses 

Comment: EPA received a number of 

comments on the overall economic 

impacts of the proposed rule. Some 

commenters stated that the economic 

impacts are understated, as costs will 

not be passed on to consumers from 

reporters. Other commenters stated that 

large increases in operating costs 

resulting from mandatory reporting of 

GHGs would lead facilities to close or 

move offshore. 

Response: As described previously, 

EPA conducted a thorough analysis of 

available information and reviewed 

comments submitted on this issue, and 

we have determined that this analysis 

provides a reasonable characterization 

of costs for facilities in each subpart and 

that the documentation provides 

adequate explanation of how the costs 

were estimated. Our economic impact 

analysis has been conducted without 


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32EPA’s RFA guidance for rule writers suggests 

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

quantitative metric for economic impact screening 

analysis. 

taking into account the fact that some 

share of costs may be passed on to 

customers of each affected sector. 

Instead, facilities’ annualized costs were 

compared to sales for entities in the 

sector, overall and for small entities. 

Even when all costs are absorbed by the 

facility, the costs represent less than one 

percent of sales and thus are not 

expected to result in significant 

hardship for affected firms. 

D. What are the impacts of the rule on 

small businesses? 

1. Summary of Impacts on Small 

Businesses 

As required by the RFA and Small 

Business Regulatory Enforcement and 

Fairness ACT (SBREFA), EPA assessed 

the potential impacts of the rule on 

small entities (small businesses, 

governments, and non-profit 

organizations). (See Section VIII.C of 

this preamble for definitions of small 

entities.) 

EPA has determined the selected 

thresholds maximize the rule coverage 

with 81 to 86 percent of U.S. GHG 

emissions reported by approximately 

10,152 reporters, while keeping 

reporting burden to a minimum and 

excluding small emitters. Furthermore, 

many industry stakeholders that EPA 

met with expressed support for a 25,000 

metric ton CO2e threshold because it 

sufficiently captures the majority of 

GHG emissions in the U.S., while 

excluding smaller facilities and sources. 

For small facilities that are covered by 

the rule, EPA has included simplified 

emission estimation methods in the rule 

where feasible (e.g., stationary 

combustion equipment under a certain 

rating can use a simplified calculation 

approach as opposed to more rigorous 

direct monitoring) to keep the burden of 

reporting as low as possible. We 

received many comments related to 

monitoring and reporting requirements 

in specific source categories, and made 

many changes in response to reduce 

burden on reporters. For information on 

these issues, refer to the discussion of 

each source category in this preamble 

and the relevant volume of ‘‘Mandatory 

Greenhouse Gas Reporting Rule: EPA’s 

Response to Public Comments.’’ For 

further detail on the rationale for 

excluding small entities through 

threshold selection please see the 

Thresholds TSD (EPA–HQ–OAR–2008– 

0508–046) and Section III.C.3 of this 

preamble. 

EPA conducted a screening 

assessment comparing compliance costs 

for affected industry sectors to industryspecific receipts data for establishments 

owned by small businesses. This ratio 

constitutes a ‘‘sales’’ test that computes 

the annualized compliance costs of this 

rule as a percentage of sales and 

determines whether the ratio exceeds 

some level (e.g., one percent or three 

percent).32 The cost-to-sales ratios were 

constructed at the establishment level 

(average reporting program costs per 

establishment/average establishment 

receipts) for several business size 

ranges. This allowed EPA to account for 

receipt differences between 

establishments owned by large and 

small businesses and differences in 

small business definitions across 

affected industries. The results of the 

screening assessment are shown in 

Table VII–5 of this preamble. 

TABLE VII–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 

(percent) 

Owned by enterprises with: 

<20 employees f

(percent) 

20 to 99 

employees (percent) 

100 to 

499 employees 

(percent) 

500 to 

749 employees 

(percent) 

750 to 

999 employees 

(percent) 

1,000 to 

1,499 

employees (percent) 

Oil and Gas Extraction.211 Oil & gas extraction.500 .............. $2 0.0 0.2 0.0 0.0 0.0 0.0 0.0 

SF6 from Electrical 

Systems.

221 Utilities .................. (b) ................ 5 0.0 0.2 0.0 0.0 0.0 0.0 0.0 

Pulp & Paper Manufacturing.322 Paper mfg ............. 500 to 750 ... 20 0.1 1.2 0.2 0.1 0.0 0.0 0.0 

Petroleum and 

Coal Products.

324 Petroleum & coal 

products mfg.

(c) ................ 21 0.0 0.6 0.1 0.1 0.0 0.2 0.0 

Chemical Manufacturing.325 Chemical mfg ....... 500 to 1,000 14 0.0 0.7 0.1 0.0 0.0 0.0 0.0 

Cement & Other 

Mineral Production.

327 Nonmetallic mineral product mfg.500 to 1,000 50 0.8 4.8 0.9 0.5 0.4 0.5 0.4 

Primary Metal 

Manufacturing.

331 Primary metal mfg 500 to 1,000 26 0.1 2.1 0.3 0.1 0.1 0.0 0.0 

Oil & Natural Gas 

Transportation.

486 Pipeline transportation.(d) ................ 4 0.0 0.0 0.2 0.1 NA NA NA 

Waste Management and Remediation Services.

562 Waste management & remediation services.

(e) ................ 5 0.2 0.7 0.1 0.1 0.0 0.0 0.0 

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 ........... 17 0.1 0.9 0.5 NA NA NA NA 

Cement ................. 327310 Cement mfg .......... 750 .............. 63 0.2 2.0 1.5 0.3 NA NA 0.1 

Ferroalloys ............ 331112 Electrometallurgical ferroalloy 

product mfg.

750 .............. 9 0.0 NA NA NA NA NA NA 

Glass ..................... 3272 Glass & glass 

product mfg.

500 to 1,000 8 0.1 1.4 0.2 0.0 0.0 0.1 0.0 

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


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TABLE VII–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 

(percent) 

Owned by enterprises with: 

<20 employees f

(percent) 

20 to 99 

employees (percent) 

100 to 

499 employees 

(percent) 

500 to 

749 employees 

(percent) 

750 to 

999 employees 

(percent) 

1,000 to 

1,499 

employees (percent) 

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

product mfg.

750 .............. 30 0.1 NA NA NA NA NA NA 

Lead Production .... 3314 Nonferrous metal 

(except aluminum) production & processing.

750 to 1,000 10 0.0 0.6 0.1 0.0 NA NA 0.0 

Lime Manufacturing.327410 Lime mfg .............. 500 .............. 60 0.4 16.5 1.2 NA NA NA NA 

Nitric Acid .............. 325311 Nitrogenous fertilizer mfg.1,000 ........... 20 0.1 1.0 0.6 NA NA NA NA 

Petrochemical ....... 324110 Petroleum refineries.(c) ................ 27 0.0 0.4 0.0 0.0 0.0 NA NA 

Phosphoric Acid .... 325312 Phosphatic fertilizer mfg.500 .............. 60 0.1 10.1 NA NA NA NA NA 

Pulp and Paper ..... 322110 Pulp mills .............. 750 .............. 20 0.0 1.4 NA NA NA NA NA 

Refineries .............. 324110 Petroleum refineries.(c) ................ 41 0.0 0.6 0.0 0.0 0.0 NA NA 

Silicon Carbide ...... 327910 Abrasive product 

mfg.

500 .............. 10 0.1 0.8 0.2 0.1 NA NA NA 

Soda Ash Manufacturing.3251 Basic chemical 

mfg.

500 to 1,000 16 0.0 0.5 0.1 0.0 0.0 0.0 0.0 

Titanium Dioxide ... 325188 All other basic inorganic chemical 

mfg.

1,000 ........... 10 0.0 0.7 0.4 0.1 NA NA NA 

Zinc Production ..... 3314 Nonferrous metal 

(except aluminum) production & processing.

750 to 1,000 13 0.1 0.9 0.1 0.0 NA NA 0.0 

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 four million MW hours. c 500 to 1,500. For NAICS code 324110—For purposes of Government procurement, the petroleum refiner must be a concern that has no more than 1,500 employees nor more than 125,000 barrels per calendar day total Operable Atmospheric Crude Oil Distillation capacity. Capacity includes owned or leased facilities as well as 

facilities under a processing agreement or an arrangement such as an exchange agreement or a throughput. The total product to be delivered under the contract 

must be at least 90 percent refined by the successful bidder from either crude oil or bona fide feedstocks. d NAICS codes 486110 = 1,500 employees; NAICS 486210 = $6.5 million annual receipts; NAICS 486910 = 1,500 employees; and NAICS 486990 = $11.5 million 

annual receipts. e Ranges from $6.5 to $13.0 million annual receipts; Environmental Remediation services has a 500 employee definition and the following criteria. NAICS 562910— 

Environmental Remediation Services: 

(1) For SBA assistance as a small business concern in the industry of Environmental Remediation Services, other than for Government procurement, a concern 

must be engaged primarily in furnishing a range of services for the remediation of a contaminated environment to an acceptable condition including, but not limited to, 

preliminary assessment, site inspection, testing, remedial investigation, feasibility studies, remedial design, containment, remedial action, removal of contaminated 

materials, storage of contaminated materials and security and site closeouts. If one of such activities accounts for 50 percent or more of a concern’s total revenues, 

employees, or other related factors, the concern’s primary industry is that of the particular industry and not the Environmental Remediation Services Industry. 

(2) For purposes of classifying a Government procurement as Environmental Remediation Services, the general purpose of the procurement must be to restore a 

contaminated environment and also the procurement must be composed of activities in three or more separate industries with separate NAICS codes or, in some instances (e.g., engineering), smaller sub-components of NAICS codes with separate, distinct size standards. These activities may include, but are not limited to, separate activities in industries such as: Heavy Construction; Special Trade Construction; Engineering Services; Architectural Services; Management Services; Refuse 

Systems; Sanitary Services, Not Elsewhere Classified; Local Trucking Without Storage; Testing Laboratories; and Commercial, Physical and Biological Research. If 

any activity in the procurement can be identified with a separate NAICS code, or component of a code with a separate distinct size standard, and that industry accounts for 50 percent or more of the value of the entire procurement, then the proper size standard is the one for that particular industry, and not the Environmental 

Remediation Service size standard. 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. 

EPA was not able to calculate a costto-sales ratio for manure management 

(NAICS 112) as Statistics of U.S. 

Businesses ([SUSB]SBA, 2008a) data do 

not provide establishment information 

for agricultural NAICS codes (e.g., 

NAICS 112 which covers manure 

management). EPA estimates that the 

total first year reporting costs for the 

entire manure management industry to 

be $0.3 million with an average cost per 

ton of CO2e reported of $0.07. 

As shown, the cost-to-sales ratios are 

less than one percent for establishments 

owned by small businesses that EPA 

considers most likely to be covered by 

the reporting program (e.g., 

establishments owned by businesses 

with 20 or more employees). 

EPA acknowledges that several 

enterprise categories have ratios that 

exceed this threshold (e.g., enterprise 

with one to 20 employees). EPA took a 

conservative approach with the model 

entity analysis. Although the 

appropriate SBA size definition should 

be applied at the parent company 

(enterprise) level, data limitations 

allowed us only to compute and 

compare ratios for a model 

establishment within several enterprise 

size ranges. To assess the likelihood that 


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56368 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

33Nicholas 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. 

these small businesses will be covered 

by the rule, we performed several case 

studies for manufacturing industries 

where the cost-to-receipt ratio exceeded 

one percent. For each industry, we used 

and applied emission data from a recent 

study examining emission thresholds 33. 

This study provides industry-average 

CO2 emission rates (e.g., tons per 

employee) for these manufacturing 

industries. 

The case studies showed two 

industries (cement and lime 

manufacturing) where emission rates 

suggest small businesses of this 

employment size could potentially be 

covered by the rule. As a result, EPA 

examined corporate structures and 

ultimate parent companies were 

identified using industry surveys and 

the latest private databases such as Dun 

& Bradstreet. The results of this analysis 

show cost to sales ratios below one 

percent. 

For the other enterprise categories 

identified with ratios between one 

percent and three percent EPA 

examined industry specific bottom up 

databases and previous industry specific 

studies to ensure that no entities with 

less than 20 employees are captured 

under the rule. 

Although this rule will not have a 

significant economic impact on a 

substantial number of small entities, the 

Agency nonetheless tried to reduce the 

impact of this rule on small entities, 

including seeking input from a wide 

range of private- and public-sector 

stakeholders. When developing the rule, 

the Agency took special steps to ensure 

that the burdens imposed on small 

entities were minimal. The Agency 

conducted several meetings with 

industry trade associations to discuss 

regulatory options and the 

corresponding burden on industry, such 

as recordkeeping and reporting. The 

Agency investigated alternative 

thresholds and analyzed the marginal 

costs associated with requiring smaller 

entities with lower emissions to report. 

The Agency also recommended a hybrid 

method for reporting, which provides 

flexibility to entities and helps 

minimize reporting costs. 

Additional analysis for a model small 

government also showed that the 

annualized reporting program costs 

were less than one percent of revenue. 

These impacts are likely representative 

of ratios in industries where data 

limitations do not allow EPA to 

compute sales tests (e.g., general 

stationary combustion and manure 

management). Potential impacts of the 

rule on small governments were 

assessed separately from impacts on 

Federal Agencies. Small governments 

and small non-profit organizations may 

be affected if they own affected 

stationary combustion sources, landfills, 

or natural gas suppliers. However, the 

estimated costs under the rule are 

estimated to be small enough that no 

small government or small non-profit is 

estimated to incur significant impacts. 

For example, from the 2002 Census (in 

$2006), revenues for small governments 

(counties and municipalities) with 

populations fewer than 10,000 are $3 

million, and revenues for local 

governments with populations less than 

50,000 is $7 million. As an upper bound 

estimate, summing typical perrespondent costs of combustion plus 

landfills plus natural gas suppliers 

yields a cost of approximately $18,000 

per local government. Thus, for the 

smallest group of local governments 

(<10,000 people), cost-to-revenue ratio 

is 0.7 percent. For the larger group of 

governments less than 50,000, the costto-revenue ratio is 0.2 percent. 

2. Summary of Comments and 

Responses 

Comment: Comments received on 

small business impacts focused on the 

economic burden to small businesses for 

compliance with mandatory GHG 

reporting. One commenter noted that 

lowering the reporting threshold below 

the proposed 25,000 metric ton CO2e 

level would disproportionately affect 

small businesses. Another commenter 

stated that small businesses are not well 

equipped to handle detailed 

requirements for reporting and that the 

proposed rule would impose a large 

burden for monitoring, recordkeeping, 

and reporting activities. 

Additional comments received 

requested that EPA establish a SBREFA 

process to investigate the impacts that 

the proposed rule would have on small 

businesses. 

Response: As summarized above, EPA 

investigated alternative thresholds and 

analyzed the marginal costs associated 

with requiring smaller entities with 

lower emissions to report. EPA 

recognized the additional burden placed 

on small entities at lower thresholds, 

and had retained the hybrid method for 

reporting that includes a 25,000 metric 

ton CO2e level threshold. Under this 

threshold, EPA has assessed the 

economic impact of the final rule on 

small entities and concluded that this 

action will not have a significant 

economic impact on a substantial 

number of small entities. 

For this reason, EPA did not establish 

a SBREFA panel process for the 

rulemaking. The summary of the factual 

basis for the certification is provided in 

the preamble for the rule. Complete 

documentation of the analysis can be 

found in Section 5.2 of the RIA for the 

final rule. 

E. What are the benefits of the rule for 

society? 

1. Summary of Method Used To 

Estimate Compliance Costs 

EPA examined the potential benefits 

of the GHG reporting rule. The benefits 

of a reporting system are based on their 

relevance to policy making, 

transparency issues, and market 

efficiency. Benefits are very difficult to 

quantify and monetize. Instead of a 

quantitative analysis of the benefits, 

EPA conducted a systematic literature 

review of existing studies including 

government, consulting, and scholarly 

reports. 

A mandatory reporting system will 

benefit the public by increased 

transparency of facility emissions data. 

Transparent, public data on emissions 

allows for accountability of polluters to 

the public stakeholders who bear the 

cost of the pollution. Citizens, 

community groups, and labor unions 

have made use of data from Pollutant 

Release and Transfer Registers to 

negotiate directly with polluters to 

lower emissions, circumventing greater 

government regulation. Publicly 

available emissions data also will allow 

individuals to alter their consumption 

habits based on the GHG emissions of 

producers. 

The greatest benefit of mandatory 

reporting of industry GHG emissions to 

government will be realized in 

developing future GHG policies. For 

example, in the EU’s Emissions Trading 

System, a lack of accurate monitoring at 

the facility level before establishing CO2

allowance permits resulted in allocation 

of permits for emissions levels an 

average of 15 percent above actual levels 

in every country except the United 

Kingdom. 

Benefits to industry of GHG emissions 

monitoring include the value of having 

independent, verifiable data to present 

to the public to demonstrate appropriate 

environmental stewardship, and a better 

understanding of their emission levels 

and sources to identify opportunities to 

reduce emissions. Such monitoring 

allows for inclusion of standardized 

GHG data into environmental 

management systems, providing the 

necessary information to achieve and 


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34Although CBI determinations are usually made 

on a case-by-case basis, EPA has issued guidance 

in an earlier Federal Register notice on what 

constitutes emissions data that cannot be 

considered CBI (956 FR 7042–7043, February 21, 

1991). As discussed in Section II.R of this preamble, 

EPA will be initiating a separate notice and 

comment process to make CBI determinations for 

the data collected under this rulemaking. 

35EPA estimates that 30,000 facilities are 

potentially affected by the rule. Of these, EPA 

estimates that 10,152 facilities across various 

sectors will be over their sector-specific reporting 

threshold and thus required to report; the remaining 

19,848 will determine during the first year that they 

are beneath the threshold and do not need to report. 

The average number of respondents is thus 

(30,000+10,152+10,152)/3 = 16,768; excluding 43 

Federal facilities, the number of private 

respondents is 16,725. 

disseminate their environmental 

achievements. 

Standardization will also be a benefit 

to industry, once facilities invest in the 

institutional knowledge and systems to 

report emissions, the cost of monitoring 

should fall and the accuracy of the 

accounting should improve. A 

standardized reporting program will 

also allow for facilities to benchmark 

themselves against similar facilities to 

understand better their relative standing 

within their industry. 

2. Summary of Comments and 

Responses 

Comment: Comments received on the 

benefits of the mandatory reporting 

program focused on the potential future 

uses of the collected data. Additional 

comments on the benefits of the 

program were concerned that the 

benefits of the rule are not quantified. 

Response: The data collected under 

this rule will provide comprehensive 

and accurate data to inform future 

climate change policies. Potential future 

CAA and other climate policies include 

research and development initiatives, 

economic incentives, new or expanded 

voluntary programs, adaptation 

strategies, emission standards, a carbon 

tax, or a cap-and-trade program. Because 

EPA does not know at this time the 

specific policies that may be adopted, 

the data reported through this rule 

should be of sufficient quality to 

support a range of approaches. 

Section VI of the RIA for the final rule 

summarizes the anticipated benefits of 

the rule, which include providing the 

government with sound data on which 

to base future policies and providing 

industry and the public independently 

verified information documenting firms’ 

environmental performance. While EPA 

has not quantified the benefits of the 

mandatory reporting rule, EPA believes 

that they are substantial and outweigh 

the estimated costs. 

VIII. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review 

Under section 3(f)(1) of EO 12866 (58 

FR 51735, October 4, 1993), this action 

is an ‘‘economically significant 

regulatory action’’ because it is likely to 

have an annual effect on the economy 

of $100 million or more. Accordingly, 

EPA submitted this action to the OMB 

for review under EO 12866 and any 

changes made in response to OMB 

recommendations have been 

documented in the docket for this 

action. 

In addition, EPA prepared an analysis 

of the potential costs and benefits 

associated with this action. A copy of 

the analysis is available in Docket No. 

EPA–HQ–OAR–2008–0508, the RIA for 

the final rule, and is briefly summarized 

in Section VII of this preamble. 

B. Paperwork Reduction Act 

The information collection 

requirements in this rule have been 

submitted for approval to the Office of 

Management and Budget (OMB) under 

the Paperwork Reduction Act, 44 U.S.C. 

3501 et seq. The information collection 

requirements are not enforceable until 

OMB approves them. The ICR document 

prepared by EPA has been assigned EPA 

ICR number 2300.03. 

EPA plans to collect complete and 

accurate economy-wide data on facilitylevel GHG emissions. Accurate and 

timely information on GHG emissions is 

essential for informing future climate 

change policy decisions. Through data 

collected under this rule, EPA will gain 

a better understanding of the relative 

emissions of specific industries, and the 

distribution of emissions from 

individual facilities within those 

industries. The facility-specific data will 

also improve our understanding of the 

factors that influence GHG emission 

rates and actions that facilities are 

already taking to reduce emissions. 

Additionally, EPA will be able to track 

the trend of emissions from industries 

and facilities within industries over 

time, particularly in response to policies 

and potential regulations. The data 

collected by this rule will improve 

EPA’s ability to formulate climate 

change policy options and to assess 

which industries would be affected, and 

how these industries would be affected 

by the options. 

This information collection is 

mandatory and will be carried out under 

CAA sections 114 and 208. Information 

identified and marked as CBI will not be 

disclosed except in accordance with 

procedures set forth in 40 CFR part 2. 

However, emissions data collected 

under CAA sections 114 and 208 cannot 

generally be claimed as CBI and will be 

made public.34

The projected cost and hour burden 

for non-Federal respondents is $86.3 

million and 1.21 million hours per year. 

The estimated average burden per 

response is two hours; the frequency of 

response is annual for all respondents 

that must comply with the rule’s 

reporting requirements, except for 

electricity generating units that are 

already required to report quarterly 

under 40 CFR part 75 (EPA Acid Rain 

Program); and the estimated average 

number of likely respondents per year is 

16,725 35. The cost burden to 

respondents resulting from the 

collection of information includes the 

total capital cost annualized over the 

equipment’s expected useful life 

(averaging $9.1 million), a total 

operation and maintenance component 

(averaging $11.0 million per year), and 

a labor cost component (averaging $66.1 

million per year). Burden is defined at 

5 CFR 1320.3(b). These cost numbers 

differ from those shown elsewhere in 

the RIA for the final rule because the 

ICR costs represent the average cost over 

the first three years of the rule, but costs 

are reported elsewhere in the RIA for 

the final rule for the first year of the rule 

and for subsequent years of the rule. In 

addition, the ICR focuses on respondent 

burden, while the RIA for the final rule 

includes EPA Agency costs. 

An agency may not conduct or 

sponsor, and a person is not required to 

respond to, a collection of information 

unless it displays a currently valid OMB 

control number. The OMB control 

numbers for EPA’s regulations in 40 

CFR are listed in 40 CFR part 9. When 

this ICR is approved by OMB, the 

Agency will publish a technical 

amendment to 40 CFR part 9 in the 

Federal Register to display the OMB 

control number for the approved 

information collection requirements 

contained in this final rule. 

C. Regulatory Flexibility Act (RFA) 

The RFA generally requires an agency 

to prepare a regulatory flexibility 

analysis of any rule subject to notice 

and comment rulemaking requirements 

under the Administrative Procedure Act 

or any other statute unless the agency 

certifies that the rule will not have a 

significant economic impact on a 

substantial number of small entities. 

Small entities include small businesses, 

small organizations, and small 

governmental jurisdictions. 

For purposes of assessing the impacts 

of today’s rule on small entities, small 

entity is defined as: (1) A small business 


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36U.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. 

as defined by the Small Business 

Administration’s regulations at 13 CFR 

121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s final rule on small 

entities, I therefore certify that this final 

rule will not have a significant 

economic impact on a substantial 

number of small entities. 

The small entities directly regulated 

by this final rule include small 

businesses across all sectors 

encompassed by the rule, small 

governmental jurisdictions and small 

non-profits. We have determined that 

some small businesses will be affected 

because their production processes emit 

GHGs that must be reported, because 

they have stationary combustion units 

on site that emit GHGs that must be 

reported, or because they have fuel 

supplier operations for which supply 

quantities and GHG data must be 

reported. Small governments and small 

non-profits are generally affected 

because they have regulated landfills or 

stationary combustion units on site, or 

because they own an LDC. 

For affected small entities, EPA 

conducted a screening assessment 

comparing compliance costs for affected 

industry sectors to industry-specific 

data on revenues for small businesses. 

This ratio constitutes a ‘‘sales’’ test that 

computes the annualized compliance 

costs of this final rule as a percentage of 

sales and determines whether the ratio 

exceeds some level (e.g., one percent or 

three percent). The cost-to-sales ratios 

were constructed at the establishment 

level (average compliance cost for the 

establishment/average establishment 

revenues). As shown in Table VII–5 of 

this preamble, the cost-to-sales ratios are 

less than one percent for establishments 

owned by small businesses that EPA 

considers most likely to be covered by 

the reporting program, those with more 

than 20 employees.36 For the few sectors 

where the preliminary screening 

showed a cost-to-sales ratio exceeding 

one percent, EPA’s examination of firmspecific sales information showed that 

no affected entity was likely to incur 

costs exceeding one percent of sales. 

The screening analysis thus indicates 

that the final rule will not have a 

significant economic impact on a 

substantial number of small entities. See 

Table VII–5 of this preamble for 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 one percent of average 

revenues for the smallest category of 

governments (those with fewer than 

10,000 people). 

Although this final rule will not have 

a significant economic impact on a 

substantial number of small entities, 

EPA nonetheless took several steps to 

reduce the impact of this rule on small 

entities. For example, EPA determined 

appropriate thresholds that reduce the 

number of small businesses reporting. In 

addition, EPA is not requiring facilities 

to install CEMS if they do not already 

have them. Facilities without CEMS can 

calculate emissions using readily 

available data or data that are less 

expensive to collect such as process 

data or material consumption data. For 

some source categories, EPA developed 

tiered methods that are simpler and less 

burdensome. Also, EPA is requiring 

annual instead of more frequent 

reporting. 

Through comprehensive outreach 

activities prior to proposal of the rule, 

EPA held approximately 100 meetings 

and/or conference calls with 

representatives of the primary audience 

groups, including numerous trade 

associations and industries that include 

small business members. EPA’s 

outreach activities prior to proposal of 

the rule are documented in the 

memorandum, ‘‘Summary of EPA 

Outreach Activities for Developing the 

Greenhouse Gas Reporting Rule,’’ 

located in Docket No. EPA–HQ–OAR– 

2008–0508–055. After proposal, EPA 

posted a guide for small businesses on 

EPA’s GHG reporting rule Web site, 

along with a general fact sheet for the 

rule, information sheets for every source 

category, and an FAQ document. EPA 

also operated a hotline to answer 

questions about the proposed rule. We 

continued to meet with stakeholders 

and entered documentation of all 

meetings into the docket. We considered 

public comments, including comments 

from small businesses and organizations 

that include small business members, in 

developing the final rule. 

During rule implementation, EPA will 

maintain an ‘‘open door’’ policy for 

stakeholders to ask questions about the 

rule or provide suggestions to EPA 

about the types of compliance assistance 

that would be useful to small 

businesses. EPA intends to develop a 

range of compliance assistance tools and 

materials and conduct extensive 

outreach for the final rule. 

D. Unfunded Mandates Reform Act 

(UMRA) 

Title II of the Unfunded Mandates 

Reform Act of 1995 (UMRA), 2 U.S.C. 

1531–1538, requires Federal agencies, 

unless otherwise prohibited by law, to 

assess the effects of their regulatory 

actions on State, local, and Tribal 

governments and the private sector. 

EPA has developed this regulation 

under authority of CAA sections 114 

and 208. The required activities under 

this Federal mandate include 

monitoring, recordkeeping, and 

reporting of GHG emissions from 

multiple source categories (e.g., 

combustion, process, and biologic). This 

rule contains a Federal mandate that 

may result in expenditures of $100 

million for the private sector in any one 

year. As described below, we have 

determined that the expenditures for 

State, local, and Tribal governments, in 

the aggregate, will be approximately 

$12.1 million per year, based on average 

costs over the first three years of the 

rule, including approximately $2 

million during the first year of the rule 

for governments to make a reporting 

determination and subsequently 

determine that their emissions are 

below the threshold and thus, they are 

not required to report their emissions. 

Accordingly, EPA has prepared under 

section 202 of the UMRA a written 

statement which is summarized below. 

Consistent with the intergovernmental 

consultation provisions of section 204 of 

the UMRA, EPA initiated an outreach 

effort with the governmental entities 

affected by this rule including State, 

local, and Tribal officials. EPA 

maintained an ‘‘open door’’ policy for 

stakeholders to provide input on key 

issues and to help inform EPA’s 

understanding of issues, including 

impacts to State, local and Tribal 

governments. The outreach audience 

included State environmental protection 

agencies, regional and Tribal 

organizations, and other State and local 

government organizations. EPA 

contacted several States and State and 

regional organizations already involved 

in GHG emissions reporting. EPA also 

conducted several conference calls with 

Tribal organizations during the proposal 

phase. For example, EPA staff provided 

information to tribes through conference 

calls with multiple Tribal working 

groups and organizations at EPA and 


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through individual calls with two Tribal 

board members of TRI. In addition, EPA 

held meetings and conference calls with 

groups such as TRI, National 

Association of Clean Air Agencies 

(NACAA), ECOS, and with State 

members of RGGI, the Midwestern GHG 

Reduction Accord, and WCI. See the 

‘‘Summary of EPA Outreach Activities 

for Developing the Greenhouse Gas 

Reporting Rule,’’ in Docket No. EPA– 

HQ–OAR–2008–0508–055 for a 

complete list of organizations and 

groups that EPA contacted. 

At proposal of the rule, EPA posted a 

guide for State and local agencies on the 

Web site, along with other information 

sheets, to communicate key aspects of 

the proposed rule to these agencies. 

Several State and local agencies and 

three Tribal organizations or 

communities submitted written public 

comments, and EPA carefully 

considered these comments in 

developing the final rule. EPA also 

continued to meet with government 

agencies or organizations with State 

members such as California ARB, 

Connecticut DEP, New Jersey DEP, New 

Mexico ED, Washington DE, 

Massachusetts DEP, Illinois EPA, Iowa 

DNR, and TCR These meetings are 

documented in the docket. EPA intends 

to continue to work closely with State, 

local, and Tribal agencies during rule 

implementation. 

Consistent with section 205 of the 

UMRA, EPA has identified and 

considered a reasonable number of 

regulatory alternatives. EPA carefully 

examined regulatory alternatives, and 

selected the lowest cost/least 

burdensome alternative that EPA deems 

adequate to address Congressional 

concerns and to provide a consistent, 

comprehensive source of information 

about emissions of GHGs. EPA has 

considered the costs and benefits of the 

GHG reporting rule, and has concluded 

that the costs will fall mainly on the 

private sector (approximately $77 

million), with some costs incurred by 

State, local, and Tribal governments that 

must report their emissions (less than 

$10.1 million) that own and operate 

stationary combustion units, landfills, 

or natural gas local distribution 

companies (LDCs). EPA estimates that 

an additional 2,034 facilities owned by 

State, local, or Tribal governments will 

incur approximately $2.0 million in 

costs during the first year of the rule to 

make a reporting determination and 

subsequently determine that their 

emissions are below the threshold and 

thus, they are not required to report 

their emissions. Furthermore, we think 

it is unlikely that State, local, and Tribal 

governments would begin operating 

large industrial facilities, similar to 

those affected by this rulemaking 

operated by the private sector. 

Initially, EPA estimates that costs of 

complying with the final rule will be 

widely dispersed throughout many 

sectors of the economy. Although EPA 

acknowledges that over time changes in 

the patterns of economic activity may 

mean that GHG generation and thus 

reporting costs will change, data are 

inadequate for projecting these changes. 

Thus, EPA assumes that costs averaged 

over the first three years of the program 

are typical of ongoing costs of 

compliance. EPA estimates that future 

compliance costs will total 

approximately $104 million per year. 

EPA examined the distribution of these 

costs between private owners and State, 

local, and Tribal governments owning 

GHG emitters. In addition, EPA 

examined, within the private sector, the 

impacts on various industries. In 

general, estimated cost per entity 

represents less than 0.1 percent of 

company sales in affected industries. 

These costs are broadly distributed to a 

variety of economic sectors and 

represent approximately 0.001 percent 

of 2008 Gross Domestic Product; overall, 

EPA does not believe the final rule will 

have a significant macroeconomic 

impact on the national economy. 

Therefore, this rule is not subject to the 

requirements of section 203 of UMRA 

because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. 

EPA does not anticipate that 

substantial numbers of either public or 

private sector entities will incur 

significant economic impacts as a result 

of this final rule. EPA further expects 

that benefits of the final rule will 

include more and better information for 

EPA and the private sector about 

emissions of GHGs. This improved 

information will enhance EPA’s ability 

to develop sound future climate 

policies, and may encourage GHG 

emitters to develop voluntary plans to 

reduce their emissions. 

This regulation applies directly to 

facilities that supply fuel or chemicals 

that when used emit greenhouse gases, 

to motor vehicle manufacturers, and to 

facilities that directly emit greenhouses 

gases. It does not apply to governmental 

entities unless the government entity 

owns a facility that directly emits GHGs 

above threshold levels such as a landfill 

or large stationary combustion source, 

or LDC. In addition, this rule does not 

impose any implementation 

responsibilities on State, local, or Tribal 

governments and it is not expected to 

increase the cost of existing regulatory 

programs managed by those 

governments. Thus, the impact on 

governments affected by the rule is 

expected to be minimal. 

E. Executive Order 13132: Federalism 

EO 13132, entitled ‘‘Federalism’’ (64 

FR 43255, August 10, 1999), requires 

EPA to develop an accountable process 

to ensure ‘‘meaningful and timely input 

by State and local officials in the 

development of regulatory policies that 

have Federalism implications.’’ 

‘‘Policies that have Federalism 

implications’’ is defined in the EO to 

include regulations that have 

‘‘substantial direct effects on the States, 

on the relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government.’’ 

This final rule does not have 

Federalism implications. It will not 

have substantial direct effects on the 

States, on the relationship between the 

national government and the States, or 

on the distribution of power and 

responsibilities among the various 

levels of government, as specified in EO 

13132. However, for a more detailed 

discussion about how this final rule 

relates to existing State programs, please 

see Section II of the proposal preamble 

(74 FR 16457 to 16461, April 10, 2009) 

and Sections I.E. and II.C.2 of this 

preamble. 

This regulation applies directly to 

facilities that supply fuel or chemicals 

that when used emit greenhouse gases, 

motor vehicle manufacturers, or 

facilities that directly emit greenhouses 

gases. It does not apply to governmental 

entities unless the government entity 

owns a facility that directly emits GHGs 

above threshold levels such as a landfill, 

large stationary combustion source, or 

LDC, so relatively few government 

facilities would be affected. This 

regulation also does not limit the power 

of States or localities to collect GHG 

data and/or regulate GHG emissions. 

Thus, EO 13132 does not apply to this 

rule. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, EPA 

specifically solicited comments on the 

proposed rule from State and local 

officials. See Section VIII.D above, for 

discussion of outreach activities to 

State, local, or Tribal organizations. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This final rule does not have Tribal 

implications, as specified in EO 13175 

(65 FR 67249, November 9, 2000). This 


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regulation applies directly to facilities 

that supply fuel or chemicals that when 

used emit GHGs or facilities that 

directly emit greenhouses gases. 

Facilities expected to be affected by the 

final rule are not expected to be owned 

by Tribal governments. Thus, Executive 

Order 13175 does not apply to this final 

rule. 

Although EO 13175 does not apply to 

this final rule, EPA sought opportunities 

to provide information to Tribal 

governments and representatives during 

development of the rule. In consultation 

with EPA’s American Indian 

Environment Office, EPA’s outreach 

plan included tribes. EPA conducted 

several conference calls with Tribal 

organizations during the proposal 

phase. For example, EPA staff provided 

information to tribes through conference 

calls with multiple Indian working 

groups and organizations at EPA that 

interact with tribes and through 

individual calls with two Tribal board 

members of TCR. In addition, EPA 

prepared a short article on the GHG 

reporting rule that appeared on the front 

page a Tribal newsletter—Tribal Air 

News—that was distributed to EPA/ 

OAQPS’s network of Tribal 

organizations. EPA gave a presentation 

on various climate efforts, including the 

mandatory reporting rule, at the 

National Tribal Conference on 

Environmental Management on June 

24–26, 2008. In addition, EPA had 

copies of a short information sheet 

distributed at a meeting of the National 

Tribal Caucus. See the ‘‘Summary of 

EPA Outreach Activities for Developing 

the GHG reporting rule,’’ in Docket No. 

EPA–HQ–OAR–2008–0508–055 for a 

complete list of Tribal contacts. EPA 

participated in a conference call with 

Tribal air coordinators in April 2009 

and prepared a guidance sheet for Tribal 

governments on the proposed rule. It 

was posted on the MRR Web site and 

published in the Tribal Air Newsletter. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

EPA interprets EO 13045 (62 FR 

19885, April 23, 1997) as applying only 

to those regulatory actions that concern 

health or safety risks, such that the 

analysis required under section 5–501 of 

the EO has the potential to influence the 

regulation. This action is not subject to 

EO 13045 because it does not establish 

an environmental standard intended to 

mitigate health or safety risks. 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

This final rule is not a ‘‘significant 

energy action’’ as defined in EO 13211 

(66 FR 28355, May 22, 2001) because it 

is not likely to have a significant 

adverse effect on the supply, 

distribution, or use of energy. Further, 

we have concluded that this rule is not 

likely to have any adverse energy 

effects. This final rule relates to 

monitoring, reporting and 

recordkeeping at facilities that supply 

fuel or chemicals that when used emit 

GHGs or facilities that directly emit 

greenhouses gases and does not impact 

energy supply, distribution or use. 

Therefore, we conclude that this rule is 

not likely to have any adverse effects on 

energy supply, distribution, or use. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs EPA to 

use voluntary consensus standards in its 

regulatory activities unless to do so 

would be inconsistent with applicable 

law or otherwise impractical. Voluntary 

consensus standards are technical 

standards (e.g., materials specifications, 

test methods, sampling procedures, and 

business practices) that are developed or 

adopted by voluntary consensus 

standards bodies. NTTAA directs EPA 

to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This rulemaking involves technical 

standards. EPA will use more than 60 

voluntary consensus standards from 10 

different voluntary consensus standards 

bodies, including the following: ASTM, 

ASME, ISO, Gas Processors Association, 

American Gas Association, and National 

Lime Association. These voluntary 

consensus standards will help facilities 

monitor, report, and keep records of 

GHG emissions. No new test methods 

were developed for this rule. Instead, 

from existing rules for source categories 

and voluntary GHG programs, EPA 

identified existing means of monitoring, 

reporting, and keeping records of GHG 

emissions. The existing methods 

(voluntary consensus standards) include 

a broad range of measurement 

techniques, including many for 

combustion sources such as methods to 

analyze fuel and measure its heating 

value; methods to measure gas or liquid 

flow; and methods to gauge and 

measure petroleum and petroleum 

products. The test methods are 

incorporated by reference into the final 

rule and are available as specified in 40 

CFR 98.7. 

By incorporating voluntary consensus 

standards into this final rule, EPA is 

both meeting the requirements of the 

NTTAA and presenting multiple 

options and flexibility for measuring 

GHG emissions. 

J. Executive Order 12898: Federal 

Actions To Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

EO 12898 (59 FR 7629, February 16, 

1994) establishes Federal executive 

policy on environmental justice. Its 

main provision directs Federal agencies, 

to the greatest extent practicable and 

permitted by law, to make 

environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the U.S. 

EPA has determined that this final 

rule will not have disproportionately 

high and adverse human health or 

environmental effects on minority or 

low-income populations because it does 

not affect the level of protection 

provided to human health or the 

environment. This final rule does not 

affect the level of protection provided to 

human health or the environment 

because it is a rule addressing 

information collection and reporting 

procedures. 

K. Congressional Review Act 

The Congressional Review Act, 5 

U.S.C. 801 et seq., as added by the Small 

Business Regulatory Enforcement 

Fairness Act of 1996, generally provides 

that before a rule may take effect, the 

agency promulgating the rule must 

submit a rule report, which includes a 

copy of the rule, to each House of the 

Congress and to the Comptroller General 

of the United States. EPA will submit a 

report containing this rule and other 

required information to the U.S. Senate, 

the U.S. House of Representatives, and 

the Comptroller General of the U.S. 

prior to publication of the rule in the 

Federal Register. A major rule cannot 

take effect until 60 days after it is 

published in the Federal Register. This 

action is a ‘‘major rule’’ as defined by 

5 U.S.C. 804(2). This rule will be 

effective December 29, 2009. 

List of Subjects 

40 CFR Part 86 

Environmental protection, 

Administrative practice and procedure, 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56373 

Air pollution control, Reporting and 

recordkeeping requirements, Motor 

vehicle pollution. 

40 CFR Part 87 

Environmental protection, Air 

pollution control, Aircraft, 

Incorporation by reference. 

40 CFR Part 89 

Environmental protection, 

Administrative practice and procedure, 

Confidential business information, 

Imports, Labeling, Motor vehicle 

pollution, Reporting and recordkeeping 

requirements, Research, Vessels, 

Warranty. 

40 CFR Part 90 

Environmental protection, 

Administrative practice and procedure, 

Confidential business information, 

Imports, Labeling, Reporting and 

recordkeeping requirements, Research, 

Warranty. 

40 CFR Part 94 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Vessels, Reporting and 

recordkeeping requirements, 

Warranties. 

40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Incorporation by 

reference, Suppliers, Reporting and 

recordkeeping requirements. 

40 CFR Part 1033 

Environmental protection, 

Administrative practice and procedure, 

Confidential business information, 

Incorporation by reference, Labeling, 

Penalties, Railroads, Reporting and 

recordkeeping requirements. 

40 CFR Part 1039 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Reporting and recordkeeping 

requirements, Warranties. 

40 CFR Part 1042 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Vessels, Reporting and 

recordkeeping requirements, 

Warranties. 

40 CFR Parts 1045, 1048, 1051, and 

1054 

Environmental protection, 

Administrative practice and procedure, 

Air pollution control, Confidential 

business information, Imports, 

Incorporation by reference, Labeling, 

Penalties, Reporting and recordkeeping 

requirements, Warranties. 

40 CFR Part 1065 

Environmental protection, 

Administrative practice and procedure, 

Incorporation by reference, Reporting 

and recordkeeping requirements, 

Research. 

Dated: September 22, 2009. 

Lisa P. Jackson, 

Administrator. 

■ For the reasons stated in the preamble, 

title 40, chapter I, of the Code of Federal 

Regulations is 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) Measure CO2, N2O, and CH4 with 

each low-hour certification test for 

heavy-duty engines using the 

procedures specified in 40 CFR part 

1065 as specified in this paragraph (n). 

Report these values in your application 

for certification. The requirements of 

this paragraph (n) apply starting with 

model year 2011 for CO2 and 2012 for 

CH4. The requirements of this paragraph 

(n) related to N2O emissions apply for 

engine families that depend on NOx

aftertreatment to meet emission 

standards starting with model year 

2013. These measurements are not 

required for NTE testing. Use the same 

units and calculations as for your other 

results to report a single weighted value 

for CO2, N2O, and CH4 for each test. 

Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/bhphr. 

(2) Round N2O to the nearest 0.001 g/ 

bhp-hr. 

(3) Round CH4 to the nearest 0.001 g/ 

bhp-hr. 

■ 3. Section 86.078–3 is amended by 

removing the paragraph designation 

‘‘(a)’’ and adding the abbreviations CH4

and N2O in alphanumeric order to read 

as follows: 

§ 86.078–3 Abbreviations. 

* * * * * 

* * * * * 

CH4 methane. 

* * * * * 

N2O nitrous oxide. 

* * * * * 

Subpart E—[Amended] 

■ 4. 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. 

* * * * * 

■ 5. Section 86.431–78 is amended by 

adding paragraph (e) to read as follows: 

§ 86.431–78 Data submission. 

* * * * * 

(e) Measure CO2, N2O, and CH4 as 

described in this paragraph (e) with 

each zero kilometer certification test (if 

one is conducted) and with each test 

conducted at the applicable minimum 

test distance as defined in § 86.427–78. 

Use the analytical equipment and 

procedures specified in 40 CFR part 

1065 as needed to measure N2O and 

CH4. Report these values in your 

application for certification. The 

requirements of this paragraph (e) apply 

starting with model year 2011 for CO2

and 2012 for CH4. The requirements of 

this paragraph (e) related to N2O 

emissions apply for engine families that 

depend on NOX aftertreatment to meet 

emission standards starting with model 

year 2013. Small-volume manufacturers 

(as defined in § 86.410–2006(e)) may 

omit measurement of N2O and CH4; 

other manufacturers may provide 

appropriate data and/or information and 

omit measurement of N2O and CH4 as 

described in 40 CFR 1065.5. Use the 

same measurement methods as for your 

other results to report a single value for 

CO2, N2O, and CH4. Round the final 

values as follows: 

(1) Round CO2 to the nearest 1 g/km. 

(2) Round N2O to the nearest 0.001 g/ 

km. 

(3) Round CH4 to the nearest 0.001 g/ 

km. 

PART 87—[AMENDED] 

■ 6. The authority citation for part 87 is 

revised to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 


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56374 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

Subpart A—[Amended] 

■ 7. Section 87.2 is amended by revising 

the section heading and adding the 

abbreviation CO2 in alphanumeric order 

to read as follows: 

§ 87.2 Acronyms and abbreviations. 

* * * * * 

CO2 Carbon dioxide. 

* * * * * 

■ 8. 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 January 1, 2011, report 

CO2 values along with your emission 

levels of regulated NOX to the 

Administrator for engines of a type or 

model of which the date of manufacture 

of the first individual production model 

was on or after January 1, 2011. By 

January 1, 2011, report CO2 values along 

with your emission levels of regulated 

NOX to the Administrator for engines 

currently in production and of a type or 

model for which the date of 

manufacture of the individual engine 

was before January 1, 2011. Round CO2

to the nearest 1 g/kilonewton rO. 

(c) Report CO2 by calculation from 

fuel mass flow rate measurements in 

Appendices 3 and 5 to ICAO Annex 16, 

volume II or alternatively, according to 

the measurement criteria of CO2 in 

Appendices 3 and 5 to ICAO Annex 16, 

volume II. 

PART 89—[AMENDED] 

■ 9. The authority citation for part 89 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart B—[Amended] 

■ 10. 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 as specified in 

§ 89.407(d)(1); 

* * * * * 

Subpart E—[Amended] 

■ 11. 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. 

Use the same units and modal 

calculations as for your other results to 

report a single weighted value for CO2; 

round CO2 to the nearest 1 g/kW-hr. 

* * * * * 

PART 90—[AMENDED] 

■ 12. The authority citation for part 90 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart B—[Amended] 

■ 13. 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 as specified in 

§ 90.409(c)(1); 

* * * * * 

Subpart E—[Amended] 

■ 14. 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. 

Use the same units and modal 

calculations as for your other results to 

report a single weighted value for CO2; 

round CO2 to the nearest 1 g/kW–hr. 

* * * * * 

PART 94—[AMENDED] 

■ 15. The authority citation for part 94 

continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 16. Section 94.3 is amended by adding 

the abbreviation CH4 in alphanumeric 

order to read as follows: 

§ 94.3 Abbreviations. 

* * * * * 

CH4 methane. 

* * * * * 

Subpart B—[Amended] 

■ 17. Section 94.103 is amended by 

adding paragraph (c) to read as follows: 

§ 94.103 Test procedures for Category 1 

marine engines. 

* * * * * 

(c) Measure CH4 as specified in 40 

CFR 1042.235 starting in the 2012 

model year. 

■ 18. 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. Measure CO2 as specified in 40 

CFR 1042.235 starting in the 2011 

model year. Measure CH4 as specified in 

40 CFR 1042.235 starting in the 2012 

model year. 

Subpart C—[Amended] 

■ 19. 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 and CH4 as specified in 

40 CFR 89.407(d)(1) and § 94.103(c) for 

Category 1 engines, § 94.104(e) for 

Category 2 engines, and § 94.109(d) for 

Category 3 engines. Small-volume 

manufacturers may omit measurement 

and reporting of CH4. 

* * * * * 

■ 20. Add part 98 to read as follows: 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

Sec. 

Subpart A—General Provisions 

98.1 Purpose and scope. 

98.2 Who must report? 

98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

98.4 Authorization and responsibilities of 

the designated representative. 

98.5 How is the report submitted? 

98.6 Definitions. 

98.7 What standardized methods are 

incorporated by reference into this part? 

98.8 What are the compliance and 

enforcement provisions of this part? 

98.9 Addresses. 

Table A–1 to Subpart A of Part 98—Global 

Warming Potentials (100-Year Time 

Horizon) 

Table A–2 to Subpart A of Part 98—Units of 

Measure Conversions 


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Subpart B—[RESERVED] 

Subpart C—General Stationary Fuel 

Combustion Sources 

98.30 Definition of the source category. 

98.31 Reporting threshold. 

98.32 GHGs to report. 

98.33 Calculating GHG emissions. 

98.34 Monitoring and QA/QC 

requirements. 

98.35 Procedures for estimating missing 

data. 

98.36 Data reporting requirements. 

98.37 Records that must be retained. 

98.38 Definitions. 

Table C–1 to Subpart C of Part 98—Default 

CO2 Emission Factors and High Heat 

Values for Various Types of Fuel 

Table C–2 to Subpart C of Part 98—Default 

CH4 and N2O Emission Factors for 

Various Types of Fuel 

Subpart D—Electricity Generation 

98.40 Definition of the source category. 

98.41 Reporting threshold. 

98.42 GHGs to report. 

98.43 Calculating GHG emissions. 

98.44 Monitoring and QA/QC requirements 

98.45 Procedures for estimating missing 

data. 

98.46 Data reporting requirements. 

98.47 Records that must be retained. 

98.48 Definitions. 

Subpart E—Adipic Acid Production 

98.50 Definition of source category. 

98.51 Reporting threshold. 

98.52 GHGs to report. 

98.53 Calculating GHG emissions. 

98.54 Monitoring and QA/QC requirements 

98.55 Procedures for estimating missing 

data. 

98.56 Data reporting requirements. 

98.57 Records that must be retained. 

98.58 Definitions. 

Subpart F—Aluminum Production 

98.60 Definition of the source category. 

98.61 Reporting threshold. 

98.62 GHGs to report. 

98.63 Calculating GHG emissions. 

98.64 Monitoring and QA/QC 

requirements. 

98.65 Procedures for estimating missing 

data. 

98.66 Data reporting requirements. 

98.67 Records that must be retained. 

98.68 Definitions. 

Table F–1 to Subpart F of Part 98—Slope and 

Overvoltage Coefficients for the 

Calculation of PFC Emissions From 

Aluminum Production 

Table F–2 to Subpart F of Part 98—Default 

Data Sources for Parameters Used for 

CO2 Emissions 

Subpart G—Ammonia Manufacturing 

98.70 Definition of source category. 

98.71 Reporting threshold. 

98.72 GHGs to report. 

98.73 Calculating GHG emissions. 

98.74 Monitoring and QA/QC 

requirements. 

98.75 Procedures for estimating missing 

data. 

98.76 Data reporting requirements. 

98.77 Records that must be retained. 

98.78 Definitions. 

Subpart H—Cement Production 

98.80 Definition of the source category. 

98.81 Reporting threshold. 

98.82 GHGs to report. 

98.83 Calculating GHG emissions. 

98.84 Monitoring and QA/QC 

requirements. 

98.85 Procedures for estimating missing 

data. 

98.86 Data reporting requirements. 

98.87 Records that must be retained. 

98.88 Definitions. 

Subpart I—[RESERVED] 

Subpart J—[RESERVED] 

Subpart K—Ferroalloy Production 

98.110 Definition of the source category. 

98.111 Reporting threshold. 

98.112 GHGs to report. 

98.113 Calculating GHG emissions. 

98.114 Monitoring and QA/QC 

requirements. 

98.115 Procedures for estimating missing 

data. 

98.116 Data reporting requirements. 

98.117 Records that must be retained. 

98.118 Definitions. 

Table K–1 to Subpart K of Part 98—Electric 

Arc Furnace (EAF) CH4 Emission Factors 

Subpart L—[RESERVED] 

Subpart M—[RESERVED] 

Subpart N—Glass Production 

98.140 Definition of the source category. 

98.141 Reporting threshold. 

98.142 GHGs to report. 

98.143 Calculating GHG emissions. 

98.144 Monitoring and QA/QC 

requirements. 

98.145 Procedures for estimating missing 

data. 

98.146 Data reporting requirements. 

98.147 Records that must be retained. 

98.148 Definitions. 

Table N–1 to Subpart N of Part 98—CO2

Emission Factors for Carbonate-Based 

Raw Materials 

Subpart O—HCFC–22 Production and HFC– 

23 Destruction 

98.150 Definition of the source category. 

98.151 Reporting threshold. 

98.152 GHGs to report. 

98.153 Calculating GHG emissions. 

98.154 Monitoring and QA/QC 

requirements. 

98.155 Procedures for estimating missing 

data. 

98.156 Data reporting requirements. 

98.157 Records that must be retained. 

98.158 Definitions. 

Table O–1 to Subpart O of Part 98—Emission 

Factors for Equipment Leaks 

Subpart P—Hydrogen Production 

98.160 Definition of the source category. 

98.161 Reporting threshold. 

98.162 GHGs to report. 

98.163 Calculating GHG emissions. 

98.164 Monitoring and QA/QC 

requirements. 

98.165 Procedures for estimating missing 

data. 

98.166 Data reporting requirements. 

98.167 Records that must be retained. 

98.168 Definitions. 

Subpart Q—Iron and Steel Production 

98.170 Definition of the source category. 

98.171 Reporting threshold. 

98.172 GHGs to report. 

98.173 Calculating GHG emissions. 

98.174 Monitoring and QA/QC 

requirements. 

98.175 Procedures for estimating missing 

data. 

98.176 Data reporting requirements. 

98.177 Records that must be retained. 

98.178 Definitions. 

Subpart R—Lead Production 

98.180 Definition of the source category. 

98.181 Reporting threshold. 

98.182 GHGs to report. 

98.183 Calculating GHG emissions. 

98.184 Monitoring and QA/QC 

requirements. 

98.185 Procedures for estimating missing 

data. 

98.186 Data reporting procedures. 

98.187 Records that must be retained. 

98.188 Definitions. 

Subpart S—Lime Manufacturing 

98.190 Definition of the source category. 

98.191 Reporting threshold. 

98.192 GHGs to report. 

98.193 Calculating GHG emissions. 

98.194 Monitoring and QA/QC 

requirements. 

98.195 Procedures for estimating missing 

data. 

98.196 Data reporting requirements. 

98.197 Records that must be retained. 

98.198 Definitions. 

Table S–1 to Subpart S of Part 98—Basic 

Parameters for the Calculation of 

Emission Factors for Lime Production 

Subpart T—[RESERVED] 

Subpart U—Miscellaneous Uses of 

Carbonate 

98.210 Definition of the source category. 

98.211 Reporting threshold. 

98.212 GHGs to report. 

98.213 Calculating GHG emissions. 

98.214 Monitoring and QA/QC 

requirements. 

98.215 Procedures for estimating missing 

data. 

98.216 Data reporting requirements. 

98.217 Records that must be retained. 

98.218 Definitions. 

Table U–1 to Subpart U of Part 98—CO2

Emission Factors for Common 

Carbonates 

Subpart V—Nitric Acid Production 

98.220 Definition of source category. 

98.221 Reporting threshold. 

98.222 GHGs to report. 

98.223 Calculating GHG emissions. 

98.224 Monitoring and QA/QC 

requirements. 

98.225 Procedures for estimating missing 

data. 

98.226 Data reporting requirements. 

98.227 Records that must be retained. 

98.228 Definitions. 


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Subpart W—[RESERVED] 

Subpart X—Petrochemical Production 

98.240 Definition of the source category. 

98.241 Reporting threshold. 

98.242 GHGs to report. 

98.243 Calculating GHG emissions. 

98.244 Monitoring and QA/QC 

requirements. 

98.245 Procedures for estimating missing 

data. 

98.246 Data reporting requirements. 

98.247 Records that must be retained. 

98.248 Definitions. 

Subpart Y—Petroleum Refineries 

98.250 Definition of source category. 

98.251 Reporting threshold. 

98.252 GHGs to report. 

98.253 Calculating GHG emissions. 

98.254 Monitoring and QA/QC 

requirements. 

98.255 Procedures for estimating missing 

data. 

98.256 Data reporting requirements. 

98.257 Records that must be retained. 

98.258 Definitions. 

Subpart Z—Phosphoric Acid Production 

98.260 Definition of the source category. 

98.261 Reporting threshold. 

98.262 GHGs to report. 

98.263 Calculating GHG emissions. 

98.264 Monitoring and QA/QC 

requirements. 

98.265 Procedures for estimating missing 

data. 

98.266 Data reporting requirements. 

98.267 Records that must be retained. 

98.268 Definitions. 

Table Z–1 to Subpart Z of Part 98—Default 

Chemical Composition of Phosphate 

Rock by Origin 

Subpart AA—Pulp and Paper Manufacturing 

98.270 Definition of source category. 

98.271 Reporting threshold. 

98.272 GHGs to report. 

98.273 Calculating GHG emissions. 

98.274 Monitoring and QA/QC 

requirements. 

98.275 Procedures for estimating missing 

data. 

98.276 Data reporting requirements. 

98.277 Records that must be retained. 

98.278 Definitions. 

Table AA–1 to Subpart AA of Part 98—Kraft 

Pulping Liquor Emissions Factors for 

Biomass-Based CO2, CH4, and N2O 

Table AA–2 to Subpart AA of Part 98—Kraft 

Lime Kiln and Calciner Emissions 

Factors for Fossil Fuel-Based CO2, CH4, 

and N2O 

Subpart BB—Silicon Carbide Production 

98.280 Definition of the source category. 

98.281 Reporting threshold. 

98.282 GHGs to report. 

98.283 Calculating GHG emissions. 

98.284 Monitoring and QA/QC 

requirements. 

98.285 Procedures for estimating missing 

data. 

98.286 Data reporting requirements. 

98.287 Records that must be retained. 

98.288 Definitions. 

Subpart CC—Soda Ash Manufacturing 

98.290 Definition of the source category. 

98.291 Reporting threshold. 

98.292 GHGs to report. 

98.293 Calculating GHG emissions. 

98.294 Monitoring and QA/QC 

requirements. 

98.295 Procedures for estimating missing 

data. 

98.296 Data reporting requirements. 

98.297 Records that must be retained. 

98.298 Definitions. 

Subpart DD—[RESERVED] 

Subpart EE—Titanium Dioxide Production 

98.310 Definition of the source category. 

98.311 Reporting threshold. 

98.312 GHGs to report. 

98.313 Calculating GHG emissions. 

98.314 Monitoring and QA/QC 

requirements. 

98.315 Procedures for estimating missing 

data. 

98.316 Data reporting requirements. 

98.317 Records that must be retained. 

98.318 Definitions. 

Subpart FF—[RESERVED] 

Subpart GG—Zinc Production 

98.330 Definition of the source category. 

98.331 Reporting threshold. 

98.332 GHGs to report. 

98.333 Calculating GHG emissions. 

98.334 Monitoring and QA/QC 

requirements. 

98.335 Procedures for estimating missing 

data. 

98.336 Data reporting requirements. 

98.337 Records that must be retained. 

98.338 Definitions. 

Subpart HH—Municipal Solid Waste 

Landfills 

98.340 Definition of the source category. 

98.341 Reporting threshold. 

98.342 GHGs to report. 

98.343 Calculating GHG emissions. 

98.344 Monitoring and QA/QC 

requirements. 

98.345 Procedures for estimating missing 

data. 

98.346 Data reporting requirements. 

98.347 Records that must be retained. 

98.348 Definitions. 

Table HH–1 to Subpart HH of Part 98— 

Emissions Factors, Oxidation Factors 

and Methods 

Table HH–2 to Subpart HH of Part 98—U.S. 

Per Capita Waste Disposal Rates 

Table HH–3 to Subpart HH of Part 98— 

Landfill Gas Collection Efficiencies 

Subpart II—[RESERVED] 

Subpart JJ—Manure Management 

98.360 Definition of the source category. 

98.361 Reporting threshold. 

98.362 GHGs to report. 

98.363 Calculating GHG emissions. 

98.364 Monitoring and QA/QC 

requirements. 

98.365 Procedures for estimating missing 

data. 

98.366 Data reporting requirements. 

98.367 Records that must be retained. 

98.368 Definitions. 

Table JJ–1 to Subpart JJ of Part 98—Animal 

Population Threshold Level Below 

which Facilities are not required to 

report Emissions under Subpart JJ 

Table JJ–2 to Subpart JJ of Part 98—Waste 

Characteristics Data 

Table JJ–3 to Subpart JJ of Part 98—StateSpecific Volatile Solids (VS) and 

Nitrogen (N) Excretion Rates for Cattle 

Table JJ–4 to Subpart JJ of Part 98—Volatile 

Solids and Nitrogen Removal through 

Solids Separation 

Table JJ–5 to Subpart JJ of Part 98—Methane 

Conversion Factors 

Table JJ–6 to Subpart JJ of Part 98—Collection 

Efficiencies of Anaerobic Digesters 

Table JJ–7 to Subpart JJ of Part 98—Nitrous 

Oxide Emission Factors (kg N2O–N/kg 

Kjdl N) 

Subpart KK—[RESERVED] 

Subpart LL—Suppliers of Coal-based Liquid 

Fuels 

98.380 Definition of the source category. 

98.381 Reporting threshold. 

98.382 GHGs to report. 

98.383 Calculating GHG emissions. 

98.384 Monitoring and QA/QC 

requirements. 

98.385 Procedures for estimating missing 

data. 

98.386 Data reporting requirements. 

98.387 Records that must be retained. 

98.388 Definitions. 

Subpart MM—Suppliers of Petroleum 

Products 

98.390 Definition of the source category. 

98.391 Reporting threshold. 

98.392 GHGs to report. 

98.393 Calculating GHG emissions. 

98.394 Monitoring and QA/QC 

requirements. 

98.395 Procedures for estimating missing 

data. 

98.396 Data reporting requirements. 

98.397 Records that must be retained. 

98.398 Definitions. 

Table MM–1 to Subpart MM—Default CO2

Factors for Petroleum Products 

Table MM–2 to Subpart MM—Default Factors 

for Biomass-Based Fuels and Biomass 

Subpart NN—Suppliers of Natural Gas and 

Natural Gas Liquids 

98.400 Definition of the source category. 

98.401 Reporting threshold. 

98.402 GHGs to report. 

98.403 Calculating GHG emissions. 

98.404 Monitoring and QA/QC 

requirements. 

98.405 Procedures for estimating missing 

data. 

98.406 Data reporting requirements. 

98.407 Records that must be retained. 

98.408 Definitions. 

Table NN–1 to Subpart NN of Part 98— 

Default Factors for Calculation 

Methodology 1 of this Subpart 

Table NN–2 to Subpart NN of Part 98— 

Lookup Default Values for Calculation 

Methodology 2 of this Subpart 

Subpart OO—Suppliers of Industrial 

Greenhouse Gases 

98.410 Definition of the source category. 


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98.411 Reporting threshold. 

98.412 GHGs to report. 

98.413 Calculating GHG emissions. 

98.414 Monitoring and QA/QC 

requirements. 

98.415 Procedures for estimating missing 

data. 

98.416 Data reporting requirements. 

98.417 Records that must be retained. 

98.418 Definitions. 

Subpart PP—Suppliers of Carbon Dioxide 

98.420 Definition of the source category. 

98.421 Reporting threshold. 

98.422 GHGs to report. 

98.423 Calculating CO2 supply. 

98.424 Monitoring and QA/QC 

requirements. 

98.425 Procedures for estimating missing 

data. 

98.426 Data reporting requirements. 

98.427 Records that must be retained. 

98.428 Definitions. 

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

Subpart A—General Provisions 

§ 98.1 Purpose and scope. 

(a) This part establishes mandatory 

greenhouse gas (GHG) reporting 

requirements for owners and operators 

of certain facilities that directly emit 

GHG as well as for certain fossil fuel 

suppliers and industrial GHG suppliers. 

For suppliers, the GHGs reported are the 

quantity that would be emitted from 

combustion or use of the products 

supplied. 

(b) Owners and operators of facilities 

and suppliers that are subject to this 

part must follow the requirements of 

subpart A and all applicable subparts of 

this part. If a conflict exists between a 

provision in subpart A and any other 

applicable subpart, the requirements of 

the subparts B through PP of this part 

shall take precedence. 

§ 98.2 Who must report? 

(a) The GHG reporting requirements 

and related monitoring, recordkeeping, 

and reporting requirements of this part 

apply to the owners and operators of 

any facility that is located in the United 

States and that meets the requirements 

of either paragraph (a)(1), (a)(2), or (a)(3) 

of this section; and any supplier that 

meets the requirements of paragraph 

(a)(4) of this section: 

(1) A facility that contains any source 

category (as defined in subparts C 

through JJ of this part) that is listed in 

this paragraph (a)(1) in any calendar 

year starting in 2010. For these facilities, 

the annual GHG report must cover all 

source categories and GHGs for which 

calculation methodologies are provided 

in subparts C through JJ of this part. 

(i) Electricity generation (units that 

report CO2 emissions year-round 

through 40 CFR part 75). 

(ii) Adipic acid production. 

(iii) Aluminum production. 

(iv) Ammonia manufacturing. 

(v) Cement production. 

(vi) HCFC–22 production. 

(vii) HFC–23 destruction processes 

that are not collocated with a HCFC–22 

production facility and that destroy 

more than 2.14 metric tons of HFC–23 

per year. 

(viii) Lime manufacturing. 

(ix) Nitric acid production. 

(x) Petrochemical production. 

(xi) Petroleum refineries. 

(xii) Phosphoric acid production. 

(xiii) Silicon carbide production. 

(xiv) Soda ash production. 

(xv) Titanium dioxide production. 

(xvi) Municipal solid waste landfills 

that generate CH4 in amounts equivalent 

to 25,000 metric tons CO2e or more per 

year, as determined according to subpart 

HH of this part. 

(xvii) Manure management systems 

with combined CH4 and N2O emissions 

in amounts equivalent to 25,000 metric 

tons CO2e or more per year, as 

determined according to subpart JJ of 

this part. 

(2) A facility that contains any source 

category (as defined in subparts C 

through JJ of this part) that is listed in 

this paragraph (a)(2) in any calendar 

year starting in 2010 and that emits 

25,000 metric tons CO2e or more per 

year in combined emissions from 

stationary fuel combustion units, 

miscellaneous uses of carbonate, and all 

source categories that are listed in this 

paragraph. For these facilities, the 

annual GHG report must cover all 

source categories and GHGs for which 

calculation methodologies are provided 

in subparts C through JJ of this part. 

(i) Ferroalloy Production. 

(ii) Glass Production. 

(iii) Hydrogen Production. 

(iv) Iron and Steel Production. 

(v) Lead Production. 

(vi) Pulp and Paper Manufacturing. 

(vii) Zinc Production. 

(3) A facility that in any calendar year 

starting in 2010 meets all three of the 

conditions listed in this paragraph 

(a)(3). For these facilities, the annual 

GHG report must cover emissions from 

stationary fuel combustion sources only. 

(i) The facility does not meet the 

requirements of either paragraph (a)(1) 

or (a)(2) of this section. 

(ii) The aggregate maximum rated heat 

input capacity of the stationary fuel 

combustion units at the facility is 30 

mmBtu/hr or greater. 

(iii) The facility emits 25,000 metric 

tons CO2e or more per year in combined 

emissions from all stationary fuel 

combustion sources. 

(4) A supplier (as defined in subparts 

KK through PP of this part) that 

provides products listed in this 

paragraph (a)(4) in any calendar year 

starting in 2010. For these suppliers, the 

annual GHG report must cover all 

applicable products for which 

calculation methodologies are provided 

in subparts KK through PP of this part. 

(i) Coal-to-liquids suppliers, as 

specified in this paragraph (a)(4)(i). 

(A) All producers of coal-to-liquid 

products. 

(B) Importers of an annual quantity of 

coal-to-liquid products that is 

equivalent to 25,000 metric tons CO2e or 

more. 

(C) Exporters of an annual quantity of 

coal-to-liquid products is equivalent to 

25,000 metric tons CO2e or more. 

(ii) Petroleum product suppliers, as 

specified in this paragraph (a)(4)(ii): 

(A) All petroleum refineries that 

distill crude oil. 

(B) Importers of an annual quantity of 

petroleum products that is equivalent to 

25,000 metric tons CO2e or more. 

(C) Exporters of an annual quantity of 

petroleum products that is equivalent to 

25,000 metric tons CO2e or more. 

(iii) Natural gas and natural gas 

liquids suppliers, as specified in this 

paragraph (a)(4)(iii): 

(A) All natural gas fractionators. 

(B) All local natural gas distribution 

companies. 

(iv) Industrial greenhouse gas 

suppliers, as specified in this paragraph 

(a)(4)(iv): 

(A) All producers of industrial 

greenhouse gases. 

(B) Importers of industrial greenhouse 

gases with annual bulk imports of N2O, 

fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 

metric tons CO2e or more. 

(C) Exporters of industrial greenhouse 

gases with annual bulk exports of N2O, 

fluorinated GHG, and CO2 that in 

combination are equivalent to 25,000 

metric tons CO2e or more. 

(v) Carbon dioxide suppliers, as 

specified in this paragraph (a)(4)(v). 

(A) All producers of CO2. 

(B) Importers of CO2 with annual bulk 

imports of N2O, fluorinated GHG, and 

CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more. 

(C) Exporters of CO2 with annual bulk 

exports of N2O, fluorinated GHG, and 

CO2 that in combination are equivalent 

to 25,000 metric tons CO2e or more. 

(5) Research and development 

activities are not considered to be part 

of any source category defined in this 

part. 

(b) To calculate GHG emissions for 

comparison to the 25,000 metric ton 

CO2e per year emission threshold in 

paragraph (a)(2) of this section, the 

owner or operator shall calculate annual 


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CO2e emissions, as described in 

paragraphs (b)(1) through (b)(4) of this 

section. 

(1) Calculate the annual emissions of 

CO2, CH4, N2O,and each fluorinated 

GHG in metric tons from all applicable 

source categories listed in paragraph 

(a)(2) of this section. The GHG 

emissions shall be calculated using the 

calculation methodologies specified in 

each applicable subpart and available 

company records. Include emissions 

from only those gases listed in Table A– 

1 of this subpart. 

(2) For each general stationary fuel 

combustion unit, calculate the annual 

CO2 emissions in metric tons using any 

of the four calculation methodologies 

specified in § 98.33(a). Calculate the 

annual CH4 and N2O emissions from the 

stationary fuel combustion sources in 

metric tons using the appropriate 

equation in § 98.33(c). Exclude carbon 

dioxide emissions from the combustion 

of biomass, but include emissions of 

CH4 and N2O from biomass combustion. 

(3) For miscellaneous uses of 

carbonate, calculate the annual CO2

emissions in metric tons using the 

procedures specified in subpart U of 

this part. 

(4) Sum the emissions estimates from 

paragraphs (b)(1), (b)(2), and (b)(3) of 

this section for each GHG and calculate 

metric tons of CO2e using Equation A– 

1 of this section. 

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 listed in Table A–1 of this subpart, 

metric tons/year. 

GWPi = Global warming potential for each 

greenhouse gas from Table A–1 of this 

subpart. 

n = The number of greenhouse gases emitted. 

(5) For purpose of determining if an 

emission threshold has been exceeded, 

include in the emissions calculation any 

CO2 that is captured for transfer off site. 

(c) To calculate GHG emissions for 

comparison to the 25,000 metric ton 

CO2e/year emission threshold for 

stationary fuel combustion under 

paragraph (a)(3) of this section, calculate 

CO2, CH4, and N2O emissions from each 

stationary fuel combustion unit by 

following the methods specified in 

paragraph (b)(2) of this section. Then, 

convert the emissions of each GHG to 

metric tons CO2e per year using 

Equation A–1 of this section, and sum 

the emissions for all units at the facility. 

(d) To calculate GHG quantities for 

comparison to the 25,000 metric ton 

CO2 per year threshold for importers 

and exporters of coal-to-liquid products 

under paragraph (a)(4)(i) of this section, 

calculate the mass in metric tons per 

year of CO2 that would result from the 

complete combustion or oxidation of the 

quantity of coal-to-liquid products that 

are imported during the reporting year 

and that are exported during the 

reporting year. Calculate the emissions 

using the methodology specified in 

subpart LL of this part. 

(e) To calculate GHG quantities for 

comparison to the 25,000 metric ton 

CO2e per year threshold for importers 

and exporters of petroleum products 

under paragraph (a)(4)(ii) of this section, 

calculate the mass in metric tons per 

year of CO2 that would result from the 

complete combustion or oxidation of the 

volume of petroleum products and 

natural gas liquids that are imported 

during the reporting year and that are 

exported during the reporting year. 

Calculate the emissions using the 

methodology specified in subpart MM 

of this part. 

(f) To calculate GHG quantities for 

comparison to the 25,000 metric ton 

CO2e per year threshold under 

paragraph (a)(4) of this section for 

importers and exporters of industrial 

greenhouse gases and for importers and 

exporters of CO2, the owner or operator 

shall calculate the mass in metric tons 

per year of CO2e imports and exports as 

described in paragraphs (f)(1) through 

(f)(3) of this section. 

(1) Calculate the mass in metric tons 

per year of CO2, N2O, and each 

fluorinated GHG that is imported and 

the mass in metric tons per year of CO2, 

N2O, and each fluorinated GHG that is 

exported during the year. Include only 

those gases listed in Table A–1 of this 

subpart. 

(2) Convert the mass of each imported 

and each GHG exported from paragraph 

(f)(1) of this section to metric tons of 

CO2e using Equation A–1 of this section. 

(3) Sum the total annual metric tons 

of CO2e in paragraph (f)(2) of this 

section for all imported GHGs. Sum the 

total annual metric tons of CO2e in 

paragraph (f)(2) of this section for all 

exported GHGs. 

(g) If a capacity or generation 

reporting threshold in paragraph (a)(1) 

of this section applies, the owner or 

operator shall review the appropriate 

records and perform any necessary 

calculations to determine whether the 

threshold has been exceeded. 

(h) An owner or operator of a facility 

or supplier that does not meet the 

applicability requirements of paragraph 

(a) of this section is not subject to this 

rule. Such owner or operator would 

become subject to the rule and reporting 

requirements § 98.3(b)(3), if a facility or 

supplier exceeds the applicability 

requirements of paragraph (a) of this 

section at a later time. Thus, the owner 

or operator should reevaluate the 

applicability to this part (including the 

revising of any relevant emissions 

calculations or other calculations) 

whenever there is any change that could 

cause a facility or supplier to meet the 

applicability requirements of paragraph 

(a) of this section. Such changes include 

but are not limited to process 

modifications, increases in operating 

hours, increases in production, changes 

in fuel or raw material use, addition of 

equipment, and facility expansion. 

(i) Except as provided in this 

paragraph, once a facility or supplier is 

subject to the requirements of this part, 

the owner or operator must continue for 

each year thereafter to comply with all 

requirements of this part, including the 

requirement to submit annual GHG 

reports, even if the facility or supplier 

does not meet the applicability 

requirements in paragraph (a) of this 

section in a future year. 

(1) If reported emissions are less than 

25,000 metric tons CO2e per year for five 

consecutive years, then the owner or 

operator may discontinue complying 

with this part provided that the owner 

or operator submits a notification to the 

Administrator that announces the 

cessation of reporting and explains the 

reasons for the reduction in emissions. 

The notification shall be submitted no 

later than March 31 of the year 

immediately following the fifth 

consecutive year of emissions less than 

25,000 tons CO2e per year. The owner 

or operator must maintain the 

corresponding records required under 

§ 98.3(g) for each of the five consecutive 

years and retain such records for three 

years following the year that reporting 

was discontinued. The owner or 

operator must resume reporting if 

annual emissions in any future calendar 

year increase to 25,000 metric tons CO2e 

per year or more. 

(2) If reported emissions are less than 

15,000 metric tons CO2e per year for 

three consecutive years, then the owner 

or operator may discontinue complying 

with this part provided that the owner 

or operator submits a notification to the 

Administrator that announces the 

cessation of reporting and explains the 

reasons for the reduction in emissions. 

The notification shall be submitted no 

later than March 31 of the year 

immediately following the third 

consecutive year of emissions less than 

15,000 tons CO2e per year. The owner 

or operator must maintain the 

corresponding records required under 

§ 98.3(g) for each of the three 


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consecutive years and retain such 

records for three years following the 

year that reporting was discontinued. 

The owner or operator must resume 

reporting if annual emissions in any 

future calendar year increase to 25,000 

metric tons CO2e per year or more. 

(3) If the operations of a facility or 

supplier are changed such that all 

applicable GHG-emitting processes and 

operations listed in paragraphs (a)(1) 

through (a)(4) of this section cease to 

operate, then the owner or operator is 

exempt from reporting in the years 

following the year in which cessation of 

such operations occurs, provided that 

the owner or operator submits a 

notification to the Administrator that 

announces the cessation of reporting 

and certifies to the closure of all GHGemitting processes and operations. This 

paragraph (i)(2) does not apply to 

seasonal or other temporary cessation of 

operations. This paragraph (i)(2) does 

not apply to facilities with municipal 

solid waste landfills. The owner or 

operator must resume reporting for any 

future calendar year during which any 

of the GHG-emitting processes or 

operations resume operation. 

(j) Table A–2 of this subpart provides 

a conversion table for some of the 

common units of measure used in part 

98. 

§ 98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

The owner or operator of a facility or 

supplier that is subject to the 

requirements of this part must submit 

GHG reports to the Administrator, as 

specified in this section. 

(a) General. Except as provided in 

paragraph (d) of this section, follow the 

procedures for emission calculation, 

monitoring, quality assurance, missing 

data, recordkeeping, and reporting that 

are specified in each relevant subpart of 

this part. 

(b) Schedule. The annual GHG report 

must be submitted no later than March 

31 of each calendar year for GHG 

emissions in the previous calendar year. 

(1) For an existing facility or supplier 

that began operation before January 1, 

2010, report emissions for calendar year 

2010 and each subsequent calendar 

year. 

(2) For a new facility or supplier that 

begins operation on or after January 1, 

2010, report emissions beginning with 

the first operating month and ending on 

December 31 of that year. Each 

subsequent annual report must cover 

emissions for the calendar year, 

beginning on January 1 and ending on 

December 31. 

(3) For any facility or supplier that 

becomes subject to this rule because of 

a physical or operational change that is 

made after January 1, 2010, report 

emissions for the first calendar year in 

which the change occurs, beginning 

with the first month of the change and 

ending on December 31 of that year. For 

a facility or supplier that becomes 

subject to this rule solely because of an 

increase in hours of operation or level 

of production, the first month of the 

change is the month in which the 

increased hours of operation or level of 

production, if maintained for the 

remainder of the year, would cause the 

facility or supplier to exceed the 

applicable threshold. Each subsequent 

annual report must cover emissions for 

the calendar year, beginning on January 

1 and ending on December 31. 

(c) Content of the annual report. 

Except as provided in paragraph (d) of 

this section, each annual GHG report 

shall contain the following information: 

(1) Facility name or supplier name (as 

appropriate) and physical street address 

including the city, state, and zip code. 

(2) Year and months covered by the 

report. 

(3) Date of submittal. 

(4) For facilities, report annual 

emissions of CO2, CH4, N2O, and each 

fluorinated GHG (as defined in § 98.6) as 

follows: 

(i) Annual emissions (excluding 

biogenic CO2) aggregated for all GHG 

from all applicable source categories in 

subparts C through JJ of this part and 

expressed in metric tons of CO2e 

calculated using Equation A–1 of this 

subpart. 

(ii) Annual emissions of biogenic CO2

aggregated for all applicable source 

categories in subparts C through JJ of 

this part. 

(iii) Annual emissions from each 

applicable source category in subparts C 

through JJ of this part, expressed in 

metric tons of each GHG listed in 

paragraphs (c)(4)(iii)(A) through 

(c)(4)(iii)(E) of this section. 

(A) Biogenic CO2. 

(B) CO2 (excluding biogenic CO2). 

(C) CH4. 

(D) N2O. 

(E) Each fluorinated GHG (including 

those not listed in Table A–1 of this 

subpart). 

(iv) Emissions and other data for 

individual units. processes, activities, 

and operations as specified in the ‘‘Data 

reporting requirements’’ section of each 

applicable subpart of this part. 

(5) For suppliers, report annual 

quantities of CO2, CH4, N2O, and each 

fluorinated GHG (as defined in § 98.6) 

that would be emitted from combustion 

or use of the products supplied, 

imported, and exported during the year. 

Calculate and report quantities at the 

following levels: 

(i) Total quantity of GHG aggregated 

for all GHG from all applicable supply 

categories in subparts KK through PP of 

this part and expressed in metric tons of 

CO2e calculated using Equation A–1 of 

this subpart. 

(ii) Quantity of each GHG from each 

applicable supply category in subparts 

KK through PP of this part, expressed in 

metric tons of each GHG. For 

fluorinated GHG, report emissions of all 

fluorinated GHG, including those not 

listed in Table A–1 of this subpart. 

(iii) Any other data specified in the 

‘‘Data reporting requirements’’ section 

of each applicable subpart of this part. 

(6) A written explanation, as required 

under § 98.3(e), if you change emission 

calculation methodologies during the 

reporting period. 

(7) A brief description of each ‘‘best 

available monitoring method’’ used 

according to paragraph (d) of this 

section, the parameter measured using 

the method, and the time period during 

which the ‘‘best available monitoring 

method’’ was used. 

(8) Each data element for which a 

missing data procedure was used 

according to the procedures of an 

applicable subpart and the total number 

of hours in the year that a missing data 

procedure was used for each data 

element. 

(9) A signed and dated certification 

statement provided by the designated 

representative of the owner or operator, 

according to the requirements of 

§ 98.4(e)(1). 

(d) Special provisions for reporting 

year 2010. 

(1) Best available monitoring 

methods. During January 1, 2010 

through March 31, 2010, owners or 

operators may use best available 

monitoring methods for any parameter 

(e.g., fuel use, daily carbon content of 

feedstock by process line) that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

a relevant subpart. The owner or 

operator must use the calculation 

methodologies and equations in the 

‘‘Calculating GHG Emissions’’ sections 

of each relevant subpart, but may use 

the best available monitoring method for 

any parameter for which it is not 

reasonably feasible to acquire, install, 

and operate a required piece of 

monitoring equipment by January 1, 

2010. Starting no later than April 1, 

2010, the owner or operator must 

discontinue using best available 

methods and begin following all 

applicable monitoring and QA/QC 

requirements of this part, except as 


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provided in paragraphs (d)(2) and (d)(3) 

of this section. Best available 

monitoring methods means any of the 

following methods specified in this 

paragraph: 

(i) Monitoring methods currently used 

by the facility that do not meet the 

specifications of an relevant subpart. 

(ii) Supplier data. 

(iii) Engineering calculations. 

(iv) Other company records. 

(2) Requests for extension of the use 

of best available monitoring methods. 

The owner or operator may submit a 

request to the Administrator to use one 

or more best available monitoring 

methods beyond March 31, 2010. 

(i) Timing of request. The extension 

request must be submitted to EPA no 

later than 30 days after the effective date 

of the GHG reporting rule. 

(ii) Content of request. Requests must 

contain the following information: 

(A) A list of specific item of 

monitoring instrumentation for which 

the request is being made and the 

locations where each piece of 

monitoring instrumentation will be 

installed. 

(B) Identification of the specific rule 

requirements (by rule subpart, section, 

and paragraph numbers) for which the 

instrumentation is needed. 

(C) A description of the reasons why 

the needed equipment could not be 

obtained and installed before April 1, 

2010. 

(D) If the reason for the extension is 

that the equipment cannot be purchased 

and delivered by April 1, 2010, include 

supporting documentation such as the 

date the monitoring equipment was 

ordered, investigation of alternative 

suppliers and the dates by which 

alternative vendors promised delivery, 

backorder notices or unexpected delays, 

descriptions of actions taken to expedite 

delivery, and the current expected date 

of delivery. 

(E) If the reason for the extension is 

that the equipment cannot be installed 

without a process unit shutdown, 

include supporting documentation 

demonstrating that it is not practicable 

to isolate the equipment and install the 

monitoring instrument without a full 

process unit shutdown. Include the date 

of the most recent process unit 

shutdown, the frequency of shutdowns 

for this process unit, and the date of the 

next planned shutdown during which 

the monitoring equipment can be 

installed. If there has been a shutdown 

or if there is a planned process unit 

shutdown between promulgation of this 

part and April 1, 2010, include a 

justification of why the equipment 

could not be obtained and installed 

during that shutdown. 

(F) A description of the specific 

actions the facility will take to obtain 

and install the equipment as soon as 

reasonably feasible and the expected 

date by which the equipment will be 

installed and operating. 

(iii) Approval criteria. To obtain 

approval, the owner or operator must 

demonstrate to the Administrator’s 

satisfaction that it is not reasonably 

feasible to acquire, install, and operate 

a required piece of monitoring 

equipment by April 1, 2010. The use of 

best available methods will not be 

approved beyond December 31, 2010. 

(3) Abbreviated emissions report for 

facilities containing only general 

stationary fuel combustion sources. In 

lieu of the report required by paragraph 

(c) of this section, the owner or operator 

of an existing facility that is in operation 

on January 1, 2010 and that meets the 

conditions of § 98.2 (a)(3) may submit 

an abbreviated GHG report for the 

facility for GHGs emitted in 2010. The 

abbreviated report must be submitted by 

March 31, 2011. An owner or operator 

that submits an abbreviated report must 

submit a full GHG report according to 

the requirements of paragraph (c) of this 

section beginning in calendar year 2011. 

The abbreviated facility report must 

include the following information: 

(i) Facility name and physical street 

address including the city, state and zip 

code. 

(ii) The year and months covered by 

the report. 

(iii) Date of submittal. 

(iv) Total facility GHG emissions 

aggregated for all stationary fuel 

combustion units calculated according 

to any method specified in § 98.33(a) 

and expressed in metric tons of CO2,

CH4, N2O, and CO2e. 

(v) Any facility operating data or 

process information used for the GHG 

emission calculations. 

(vi) A signed and dated certification 

statement provided by the designated 

representative of the owner or operator, 

according to the requirements of 

paragraph (e)(1) of this section. 

(e) Emission calculations. In 

preparing the GHG report, you must use 

the calculation methodologies specified 

in the relevant subparts, except as 

specified in paragraph (d) of this 

section. For each source category, you 

must use the same calculation 

methodology throughout a reporting 

period unless you provide a written 

explanation of why a change in 

methodology was required. 

(f) Verification. To verify the 

completeness and accuracy of reported 

GHG emissions, the Administrator may 

review the certification statements 

described in paragraphs (c)(8) and 

(d)(3)(vi) of this section and any other 

credible evidence, in conjunction with a 

comprehensive review of the GHG 

reports and periodic audits of selected 

reporting facilities. Nothing in this 

section prohibits the Administrator from 

using additional information to verify 

the completeness and accuracy of the 

reports. 

(g) Recordkeeping. An owner or 

operator that is required to report GHGs 

under this part must keep records as 

specified in this paragraph. Retain all 

required records for at least 3 years. The 

records shall be kept in an electronic or 

hard-copy format (as appropriate) and 

recorded in a form that is suitable for 

expeditious inspection and review. 

Upon request by the Administrator, the 

records required under this section must 

be made available to EPA. Records may 

be retained off site if the records are 

readily available for expeditious 

inspection and review. For records that 

are electronically generated or 

maintained, the equipment or software 

necessary to read the records shall be 

made available, or, if requested by EPA, 

electronic records shall be converted to 

paper documents. You must retain the 

following records, in addition to those 

records prescribed in each applicable 

subpart of this part: 

(1) A list of all units, operations, 

processes, and activities for which GHG 

emission were calculated. 

(2) The data used to calculate the 

GHG emissions for each unit, operation, 

process, and activity, categorized by fuel 

or material type. These data include but 

are not limited to the following 

information in this paragraph (g)(2): 

(i) The GHG emissions calculations 

and methods used. 

(ii) Analytical results for the 

development of site-specific emissions 

factors. 

(iii) The results of all required 

analyses for high heat value, carbon 

content, and other required fuel or 

feedstock parameters. 

(iv) Any facility operating data or 

process information used for the GHG 

emission calculations. 

(3) The annual GHG reports. 

(4) Missing data computations. For 

each missing data event, also retain a 

record of the duration of the event, 

actions taken to restore malfunctioning 

monitoring equipment, the cause of the 

event, and the actions taken to prevent 

or minimize occurrence in the future. 

(5) A written GHG Monitoring Plan. 

(i) At a minimum, the GHG 

Monitoring Plan shall include the 

elements listed in this paragraph 

(g)(5)(i). 


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(A) Identification of positions of 

responsibility (i.e., job titles) for 

collection of the emissions data. 

(B) Explanation of the processes and 

methods used to collect the necessary 

data for the GHG calculations. 

(C) Description of the procedures and 

methods that are used for quality 

assurance, maintenance, and repair of 

all continuous monitoring systems, flow 

meters, and other instrumentation used 

to provide data for the GHGs reported 

under this part. 

(ii) The GHG Monitoring Plan may 

rely on references to existing corporate 

documents (e.g., standard operating 

procedures, quality assurance programs 

under appendix F to 40 CFR part 60 or 

appendix B to 40 CFR part 75, and other 

documents) provided that the elements 

required by paragraph (g)(5)(i) of this 

section are easily recognizable. 

(iii) The owner or operator shall 

revise the GHG Monitoring Plan as 

needed to reflect changes in production 

processes, monitoring instrumentation, 

and quality assurance procedures; or to 

improve procedures for the maintenance 

and repair of monitoring systems to 

reduce the frequency of monitoring 

equipment downtime. 

(iv) Upon request by the 

Administrator, the owner or operator 

shall make all information that is 

collected in conformance with the GHG 

Monitoring Plan available for review 

during an audit. Electronic storage of 

the information in the plan is 

permissible, provided that the 

information can be made available in 

hard copy upon request during an audit. 

(6) The results of all required 

certification and quality assurance tests 

of continuous monitoring systems, fuel 

flow meters, and other instrumentation 

used to provide data for the GHGs 

reported under this part. 

(7) Maintenance records for all 

continuous monitoring systems, flow 

meters, and other instrumentation used 

to provide data for the GHGs reported 

under this part. 

(h) Annual GHG report revisions. The 

owner or operator shall submit a revised 

report within 45 days of discovering or 

being notified by EPA of errors in an 

annual GHG report. The revised report 

must correct all identified errors. The 

owner or operator shall retain 

documentation for 3 years to support 

any revisions made to an annual GHG 

report. 

(i) Calibration accuracy requirements. 

The owner or operator of a facility or 

supplier that is subject to the 

requirements of this part must meet the 

calibration accuracy requirements of 

this paragraph (i). 

(1) Except as provided paragraphs 

(i)(4) through (i)(6) of this section, flow 

meters and other devices (e.g., belt 

scales) that measure data used to 

calculate GHG emissions shall be 

calibrated prior to April 1, 2010 using 

the procedures specified in this 

paragraph and each relevant subpart of 

this part. All measurement devices must 

be calibrated according to the 

manufacturer’s recommended 

procedures, an appropriate industry 

consensus standard, or a method 

specified in a relevant subpart of this 

part. All measurement devices shall be 

calibrated to an accuracy of 5 percent. 

For facilities and suppliers that become 

subject to this part after April 1, 2010, 

the initial calibration shall be conducted 

on the date that data collection is 

required to begin. Subsequent 

calibrations shall be performed at the 

frequency specified in each applicable 

subpart. 

(2) For flow meters, perform all 

calibrations at measurement points that 

are representative of normal operation 

of the meter. Except for the orifice, 

nozzle, and venturi flow meters 

described in paragraph (i)(3) of this 

section, calculate the calibration error at 

each measurement point using Equation 

A–2 of this section. The terms ‘‘R’’ and 

‘‘A’’ in Equation A–2 must be expressed 

in consistent units of measure (e.g., 

gallons/minute, ft 3/min). The 

calibration error at each measurement 

point shall not exceed 5.0 percent of the 

reference value. 

CE R A

R = x 100 (Eq. A-2) −

Where: 

CE = Calibration error (%) 

R = Reference value 

A = Flow meter response to the reference 

value 

(3) For orifice, nozzle, and venturi 

flow meters, the initial quality 

assurance consists of in-situ calibration 

of the differential pressure (delta-P), 

total pressure, and temperature 

transmitters. Calibrate each transmitter 

at a zero point and at least one upscale 

point. Fixed reference points, such as 

the freezing point of water, may be used 

for temperature transmitter calibrations. 

Calculate the calibration error of each 

transmitter at each measurement point, 

using Equation A–3 of this subpart. The 

terms ‘‘R’’, ‘‘A’’, and ‘‘FS’’ in Equation 

A–3 of this subpart must be in 

consistent units of measure (e.g., 

milliamperes, inches of water, psi, 

degrees). For each transmitter, the CE 

value at each measurement point shall 

not exceed 2.0 percent of full-scale. 

Alternatively, the results are acceptable 

if the sum of the calculated CE values 

for the three transmitters at each 

calibration level (i.e., at the zero level 

and at each upscale level) does not 

exceed 5.0 percent. 

CE R A

FS = x 100 (Eq. A-3) −

Where: 

CE = Calibration error (%) 

R = Reference value 

A = Transmitter response to the reference 

value 

FS = Full-scale value of the transmitter 

(4) Fuel billing meters are exempted 

from the calibration requirements of this 

section, provided that the fuel supplier 

and any unit combusting the fuel do not 

have any common owners and are not 

owned by subsidiaries or affiliates of the 

same company. 

(5) For a flow meter or other 

measurement device that has been 

previously calibrated in accordance 

with this part, an initial calibration is 

not required by the date specified in 

paragraph (i)(1) of this section if, as of 

the date required for the initial 

calibration, the previous calibration is 

still active (i.e., the device is not yet due 

for recalibration because the time 

interval between successive 

calibrations, as required by this part, has 

not elapsed). 

(6) For units and processes that 

operate continuously with infrequent 

outages, it may not be possible to meet 

the April 1, 2010 deadline for the initial 

calibration of a flow meter or other 

measurement device without removing 

the device from service and shipping it 

to a remote location, thereby disrupting 

normal process operation. In such cases, 

the owner or operator may postpone the 

initial calibration until the next 

scheduled maintenance outage, and may 

similarly postpone the subsequent 

recalibrations. Such postponements 

shall be documented in the monitoring 

plan that is required under § 98.3(g)(5). 

§ 98.4 Authorization and responsibilities of 

the designated representative. 

(a) General. Except as provided under 

paragraph (f) of this section, each 

facility, and each supplier, that is 

subject to this part, shall have one and 

only one designated representative, who 

shall be responsible for certifying, 

signing, and submitting GHG emissions 

reports and any other submissions for 

such facility and supplier respectively 

to the Administrator under this part. If 

the facility is required under any other 

part of title 40 of the Code of Federal 

Regulations to submit to the 

Administrator any other emission report 

that is subject to any requirement in 40 


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CFR part 75, the same individual shall 

be the designated representative 

responsible for certifying, signing, and 

submitting the GHG emissions reports 

and all such other emissions reports 

under this part. 

(b) Authorization of a designated 

representative. The designated 

representative of the facility or supplier 

shall be an individual selected by an 

agreement binding on the owners and 

operators of such facility or supplier 

and shall act in accordance with the 

certification statement in paragraph 

(i)(4)(iv) of this section. 

(c) Responsibility of the designated 

representative. Upon receipt by the 

Administrator of a complete certificate 

of representation under this section for 

a facility or supplier, the designated 

representative identified in such 

certificate of representation shall 

represent and, by his or her 

representations, actions, inactions, or 

submissions, legally bind each owner 

and operator of such facility or supplier 

in all matters pertaining to this part, 

notwithstanding any agreement between 

the designated representative and such 

owners and operators. The owners and 

operators shall be bound by any 

decision or order issued to the 

designated representative by the 

Administrator or a court. 

(d) Timing. No GHG emissions report 

or other submissions under this part for 

a facility or supplier will be accepted 

until the Administrator has received a 

complete certificate of representation 

under this section for a designated 

representative of the facility or supplier. 

Such certificate of representation shall 

be submitted at least 60 days before the 

deadline for submission of the facility’s 

or supplier’s initial emission report 

under this part. 

(e) Certification of the GHG emissions 

report. Each GHG emission report and 

any other submission under this part for 

a facility or supplier shall be certified, 

signed, and submitted by the designated 

representative or any alternate 

designated representative of the facility 

or supplier in accordance with this 

section and § 3.10 of this chapter. 

(1) Each such submission shall 

include the following certification 

statement signed by the designated 

representative or any alternate 

designated representative: ‘‘I am 

authorized to make this submission on 

behalf of the owners and operators of 

the facility or supplier, as applicable, for 

which the submission is made. I certify 

under penalty of law that I have 

personally examined, and am familiar 

with, the statements and information 

submitted in this document and all its 

attachments. Based on my inquiry of 

those individuals with primary 

responsibility for obtaining the 

information, I certify that the statements 

and information are to the best of my 

knowledge and belief true, accurate, and 

complete. I am aware that there are 

significant penalties for submitting false 

statements and information or omitting 

required statements and information, 

including the possibility of fine or 

imprisonment.’’ 

(2) The Administrator will accept a 

GHG emission report or other 

submission for a facility or supplier 

under this part only if the submission is 

certified, signed, and submitted in 

accordance with this section. 

(f) Alternate designated 

representative. A certificate of 

representation under this section for a 

facility or supplier may designate one 

alternate designated representative, who 

shall be an individual selected by an 

agreement binding on the owners and 

operators, and may act on behalf of the 

designated representative, of such 

facility or supplier. The agreement by 

which the alternate designated 

representative is selected shall include 

a procedure for authorizing the alternate 

designated representative to act in lieu 

of the designated representative. 

(1) Upon receipt by the Administrator 

of a complete certificate of 

representation under this section for a 

facility or supplier identifying an 

alternate designated representative. 

(i) The alternate designated 

representative may act on behalf of the 

designated representative for such 

facility or supplier. 

(ii) Any representation, action, 

inaction, or submission by the alternate 

designated representative shall be 

deemed to be a representation, action, 

inaction, or submission by the 

designated representative. 

(2) Except in this section, whenever 

the term ‘‘designated representative’’ is 

used in this part, the term shall be 

construed to include the designated 

representative or any alternate 

designated representative. 

(g) Changing a designated 

representative or alternate designated 

representative. The designated 

representative or alternate designated 

representative identified in a complete 

certificate of representation under this 

section for a facility or supplier received 

by the Administrator may be changed at 

any time upon receipt by the 

Administrator of another later signed, 

complete certificate of representation 

under this section for the facility or 

supplier. Notwithstanding any such 

change, all representations, actions, 

inactions, and submissions by the 

previous designated representative or 

the previous alternate designated 

representative of the facility or supplier 

before the time and date when the 

Administrator receives such later signed 

certificate of representation shall be 

binding on the new designated 

representative and the owners and 

operators of the facility or supplier. 

(h) Changes in owners and operators. 

In the event an owner or operator of the 

facility or supplier is not included in 

the list of owners and operators in the 

certificate of representation under this 

section for the facility or supplier, such 

owner or operator shall be deemed to be 

subject to and bound by the certificate 

of representation, the representations, 

actions, inactions, and submissions of 

the designated representative and any 

alternate designated representative of 

the facility or supplier, as if the owner 

or operator were included in such list. 

Within 90 days after any change in the 

owners and operators of the facility or 

supplier (including the addition of a 

new owner or operator), the designated 

representative or any alternate 

designated representative shall submit a 

certificate of representation that is 

complete under this section except that 

such list shall be amended to reflect the 

change. If the designated representative 

or alternate designated representative 

determines at any time that an owner or 

operator of the facility or supplier is not 

included in such list and such exclusion 

is not the result of a change in the 

owners and operators, the designated 

representative or any alternate 

designated representative shall submit, 

within 90 days of making such 

determination, a certificate of 

representation that is complete under 

this section except that such list shall be 

amended to include such owner or 

operator. 

(i) Certificate of representation. A 

certificate of representation shall be 

complete if it includes the following 

elements in a format prescribed by the 

Administrator in accordance with this 

section: 

(1) Identification of the facility or 

supplier for which the certificate of 

representation is submitted. 

(2) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of the designated representative and any 

alternate designated representative. 

(3) A list of the owners and operators 

of the facility or supplier identified in 

paragraph (i)(1) of this section, provided 

that, if the list includes the operators of 

the facility or supplier and the owners 

with control of the facility or supplier, 

the failure to include any other owners 

shall not make the certificate of 

representation incomplete. 


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(4) The following certification 

statements by the designated 

representative and any alternate 

designated representative: 

(i) ‘‘I certify that I was selected as the 

designated representative or alternate 

designated representative, as applicable, 

by an agreement binding on the owners 

and operators of the facility or supplier, 

as applicable.’’ 

(ii) ‘‘I certify that I have all the 

necessary authority to carry out my 

duties and responsibilities under 40 

CFR part 98 on behalf of the owners and 

operators of the facility or supplier, as 

applicable, and that each such owner 

and operator shall be fully bound by my 

representations, actions, inactions, or 

submissions.’’ 

(iii) ‘‘I certify that the owners and 

operators of the facility or supplier, as 

applicable, shall be bound by any order 

issued to me by the Administrator or a 

court regarding the facility or supplier.’’ 

(iv) ‘‘If there are multiple owners and 

operators of the facility or supplier, as 

applicable, I certify that I have given a 

written notice of my selection as the 

‘designated representative’ or ‘alternate 

designated representative’, as 

applicable, and of the agreement by 

which I was selected to each owner and 

operator of the facility or supplier.’’ 

(5) The signature of the designated 

representative and any alternate 

designated representative and the dates 

signed. 

(j) Documents of agreement. Unless 

otherwise required by the 

Administrator, documents of agreement 

referred to in the certificate of 

representation shall not be submitted to 

the Administrator. The Administrator 

shall not be under any obligation to 

review or evaluate the sufficiency of 

such documents, if submitted. 

(k) Binding nature of the certificate of 

representation. Once a complete 

certificate of representation under this 

section for a facility or supplier has 

been received, the Administrator will 

rely on the certificate of representation 

unless and until a later signed, complete 

certificate of representation under this 

section for the facility or supplier is 

received by the Administrator. 

(l) Objections Concerning a Designated 

Representative 

(1) Except as provided in paragraph 

(g) of this section, no objection or other 

communication submitted to the 

Administrator concerning the 

authorization, or any representation, 

action, inaction, or submission, of the 

designated representative or alternate 

designated representative shall affect 

any representation, action, inaction, or 

submission of the designated 

representative or alternate designated 

representative, or the finality of any 

decision or order by the Administrator 

under this part. 

(2) The Administrator will not 

adjudicate any private legal dispute 

concerning the authorization or any 

representation, action, inaction, or 

submission of any designated 

representative or alternate designated 

representative. 

(m) Delegation by designated 

representative and alternate designated 

representative. 

(1) A designated representative or an 

alternate designated representative may 

delegate his or her own authority, to one 

or more individuals, to submit an 

electronic submission to the 

Administrator provided for or required 

under this part, except for a submission 

under this paragraph. 

(2) In order to delegate his or her own 

authority, to one or more individuals, to 

submit an electronic submission to the 

Administrator in accordance with 

paragraph (m)(1) of this section, the 

designated representative or alternate 

designated representative must submit 

electronically to the Administrator a 

notice of delegation, in a format 

prescribed by the Administrator, that 

includes the following elements: 

(i) The name, address, e-mail address 

(if any), telephone number, and 

facsimile transmission number (if any) 

of such designated representative or 

alternate designated representative. 

(ii) The name, address, e-mail 

address, telephone number, and 

facsimile transmission number (if any) 

of each such individual (referred to as 

an ‘‘agent’’). 

(iii) For each such individual, a list of 

the type or types of electronic 

submissions under paragraph (m)(1) of 

this section for which authority is 

delegated to him or her. 

(iv) For each type of electronic 

submission listed in accordance with 

paragraph (m)(2)(iii) of this section, the 

facility or supplier for which the 

electronic submission may be made. 

(v) The following certification 

statements by such designated 

representative or alternate designated 

representative: 

(A) ‘‘I agree that any electronic 

submission to the Administrator that is 

by an agent identified in this notice of 

delegation and of a type listed, and for 

a facility or supplier designated, for 

such agent in this notice of delegation 

and that is made when I am a 

designated representative or alternate 

designated representative, as applicable, 

and before this notice of delegation is 

superseded by another notice of 

delegation under § 98.4(m)(3) shall be 

deemed to be an electronic submission 

certified, signed, and submitted by me.’’ 

(B) ‘‘Until this notice of delegation is 

superseded by a later signed notice of 

delegation under § 98.4(m)(3), I agree to 

maintain an e-mail account and to 

notify the Administrator immediately of 

any change in my e-mail address unless 

all delegation of authority by me under 

§ 98.4(m) is terminated.’’ 

(vi) The signature of such designated 

representative or alternate designated 

representative and the date signed. 

(3) A notice of delegation submitted 

in accordance with paragraph (m)(2) of 

this section shall be effective, with 

regard to the designated representative 

or alternate designated representative 

identified in such notice, upon receipt 

of such notice by the Administrator and 

until receipt by the Administrator of 

another such notice that was signed 

later by such designated representative 

or alternate designated representative, 

as applicable. The later signed notice of 

delegation may replace any previously 

identified agent, add a new agent, or 

eliminate entirely any delegation of 

authority. 

(4) Any electronic submission covered 

by the certification in paragraph 

(m)(2)(iv)(A) of this section and made in 

accordance with a notice of delegation 

effective under paragraph (m)(3) of this 

section shall be deemed to be an 

electronic submission certified, signed, 

and submitted by the designated 

representative or alternate designated 

representative submitting such notice of 

delegation. 

§ 98.5 How is the report submitted? 

Each GHG report and certificate of 

representation for a facility or supplier 

must be submitted electronically in 

accordance with the requirements of 

§ 98.4 and in a format specified by the 

Administrator. 

§ 98.6 Definitions. 

All terms used in this part shall have 

the same meaning given in the Clean Air 

Act and in this section. 

Accuracy of a measurement at a 

specified level (e.g., one percent of full 

scale or one percent of the value 

measured) means that the mean of 

repeat measurements made by a device 

or technique are within 95 percent of 

the range bounded by the true value 

plus or minus the specified level. 

Acid Rain Program means the 

program established under title IV of the 

Clean Air Act, and implemented under 

parts 72 through 78 of this chapter for 

the reduction of sulfur dioxide and 

nitrogen oxides emissions. 

Administrator means the 

Administrator of the United States 


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Environmental Protection Agency or the 

Administrator’s authorized 

representative. 

AGA means the American Gas 

Association 

Alkali bypass means a duct between 

the feed end of the kiln and the 

preheater tower through which a 

portion of the kiln exit gas stream is 

withdrawn and quickly cooled by air or 

water to avoid excessive buildup of 

alkali, chloride and/or sulfur on the raw 

feed. This may also be referred to as the 

‘‘kiln exhaust gas bypass.’’ 

Anaerobic digester means the system 

where wastes are collected and 

anaerobically digested in large 

containment vessels or covered lagoons. 

Anaerobic digesters stabilize waste by 

the microbial reduction of complex 

organic compounds to CO2 and CH4, 

which is captured and may be flared or 

used as fuel. Anaerobic digestion 

systems, include but are not limited to 

covered lagoon, complete mix, plug 

flow, and fixed film digesters. 

Anaerobic lagoon means a type of 

liquid storage system component, either 

at manure management system or a 

wastewater treatment system, that is 

designed and operated to stabilize 

wastes using anaerobic microbial 

processes. Anaerobic lagoons may be 

designed for combined stabilization and 

storage with varying lengths of retention 

time (up to a year or greater), depending 

on the climate region, the volatile solids 

loading rate, and other operational 

factors. 

Anode effect is a process upset 

condition of an aluminum electrolysis 

cell caused by too little alumina 

dissolved in the electrolyte. The anode 

effect begins when the voltage rises 

rapidly and exceeds a threshold voltage, 

typically 8 volts. 

Anode Effect Minutes per Cell Day (24 

hours) are the total minutes during 

which an electrolysis cell voltage is 

above the threshold voltage, typically 8 

volts. 

ANSI means the American National 

Standards Institute. 

API means the American Petroleum 

Institute. 

Argon-oxygen decarburization (AOD) 

vessel means any closed-bottom, 

refractory-lined converter vessel with 

submerged tuyeres through which 

gaseous mixtures containing argon and 

oxygen or nitrogen may be blown into 

molten steel for further refining to 

reduce the carbon content of the steel. 

ASABE means the American Society 

of Agricultural and Biological 

Engineers. 

ASME means the American Society of 

Mechanical Engineers. 

ASTM means the American Society of 

Testing and Materials. 

Asphalt means a dark brown-to-black 

cement-like material obtained by 

petroleum processing and containing 

bitumens as the predominant 

component. It includes crude asphalt as 

well as the following finished products: 

cements, fluxes, the asphalt content of 

emulsions (exclusive of water), and 

petroleum distillates blended with 

asphalt to make cutback asphalts. 

Aviation Gasoline means a complex 

mixture of volatile hydrocarbons, with 

or without additives, suitably blended 

to be used in aviation reciprocating 

engines. Specifications can be found in 

ASTM Specification D910–07a, 

Standard Specification for Aviation 

Gasolines (incorporated by reference, 

see § 98.7). 

B0 means the maximum CH4

producing capacity of a waste stream, kg 

CH4/kg COD. 

Basic oxygen furnace means any 

refractory-lined vessel in which highpurity oxygen is blown under pressure 

through a bath of molten iron, scrap 

metal, and fluxes to produce steel. 

bbl means barrel. 

Biodiesel means a mono-akyl ester 

derived from biomass and conforming to 

ASTM D6751–08, Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels. 

Biogenic CO2 means carbon dioxide 

emissions generated as the result of 

biomass combustion from combustion 

units for which emission calculations 

are required by an applicable part 98 

subpart. 

Biomass means non-fossilized and 

biodegradable organic material 

originating from plants, animals or 

micro-organisms, including products, 

by-products, residues and waste from 

agriculture, forestry and related 

industries as well as the non-fossilized 

and biodegradable organic fractions of 

industrial and municipal wastes, 

including gases and liquids recovered 

from the decomposition of nonfossilized and biodegradable organic 

material. 

Blast furnace means a furnace that is 

located at an integrated iron and steel 

plant and is used for the production of 

molten iron from iron ore pellets and 

other iron bearing materials. 

Blendstocks are petroleum products 

used for blending or compounding into 

finished motor gasoline. These include 

RBOB (reformulated blendstock for 

oxygenate blending) and CBOB 

(conventional blendstock for oxygenate 

blending), but exclude oxygenates, 

butane, and pentanes plus. 

Blendstocks—Others are products 

used for blending or compounding into 

finished motor gasoline that are not 

defined elsewhere. Excludes Gasoline 

Treated as Blendstock (GTAB), Diesel 

Treated as Blendstock (DTAB), 

conventional blendstock for oxygenate 

blending (CBOB), reformulated 

blendstock for oxygenate blending 

(RBOB), oxygenates (e.g. fuel ethanol 

and methyl tertiary butyl ether), butane, 

and pentanes plus. 

Blowdown mean the act of emptying 

or depressuring a vessel. This may also 

refer to the discarded material such as 

blowdown water from a boiler or 

cooling tower. 

British Thermal Unit or Btu means the 

quantity of heat required to raise the 

temperature of one pound of water by 

one degree Fahrenheit at about 39.2 

degrees Fahrenheit. 

Bulk, with respect to industrial GHG 

suppliers and CO2 suppliers, means the 

transfer of a product inside containers, 

including but not limited to tanks, 

cylinders, drums, and pressure vessels. 

Bulk natural gas liquid or NGL refers 

to mixtures of hydrocarbons that have 

been separated from natural gas as 

liquids through the process of 

absorption, condensation, adsorption, or 

other methods at lease separators and 

field facilities. Generally, such liquids 

consist of ethane, propane, butanes, and 

pentanes plus. Bulk NGL is sold to 

fractionators or to refineries and 

petrochemical plants where the 

fractionation takes place. 

Butane, or n-Butane, is a paraffinic 

straight-chain hydrocarbon with 

molecular formula C4H10. 

Butylene, or n-Butylene, is an olefinic 

straight-chain hydrocarbon with 

molecular formula C4H8. 

By-product coke oven battery means a 

group of ovens connected by common 

walls, where coal undergoes destructive 

distillation under positive pressure to 

produce coke and coke oven gas from 

which by-products are recovered. 

Calcination means the process of 

thermally treating minerals to 

decompose carbonates from ore. 

Calculation methodology means a 

methodology prescribed under the 

section ‘‘Calculating GHG Emissions’’ in 

any subpart of part 98. 

Carbon dioxide equivalent or CO2e 

means the number of metric tons of CO2

emissions with the same global warming 

potential as one metric ton of another 

greenhouse gas, and is calculated using 

Equation A–1 of this subpart. 

Carbon dioxide production well 

means any hole drilled in the earth for 

the primary purpose of extracting 

carbon dioxide from a geologic 

formation or group of formations which 

contain deposits of carbon dioxide. 


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Carbon dioxide production well 

facility means one or more carbon 

dioxide production wells that are 

located on one or more contiguous or 

adjacent properties, which are under the 

control of the same entity. Carbon 

dioxide production wells located on 

different oil and gas leases, mineral fee 

tracts, lease tracts, subsurface or surface 

unit areas, surface fee tracts, surface 

lease tracts, or separate surface sites, 

whether or not connected by a road, 

waterway, power line, or pipeline, shall 

be considered part of the same CO2

production well facility if they 

otherwise meet the definition. 

Carbon dioxide stream means carbon 

dioxide that has been captured from an 

emission source (e.g. a power plant or 

other industrial facility) or extracted 

from a carbon dioxide production well 

plus incidental associated substances 

either derived from the source materials 

and the capture process or extracted 

with the carbon dioxide. 

Carbon share means the percent of 

total mass that carbon represents in any 

product. 

Carbonate means compounds 

containing the radical CO3

¥2. Upon 

calcination, the carbonate radical 

decomposes to evolve carbon dioxide 

(CO2). Common carbonates consumed in 

the mineral industry include calcium 

carbonate (CaCO3) or calcite; 

magnesium carbonate (MgCO3) or 

magnesite; and calcium-magnesium 

carbonate (CaMg(CO3)2) or dolomite. 

Carbonate-based mineral means any 

of the following minerals used in the 

manufacture of glass: Calcium carbonate 

(CaCO3), calcium magnesium carbonate 

(CaMg(CO3)2), and sodium carbonate 

(Na2CO3). 

Carbonate-based mineral mass 

fraction means the following: For 

limestone, the mass fraction of CaCO3 in 

the limestone; for dolomite, the mass 

fraction of CaMg(CO3)2 in the dolomite; 

and for soda ash, the mass fraction of 

Na2CO3 in the soda ash. 

Carbonate-based raw material means 

any of the following materials used in 

the manufacture of glass: Limestone, 

dolomite, and soda ash. 

Catalytic cracking unit means a 

refinery process unit in which 

petroleum derivatives are continuously 

charged and hydrocarbon molecules in 

the presence of a catalyst are fractured 

into smaller molecules, or react with a 

contact material suspended in a 

fluidized bed to improve feedstock 

quality for additional processing and the 

catalyst or contact material is 

continuously regenerated by burning off 

coke and other deposits. Catalytic 

cracking units include both fluidized 

bed systems, which are referred to as 

fluid catalytic cracking units (FCCU), 

and moving bed systems, which are also 

referred to as thermal catalytic cracking 

units. The unit includes the riser, 

reactor, regenerator, air blowers, spent 

catalyst or contact material stripper, 

catalyst or contact material recovery 

equipment, and regenerator equipment 

for controlling air pollutant emissions 

and for heat recovery. 

Deep bedding systems for cattle swine 

means a manure management system in 

which, as manure accumulates, bedding 

is continually added to absorb moisture 

over a production cycle and possibly for 

as long as 6 to 12 months. This manure 

management system also is known as a 

bedded pack manure management 

system and may be combined with a dry 

lot or pasture. 

CBOB-Summer (conventional 

blendstock for oxygenate blending) 

means a petroleum product which, 

when blended with a specified type and 

percentage of oxygenate, meets the 

definition of Conventional-Summer. 

CBOB-Winter (conventional 

blendstock for oxygenate blending) 

means a petroleum product which, 

when blended with a specified type and 

percentage of oxygenate, meets the 

definition of Conventional-Winter. 

Certified standards means calibration 

gases certified by the manufacturer of 

the calibration gases to be accurate to 

within 2 percent of the value on the 

label or calibration gases. 

CH4 means methane. 

Chemical recovery combustion unit 

means a combustion device, such as a 

recovery furnace or fluidized-bed 

reactor where spent pulping liquor from 

sulfite or semi-chemical pulping 

processes is burned to recover pulping 

chemicals. 

Chemical recovery furnace means an 

enclosed combustion device where 

concentrated spent liquor produced by 

the kraft or soda pulping process is 

burned to recover pulping chemicals 

and produce steam. Includes any 

recovery furnace that burns spent 

pulping liquor produced from both the 

kraft and soda pulping processes. 

Chloride process means a production 

process where titanium dioxide is 

produced using calcined petroleum 

coke and chlorine as raw materials. 

City gate means a location at which 

natural gas ownership or control passes 

from one party to another, neither of 

which is the ultimate consumer. In this 

rule, in keeping with common practice, 

the term refers to a point or measuring 

station at which a local gas distribution 

utility receives gas from a natural gas 

pipeline company or transmission 

system. Meters at the city gate station 

measure the flow of natural gas into the 

local distribution company system and 

typically are used to measure local 

distribution company system sendout to 

customers. 

CO2 means carbon dioxide. 

Coal means all solid fuels classified as 

anthracite, bituminous, sub-bituminous, 

or lignite by the American Society for 

Testing and Materials Designation 

ASTM D388–05 Standard Classification 

of Coals by Rank (incorporated by 

reference, see § 98.7). 

COD means the chemical oxygen 

demand as determined using methods 

specified pursuant to 40 CFR part 136. 

Coke burn-off means the coke 

removed from the surface of a catalyst 

by combustion during catalyst 

regeneration. Coke burn-off also means 

the coke combusted in fluid coking unit 

burner. 

Cokemaking means the production of 

coke from coal in either a by-product 

coke oven battery or a non-recovery 

coke oven battery. 

Commercial applications means 

executing a commercial transaction 

subject to a contract. A commercial 

application includes transferring 

custody of a product from one facility to 

another if it otherwise meets the 

definition. 

Company records means, in reference 

to the amount of fuel consumed by a 

stationary combustion unit (or by a 

group of such units), a complete record 

of the methods used, the measurements 

made, and the calculations performed to 

quantify fuel usage. Company records 

may include, but are not limited to, 

direct measurements of fuel 

consumption by gravimetric or 

volumetric means, tank drop 

measurements, and calculated values of 

fuel usage obtained by measuring 

auxiliary parameters such as steam 

generation or unit operating hours. Fuel 

billing records obtained from the fuel 

supplier qualify as company records. 

Connector means to flanged, screwed, 

or other joined fittings used to connect 

pipe line segments, tubing, pipe 

components (such as elbows, reducers, 

‘‘T’s’’ or valves) or a pipe line and a 

piece of equipment or an instrument to 

a pipe, tube or piece of equipment. A 

common connector is a flange. Joined 

fittings welded completely around the 

circumference of the interface are not 

considered connectors for the purpose 

of this part. 

Container glass means glass made of 

soda-lime recipe, clear or colored, 

which is pressed and/or blown into 

bottles, jars, ampoules, and other 

products listed in North American 

Industry Classification System 327213 

(NAICS 327213). 


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Continuous emission monitoring 

system or CEMS means the total 

equipment required to sample, analyze, 

measure, and provide, by means of 

readings recorded at least once every 15 

minutes, a permanent record of gas 

concentrations, pollutant emission rates, 

or gas volumetric flow rates from 

stationary sources. 

Continuous glass melting furnace 

means a glass melting furnace that 

operates continuously except during 

periods of maintenance, malfunction, 

control device installation, 

reconstruction, or rebuilding. 

Conventional-Summer refers to 

finished gasoline formulated for use in 

motor vehicles, the composition and 

properties of which do not meet the 

requirements of the reformulated 

gasoline regulations promulgated by the 

U.S. Environmental Protection Agency 

under 40 CFR 80.40, but which meet 

summer RVP standards required under 

40 CFR 80.27 or as specified by the 

state. Note: This category excludes 

conventional gasoline for oxygenate 

blending (CBOB) as well as other 

blendstock. 

Conventional-Winter refers to finished 

gasoline formulated for use in motor 

vehicles, the composition and 

properties of which do not meet the 

requirements of the reformulated 

gasoline regulations promulgated by the 

U.S. Environmental Protection Agency 

under 40 CFR 80.40 or the summer RVP 

standards required under 40 CFR 80.27 

or as specified by the state. Note: This 

category excludes conventional 

blendstock for oxygenate blending 

(CBOB) as well as other blendstock. 

Crude oil means a mixture of 

hydrocarbons that exists in the liquid 

phase in the underground reservoir and 

remains liquid at atmospheric pressure 

after passing through surface separating 

facilities. 

Daily spread means a manure 

management system component in 

which manure is routinely removed 

from a confinement facility and is 

applied to cropland or pasture within 24 

hours of excretion. 

Day means any consistently 

designated 24 hour period during which 

an emission unit is operated. 

Degradable organic carbon (DOC) 

means the fraction of the total mass of 

a waste material that can be biologically 

degraded. 

Delayed coking unit means one or 

more refinery process units in which 

high molecular weight petroleum 

derivatives are thermally cracked and 

petroleum coke is produced in a series 

of closed, batch system reactors. A 

delayed coking unit consists of the coke 

drums and ancillary equipment 

associated with a single fractionator. 

Density means the mass contained in 

a given unit volume (mass/volume). 

Destruction means: 

(1) With respect to landfills and 

manure management, the combustion of 

methane in any on-site or off-site 

combustion technology. Destroyed 

methane includes, but is not limited to, 

methane combusted by flaring, methane 

destroyed by thermal oxidation, 

methane combusted for use in on-site 

energy or heat production technologies, 

methane that is conveyed through 

pipelines (including natural gas 

pipelines) for off-site combustion, and 

methane that is collected for any other 

on-site or off-site use as a fuel. 

(2) With respect to fluorinated GHGs, 

the expiration of a fluorinated GHG to 

the destruction efficiency actually 

achieved. Such destruction does not 

result in a commercially useful end 

product. 

Destruction Efficiency means the 

efficiency with which a destruction 

device reduces the GWP-weighted mass 

of greenhouse gases fed into the device, 

considering the GWP-weighted masses 

of both the greenhouse gases fed into the 

device and those exhausted from the 

device. Destruction efficiency, or flaring 

destruction efficiency, refers to the 

fraction of the gas that leaves the flare 

partially or fully oxidized. The 

Destruction Efficiency is expressed in 

Equation A–2 of this section: 

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 

Diesel—Other is any distillate fuel oil 

not defined elsewhere, including Diesel 

Treated as Blendstock (DTAB). 

DIPE (diisopropyl ether, 

(CH3)2CHOCH(CH3)2) is an ether as 

described in ‘‘Oxygenates.’’ 

Direct liquefaction means the 

conversion of coal directly into liquids, 

rather than passing through an 

intermediate gaseous state. 

Direct reduction furnace means a high 

temperature furnace typically fired with 

natural gas to produce solid iron from 

iron ore or iron ore pellets and coke, 

coal, or other carbonaceous materials. 

Distillate Fuel Oil means a 

classification for one of the petroleum 

fractions produced in conventional 

distillation operations and from crackers 

and hydrotreating process units. The 

generic term distillate fuel oil includes 

kerosene, diesel fuels (Diesel Fuels No. 

1, No. 2, and No. 4), and fuel oils (Fuel 

Oils No. 1, No. 2, and No. 4). 

Distillate Fuel No. 1 has a maximum 

distillation temperature of 550 °F at the 

90 percent recovery point and a 

minimum flash point of 100 °F and 

includes fuels commonly known as 

Diesel Fuel No. 1 and Fuel Oil No. 1, 

but excludes kerosene. This fuel is 

further subdivided into categories of 

sulfur content: High Sulfur (greater than 

500 ppm), Low Sulfur (less than or 

equal to 500 ppm and greater than 15 

ppm), and Ultra Low Sulfur (less than 

or equal to 15 ppm). 

Distillate Fuel No. 2 has a minimum 

and maximum distillation temperature 

of 540 °F and 640 °F at the 90 percent 

recovery point, respectively, and 

includes fuels commonly known as 

Diesel Fuel No. 2 and Fuel Oil No. 2. 

This fuel is further subdivided into 

categories of sulfur content: High Sulfur 

(greater than 500 ppm), Low Sulfur (less 

than or equal to 500 ppm and greater 

than 15 ppm), and Ultra Low Sulfur 

(less than or equal to 15 ppm). 

Distillate Fuel No. 4 is a distillate fuel 

oil made by blending distillate fuel oil 

and residual fuel oil, with a minimum 

flash point of 131 °F. 

DOCf means the fraction of DOC that 

actually decomposes under the 

(presumably anaerobic) conditions 

within the landfill. 

Dry lot means a manure management 

system component consisting of a paved 

or unpaved open confinement area 

without any significant vegetative cover 

where accumulating manure may be 

removed periodically. 

Electric arc furnace (EAF) means a 

furnace that produces molten alloy 

metal and heats the charge materials 

with electric arcs from carbon 

electrodes. 

Electric arc furnace steelmaking 

means the production of carbon, alloy, 

or specialty steels using an EAF. This 

definition excludes EAFs at steel 

foundries and EAFs used to produce 

nonferrous metals. 

Electrothermic furnace means a 

furnace that heats the charged materials 

with electric arcs from carbon 

electrodes. 

Emergency generator means a 

stationary combustion device, such as a 

reciprocating internal combustion 

engine or turbine that serves solely as a 

secondary source of mechanical or 

electrical power whenever the primary 

energy supply is disrupted or 

discontinued during power outages or 

natural disasters that are beyond the 

control of the owner or operator of a 


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facility. An emergency generator 

operates only during emergency 

situations, for training of personnel 

under simulated emergency conditions, 

as part of emergency demand response 

procedures, or for standard performance 

testing procedures as required by law or 

by the generator manufacturer. A 

generator that serves as a back-up power 

source under conditions of load 

shedding, peak shaving, power 

interruptions pursuant to an 

interruptible power service agreement, 

or scheduled facility maintenance shall 

not be considered an emergency 

generator. 

Emergency equipment means any 

auxiliary fossil fuel-powered 

equipment, such as a fire pump, that is 

used only in emergency situations. 

ETBE (ethyl tertiary butyl ether, 

(CH3)3COC2H) is an ether as described 

in ‘‘Oxygenates.’’ 

Ethane is a paraffinic hydrocarbon 

with molecular formula C2H6. 

Ethanol is an anhydrous alcohol with 

molecular formula C2H5OH. 

Ethylene is an olefinic hydrocarbon 

with molecular formula C2H4. 

Ex refinery gate means the point at 

which a petroleum product leaves the 

refinery. 

Experimental furnace means a glass 

melting furnace with the sole purpose of 

operating to evaluate glass melting 

processes, technologies, or glass 

products. An experimental furnace does 

not produce glass that is sold (except for 

further research and development 

purposes) or that is used as a raw 

material for non-experimental furnaces. 

Export means to transport a product 

from inside the United States to persons 

outside the United States, excluding any 

such transport on behalf of the United 

States military including foreign 

military sales under the Arms Export 

Control Act. 

Exporter means any person, company 

or organization of record that transfers 

for sale or for other benefit, domestic 

products from the United States to 

another country or to an affiliate in 

another country, excluding any such 

transfers on behalf of the United States 

military or military purposes including 

foreign military sales under the Arms 

Export Control Act. An exporter is not 

the entity merely transporting the 

domestic products, rather an exporter is 

the entity deriving the principal benefit 

from the transaction. 

Facility means any physical property, 

plant, building, structure, source, or 

stationary equipment located on one or 

more contiguous or adjacent properties 

in actual physical contact or separated 

solely by a public roadway or other 

public right-of-way and under common 

ownership or common control, that 

emits or may emit any greenhouse gas. 

Operators of military installations may 

classify such installations as more than 

a single facility based on distinct and 

independent functional groupings 

within contiguous military properties. 

Feed means the prepared and mixed 

materials, which include but are not 

limited to materials such as limestone, 

clay, shale, sand, iron ore, mill scale, 

cement kiln dust and flyash, that are fed 

to the kiln. Feed does not include the 

fuels used in the kiln to produce heat to 

form the clinker product. 

Feedstock means raw material inputs 

to a process that are transformed by 

reaction, oxidation, or other chemical or 

physical methods into products and byproducts. Supplemental fuel burned to 

provide heat or thermal energy is not a 

feedstock. 

Fischer-Tropsch process means a 

catalyzed chemical reaction in which 

synthesis gas, a mixture of carbon 

monoxide and hydrogen, is converted 

into liquid hydrocarbons of various 

forms. 

Flare means a combustion device, 

whether at ground level or elevated, that 

uses an open flame to burn combustible 

gases with combustion air provided by 

uncontrolled ambient air around the 

flame. 

Flat glass means glass made of sodalime recipe and produced into 

continuous flat sheets and other 

products listed in NAICS 327211. 

Flowmeter means a device that 

measures the mass or volumetric rate of 

flow of a gas, liquid, or solid moving 

through an open or closed conduit (e.g. 

flowmeters include, but are not limited 

to, rotameters, turbine meters, coriolis 

meters, orifice meters, ultra-sonic 

flowmeters, and vortex flowmeters). 

Fluid coking unit means one or more 

refinery process units in which high 

molecular weight petroleum derivatives 

are thermally cracked and petroleum 

coke is continuously produced in a 

fluidized bed system. The fluid coking 

unit includes equipment for controlling 

air pollutant emissions and for heat 

recovery on the fluid coking burner 

exhaust vent. There are two basic types 

of fluid coking units: A traditional fluid 

coking unit in which only a small 

portion of the coke produced in the unit 

is burned to fuel the unit and the fluid 

coking burner exhaust vent is directed 

to the atmosphere (after processing in a 

CO boiler or other air pollutant control 

equipment) and a flexicoking unit in 

which an auxiliary burner is used to 

partially combust a significant portion 

of the produced petroleum coke to 

generate a low value fuel gas that is 

used as fuel in other combustion 

sources at the refinery. 

Fluorinated greenhouse gas means 

sulfur hexafluoride (SF6), nitrogen 

trifluoride (NF3), and any fluorocarbon 

except for controlled substances as 

defined at 40 CFR part 82, subpart A 

and substances with vapor pressures of 

less than 1 mm of Hg absolute at 25 

degrees C. With these exceptions, 

‘‘fluorinated GHG’’ includes but is not 

limited to any hydrofluorocarbon, any 

perfluorocarbon, any fully fluorinated 

linear, branched or cyclic alkane, ether, 

tertiary amine or aminoether, any 

perfluoropolyether, and any 

hydrofluoropolyether. 

Fossil fuel means natural gas, 

petroleum, coal, or any form of solid, 

liquid, or gaseous fuel derived from 

such material, including for example, 

consumer products that are derived 

from such materials and are combusted. 

Fossil fuel-fired means powered by 

combustion of fossil fuel, alone or in 

combination with any other fuel, 

regardless of the percentage of fossil fuel 

consumed. 

Fractionators means plants that 

produce fractionated natural gas liquids 

(NGLs) extracted from produced natural 

gas and separate the NGLs individual 

component products: ethane, propane, 

butanes and pentane-plus (C5+). Plants 

that only process natural gas but do not 

fractionate NGLs further into 

component products are not considered 

fractionators. Some fractionators do not 

process production gas, but instead 

fractionate bulk NGLs received from 

natural gas processors. Some 

fractionators both process natural gas 

and fractionate bulk NGLs received from 

other plants. 

Fuel means solid, liquid or gaseous 

combustible material. 

Fuel gas means gas generated at a 

petroleum refinery, petrochemical plant, 

or similar industrial process unit, and 

that is combusted separately or in any 

combination with any type of gas. 

Fuel gas system means a system of 

compressors, piping, knock-out pots, 

mix drums, and, if necessary, units used 

to remove sulfur contaminants from the 

fuel gas (e.g., amine scrubbers) that 

collects fuel gas from one or more 

sources for treatment, as necessary, and 

transport to a stationary combustion 

unit. A fuel gas system may have an 

overpressure vent to a flare but the 

primary purpose for a fuel gas system is 

to provide fuel to the various 

combustion units at the refinery or 

petrochemical plant. 

Gas collection system or landfill gas 

collection system means a system of 

pipes used to collect landfill gas from 

different locations in the landfill to a 


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single location for treatment (thermal 

destruction) or use. Landfill gas 

collection systems may also include 

knock-out or separator drums and/or a 

compressor. 

Gas-fired unit means a stationary 

combustion unit that derives more than 

50 percent of its annual heat input from 

the combustion of gaseous fuels, and the 

remainder of its annual heat input from 

the combustion of fuel oil or other 

liquid fuels. 

Gas monitor means an instrument that 

continuously measures the 

concentration of a particular gaseous 

species in the effluent of a stationary 

source. 

Gaseous fuel means a material that is 

in the gaseous state at standard 

atmospheric temperature and pressure 

conditions and that is combusted to 

produce heat and/or energy. 

Gasification means the conversion of 

a solid or liquid raw material into a gas. 

Gasoline—Other is any gasoline that 

is not defined elsewhere, including 

GTAB (gasoline treated as blendstock). 

Glass melting furnace means a unit 

comprising a refractory-lined vessel in 

which raw materials are charged and 

melted at high temperature to produce 

molten glass. 

Glass produced means the weight of 

glass exiting a glass melting furnace. 

Global warming potential or GWP 

means the ratio of the time-integrated 

radiative forcing from the instantaneous 

release of one kilogram of a trace 

substance relative to that of one 

kilogram- of a reference gas, i.e., CO2. 

GPA means the Gas Processors 

Association. 

Greenhouse gas or GHG means carbon 

dioxide (CO2), methane (CH4), nitrous 

oxide (N2O), sulfur hexafluoride (SF6), 

hydrofluorocarbons (HFCs), 

perfluorocarbons (PFCs), and other 

fluorinated greenhouse gases as defined 

in this section. 

GTBA (gasoline-grade tertiary butyl 

alcohol, (CH3)3COH), or t-butanol, is an 

alcohol as described in ‘‘Oxygenates.’’ 

Heavy Gas Oils are petroleum 

distillates with an approximate boiling 

range from 651 °F to 1,000 °F. 

Heel means the amount of gas that 

remains in a shipping container after it 

is discharged or off-loaded (that is no 

more than ten percent of the volume of 

the container). 

High heat value or HHV means the 

high or gross heat content of the fuel 

with the heat of vaporization included. 

The water is assumed to be in a liquid 

state. 

Hydrofluorocarbons or HFCs means a 

class of GHGs consisting of hydrogen, 

fluorine, and carbon. 

Import means, to land on, bring into, 

or introduce into, any place subject to 

the jurisdiction of the United States 

whether or not such landing, bringing, 

or introduction constitutes an 

importation within the meaning of the 

customs laws of the United States, with 

the following exemptions: 

(1) Off-loading used or excess 

fluorinated GHGs or nitrous oxide of 

U.S. origin from a ship during servicing. 

(2) Bringing fluorinated GHGs or 

nitrous oxide into the U.S. from Mexico 

where the fluorinated GHGs or nitrous 

oxide had been admitted into Mexico in 

bond and were of U.S. origin. 

(3) Bringing fluorinated GHGs or 

nitrous oxide into the U.S. when 

transported in a consignment of 

personal or household effects or in a 

similar non-commercial situation 

normally exempted from U.S. Customs 

attention. 

(4) Bringing fluorinated GHGs or 

nitrous into U.S. jurisdiction 

exclusively for U. S. military purposes. 

Importer means any person, company, 

or organization of record that for any 

reason brings a product into the United 

States from a foreign country, excluding 

introduction into U.S. jurisdiction 

exclusively for United States military 

purposes. An importer is the person, 

company, or organization primarily 

liable for the payment of any duties on 

the merchandise or an authorized agent 

acting on their behalf. The term 

includes, as appropriate: 

(1) The consignee. 

(2) The importer of record. 

(3) The actual owner. 

(4) The transferee, if the right to draw 

merchandise in a bonded warehouse has 

been transferred. 

Indurating furnace means a furnace 

where unfired taconite pellets, called 

green balls, are hardened at high 

temperatures to produce fired pellets for 

use in a blast furnace. Types of 

indurating furnaces include straight gate 

and grate kiln furnaces. 

Industrial greenhouse gases means 

nitrous oxide or any fluorinated 

greenhouse gas. 

In-line kiln/raw mill means a system 

in a portland cement production process 

where a dry kiln system is integrated 

with the raw mill so that all or a portion 

of the kiln exhaust gases are used to 

perform the drying operation of the raw 

mill, with no auxiliary heat source used. 

In this system the kiln is capable of 

operating without the raw mill 

operating, but the raw mill cannot 

operate without the kiln gases, and 

consequently, the raw mill does not 

generate a separate exhaust gas stream. 

Isobutane is a paraffinic branch chain 

hydrocarbon with molecular formula 

C4H10.

Isobutylene is an olefinic branch 

chain hydrocarbon with molecular 

formula C4H8.

Kerosene is a light petroleum 

distillate with a maximum distillation 

temperature of 400 °F at the 10-percent 

recovery point, a final maximum boiling 

point of 572 °F, a minimum flash point 

of 100 °F, and a maximum freezing 

point of ¥22 °F. Included are No. 1–K 

and No. 2–K, distinguished by 

maximum sulfur content (0.04 and 0.30 

percent of total mass, respectively), as 

well as all other grades of kerosene 

called range or stove oil. Excluded is 

kerosene-type jet fuel (see definition 

herein). 

Kerosene-type jet fuel means a 

kerosene-based product used in 

commercial and military turbojet and 

turboprop aircraft. The product has a 

maximum distillation temperature of 

400 °F at the 10 percent recovery point 

and a final maximum boiling point of 

572 °F. Included are Jet A, Jet A–1, 

JP–5, and JP–8. 

Kiln means an oven, furnace, or 

heated enclosure used for thermally 

processing a mineral or mineral-based 

substance. 

Landfill means an area of land or an 

excavation in which wastes are placed 

for permanent disposal and that is not 

a land application unit, surface 

impoundment, injection well, or waste 

pile as those terms are defined under 40 

CFR 257.2. 

Landfill gas means gas produced as a 

result of anaerobic decomposition of 

waste materials in the landfill. Landfill 

gas generally contains 40 to 60 percent 

methane on a dry basis, typically less 

than 1 percent non-methane organic 

chemicals, and the remainder being 

carbon dioxide. 

Lime is the generic term for a variety 

of chemical compounds that are 

produced by the calcination of 

limestone or dolomite. These products 

include but are not limited to calcium 

oxide, high-calcium quicklime, calcium 

hydroxide, hydrated lime, dolomitic 

quicklime, and dolomitic hydrate. 

Liquid/Slurry means a manure 

management component in which 

manure is stored as excreted or with 

some minimal addition of water to 

facilitate handling and is stored in 

either tanks or earthen ponds, usually 

for periods less than one year. 

Lubricants include all grades of 

lubricating oils, from spindle oil to 

cylinder oil to those used in greases. 

Petroleum lubricants may be produced 

from distillates or residues. 

Makeup chemicals means carbonate 

chemicals (e.g., sodium and calcium 

carbonates) that are added to the 

chemical recovery areas of chemical 


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pulp mills to replace chemicals lost in 

the process. 

Manure composting means the 

biological oxidation of a solid waste 

including manure usually with bedding 

or another organic carbon source 

typically at thermophilic temperatures 

produced by microbial heat production. 

There are four types of composting 

employed for manure management: 

Static, in vessel, intensive windrow and 

passive windrow. Static composting 

typically occurs in an enclosed channel, 

with forced aeration and continuous 

mixing. In vessel composting occurs in 

piles with forced aeration but no 

mixing. Intensive windrow composting 

occurs in windrows with regular turning 

for mixing and aeration. Passive 

windrow composting occurs in 

windrows with infrequent turning for 

mixing and aeration. 

Maximum rated heat input capacity 

means the hourly heat input to a unit (in 

mmBtu/hr), when it combusts the 

maximum amount of fuel per hour that 

it is capable of combusting on a steady 

state basis, as of the initial installation 

of the unit, as specified by the 

manufacturer. 

Maximum rated input capacity means 

the maximum charging rate of a 

municipal waste combustor unit 

expressed in tons per day of municipal 

solid waste combusted, calculated 

according to the procedures under 40 

CFR 60.58b(j). 

Mcf means thousand cubic feet. 

Methane conversion factor means the 

extent to which the CH4 producing 

capacity (Bo) is realized in each type of 

treatment and discharge pathway and 

system. Thus, it is an indication of the 

degree to which the system is anaerobic. 

Methane correction factor means an 

adjustment factor applied to the 

methane generation rate to account for 

portions of the landfill that remain 

aerobic. The methane correction factor 

can be considered the fraction of the 

total landfill waste volume that is 

ultimately disposed of in an anaerobic 

state. Managed landfills that have soil or 

other cover materials have a methane 

correction factor of 1. 

Methanol (CH3OH) is an alcohol as 

described in ‘‘Oxygenates.’’ 

Midgrade gasoline has an octane 

rating greater than or equal to 88 and 

less than or equal to 90. This definition 

applies to the midgrade categories of 

Conventional-Summer, ConventionalWinter, Reformulated-Summer, and 

Reformulated-Winter. For midgrade 

categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the 

expected octane rating of the finished 

gasoline after oxygenate has been added 

to the RBOB or CBOB. 

Miscellaneous products include all 

refined petroleum products not defined 

elsewhere. It includes, but is not limited 

to, naphtha-type jet fuel (Jet B and JP– 

4), petrolatum lube refining by-products 

(aromatic extracts and tars), absorption 

oils, ram-jet fuel, petroleum rocket fuels, 

synthetic natural gas feedstocks, waste 

feedstocks, and specialty oils. It 

excludes organic waste sludges, tank 

bottoms, spent catalysts, and sulfuric 

acid. 

MMBtu means million British thermal 

units. 

Motor gasoline (finished) means a 

complex mixture of volatile 

hydrocarbons, with or without 

additives, suitably blended to be used in 

spark ignition engines. Motor gasoline 

includes conventional gasoline, 

reformulated gasoline, and all types of 

oxygenated gasoline. Gasoline also has 

seasonal variations in an effort to 

control ozone levels. This is achieved by 

lowering the Reid Vapor Pressure (RVP) 

of gasoline during the summer driving 

season. Depending on the region of the 

country the RVP is lowered to below 9.0 

psi or 7.8 psi. The RVP may be further 

lowered by state regulations. 

Mscf means million standard cubic 

feet. 

MTBE (methyl tertiary butyl ether, 

(CH3)3COCH3) is an ether as described 

in ‘‘Oxygenates.’’ 

Municipal solid waste landfill or 

MSW landfill means an entire disposal 

facility in a contiguous geographical 

space where household waste is placed 

in or on land. An MSW landfill may 

also receive other types of RCRA 

Subtitle D wastes (40 CFR 257.2) such 

as commercial solid waste, 

nonhazardous sludge, conditionally 

exempt small quantity generator waste, 

and industrial solid waste. Portions of 

an MSW landfill may be separated by 

access roads, public roadways, or other 

public right-of-ways. An MSW landfill 

may be publicly or privately owned. 

Municipal solid waste or MSW means 

solid phase household, commercial/ 

retail, and/or institutional waste, such 

as, but not limited to, yard waste and 

refuse. 

N2O means nitrous oxide. 

Naphthas (< 401 °F) is a generic term 

applied to a petroleum fraction with an 

approximate boiling range between 122 

°F and 400 °F. The naphtha fraction of 

crude oil is the raw material for gasoline 

and is composed largely of paraffinic 

hydrocarbons. 

Natural gas means a naturally 

occurring mixture of hydrocarbon and 

non-hydrocarbon gases found in 

geologic formations beneath the earth’s 

surface, of which its constituents 

include, but are not limited to, methane, 

heavier hydrocarbons and carbon 

dioxide. Natural gas may be field quality 

(which varies widely) or pipeline 

quality. For the purposes of this subpart, 

the definition of natural gas includes 

similarly constituted fuels such as field 

production gas, process gas, and fuel 

gas. 

Natural gas liquids (NGLs) means 

those hydrocarbons in natural gas that 

are separated from the gas as liquids 

through the process of absorption, 

condensation, adsorption, or other 

methods at lease separators and field 

facilities. Generally, such liquids consist 

of ethane, propane, butanes, and 

pentanes plus. Bulk NGLs refers to 

mixtures of NGLs that are sold or 

delivered as undifferentiated product 

from natural gas processing plants. 

Natural gasoline means a mixture of 

liquid hydrocarbons (mostly pentanes 

and heavier hydrocarbons) extracted 

from natural gas. It includes isopentane. 

NIST means the United States 

National Institute of Standards and 

Technology. 

Nitric acid production line means a 

series of reactors and absorbers used to 

produce nitric acid. 

Nitrogen excreted is the nitrogen that 

is excreted by livestock in manure and 

urine. 

Non-crude feedstocks means any 

petroleum product or natural gas liquid 

that enters the refinery as a feedstock to 

be further refined or otherwise used on 

site. 

Non-recovery coke oven battery means 

a group of ovens connected by common 

walls and operated as a unit, where coal 

undergoes destructive distillation under 

negative pressure to produce coke, and 

which is designed for the combustion of 

the coke oven gas from which byproducts are not recovered. 

Oil-fired unit means a stationary 

combustion unit that derives more than 

50 percent of its annual heat input from 

the combustion of fuel oil, and the 

remainder of its annual heat input from 

the combustion of natural gas or other 

gaseous fuels. 

Open-ended valve or lines (OELs) 

means any valve, except pressure relief 

valves, having one side of the valve seat 

in contact with process fluid and one 

side open to atmosphere, either directly 

or through open piping. 

Operating hours means the duration 

of time in which a process or process 

unit is utilized; this excludes shutdown, 

maintenance, and standby. 

Operational change means, for 

purposes of § 98.3(b), a change in the 

type of feedstock or fuel used, a change 


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in operating hours, or a change in 

process production rate. 

Operator means any person who 

operates or supervises a facility or 

supplier. 

Other oils (> 401 °F) are oils with a 

boiling range equal to or greater than 

401 °F that are generally intended for 

use as a petrochemical feedstock and are 

not defined elsewhere. 

Owner means any person who has 

legal or equitable title to, has a 

leasehold interest in, or control of a 

facility or supplier, except a person 

whose legal or equitable title to or 

leasehold interest in the facility or 

supplier arises solely because the 

person is a limited partner in a 

partnership that has legal or equitable 

title to, has a leasehold interest in, or 

control of the facility or supplier shall 

not be considered an ‘‘owner’’ of the 

facility or supplier. 

Oxygenates means substances which, 

when added to gasoline, increase the 

oxygen content of the gasoline. Common 

oxygenates are ethanol, methyl tertiary 

butyl ether (MTBE), ethyl tertiary butyl 

ether (ETBE), tertiary amyl methyl ether 

(TAME), diisopropyl ether (DIPE), and 

methanol. 

Pasture/Range/Paddock means the 

manure from pasture and range grazing 

animals is allowed to lie as deposited, 

and is not managed. 

Pentanes plus, or C5+, is a mixture of 

hydrocarbons that is a liquid at ambient 

temperature and pressure, and consists 

mostly of pentanes (five carbon chain) 

and higher carbon number 

hydrocarbons. Pentanes plus includes, 

but is not limited to, normal pentane, 

isopentane, hexanes-plus (natural 

gasoline), and plant condensate. 

Perfluorocarbons or PFCs means a 

class of greenhouse gases consisting on 

the molecular level of carbon and 

fluorine. 

Petrochemical means methanol, 

acrylonitrile, ethylene, ethylene oxide, 

ethylene dichloride, and any form of 

carbon black. 

Petrochemical feedstocks means 

feedstocks derived from petroleum for 

the manufacture of chemicals, synthetic 

rubber, and a variety of plastics. This 

category is usually divided into 

naphthas less than 401 °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), has 

low ash content, and may be used as a 

feedstock in coke ovens. This product is 

also known as marketable coke or 

catalyst coke. 

Petroleum product means all refined 

and semi-refined products that are 

produced at a refinery by processing 

crude oil and other petroleum-based 

feedstocks, including petroleum 

products derived from co-processing 

biomass and petroleum feedstock 

together, but not including plastics or 

plastic products. Petroleum products 

may be combusted for energy use, or 

they may be used either for non-energy 

processes or as non-energy products. 

The definition of petroleum product for 

importers and exporters excludes 

waxes. 

Pit storage below animal confinement 

(deep pits) means the collection and 

storage of manure typically below a 

slatted floor in an enclosed animal 

confinement facility. This usually 

occurs with little or no added water for 

periods less than one year. 

Portable means designed and capable 

of being carried or moved from one 

location to another. Indications of 

portability include but are not limited to 

wheels, skids, carrying handles, dolly, 

trailer, or platform. Equipment is not 

portable if any one of the following 

conditions exists: 

(1) The equipment is attached to a 

foundation. 

(2) The equipment or a replacement 

resides at the same location for more 

than 12 consecutive months. 

(3) The equipment is located at a 

seasonal facility and operates during the 

full annual operating period of the 

seasonal facility, remains at the facility 

for at least two years, and operates at 

that facility for at least three months 

each year. 

(4) The equipment is moved from one 

location to another in an attempt to 

circumvent the portable residence time 

requirements of this definition. 

Poultry manure with litter means a 

manure management system component 

that is similar to cattle and swine deep 

bedding except usually not combined 

with a dry lot or pasture. The system is 

typically used for poultry breeder flocks 

and for the production of meat type 

chickens (broiler) and other fowl. 

Poultry manure without litter means a 

manure management system component 

that may manage manure in a liquid 

form, similar to open pits in enclosed 

animal confinement facilities. These 

systems may alternatively be designed 

and operated to dry manure as it 

accumulates. The latter is known as a 

high-rise manure management system 

and is a form of passive windrow 

manure composting when designed and 

operated properly. 

Precision of a measurement at a 

specified level (e.g., one percent of full 

scale or one percent of the value 

measured) means that 95 percent of 

repeat measurements made by a device 

or technique are within the range 

bounded by the mean of the 

measurements plus or minus the 

specified level. 

Premium grade gasoline is gasoline 

having an antiknock index, i.e., octane 

rating, greater than 90. This definition 

applies to the premium grade categories 

of Conventional-Summer, ConventionalWinter, Reformulated-Summer, and 

Reformulated-Winter. For premium 

grade categories of RBOB-Summer, 

RBOB-Winter, CBOB-Summer, and 

CBOB-Winter, this definition refers to 

the expected octane rating of the 

finished gasoline after oxygenate has 

been added to the RBOB or CBOB. 

Pressed and blown glass means glass 

which is pressed, blown, or both, into 

products such as light bulbs, glass fiber, 

technical glass, and other products 

listed in NAICS 327212. 

Pressure relief device or pressure 

relief valve or pressure safety valve 

means a safety device used to prevent 

operating pressures from exceeding the 

maximum allowable working pressure 

of the process equipment. A common 

pressure relief device is but not limited 

to a spring-loaded pressure relief valve. 

Devices that are actuated either by a 

pressure of less than or equal to 2.5 psig 

or by a vacuum are not pressure relief 

devices. 

Process emissions means the 

emissions from industrial processes 

(e.g., cement production, ammonia 

production) involving chemical or 

physical transformations other than fuel 

combustion. For example, the 

calcination of carbonates in a kiln 

during cement production or the 

oxidation of methane in an ammonia 

process results in the release of process 

CO2 emissions to the atmosphere. 

Emissions from fuel combustion to 

provide process heat are not part of 

process emissions, whether the 

combustion is internal or external to the 

process equipment. 

Process unit means the equipment 

assembled and connected by pipes and 

ducts to process raw materials and to 

manufacture either a final product or an 

intermediate used in the onsite 

production of other products. The 

process unit also includes the 

purification of recovered byproducts. 

Process vent means means a gas 

stream that: Is discharged through a 

conveyance to the atmosphere either 

directly or after passing through a 


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control device; originates from a unit 

operation, including but not limited to 

reactors (including reformers, crackers, 

and furnaces, and separation equipment 

for products and recovered byproducts); 

and contains or has the potential to 

contain GHG that is generated in the 

process. Process vent does not include 

safety device discharges, equipment 

leaks, gas streams routed to a fuel gas 

system or to a flare, discharges from 

storage tanks. 

Propane is a paraffinic hydrocarbon 

with molecular formula C3H8. 

Propylene is an olefinic hydrocarbon 

with molecular formula C3H6. 

Pulp mill lime kiln means the 

combustion units (e.g., rotary lime kiln 

or fluidized bed calciner) used at a kraft 

or soda pulp mill to calcine lime mud, 

which consists primarily of calcium 

carbonate, into quicklime, which is 

calcium oxide. 

Pushing means the process of 

removing the coke from the coke oven 

at the end of the coking cycle. Pushing 

begins when coke first begins to fall 

from the oven into the quench car and 

ends when the quench car enters the 

quench tower. 

Raw mill means a ball and tube mill, 

vertical roller mill or other size 

reduction equipment, that is not part of 

an in-line kiln/raw mill, used to grind 

feed to the appropriate size. Moisture 

may be added or removed from the feed 

during the grinding operation. If the raw 

mill is used to remove moisture from 

feed materials, it is also, by definition, 

a raw material dryer. The raw mill also 

includes the air separator associated 

with the raw mill. 

RBOB-Summer (reformulated 

blendstock for oxygenate blending) 

means a petroleum product which, 

when blended with a specified type and 

percentage of oxygenate, meets the 

definition of Reformulated-Summer. 

RBOB-Winter (reformulated 

blendstock for oxygenate blending) 

means a petroleum product which, 

when blended with a specified type and 

percentage of oxygenate, meets the 

definition of Reformulated-Winter. 

Reformulated-Summer refers to 

finished gasoline formulated for use in 

motor vehicles, the composition and 

properties of which meet the 

requirements of the reformulated 

gasoline regulations promulgated by the 

U.S. Environmental Protection Agency 

under 40 CFR 80.40 and 40 CFR 80.41, 

and summer RVP standards required 

under 40 CFR 80.27 or as specified by 

the state. Reformulated gasoline 

excludes Reformulated Blendstock for 

Oxygenate Blending (RBOB) as well as 

other blendstock. 

Reformulated-Winter refers to 

finished gasoline formulated for use in 

motor vehicles, the composition and 

properties of which meet the 

requirements of the reformulated 

gasoline regulations promulgated by the 

U.S. Environmental Protection Agency 

under 40 CFR 80.40 and 40 CFR 80.41, 

but which do not meet summer RVP 

standards required under 40 CFR 80.27 

or as specified by the state. Note: This 

category includes Oxygenated Fuels 

Program Reformulated Gasoline (OPRG). 

Reformulated gasoline excludes 

Reformulated Blendstock for Oxygenate 

Blending (RBOB) as well as other 

blendstock. 

Regular grade gasoline is gasoline 

having an antiknock index, i.e., octane 

rating, greater than or equal to 85 and 

less than 88. This definition applies to 

the regular grade categories of 

Conventional-Summer, ConventionalWinter, Reformulated-Summer, and 

Reformulated-Winter. For regular grade 

categories of RBOB-Summer, RBOBWinter, CBOB-Summer, and CBOBWinter, this definition refers to the 

expected octane rating of the finished 

gasoline after oxygenate has been added 

to the RBOB or CBOB. 

Rendered animal fat, or tallow, means 

fats extracted from animals which are 

generally used as a feedstock in making 

biodiesel. 

Research and development means 

those activities conducted in process 

units or at laboratory bench-scale 

settings whose purpose is to conduct 

research and development for new 

processes, technologies, or products and 

whose purpose is not for the 

manufacture of products for commercial 

sale, except in a de minimis manner. 

Residual Fuel Oil No. 5 (Navy 

Special) is a classification for the 

heavier fuel oil generally used in steam 

powered vessels in government service 

and inshore power plants. It has a 

minimum flash point of 131 °F. 

Residual Fuel Oil No. 6 (a.k.a. Bunker 

C) is a classification for the heavier fuel 

oil generally used for the production of 

electric power, space heating, vessel 

bunkering and various industrial 

purposes. It has a minimum flash point 

of 140 °F. 

Residuum is residue from crude oil 

after distilling off all but the heaviest 

components, with a boiling range 

greater than 1,000 °F. 

Road oil is any heavy petroleum oil, 

including residual asphaltic oil used as 

a dust palliative and surface treatment 

on roads and highways. It is generally 

produced in six grades, from 0, the most 

liquid, to 5, the most viscous. 

Rotary lime kiln means a unit with an 

inclined rotating drum that is used to 

produce a lime product from limestone 

by calcination. 

Safety device means a closure device 

such as a pressure relief valve, frangible 

disc, fusible plug, or any other type of 

device which functions exclusively to 

prevent physical damage or permanent 

deformation to a unit or its air emission 

control equipment by venting gases or 

vapors directly to the atmosphere 

during unsafe conditions resulting from 

an unplanned, accidental, or emergency 

event. A safety device is not used for 

routine venting of gases or vapors from 

the vapor headspace underneath a cover 

such as during filling of the unit or to 

adjust the pressure in response to 

normal daily diurnal ambient 

temperature fluctuations. A safety 

device is designed to remain in a closed 

position during normal operations and 

open only when the internal pressure, 

or another relevant parameter, exceeds 

the device threshold setting applicable 

to the air emission control equipment as 

determined by the owner or operator 

based on manufacturer 

recommendations, applicable 

regulations, fire protection and 

prevention codes and practices, or other 

requirements for the safe handling of 

flammable, combustible, explosive, 

reactive, or hazardous materials. 

Semi-refined petroleum product 

means all oils requiring further 

processing. Included in this category are 

unfinished oils which are produced by 

the partial refining of crude oil and 

include the following: Naphthas and 

lighter oils; kerosene and light gas oils; 

heavy gas oils; and residuum, and all 

products that require further processing 

or the addition of blendstocks. 

Sendout means, in the context of a 

local distribution company, the total 

deliveries of natural gas to customers 

over a specified time interval (typically 

hour, day, month, or year). Sendout is 

the sum of gas received through the city 

gate, gas withdrawn from on-system 

storage or peak shaving plants, and gas 

produced and delivered into the 

distribution system; and is net of any 

natural gas injected into on-system 

storage. It comprises gas sales, 

exchange, deliveries, gas used by 

company, and unaccounted for gas. 

Sendout is measured at the city gate 

station, and other on-system receipt 

points from storage, peak shaving, and 

production. 

Sensor means a device that measures 

a physical quantity/quality or the 

change in a physical quantity/quality, 

such as temperature, pressure, flow rate, 

pH, or liquid level. 

SF6 means sulfur hexafluoride. 


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Shutdown means the cessation of 

operation of an emission source for any 

purpose. 

Silicon carbide means an artificial 

abrasive produced from silica sand or 

quartz and petroleum coke. 

Sinter process means a process that 

produces a fused aggregate of fine 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 gas means any gas that contains 

significant concentrations of hydrogen 

sulfide. Sour gas may include untreated 

fuel gas, amine stripper off-gas, or sour 

water stripper gas. 

Special naphthas means all finished 

products with the naphtha boiling range 

(290 ° to 470 °F) that are generally used 

as paint thinners, cleaners or solvents. 

These products are refined to a specified 

flash point. Special naphthas include all 

commercial hexane and cleaning 

solvents conforming to ASTM 

Specification D1836–07, Standard 

Specification for Commercial Hexanes, 

and D235–02 (Reapproved 2007), 

Standard Specification for Mineral 

Spirits (Petroleum Spirits) (Hydrocarbon 

Dry Cleaning Solvent), respectively. 

Naphthas to be blended or marketed as 

motor gasoline or aviation gasoline, or 

that are to be used as petrochemical and 

synthetic natural gas (SNG) feedstocks 

are excluded. 

Spent liquor solids means the dry 

weight of the solids in the spent pulping 

liquor that enters the chemical recovery 

furnace or chemical recovery 

combustion unit. 

Spent pulping liquor means the 

residual liquid collected from on-site 

pulping operations at chemical pulp 

facilities that is subsequently fired in 

chemical recovery furnaces at kraft and 

soda pulp facilities or chemical recovery 

combustion units at sulfite or semichemical pulp facilities. 

Standard conditions or standard 

temperature and pressure (STP) means 

68 degrees Fahrenheit and 14.7 pounds 

per square inch absolute. 

Steam reforming means a catalytic 

process that involves a reaction between 

natural gas or other light hydrocarbons 

and steam. The result is a mixture of 

hydrogen, carbon monoxide, carbon 

dioxide, and water. 

Still gas means any form or mixture 

of gases produced in refineries by 

distillation, cracking, reforming, and 

other processes. The principal 

constituents are methane, ethane, 

ethylene, normal butane, butylene, 

propane, and propylene. 

Storage tank means a vessel 

(excluding sumps) that is designed to 

contain an accumulation of crude oil, 

condensate, intermediate hydrocarbon 

liquids, or produced water and that is 

constructed entirely of non-earthen 

materials (e.g., wood, concrete, steel, 

plastic) that provide structural support. 

Sulfur recovery plant means all 

process units which recover sulfur or 

produce sulfuric acid from hydrogen 

sulfide (H2S) and/or sulfur dioxide 

(SO2) from a common source of sour gas 

at a petroleum refinery. The sulfur 

recovery plant also includes sulfur pits 

used to store the recovered sulfur 

product, but it does not include 

secondary sulfur storage vessels or 

loading facilities downstream of the 

sulfur pits. For example, a Claus sulfur 

recovery plant includes: Reactor furnace 

and waste heat boiler, catalytic reactors, 

sulfur pits, and, if present, oxidation or 

reduction control systems, or 

incinerator, thermal oxidizer, or similar 

combustion device. Multiple sulfur 

recovery units are a single sulfur 

recovery plant only when the units 

share the same source of sour gas. Sulfur 

recovery units that receive source gas 

from completely segregated sour gas 

treatment systems are separate sulfur 

recovery plants. 

Supplemental fuel means a fuel 

burned within a petrochemical process 

that is not produced within the process 

itself. 

Supplier means a producer, importer, 

or exporter of a fossil fuel or an 

industrial greenhouse gas. 

Taconite iron ore processing means an 

industrial process that separates and 

concentrates iron ore from taconite, a 

low grade iron ore, and heats the 

taconite in an indurating furnace to 

produce taconite pellets that are used as 

the primary feed material for the 

production of iron in blast furnaces at 

integrated iron and steel plants. 

TAME means tertiary amyl methyl 

ether, (CH3)2(C2H5)COCH3). 

Trace concentrations means 

concentrations of less than 0.1 percent 

by mass of the process stream. 

Transform means to use and entirely 

consume (except for trace 

concentrations) nitrous oxide or 

fluorinated GHGs in the manufacturing 

of other chemicals for commercial 

purposes. Transformation does not 

include burning of nitrous oxide. 

Transshipment means the continuous 

shipment of nitrous oxide or a 

fluorinated GHG from a foreign state of 

origin through the United States or its 

territories to a second foreign state of 

final destination, as long as the 

shipment does not enter into United 

States jurisdiction. A transshipment, as 

it moves through the United States or its 

territories, cannot be re-packaged, sorted 

or otherwise changed in condition. 

Trona means the raw material 

(mineral) used to manufacture soda ash; 

hydrated sodium bicarbonate carbonate 

(e.g., Na2CO3.NaHCO3.2H2O). 

Ultimate analysis means the 

determination of the percentages of 

carbon, hydrogen, nitrogen, sulfur, and 

chlorine and (by difference) oxygen in 

the gaseous products and ash after the 

complete combustion of a sample of an 

organic material. 

Unfinished oils are all oils requiring 

further processing, except those 

requiring only mechanical blending. 

United States means the 50 states, the 

District of Columbia, and U.S. 

possessions and territories. 

Unstabilized crude oil means, for the 

purposes of this part, crude oil that is 

pumped from the well to a pipeline or 

pressurized storage vessel for transport 

to the refinery without intermediate 

storage in a storage tank at atmospheric 

pressures. Unstabilized crude oil is 

characterized by having a true vapor 

pressure of 5 pounds per square inch 

absolute (psia) or greater. 

Valve means any device for halting or 

regulating the flow of a liquid or gas 

through a passage, pipeline, inlet, 

outlet, or orifice; including, but not 

limited to, gate, globe, plug, ball, 

butterfly and needle valves. 

Vegetable oil means oils extracted 

from vegetation that are generally used 

as a feedstock in making biodiesel. 

Volatile solids are the organic material 

in livestock manure and consist of both 

biodegradable and non-biodegradable 

fractions. 

Waelz kiln means an inclined rotary 

kiln in which zinc-containing materials 

are charged together with a carbon 


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reducing agent (e.g., petroleum coke, 

metallurgical coke, or anthracite coal). 

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. This includes all 

marketable wax, whether crude or 

refined, with a congealing point 

between 80 (or 85) and 240 °F and a 

maximum oil content of 50 weight 

percent. 

Wool fiberglass means fibrous glass of 

random texture, including fiberglass 

insulation, and other products listed in 

NAICS 327993. 

You means an owner or operator 

subject to Part 98. 

Zinc smelters means a facility engaged 

in the production of zinc metal, zinc 

oxide, or zinc alloy products from zinc 

sulfide ore concentrates, zinc calcine, or 

zinc-bearing scrap and recycled 

materials through the use of 

pyrometallurgical techniques involving 

the reduction and volatization of 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 in the 

corresponding sections noted. These 

incorporations by reference were 

approved by the Director of Federal 

Register in accordance with 5 U.S.C. 

552(a) and 1 CFR part 51. These 

materials are incorporated as they exist 

on the date of approval, and a notice of 

any change in the materials will be 

published in the Federal Register. The 

materials are available for purchase at 

the corresponding address in this 

section. The materials are available for 

inspection at the EPA Docket Center, 

Public Reading Room, EPA West 

Building, Room 3334, 1301 Constitution 

Avenue, NW., Washington, DC, phone 

(202) 566–1744 and at the National 

Archives and Records Administration 

(NARA). For information on the 

availability of this material at NARA, 

call 202–741–6030, or go to: http:// 

www.archives.gov/federal_register/ 

code_of_federal_regulations/ 

ibr_locations.html. 

(a) The following material is available 

for purchase from the Association of 

Fertilizer and Phosphate Chemists 

(AFPC), P.O. Box 1645, Bartow, Florida 

33831, http://afpc.net. 

(1) Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

AFPC Manual 10th Edition 2009— 

Version 1.9, incorporation by reference 

(IBR) approved for § 98.264(a) and 

§ 98.264(b). 

(2) [Reserved] 

(b) The following material is available 

for purchase from the American Gas 

Association (AGA), 400 North Capitol 

Street, NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http:// 

www.aga.org. 

(1) AGA Report No. 3 Orifice Metering 

of Natural Gas and Other Related 

Hydrocarbon Fluids Part 1: General 

Equations & Uncertainty Guidelines 

(1990), incorporation by reference (IBR) 

approved for § 98.34(b) and § 98.244(b). 

(2) AGA Report No. 3 Orifice Metering 

of Natural Gas and Other Related 

Hydrocarbon Fluids Part 2: 

Specification and Installation 

Requirements (2000), IBR approved for 

§ 98.34(b) and § 98.244(b). 

(3) AGA Report No. 11 Measurement 

of Natural Gas by Coriolis Meter (2003), 

IBR approved for § 98.244(b) and 

§ 98.254(c). 

(4) AGA Transmission Measurement 

Committee Report No. 7 Measurement 

of Natural Gas by Turbine Meter (2006)/ 

February, IBR approved for § 98.34(b) 

and § 98.244(b). 

(c) The following material is available 

for purchase from the ASM 

International, 9639 Kinsman Road, 

Materials Park, OH 44073, (440) 338– 

5151, http://www.asminternational.org. 

(1) ASM CS–104 UNS No. G10460— 

Alloy Digest April 1985 (Carbon Steel of 

Medium Carbon Content), incorporation 

by reference (IBR) approved for 

§ 98.174(b). 

(2) [Reserved] 

(d) The following material is available 

for purchase from the American Society 

of Mechanical Engineers (ASME), Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http:// 

www.asme.org. 

(1) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi, 

incorporation by reference (IBR) 

approved for § 98.34(b), § 98.244(b), 

§ 98.254(c), § 98.344(c), and § 98.364(e). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters, IBR approved for 

§ 98.34(b), § 98.244(b), § 98.254(c), 

§ 98.344(c), and § 98.364(e). 

(3) ASME MFC–5M–1985 (Reaffirmed 

1994) Measurement of Liquid Flow in 

Closed Conduits Using Transit-Time 

Ultrasonic Flowmeters, IBR approved 

for § 98.34(b) and § 98.244(b). 

(4) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters, IBR approved 

for § 98.34(b), § 98.244(b), § 98.254(c), 

§ 98.344(c), and § 98.364(e). 

(5) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles, 

IBR approved for § 98.34(b), § 98.244(b), 

§ 98.254(c), § 98.344(c), and § 98.364(e). 

(6) ASME MFC–9M–1988 (Reaffirmed 

2001) Measurement of Liquid Flow in 

Closed Conduits by Weighing Method, 

IBR approved for § 98.34(b) and 

§ 98.244(b). 

(7) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters, IBR 

approved for § 98.244(b), § 98.254(c), 

and § 98.344(c). 

(8) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters, IBR 

approved for § 98.244(b), § 98.254(c), 

§ 98.344(c), and § 98.364(e). 

(9) ASME MFC–16–2007 

Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic 

Flowmeters, IBR approved for 

§ 98.244(b). 

(10) ASME MFC–18M–2001 

Measurement of Fluid Flow Using 

Variable Area Meters, IBR approved for 

§ 98.244(b), § 98.254(c),§ 98.344(c), and 

§ 98.364(e). 

(11) ASME MFC–22–2007 

Measurement of Liquid by Turbine 

Flowmeters, IBR approved for 

§ 98.244(b). 

(e) The following material is available 

for purchase from the American Society 

for Testing and Material (ASTM), 100 

Barr Harbor Drive, P.O. Box CB700, 

West Conshohocken, Pennsylvania 

19428–B2959, (800) 262–1373, http:// 

www.astm.org. 

(1) ASTM C25–06 Standard Test 

Method for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime, incorporation by reference (IBR) 

approved for § 98.114(b), § 98.174(b), 

§ 98.184(b), § 98.194(c), and § 98.334(b). 

(2) ASTM C114–09 Standard Test 

Methods for Chemical Analysis of 

Hydraulic Cement, IBR approved for 

§ 98.84(a), § 98.84(b), and § 98.84(c). 

(3) ASTM D235–02 (Reapproved 

2007) Standard Specification for 

Mineral Spirits (Petroleum Spirits) 

(Hydrocarbon Dry Cleaning Solvent), 

IBR approved for § 98.6. 

(4) ASTM D240–02 (Reapproved 

2007) Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter, IBR 

approved for § 98.34(a) and § 98.254(e). 

(5) ASTM D388–05 Standard 

Classification of Coals by Rank, IBR 

approved for § 98.6. 

(6) ASTM D910–07a Standard 

Specification for Aviation Gasolines, 

IBR approved for § 98.6. 

(7) ASTM D1298–99 (Reapproved 

2005) Standard Test Method for Density, 


sroberts on DSKD5P82C1PROD with RULES
56394 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

Relative Density (Specific Gravity), or 

API Gravity of Crude Petroleum and 

Liquid Petroleum Products by 

Hydrometer Method, IBR approved for 

§ 98.33(a). 

(8) ASTM D1826–94 (Reapproved 

2003) Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter, IBR approved 

for § 98.34(a) and § 98.254(e). 

(9) ASTM D1836–07 Standard 

Specification for Commercial Hexanes, 

IBR approved for § 98.6. 

(10) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography, IBR approved for 

§ 98.34(b), § 98.74(c), § 98.164(b), 

§ 98.244(b), § 98.254(d), and § 98.344(b). 

(11) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography, 

IBR approved for § 98.34(b), § 98.74(c), 

§ 98.164(b), § 98.254(d), § 98.344(b), and 

§ 98.364(c). 

(12) ASTM D2013–07 Standard 

Practice for Preparing Coal Samples for 

Analysis, IBR approved for § 98.164(b). 

(13) ASTM D2234/D2234M–07 

Standard Practice for Collection of a 

Gross Sample of Coal, IBR approved for 

§ 98.164(b). 

(14) ASTM D2502–04 Standard Test 

Method for Estimation of Mean Relative 

Molecular Mass of Petroleum Oils From 

Viscosity Measurements, IBR approved 

for § 98.34(b) and § 98.74(c). 

(15) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure, IBR 

approved for § 98.34(b) and § 98.74(c). 

(16) ASTM D2505–88 (Reapproved 

2004)e1 Standard Test Method for 

Ethylene, Other Hydrocarbons, and 

Carbon Dioxide in High-Purity Ethylene 

by Gas Chromatography, IBR approved 

for § 98.244(b). 

(17) ASTM D2597–94 (Reapproved 

2004) Standard Test Method for 

Analysis of Demethanized Hydrocarbon 

Liquid Mixtures Containing Nitrogen 

and Carbon Dioxide by Gas 

Chromatography, IBR approved for 

§ 98.164(b). 

(18) ASTM D3176–89 (Reapproved 

2002) Standard Practice for Ultimate 

Analysis of Coal and Coke, IBR 

approved for § 98.74(c), § 98.164(b), 

§ 98.244(b), § 98.254(i), § 98.284(c), 

§ 98.284(d), § 98.314(c), § 98.314(d), and 

§ 98.314(f). 

(19) ASTM D3238–95 (Reapproved 

2005) Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method, IBR 

approved for § 98.34(b), § 98.74(c), and 

§ 98.164(b). 

(20) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels, IBR 

approved for § 98.34(a) and § 98.254(e). 

(21) ASTM D3682–01 (Reapproved 

2006) Standard Test Method for Major 

and Minor Elements in Combustion 

Residues from Coal Utilization 

Processes, IBR approved for § 98.144(b). 

(22) ASTM D4057–06 Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products, IBR 

approved for § 98.164(b). 

(23) ASTM D4177–95 (Reapproved 

2005) Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products, IBR approved for § 98.164(b). 

(24) ASTM D4809–06 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method), IBR 

approved for § 98.34(a) and § 98.254(e). 

(25) ASTM D4891–89 (Reapproved 

2006), Standard Test Method for 

Heating Value of Gases in Natural Gas 

Range by Stoichiometric Combustion, 

IBR approved for § 98.34(a) and 

§ 98.254(e). 

(26) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants, IBR approved 

for § 98.34(b), § 98.74(c), § 98.164(b), 

§ 98.244(b), § 98.254(i). 

(27) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal, IBR 

approved for § 98.34(b), § 98.74(c), 

§ 98.114(b), § 98.164(b), § 98.174(b), 

§ 98.184(b), § 98.244(b), § 98.254(i), 

§ 98.274(b), § 98.284(c), § 98.284(d), 

§ 98.314(c), § 98.314(d), § 98.314(f), and 

§ 98.334(b). 

(28) ASTM D5865–07a Standard Test 

Method for Gross Calorific Value of Coal 

and Coke, IBR approved for § 98.34(a). 

(29) ASTM D6060–96 (Reapproved 

2001) Standard Practice for Sampling of 

Process Vents With a Portable Gas 

Chromatograph, IBR approved for 

§ 98.244(b). 

(30) ASTM D6348–03 Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy, IBR approved for 

§ 98.54(b) and § 98.224(b). 

(31) ASTM D6609–08 Standard Guide 

for Part-Stream Sampling of Coal, IBR 

approved for § 98.164(b). 

(32) ASTM D6751–08 Standard 

Specification for Biodiesel Fuel Blend 

Stock (B100) for Middle Distillate Fuels, 

IBR approved for § 98.6. 

(33) ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis, 

IBR approved for § 98.33(e), § 98.34(d), 

§ 98.34(e), and § 98.36(e). 

(34) ASTM D6883–04 Standard 

Practice for Manual Sampling of 

Stationary Coal from Railroad Cars, 

Barges, Trucks, or Stockpiles, IBR 

approved for § 98.164(b). 

(35) ASTM D7430–08ae1 Standard 

Practice for Mechanical Sampling of 

Coal, IBR approved for § 98.164(b). 

(36) ASTM D7459–08 Standard 

Practice for Collection of Integrated 

Samples for the Speciation of Biomass 

(Biogenic) and Fossil-Derived Carbon 

Dioxide Emitted from Stationary 

Emissions Sources, IBR approved for 

§ 98.33(e), § 98.34(d), § 98.34(e), and 

§ 98.36(e). 

(37) ASTM E359–00 (Reapproved 

2005)e1 Standard Test Methods for 

Analysis of Soda Ash (Sodium 

Carbonate), IBR approved for § 98.294(a) 

and § 98.294(b). 

(38) ASTM E1019–08 Standard Test 

Methods for Determination of Carbon, 

Sulfur, Nitrogen, and Oxygen in Steel, 

Iron, Nickel, and Cobalt Alloys by 

Various Combustion and Fusion 

Techniques, IBR approved for 

§ 98.174(b). 

(39) ASTM E1747–95 (Reapproved 

2005) Standard Guide for Purity of 

Carbon Dioxide Used in Supercritical 

Fluid Applications, IBR approved for 

98.424(b). 

(40) ASTM E1915–07a Standard Test 

Methods for Analysis of Metal Bearing 

Ores and Related Materials by 

Combustion Infrared-Absorption 

Spectrometry, IBR approved for 

§ 98.174(b). 

(41) ASTM E1941–04 Standard Test 

Method for Determination of Carbon in 

Refractory and Reactive Metals and 

Their Alloys, IBR approved for 

§ 98.114(b), § 98.184(b), § 98.334(b). 

(42) ASTM UOP539–97 Refinery Gas 

Analysis by Gas Chromatography, IBR 

approved for § 98.164(b), § 98.244(b), 

and § 98.254(d), and § 98.344(b). 

(f) The following material is available 

for purchase from the Gas Processors 

Association (GPA), 6526 East 60th 

Street, Tulsa, Oklahoma 74143, (918) 

493–3872, http:// 

www.gasprocessors.com. 

(1) GPA 2172–09 Calculation of Gross 

Heating Value, Relative Density, 

Compressibility and Theoretical 

Hydrocarbon Liquid Content for Natural 

Gas Mixtures for Custody Transfer, IBR 

approved for § 98.34(a). 

(2) GPA 2261–00 Analysis for Natural 

Gas and Similar Gaseous Mixtures by 

Gas Chromatography, IBR approved for 


sroberts on DSKD5P82C1PROD with RULES
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56395 

§ 98.34(a), § 98.164(b), § 98.254(d), and 

§ 98.344(b). 

(g) The following material is available 

for purchase from the International 

Standards Organization (ISO), 1, ch. de 

la Voie-Creuse, Case postale 56, CH– 

1211 Geneva 20, Switzerland, +41 22 

749 01 11, http://www.iso.org/iso/ 

home.htm. 

(1) ISO 3170: Petroleum liquids— 

Manual sampling—Third Edition 2004– 

02–01, IBR approved for § 98.164(b). 

(2) ISO 3171: Petroleum Liquids— 

Automatic pipeline sampling—Second 

Edition 1988–12–01, IBR approved for 

§ 98.164(b). 

(3) ISO 8316: Measurement of Liquid 

Flow in Closed Conduits— Method by 

Collection of the Liquid in a Volumetric 

Tank (1987–10–01)—First Edition, IBR 

approved for § 98.244(b). 

(4) ISO/TR 15349–1: 1998, Unalloyed 

steel—Determination of low carbon 

content. Part 1: Infrared absorption 

method after combustion in an electric 

resistance furnace (by peak separation) 

(1998–10–15)—First Edition, IBR 

approved for § 98.174(b). 

(5) ISO/TR 15349–3: 1998, Unalloyed 

steel—Determination of low carbon 

content. Part 3: Infrared absorption 

method after combustion in an electric 

resistance furnace (with preheating) 

(1998–10–15)—First Edition, IBR 

approved for § 98.174(b). 

(h) The following material is available 

for purchase from the National Lime 

Association (NLA), 200 North Glebe 

Road, Suite 800, Arlington, Virginia 

22203, (703) 243–5463, http:// 

www.lime.org. 

(1) CO2 Emissions Calculation 

Protocol for the Lime Industry—English 

Units Version, February 5, 2008 

Revision—National Lime Association, 

incorporation by reference (IBR) 

approved for § 98.194(c) and § 98.194(e). 

(2) [Reserved] 

(i) The following material is available 

for purchase from the National Institute 

of Standards and Technology (NIST), 

100 Bureau Drive, Stop 1070, 

Gaithersburg, MD 20899–1070, (800) 

877–8339, http://www.nist.gov/ 

index.html. 

(1) Specifications, Tolerances, and 

Other Technical Requirements For 

Weighing and Measuring Devices, NIST 

Handbook 44 (2009), incorporation by 

reference (IBR) approved for § 98.244(b), 

§ 98.254(h), and § 98.344(a). 

(2) [Reserved] 

(j) The following material is available 

for purchase from the Technical 

Association of the Pulp and Paper 

Industry (TAPPI), 15 Technology 

Parkway South, Norcross, GA 30092, 

(800) 332–8686, http://www.tappi.org. 

(1) T650 om-05 Solids Content of 

Black Liquor, TAPPI, incorporation by 

reference (IBR) approved for § 98.276(c) 

and § 98.277(d). 

(2) T684 om-06 Gross Heating Value 

of Black Liquor, TAPPI, incorporation 

by reference (IBR) approved for 

§ 98.274(b). 

§ 98.8 What are the compliance and 

enforcement provisions of this part? 

Any violation of any requirement of 

this part shall be a violation of the Clean 

Air Act, including section 114 (42 

U.S.C. 7414). A violation includes but is 

not limited to failure to report GHG 

emissions, failure to collect data needed 

to calculate GHG emissions, failure to 

continuously monitor and test as 

required, failure to retain records 

needed to verify the amount of GHG 

emissions, and failure to calculate GHG 

emissions following the methodologies 

specified in this part. Each day of a 

violation constitutes a separate 

violation. 

§ 98.9 Addresses. 

All requests, notifications, and 

communications to the Administrator 

pursuant to this part, other than 

submittal of the annual GHG report, 

shall be submitted to the following 

address: 

(a) For U.S. mail. Director, Climate 

Change Division, 1200 Pennsylvania 

Ave., NW., Mail Code: 6207J, 

Washington, DC 20460. 

(b) For package deliveries. Director, 

Climate Change Division, 1310 L St, 

NW., Washington, DC 20005. 

TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS

[100-Year Time Horizon] 

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 

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 


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TABLE A–1 TO SUBPART A OF PART 98—GLOBAL WARMING POTENTIALS—Continued 

[100-Year Time Horizon] 

Name CAS No. Chemical formula 

Global warming 

potential 

(100 yr.) 

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) ........................ E1730133 CHF2OCF2OC2F4OCHF2 .......................................... 1,870 

HFE–125 ................................................................... 3822–68–2 CHF2OCF3 ................................................................ 14,900 

HFE–134 ................................................................... 1691–17–4 CHF2OCHF2 ............................................................. 6,320 

HFE–143a ................................................................. 421–14–7 CH3OCF3 .................................................................. 756 

HFE–227ea ............................................................... 2356–62–9 CF3CHFOCF3 ........................................................... 1,540 

HFE–236ca12 (HG–10) ............................................ 78522–47–1 CHF2OCF2OCHF2 .................................................... 2,800 

HFE–236ea2 (Desflurane) ........................................ 57041–67–5 CHF2OCHFCF3 ......................................................... 989 

HFE–236fa ................................................................ 20193–67–3 CF3CH2OCF3 ............................................................ 487 

HFE–245cb2 ............................................................. 22410–44–2 CH3OCF2CF3 ............................................................ 708 

HFE–245fa1 .............................................................. 84011–15–4 CHF2CH2OCF3 ......................................................... 286 

HFE–245fa2 .............................................................. 1885–48–9 CHF2OCH2CF3 ......................................................... 659 

HFE–254cb2 ............................................................. 425–88–7 CH3OCF2CHF2 ......................................................... 359 

HFE–263fb2 .............................................................. 460–43–5 CF3CH2OCH3 ............................................................ 11 

HFE–329mcc2 .......................................................... 67490–36–2 CF3CF2OCF2CHF2 .................................................... 919 

HFE–338mcf2 ........................................................... 156053–88–2 CF3CF2OCH2CF3 ...................................................... 552 

HFE–338pcc13 (HG–01) .......................................... 188690–78–0 CHF2OCF2CF2OCHF2 .............................................. 1,500 

HFE–347mcc3 .......................................................... 28523–86–6 CH3OCF2CF2CF3 ...................................................... 575 

HFE–347mcf2 ........................................................... E1730135 CF3CF2OCH2CHF2 ................................................... 374 

HFE–347pcf2 ............................................................ 406–78–0 CHF2CF2OCH2CF3 ................................................... 580 

HFE–356mec3 .......................................................... 382–34–3 CH3OCF2CHFCF3 ..................................................... 101 

HFE–356pcc3 ........................................................... 160620–20–2 CH3OCF2CF2CHF2 ................................................... 110 

HFE–356pcf2 ............................................................ E1730137 CHF2CH2OCF2CHF2 ................................................. 265 

HFE–356pcf3 ............................................................ 35042–99–0 CHF2OCH2CF2CHF2 ................................................. 502 

HFE–365mcf3 ........................................................... 378–16–5 CF3CF2CH2OCH3 ..................................................... 11 

HFE–374pc2 ............................................................. 512–51–6 CH3CH2OCF2CHF2 ................................................... 557 

HFE–449sl (HFE–7100) ...........................................

Chemical blend .........................................................

163702–07–6 

163702–08–7 

C4F9OCH3 .................................................................

(CF3)2CFCF2OCH3 ...................................................

297 

HFE–569sf2 (HFE–7200) .........................................

Chemical blend .........................................................

163702–05–4 

163702–06–5 

C4F9OC2H5 ...............................................................

(CF3)2CFCF2OC2H5 ..................................................

59 

Sevoflurane ............................................................... 28523–86–6 CH2FOCH(CF3)2 ....................................................... 345 

HFE–356mm1 ........................................................... 13171–18–1 (CF3)2CHOCH3 ......................................................... 27 

HFE–338mmz1 ......................................................... 26103–08–2 CHF2OCH(CF3)2 ....................................................... 380 

(Octafluorotetramethy-lene)hydroxymethyl group .... NA X-(CF2)4CH(OH)-X .................................................... 73 

HFE–347mmy1 ......................................................... 22052–84–2 CH3OCF(CF3)2 .......................................................... 343 

Bis(trifluoromethyl)-methanol .................................... 920–66–1 (CF3)2CHOH ............................................................. 195 

2,2,3,3,3-pentafluoropropanol ................................... 422–05–9 CF3CF2CH2OH ......................................................... 42 

PFPMIE .................................................................... NA CF3OCF(CF3)CF2OCF2OCF3 ................................... 10,300 

NA = not available. 

TABLE A–2 TO SUBPART A OF PART 98—UNITS OF MEASURE CONVERSIONS

To convert from To Multiply by 

Kilograms (kg) ....................................................................... Pounds (lbs) ......................................................................... 2.20462 

Pounds (lbs) .......................................................................... Kilograms (kg) ...................................................................... 0.45359 

Pounds (lbs) .......................................................................... Metric tons ........................................................................... 4.53592 × 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 

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 


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TABLE A–2 TO SUBPART A OF PART 98—UNITS OF MEASURE CONVERSIONS—Continued 

To convert from To Multiply by 

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, 

simple and combined-cycle combustion 

turbines, engines, incinerators, and 

process heaters. 

(b) This source category does not 

include: 

(1) Portable equipment, as defined in 

§ 98.6. 

(2) Emergency generators and 

emergency equipment, as defined in 

§ 98.6. 

(3) Irrigation pumps at agricultural 

operations. 

(4) Flares, unless otherwise required 

by provisions of another subpart of 40 

CFR part 98 to use methodologies in this 

subpart. 

(5) Electricity generating units that are 

subject to subpart D of this part. 

(c) For a unit that combusts hazardous 

waste (as defined in 40 CFR 261.3), 

reporting of GHG emissions is not 

required unless either of the following 

conditions apply: 

(1) Continuous emission monitors 

(CEMS) are used to quantify CO2 mass 

emissions. 

(2) Any fuel listed in Table C–1 of this 

subpart is also combusted in the unit. In 

this case, report GHG emissions from 

combustion of all fuels listed in Table 

C–1 of this subpart. 

§ 98.31 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 

contains one or more stationary fuel 

combustion sources and the facility 

meets the applicability requirements of 

either §§ 98.2(a)(1), 98.2(a)(2), or 

98.2(a)(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. 

You must calculate CO2 emissions 

according to paragraph (a) of this 

section, and calculate CH4 and N2O 

emissions according to paragraph (c) of 

this section. 

(a) CO2 emissions from fuel 

combustion. Calculate CO2 emissions by 

using one of the four calculation 

methodologies in this paragraph (a) 

subject to the conditions, requirements, 

and restrictions set forth in paragraph 

(b) of this section. If you co-fire biomass 

fuels with fossil fuels, report CO2

emissions from the combustion of 

biomass separately using the methods in 

paragraph (e) of this section. 

(1) Tier 1 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions for each type of fuel by using 

Equation C–1 of this section. 

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 as defined 

in § 98.6 (express mass in short tons for 

solid fuel, volume in standard cubic feet 

for gaseous fuel, and volume in gallons 

for liquid fuel). 

HHV = Default high heat value of the fuel, 

from Table C–1 of this subpart (mmBtu 

per mass or mmBtu per volume, as 

applicable). 

EF = Fuel-specific default CO2 emission 

factor, from Table C–1 of this subpart (kg 

CO2/mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(2) Tier 2 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions for each type of fuel by using 

either Equation C2a or C2c of this 

section, as appropriate. 

(i) Equation C–2a of this section 

applies to any type of fuel listed in 

Table C–1 of the subpart, except for 

municipal solid waste (MSW). For MSW 

combustion, use Equation C–2c of this 

section. 


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CO x Fuel HHV EF 2

3 = ∗∗ ∗ 1 10− (Eq. C-2a)

Where: 

CO2 = Annual CO2 mass emissions for a 

specific fuel type (metric tons). 

Fuel = Mass or volume of the fuel combusted 

during the year, from company records 

as defined in § 98.6 (express mass in 

short tons for solid fuel, volume in 

standard cubic feet for gaseous fuel, and 

volume in gallons for liquid fuel). 

HHV = Annual average high heat value of the 

fuel from all valid samples for the year 

(mmBtu per mass or volume). The 

average HHV shall be calculated 

according to the requirements of 

paragraph (a)(2)(ii) of this section. 

EF = Fuel-specific default CO2 emission 

factor, from Table C–1 of this subpart (kg 

CO2/mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(ii) The minimum number of HHV 

samples for determining annual average 

HHV is specified (e.g., monthly, 

quarterly, semi-annually, or by lot) in 

§ 98.34. The method for computing the 

annual average HHV is a function of 

how frequently you perform or receive 

from the fuel supplier the results of fuel 

sampling for HHV. The method is 

specified in paragraph (a)(2)(ii)(A) or 

(a)(2)(ii)(B) of this section, as applicable. 

(A) If the results of fuel sampling are 

received monthly or more frequently, 

then the annual average HHV shall be 

calculated using Equation C–2b of this 

section. If multiple HHV determinations 

are made in any month, average the 

values for the month arithmetically. 

HHV

HHV Fuel

Fuel

annual

i i

i

n

i

i

n ( ) =

∗

=

=

∑

∑

( )( )

( )

1

1

(Eq. C-2b)

Where: 

(HHV)annual = Weighted annual average high 

heat value of the fuel (mmBtu per mass 

or volume). 

(HHV)i = High heat value of the fuel, for 

month ‘‘i’’ (mmBtu per mass or volume). 

(Fuel)i = Mass or volume of the fuel 

combusted during month ‘‘i’’ (express 

mass in short tons for solid fuel, volume 

in standard cubic feet for gaseous fuel, 

and volume in gallons for liquid fuel). 

n = Number of months in the year that fuel 

is burned in the unit. 

(B) If the results of fuel sampling are 

received less frequently than monthly, 

then the annual average HHV shall be 

computed as the arithmetic average 

HHV for all values for the year 

(including valid samples and substitute 

data values under § 98.35). 

(iii) For units that combust municipal 

solid waste (MSW) and that produce 

steam, use Equation C–2c of this 

section. Equation C–2c of this section 

may also be used for any other solid fuel 

listed in Table C–1 of this subpart 

provided that steam is generated by the 

unit. 

CO x Steam B EF (Eq. C-2c) 2

3 = ∗∗ 1 10−

Where: 

CO2 = Annual CO2 mass emissions from 

MSW or solid fuel combustion (metric 

tons). 

Steam = Total mass of steam generated by 

MSW or solid fuel combustion during 

the reporting year (lb steam). 

B = Ratio of the boiler’s maximum rated heat 

input capacity to its design rated steam 

output capacity (mmBtu/lb steam). 

EF = Fuel-specific default CO2 emission 

factor, from Table C–1 of this subpart (kg 

CO2/mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(3) Tier 3 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions for each fuel by using either 

Equation C3, C4, or C5 of this section, 

as appropriate. 

(i) For a solid fuel, use Equation C– 

3 of this section. 

CO Fuel CC 0.91 (Eq. C-3) 2

44

12 =∗ ∗ ∗

Where: 

CO2 = Annual CO2 mass emissions from the 

combustion of the specific solid fuel 

(metric tons). 

Fuel = Annual mass of the solid fuel 

combusted, from company records as 

defined in § 98.6 (short tons). 

CC = Annual average carbon content of the 

solid fuel (percent by weight, expressed 

as a decimal fraction, e.g., 95% = 0.95). 

The annual average carbon content shall 

be determined using the same 

procedures as specified for HHV in 

paragraph (a)(2)(ii) of this section. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.91 = Conversion factor from short tons to 

metric tons. 

(ii) For a liquid fuel, use Equation C– 

4 of this section. 

CO Fuel CC 0.001 (Eq. C-4) 2

44

12 =∗ ∗ ∗


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Where: 

CO2 = Annual CO2 mass emissions from the 

combustion of the specific liquid fuel 

(metric tons). 

Fuel = Annual volume of the liquid fuel 

combusted (gallons). The volume of fuel 

combusted must be measured directly, 

using fuel flow meters calibrated 

according to § 98.3(i). Fuel billing meters 

may be used for this purpose. Tank drop 

measurements may also be used. 

CC = Annual average carbon content of the 

liquid fuel (kg C per gallon of fuel). The 

annual average carbon content shall be 

determined using the same procedures as 

specified for HHV in paragraph (a)(2)(ii) 

of this section. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

(iii) For a gaseous fuel, use Equation 

C–5 of this section. 

CO2

44

12 =∗ ∗ ∗ ∗ Fuel CC 0 001 MW

MVC . (Eq. C-5)

Where: 

CO2 = Annual CO2 mass emissions from 

combustion of the specific gaseous fuel 

(metric tons). 

Fuel = Annual volume of the gaseous fuel 

combusted (scf). The volume of fuel 

combusted must be measured directly, 

using fuel flow meters calibrated 

according to § 98.3(i). Fuel billing meters 

may be used for this purpose. 

CC = Annual average carbon content of the 

liquid fuel (kg C per gallon of fuel). The 

annual average carbon content shall be 

determined using the same procedures as 

specified for HHV in paragraph (a)(2)(ii) 

of this section. 

MW = Annual average molecular weight of 

the gaseous fuel (kg/kg-mole). The 

annual average carbon content shall be 

determined using the same procedures as 

specified for HHV in paragraph (a)(2)(ii) 

of this section. 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions, as defined in § 98.6). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

(iv) Fuel flow meters that measure 

mass flow rates may be used for liquid 

fuels, provided that the fuel density is 

used to convert the readings to 

volumetric flow rates. The density shall 

be measured at the same frequency as 

the carbon content, using ASTM D1298– 

99 (Reapproved 2005) ‘‘Standard Test 

Method for Density, Relative Density 

(Specific Gravity), or API Gravity of 

Crude Petroleum and Liquid Petroleum 

Products by Hydrometer Method’’ 

(incorporated by reference, see § 98.7). 

(v) The following default density 

values may be used for fuel oil, in lieu 

of using the ASTM method in paragraph 

(a)(3)(iv) of this section: 6.8 lb/gal for 

No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/ 

gal for No. 6 oil. 

(4) Tier 4 Calculation Methodology. 

Calculate the annual CO2 mass 

emissions from all fuels combusted in a 

unit, by using quality-assured data from 

continuous emission monitoring 

systems (CEMS). 

(i) This methodology requires a CO2

concentration monitor and a stack gas 

volumetric flow rate monitor, except as 

otherwise provided in paragraph 

(a)(4)(iv) of this section. Hourly 

measurements of CO2 concentration and 

stack gas flow rate are converted to CO2

mass emission rates in metric tons per 

hour. 

(ii) When the CO2 concentration is 

measured on a wet basis, Equation C–6 

of this section is used to calculate the 

hourly CO2 emission rates: 

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 × 10¥7 = Conversion factor (metric tons/ 

scf/% CO2). 

(iii) If the CO2 concentration is 

measured on a dry basis, a correction for 

the stack gas moisture content is 

required. You shall either continuously 

monitor the stack gas moisture content 

as described in § 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 

(metric tons/hr). 

%H2O = Hourly moisture percentage in the 

stack gas (measured or default value, as 

appropriate). 

(iv) An oxygen (O2) concentration 

monitor may be used in lieu of a CO2

concentration monitor to determine the 

hourly CO2 concentrations, in 

accordance with Equation F–14a or F– 

14b (as applicable) in appendix F to 40 

CFR part 75, if the effluent gas stream 

monitored by the CEMS consists solely 

of combustion products (i.e., no process 

CO2 emissions are mixed with the 

combustion products) and if only fuels 

that are listed in Table 1 in section 3.3.5 

of appendix F to 40 CFR part 75 are 

combusted in the unit. If the O2

monitoring option is selected, the Ffactors used in Equations F–14a and F– 

14b shall be determined according to 

section 3.3.5 or section 3.3.6 of 

appendix F to 40 CFR part 75, as 

applicable. If Equation F–14b is used, 

the hourly moisture percentage in the 

stack gas shall be either a measured 

value in accordance with § 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 each calendar 

quarter and the quarterly totals are 

summed to determine the annual CO2

mass emissions. 

(vii) If both biomass and fossil fuel are 

combusted during the year, determine 

and report the biogenic CO2 mass 

emissions separately, as described in 

paragraph (e) of this section. 

(5) Alternative methods for units with 

continuous monitoring systems. Units 

not subject to the Acid Rain Program 

that report data to EPA according to 40 

CFR part 75 may use the alternative 

methods in this paragraph in lieu of 

using any of the four calculation 

methodology tiers. 

(i) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to the Acid Rain Program, monitors and 

reports heat input data year-round 

according to appendix D to 40 CFR part 


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75, but is not required by the applicable 

40 CFR part 75 program to report CO2

mass emissions data, calculate the 

annual CO2 mass emissions for the 

purposes of this part as follows: 

(A) Use the hourly heat input data 

from appendix D to 40 CFR part 75, 

together with Equation G–4 in appendix 

G to 40 CFR part 75 to determine the 

hourly CO2 mass emission rates, in units 

of tons/hr; 

(B) Use Equations F–12 and F–13 in 

appendix F to 40 CFR part 75 to 

calculate the quarterly and cumulative 

annual CO2 mass emissions, 

respectively, in units of short tons; and 

(C) Divide the cumulative annual CO2

mass emissions value by 1.1 to convert 

it to metric tons. 

(ii) For a unit that combusts only 

natural gas and/or fuel oil, is not subject 

to the Acid Rain Program, monitors and 

reports heat input data year-round 

according to 40 CFR 75.19 of this 

chapter but is not required by the 

applicable 40 CFR part 75 program to 

report CO2 mass emissions data, 

calculate the annual CO2 mass 

emissions for the purposes of this part 

as follows: 

(A) Calculate the hourly CO2 mass 

emissions, in units of short tons, using 

Equation LM–11 in 40 CFR 

75.19(c)(4)(iii). 

(B) Sum the hourly CO2 mass 

emissions values over the entire 

reporting year to obtain the cumulative 

annual CO2 mass emissions, in units of 

short tons. 

(C) Divide the cumulative annual CO2

mass emissions value by 1.1 to convert 

it to metric tons. 

(iii) For a unit that is not subject to 

the Acid Rain Program, uses flow rate 

and CO2 (or O2) CEMS to report heat 

input data year-round according to 40 

CFR part 75, but is not required by the 

applicable 40 CFR part 75 program to 

report CO2 mass emissions data, 

calculate the annual CO2 mass 

emissions as follows: 

(A) Use Equation F–11 or F–2 (as 

applicable) in appendix F to 40 CFR 

part 75 to calculate the hourly CO2 mass 

emission rates from the CEMS data. If an 

O2 monitor is used, convert the hourly 

average O2 readings to CO2 using 

Equation F–14a or F–14b in appendix F 

to 40 CFR part 75 (as applicable), before 

applying Equation F–11 or F–2. 

(B) Use Equations F–12 and F–13 in 

appendix F to 40 CFR part 75 to 

calculate the quarterly and cumulative 

annual CO2 mass emissions, 

respectively, in units of short tons. 

(C) Divide the cumulative annual CO2

mass emissions value by 1.1 to convert 

it to metric tons. 

(D) If both biomass and fossil fuel are 

combusted during the year, determine 

and report the biogenic CO2 mass 

emissions separately, as described in 

paragraph (e) of this section. 

(b) Use of the four tiers. Use of the 

four tiers of CO2 emissions calculation 

methodologies described in paragraph 

(a) of this section is subject to the 

following conditions, requirements, and 

restrictions: 

(1) The Tier 1 Calculation 

Methodology: 

(i) May be used for any fuel listed in 

Table C–1 of this subpart that is 

combusted in a unit with a maximum 

rated heat input capacity of 250 mmBtu/ 

hr or less. 

(ii) May be used for MSW in a unit of 

any size that does not produce steam, if 

the use of Tier 4 is not required. 

(iii) May be used for solid, gaseous, or 

liquid biomass fuels in a unit of any size 

provided that the fuel is listed in Table 

C–1 of this subpart. 

(iv) May not be used if you routinely 

perform fuel sampling and analysis for 

the fuel high heat value (HHV) or 

routinely receive the results of HHV 

sampling and analysis from the fuel 

supplier at the minimum frequency 

specified in § 98.34(a), or at a greater 

frequency. In such cases, Tier 2 shall be 

used. 

(2) The Tier 2 Calculation 

Methodology: 

(i) May be used for the combustion of 

any type of fuel in a unit with a 

maximum rated heat input capacity of 

250 mmBtu/hr or less provided that the 

fuel is listed in Table C–1 of this 

subpart. 

(ii) May be used in a unit with a 

maximum rated heat input capacity 

greater than 250 mmBtu/hr for the 

combustion of pipeline quality natural 

gas and distillate fuel oil. 

(iii) May be used for MSW in a unit 

of any size that produces steam, if the 

use of Tier 4 is not required. 

(3) The Tier 3 Calculation 

Methodology: 

(i) May be used for a unit of any size 

that combusts any type of fuel listed in 

Table C–1 of this subpart (except for 

MSW), unless the use of Tier 4 is 

required. 

(ii) Shall be used for a unit with a 

maximum rated heat input capacity 

greater than 250 mmBtu/hr that 

combusts any type of fuel listed in Table 

C–1 of this subpart (except MSW), 

unless either of the following conditions 

apply: 

(A) The use of Tier 1 or 2 is permitted, 

as described in paragraphs (b)(1)(iii) and 

(b)(2)(ii) of this section. 

(B) The use of Tier 4 is required. 

(iii) Shall be used for a fuel not listed 

in Table C–1 of this subpart if the fuel 

is combusted in a unit with a maximum 

rated heat input capacity greater than 

250 mmBtu/hr provided that both of the 

following conditions apply: 

(A) The use of Tier 4 is not required. 

(B) The fuel provides 10% or more of 

the annual heat input to the unit or, if 

§ 98.36(c)(3) applies, to a group of units 

served by common supply pipe. 

(4) The Tier 4 Calculation 

Methodology: 

(i) May be used for a unit of any size, 

combusting any type of fuel. 

(ii) Shall be used if the unit meets all 

six of the conditions specified in 

paragraphs (b)(4)(ii)(A) through 

(b)(4)(ii)(F) of this section: 

(A) The unit has a maximum rated 

heat input capacity greater than 250 

mmBtu/hr, or if the unit combusts 

municipal solid waste and has a 

maximum rated input capacity greater 

than 250 tons per day of MSW. 

(B) The unit combusts solid fossil fuel 

or MSW, either as a primary or 

secondary fuel. 

(C) The unit has operated for more 

than 1,000 hours in any calendar year 

since 2005. 

(D) The unit has installed CEMS that 

are required either by an applicable 

Federal or State regulation or the unit’s 

operating permit. 

(E) The installed CEMS include a gas 

monitor of any kind or a stack gas 

volumetric flow rate monitor, or both 

and the monitors have been certified, 

either in accordance with the 

requirements of 40 CFR part 75, part 60 

of this chapter, or an applicable State 

continuous monitoring program. 

(F) The installed gas or stack gas 

volumetric flow rate monitors are 

required, either by an applicable Federal 

or State regulation or by the unit’s 

operating permit, to undergo periodic 

quality assurance testing in accordance 

with either appendix B to 40 CFR part 

75, appendix F to 40 CFR part 60, or an 

applicable State continuous monitoring 

program. 

(iii) Shall be used for a unit with a 

maximum rated heat input capacity of 

250 mmBtu/hr or less and for a unit that 

combusts municipal solid waste with a 

maximum rated input capacity of 250 

tons of MSW per day or less, if the unit 

meets all of the following three 

conditions: 

(A) The unit has both a stack gas 

volumetric flow rate monitor and a CO2

concentration monitor. 

(B) The unit meets the conditions 

specified in paragraphs (b)(4)(ii)(B) 

through (b)(4)(ii)(D) of this section. 

(C) The CO2 and stack gas volumetric 

flow rate monitors meet the conditions 

specified in paragraphs (b)(4)(ii)(E) and 

(b)(4)(ii)(F) of this section. 


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(5) The Tier 4 Calculation 

Methodology shall be used beginning 

on: 

(i) January 1, 2010, for a unit that is 

required to report CO2 mass emissions 

beginning on that date, if all of the 

monitors needed to measure CO2 mass 

emissions have been installed and 

certified by that date. 

(ii) January 1, 2011, for a unit that is 

required to report CO2 mass emissions 

beginning on January 1, 2010, if all of 

the monitors needed to measure CO2

mass emissions have not been installed 

and certified by January 1, 2010. In this 

case, you may use Tier 2 or Tier 3 to 

report GHG emissions for 2010. 

(6) You may elect to use any 

applicable higher tier for one or more of 

the fuels combusted in a unit. For 

example, if a 100 mmBtu/hr unit 

combusts natural gas and distillate fuel 

oil, you may elect to use Tier 1 for 

natural gas and Tier 3 for the fuel oil, 

even though Tier 1 could have been 

used for both fuels. However, for units 

that use either the Tier 4 or the 

alternative calculation methodology 

specified in paragraph (a)(5) of this 

section, CO2 emissions from the 

combustion of all fuels shall be based 

solely on CEMS measurements. 

(c) Calculation of CH4 and N2O 

emissions from stationary combustion 

sources. You must calculate annual CH4

and N2O mass emissions only for units 

that are required to report CO2

emissions using the calculation 

methodologies of this subpart and for 

only those fuels that are listed in Table 

C–2 of this subpart. 

(1) Use Equation C–8 of this section 

to estimate CH4 and N2O emissions for 

any fuels for which you use the Tier 1 

or Tier 3 calculation methodologies for 

CO2. Use the same values for fuel 

combustion that you use for the Tier 1 

or Tier 3 calculation. 

CH or N O x Fuel HHV EF 4 2 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). 

Fuel = Mass or volume of the fuel combusted, 

either from company records or directly 

measured by a fuel flow meter, as 

applicable (mass or volume per year). 

HHV = Default high heat value of the fuel 

from Table C–1 of this subpart (mmBtu 

per mass or volume). 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(2) Use Equation C–9a of this section 

to estimate CH4 and N2O emissions for 

any fuels for which you use the Tier 2 

Equation C–2a of this section to estimate 

CO2 emissions. Use the same values for 

fuel combustion and HHV that you use 

for the Tier 1 or Tier 3 calculation. 

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

during the reporting year. 

HHV = High heat value of the fuel, averaged 

for all valid measurements for the 

reporting year (mmBtu per mass or 

volume). 

EF = Fuel-specific default emission factor for 

CH4 or N2O, from Table C–2 of this 

subpart (kg CH4 or N2O per mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(3) Use Equation C–9b of this section 

to estimate CH4 and N2O emissions for 

any fuels for which you use Equation 

C–2c of this section to calculate the CO2

emissions. Use the same values for 

steam generation and the ratio ‘‘B’’ that 

you use for Equation C–2c. 

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

Where: 

CH4 or N2O = Annual CH4 or N2O emissions 

from the combustion of a solid fuel 

(metric tons). 

Steam = Total mass of steam generated by 

solid fuel combustion during the 

reporting year (lb steam). 

B = Ratio of the boiler’s maximum rated heat 

input capacity to its design rated steam 

output (mmBtu/lb steam). 

EF = Fuel-specific emission factor for CH4 or 

N2O, from Table C–2 of this subpart (kg 

CH4 or N2O per mmBtu). 

1 × 10¥3 = Conversion factor from kilograms 

to metric tons. 

(4) Use Equation C–10 of this section 

for units in the Acid Rain Program, 

units that monitor and report heat input 

on a year-round basis according to 40 

CFR part 75, and units that use the Tier 

4 Calculation Methodology. 

CH or N O (HI) EF (Eq. C-10) 42 A =∗ ∗ 0 001 .

Where: 

CH4 or N2O = Annual CH4 or N2O emissions 

from the combustion of a particular type 

of fuel (metric tons). 

(HI)A = Cumulative annual heat input from 

the fuel, derived from the electronic data 

reports required under § 75.64 of this 

chapter or, for Tier 4 units, from the best 

available information as described in 

paragraph (c)(4)(ii) of this section 

(mmBtu). 

EF = Fuel-specific emission factor for CH4 or 

N2O, from Table C–2 of this section (kg 

CH4 or N2O per mmBtu). 

0.001 = Conversion factor from kg to metric 

tons. 

(i) If only one type of fuel listed in 

Table C–2 of this subpart is combusted 

during normal operation, substitute the 

cumulative annual heat input from 

combustion of the fuel into Equation 

C–10 of this section to calculate the 

annual CH4 or N2O emissions. 


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(ii) If more than one type of fuel listed 

in Table C–2 of this subpart is 

combusted during normal operation, use 

Equation C–10 of this section separately 

for each type of fuel. If flow rate and 

diluent gas monitors are used to 

measure the unit heat input, use the best 

available information (e.g., fuel feed rate 

measurements, fuel heating values, 

engineering analysis) to estimate the 

annual heat input from each type of 

fuel. 

(5) When multiple fuels are 

combusted during the reporting year, 

sum the fuel-specific results from 

Equations C–8, C–9a, C–9b, or C–10 of 

this section (as applicable) to obtain the 

total annual CH4 and N2O emissions, in 

metric tons. 

(d) Calculation of CO2 from sorbent. 

(1) When a unit is a fluidized bed 

boiler, is equipped with a wet flue gas 

desulfurization system, or uses other 

acid gas emission controls with sorbent 

injection, use Equation C–11 of this 

section to calculate the CO2 emissions 

from the sorbent, if those CO2 emissions 

are not monitored by CEMS: 

CO S R MW

MW

CO

S

2 = ∗∗∗ 0 91 ⎛

⎝

⎜ ⎞

⎠

⎟ . 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, from company records 

(short tons). 

R = 1.00, the calcium-to-sulfur stoichiometric 

ratio. 

MWCO2 = Molecular weight of carbon dioxide 

(44). 

MWS = Molecular weight of sorbent (100 if 

calcium carbonate). 

0.91 = Conversion factor from short tons to 

metric tons. 

(2) The annual CO2 mass emissions 

for the unit shall be the sum of the CO2

emissions from the combustion process 

and the CO2 emissions from the sorbent. 

(e) CO2 emissions from combustion of 

biomass. Use the procedures of this 

paragraph (e) to estimate biogenic CO2

emissions from units that combust a 

combination of biomass and fossil fuels. 

Reporting of CO2 emissions from 

combustion of biomass is required only 

for those biomass fuels listed in Table 

C–1 of this section, unless emissions are 

measured using CEMS. 

(1) If CEMS are not used to measure 

CO2, use Equation C–1 of this subpart to 

calculate the annual CO2 mass 

emissions from the combustion of 

biomass (except MSW) for a unit of any 

size. Determine the mass of biomass 

combusted using one of the following 

procedures in this paragraph (e)(1), as 

appropriate. 

(i) Use company records. 

(ii) Follow the procedures in 

paragraph (e)(5) of this section. 

(iii) For premixed fuels that contain 

biomass and fossil fuels (e.g., mixtures 

containing biodiesel), use best available 

information to determine the mass of 

biomass fuels and document the 

procedure used in the GHG Monitoring 

Plan required by § 98.3(g)(5). 

(2) If a CO2 CEMS (or a surrogate O2

monitor) and a stack gas flow rate 

monitor are used to determine the 

annual CO2 mass emissions either 

according to 40 CFR part 75, the Tier 4 

Calculation Methodology, or the 

alternative calculation methodology 

specified in paragraph (a)(5)(iii); and if 

both fossil fuel and biomass (except for 

MSW) are combusted in the unit during 

the reporting year, you may use the 

following procedure to determine the 

annual biogenic CO2 mass emissions. If 

MSW is combusted in the unit, follow 

the procedures in paragraph (e)(3) of 

this section. 

(i) For each operating hour, use 

Equation C–12 of this section to 

determine the volume of CO2 emitted. 

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 average CO2 concentration, 

measured by the CO2 concentration 

monitor, or, if applicable, calculated 

from the hourly average O2 concentration 

(%CO2). 

Qh = Hourly average stack gas volumetric 

flow rate, measured by the stack gas 

volumetric flow rate monitor (scfh). 

th = Source operating time (decimal fraction 

of the hour during which the source 

combusts fuel, i.e., 1.0 for a full 

operating hour, 0.5 for 30 minutes of 

operation, etc.). 

100 = Conversion factor from percent to a 

decimal fraction. 

(ii) Sum all of the hourly VCO2h values 

for the reporting year, to obtain Vtotal, 

the total annual volume of CO2 emitted. 

(iii) Calculate the annual volume of 

CO2 emitted from fossil fuel combustion 

using Equation C–13 of this section. If 

two or more types of fossil fuel are 

combusted during the year, perform a 

separate calculation with Equation C–13 

of this section for each fuel and sum the 

results. 

V Fuel F HHV (Eq. C-13) ff c = ∗ ∗

106

Where: 

Vff = Annual volume of CO2 emitted from 

combustion of a particular fossil fuel 

(scf). 

Fuel = Total quantity of the fossil fuel 

combusted in the reporting year, from 

company records, as defined in § 98.6 (lb 

for solid fuel, gallons for liquid fuel, and 

scf for gaseous fuel). 

Fc = Fuel-specific carbon based F-factor, 

either a default value from Table 1 in 

section 3.3.5 of appendix F to 40 CFR 

part 75 or a site-specific value 

determined under section 3.3.6 of 

appendix F to 40 CFR part 75 (scf CO2/ 

mmBtu). 

HHV = High heat value of the fossil fuel, 

from fuel sampling and analysis (annual 

average value in Btu/lb for solid fuel, 

Btu/gal for liquid fuel and Btu/scf for 

gaseous fuel, sampled as specified (e.g., 

monthly, quarterly, semi-annually, or by 

lot) in § 98.34(a)(2)). The average HHV 

shall be calculated according to the 

requirements of paragraph (a)(2)(ii) of 

this section. 

106 = Conversion factor, Btu per mmBtu. 

(iv) Subtract Vff from Vtotal to obtain 

Vbio, the annual volume of CO2 from the 

combustion of biomass. If a CEMS is 

being used to measure the combined 

combustion and process emissions from 

a unit that is subject to another subpart 

of part 98, then also subtract CO2

process emissions from Vtotal to 

determine Vbio. The CO2 process 

emissions must be calculated according 

to the requirements of the applicable 

subpart. 


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(v) Calculate the biogenic percentage 

of the annual CO2 emissions,expressed 

as a decimal fraction, using Equation C– 

14 of this section: 

% Biogenic V

V

bio

total

= (Eq. C-14)

(vi) Calculate the annual biogenic CO2

mass emissions, in metric tons, by 

multiplying the results obtained from 

Equation C–14 of this section by the 

annual CO2 mass emissions in metric 

tons, as determined: 

(A) Under paragraph (a)(4)(vi) of this 

section, for units using the Tier 4 

Calculation Methodology. 

(B) Under paragraph (a)(5)(iii)(B) of 

this section, for units using the 

alternative calculation methodology 

specified in paragraph (a)(5)(iii). 

(C) From the electronic data report 

required under § 75.64 of this chapter, 

for units in the Acid Rain Program and 

other units using CEMS to monitor and 

report CO2 mass emissions according to 

40 CFR part 75. However, before 

calculating the annual biogenic CO2

mass emissions, multiply the 

cumulative annual CO2 mass emissions 

by 0.91 to convert from short tons to 

metric tons. 

(3) For a unit that combusts MSW, the 

annual biogenic CO2 emissions shall be 

calculated using the procedures in this 

paragraph (e)(3). 

(i) If the Tier 1 or Tier 2 Calculation 

Methodology is used to quantify CO2

mass emissions: 

(A) Use Equation C–1 or C–2c of this 

subpart, as appropriate, to calculate the 

annual CO2 mass emissions from MSW 

combustion. 

(B) Determine the relative proportions 

of biogenic and non-biogenic CO2

emissions on a quarterly basis using the 

method specified in § 98.34(d). 

(C) Determine the annual biogenic 

CO2 mass emissions from MSW 

combustion by multiplying the annual 

CO2 mass emissions by the annual 

average biogenic decimal fraction 

obtained from § 98.34(d). 

(ii) If the unit uses Tier 4 to quantify 

CO2 emissions: 

(A) Follow the procedures in 

paragraphs (e)(2)(i) and (ii) of this 

section, to determine Vtotal. 

(B) If any fossil fuel was combusted 

during the year, follow the procedures 

in paragraph (e)(2)(iii) of this section, to 

determine Vff. 

(C) Subtract Vff from Vtotal, to obtain 

VMSW, the annual volume of CO2

emissions from MSW combustion. 

(D) Determine the annual volume of 

biogenic CO2 emissions (Vbio) from 

MSW combustion as follows. Multiply 

the annual volume of CO2 emissions 

from MSW combustion (VMSW) by the 

annual average biogenic decimal 

fraction obtained from ASTM D6866–08 

and ASTM D7459–08. 

(E) Calculate the biogenic percentage 

of the annual CO2 emissions from the 

unit, using Equation C–14 of this 

section. For the purposes of this 

calculation, the term ‘‘Vbio’’ in the 

numerator of Equation C–14 of this 

section shall be the results of the 

calculation performed under paragraph 

(e)(3)(ii)(D) of this section. 

(F) Calculate the annual biogenic CO2

mass emissions according to paragraph 

(e)(2)(vi)(A) of this section. 

(4) As an alternative to the procedures 

in paragraph (e)(2) of this section, use 

ASTM Methods D7459–08 and D6866– 

08 to determine the biogenic portion of 

the annual CO2 emissions, as described 

in § 98.34(e). If this option is selected, 

the results of each determination shall 

be expressed as a decimal fraction (e.g., 

0.30, if 30 percent of the CO2 is 

biogenic), and the values shall be 

averaged over the reporting year. The 

annual biogenic CO2 mass emissions 

shall be calculated by multiplying the 

the total annual CO2 mass emissions by 

the annual average biogenic fraction 

obtained from ASTM D6866–08 and 

ASTM D7459–08. 

(5) If Equation C–1 of this section is 

selected to calculate the annual biogenic 

mass emissions for wood, wood waste, 

or other solid biomass-derived fuel, 

Equation C–15 of this section may be 

used to quantify biogenic fuel 

consumption, provided that all of the 

required input parameters are accurately 

quantified. Similar equations and 

calculation methodologies based on 

steam generation and boiler efficiency 

may be used, provided that they are 

documented in the GHG Monitoring 

Plan required by § 98.3(g)(5). 

( ) [ ]( )

( )

Fuel H S HI

HHV p

nb

bio

= ∗ −

2000 ( ) (Eq. C-15) Eff bio

Where: 

(Fuel)p = Quantity of biomass consumed 

during the measurement period ‘‘p’’ (tons/ 

year or tons/month, as applicable). 

H = Average enthalpy of the boiler steam for 

the measurement period (Btu/lb). 

S = Total boiler steam production for the 

measurement period (lb/month or lb/year, 

as applicable). 

(HI)nb = Heat input from co-fired fossil fuels 

and non-biomass-derived fuels for the 

measurement period, based on company 

records of fuel usage and default or 

measured HHV values (Btu/month or Btu/ 

year, as applicable). 

(HHV)bio = Default or measured high heat 

value of the biomass fuel (Btu/lb). 

(Eff)bio = Percent efficiency of biomass-toenergy conversion, expressed as a decimal 

fraction. 

2000 = Conversion factor (lb/ton). 

§ 98.34 Monitoring and QA/QC 

requirements. 

The CO2 mass emissions data for 

stationary fuel combustion sources shall 

be monitored as follows: 

(a) For the Tier 2 Calculation 

Methodology: 

(1) All fuel samples shall be taken at 

a location in the fuel handling system 

that provides a sample representative of 

the fuel combusted. The fuel sampling 

and analysis may be performed by either 

the owner or operator or the supplier of 

the fuel. 

(2) The minimum required frequency 

of the HHV sampling and analysis for 

each type of fuel is specified in this 

paragraph. When the specified 

frequency is based on a specified time 

period (i.e., weekly, monthly, quarterly, 

or semiannually), fuel sampling and 

analysis is required only for those 

periods in which the unit operates. 

(i) For natural gas, semiannual 

sampling and analysis is required (i.e., 

twice in a calendar year, with 

consecutive samples taken at least four 

months apart). 

(ii) For coal and fuel oil, analysis of 

at least one representative sample from 

each fuel lot is required. For the 

purposes of this section, a fuel lot is 

defined as a shipment or delivery of a 

single fuel (e.g., ship load, barge load, 

group of trucks, group of railroad cars, 

etc.). 

(iii) For liquid fuels other than fuel 

oil, for fossil fuel-derived gaseous fuels, 

and for biogas; sampling and analysis is 

required at least once per calendar 

quarter. To the extent practicable, 

consecutive quarterly samples shall be 

taken at least 30 days apart. 

(iv) For solid fuels other than coal and 

MSW, weekly sampling is required to 


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obtain composite samples, which are 

then analyzed monthly. 

(3) If different types of fuel (e.g., 

different ranks of coal or different 

grades of fuel oil) are blended prior to 

combustion, use one of the following 

procedures in this paragraph. 

(i) Use a weighted HHV value in the 

emission calculations, based on the 

relative proportions of each fuel in the 

blend. 

(ii) Take a representative sample of 

the blend and analyze it for HHV. 

(4) If, for a particular type of fuel, 

HHV sampling and analysis is 

performed more often than the 

minimum frequency specified in 

paragraph (a)(2) of this section, the 

results of all valid fuel analyses shall be 

used in the GHG emission calculations. 

(5) If, for a particular type of fuel, 

valid HHV values are obtained at less 

than the minimum frequency specifed 

in paragraph (a)(2) of this section, 

appropriate substitute data values shall 

be used in the emissions calculations, in 

accordance with missing data 

procedures of § 98.35. 

(6) Use any applicable fuel sampling 

and analysis methods in this paragraph 

(a)(6) to determine the high heat values. 

Alternatively, for gaseous fuels, the 

HHV may be calculated using 

chromatographic analysis together with 

standard heating values of the fuel 

constituents, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

(i) ASTM D4809–06 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method) 

(incorporated by reference, see § 98.7). 

(ii) ASTM D240–02 (Reapproved 

2007) Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter 

(incorporated by reference, see § 98.7). 

(iii) ASTM D1826–94 (Reapproved 

2003) Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter (incorporated by 

reference, see § 98.7). 

(iv) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels 

(incorporated by reference, see § 98.7). 

(v) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion 

(incorporated by reference, see § 98.7). 

(vi) GPA Standard 2172–09 

Calculation of Gross Heating Value, 

Relative Density, Compressibility and 

Theoretical Hydrocarbon Liquid 

Content for Natural Gas Mixtures for 

Custody Transfer (incorporated by 

reference, see § 98.7). 

(vii) GPA Standard 2261–00, Analysis 

for Natural Gas and Similar Gaseous 

Mixtures by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(viii) ASTM D5865–07a, Standard 

Test Method for Gross Calorific Value of 

Coal and Coke (incorporated by 

reference, see § 98.7). 

(b) For the Tier 3 Calculation 

Methodology: 

(1) Calibrate each oil and gas flow 

meter according to § 98.3(i) and the 

provisions of this paragraph (b). 

(i) Perform calibrations using any of 

the test methods and procedures in this 

paragraph (b)(1)(i): 

(A) An applicable flow meter test 

method listed in paragraphs (b)(4)(i) 

through (b)(4)(viii) of this section. 

(B) The calibration procedures 

specified by the flow meter 

manufacturer. 

(C) An industry-accepted or industry 

standard calibration practice. 

(ii) In addition to the initial 

calibration required by § 98.3(i), 

recalibrate each fuel flow meter (except 

for qualifying billing meters under 

paragraph (b)(1)(iii) of this section) 

either annually, at the minimum 

frequency specified by the 

manufacturer, or at the interval 

specified by the industry consensus 

standard practice used. 

(iii) Fuel billing meters are exempted 

from the initial and ongoing calibration 

requirements of this paragraph, 

provided that the fuel supplier and the 

unit combusting the fuel do not have 

any common owners and are not owned 

by subsidiaries or affiliates of the same 

company. 

(iv) For the initial calibration of an 

orifice, nozzle, or venturi meter; in-situ 

calibration of the transmitters is 

sufficient. A primary element inspection 

(PEI) shall be performed at least once 

every three years. 

(v) For the continuously-operating 

units and processes described in 

§ 98.3(i)(6), the required flow meter 

recalibrations and, if necessary, the PEIs 

may be postponed until the next 

scheduled maintenance outage. 

(vi) If a mixture of fuels is transported 

by a common pipe (e.g., still gas and 

supplementary natural gas), you must 

either separately meter each of the fuels 

prior to mixing using flow meters 

calibrated according to § 98.3(i), or use 

flow meters calibrated according to 

§ 98.3(i) to measure the mixed fuel at 

the common pipe and to separately 

meter an appropriate subset of the fuels 

prior to mixing. If the latter option is 

chosen, quantify the fuels that are not 

measured prior to mixing by subtracting 

out the fuels measured prior to mixing 

from the fuel measured at the common 

pipe. 

(2) Oil tank drop measurements (if 

used to determine liquid fuel use 

volume) shall be performed according to 

any an appropriate method published 

by a consensus-based standards 

organization (e.g., the American 

Petroleum Institute). 

(3) The carbon content and, if 

applicable, molecular weight of the 

fuels shall be determined according to 

the procedures in this paragraph (b)(3). 

(i) All fuel samples shall be taken at 

a location in the fuel handling system 

that provides a sample representative of 

the fuel combusted. The fuel sampling 

and analysis may be performed by either 

the owner or operator or by the supplier 

of the fuel. 

(ii) At a minimum, fuel samples shall 

be collected at the frequency specified 

in this paragraph. When sampling is 

required at a specified time interval 

(e.g., weekly, monthly, quarterly, or 

semiannually), fuel sampling and 

analysis is required for only those 

specified periods in which the unit 

operates. 

(A) For natural gas, semiannual 

sampling and analysis is required (i.e., 

twice in a calendar year, with 

consecutive samples taken at least four 

months apart). 

(B) For coal and fuel oil, analysis of 

at least one representative sample from 

each fuel lot is required. For the 

purposes of this section, a fuel lot is 

defined as a shipment or delivery of a 

single fuel (e.g., ship load, barge load, 

group of trucks, group of railroad cars, 

etc.). 

(C) For other liquid fuels other than 

fuel oil, for fossil fuel-derived gaseous 

fuels, and for biogas; sampling and 

analysis is required at least once per 

calendar quarter. To the extent 

practicable, consecutive quarterly 

samples shall be taken at least 30 days 

apart. 

(D) For solid fuels other than coal, 

weekly sampling is required to obtain 

composite samples, which are then 

analyzed monthly. 

(E) For gaseous fuels other than 

natural gas and biogas (e.g., refinery 

gas), daily sampling and analysis to 

determine the carbon content and 

molecular weight of the fuel is required 

if the necessary equipment is in place to 

make these measurements. Otherwise, 

weekly sampling and analysis shall be 

performed. 

(iii) If, for a particular type of fuel, 

sampling and analysis for carbon 

content and molecular weight is 

performed more often than the 


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minimum frequency specified in 

paragraph (b)(3) of this section, the 

results of all valid fuel analyses shall be 

used in the GHG emission calculations. 

(iv) If, for a particular type of fuel, 

sampling and analysis for carbon 

content and molecular weight is 

performed at less than the minimum 

frequency specified in paragraph (b)(3) 

of this section, appropriate substitute 

data values shall be used in the 

emissions calculations, in accordance 

with the missing data procedures of 

§ 98.35. 

(v) The procedures of paragraph (a)(3) 

of this section apply to carbon content 

and molecular weight determinations. 

(4) Use any applicable standard 

method from the following list to 

quality assure the data from each fuel 

flow meter. 

(i) AGA Report No. 3, Orifice 

Metering of Natural Gas and Other 

Related Hydrocarbon Fluids, Part 1: 

General Equations and Uncertainty 

Guidelines (1990) and Part 2: 

Specification and Installation 

Requirements (2000) (incorporated by 

reference, see § 98.7). 

(ii) AGA Transmission Measurement 

Committee Report No. 7, Measurement 

of Gas by Turbine Meters (2006) 

(incorporated by reference, see § 98.7). 

(iii) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi 

(incorporated by reference, see § 98.7). 

(iv) ASME MFC–4M–1986 

(Reaffirmed 1997), Measurement of Gas 

Flow by Turbine Meters (incorporated 

by reference, see § 98.7). 

(v) ASME MFC–5M–1985 (Reaffirmed 

1994), Measurement of Liquid Flow in 

Closed Conduits Using Transit-Time 

Ultrasonic Flowmeters (incorporated by 

reference, see § 98.7). 

(vi) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters (incorporated 

by reference, see § 98.7). 

(vii) ASME MFC–7M–1987 

(Reaffirmed 1992), Measurement of Gas 

Flow by Means of Critical Flow Venturi 

Nozzles (incorporated by reference, see 

§ 98.7). 

(viii) ASME MFC–9M–1988 

(Reaffirmed 2001), Measurement of 

Liquid Flow in Closed Conduits by 

Weighing Method (incorporated by 

reference, see § 98.7). 

(5) Use any applicable methods from 

the following list to determine the 

carbon content and molecular weight 

(for gaseous fuel) of the fuel. 

Alternatively, the results of 

chromatographic analysis of the fuel 

may be used, provided that the gas 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions. 

(i) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(ii) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(iii) ASTM D2502–04 (Reapproved 

2002) Standard Test Method for 

Estimation of Molecular Weight 

(Relative Molecular Mass) of Petroleum 

Oils from Viscosity Measurements 

(incorporated by reference, see § 98.7). 

(iv) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Relative Molecular 

Weight) of Hydrocarbons by 

Thermoelectric Measurement of Vapor 

Pressure (incorporated by reference, see 

§ 98.7). 

(v) ASTM D3238–95 (Reapproved 

2005) Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method (incorporated 

by reference, see § 98.7). 

(vi) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants (incorporated 

by reference, see § 98.7). 

(vii) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 

(c) For the Tier 4 Calculation 

Methodology, the CO2 and flow rate 

monitors must be certified prior to the 

applicable deadline specified in 

§ 98.33(b)(5). 

(1) For initial certification, you may 

use any one of the following three 

procedures in this paragraph. 

(i) § 75.20(c)(2) and (4) and appendix 

A to 40 CFR part 75. 

(ii) The calibration drift test and 

relative accuracy test audit (RATA) 

procedures of Performance Specification 

3 in appendix B to part 60 (for the CO2

concentration monitor) and Performance 

Specification 6 in appendix B to part 60 

(for the continuous emission rate 

monitoring system (CERMS)). 

(iii) The provisions of an applicable 

State continuous monitoring program. 

(2) If an O2 concentration monitor is 

used to determine CO2 concentrations, 

the applicable provisions of 40 CFR part 

75, 40 CFR part 60, or an applicable 

State continuous monitoring program 

shall be followed for initial certification 

and on-going quality assurance, and all 

required RATAs of the monitor shall be 

done on a percent CO2 basis. 

(3) For ongoing quality assurance, 

follow the applicable procedures in 

either appendix B to 40 CFR part 75, 

appendix F to 40 CFR part 60, or an 

applicable State continuous monitoring 

program. If appendix F to 40 CFR part 

60 is selected for on-going quality 

assurance, perform daily calibration 

drift assessments for both the CO2

monitor (or surrogate O2 monitor) and 

the flow rate monitor, conduct cylinder 

gas audits of the CO2 concentration 

monitor in three of the four quarters of 

each year (except for non-operating 

quarters), and perform annual RATAs of 

the CO2 concentration monitor and the 

CERMS. 

(4) For the purposes of this part, the 

stack gas volumetric flow rate monitor 

RATAs required by appendix B to 40 

CFR part 75 and the annual RATAs of 

the CERMS required by appendix F to 

40 CFR part 60 need only be done at one 

operating level, representing normal 

load or normal process operating 

conditions, both for initial certification 

and for ongoing quality assurance. 

(5) If, for any source operating hour, 

quality assured data are not obtained 

with a CO2 monitor (or surrogate O2

monitor), flow rate monitor, or (if 

applicable) moisture monitor, use 

appropriate substitute data values in 

accordance with the missing data 

provisions of § 98.35. 

(d) When municipal solid waste 

(MSW) is combusted in a unit, 

determine the biogenic portion of the 

CO2 emissions from MSW combustion 

using ASTM D6866–08 Standard Test 

Methods for Determining the Biobased 

Content of Solid, Liquid, and Gaseous 

Samples Using Radiocarbon Analysis 

(incorporated by reference, see § 98.7) 

and ASTM D7459–08 Standard Practice 

for Collection of Integrated Samples for 

the Speciation of Biomass (Biogenic) 

and Fossil-Derived Carbon Dioxide 

Emitted from Stationary Emissions 

Sources (incorporated by reference, see 

§ 98.7). Perform the ASTM D7459–08 

sampling and the ASTM D6866–08 

analysis at least once in every calendar 

quarter in which MSW is combusted in 

the unit. Collect each gas sample during 

normal unit operating conditions while 

MSW is the only fuel being combusted 

for at least 24 consecutive hours or for 

as long as is necessary to obtain a 

sample large enough to meet the 

specifications of ASTM D6866–08. 

Separate CO2 emissions into the 

biogenic and non-biogenic fraction 

using the average proportion of biogenic 

emissions of all samples analyzed 

during the reporting year. Express the 

results as a decimal fraction (e.g., 0.30, 

if 30 percent of the CO2 from MSW 

combustion is biogenic). If there is a 


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common fuel source of MSW that feeds 

multiple units at the facility, performing 

the testing at only one of the units is 

sufficient. 

(e) For units that use CEMS to 

measure the total CO2 mass emissions 

and combust a combination of biogenic 

fuels (other than MSW) with a fossil 

fuel, ASTM D6866–08 and ASTM 

D7459–08 may be used to determine the 

biogenic portion of the CO2 emissions. 

Perform the ASTM D7459–08 sampling 

and the ASTM D6866–08 analysis at 

least once in every calendar quarter in 

which biogenic and non-biogenic fuels 

are co-fired in the unit. The relative 

proportions of the biogenic and nonbiogenic fuels during the sampling shall 

be representative of the average fuel 

blend for a typical operating year. 

Collect each gas sample using ASTM 

D7459–08 during normal unit operation 

for at least 24 consecutive hours or for 

as long as is necessary to obtain a 

sample large enough to meet the 

specifications of ASTM D6866–08. 

(f) Whenever company records are 

used in the calculation of CO2

emissions, the records required under 

§ 98.3(g) shall include both the company 

records and an explanation of how those 

records are used to estimate the 

following parameters: 

(1) Fuel consumption, when the Tier 

1 and Tier 2 Calculation Methodologies 

are used. 

(2) Fuel consumption, when solid fuel 

is combusted and the Tier 3 Calculation 

Methodology is used. 

(3) Fossil fuel consumption when 

§ 98.33(e) applies to a unit that uses 

CEMS to quantify CO2 emissions and 

that combusts both fossil and biomass 

fuels. 

(4) Sorbent usage, when § 98.33(d) 

applies. 

(5) Quantity of steam generated by a 

unit when § 98.33(a)(2) applies. 

(6) Biogenic fuel consumption under 

§ 98.33(e)(5). 

(g) As part of the GHG Monitoring 

Plan required under § 98.3(g)(5), you 

must document the procedures used to 

ensure the accuracy of the estimates of 

fuel usage, sorbent usage, steam 

production, and boiler efficiency (as 

applicable) in paragraph (f) of this 

section, including but not limited to 

calibration of weighing equipment, fuel 

flow meters, steam flow meters, and 

other measurement devices. The 

estimated accuracy of measurements 

made with these devices shall also be 

recorded, and the technical basis for 

these estimates shall be provided. 

§ 98.35 Procedures for estimating missing 

data. 

Whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a CEMS malfunctions during unit 

operation or if a required fuel sample is 

not taken), a substitute data value for 

the missing parameter shall be used in 

the calculations. 

(a) For all units subject to the 

requirements of the Acid Rain Program, 

and all other stationary combustion 

units subject to the requirements of this 

part that monitor and report emissions 

and heat input data in accordance with 

40 CFR part 75, the missing data 

substitution procedures in 40 CFR part 

75 shall be followed for CO2

concentration, stack gas flow rate, fuel 

flow rate, high heating value, and fuel 

carbon content. 

(b) For units that use the Tier 1, Tier 

2, Tier 3, and Tier 4 Calculation 

Methodologies, perform missing data 

substitution as follows for each 

parameter: 

(1) For each missing value of the high 

heating value, carbon content, or 

molecular weight of the fuel, substitute 

the arithmetic average of the qualityassured values of that parameter 

immediately preceding and immediately 

following the missing data incident. If 

the ‘‘after’’ value has not been obtained 

by the time that the GHG emissions 

report is due, you may use the ‘‘before’’ 

value for missing data substitution or 

the best available estimate of the 

parameter, based on all available 

process data (e.g., electrical load, steam 

production, operating hours). If, for a 

particular parameter, no quality-assured 

data are available prior to the missing 

data incident, the substitute data value 

shall be the first quality-assured value 

obtained after the missing data period. 

(2) For missing records of CO2

concentration, stack gas flow rate, 

percent moisture, fuel usage, and 

sorbent usage, the substitute data value 

shall be the best available estimate of 

the parameter, based on all available 

process data (e.g., electrical load, steam 

production, operating hours, etc.). You 

must document and retain records of the 

procedures used for all such estimates. 

§ 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 paragraphs (b) 

through (d) of this section (as 

applicable) and the emissions 

verification data in paragraph (e) of this 

section. 

(b) Units that use the four tiers. You 

shall report the following information 

for stationary combustion units that use 

the Tier 1, Tier 2, Tier 3, or Tier 4 

methodology in § 98.33(a) to calculate 

CO2 emissions, except as otherwise 

provided in paragraphs (c) and (d) of 

this section: 

(1) The unit ID number. 

(2) A code representing the type of 

unit. 

(3) Maximum rated heat input 

capacity of the unit, in mmBtu/hr for 

boilers and process heaters only and 

relevant units of measure for other 

combustion sources. 

(4) Each type of fuel combusted in the 

unit during the report year. 

(5) The tier used to calculate the CO2

emissions for each type of fuel 

combusted (i.e., Tier 1, 2, 3, or 4). 

(6) For a unit that uses Tiers 1, 2, and 

3; the CO2, CH4, and N2O emissions for 

each type of fuel combusted, expressed 

in metric tons of each gas and in metric 

tons of CO2e. 

(7) For a unit that uses Tier 4: 

(i) For units that burn fossil fuels 

only, the annual CO2 emissions for all 

fuels combined. Reporting CO2

emissions by type of fuel is not 

required. 

(ii) For units that burn both fossil 

fuels and biomass, the annual CO2

emissions from combustion of all fossil 

fuels combined and the annual CO2

emissions from combustion of all 

biomass fuels combined. Reporting CO2

emissions by type of fuel is not 

required. 

(iii) Annual CH4 and N2O emissions 

for each type of fuel combusted 

expressed in metric tons of each gas and 

in metric tons of CO2e. 

(8) Annual CO2 emissions from 

sorbent (if calculated using Equation C– 

11 of this subpart), expressed in metric 

tons. 

(9) Annual GHG emissions from all 

fossil fuels burned in the unit (i.e., the 

sum of the CO2, CH4, and N2O 

emissions), expressed in metric tons of 

CO2e. 

(10) Customer meter number for units 

that combust natural gas. 

(c) Reporting alternatives for units 

using the four Tiers. You may use any 

of the applicable reporting alternatives 

of this paragraph to simplify the unitlevel reporting required under 

paragraph (b) of this section: 

(1) Aggregation of units. If a facility 

contains two or more units (e.g., boilers 

or combustion turbines), each of which 

has a maximum rated heat input 

capacity of 250 mmBtu/hr or less, you 

may report the combined GHG 

emissions for the group of units in lieu 

of reporting GHG emissions from the 

individual units, provided that the use 

of Tier 4 is not required or elected for 


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any of the units and the units use the 

same tier for any common fuels 

combusted. If this option is selected, the 

following information shall be reported 

instead of the information in paragraph 

(b) of this section: 

(i) Group ID number, beginning with 

the prefix ‘‘GP’’. 

(ii) An identification number for each 

unit in the group. 

(iii) Cumulative maximum rated heat 

input capacity of the group (mmBtu/hr). 

(iv) The highest maximum rated heat 

input capacity of any unit in the group 

(mmBtu/hr). 

(v) Each type of fuel combusted in the 

group of units during the reporting year. 

(vi) Annual CO2, CH4, and N2O mass 

emissions aggregated for each type of 

fuel combusted in the group of units 

during the year, expressed in metric 

tons of each gas and in metric tons of 

CO2e. If any of the units burn both fossil 

fuels and biomass, report also the 

annual CO2 emissions from combustion 

of all fossil fuels combined and annual 

CO2 emissions from combustion of all 

biomass fuels combined, expressed in 

metric tons. 

(vii) The tier used to calculate the CO2

mass emissions for each type of fuel 

combusted in the units (i.e., Tier 1, Tier 

2, or Tier 3). 

(viii) The calculated CO2 mass 

emissions (if any) from sorbent. 

(ix) Annual GHG emissions from all 

fossil fuels burned in the group (i.e., the 

sum of the CO2, CH4, and N2O 

emissions), expressed in metric tons of 

CO2e. 

(2) Monitored common stack or duct 

configurations. When the flue gases 

from two or more stationary combustion 

units at a facility are discharged through 

a common stack or duct before exiting 

to the atmosphere and if CEMS are used 

to continuously monitor CO2 mass 

emissions at the common stack or duct 

according to the Tier 4 Calculation 

Methodology, you may report the 

combined emissions from the units 

sharing the common stack or duct, in 

lieu of separately reporting the GHG 

emissions from the individual units. 

The following information shall be 

reported instead of the information in 

paragraph (b) of this section: 

(i) Common stack or duct 

identification number, beginning with 

the prefix ‘‘CS’’. 

(ii) Identification numbers of the units 

sharing the common stack or duct. 

(iii) Maximum rated heat input 

capacity of each unit sharing the 

common stack or duct (mmBtu/hr). 

(iv) Each type of fuel combusted in 

the units during the year. 

(v) The methodology used to calculate 

the CO2 mass emissions, i.e., Tier 4. 

(vi) If the any of the units burn both 

fossil fuels and biomass, annual CO2

mass emissions, annual CO2 emissions 

from combustion of fossil fuels, and 

annual CO2 emissions from combustion 

of biomass measured at the common 

stack or duct, expressed in metric tons. 

(vii) The annual CH4 and N2O 

emissions from the units sharing the 

common stack or duct, expressed in 

metric tons of each gas and in metric 

tons of CO2e. 

(viii) Annual GHG emissions from all 

fossil fuels burned in the group (i.e., the 

sum of the CO2, CH4, and N2O 

emissions), expressed in metric tons of 

CO2e. 

(3) Common pipe configurations. 

When two or more liquid-fired or 

gaseous-fired stationary combustion 

units at a facility combust the same type 

of fuel and the fuel is fed to the 

individual units through a common 

supply line or pipe, you may report the 

combined emissions from the units 

served by the common supply line, in 

lieu of separately reporting the GHG 

emissions from the individual units, 

provided that the total amount of fuel 

combusted by the units is accurately 

measured at the common pipe or supply 

line using a fuel flow meter that is 

calibrated in accordance with § 98.34(a). 

If a portion of the fuel measured at the 

common pipe is diverted to a chemical 

or industrial process where it is used 

but not combusted, you may subtract 

the diverted fuel from the fuel measured 

at the common pipe prior to performing 

the GHG emissions calculations, 

provided that the amount of fuel 

diverted is also measured with a 

calibrated flow meter per § 98.3(i). If the 

common pipe option is selected, the 

applicable tier shall be used based on 

the maximum rated heat input capacity 

of the largest unit served by the 

common pipe configuration. The 

following information shall be reported 

instead of the information in paragraph 

(b) of this section: 

(i) Common pipe identification 

number, beginning with the prefix 

‘‘CP’’. 

(ii) The identification numbers of the 

units served by the common pipe. 

(iii) Maximum rated heat input 

capacity of each unit served by the 

common pipe (mmBtu/hr). 

(iv) The fuels combusted in the units 

during the reporting year. 

(v) The methodology used to calculate 

the CO2 mass emissions (i.e., Tier 1, Tier 

2, or Tier 3). 

(vi) If the any of the units burns both 

fossil fuels and biomass, the annual CO2

mass emissions from combustion of all 

fossil fuels and annual CO2 emissions 

from combustion of all biomass fuels 

from the units served by the common 

pipe, expressed in metric tons. 

(vii) Annual CH4 and N2O emissions 

from the units served by the common 

pipe, expressed in metric tons of each 

gas and in metric tons of CO2e. 

(viii) Annual GHG emissions from all 

fossil fuels burned in units served by 

the common pipe (i.e., the sum of the 

CO2, CH4, and N2O emissions), 

expressed in metric tons of CO2e. 

(d) Units subject to 40 CFR part 75. 

(1) For stationary combustion units 

that are either subject to the Acid Rain 

Program or not in the Acid Rain 

Program but monitor and report CO2

mass emissions year-round according to 

40 CFR part 75, you shall report the 

following unit-level information: 

(i) Unit or stack identification 

numbers. Use exact same unit, common 

stack, or multiple stack identification 

numbers that represent the monitored 

locations (e.g., 1, 2, CS001, MS1A, etc.) 

that are reported under § 75.64 of this 

chapter. 

(ii) Annual CO2, CH4, and N2O 

emissions at each monitored location, 

expressed in metric tons of CO2e. 

(iii) Identification of the Part 75 

methodology used to determine the CO2

mass emissions. 

(2) For units that use the alternative 

CO2 mass emissions calculation 

methods for units with continuous 

monitoring systems provided in 

§ 98.33(a)(5), you shall report the 

following unit-level information: 

(i) Unit, stack, or pipe ID numbers. 

Use exact same unit, common stack, or 

multiple stack identification numbers 

that represent the monitored locations 

(e.g., 1, 2, CS001, MS1A, etc.) that are 

reported under § 75.64 of this chapter. 

(ii) For units that use the alternative 

methods specified in § 98.33(a)(5)(i) and 

(ii) to monitor and report heat input 

data year-round according to appendix 

D to 40 CFR part 75 or 40 CFR 75.19: 

(A) Each type of fuel combusted in the 

unit during the reporting year. 

(B) The methodology used to calculate 

the CO2 mass emissions for each fuel 

type. 

(C) A code or flag to indicate whether 

heat input is calculated according to 

appendix D to 40 CFR part 75 or 40 CFR 

75.19. 

(D) Annual CO2, CH4, and N2O 

emissions at each monitored location, 

across all fuel types, expressed in metric 

tons of CO2e. 

(iii) For units with continuous 

monitoring systems that use the 

alternative method for units with 

continuous monitoring systems in 

§ 98.33(a)(5)(iii) to monitor heat input 

year-round according to 40 CFR part 75: 

(A) Fuel combusted during the 

reporting year. 


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(B) Methodology used to calculate the 

CO2 mass emissions. 

(C) A code or flag to indicate that the 

heat input data is derived from CEMS 

measurements. 

(D) The total annual CO2, CH4, and 

N2O emissions at each monitored 

location, expressed in metric tons of 

CO2e. 

(e) Verification data. You must keep 

on file, in a format suitable for 

inspection and auditing, sufficient data 

to verify the reported GHG emissions. 

This data and information must, where 

indicated in this paragraph (e), be 

included in the annual GHG emissions 

report. 

(1) The applicable verification data 

specified in this paragraph (e) are not 

required to be kept on file or reported 

for units that meet any one of the three 

following conditions: 

(i) Are subject to the Acid Rain 

Program. 

(ii) Use the alternative methods for 

units with continuous monitoring 

systems provided in § 98.33(a)(5). 

(iii) Are not in the Acid Rain Program, 

but are required monitor and report CO2

mass emissions and heat input data 

year-round, in accordance with 40 CFR 

part 75. 

(2) For stationary combustion sources 

using the Tier 1, Tier 2, Tier 3, and Tier 

4 Calculation Methodologies in 

§ 98.33(a) to quantify CO2 emissions, the 

following additional information shall 

be kept on file and included in the GHG 

emissions report, where indicated: 

(i) For the Tier 1 Calculation 

Methodology, report the total quantity 

of each type of fuel combusted in the 

unit or group of aggregated units (as 

applicable) during the reporting year, in 

short tons for solid fuels, gallons for 

liquid fuels and standard cubic feet for 

gaseous fuels. 

(ii) For the Tier 2 Calculation 

Methodology, report: 

(A) The total quantity of each type of 

fuel combusted in the unit or group of 

aggregated units (as applicable) during 

each month of the reporting year. 

Express the quantity of each fuel 

combusted during the measurement 

period in short tons for solid fuels, 

gallons for liquid fuels, and scf for 

gaseous fuels. 

(B) The frequency of the HHV 

determinations (e.g., once a month, once 

per fuel lot). 

(C) The high heat values used in the 

CO2 emissions calculations for each 

type of fuel combusted, in mmBtu per 

short ton for solid fuels, mmBtu per 

gallon for liquid fuels, and mmBtu per 

scf for gaseous fuels. Specify the date on 

which each fuel sample was taken. 

Indicate whether each HHV is a 

measured value of a substitute data 

value. 

(D) If Equation C–2c of this subpart is 

used to calculate CO2 mass emissions, 

report the total quantity (i.e., pounds) of 

steam produced from MSW or solid fuel 

combustion during the year, and the 

ratio of the maximum rate heat input 

capacity to the design rated steam 

output capacity of the unit, in mmBtu 

per lb of steam. 

(iii) For the Tier 2 Calculation 

Methodology, keep records of the 

methods used to determine the HHV for 

each type of fuel combusted and the 

date on which each fuel sample was 

taken. 

(iv) For the Tier 3 Calculation 

Methodology, report: 

(A) The quantity of each type of fuel 

combusted in the unit or group of units 

(as applicable) during the year, in short 

tons for solid fuels, gallons for liquid 

fuels, and scf for gaseous fuels. 

(B) The frequency of carbon content 

and, if applicable, molecular weight 

determinations for each type of fuel for 

the reporting year (e.g., daily, weekly, 

monthly, semiannually, once per fuel 

lot). 

(C) The carbon content and, if 

applicable, gas molecular weight values 

used in the emission calculations 

(including both valid and substitute 

data values). Report all measured values 

if the fuel is sampled monthly or less 

frequently. Otherwise, for daily and 

weekly sampling, report monthly 

average values determined using the 

calculation procedures in Equation C– 

2b for each variable. Express carbon 

content as a decimal fraction for solid 

fuels, kg C per gallon for liquid fuels, 

and kg C per kg of fuel for gaseous fuels. 

Express the gas molecular weights in 

units of kg per kg-mole. 

(D) The total number of valid carbon 

content determinations and, if 

applicable, molecular weight 

determinations made during the 

reporting year, for each fuel type. 

(E) The number of substitute data 

values used for carbon content and, if 

applicable, molecular weight used in 

the annual GHG emissions calculations. 

(v) For the Tier 3 Calculation 

Methodology, keep records of the 

following: 

(A) For liquid and gaseous fuel 

combustion, the dates and results of the 

initial calibrations and periodic 

recalibrations of the required fuel flow 

meters. 

(B) For fuel oil combustion, the 

method from § 98.34(b) used to make 

tank drop measurements (if applicable). 

(C) The methods used to determine 

the carbon content for each type of fuel 

combusted. 

(D) The methods used to calibrate the 

fuel flow meters). 

(vi) For the Tier 4 Calculation 

Methodology, report: 

(A) The total number of source 

operating hours in the reporting year. 

(B) The cumulative CO2 mass 

emissions in each quarter of the 

reporting year, i.e., the sum of the 

hourly values calculated from Equation 

C–6 or C–7 of this subpart (as 

applicable), in metric tons. 

(C) For CO2 concentration, stack gas 

flow rate, and (if applicable) stack gas 

moisture content, the percentage of 

source operating hours in which a 

substitute data value of each parameter 

was used in the emissions calculations. 

(vii) For the Tier 4 Calculation 

Methodology, keep records of: 

(A) Whether the CEMS certification 

and quality assurance procedures of 40 

CFR part 75, 40 CFR part 60, or an 

applicable State continuous monitoring 

program were used. 

(B) The dates and results of the initial 

certification tests of the CEMS. 

(C) The dates and results of the major 

quality assurance tests performed on the 

CEMS during the reporting year, i.e., 

linearity checks, cylinder gas audits, 

and relative accuracy test audits 

(RATAs). 

(viii) If CO2 emissions that are 

generated from acid gas scrubbing with 

sorbent injection are not captured using 

CEMS, report: 

(A) The total amount of sorbent used 

during the report year, in short tons. 

(B) The molecular weight of the 

sorbent. 

(C) The ratio (‘‘R’’) in Equation C–11 

of this subpart. 

(ix) For units that combust both fossil 

fuel and biomass, when CEMS are used 

to quantify the annual CO2 emissions 

and biogenic CO2 is determined 

according to § 98.33(e)(2), you shall 

report the following additional 

information, as applicable: 

(A) The annual volume of CO2

emitted from the combustion of all 

fuels, i.e., Vtotal, in scf. 

(B) The annual volume of CO2 emitted 

from the combustion of fossil fuels, i.e., 

Vff, in scf. If more than one type of fossil 

fuel was combusted, report the 

combustion volume of CO2 for each fuel 

separately as well as the total. 

(C) The annual volume of CO2 emitted 

from the combustion of biomass, i.e., 

Vbio, in scf. 

(D) The carbon-based F-factor used in 

Equation C–13 of this subpart, for each 

type of fossil fuel combusted, in scf CO2

per mmBtu. 

(E) The annual average HHV value 

used in Equation C–13 of this subpart, 

for each type of fossil fuel combusted, 


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in Btu/lb, Btu/gal, or Btu/scf, as 

appropriate. 

(F) The total quantity of each type of 

fossil fuel combusted during the 

reporting year, in lb, gallons, or scf, as 

appropriate. 

(G) Annual biogenic CO2 mass 

emissions, in metric tons. 

(x) When ASTM methods D7459–08 

and D6866–08 are used to determine the 

biogenic portion of the annual CO2

emissions from MSW combustion, 

report: 

(A) The results of each quarterly 

sample analysis, expressed as a decimal 

fraction (e.g., if the biogenic fraction of 

the CO2 emissions from MSW 

combustion is 30 percent, report 0.30). 

(B) Annual combined biomass and 

fossil fuel CO2 emissions from MSW 

combustion, in metric tons of CO2e. 

(C) The quantities Vff, Vtotal, and VMSW

from § 98.33(e)(4)(ii), if CEMS are used 

to measure CO2 emissions. 

(D) The annual volume of biogenic 

CO2 emissions from MSW combustion, 

in metric tons. 

(xi) When ASTM methods D7459–08 

and D6866–08 are used to determine the 

biogenic portion of the annual CO2

emissions from a unit that co-fires 

biogenic (other than MSW) and nonbiogenic fuels, you shall report the 

results of each quarterly sample 

analysis, expressed as a decimal fraction 

(e.g., if the biogenic fraction of the CO2

emissions is 30 percent, report 0.30). 

(3) Within 30 days of receipt of a 

written request from the Administrator, 

you shall submit explanations of the 

following: 

(i) An explanation of how company 

records are used to quantify fuel 

consumption, if the Tier 1 or Tier 2 

Calculation Methodology is used to 

calculate CO2 emissions. 

(ii) An explanation of how company 

records are used to quantify fuel 

consumption, if solid fuel is combusted 

and the Tier 3 Calculation Methodology 

is used to calculate CO2 emissions. 

(iii) An explanation of how sorbent 

usage is quantified. 

(iv) An explanation of how company 

records are used to quantify fossil fuel 

consumption in units that uses CEMS to 

quantify CO2 emissions and combusts 

both fossil fuel and biomass. 

(v) An explanation of how company 

records are used to measure steam 

production, when it is used to calculate 

CO2 mass emissions under 

§ 98.33(a)(2)(iii) or to quantify solid fuel 

usage under § 98.33(c)(3). 

(4) Within 30 days of receipt of a 

written request from the Administrator, 

you shall submit the verification data 

and information described in 

paragraphs (e)(2)(iii), (e)(2)(v), and 

(e)(2)(vii) of this section. 

§ 98.37 Records that must be retained. 

In addition to the requirements of 

§ 98.3(g), you must retain the applicable 

records specified in §§ 98.34(f) and (g), 

98.35(b), and 98.36(e). 

§ 98.38 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE C–1 TO SUBPART C OF PART 98—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS

TYPES OF FUEL

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 

Subbituminous ................................................................................................................................................ 17.25 97.02 

Lignite ............................................................................................................................................................. 14.21 96.36 

Coke ................................................................................................................................................................ 24.80 102.04 

Mixed (Commercial sector) ............................................................................................................................. 21.39 95.26 

Mixed (Industrial coking) ................................................................................................................................. 26.28 93.65 

Mixed (Industrial sector) ................................................................................................................................. 22.35 93.91 

Mixed (Electric Power sector) ......................................................................................................................... 19.73 94.38 

Natural gas mmBtu/scf kg CO2/mmBtu 

Pipeline (Weighted U.S. Average) .................................................................................................................. 1.028 × 10¥3 53.02 

Petroleum products mmBtu/gallon kg CO2/mmBtu 

Distillate Fuel Oil No. 1 ................................................................................................................................... 0.139 73.25 

Distillate Fuel Oil No. 2 ................................................................................................................................... 0.138 73.96 

Distillate Fuel Oil No. 4 ................................................................................................................................... 0.146 75.04 

Residual Fuel Oil No. 5 .................................................................................................................................. 0.140 72.93 

Residual Fuel Oil No. 6 .................................................................................................................................. 0.150 75.10 

Still Gas .......................................................................................................................................................... 0.143 66.72 

Kerosene ......................................................................................................................................................... 0.135 75.20 

Liquefied petroleum gases (LPG) ................................................................................................................... 0.092 62.98 

Propane .......................................................................................................................................................... 0.091 61.46 

Propylene ........................................................................................................................................................ 0.091 65.95 

Ethane ............................................................................................................................................................. 0.096 62.64 

Ethylene .......................................................................................................................................................... 0.100 67.43 

Isobutane ........................................................................................................................................................ 0.097 64.91 

Isobutylene ...................................................................................................................................................... 0.103 67.74 

Butane ............................................................................................................................................................. 0.101 65.15 

Butylene .......................................................................................................................................................... 0.103 67.73 

Naphtha (<401 deg F) .................................................................................................................................... 0.125 68.02 

Natural Gasoline ............................................................................................................................................. 0.110 66.83 

Other Oil (>401 deg F) ................................................................................................................................... 0.139 76.22 

Pentanes Plus ................................................................................................................................................. 0.110 70.02 

Petrochemical Feedstocks .............................................................................................................................. 0.129 70.97 


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TABLE C–1 TO SUBPART C OF PART 98—DEFAULT CO2 EMISSION FACTORS AND HIGH HEAT VALUES FOR VARIOUS

TYPES OF FUEL—Continued 

Fuel type Default high 

heat value 

Default CO2

emission factor 

Petroleum Coke .............................................................................................................................................. 0.143 102.41 

Special Naphtha ............................................................................................................................................. 0.125 72.34 

Unfinished Oils ................................................................................................................................................ 0.139 74.49 

Heavy Gas Oils ............................................................................................................................................... 0.148 74.92 

Lubricants ....................................................................................................................................................... 0.144 74.27 

Motor Gasoline ............................................................................................................................................... 0.125 70.22 

Aviation Gasoline ............................................................................................................................................ 0.120 69.25 

Kerosene-Type Jet Fuel ................................................................................................................................. 0.135 72.22 

Asphalt and Road Oil ..................................................................................................................................... 0.158 75.36 

Crude Oil ......................................................................................................................................................... 0.138 74.49 

Fossil fuel-derived fuels (solid) mmBtu/short ton kg CO2/mmBtu 

Municipal Solid Waste 1 .................................................................................................................................. 9.95 90.7 

Tires ................................................................................................................................................................ 26.87 85.97 

Fossil fuel-derived fuels (gaseous) mmBtu/scf kg CO2/mmBtu 

Blast Furnace Gas .......................................................................................................................................... 0.092 × 10¥3 274.32 

Coke Oven Gas .............................................................................................................................................. 0.599 × 10¥3 46.85 

Biomass fuels—solid mmBtu/short ton kg CO2/mmBtu 

Wood and Wood Residuals ............................................................................................................................ 15.38 93.80 

Agricultural Byproducts ................................................................................................................................... 8.25 118.17 

Peat ................................................................................................................................................................. 8.00 111.84 

Solid Byproducts ............................................................................................................................................. 25.83 105.51 

Biomass fuels—gaseous mmBtu/scf kg CO2/mmBtu 

Biogas (Captured methane) ........................................................................................................................... 0.841 × 10¥3 52.07 

Biomass Fuels—Liquid ................................................................................................................................... mmBtu/gallon kg CO2/mmBtu 

Ethanol (100%) ............................................................................................................................................... 0.084 68.44 

Biodiesel (100%) ............................................................................................................................................. 0.128 73.84 

Rendered Animal Fat ...................................................................................................................................... 0.125 71.06 

Vegetable Oil .................................................................................................................................................. 0.120 81.55 

1Allowed only for units that do not generate steam and use Tier 1. 

TABLE C–2 TO SUBPART C OF PART 98—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Coal and Coke (All fuel types in Table C–1) .................................................................................................... 1.1 × 10¥2 1.6 × 10¥03

Natural Gas ........................................................................................................................................................ 1.0 × 10¥03 1.0 × 10¥04

Petroleum (All fuel types in Table C–1) ............................................................................................................ 3.0 × 10¥03 6.0 × 10¥04

Municipal Solid Waste ....................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Tires ................................................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Blast Furnace Gas ............................................................................................................................................. 2.2 × 10¥05 1.0 × 10¥04

Coke Oven Gas ................................................................................................................................................. 4.8 × 10¥04 1.0 × 10¥04

Biomass Fuels—Solid (All fuel types in Table C–1) ......................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Biogas ................................................................................................................................................................ 3.2 × 10¥03 6.3 × 10¥04

Biomass Fuels—Liquid (All fuel types in Table C–1) ........................................................................................ 1.1 × 10¥03 1.1 × 10¥04

Note: Those employing this table are assumed to fall under the IPCC definitions of the ‘‘Energy Industry’’ or ‘‘Manufacturing Industries and 

Construction’’. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC 

‘‘Energy Industry’’ category may employ a value of 1g of CH4/MMBtu. 1Allowed only for units that do not generate steam and use Tier 1. 

TABLE C–2 TO SUBPART C—DEFAULT CH4 AND N2O EMISSION FACTORS FOR VARIOUS TYPES OF FUEL

Fuel type 

Default CH4

emission factor 

(kg CH4/mmBtu) 

Default N2O 

emission factor 

(kg N2O/mmBtu) 

Coal and Coke (All fuel types in Table C–1) .................................................................................................... 1.1 × 10¥2 1.6 × 10¥03

Natural Gas ........................................................................................................................................................ 1.0 × 10¥03 1.0 × 10¥04


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TABLE C–2 TO 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 (All fuel types in Table C–1) ............................................................................................................ 3.0 × 10¥03 6.0 × 10¥04

Municipal Solid Waste ....................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Tires ................................................................................................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Blast Furnace Gas ............................................................................................................................................. 2.2 × 10¥05 1.0 × 10¥04

Coke Oven Gas ................................................................................................................................................. 4.8 × 10¥04 1.0 × 10¥04

Biomass Fuels—Solid (All fuel types in Table C–1) ......................................................................................... 3.2 × 10¥02 4.2 × 10¥03

Biogas ................................................................................................................................................................ 3.2 × 10¥03 6.3 × 10¥04

Biomass Fuels—Liquid (All fuel types in Table C–1) ........................................................................................ 1.1 × 10¥03 1.1 × 10¥04

Note: Those employing this table are assumed to fall under the IPCC definitions of the ‘‘Energy Industry’’ or ‘‘Manufacturing Industries and 

Construction’’. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC 

‘‘Energy Industry’’ category may employ a value of 1 g of CH4/MMBtu. 

Subpart D—Electricity Generation 

§ 98.40 Definition of the source category. 

(a) The electricity generation source 

category comprises electricity 

generating units that are subject to the 

requirements of the Acid Rain Program 

and any other electricity generating 

units that are required to monitor and 

report to EPA CO2 emissions year-round 

according to 40 CFR part 75. 

(b) This source category does not 

include portable equipment, emergency 

equipment, or emergency generators, as 

defined in § 98.6. 

§ 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 § 98.2(a)(1). 

§ 98.42 GHGs to report. 

(a) For each electricity generating unit 

that is subject to the requirements of the 

Acid Rain Program or is otherwise 

required to monitor and report to EPA 

CO2 emissions year-round according to 

40 CFR part 75, you must report under 

this subpart the annual mass emissions 

of CO2, N2O, and CH4 by following the 

requirements of this subpart. 

(b) For each electricity generating unit 

that is not subject to the Acid Rain 

Program or otherwise required to 

monitor and report to EPA CO2

emissions year-round according to 40 

CFR part 75, you must report under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) 

the emissions of CO2, CH4, and N2O by 

following the requirements of subpart C. 

(c) For each stationary fuel 

combustion unit that does not generate 

electricity, you must report under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) 

the emissions of CO2, CH4, and N2O by 

following the requirements of subpart C 

of this part. 

§ 98.43 Calculating GHG emissions. 

Continue to monitor and report CO2

mass emissions as required under 

§ 75.13 or section 2.3 of apppendix G to 

40 CFR part 75, and § 75.64. Calculate 

CO2, CH4, and N2O emissions as 

follows: 

(a) Convert the cumulative annual 

CO2 mass emissions reported in the 

fourth quarter electronic data report 

required under § 75.64 from units of 

short tons to metric tons. To convert 

tons to metric tons, divide by 1.1023. 

(b) Calculate and report annual CH4

and N2O mass emissions under this 

subpart by following the applicable 

method specified in § 98.33(c). 

§ 98.44 Monitoring and QA/QC 

requirements. 

Follow the applicable quality 

assurance procedures for CO2 emissions 

in appendices B, D, and G to 40 CFR 

part 75. 

§ 98.45 Procedures for estimating missing 

data. 

Follow the applicable missing data 

substitution procedures in 40 CFR part 

75 for CO2 concentration, stack gas flow 

rate, fuel flow rate, high heating value, 

and fuel carbon content. 

§ 98.46 Data reporting requirements. 

The annual report shall comply with 

the data reporting requirements 

specified in § 98.36(b) and, if applicable, 

§ 98.36(c)(2) or (c)(3). 

§ 98.47 Records that must be retained. 

You shall comply with the 

recordkeeping requirements of 

§§ 98.3(g) and 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 at the facility level. 

(b) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit following the 

requirements of subpart C. 

§ 98.53 Calculating GHG emissions. 

(a) You must determine annual N2O 

emissions from adipic acid production 

according to paragraphs (a)(1) or (a)(2) 

of this section. 

(1) Use a site-specific emission factor 

and production data according to 

paragraphs (b) through (h) of this 

section. 

(2) Request Administrator approval 

for an alternative method of determining 

N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section. 

(i) You must submit the request 

within 45 days following promulgation 

of this subpart or within the first 30 

days of each subsequent reporting year. 

(ii) If the Administrator does not 

approve your requested alternative 

method within 150 days of the end of 

the reporting year, you must determine 

the N2O emissions factor for the current 

reporting period using the procedures 

specified in paragraphs (b) through (h) 

of this section. 

(b) You must conduct an annual 

performance test according to 


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56412 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

paragraphs (b)(1) through (b)(3) of this 

section. 

(1) You must conduct the test on the 

waste gas stream from the nitric acid 

oxidation step of the process using the 

methods specified in § 98.54(b) through 

(d). 

(2) You must conduct the 

performance test under normal process 

operating conditions and without using 

N2O abatement technology. 

(3) You must measure the adipic acid 

production rate during the test and 

calculate the production rate for the test 

period in metric tons per hour. 

(c) You must determine an N2O 

emissions factor to use in Equation E– 

2 of this section according to paragraphs 

(c)(1) or (c)(2) of this section. 

(1) You may request Administrator 

approval for an alternative method of 

determining N2O concentration 

according to the procedures in 

paragraphs (a)(2)(i) and (a)(2)(ii) of this 

section. Alternative methods include 

the use of N2O CEMs. 

(2) Using the results of the 

performance test in paragraph (b) of this 

section, you must calculate a facilityspecific emissions 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 generated/ton 

adipic acid produced). 

CN2O = N2O concentration per text run during 

the performance test (ppm N2O). 

1.14 × 10¥7 = Conversion factor (lb/dscf-ppm 

N2O). 

Q = Volumetric flow rate of effluent gas per 

test run during the performance test 

(dscf/hr). 

P = Production rate per test run during the 

performance test (tons adipic acid 

produced/hr). 

n = Number of test runs. 

(d) If applicable, you must determine 

the destruction efficiency for each N2O 

abatement technology used at your 

facility according to paragraphs (d)(1), 

(d)(2), or (d)(3) of this section. 

(1) Use the manufacturer’s specified 

destruction efficiency. 

(2) Estimate the destruction efficiency 

through process knowledge. Examples 

of information that could constitute 

process knowledge include calculations 

based on material balances, process 

stoichiometry, or previous test results 

provided the results are still relevant to 

the current vent stream conditions. You 

must document how process knowledge 

was used to determine the destruction 

efficiency. 

(3) Calculate the destruction 

efficiency by conducting an additional 

performance test on the emissions 

stream following the N2O abatement 

technology. 

(e) If applicable, you must determine 

the abatement factor for each N2O 

abatement technology used at your 

facility. The abatement factor is 

calculated for each adipic acid facility 

according to Equation E–2 of this 

section. 

AF =

P N

a Abate

a

P (Eq. E-2)

Where: 

AFN = Abatement factor of N2O abatement 

technology (fraction of annual 

production that abatement technology is 

operating). 

Pa Abate = Annual adipic acid production 

during which N2O abatement was used. 

Pa = Total annual adipic acid production (ton 

acid produced). 

(f) You must determine the annual 

amount of adipic acid produced and the 

annual adipic acid production during 

which N2O abatement is operating. 

(g) You must calculate annual adipic 

acid production process emissions of 

N2O by multiplying the emissions factor 

(determined using Equation E–1 of this 

section) by the total annual adipic acid 

production and accounting for N2O 

abatement, according to Equation E–3 of 

this section: 

N O

EF P DF AF NO a N N

N

2 = (Eq. E-3) ∗ ∗− ∗ ( ) ( ) ∑ 2

1

1

2205

Where: 

N2O = Annual N2O mass emissions from 

adipic acid production (metric tons). 

EFN2O = Facility-specific N2O emissions 

factor (lb N2O generated/ton adipic acid 

produced). 

Pa = Annual adipic acid produced (tons). 

DFN = Destruction efficiency of N2O 

abatement technology N (abatement 

device destruction efficiency, percent of 

N2O removed from air stream). 

AFN = Abatement factor of N2O abatement 

technology N (fraction of annual 

production abatement technology is 

operating). 

2205 = Conversion factor (lb/metric ton). 

N = Number of different N2O abatement 

technologies. 

(h) You must determine the amount of 

process N2O emissions that is sold or 

transferred off site (if applicable). You 

can determine the amount using 

existing process flow meters and N2O 

analyzers. 

§ 98.54 Monitoring and QA/QC 

requirements. 

(a) You must conduct a new 

performance test and calculate a new 

facility-specific emissions factor 

according to the frequency specified in 

paragraphs (a)(1) through (a)(3) of this 

section. 

(1) Conduct the performance test 

annually. 

(2) Conduct the performance test 

when your adipic acid production 

process is changed either by altering the 

ratio of cyclohexanone to cyclohexanol 

or by installing abatement equipment. 

(3) If you requested Administrator 

approval for an alternative method of 

determining N2O concentration under 

§ 98.53(a)(2), you must conduct the 

performance test if your request has not 

been approved by the Administrator 

within 150 days of the end of the 

reporting year in which it was 

submitted. 

(b) You must measure the N2O 

concentration during the performance 

test using one of the methods in 

paragraphs (b)(1) through (b)(3) of this 

section. 

(1) EPA Method 320, Measurement of 

Vapor Phase Organic and Inorganic 

Emissions by Extractive Fourier 


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Transform Infrared (FTIR) Spectroscopy 

in 40 CFR part 63, Appendix A; 

(2) ASTM D6348–03 Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy (incorporated by 

reference, see § 98.7); or 

(3) An equivalent method, with 

Administrator approval. 

(c) You must determine the 

production rate(s) during the 

performance test according to paragraph 

(c)(1) or (c)(2) of this section. 

(1) Direct measurement (such as using 

flow meters or weigh scales). 

(2) Existing plant procedures used for 

accounting purposes. 

(d) You must conduct all required 

performance tests according to the 

methods in § 98.54(b) in conjunction 

with the applicable EPA methods in 40 

CFR part 60, appendices A–1 through 

A–4. Conduct three emissions test runs 

of 1 hour each. All QA/QC procedures 

specified in the reference test methods 

and any associated performance 

specifications apply. For each test, the 

facility must prepare an emissions factor 

determination report that must include 

the items in paragraphs (d)(1) through 

(d)(3) of this section: 

(1) Analysis of samples, 

determination of emissions, and raw 

data. 

(2) All information and data used to 

derive the emissions factor. 

(3) The production rate(s) during the 

performance test and how each 

production rate was determined. 

(e) You must determine the monthly 

adipic acid production quantity and the 

monthly adipic acid production during 

which N2O abatement technology is 

operating according to the methods in 

paragraphs (c)(1) or (c)(2) of this section. 

(f) You must determine the annual 

adipic acid production quantity and the 

annual adipic production quantity 

during which N2O abatement 

technology is operating by summing the 

respective monthly adipic acid 

production quantities. 

§ 98.55 Procedures for estimating missing 

data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable, a 

substitute data value for the missing 

parameter shall be used in the 

calculations as specified in paragraphs 

(a) and (b) of this section. 

(a) For each missing value of monthly 

adipic acid production, the substitute 

data shall be the best available estimate 

based on all available process data or 

data used for accounting purposes (such 

as sales records). 

(b) For missing values related to the 

performance test, including emission 

factors, production rate, and N2O 

concentration, you must conduct a new 

performance test according to the 

procedures in § 98.54 (a) through (d). 

§ 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 (k) of this 

section at the facility level: 

(a) Annual process N2O emissions 

from adipic acid production (metric 

tons). 

(b) Annual adipic acid production 

(tons). 

(c) Annual adipic acid production 

during which N2O abatement 

technology is operating (tons). 

(d) Annual process N2O emissions 

from adipic acid production facility that 

is sold or transferred off site (metric 

tons). 

(e) Number of abatement technologies 

(if applicable). 

(f) Types of abatement technologies 

used (if applicable). 

(g) Abatement technology destruction 

efficiency for each abatement 

technology (percent destruction). 

(h) Abatement utilization factor for 

each abatement technology (fraction of 

annual production that abatement 

technology is operating). 

(i) Number of times in the reporting 

year that missing data procedures were 

followed to measure adipic acid 

production (months). 

(j) If you conducted a performance 

test and calculated a site-specific 

emissions factor according to 

§ 98.53(a)(1), each annual report must 

also contain the information specified in 

paragraphs (j)(1) through (j)(7) of this 

section for each adipic acid production 

facility. 

(1) Emissions factor (lb N2O/ton 

adipic acid). 

(2) Test method used for performance 

test. 

(3) Production rate per test run during 

performance test (tons/hr). 

(4) N2O concentration per test run 

during performance test (ppm N2O). 

(5) Volumetric flow rate per test run 

during performance test (dscf/hr). 

(6) Number of test runs. 

(7) Number of times in the reporting 

year that a performance test had to be 

repeated (number). 

(k) If you requested Administrator 

approval for an alternative method of 

determining N2O concentration under 

§ 98.53(a)(2), each annual report must 

also contain the information specified in 

paragraphs (k)(1) through (k)(4) of this 

section for each adipic acid production 

facility. 

(1) Name of alternative method. 

(2) Description of alternative method. 

(3) Request date. 

(4) Approval date. 

§ 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 (h) of this section at the facility 

level: 

(a) Annual adipic acid production 

capacity (tons). 

(b) Records of significant changes to 

process. 

(c) Number of facility operating hours 

in calendar year. 

(d) Documentation of how accounting 

procedures were used to estimate 

production rate. 

(e) Documentation of how process 

knowledge was used to estimate 

abatement technology destruction 

efficiency. 

(f) Performance test reports of N2O 

emissions. 

(g) Measurements, records and 

calculations used to determine reported 

parameters. 

(h) Documentation of the procedures 

used to ensure the accuracy of the 

measurements of all reported 

parameters, including but not limited to, 

calibration of weighing equipment, flow 

meters, and other measurement devices. 

The estimated accuracy of 

measurements made with these devices 

must also be recorded, and the technical 

basis for these estimates must be 

provided. 

§ 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 


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56414 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

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

(a)(2). 

§ 98.62 GHGs to report. 

You must report: 

(a) Perfluoromethane (CF4), and 

perfluoroethane (C2F6) emissions from 

anode effects in all prebake and 

S<derberg electolysis cells. 

(b) CO2 emissions from anode 

consumption during electrolysis in all 

prebake and S<derberg electolysis cells. 

(c) CO2 emissions from on-site anode 

baking. 

(d) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, N2O, and CH4 emissions from each 

stationary fuel combustion unit by 

following the requirements of subpart C. 

§ 98.63 Calculating GHG emissions. 

(a) The annual value for PFC 

emissions shall be estimated from the 

sum of monthly values using Equation 

F–1 of this section: 

E E PFC m =

=

=

∑

m

m

1

12

(Eq. F-1)

Where: 

EPFC = Annual PFC emissions from 

aluminum production (metric tons PFC). 

Em = PFC emissions from aluminum 

production for the month ‘‘m’’ (metric 

tons PFC). 

(b) Use Equation F–2 of this section to 

estimate CF4 emissions from anode 

effect duration or Equation F–3 of this 

section to estimate CF4 emissions from 

overvoltage, and use Equation F–4 of 

this section to estimate C2F6 emissions 

from anode effects from each prebake 

and S<derberg electolysis cell. 

ECF CF 4 4 S AEM MP (Eq. F-2) = × ×× 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. 

ECF CF 4 4 EF MP (Eq. F-3) = ×× 0 001 .

Where: 

ECF4 = Monthly CF4 emissions from 

aluminum production (metric tons CF4). 

EFCF4 = The overvoltage emission factor (kg 

CF4/metric ton Al). 

MP = Metal production (metric tons Al), 

where MP is calculated monthly. 

E EF C F CF C F CF 26 4 26 4 (Eq. F-4) =× × 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. 

(c) You must calculate and report the 

annual process CO2 emissions from 

anode consumption during electrolysis 

and anode baking of prebake cells using 

either the procedures in paragraph (d) of 

this section or the procedures in 

paragraphs (e) and (f) of this section. 

(d) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(e) Use the following procedures to 

calculate CO2 emissions from anode 

consumption during electrolysis: 

(1) For Prebake cells: you must 

calculate CO2 emissions from anode 

consumption using Equation F–5 of this 

section: 

E NAC MP S Ash CO a a 2 = × × −− (Eq. F-5) ( ) [ ] 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 = 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–6 of this section: 

E PC MP CSM 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-6)

−× × MP CD


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56415 

Where: 

ECO2 = Annual CO2 emissions from paste 

consumption (metric ton CO2). 

PC = Annual paste consumption (metric ton/ 

metric ton Al). 

MP = Annual metal production (metric ton 

Al). 

CSM = Annual emissions of cyclohexane 

soluble matter (kg/metric ton Al). 

BC = Binder content of paste (percent 

weight). 

Sp = Sulfur content of pitch (percent weight). 

Ashp = Ash content of pitch (percent weight). 

Hp = Hydrogen content of pitch (percent 

weight). 

Sc = Sulfur content in calcined coke (percent 

weight). 

Ashc = Ash content in calcined coke (percent 

weight). 

CD = Carbon in skimmed dust from 

S<derberg cells (metric ton C/metric ton 

Al). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(f) Use the following procedures to 

calculate CO2 emissions from anode 

baking of prebake cells: 

(1) Use Equation F–7 of this section to 

calculate emissions from pitch volatiles 

combustion. 

E GA H BA WT CO PV w 2 = −−− (Eq. F-7) ( ) × ( /) 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–8 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-8)

Where: 

ECO2PC = Annual CO2 emissions from bake 

furnace packing material (metric tons 

CO2). 

PCC = Annual packing coke consumption 

(metric tons/metric ton baked anode). 

BA = Annual baked anode production 

(metric tons). 

Spc = Sulfur content in packing coke (percent 

weight). 

Ashpc = Ash content in packing coke (percent 

weight). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(g) If process CO2 emissions from 

anode consumption during electrolysis 

or anode baking of prebake cells are 

vented through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraphs 

(d) and (e) of this section shall not be 

used to calculate those process 

emissions. The owner or operation shall 

report under this subpart the combined 

stack emissions according to the Tier 4 

Calculation Methodology in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

§ 98.64 Monitoring and QA/QC 

requirements. 

(a) Effective one year after publication 

of the rule for smelters with no prior 

measurement or effective three years 

after publication for facilities with 

historic measurements, the smelterspecific slope coefficients used in 

Equations F–2, F–3, and F–4 of this 

subpart must be measured in 

accordance with the recommendations 

of the EPA/IAI Protocol for 

Measurement of Tetrafluoromethane 

(CF4) and Hexafluoroethane (C2F6) 

Emissions from Primary Aluminum 

Production (2008), except the minimum 

frequency of measurement shall be 

every 10 years unless a change occurs in 

the control algorithm that affects the 

mix of types of anode effects or the 

nature of the anode effect termination 

routine. Facilities which operate at less 

than 0.2 anode effect minutes per cell 

day or operate with less than 1.4mV 

anode effect overvoltage can use either 

smelter-specific slope coefficients or the 

technology specific default values in 

Table F–1 of this subpart. 

(b) The minimum frequency of the 

measurement and analysis is annually 

except as follows: Monthly—anode 

effect minutes per cell day (or anode 

effect overvoltage and current 

efficiency), production. 

(c) Sources may use either smelterspecific values from annual 

measurements of parameters needed to 

complete the equations in § 98.63 (e.g., 

sulfur, ash, and hydrogen contents) or 

the default values shown in Table F–2 

of this subpart. 

§ 98.65 Procedures for estimating missing 

data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions during unit 

operation or if a required sample 

measurement is not taken), a substitute 

data value for the missing parameter 

shall be used in the calculations, 

according to the following requirements: 

(a) Where anode or paste 

consumption data are missing, CO2

emissions can be estimated from 

aluminum production using Tier 1 

method per Equation F–8 of this section. 

ECO EF x MP EF x MP 2 = + ppss (Eq. F-8)

Where: 

ECO2 = CO2 emissions from anode and/or 

paste consumption, metric tons CO2. 

EFp = Prebake technology specific emission 

factor (1.6 metric tons CO2/metric ton 

aluminum produced). 

MPp = Metal production from prebake 

process (metric tons Al). 

EFs = S<derberg technology specific emission 

factor (1.7 metric tons CO2/metric ton Al 

produced). 

MPs = Metal production from S<derberg 

process (metric tons Al). 


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(b) For other parameters, use the 

average of the two most recent data 

points after the missing data. 

§ 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 

(AE-mins/cell-day), anode effect 

frequency (AE/cell-day), anode effect 

duration (minutes). (Or anode effect 

overvoltage factor ((kg CF4/metric ton 

Al)/(mV/cell day)), potline overvoltage 

(mV/cell day), current efficiency (%).) 

(3) Smelter-specific slope coefficients 

(or overvoltage emission factors) and the 

last date when the smelter-specificslope coefficients (or overvoltage 

emission factors) were measured. 

(d) Method used to measure the 

frequency and duration of anode effects 

(or overvoltage). 

(e) The following CO2-specific 

information for prebake cells: 

(1) Annual anode consumption. 

(2) Annual CO2 emissions from the 

smelter. 

(f) The following CO2-specific 

information for S<derberg cells: 

(1) Annual paste consumption. 

(2) Annual CO2 emissions from the 

smelter. 

(g) Smelter-specific inputs to the CO2

process equations (e.g., levels of sulfur 

and ash) that were used in the 

calculation, on an annual basis. 

(h) Exact data elements required will 

vary depending on smelter technology 

(e.g., point-feed prebake or S<derberg) 

and process control technology (e.g., 

Pechiney or other). 

§ 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 prebake and S<derberg 

electolysis cells. 

(2) Anode effect minutes per cell-day 

(AE-mins/cell-day), anode effect 

frequency (AE/cell-day), anode effect 

duration (minutes). (Or anode effect 

overvoltage factor ((kg CF4/metric ton 

Al)/(mV/cell day)), potline overvoltage 

(mV/cell day), current efficiency (%).)) 

(3) Smelter-specific slope coefficients 

and the last date when the smelterspecific-slope coefficients were 

measured. 

(d) Method used to measure the 

frequency and duration of anode effects 

(or to measure anode effect overvoltage 

and current efficiency). 

(e) The following CO2-specific 

information for prebake cells: 

(1) Annual anode consumption. 

(2) Annual CO2 emissions from the 

smelter. 

(f) The following CO2-specific 

information for S<derberg cells: 

(1) Annual paste consumption. 

(2) Annual CO2 emissions from the 

smelter. 

(g) Smelter-specific inputs to the CO2

process equations (e.g., levels of sulfur 

and ash) that were used in the 

calculation, on an annual basis. 

(h) Exact data elements required will 

vary depending on smelter technology 

(e.g., point-feed prebake or S<derberg) 

and process control technology (e.g., 

Pechiney or other). 

§ 98.68 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE F–1 TO SUBPART F OF PART 98—SLOPE AND OVERVOLTAGE COEFFICIENTS FOR THE CALCULATION OF PFC 

EMISSIONS FROM ALUMINUM PRODUCTION

Technology 

CF4 slope 

coefficient 

[(kg CF4/metric 

ton Al)/(AEMins/cell-day)] 

CF4 overvoltage 

coefficient 

[(kg CF4/metric 

ton Al)/(mV)] 

Weight fraction 

C2F6/CF4

[(kg C2F6/ 

kg CF4)] 

CWPB .......................................................................................................................................... 0.143 1.16 0.121 

SWPB .......................................................................................................................................... 0.272 3.65 0.252 

VSS .............................................................................................................................................. 0.092 NA 0.053 

HSS .............................................................................................................................................. 0.099 NA 0.085 

TABLE F–2 TO SUBPART F OF PART 98—DEFAULT DATA SOURCES FOR PARAMETERS USED FOR CO2 EMISSIONS

Parameter Data source 

CO2 Emissions from Prebake Cells (CWPB and SWPB) 

MP: metal production (metric tons Al) ............................................................................................................................ Individual facility records. 

NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) ................................ Individual facility records. 

Sa: sulfur content in baked anode (percent weight) ....................................................................................................... 2.0. 

Asha: ash content in baked anode (percent weight) ...................................................................................................... 0.4. 

CO2 Emissions from S<derberg Cells (VSS and HSS) 

MP: metal production (metric tons Al) ............................................................................................................................ Individual facility records. 

PC: annual paste consumption (metric ton/metric ton Al) ............................................................................................. Individual facility records. 

CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) .................................................................... HSS: 4.0. 

VSS: 0.5. 

BC: binder content of paste (percent weight) ................................................................................................................ Dry Paste: 24. 

Wet Paste: 27. 

Sp: sulfur content of pitch (percent weight) .................................................................................................................... 0.6. 

Ashp: ash content of pitch (percent weight) ................................................................................................................... 0.2. 


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TABLE F–2 TO SUBPART F OF PART 98—DEFAULT DATA SOURCES FOR PARAMETERS USED FOR CO2 EMISSIONS— 

Continued 

Parameter Data source 

Hp: hydrogen content of pitch (percent weight) .............................................................................................................. 3.3. 

Sc: sulfur content in calcined coke (percent weight) ...................................................................................................... 1.9. 

Ashc: ash content in calcined coke (percent weight) ..................................................................................................... 0.2. 

CD: carbon in skimmed dust from S<derberg cells (metric ton C/metric ton Al) ........................................................... 0.01. 

CO2 Emissions from Pitch Volatiles Combustion (VSS and HSS) 

GA: initial weight of green anodes (metric tons) ............................................................................................................ Individual facility records. 

Hw: annual hydrogen content in green anodes (metric tons) ........................................................................................ 0.005 × GA. 

BA: annual baked anode production (metric tons) ......................................................................................................... Individual facility records. 

WT: annual waste tar collected (metric tons) ................................................................................................................. (a) 0.005 × GA. 

(a) Riedhammer furnaces ............................................................................................................................................... (b) insignificant. 

(b) all other furnaces.

CO2 Emissions From Bake Furnace Packing Materials (CWPB and SWPB) 

PCC: annual packing coke consumption (metric tons/metric ton baked anode) ........................................................... 0.015. 

BA: annual baked anode production (metric tons) ......................................................................................................... Individual facility records. 

Spc: sulfur content in packing coke (percent weight) ..................................................................................................... 2. 

Ashpc: ash content in packing coke (percent weight) ..................................................................................................... 2.5. 

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 and liquid 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) CO2 process emissions from steam 

reforming of a hydrocarbon or the 

gasification of solid and liquid raw 

material, reported for each ammonia 

manufacturing process unit following 

the requirements in this subpart. 

(b) CO2, CH4, and N2O emissions from 

each stationary fuel combustion unit. 

You must report these emissions under 

subpart C of this part (General 

Stationary Fuel Combustion Sources), 

by following the requirements of 

subpart C. 

(c) CO2 emissions collected and 

transferred off site under subpart PP of 

this part (Suppliers of CO2), following 

the requirements of subpart PP. 

§ 98.73 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

ammonia manufacturing process unit 

using the procedures in either paragraph 

(a) or (b) of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart process CO2 emissions using the 

procedures in paragraphs (b)(1) through 

(b)(6) of this section for gaseous 

feedstock, liquid feedstock, or solid 

feedstock, as applicable. 

(1) Gaseous feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from gaseous feedstock 

according to Equation G–1 of this 

section: 

CO Fdstk CC MW

MVC 2 Gk nk n

44

12

0 001 ,, , = ∗ ∗∗ . ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ ∑ ∗

n=1

12

(Eq. G-1)

Where: 

CO2,G = Annual CO2 emissions arising from 

feedstock consumption (metric tons). 

Fdstkn = Volume of the gaseous feedstock 

used in month n (scf of feedstock). 

CCn = Carbon content of the gaseous 

feedstock, for month n (kg C per kg of 

feedstock), determined according to 

98.74(c). 

MW = Molecular weight of the gaseous 

feedstock (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

k = Processing unit. 

n = Number of month. 

(2) Liquid feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from liquid feedstock 

according to Equation G–2 of this 

section: 


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CO Fdstk CC 2 Lk nk n

44

12

0 001 ,, , =∗ ∗ . ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ ∑ ∗

n=1

12

(Eq. G-2)

Where: 

CO2,L = Annual CO2 emissions arising from 

feedstock consumption (metric tons). 

Fdstkn = Volume of the liquid feedstock used 

in month n (gallons of feedstock). 

CCn = Carbon content of the liquid feedstock, 

for month n (kg C per gallon of 

feedstock) determined according to 

98.74(c). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

k = Processing unit. 

n = Number of month. 

(3) Solid feedstock. You must 

calculate, from each ammonia 

manufacturing unit, the CO2 process 

emissions from solid feedstock 

according to Equation G–3 of this 

section: 

CO Fdstk CC Sk nk n

n

2

1

12 44

12

0 001 ,, , =∗ ∗ . ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ ∗

=

∑ (Eq. G-3)

Where: 

CO2,S = Annual CO2 emissions arising from 

feedstock consumption (metric tons). 

Fdstkn = Mass of the solid feedstock used in 

month n (kg of feedstock). 

CCn = Carbon content of the solid feedstock, 

for month n (kg C per kg of feedstock), 

determined according to 98.74(c). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

k = Processing unit. 

n = Number of month. 

(4) You must calculate the annual 

process CO2 emissions from each 

ammonia processing unit k at your 

facility summing emissions, as 

applicable from Equation G–1, G–2, and 

G–3 of this section using Equation G–4. 

ECO G S L 22 2 2 k= + CO + CO CO (Eq. G-4) ,, ,

Where: 

ECO2k = Annual CO2 emissions from each 

ammonia processing unit k (metric tons). 

k = Processing unit. 

(5) You must determine the combined 

CO2 emissions from all ammonia 

processing units at your facility using 

Equation G–5 of this section. 

CO = E (Eq. G-5) 2 CO2

k=1

n

∑ k

Where: 

CO2 = Annual combined CO2 emissions from 

all ammonia processing units (metric 

tons). 

ECO2k = Annual CO2 emissions from each 

ammonia processing unit (metric tons). 

k = Processing unit. 

n = Total number of ammonia processing 

units. 

(6) If applicable, ammonia 

manufacturing facilities that utilize the 

waste recycle stream as a fuel must 

calculate emissions associated with the 

waste stream for each ammonia process 

unit according to Equation G–6 of this 

section: 

CO cycleStream CC MW

MVC 2 n n

44

12 = ∗ ∗∗ 0 001 ⎛

⎝

⎜

⎜

⎞

⎠

⎟ ∑ ⎟ Re .

n=1

12

(Eq. G-6)

Where: 

CO2 = Annual CO2 contained in waste 

recycle stream (metric tons). 

RecycleStreamn = Volume of the waste 

recycle stream in month n (scf). 

CCn = Carbon content of the waste recycle 

stream, for month n (kg C per kg of waste 

recycle stream) determined according to 

98.74(f). 

MW = Molecular weight of the waste recycle 

stream (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

n = Number of month 

(c) If GHG emissions from an 

ammonia manufacturing unit are vented 

through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraph 

(b) of this section shall not be used to 

calculate process emissions. The owner 

or operator shall report under this 

subpart the combined stack emissions 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part. 

§ 98.74 Monitoring and QA/QC 

requirements. 

(a) You must continuously measure 

the quantity of gaseous or liquid 

feedstock consumed using a flow meter. 

The quantity of solid feedstock 

consumed can be obtained from 

company records and aggregated on a 

monthly basis. 

(b) You must document the 

procedures used to ensure the accuracy 

of the estimates of feedstock 

consumption. 

(c) You must determine monthly 

carbon contents and the average 

molecular weight of each feedstock 

consumed from reports from your 

supplier. As an alternative to using 

supplier information on carbon 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56419 

contents, you can also collect a sample 

of each feedstock on a monthly basis 

and analyze the carbon content and 

molecular weight of the fuel using any 

of the following methods listed in 

paragraphs (c)(1) through (c)(8) of this 

section, as applicable. 

(1) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(2) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(3) ASTM D2502–04 (Reapproved 

2002) Standard Test Method for 

Estimation of Mean Relative Molecular 

Mass of Petroleum Oils from Viscosity 

Measurements (incorporated by 

reference, see § 98.7). 

(4) ASTM D2503–92 (Reapproved 

2007) Standard Test Method for Relative 

Molecular Mass (Molecular Weight) of 

Hydrocarbons by Thermoelectric 

Measurement of Vapor Pressure 

(incorporated by reference, see § 98.7). 

(5) ASTM D3238–95 (Reapproved 

2005) Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method (incorporated 

by reference, see § 98.7). 

(6) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants (incorporated 

by reference, see § 98.7). 

(7) ASTM D3176–89 (Reapproved 

2002) Standard Practice for Ultimate 

Analysis of Coal and Coke (incorporated 

by reference, see § 98.7). 

(8) ASTM D5373–08 Standard 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 

(d) Calibrate all oil and gas flow 

meters (except for gas billing meters) 

and perform oil tank measurements 

according to the monitoring and QA/QC 

requirements for the Tier 3 methodology 

in § 98.34(b). 

(e) For quality assurance and quality 

control of the supplier data, on an 

annual basis, you must measure the 

carbon contents of a representative 

sample of the feedstocks consumed 

using the appropriate ASTM Method as 

listed in paragraphs (c)(1) through (c)(8) 

of this section. 

(f) Facilities must continuously 

measure the quantity of waste gas 

recycled using a flow meter, as 

applicable. You must determine the 

carbon content and the molecular 

weight of the waste recycle stream by 

collecting a sample of each waste 

recycle stream on a monthly basis and 

analyzing the carbon content using the 

appropriate ASTM Method as listed in 

paragraphs (c)(1) through (c)(8) of this 

section. 

(g) If CO2 from ammonia production 

is used to produce urea at the same 

facility, you must determine the 

quantity of urea produced using 

methods or plant instruments used for 

accounting purposes (such as sales 

records). You must document the 

procedures used to ensure the accuracy 

of the estimates of urea produced. 

§ 98.75 Procedures for estimating missing 

data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever the monitoring and quality 

assurance procedures in § 98.74 cannot 

be followed (e.g., if a meter 

malfunctions during unit operation), a 

substitute data value for the missing 

parameter shall be used in the 

calculations following paragraphs (a) 

and (b) of this section. You must 

document and keep records of the 

procedures used for all such estimates. 

(a) For missing data on monthly 

carbon contents of feedstock or the 

waste recycle stream, the substitute data 

value shall be the arithmetic average of 

the quality-assured values of that carbon 

content in the month preceding and the 

month immediately following the 

missing data incident. If no qualityassured data are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value for carbon content 

obtained in the month after the missing 

data period. 

(b) For missing feedstock supply rates 

or waste recycle stream used to 

determine monthly feedstock 

consumption or monthly waste recycle 

stream quantity, you must determine the 

best available estimate(s) of the 

parameter(s), based on all available 

process data. 

§ 98.76 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) and (b) of this section, 

as applicable for each ammonia 

manufacturing process unit. 

(a) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.37(e)(2)(vi) for the Tier 4 

Calculation Methodology and the 

following information in this paragraph 

(a): 

(1) Annual quantity of each type of 

feedstock consumed for ammonia 

manufacturing (scf of feedstock or 

gallons of feedstock or kg of feedstock). 

(2) Method used for determining 

quantity of feedstock used. 

(b) If a CEMS is not used to measure 

emissions, then you must report the 

following information: 

(1) Annual CO2 process emissions 

(metric tons) for each ammonia 

manufacturing process unit. 

(2) Monthly quantity of each type of 

feedstock consumed for ammonia 

manufacturing for each ammonia 

processing unit (scf of feedstock or 

gallons of feedstock or kg of feedstock). 

(3) Method used for determining 

quantity of monthly feedstock used. 

(4) Whether carbon content for each 

feedstock for month n is based on 

reports from the supplier or analysis of 

carbon content. 

(5) If carbon content of feedstock for 

month n is based on analysis, the test 

method used. 

(6) Sampling analysis results of 

carbon content of petroleum coke as 

determined for QA/QC of supplier data 

under § 98.74(e). 

(7) If a facility uses gaseous feedstock, 

the carbon content of the gaseous 

feedstock, for month n, (kg C per kg of 

feedstock). 

(8) If a facility uses gaseous feedstock, 

the molecular weight of the gaseous 

feedstock (kg/kg-mole). 

(9) If a facility uses gaseous feedstock, 

the molar volume conversion factor of 

the gaseous feedstock (scf per kg-mole). 

(10) If a facility uses liquid feedstock, 

the carbon content of the liquid 

feedstock, for month n, (kg C per gallon 

of feedstock). 

(11) If a facility uses solid feedstock, 

the carbon content of the solid 

feedstock, for month n, (kg C per kg of 

feedstock). 

(12) Annual CO2 emissions associated 

with the waste recycle stream for each 

ammonia process unit (metric tons) 

(13) Carbon content of the waste 

recycle stream for month n for each 

ammonia process unit (kg C per kg of 

waste recycle stream). 

(14) Volume of the waste recycle 

stream for month n for each ammonia 

process unit (scf) 

(15) Method used for analyzing 

carbon content of waste recycle stream. 

(16) Annual urea production (metric 

tons) and method used to determine 

urea production. 

(17) Uses of urea produced, if known, 

such as but not limited to fertilizer, 

animal feed, manufacturing of plastics 

or resins, and pollution control 

technologies. 

(c) Total pounds of synthetic fertilizer 

produced through and total nitrogen 

contained in that fertilizer. 


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§ 98.77 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) and 

(b) of this section for each ammonia 

manufacturing unit. 

(a) If a CEMS is used to measure 

emissions, retain records of all feedstock 

purchases in addition to the 

requirements in § 98.37 for the Tier 4 

Calculation Methodology. 

(b) If a CEMS is not used to measure 

process CO2 emissions, you must also 

retain the records specified in 

paragraphs (b)(1) through (b)(2) of this 

section: 

(1) Records of all analyses and 

calculations conducted for reported data 

as listed in § 98.76(b). 

(2) Monthly records of carbon content 

of feedstock from supplier and/or all 

analyses conducted of carbon content. 

§ 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. 

You must report: 

(a) CO2 process emissions from 

calcination in each kiln. 

(b) CO2 combustion emissions from 

each kiln. 

(c) CH4 and N2O combustion 

emissions from each kiln. You must 

calculate and report these emissions 

under subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from 

each stationary combustion unit other 

than kilns. You must report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

§ 98.83 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

kiln using the procedure in paragraphs 

(a) and (b) of this section. 

(a) For each cement kiln that meets 

the conditions specified in 

§ 98.33(b)(4)(ii) or (b)(4)(iii), you must 

calculate and report under this subpart 

the combined process and combustion 

CO2 emissions by operating and 

maintaining a CEMS to measure CO2

emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(b) For each kiln that is not subject to 

the requirements in paragraph (a) of this 

section, calculate and report the process 

and combustion CO2 emissions from the 

kiln by using the procedure in either 

paragraph (c) or (d) of this section. 

(c) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 

and maintaining a CEMS to measure 

CO2 emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(d) Calculate and report process and 

combustion CO2 emissions separately 

using the procedures specified in 

paragraphs (d)(1) through (d)(4) of this 

section. 

(1) Calculate CO2 process emissions 

from all kilns at the facility using 

Equation H–1 of this section: 

CO CO CO CMF Cli,m rm

m

k

2 22

1

= +

=

∑ (Eq. H-1)

Where: 

CO2 CMF = Annual process emissions of CO2

from cement manufacturing, metric tons. 

CO2 Cli,m = Total annual emissions of CO2

from clinker production from kiln m, 

metric tons. 

CO2 rm = Total annual emissions of CO2 from 

raw materials, metric tons. 

k = Total number of kilns at a cement 

manufacturing facility. 

(2) CO2 emissions from clinker 

production. Calculate CO2 emissions 

from each kiln using Equations H–2 

through H–5 of this section. 

CO Cli, EF CKD, EF 2 Cli,m j Cli, j i CKD,i

2000

2205 = ( ) ∗( ) ∗ ⎡

⎣

⎢ ⎤

⎦

⎥ + ( ) ∗ ( ) ∗ ⎡

⎣

⎢ ⎤

⎦

⎥ = =

∑ ∑ 2000

2205 1 1

(Eq. H-2)

i

r

j

p

Where: 

Cli,j = Quantity of clinker produced in month 

j from kiln m, tons. 

EFCli,j = Kiln specific clinker emission factor 

for month j for kiln m, metric tons CO2/ 

metric ton clinker computed as specified 

in Equation H–3 of this section. 

CKD,i = Cement kiln dust (CKD) not recycled 

to the kiln in quarter i from kiln m, tons. 

EFCKD,i = Kiln specific CKD emission factor 

for quarter i from kiln m, metric tons 

CO2/metric ton CKD computed as 

specified in Equation H–4 of this section. 

p = Number of months for clinker 

calculation, 12. 

r = Number of quarters for CKD calculation, 

4. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

(i) Kiln-Specific Clinker Emission 

Factor. (A) Calculate the kiln-specific 

clinker emission factor using Equation 

H–3 of this section. 

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


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Where: 

CliCaO = Monthly total CaO content of 

Clinker, wt-fraction. 

ClincCaO = Monthly non-calcined CaO content 

of Clinker, wt-fraction. 

MRCaO = Molecular-weight Ratio of CO2/CaO 

= 0.785. 

CliMgO = Monthly total MgO content of 

Clinker, wt-fraction. 

ClincMgO = Monthly non-calcined MgO 

content of Clinker, wt-fraction. 

MRMgO = Molecular-weight Ratio of CO2/ 

MgO = 1.092. 

(B) Non-calcined CaO is CaO that 

remains in the clinker in the form of 

CaCO3 and CaO in the clinker that 

entered the kiln as a non-carbonate 

species. Non-calcined MgO is MgO that 

remains in the clinker in the form of 

MgCO3 and MgO in the clinker that 

entered the kiln as a non-carbonate 

species. 

(ii) Kiln-Specific CKD Emission 

Factor. (A) Calculate the kiln-specific 

CKD emission factor for CKD not 

recycled to the kiln using Equation H– 

4 of this section. 

EF CKD CKD MR CKD CKD MR CKD = − ( ) CaO ncCaO CaO MgO ncMgO MgO ∗+ − ( ) ∗ (Eq. H-4)

Where: 

CKDCaO = Quarterly total CaO content of CKD 

not recycled to the kiln, wt-fraction. 

CKDCaO = Quarterly non-calcined CaO 

content of CKD not recycled to the kiln, 

wt-fraction. 

MRCaO = Molecular-weight Ratio of CO2/CaO 

= 0.785. 

CKDMgO = Quarterly total MgO content of 

CKD not recycled to the kiln, wt-fraction. 

CKDMgO = Quarterly non-calcined MgO 

content of CKD not recycled to the kiln, 

wt-fraction. 

MRMgO = Molecular-weight Ratio of CO2/ 

MgO = 1.092. 

(B) Non-calcined CaO is CaO that 

remains in the CKD in the form of 

CaCO3 and CaO in the CKD that entered 

the kiln as a non-carbonate species. 

Non-calcined MgO is MgO that remains 

in the CKD in the form of MgCO3 and 

MgO in the CKD that entered the kiln as 

a non-carbonate species. 

(3) CO2 emissions from raw materials. 

Calculate CO2 emissions using Equation 

H–5 of this section: 

CO rm TOCrm rm

i

m

2

44

12

2000

2205 , = ∗ ∗∗

=

∑ (Eq. H-5)

1

Where: 

rm = The amount of raw material i consumed 

annually, tons/yr (dry basis). 

CO2,rm = Annual CO2 emissions from raw 

materials. 

TOCrm = Organic carbon content of raw 

material i (dry basis), as determined in 

§ 98.84(c) or using a default factor of 0.2 

percent of total raw material weight. 

M = Number of raw materials. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

(4) Calculate and report under subpart 

C of this part (General Stationary Fuel 

Combustion Sources) the combustion 

CO2 emissions from the kiln according 

to the applicable requirements in 

subpart C. 

§ 98.84 Monitoring and QA/QC 

requirements. 

(a) You must determine the weight 

fraction of total CaO and total MgO in 

CKD not recycled to the kiln from each 

kiln using ASTM C114–09, Standard 

Test Methods for Chemical Analysis of 

Hydraulic Cement (incoporated by 

reference, see § 98.7). The monitoring 

must be conducted quarterly for each 

kiln from a CKD sample drawn either as 

CKD is exiting the kiln or from bulk 

CKD storage. 

(b) You must determine the weight 

fraction of total CaO and total MgO in 

clinker from each kiln using ASTM 

C114–07 Standard Test Methods for 

Chemical Analysis of Hydraulic Cement 

(incorporated by reference, see § 98.7). 

The monitoring must be conducted 

monthly for each kiln from a clinker 

sample drawn from bulk clinker storage. 

(c) The total organic carbon contents 

(dry basis) of each raw material must be 

determined annually using ASTM 

C114–09 Standard Test Methods for 

Chemical Analysis of Hydraulic Cement 

(incorporated by reference, see § 98.7) or 

a similar industry standard practice or 

method approved for total organic 

carbon determination in raw mineral 

materials. The analysis must be 

conducted on sample material drawn 

from bulk raw material storage for each 

category of raw material (i.e., limestone, 

sand, shale, iron oxide, and alumina). 

Facilities that opt to use the default total 

organic carbon factor provided in 

§ 98.83(d)(3), are not required to 

monitor for TOC. 

(d) The quantity of clinker produced 

monthly by each kiln must be 

determined by direct weight 

measurement using the same plant 

instruments used for accounting 

purposes, such as weigh hoppers or belt 

weigh feeders. 

(e) The quantity of CKD not recycled 

to the kiln by each kiln must be 

determined quarterly by direct weight 

measurement using the same plant 

instruments used for accounting 

purposes, such as weigh hoppers, truck 

weigh scales, or belt weigh feeders. 

(f) The quantity of each category of 

raw materials consumed annually by the 

facility (e.g., limestone, sand, shale, iron 

oxide, and alumina) must be determined 

monthly by direct weight measurement 

using the same plant instruments used 

for accounting purposes, such as weigh 

hoppers, truck weigh scales, or belt 

weigh feeders. 

(g) The monthly non-calcined CaO 

and MgO that remains in the clinker in 

the form of CaCO3 or that enters the kiln 

as a non-carbonate species may be 

assumed to be a default value of 0.0 or 

may be determined monthly by careful 

chemical analysis of feed material and 

clinker material from each kiln using 

well documented analytical and 

calculational methods or the 

appropriate industry standard practice. 

(h) The quarterly non-calcined CaO 

and MgO that remains in the CKD in the 

form of CaCO3 or that enters the kiln as 

a non-carbonate species may be 

assumed to be a default value of 0.0 or 

may be determined quarterly by careful 

chemical analysis of feed material and 

CKD material from each kiln using well 

documented analytical and 

calculational methods or the 

appropriate industry standard practice. 

§ 98.85 Procedures for estimating missing 

data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.83 is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 


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the missing parameter shall be used in 

the calculations. The owner or operator 

must document and keep records of the 

procedures used for all such estimates. 

(a) If the CEMS approach is used to 

determine combined process and 

combustion CO2 emissions, the missing 

data procedures in § 98.35 apply. 

(b) For CO2 process emissions from 

cement manufacturing facilities 

calculated according to § 98.83(d), if 

data on the carbonate content (of clinker 

or CKD), noncalcined content (of clinker 

or CKD) or the annual organic carbon 

content of raw materials are missing, 

facilities must undertake a new analysis. 

(c) For each missing value of monthly 

clinker production the substitute data 

value must be the best available 

estimate of the monthly clinker 

production based on information used 

for accounting purposes, or use the 

maximum tons per day capacity of the 

system and the number of days per 

month. 

(d) For each missing value of monthly 

raw material consumption the substitute 

data value must be the best available 

estimate of the monthly raw material 

consumption based on information used 

for accounting purposes (such as 

purchase records), or use the maximum 

tons per day raw material throughput of 

the kiln and the number of days per 

month. 

§ 98.86 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) and (b) of this section, 

as appropriate. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required by § 98.36(e)(2)(vi) and the 

information listed in this paragraph(a): 

(1) Monthly clinker production from 

each kiln at the facility. 

(2) Monthly cement production from 

each kiln at the facility. 

(3) Number of kilns and number of 

operating kilns. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in this paragraph (b) 

for each kiln: 

(1) Kiln identification number. 

(2) Monthly clinker production from 

each kiln. 

(3) Monthly cement production from 

each kiln. 

(4) Number of kilns and number of 

operating kilns. 

(5) Quarterly quantity of CKD not 

recycled to the kiln for each kiln at the 

facility. 

(6) Monthly fraction of total CaO, total 

MgO, non-calcined CaO and noncalcined MgO in clinker for each kiln 

(as wt-fractions). 

(7) Method used to determine noncalcined CaO and non-calcined MgO in 

clinker. 

(8) Quarterly fraction of total CaO, 

total MgO, non-calcined CaO and noncalcined MgO in CKD not recycled to 

the kiln for each kiln (as wt-fractions). 

(9) Method used to determine noncalcined CaO and non-calcined MgO in 

CKD. 

(10) Monthly kiln-specific clinker CO2

emission factors for each kiln (metric 

tons CO2/metric ton clinker produced). 

(11) Quarterly kiln-specific CKD CO2

emission factors for each kiln (metric 

tons CO2/metric ton CKD produced). 

(12) Annual organic carbon content of 

each raw material (wt-fraction, dry 

basis). 

(13) Annual consumption of each raw 

material (dry basis). 

(14) Number of times missing data 

procedures were used to determine the 

following information: 

(i) Clinker production (number of 

months). 

(ii) Carbonate contents of clinker 

(number of months). 

(iii) Non-calcined content of clinker 

(number of months). 

(iv) CKD not recycled to kiln (number 

of quarters). 

(v) Non-calcined content of CKD 

(number of quarters) 

(vi) Organic carbon contents of raw 

materials (number of times). 

(vii) Raw material consumption 

(number of months). 

§ 98.87 Records that must be retained. 

(a) If a CEMS is used to measure CO2

emissions, then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology in 

§ 98.37. 

(1) Documentation of monthly 

calculated kiln-specific clinker CO2

emission factor. 

(2) Documentation of quarterly 

calculated kiln-specific CKD CO2

emission factor. 

(3) Measurements, records and 

calculations used to determine reported 

parameters. 

(b) If a CEMS is not used to measure 

CO2 emissions, then in addition to the 

records required by § 98.3(g), you must 

retain the records specified in 

paragraphs (a) through (b) of this section 

for each portland cement manufacturing 

facility. 

§ 98.88 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

Subpart I—[Reserved] 

Subpart J—[Reserved] 

Subpart K—Ferroalloy Production 

§ 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. 

You must report: 

(a) Process CO2 emissions from each 

electric arc furnace (EAF) used for the 

production of any ferroalloy listed in 

§ 98.110. 

(b) CO2, CH4, and N2O emissions from 

each stationary combustion unit 

following the requirements of subpart C 

of this part. You must report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

§ 98.113 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

EAF using the procedures in either 

paragraph (a) or (b) of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the annual process CO2

emissions using the procedure in either 

paragraph (b)(1) or (b)(2) of this section. 

(1) Calculate and report under this 

subpart the annual process CO2

emissions from EAFs by operating and 

maintaining a CEMS according to the 

Tier 4 Calculation Methodology 

specified in § 98.33(a)(4) and the 

applicable requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(2) Calculate and report under this 

subpart the annual process CO2

emissions from the EAFs using the 

carbon mass balance procedure 

specified in paragraphs (b)(2)(i) and 

(b)(2)(ii) of this section. 


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(i) For each EAF, determine the 

annual mass of carbon in each carboncontaining input and output material for 

the EAF and estimate annual process 

CO2 emissions from the EAF using 

Equation K–1 of this section. Carboncontaining input materials include 

carbon electrodes and carbonaceous 

reducing agents. If you document that a 

specific input or output material 

contributes less than 1 percent of the 

total carbon into or out of the process, 

you do not have to include the material 

in your calculation using Equation K–1 

of this section. 

ECO2

1

44

12

2000

2205

=× × × ( ) M C reducing agent reducing agent

i

i i ∑ 

+× × × ∑ ( )

+ ×

44

12

2000

2205

44

12

2000

2

1

M C electrode electrode

m

m m 

205

× × ( ) M C ore ore h h (Eq. K-1)

flux f C j

1

44

12

2000

2205

h

M

∑

+× × × lux j

 

( )

−× × ×

∑

1

44

12

2000

2205

j

M C product outgoing product out k going

k

non- product outgoing non- p

k

l M C

( )

−× × ×

∑

1

44

12

2000

2205 roduct outgoing

l

l ∑ ( )

1

Where: 

ECO2 = Annual process CO2 emissions from 

an individual EAF (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

Mreducing agenti = Annual mass of reducing 

agent i fed, charged, or otherwise 

introduced into the EAF (tons). 

Creducing agenti = Carbon content in reducing 

agent i (percent by weight, expressed as 

a decimal fraction). 

Melectrodem = Annual mass of carbon electrode 

m consumed in the EAF (tons). 

Celectrodem = Carbon content of the carbon 

electrode m (percent by weight, 

expressed as a decimal fraction). 

Moreh = Annual mass of ore h charged to the 

EAF (tons). 

Coreh = Carbon content in ore h (percent by 

weight, expressed as a decimal fraction). 

Mfluxj = Annual mass of flux material j fed, 

charged, or otherwise introduced into 

the EAF to facilitate slag formation 

(tons). 

Cfluxj = Carbon content in flux material j 

(percent by weight, expressed as a 

decimal fraction). 

Mproductk = Annual mass of alloy product k 

tapped from EAF (tons). 

Cproductk = Carbon content in alloy product k. 

(percent by weight, expressed as a 

decimal fraction). 

Mnon-product outgoingl = Annual mass of nonproduct outgoing material l removed 

from EAF (tons). 

Cnon-product outgoingl = Carbon content in nonproduct outgoing material l (percent by 

weight, expressed as a decimal fraction). 

(ii) Determine the combined annual 

process CO2 emissions from the EAFs at 

your facility using Equation K–2 of this 

section. 

CO ECO

k

k 2 2

1

= ∑ (Eq. K-2)

Where: 

CO2 = Annual process CO2 emissions from 

EAFs at facility used for the production 

of any ferroalloy listed in § 98.110 

(metric tons). 

ECO2k = Annual process CO2 emissions 

calculated from EAF k calculated using 

Equation K–1 of this section (metric 

tons). 

k = Total number of EAFs at facility used for 

the production of any ferroalloy listed in 

§ 98.110. 

(c) If GHG emissions from an EAF are 

vented through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraph 

(b) of this section shall not be used to 

calculate process emissions. The owner 

or operator shall report under this 

subpart the combined stack emissions 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part. 

(d) For the EAFs at your facility used 

for the production of any ferroalloy 

listed in Table K–1 of this subpart, you 

must calculate and report the annual 

CH4 emissions using the procedure 

specified in paragraphs (d)(1) and (2) of 

this section. 

(1) For each EAF, determine the 

annual CH4 emissions using Equation 

K–3 of this section. 

ECH product product

i

M EF i i 4

1

2000

2205

= ×× ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟ (Eq. K-3)

Where: 

ECH4 = Annual process CH4 emissions from 

an individual EAF (metric tons). 

Mproducti = Annual mass of alloy product i 

produced in the EAF (tons). 

2000/2205 = Conversion factor to convert 

tons to metric tons. 


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EFproducti = CH4 emission factor for alloy 

product i from Table K–1 in this subpart 

(kg of CH4 emissions per metric ton of 

alloy product i). 

(2) Determine the combined process 

CH4 emissions from the EAFs at your 

facility using Equation K–4 of this 

section: 

CH ECH

j

j 4 4

1

= ∑ (Eq. K-4)

Where: 

CH4 = Annual process CH4 emissions from 

EAFs at facility used for the production 

of ferroalloys listed in Table K–1 of this 

subpart (metric tons). 

ECH4j = Annual process CH4 emissions from 

EAF j calculated using Equation K–3 of 

this section (metric tons). 

j = Total number of EAFs at facility used for 

the production of ferroalloys listed in 

Table K–1 of this subpart. 

§ 98.114 Monitoring and QA/QC 

requirements. 

If you determine annual process CO2

emissions using the carbon mass 

balance procedure in § 98.113(b)(2), you 

must meet the requirements specified in 

paragraphs (a) and (b) of this section. 

(a) Determine the annual mass for 

each material used for the calculations 

of annual process CO2 emissions using 

Equation K–1 of this subpart by 

summing the monthly mass for the 

material determined for each month of 

the calendar year. The monthly mass 

may be determined using plant 

instruments used for accounting 

purposes, including either direct 

measurement of the quantity of the 

material placed in the unit or by 

calculations using process operating 

information. 

(b) For each material identified in 

paragraph (a) of this section, you must 

determine the average carbon content of 

the material consumed, used, or 

produced in the calendar year using the 

methods specified in either paragraph 

(b)(1) or (b)(2) of this section. If you 

document that a specific process input 

or output contributes less than one 

percent of the total mass of carbon into 

or out of the process, you do not have 

to determine the monthly mass or 

annual carbon content of that input or 

output. 

(1) Information provided by your 

material supplier. 

(2) Collecting and analyzing at least 

three representative samples of the 

material inputs and outputs each year. 

The carbon content of the material must 

be analyzed at least annually using the 

standard methods (and their QA/QC 

procedures) specified in paragraphs 

(b)(2)(i) through (b)(2)(iii) of this 

section, as applicable. 

(i) ASTM E1941–04, Standard Test 

Method for Determination of Carbon in 

Refractory and Reactive Metals and 

Their Alloys (incorporated by reference, 

see § 98.7) for analysis of metal ore and 

alloy product. 

(ii) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7), 

for analysis of carbonaceous reducing 

agents and carbon electrodes. 

(iii) ASTM C25–06, Standard Test 

Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference, see 

§ 98.7) for analysis of flux materials 

such as limestone or dolomite. 

§ 98.115 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.113 is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in the 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) If you determine CO2 emissions for 

the EAFs at your facility using the 

carbon mass balance procedure in 

§ 98.113(b), 100 percent data availability 

is required for the carbon content of the 

input and output materials. You must 

repeat the test for average carbon 

contents of inputs according to the 

procedures in § 98.114(b) if data are 

missing. 

(b) For missing records of the monthly 

mass of carbon-containing inputs and 

outputs, the substitute data value must 

be based on the best available estimate 

of the mass of the inputs and outputs 

from on all available process data or 

data used for accounting purposes, such 

as purchase records. 

(c) If you are required to calculate CH4

emissions for an EAF at your facility as 

specified in § 98.113(d), the estimate is 

based an annual quantity of certain 

alloy products, so 100 percent data 

availability is required. 

§ 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 (e) of this 

section, as applicable: 

(a) Annual facility ferroalloy product 

production capacity (tons). 

(b) Annual production for each 

ferroalloy product (tons) identified in 

§ 98.110, as applicable. 

(c) Total number of EAFs at facility 

used for production of ferroalloy 

products reported in paragraph (a)(4) of 

this section. 

(d) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required by § 98.37 for the Tier 4 

Calculation Methodology and the 

following information specified in 

paragraphs (d)(1) through (d)(3) of this 

section. 

(1) Annual process CO2 emissions (in 

metric tons) from each EAF used for the 

production of any ferroalloy listed in 

Table K–1 of this subpart (metric tons). 

(2) Annual process CH4 emissions (in 

metric tons) from each EAF used for the 

production of any ferroalloy listed in 

Table K–1 of this subpart (metric tons). 

(3) Identification number of each EAF. 

(e) If a CEMS is not used to measure 

CO2 process emissions, and the carbon 

mass balance procedure is used to 

determine CO2 emissions according to 

the requirements in § 98.113(b), then 

you must report the following 

information specified in paragraphs 

(e)(1) through (e)(7) of this section. 

(1) Annual process CO2 emissions (in 

metric tons) from each EAF used for the 

production of any ferroalloy listed in 

Table K–1 of this subpart (metric tons). 

(3) Identification number for each 

material. 

(4) Annual material quantity for each 

material included for the calculation of 

annual process CO2 emissions for each 

EAF. 

(5) Annual average of the carbon 

content determinations for each material 

included for the calculation of annual 

process CO2 emissions for each EAF 

(percent by weight, expressed as a 

decimal fraction). 

(6) List the method used for the 

determination of carbon content for 

each material reported in paragraph 

(e)(5) of this section (e.g., supplier 

provided information, analyses of 

representative samples you collected). 

(7) If you use the missing data 

procedures in § 98.115(b), you must 

report how monthly mass of carboncontaining inputs and outputs with 

missing data was determined and the 

number of months the missing data 

procedures were used. 

§ 98.117 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 EAF, as 

applicable. 

(a) If a CEMS is used to measure CO2

emissions according to the requirements 

in § 98.113(a), then you must retain 

under this subpart the records required 


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for the Tier 4 Calculation Methodology 

in § 98.37 and the information specified 

in paragraphs (a)(1) through (a)(3) of this 

section. 

(1) Monthly EAF production quantity 

for each ferroalloy product (tons). 

(2) Number of EAF operating hours 

each month. 

(3) Number of EAF operating hours in 

a calendar year. 

(b) If the carbon mass balance 

procedure is used to determine CO2

emissions according to the requirements 

in § 98.113(b)(2), then you must retain 

records for the information specified in 

paragraphs (b)(1) through (b)(5) of this 

section. 

(1) Monthly EAF production quantity 

for each ferroalloy product (tons). 

(2) Number of EAF operating hours 

each month. 

(3) Number of EAF operating hours in 

a calendar year. 

(4) Monthly material quantity 

consumed, used, or produced for each 

material included for the calculations of 

annual process CO2 emissions (tons). 

(5) Average carbon content 

determined and records of the supplier 

provided information or analyses used 

for the determination for each material 

included for the calculations of annual 

process CO2 emissions. 

(c) You must keep records that 

include a detailed explanation of how 

company records of measurements are 

used to estimate the carbon input and 

output to each EAF, including 

documentation of specific input or 

output materials excluded from 

Equation K–1 of this subpart that 

contribute less than 1 percent of the 

total carbon into or out of the process. 

You also must document the procedures 

used to ensure the accuracy of the 

measurements of materials fed, charged, 

or placed in an EAF including, but not 

limited to, calibration of weighing 

equipment and other measurement 

devices. The estimated accuracy of 

measurements made with these devices 

must also be recorded, and the technical 

basis for these estimates must be 

provided. 

(d) If you are required to calculate 

CH4 emissions for the EAF as specified 

in § 98.113(d), you must maintain 

records of the total amount of each alloy 

product produced for the specified 

reporting period, and the appropriate 

alloy-product specific emission factor 

used to calculate the CH4 emissions. 

§ 98.118 Definitions. 

All terms used of this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE K–1 TO SUBPART K OF PART 98—ELECTRIC ARC FURNACE (EAF) CH4 EMISSION FACTORS

Alloy product produced in EAF 

CH4 emission factor 

(kg CH4 per metric ton product) 

EAF Operation 

Batchcharging Sprinklecharging a

Sprinklecharging 

and 

>750 °C b

Silicon metal ............................................................................................................................................ 1.5 1.2 0.7 

Ferrosilicon 90% ...................................................................................................................................... 1.4 1.1 0.6 

Ferrosilicon 75% ...................................................................................................................................... 1.3 1.0 0.5 

Ferrosilicon 65% ...................................................................................................................................... 1.3 1.0 0.5 

aSprinkle-charging is charging intermittently every minute. 

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

Subpart L—[Reserved] 

Subpart M—[Reserved] 

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. 

You must report: 

(a) CO2 process emissions from each 

continuous glass melting furnace. 

(b) CO2 combustion emissions from 

each continuous glass melting furnace. 

(c) CH4 and N2O combustion 

emissions from each continuous glass 

melting furnace. You must calculate and 

report these emissions under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) by following the 

requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from 

each stationary fuel combustion unit 

other than continuous glass melting 

furnaces. You must report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

§ 98.143 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

continuous glass melting furnace using 

the procedure in paragraphs (a) and (b) 

of this section. 

(a) For each continuous glass melting 

furnace that meets the conditions 

specified in § 98.33(b)(4)(ii) or (iii), you 

must calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 

and maintaining a CEMS to measure 

CO2 emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(b) For each continuous glass melting 

furnace that is not subject to the 

requirements in paragraph (a) of this 

section, calculate and report the process 

and combustion CO2 emissions from the 

glass melting furnace by using either the 

procedure in paragraph (b)(1) of this 

section or the procedure in paragraphs 

(b)(2) through (b)(7) of this section, 

except as specified in paragraph (c) of 

this section. 

(1) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 


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and maintaining a CEMS to measure 

CO2 emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(2) Calculate and report the process 

and combustion CO2 emissions 

separately using the procedures 

specified in paragraphs (b)(2)(i) through 

(b)(2)(vi) of this section. 

(i) For each carbonate-based raw 

material charged to the furnace, obtain 

from the supplier of the raw material the 

carbonate-based mineral mass fraction. 

(ii) Determine the quantity of each 

carbonate-based raw material charged to 

the furnace. 

(iii) Apply the appropriate emission 

factor for each carbonate-based raw 

material charged to the furnace, as 

shown in Table N–1 to this subpart. 

(iv) Use Equation N–1 of this section 

to calculate process mass emissions of 

CO2 for each furnace: 

E MF M EF F Eq CO i i i i 2

1

2000

2205 = ⎛

⎝

⎜ ⎞

⎠

⎟ =

∑ i i ii

i

n

(. ) N-1

Where: 

ECO2 = Process emissions of CO2 from the 

furnace (metric tons). 

n = Number of carbonate-based raw materials 

charged to furnace. 

MFi = Annual average mass fraction of 

carbonate-based mineral i in carbonatebased raw material i (percentage, 

expressed as a decimal). 

Mi = Annual amount of carbonate-based raw 

material i charged to furnace (tons). 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

EFi = Emission factor for carbonate-based raw 

material i (metric ton CO2 per metric ton 

carbonate-based raw material as shown 

in Table N–1 to this subpart). 

Fi = Fraction of calcination achieved for 

carbonate-based raw material i, assumed 

to be equal to 1.0 (percentage, expressed 

as a decimal). 

(v) You must calculate the total 

process CO2 emissions from continuous 

glass melting furnaces at the facility 

using Equation N–2 of this section: 

CO E Eq CO i

i

k

2

1 2 =

=

∑ (. ) N-2

Where: 

CO2 = Annual process CO2 emissions from 

glass manufacturing facility (metric 

tons). 

ECO2i = Annual CO2 emissions from glass 

melting furnace i (metric tons). 

k = Number of continuous glass melting 

furnaces. 

(vi) Calculate and report under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) 

the combustion CO2 emissions in the 

glass furnace according to the applicable 

requirements in subpart C. 

(c) As an alternative to data provided 

by the raw material supplier, a value of 

1.0 can be used for the mass fraction 

(MFi) of carbonate-based mineral i in 

Equation N–1 of this section. 

§ 98.144 Monitoring and QA/QC 

requirements. 

(a) You must measure annual amounts 

of carbonate-based raw materials 

charged to each continuous glass 

melting furnace from monthly 

measurements using plant instruments 

used for accounting purposes, such as 

calibrated scales or weigh hoppers. 

Total annual mass charged to glass 

melting furnaces at the facility shall be 

compared to records of raw material 

purchases for the year. 

(b) You must measure carbonatebased mineral mass fractions at least 

annually to verify the mass fraction data 

provided by the supplier of the raw 

material; such measurements shall be 

based on sampling and chemical 

analysis conducted by a certified 

laboratory using ASTM D3682–01 

(Reapproved 2006) Standard Test 

Method for Major and Minor Elements 

in Combustion Residues from Coal 

Utilization Processes (incorporated by 

reference, see § 98.7). 

(c) You must determine the annual 

average mass fraction for the carbonatebased mineral in each carbonate-based 

raw material by calculating an 

arithmetic average of the monthly data 

obtained from raw material suppliers or 

sampling and chemical analysis. 

(d) You must determine on an annual 

basis the calcination fraction for each 

carbonate consumed based on sampling 

and chemical analysis using an industry 

consensus standard. This chemical 

analysis must be conducted using an xray fluorescence test or other enhanced 

testing method published by an industry 

consensus standards organization (e.g., 

ASTM, ASME, API, etc.). 

§ 98.145 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required (e.g., carbonate 

raw materials consumed, etc.). If the 

monitoring and quality assurance 

procedures in § 98.144 cannot be 

followed and data is missing, you must 

use the most appropriate of the missing 

data procedures in paragraphs (a) and 

(b) of this section. You must document 

and keep records of the procedures used 

for all such missing value estimates. 

(a) For missing data on the monthly 

amounts of carbonate-based raw 

materials charged to any continuous 

glass melting furnace use the best 

available estimate(s) of the parameter(s), 

based on all available process data or 

data used for accounting purposes, such 

as purchase records. 

(b) For missing data on the mass 

fractions of carbonate-based minerals in 

the carbonate-based raw materials 

assume that the mass fraction of each 

carbonate based mineral is 1.0. 

§ 98.146 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) and (b) of this section, 

as applicable. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required under § 98.37 for the Tier 4 

Calculation Methodology and the 

following information specified in 

paragraphs (a)(1) and (a)(2) of this 

section: 

(1) Annual quantity of each carbonatebased raw material charged to each 

continuous glass melting furnace and 

for all furnaces combined (tons). 

(2) Annual quantity of glass produced 

(tons). 

(b) If a CEMS is not used to determine 

CO2 emissions from continuous glass 

melting furnaces, and process CO2

emissions are calculated according to 

the procedures specified in § 98.143(b), 

then you must report the following 

information as specified in paragraphs 

(b)(1) through (b)(9) of this section: 

(1) Annual process emissions of CO2

(metric tons) for each continuous glass 

melting furnace and for all furnaces 

combined. 

(2) Annual quantity of each carbonatebased raw material charged (tons) to 

each continuous glass melting furnace 

and for all furnaces combined. 


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(3) Annual quantity of glass produced 

(tons) from each continuous glass 

melting furnace and from all furnaces 

combined. 

(4) Carbonate-based mineral mass 

fraction (percentage, expressed as a 

decimal) for each carbonate-based raw 

material charged to a continuous glass 

melting furnace. 

(5) Results of all tests used to verify 

the carbonate-based mineral mass 

fraction for each carbonate-based raw 

material charged to a continuous glass 

melting furnace, as specified in 

paragraphs (b)(5)(i) through (b)(5)(iii) of 

this section. 

(i) Date of test. 

(ii) Method(s) and any variations used 

in the analyses. 

(iii) Mass fraction of each sample 

analyzed. 

(6) The fraction of calcination 

achieved for each carbonate-based raw 

material, if a value other than 1.0 is 

used to calculate process mass 

emissions of CO2. 

(7) Method used to determine fraction 

of calcination (percentage, expressed as 

a decimal). 

(8) Total number of continuous glass 

melting furnaces. 

(9) The number of times in the 

reporting year that missing data 

procedures were followed to measure 

monthly quantities of carbonate-based 

raw materials any continuous glass 

melting furnace or mass fraction of the 

carbonate-based minerals (months). 

§ 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), (b), 

and (c) of this section. 

(a) If a CEMS is used to measure 

emissions, then you must retain the 

records required under § 98.37 for the 

Tier 4 Calculation Methodology and the 

following information specified in 

paragraphs (a)(1) and (a)(2) of this 

section: 

(1) Monthly glass production rate for 

each continuous glass melting furnace 

(tons). 

(2) Monthly amount of each 

carbonate-based raw material charged to 

each continuous glass melting furnace 

(tons). 

(b) If process CO2 emissions are 

calculated according to the procedures 

specified in § 98.143(b), you must retain 

the records in paragraphs (b)(1) through 

(b)(5) of this section. 

(1) Monthly glass production rate for 

each continuous glass melting furnace 

(metric tons). 

(2) Monthly amount of each 

carbonate-based raw material charged to 

each continuous glass melting furnace 

(metric tons). 

(3) Data on carbonate-based mineral 

mass fractions provided by the raw 

material supplier for all raw materials 

consumed annually and included in 

calculating process emissions in 

Equation N–1 of this subpart. 

(4) Results of all tests used to verify 

the carbonate-based mineral mass 

fraction for each carbonate-based raw 

material charged to a continuous glass 

melting furnace, including the data 

specified in paragraphs (b)(4)(i) through 

(b)(4)(v) of this section. 

(i) Date of test. 

(ii) Method(s), and any variations of 

the methods, used in the analyses. 

(iii) Mass fraction of each sample 

analyzed. 

(iv) Relevant calibration data for the 

instrument(s) used in the analyses. 

(v) Name and address of laboratory 

that conducted the tests. 

(5) The fraction of calcination 

achieved for each carbonate-based raw 

material (percentage, expressed as a 

decimal), if a value other than 1.0 is 

used to calculate process mass 

emissions of CO2. 

(c) All other documentation used to 

support the reported GHG emissions. 

§ 98.148 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE N–1 TO SUBPART N OF PART

98—CO2 EMISSION FACTORS FOR

CARBONATE-BASED RAW MATERIALS

Carbonate-based 

raw material—mineral 

CO2 emission factor a

Limestone—CaCO3 .................. 0.440 

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 an HCFC–22 production or 

HFC–23 destruction process and the 

facility meets the requirements of either 

§ 98.2(a)(1) or (a)(2). 

§ 98.152 GHGs to report. 

(a) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit following the 

requirements of subpart C. 

(b) You must report HFC–23 

emissions from HCFC–22 production 

processes and HFC–23 destruction 

processes. 

§ 98.153 Calculating GHG emissions. 

(a) The mass of HFC–23 generated 

from each HCFC–22 production process 

shall be estimated by using one of two 

methods, as applicable: 

(1) Where the mass flow of the 

combined stream of HFC–23 and 

another reaction product (e.g., HCl) is 

measured, multiply the weekly (or more 

frequent) HFC–23 concentration 

measurement (which may be the average 

of more frequent concentration 

measurements) by the weekly (or more 

frequent) mass flow of the combined 

stream of HFC–23 and the other 

product. To estimate annual HFC–23 

production, sum the weekly (or more 

frequent) estimates of the quantities of 

HFC–23 produced over the year. This 

calculation is summarized in Equation 

O–1 of this section: 

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 weekly (or more 

frequent) measurement of the HFC–23 

concentration and the weekly (or more 

frequent) measurement of the other 

product concentration by the weekly (or 

more frequent) mass produced of the 

other product. To estimate annual HFC– 

23 production, sum the weekly (or more 


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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 OWhere: 

G23 = Mass of HFC–23 generated annually 

(metric tons). 

c23 = Fraction HFC–23 by weight in HCFC– 

22/HFC–23 stream. 

c22 = Fraction HCFC–22 by weight in HCFC– 

22/HFC–23 stream. 

P22 = Mass of HCFC–22 produced over the 

period p (kg), calculated using Equation 

O–3 of this section. 

p = Period over which masses and 

concentrations are measured. 

n = Number of concentration and mass 

measurement periods for the year. 

10¥3 = Conversion factor from kilograms to 

metric tons. 

(b) The mass of HCFC–22 produced 

over the period p shall be estimated by 

using Equation O–3 of this section: 

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 

that have a thermal oxidizer that is not 

directly connected to the HCFC–22 

production equipment, HFC–23 

emissions shall be estimated using 

Equation O–4 of this section: 

E G S OD D 23 23 23 23 23 23 =− + ++ ( ) I ( . 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 sent off site for sale 

annually (metric tons). 

OD23 = Mass of HFC–23 sent off site for 

destruction (metric tons). 

D23 = Mass of HFC–23 destroyed on site 

(metric tons). 

I23 = Increase in HFC–23 inventory = HFC– 

23 in storage at end of year—HFC–23 in 

storage at beginning of year (metric tons). 

(d) For HCFC–22 production facilities 

that use a thermal oxidizer connected to 

the HCFC–22 production equipment, 

HFC–23 emissions shall be estimated 

using Equation O–5 of this section: 

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 of this section (metric 

tons). 

EPV = Mass of HFC–23 emitted annually from 

process vents, calculated using Equation 

O–7 of this section (metric tons). 

ED = Mass of HFC–23 emitted annually from 

thermal oxidizer (metric tons), calculated 

using Equation O–8 of this section. 

(1) The mass of HFC–23 emitted 

annually from equipment leaks (for use 

in Equation O–5 of this section) shall be 

estimated by using Equation O–6 of this 

section: 

E FN FN

t

Gt Gt

p

n

L Lt Lt = ∗ ∗+∗ ∑∑c ( ) ∗ −

=

23

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 of this subpart for each source 

of equipment type and service t with a 

screening value greater than or equal to 

10,000 ppmv (kg/hr/source). 

NGt = The number of sources of equipment 

type and service t with screening values 

greater than or equal to 10,000 ppmv as 

determined according to § 98.154(i). 

FLt = The applicable leak rate specified in 

Table O–1 of this subpart for each source 

of equipment type and service t with a 

screening value of less than 10,000 ppmv 

(kg/hr/source). 

NLt = The number of sources of equipment 

type and service t with screening values 

less than 10,000 ppmv as determined 

according to § 98.154(j). 

p = One hour. 

n = Number of hours during the year during 

which equipment contained HFC–23. 

t = Equipment type and service as specified 

in Table O–1 of this subpart . 

10¥3 = Factor converting kg to metric tons. 

(2) The mass of HFC–23 emitted 

annually from process vents (for use in 

Equation O–5 of this section) shall be 

estimated by using Equation O–7 of this 

section: 

E = ER *

PR

PR

* l T

p

T

PV p

p

n

=

− ∑ ⎛

⎝

⎜ ⎞

⎠

⎟ ∗

1

3 10 ( . 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. 

(3) The total mass of HFC–23 emitted 

from destruction devices shall be 

estimated by using Equation O–8 of this 

section: 

E FD D D = − 23 ( . Eq O- ) 8


ER30OC09.052</MATH> ER30OC09.053</MATH> ER30OC09.054</MATH> ER30OC09.055</MATH> ER30OC09.056</MATH> ER30OC09.057</MATH> ER30OC09.058</MATH>sroberts on DSKD5P82C1PROD with RULES
Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56429 

Where: 

ED = Mass of HFC–23 emitted annually from 

the destruction device (metric tons). 

FD = Mass of HFC–23 fed into the destruction 

device annually (metric tons). 

D23 = Mass of HFC–23 destroyed annually 

(metric tons). 

(4) For facilities that destroy HFC–23, 

the total mass of HFC–23 destroyed 

shall be estimated by using Equation O– 

9 of this section: 

D F DE O- ) 23 D = ∗ ( . Eq 9

Where: 

D23 = Mass of HFC–23 destroyed annually 

(metric tons). 

FD = Mass of HFC–23 fed into the destruction 

device annually (metric tons). 

DE = Destruction Efficiency of the 

destruction device (fraction). 

§ 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 weekly using equipment and 

methods (e.g., gas chromatography) with 

an accuracy and precision of 5 percent 

or better at the concentrations of the 

process samples. 

(b) The mass flow of the product 

stream containing the HFC–23 shall be 

measured at least weekly using weigh 

scales, flowmeters, or a combination of 

volumetric and density measurements 

with an accuracy and precision of 1.0 

percent of full scale or better. 

(c) The mass of HCFC–22 or HCl 

coming out of the production process 

shall be measured at least weekly using 

weigh scales, flowmeters, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of 1.0 percent of full scale or 

better. 

(d) The mass of any used HCFC–22 

added back into the production process 

upstream of the output measurement in 

paragraph (c) of this section shall be 

measured (when being added) using 

flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of 1.0 percent of full scale or 

better. If the mass in paragraph (c) of 

this section is measured by weighing 

containers that include returned heels 

as well as newly produced fluorinated 

GHGs, the returned heels shall be 

considered used fluorinated HCFC–22 

for purposes of this paragraph (d) of this 

section and § 98.153(b). 

(e) The loss factor LF in Equation O– 

3 of this subpart for the mass of HCFC– 

22 produced shall have the value 1.015 

or another value that can be 

demonstrated, to the satisfaction of the 

Administrator, to account for losses of 

HCFC–22 between the reactor and the 

point of measurement at the facility 

where production is being estimated. 

(f) The mass of HFC–23 sent off site 

for sale shall be measured at least 

weekly (when being packaged) using 

flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of 1.0 percent of full scale or 

better. 

(g) The mass of HFC–23 sent off site 

for destruction shall be measured at 

least weekly (when being packaged) 

using flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of 1.0 percent of full scale or 

better. If the measured mass includes 

more than trace concentrations of 

materials other than HFC–23, the 

concentration of the fluorinated GHG 

shall be measured at least weekly using 

equipment and methods (e.g., gas 

chromatography) with an accuracy and 

precision of 5 percent or better at the 

concentrations of the process samples. 

This concentration (mass fraction) shall 

be multiplied by the mass measurement 

to obtain the mass of the HFC–23 sent 

to another facility for destruction. 

(h) The masses of HFC–23 in storage 

at the beginning and end of the year 

shall be measured using flowmeters, 

weigh scales, or a combination of 

volumetric and density measurements 

with an accuracy and precision of 1.0 

percent of full scale or better. 

(i) The number of sources of 

equipment type t with screening values 

greater than or equal to 10,000 ppmv 

shall be determined using EPA Method 

21 at 40 CFR part 60, appendix A–7, and 

defining a leak as follows: 

(1) A leak source that could emit 

HFC–23, and 

(2) A leak source at whose surface a 

concentration of fluorocarbons equal to 

or greater than 10,000 ppm is measured. 

(j) The number of sources of 

equipment type t with screening values 

less than 10,000 ppmv shall be the 

difference between the number of leak 

sources of equipment type t that could 

emit HFC–23 and the number of sources 

of equipment type t with screening 

values greater than or equal to 10,000 

ppmv as determined under paragraph 

(h) of this section. 

(k) The mass of HFC–23 emitted from 

process vents shall be estimated at least 

monthly by incorporating the results of 

the most recent emissions test into 

Equation O–6 of this subpart. HCFC–22 

production facilities that use a thermal 

oxidizer connected to the HCFC–22 

production equipment shall conduct 

emissions tests at process vents at least 

once every five years or after significant 

changes to the process. Emissions tests 

shall be conducted in accordance with 

EPA Method 18 at 40 CFR part 60, 

appendix A–6, under conditions that are 

typical for the production process at the 

facility. The sensitivity of the tests shall 

be sufficient to detect an emission rate 

that would result in annual emissions of 

200 kg of HFC–23 if sustained over one 

year. 

(l) For purposes of Equation O–9 of 

this subpart, the destruction efficiency 

must be equated to the destruction 

efficiency determined during a new or 

previous performance test of the 

destruction device. HFC–23 destruction 

facilities shall conduct annual 

measurements of HFC–23 

concentrations at the outlet of the 

thermal oxidizer in accordance with 

EPA Method 18 at 40 CFR part 60, 

appendix A–6. Three samples shall be 

taken under conditions that are typical 

for the production process and 

destruction device at the facility, and 

the average concentration of HFC–23 

shall be determined. The sensitivity of 

the concentration measurement shall be 

sufficient to detect an outlet 

concentration equal to or less than the 

outlet concentration determined in the 

destruction efficiency performance test. 

If the concentration measurement 

indicates that the HFC–23 concentration 

is less than or equal to that measured 

during the performance test that is the 

basis for the destruction efficiency, 

continue to use the previously 

determined destruction efficiency. If the 

concentration measurement indicates 

that the HFC–23 concentration is greater 

than that measured during the 

performance test that is the basis for the 

destruction efficiency, facilities shall 

either: 

(1) Substitute the higher HFC–23 

concentration for that measured during 

the destruction efficiency performance 

test and calculate a new destruction 

efficiency, or 

(2) Estimate the mass emissions of 

HFC–23 from the destruction device 

based on the measured HFC–23 

concentration and volumetric flow rate 

determined by measurement of 

volumetric flow rate using EPA Method 

2, 2A, 2C,2D, or 2F at 40 CFR part 60, 

appendix A–1, or Method 26 at 40 CFR 

part 60, appendix A–2. Determine the 

mass rate of HFC–23 into the 

destruction device by measuring the 

HFC–23 concentration and volumetric 

flow rate at the inlet or by a metering 

device for HFC–23 sent to the device. 

Determine a new destruction efficiency 


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based on the mass flow rate of HFC–23 

into and out of the destruction device. 

(m) HCFC–22 production facilities 

shall account for HFC–23 generation 

and emissions that occur as a result of 

startups, shutdowns, and malfunctions, 

either recording HFC–23 generation and 

emissions during these events, or 

documenting that these events do not 

result in significant HFC–23 generation 

and/or emissions. 

(n) The mass of HFC–23 fed into the 

destruction device shall be measured at 

least weekly using flow meters, weigh 

scales, or a combination of volumetric 

and density measurements with an 

accuracy and precision of 1.0 percent of 

full scale or better. If the measured mass 

includes more than trace concentrations 

of materials other than HFC–23, the 

concentrations of the HFC–23 shall be 

measured at least weekly using 

equipment and methods (e.g., gas 

chromatography) with an accuracy and 

precision of 5 percent or better at the 

concentrations of the process samples. 

This concentration (mass fraction) shall 

be multiplied by the mass measurement 

to obtain the mass of the HFC–23 

destroyed. 

(o) In their estimates of the mass of 

HFC–23 destroyed, HFC–23 destruction 

facilities shall account for any 

temporary reductions in the destruction 

efficiency that result from any startups, 

shutdowns, or malfunctions of the 

destruction device, including departures 

from the operating conditions defined in 

state or local permitting requirements 

and/or oxidizer manufacturer 

specifications. 

(p) Calibrate all flow meters, weigh 

scales, and combinations of volumetric 

and density measures using NISTtraceable standards and suitable 

methods published by a consensus 

standards organization (e.g., ASTM, 

ASME, ISO, or others). Recalibrate all 

flow meters, weigh scales, and 

combinations of volumetric and density 

measures at the minimum frequency 

specified by the manufacturer. 

(q) All gas chromatographs used to 

determine the concentration of HFC–23 

in process streams shall be calibrated at 

least monthly through analysis of 

certified standards (or of calibration 

gases prepared from a highconcentration certified standard using a 

gas dilution system that meets the 

requirements specified in Method 205 at 

40 CFR part 51, appendix M) with 

known HFC–23 concentrations that are 

in the same range (fractions by mass) as 

the process samples. 

§ 98.155 Procedures for estimating 

missing data. 

(a) A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions during unit 

operation or if a required process 

sample is not taken), a substitute data 

value for the missing parameter shall be 

used in the calculations, according to 

the following requirements: 

(1) For each missing value of the 

HFC–23 or HCFC–22 concentration, the 

substitute data value shall be the 

arithmetic average of the quality-assured 

values of that parameter immediately 

preceding and immediately following 

the missing data incident. If, for a 

particular parameter, no quality-assured 

data are available prior to the missing 

data incident, the substitute data value 

shall be the first quality-assured value 

obtained after the missing data period. 

(2) For each missing value of the 

product stream mass flow or product 

mass, the substitute value of that 

parameter shall be a secondary product 

measurement where such a 

measurement is available. If that 

measurement is taken significantly 

downstream of the usual mass flow or 

mass measurement (e.g., at the shipping 

dock rather than near the reactor), the 

measurement shall be multiplied by 

1.015 to compensate for losses. Where a 

secondary mass measurement is not 

available, the substitute value of the 

parameter shall be an estimate based on 

a related parameter. For example, if a 

flowmeter measuring the mass fed into 

a destruction device is rendered 

inoperable, then the mass fed into the 

destruction device may be estimated 

using the production rate and the 

previously observed relationship 

between the production rate and the 

mass flow rate into the destruction 

device. 

§ 98.156 Data reporting requirements. 

(a) In addition to the information 

required by § 98.3(c), the HCFC–22 

production facility shall report the 

following information at the facility 

level: 

(1) Annual mass of HCFC–22 

produced in metric tons. 

(2) Loss Factor used to account for the 

loss of HCFC– 22 upstream of the 

measurement. 

(3) Annual mass of reactants fed into 

the process in metric tons of reactant. 

(4) The mass (in metric tons) of 

materials other than HCFC–22 and 

HFC–23 (i.e., unreacted reactants, HCl 

and other by-products) that occur in 

more than trace concentrations and that 

are permanently removed from the 

process. 

(5) The method for tracking startups, 

shutdowns, and malfunctions and HFC– 

23 generation/emissions during these 

events. 

(6) The names and addresses of 

facilities to which any HFC–23 was sent 

for destruction, and the quantities of 

HFC–23 (metric tons) sent to each. 

(7) Annual mass of the HFC–23 

generated in metric tons. 

(8) Annual mass of any HFC–23 sent 

off site for sale in metric tons. 

(9) Annual mass of any HFC–23 sent 

off site for destruction in metric tons. 

(10) Mass of HFC–23 in storage at the 

beginning and end of the year, in metric 

tons. 

(11) Annual mass of HFC–23 emitted 

in metric tons. 

(12) Annual mass of HFC–23 emitted 

from equipment leaks in metric tons. 

(13) Annual mass of HFC–23 emitted 

from process vents in metric tons. 

(b) In addition to the information 

required by § 98.3(c), facilities that 

destroy HFC–23 shall report the 

following for each HFC–23 destruction 

process: 

(1) Annual mass of HFC–23 fed into 

the thermal oxidizer. 

(2) Annual mass of HFC–23 

destroyed. 

(3) Annual mass of HFC–23 emitted 

from the thermal oxidizer. 

(c) Each HFC–23 destruction facility 

shall report the results of the facility’s 

annual HFC–23 concentration 

measurements at the outlet of the 

destruction device, including: 

(1) Flow rate of HFC–23 being fed into 

the destruction device in kg/hr. 

(2) Concentration (mass fraction) of 

HFC–23 at the outlet of the destruction 

device. 

(3) Flow rate at the outlet of the 

destruction device in kg/hr. 

(d) Emission rate calculated from 

paragraphs (c)(2) and (3) of this section 

in kg/hr. 

(e) HFC–23 destruction facilities shall 

submit a one-time report including the 

following information for each the 

destruction process: 

(1) Destruction efficiency (DE). 

(2) The methods used to determine 

destruction efficiency. 

(3) The methods used to record the 

mass of HFC–23 destroyed. 

(4) The name of other relevant federal 

or state regulations that may apply to 

the destruction process. 

(5) If any changes are made that affect 

HFC–23 destruction efficiency or the 

methods used to record volume 

destroyed, then these changes must be 

reflected in a revision to this report. The 

revised report must be submitted to EPA 

within 60 days of the change. 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56431 

§ 98.157 Records that must be retained. 

(a) In addition to the data required by 

§ 98.3(g), HCFC–22 production facilities 

shall retain the following records: 

(1) The data used to estimate HFC–23 

emissions. 

(2) Records documenting the initial 

and periodic calibration of the gas 

chromatographs, weigh scales, 

volumetric and density measurements, 

and flowmeters used to measure the 

quantities reported under this rule, 

including the industry standards or 

manufacturer directions used for 

calibration pursuant to § 98.154(p) and 

(q). 

(b) In addition to the data required by 

§ 98.3(g), the HFC–23 destruction 

facilities shall retain the following 

records: 

(1) Records documenting their onetime and annual reports in § 98.156(b) 

through (d). 

(2) Records documenting the initial 

and periodic calibration of the gas 

chromatographs, weigh scales, 

volumetric and density measurements, 

and flowmeters used to measure the 

quantities reported under this subpart, 

including the industry standard practice 

or manufacturer directions used for 

calibration pursuant to § 98.154(p) and 

(q). 

§ 98.158 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE O–1 TO SUBPART O OF PART 98—EMISSION FACTORS FOR EQUIPMENT LEAKS

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 

Subpart P—Hydrogen Production 

§ 98.160 Definition of the source category. 

(a) A hydrogen production source 

category consists of facilities that 

produce hydrogen gas sold as a product 

to other entities. 

(b) This source category comprises 

process units that produce hydrogen by 

reforming, gasification, oxidation, 

reaction, or other transformations of 

feedstocks. 

(c) This source category includes 

merchant hydrogen production facilities 

located within a petroleum refinery if 

they are not owned by, or under the 

direct control of, the refinery owner and 

operator. 

§ 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 (a)(2). 

§ 98.162 GHGs to report. 

You must report: 

(a) CO2 process emissions from each 

hydrogen production process unit. 

(b) CO2, CH4 and N2O combustion 

emissions from each hydrogen 

production process unit. You must 

calculate and report these combustion 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

(c) CO2, CH4, and N2O emissions from 

each stationary combustion unit other 

than hydrogen production process units. 

You must calculate and report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

(d) For CO2 collected and transferred 

off site, you must follow the 

requirements of subpart PP of this part. 

§ 98.163 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

hydrogen production process unit using 

the procedures specified in either 

paragraph (a) or (b) of this section. 

(a) Continuous Emissions Montoring 

Systems (CEMS). Calculate and report 

under this subpart the process CO2

emissions by operating and maintaining 

CEMS according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(b) Fuel and feedstock material 

balance approach. Calculate and report 

process CO2 emissions as the sum of the 

annual emissions associated with each 

fuel and feedstock used for hydrogen 

production by following paragraphs 

(b)(1) through (b)(3) of this section. 

(1) Gaseous fuel and feedstock. You 

must calculate the annual CO2 process 

emissions from gaseous fuel and 

feedstock according to Equation P–1 of 

this section: 

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 fuel and feedstock consumption 

(metric tons/yr). 

Fdstkn = Volume of the gaseous fuel and 

feedstock used in month n (scf (at 

standard conditions of 68 °F and 

atmospheric pressure) of fuel and 

feedstock). 

CCn = Average carbon content of the gaseous 

fuel and feedstock, from the results of 

one or more analyses for month n (kg 

carbon per kg of fuel and feedstock). 

MW = Molecular weight of the gaseous fuel 

and feedstock (kg/kg-mole). 


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MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 0.001 = Conversion factor from 

kg to metric tons. 

(2) Liquid fuel and feedstock. You 

must calculate the annual CO2 process 

emissions from liquid fuel and 

feedstock according to Equation P–2 of 

this section: 

CO2 n n

1

= 0 001 2 44

12 P- )

n

k

Fdstk CC

=

∑ ∗ ∗ ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ ∗ . (. Eq

Where: 

CO2 = Annual CO2 emissions arising from 

fuel and feedstock consumption (metric 

tons/yr). 

Fdstkn = Volume of the liquid fuel and 

feedstock used in month n (gallons of 

fuel and feedstock). 

CCn = Average carbon content of the liquid 

fuel and feedstock, from the results of 

one or more analyses for month n (kg 

carbon per gallon of fuel and feedstock). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

(3) Solid fuel and feedstock. You must 

calculate the annual CO2 process 

emissions from solid fuel and feedstock 

according to Equation P–3 of this 

section: 

CO2 n n

1

= 0 001 3 44

12 P- )

n

k

Fdstk CC

=

∑ ∗ ∗ ⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ ∗ . (. Eq

Where: 

CO2 = Annual CO2 emissions from fuel and 

feedstock consumption in metric tons 

per month (metric tons/yr). 

Fdstkn = Mass of solid fuel and feedstock 

used in month n (kg of fuel and 

feedstock). 

CCn = Average carbon content of the solid 

fuel and feedstock, from the results of 

one or more analyses for month n (kg 

carbon per kg of fuel and feedstock). 

k = Months in the year. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.001 = Conversion factor from kg to metric 

tons. 

(c) If GHG emissions from a hydrogen 

production process unit are vented 

through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraph 

(b) of this section shall not be used to 

calculate process emissions. The owner 

or operator shall report under this 

subpart the combined stack emissions 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

§ 98.164 Monitoring and QA/QC 

requirements. 

The GHG emissions data for hydrogen 

production process units must be 

quality-assured as specified in 

paragraphs (a) or (b) of this section, as 

appropriate for each process unit: 

(a) If a CEMS is used to measure GHG 

emissions, then the facility must comply 

with the monitoring and QA/QC 

procedures specified in § 98.34(c). 

(b) If a CEMS is not used to measure 

GHG emissions, then you must: 

(1) Calibrate all oil and gas flow 

meters (except for gas billing meters), 

solids weighing equipment, and oil tank 

drop measurements (if used to 

determine liquid fuel and feedstock use 

volume) according to the calibration 

accuracy requirements in § 98.3(i) of 

this part. 

(2) Determine the carbon content and 

the molecular weight annually of 

standard gaseous hydrocarbon fuels and 

feedstocks having consistent 

composition (e.g., natural gas). For other 

gaseous fuels and feedstocks (e.g., 

biogas, refinery gas, or process gas), 

weekly sampling and analysis is 

required to determine the carbon 

content and molecular weight of the fuel 

and feedstock. 

(3) Determine the carbon content of 

fuel oil, naphtha, and other liquid fuels 

and feedstocks at least monthly, except 

annually for standard liquid 

hydrocarbon fuels and feedstocks 

having consistent composition, or upon 

delivery for liquid fuels delivered by 

bulk transport (e.g., by truck or rail). 

(4) Determine the carbon content of 

coal, coke, and other solid fuels and 

feedstocks at least monthly, except 

annually for standard solid hydrocarbon 

fuels and feedstocks having consistent 

composition, or upon delivery for solid 

fuels delivered by bulk transport (e.g., 

by truck or rail). 

(5) You must use the following 

applicable methods to determine the 

carbon content for all fuels and 

feedstocks, and molecular weight of 

gaseous fuels and feedstocks. 

(i) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(ii) ASTM D1946–90 (Reapproved 

2006), Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(iii) ASTM D2013–07 Standard 

Practice of Preparing Coal Samples for 

Analysis (incorporated by reference, see 

§ 98.7). 

(iv) ASTM D2234/D2234M–07 

Standard Practice for Collection of a 

Gross Sample of Coal (incorporated by 

reference, see § 98.7). 

(v) ASTM D2597–94 (Reapproved 

2004) Standard Test Method for 

Analysis of Demethanized Hydrocarbon 

Liquid Mixtures Containing Nitrogen 

and Carbon Dioxide by Gas 

Chromatography (incorporated by 

reference, see § 98.7). 

(vi) ASTM D3176–89 (Reapproved 

2002), Standard Practice for Ultimate 

Analysis of Coal and Coke (incorporated 

by reference, see § 98.7). 

(vii) ASTM D3238–95 (Reapproved 

2005), Standard Test Method for 

Calculation of Carbon Distribution and 

Structural Group Analysis of Petroleum 

Oils by the n-d-M Method (incorporated 

by reference, see § 98.7). 

(viii) ASTM D4057–06 Standard 

Practice for Manual Sampling of 

Petroleum and Petroleum Products 

(incorporated by reference, see § 98.7). 


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(ix) ASTM D4177–95 (Reapproved 

2005) Standard Practice for Automatic 

Sampling of Petroleum and Petroleum 

Products (incorporated by reference, see 

§ 98.7). 

(x) ASTM D5291–02 (Reapproved 

2007), Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants (incorporated 

by reference, see § 98.7). 

(xi) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 

(xii) ASTM D6609–08 Standard Guide 

for Part-Stream Sampling of Coal 

(incorporated by reference, see § 98.7). 

(xiii) ASTM D6883–04 Standard 

Practice for Manual Sampling of 

Stationary Coal from Railroad Cars, 

Barges, Trucks, or Stockpiles 

(incorporated by reference, see § 98.7). 

(xiv) ASTM D7430–08ae1 Standard 

Practice for Mechanical Sampling of 

Coal (incorporated by reference, see 

§ 98.7). 

(xv) ASTM UOP539–97 Refinery Gas 

Analysis by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(xvi) GPA 2261–00 Analysis for 

Natural Gas and Similar Gaseous 

Mixtures by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(xvii) ISO 3170: Petroleum Liquids— 

Manual sampling—Third Edition 

(incorporated by reference, see § 98.7). 

(xviii) ISO 3171: Petroleum Liquids— 

Automatic pipeline sampling—Second 

Edition (incorporated by reference, see 

§ 98.7). 

(c) For units using the calculation 

methodologies described in this section, 

the records required under § 98.3(g) 

must include both the company records 

and a detailed explanation of how 

company records are used to estimate 

the following: 

(1) Fuel and feedstock consumption, 

when solid fuel and feedstock is 

combusted and a CEMS is not used to 

measure GHG emissions. 

(2) Fossil fuel consumption, when, 

pursuant to § 98.33(e), the owner or 

operator of a unit that uses CEMS to 

quantify CO2 emissions and that 

combusts both fossil and biogenic fuels 

separately reports the biogenic portion 

of the total annual CO2 emissions. 

(3) Sorbent usage, if the methodology 

in § 98.33(d) is used to calculate CO2

emissions from sorbent. 

(d) The owner or operator must 

document the procedures used to ensure 

the accuracy of the estimates of fuel and 

feedstock usage and sorbent usage (as 

applicable) in paragraph (b) of this 

section, including, but not limited to, 

calibration of weighing equipment, fuel 

and feedstock flow meters, and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices must also be recorded, 

and the technical basis for these 

estimates must be provided. 

§ 98.165 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions during unit 

operation), a substitute data value for 

the missing parameter must be used in 

the calculations as specified in 

paragraphs (a), (b), and (c) of this 

section: 

(a) For each missing value of the 

monthly fuel and feedstock 

consumption, the substitute data value 

must be the best available estimate of 

the fuel and feedstock consumption, 

based on all available process data (e.g., 

hydrogen production, electrical load, 

and operating hours). You must 

document and keep records of the 

procedures used for all such estimates. 

(b) For each missing value of the 

carbon content or molecular weight of 

the fuel and feedstock, the substitute 

data value must be the arithmetic 

average of the quality-assured values of 

carbon contents or molecular weight of 

the fuel and feedstock immediately 

preceding and immediately following 

the missing data incident. If no qualityassured data on carbon contents or 

molecular weight of the fuel and 

feedstock are available prior to the 

missing data incident, the substitute 

data value must be the first qualityassured value for carbon contents or 

molecular weight of the fuel and 

feedstock obtained after the missing 

data period. You must document and 

keep records of the procedures used for 

all such estimates. 

(c) For missing CEMS data, you must 

use the missing data procedures in 

§ 98.35. 

§ 98.166 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) or (b) of this section, 

as appropriate: 

(a) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.36 for the Tier 4 Calculation 

Methodology and the following 

information in this paragraph (a): 

(1) Unit identification number and 

annual CO2 process emissions. 

(2) Annual quantity of hydrogen 

produced (metric tons) for each process 

unit and for all units combined. 

(3) Annual quantity of ammonia 

produced (metric tons), if applicable, for 

each process unit and for all units 

combined. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

following information for each hydrogen 

production process unit: 

(1) Unit identification number and 

annual CO2 process emissions. 

(2) Monthly consumption of each fuel 

and feedstock used for hydrogen 

production and its type (scf of gaseous 

fuels and feedstocks, gallons of liquid 

fuels and feedstocks, kg of solid fuels 

and feedstocks). 

(3) Annual quantity of hydrogen 

produced (metric tons). 

(4) Annual quantity of ammonia 

produced, if applicable (metric tons). 

(5) Monthly analyses of carbon 

content for each fuel and feedstock used 

in hydrogen production (kg carbon/kg of 

gaseous and solid fuels and feedstocks, 

(kg carbon per gallon of liquid fuels and 

feedstocks). 

(6) Monthly analyses of the molecular 

weight of gaseous fuels and feedstocks 

(kg/kg-mole) used, if any. 

(c) Quarterly quantity of CO2 collected 

and transferred off site in either gas, 

liquid, or solid forms (kg), following the 

requirements of subpart PP of this part. 

(d) Annual quantity of carbon other 

than CO2 collected and transferred off 

site in either gas, liquid, or solid forms 

(kg carbon). 

§ 98.167 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 (b) of this section for each 

hydrogen production facility. 

(a) If a CEMS is used to measure CO2

emissions, then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology in 

§ 98.37. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must retain 

records of all analyses and calculations 

conducted as listed in §§ 98.166(b), (c), 

and (d). 

§ 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 


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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 under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit following the 

requirements of subpart C except for 

flares. Stationary combustion units 

include, but are not limited to, byproduct recovery coke oven battery 

combustion stacks, blast furnace stoves, 

boilers, process heaters, reheat furnaces, 

annealing furnaces, flame suppression, 

ladle reheaters, and other miscellaneous 

combustion sources. 

(b) You must report CO2 emissions 

from flares according to the procedures 

in § 98.253(b)(1) of subpart Y (Petroleum 

Refineries) of this part except you must 

use the default CO2 emission factors for 

coke oven gas and blast furnace gas from 

Table C–1 of subpart C in Equation Y– 

1 of subpart Y of this part. You must 

report CH4 and N2O emissions from 

flares according to the requirements in 

§ 98.33(c)(2) using the emission factors 

for coke oven gas and blast furnace gas 

in Table C–2 of subpart C of this part. 

(c) You must report process CO2

emissions from each taconite indurating 

furnace; basic oxygen furnace; nonrecovery coke oven battery combustion 

stack; coke pushing process; sinter 

process; EAF; argon-oxygen 

decarburization vessel; and direct 

reduction furnace by following the 

procedures in this subpart. 

§ 98.173 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

taconite indurating furnace, basic 

oxygen furnace, non-recovery coke oven 

battery, sinter process, EAF, argonoxygen decarburization vessel, and 

direct reduction furnace using the 

procedures in either paragraph (a) or (b) 

of this section. Calculate and report the 

annual process CO2 emissions from the 

coke pushing process according to 

paragraph (c) of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the process CO2 emissions using 

the procedure in paragraph (b)(1) or 

(b)(2) of this section. 

(1) Carbon mass balance method. 

Calculate the annual mass emissions of 

CO2 for the process as specified in 

paragraphs (b)(1)(i) through (b)(1)(vii) of 

this section. The calculations are based 

on the annual mass of inputs and 

outputs to the process and an annual 

analysis of the respective weight 

fraction of carbon as determined 

according to the procedures in 

§ 98.174(b). If you have a process input 

or output other than CO2 in the exhaust 

gas that contains carbon that is not 

included in Equations Q–1 through Q– 

7 of this section, you must account for 

the carbon and mass rate of that process 

input or output in your calculations 

according to the procedures in 

§ 98.174(b)(5). 

(i) For taconite indurating furnaces, 

estimate CO2 emissions using Equation 

Q–1 of this section. 

CO F F C MW

MVC 2 s sf g gf l lf F C 44

12 = ∗ ( ) ∗ ( ) C + ( ) ∗ ( ) ∗ ∗+ 0 001 0 0 . .0 ( ) ∗ ( ) ∗ 01+ ( ) ∗ ( ) − ( ) ∗ ( ) − ∗ ( ) ⎡

⎣

⎢ ⎤

⎦

⎥ OC PC o p ( ) R CR (Eq. Q-1)

Where: 

CO2 = Annual CO2 mass emissions from the 

taconite indurating furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(Fs) = Annual mass of the solid fuel 

combusted (metric tons). 

(Csf) = Carbon content of the solid fuel, from 

the fuel analysis (percent by weight, 

expressed as a decimal fraction, e.g., 

95% = 0.95). 

(Fg) = Annual volume of the gaseous fuel 

combusted (scf). 

(Cgf) = Average carbon content of the gaseous 

fuel, from the fuel analysis results (kg C 

per kg of fuel). 

MW = Molecular weight of the gaseous fuel 

(kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

0.001 = Conversion factor from kg to metric 

tons. 

(Fl) = Annual volume of the liquid fuel 

combusted (gallons). 

(Clf) = Carbon content of the liquid fuel, from 

the fuel analysis results (kg C per gallon 

of fuel). 

(O) = Annual mass of greenball (taconite) 

pellets fed to the furnace (metric tons). 

(C0) = Carbon content of the greenball 

(taconite) pellets, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(P) = Annual mass of fired pellets produced 

by the furnace (metric tons). 

(Cp) = Carbon content of the fired pellets, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(ii) For basic oxygen process furnaces, 

estimate CO2 emissions using Equation 

Q–2 of this section. 

CO Iron Scrap C Flux C 2 Iron Scrap Flux

44

12 = ∗ ( ) ∗ ( ) C + ( ) ∗ ( ) + ( ) ∗( )

(Eq. Q- ) 2

⎡

⎣

+( ) Carbon C Steel C Slag C ∗ ( ) − ( ) ∗ ( ) − ( ) ∗ Carbon Steel Slag ( ) − ∗ ( )⎤

⎦ ( ) R CR


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Where: 

CO2 = Annual CO2 mass emissions from the 

basic oxygen furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(Iron) = Annual mass of molten iron charged 

to the furnace (metric tons). 

(CIron) = Carbon content of the molten iron, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(Scrap) = Annual mass of ferrous scrap 

charged to the furnace (metric tons). 

(CScrap) = Carbon content of the ferrous scrap, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the 

furnace (metric tons). 

(CFlux) = Carbon content of the flux materials, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(Carbon) = Annual mass of carbonaceous 

materials (e.g., coal, coke) charged to the 

furnace (metric tons). 

(CCarbon) = Carbon content of the 

carbonaceous materials, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(Steel) = Annual mass of molten raw steel 

produced by the furnace (metric tons). 

(CSteel) = Carbon content of the steel, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Slag) = Annual mass of slag produced by the 

furnace (metric tons). 

(CSlag) = Carbon content of the slag, from the 

carbon analysis (percent by weight, 

expressed as a decimal fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(iii) For non-recovery coke oven 

batteries, estimate CO2 emissions using 

Equation Q–3 of this section. 

CO Coal Coke C 2 Coal Coke

44

12 = ∗ ⎡( ) ∗ ( ) − ( ) ∗ ( ) − ∗ ( ) ⎣ ⎤

⎦ C RCR () ( . 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) = Annual mass of coal charged to the 

battery (metric tons). 

(CCoal) = Carbon content of the coal, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Coke) = Annual mass of coke produced by 

the battery (metric tons). 

(CCoke) = Carbon content of the coke, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(iv) For sinter processes, estimate CO2

emissions using Equation Q–4 of this 

section. 

CO F MW

MVC 2 g gf Feed Feed C 44

12 = ∗ ⎡( ) ∗ ( ) ∗ 0 001 ⎣ C ∗ + . Sinter ( ) ∗ ( ) − ( ) ∗ ( ) − ∗ ( )⎤

⎦ CSinter ( ) R CR ( . Eq Q-4)

Where: 

CO2 = Annual CO2 mass emissions from the 

sinter process (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(Fg) = Annual volume of the gaseous fuel 

combusted (scf). 

(Cgf) = Carbon content of the gaseous fuel, 

from the fuel analysis results (kg C per 

kg of fuel). 

MW = Molecular weight of the gaseous fuel 

(kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

0.001 = Conversion factor from kg to metric 

tons. 

(Feed) = Annual mass of sinter feed material 

(metric tons). 

(CFeed) = Carbon content of the mixed sinter 

feed materials that form the bed entering 

the sintering machine, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(Sinter) = Annual mass of sinter produced 

(metric tons). 

(CSinter) = Carbon content of the sinter pellets, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(v) For EAFs, estimate CO2 emissions 

using Equation Q–5 of this section. 

CO Iron Scrap C Flux

C El

Iron Scrap

f

2

44

12 = ∗ ( ) ∗ ( ) + ( ) ∗ ( ) + ( ) ⎡

⎣

∗( ) +

C

ectrode Carbon C Steel

C

Electrode c

St

( ) ∗ ( ) + ( ) ∗ ( ) − ( )

∗

C (Eq. Q- ) 5

eel Slag ( ) − ( ) Slag C ∗ ( ) − ∗ ( ) R C( ) R

Where: 

CO2 = Annual CO2 mass emissions from the 

EAF (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(Iron) = Annual mass of direct reduced iron 

(if any) charged to the furnace (metric 

tons). 

(CIron) = Carbon content of the direct reduced 

iron, from the carbon analysis results 

(percent by weight, expressed as a 

decimal fraction). 

(Scrap) = Annual mass of ferrous scrap 

charged to the furnace (metric tons). 

(CScrap) = Carbon content of the ferrous scrap, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(Flux) = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the 

furnace (metric tons). 

(CFlux) = Carbon content of the flux materials, 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 


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(Electrode) = Annual mass of carbon 

electrode consumed (metric tons). 

(CElectrode) = Carbon content of the carbon 

electrode, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(Carbon) = Annual mass of carbonaceous 

materials (e.g., coal, coke) charged to the 

furnace (metric tons). 

(CCarbon) = Carbon content of the 

carbonaceous materials, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(Steel) = Annual mass of molten raw steel 

produced by the furnace (metric tons). 

(CSteel) = Carbon content of the steel, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Slag) = Annual mass of slag produced by the 

furnace (metric tons). 

(CSlag) = Carbon content of the slag, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(vi) For argon-oxygen decarburization 

vessels, estimate CO2 emissions using 

Equation Q–6 of this section. 

CO Steel C 2 Steelin Steelout

44

12 = ∗ ( ) ∗ ⎡( ) − ( ) ⎣ ⎤

⎦ C RC − ∗ ( ) R () ( . 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) = Annual mass of molten steel 

charged to the vessel (metric tons). 

(CSteelin) = Carbon content of the molten steel 

before decarburization, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(CSteelout) = Carbon content of the molten steel 

after decarburization, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(vii) For direct reduction furnaces, 

estimate CO2 emissions using Equation 

Q–7 of this section. 

CO F C MW

MVC 2 = ∗ ( ) g gf Ore ∗( ) ∗ ∗+ ( ) Ore C ∗ (Eq. Q-7) ⎡

⎣

⎢

+

44

12

0 001 . ()

( (

( (

Carbon C Other C

Iron C NM

Carbon Other

Iron

) )

)

∗( ) + ∗( )

− ) ( ) − ∗( ) C RC NM R − ∗ ( )⎤

⎦ ( )

Where: 

CO2 = Annual CO2 mass emissions from the 

direct reduction furnace (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(Fg) = Annual volume of the gaseous fuel 

combusted (scf). 

(Cgf) = Carbon content of the gaseous fuel, 

from the fuel analysis results (kg C per 

kg of fuel). 

MW = Molecular weight of the gaseous fuel 

(kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

0.001 = Conversion factor from kg to metric 

tons. 

(Ore) = Annual mass of iron ore or iron ore 

pellets fed to the furnace (metric tons). 

(COre) = Carbon content of the iron ore or iron 

ore pellets, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(Carbon) = Annual mass of carbonaceous 

materials (e.g., coal, coke) charged to the 

furnace (metric tons). 

(CCarbon) = Carbon content of the 

carbonaceous materials, from the carbon 

analysis results (percent by weight, 

expressed as a decimal fraction). 

(Other) = Annual mass of other materials 

charged to the furnace (metric tons). 

(COther) = Average carbon content of the other 

materials charged to the furnace, from 

the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(Iron) = Annual mass of iron produced 

(metric tons). 

(CIron) = Carbon content of the iron, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

(NM) = Annual mass of non-metallic 

materials produced by the furnace 

(metric tons). 

(CNM) = Carbon content of the non-metallic 

materials, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(R) = Annual mass of air pollution control 

residue collected (metric tons). 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (percent by weight, expressed as 

a decimal fraction). 

(2) Site-specific emission factor 

method. Conduct a performance test and 

measure CO2 emissions from all exhaust 

stacks for the process and measure 

either the feed rate of materials into the 

process or the production rate during 

the test as described in paragraphs 

(b)(2)(i) through (b)(2)(iv) of this section. 

(i) You must measure the process 

production rate or process feed rate, as 

applicable, during the performance test 

according to the procedures in 

§ 98.174(c)(5) and calculate the average 

rate for the test period in metric tons per 

hour. 

(ii) You must calculate the hourly CO2

emission rate using Equation Q–8 of this 

section and determine the average 

hourly CO2 emission rate for the test. 

CO C H O

2 CO

7 2 5 18 10 100

100 = ⎛ −

⎝

⎜ ⎞

⎠

⎟ − . % x (Eq. Q-8) 2 Q

Where: CO2 = CO2 mass emission rate, corrected for 

moisture (metric tons/hr). 

5.18 × 10¥7 = Conversion factor (metric tons/ 

scf¥% CO2). 


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CCO2 = Hourly CO2 concentration, dry basis 

(% CO2). 

Q = Hourly stack gas volumetric flow rate 

(scfh). 

%H2O = Hourly moisture percentage in the 

stack gas. 

(iii) You must calculate a site-specific 

emission factor for the process in metric 

tons of CO2 per metric ton of feed or 

production, as applicable, by dividing 

the average hourly CO2 emission rate 

during the test by the average hourly 

feed or production rate during the test. 

(iv) You must calculate CO2 emissions 

for the process by multiplying the 

emission factor by the total amount of 

feed or production, as applicable, for the 

reporting period. 

(c) You must determine emissions of 

CO2 from the coke pushing process in 

mtCO2e by multiplying the metric tons 

of coal charged to the coke ovens during 

the reporting period by 0.008. 

(d) If GHG emissions from a taconite 

indurating furnace, basic oxygen 

furnace, non-recovery coke oven battery, 

sinter process, EAF, argon-oxygen 

decarburization vessel, or direct 

reduction furnace are vented through 

the same stack as any combustion unit 

or process equipment that reports CO2

emissions using a CEMS that complies 

with the Tier 4 Calculation 

Methodology in subpart C of this part 

(General Stationary Fuel Combustion 

Sources), then the calculation 

methodology in paragraph (b) of this 

section shall not be used to calculate 

process emissions. The owner or 

operator shall report under this subpart 

the combined stack emissions according 

to the Tier 4 Calculation Methodology 

in § 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

§ 98.174 Monitoring and QA/QC 

requirements. 

(a) If you operate and maintain a 

CEMS that measures CO2 emissions 

consistent with subpart C of this part, 

you must meet the monitoring and QA/ 

QC requirements of § 98.34(c). 

(b) If you determine CO2 emissions 

using the carbon mass balance 

procedure in § 98.173(b)(1), you must: 

(1) Except as provided in paragraph 

(b)(4) of this section, determine the mass 

of each process input and output other 

than fuels using the same plant 

instruments or procedures that are used 

for accounting purposes (such as weigh 

hoppers, belt weigh feeders, weighed 

purchased quantities in shipments or 

containers, combination of bulk density 

and volume measurements, etc.), record 

the totals for each process input and 

output for each calendar month, and 

sum the monthly mass to determine the 

annual mass for each process input and 

output. Determine the mass rate of fuels 

using the procedures for combustion 

units in § 98.34. 

(2) Except as provided in paragraph 

(b)(4) of this section, determine the 

carbon content of each process input 

and output annually for use in the 

applicable equations in § 98.173(b)(1) 

based on analyses provided by the 

supplier or by the average carbon 

content determined by collecting and 

analyzing at least three samples each 

year using the standard methods 

specified in paragraphs (b)(2)(i) through 

(b)(2)(vi) of this section as applicable. 

(i) ASTM C25–06, Standard Test 

Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference, see 

§ 98.7) for limestone, dolomite, and slag. 

(ii) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7) 

for coal, coke, and other carbonaceous 

materials. 

(iii) ASTM E1915–07a, Standard Test 

Methods for Analysis of Metal Bearing 

Ores and Related Materials by 

Combustion Infrared-Absorption 

Spectrometry (incorporated by 

reference, see § 98.7) for iron ore, 

taconite pellets, and other iron-bearing 

materials. 

(iv) ASTM E1019–08, Standard Test 

Methods for Determination of Carbon, 

Sulfur, Nitrogen, and Oxygen in Steel, 

Iron, Nickel, and Cobalt Alloys by 

Various Combustion and Fusion 

Techniques (incorporated by reference, 

see § 98.7) for iron and ferrous scrap. 

(v) ASM CS–104 UNS No. G10460— 

Alloy Digest April 1985 (Carbon Steel of 

Medium Carbon Content) (incorporated 

by reference, see § 98.7); ISO/TR 15349– 

1:1998, Unalloyed steel—Determination 

of low carbon content, Part 1: Infrared 

absorption method after combustion in 

an electric resistance furnace (by peak 

separation) (1998–10–15) First Edition 

(incorporated by reference, see § 98.7); 

or ISO/TR 15349–3:1998, Unalloyed 

steel-Determination of low carbon 

content Part 3: Infrared absorption 

method after combustion in an electric 

resistance furnace (with preheating) 

(1998–10–15) First Edition 

(incorporated by reference, see § 98.7) as 

applicable for steel. 

(vi) For each process input that is a 

fuel, determine the carbon content and 

molecular weight (if applicable) using 

the applicable methods listed in § 98.34. 

(3) For solid ferrous materials charged 

to basic oxygen process furnaces or 

EAFs that differ in carbon content, you 

may determine a weighted average 

carbon content based on the carbon 

content of each type of ferrous material 

and the average weight percent of each 

type that is used. Examples of these 

different ferrous materials include 

carbon steel, low carbon steel, stainless 

steel, high alloy steel, pig iron, iron 

scrap, and direct reduced iron. 

(4) If you document that a specific 

process input or output contributes less 

than one percent of the total mass of 

carbon into or out of the process, you do 

not have to determine the monthly mass 

or annual carbon content of that input 

or output. 

(5) Except as provided in paragraph 

(b)(4) of this section, you must 

determine the annual carbon content 

and monthly mass rate of any input or 

output that contains carbon that is not 

listed in the equations in § 98.173(b)(1) 

using the procedures in paragraphs 

(b)(1) and (b)(2) of this section. 

(c) If you determine CO2 emissions 

using the site-specific emission factor 

procedure in § 98.173(b)(2), you must: 

(1) Conduct an annual performance 

test that is based on representative 

performance (i.e., performance based on 

normal operating conditions) of the 

affected process. 

(2) For the furnace exhaust from basic 

oxygen furnaces, EAFs, argon-oxygen 

decarburization vessels, and direct 

reduction furnaces, sample the furnace 

exhaust for at least three complete 

production cycles that start when the 

furnace is being charged and end after 

steel or iron and slag have been tapped. 

For EAFs that produce both carbon steel 

and stainless or specialty (low carbon) 

steel, develop an emission factor for the 

production of both types of steel. 

(3) For taconite indurating furnaces, 

non-recovery coke batteries, and sinter 

processes, sample for at least 3 hours. 

(4) Conduct the stack test using EPA 

Method 3A at 40 CFR part 60, appendix 

A–2 to measure the CO2 concentration, 

Method 2, 2A, 2C, 2D, or 2F at 40 CFR 

part 60, appendix A–1 or Method 26 at 

40 CFR part 60, appendix A–2 to 

determine the stack gas volumetric flow 

rate, and Method 4 at 40 CFR part 60, 

at appendix A–3 to determine the 

moisture content of the stack gas. 

(5) Determine the mass rate of process 

feed or process production (as 

applicable) during the test using the 

same plant instruments or procedures 

that are used for accounting purposes 

(such as weigh hoppers, belt weigh 

feeders, combination of bulk density 

and volume measurements, etc.) 

(6) If your process operates under 

different conditions as part of normal 

operations in such a manner that CO2

emissions change by more than 20 


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percent (e.g., routine changes in the 

carbon content of the sinter feed or 

change in grade of product), you must 

perform emission testing and develop 

separate emission factors for these 

different operating conditions and 

determine emissions based on the 

number of hours the process operates 

and the production or feed rate (as 

applicable) at each specific different 

condition. 

(7) If your EAF and argon-oxygen 

decarburization vessel exhaust to a 

common emission control device and 

stack, you must sample each process in 

the ducts before the emissions are 

combined, sample each process when 

only one process is operating, or sample 

the combined emissions when both 

processes are operating and base the 

site-specific emission factor on the steel 

production rate of the EAF. 

(8) The results of a performance test 

must include the analysis of samples, 

determination of emissions, and raw 

data. The performance test report must 

contain all information and data used to 

derive the emission factor. 

(d) For a coke pushing process, 

determine the metric tons of coal 

charged to the coke ovens and record 

the totals for each pushing process for 

each calendar month. Coal charged to 

coke ovens can be measured using 

weigh belts or a combination of 

measuring volume and bulk density. 

§ 98.175 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.173 is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in the 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) For each missing data for the 

carbon content of inputs and outputs for 

facilities that estimate emissions using 

the carbon mass balance procedure in 

§ 98.173(b)(1) or for facilities that 

estimate emissions using the sitespecific emission factor procedure in 

§ 98.173(b)(2); 100 percent data 

availability is required. You must repeat 

the test for average carbon contents of 

inputs and outputs according to the 

procedures in § 98.174(b)(2). Similarly, 

you must repeat the test to determine 

the site-specific emission factor if data 

on the CO2 emission rate, process 

production rate or process feed rate are 

missing. 

(b) For missing records of the monthly 

mass or volume of carbon-containing 

inputs and outputs using the carbon 

mass balance procedure in 

§ 98.173(b)(1), the substitute data value 

must be based on the best available 

estimate of the mass of the input or 

output material from all available 

process data or data used for accounting 

purposes. 

§ 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 (f) of this 

section for each coke pushing operation; 

taconite indurating furnace; basic 

oxygen furnace; non-recovery coke oven 

battery; sinter process; EAF; argonoxygen decarburization vessel; and 

direct reduction furnace: 

(a) Unit identification number and 

annual CO2 emissions (in metric tons). 

(b) Annual production quantity (in 

metric tons) for taconite pellets, coke, 

sinter, iron, and raw steel. 

(c) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.37 for the Tier 4 Calculation 

Methodology. 

(d) If a CEMS is not used to measure 

CO2 emissions, then you must report for 

each process whether the emissions 

were determined using the carbon mass 

balance method in § 98.173(b)(1) or the 

site-specific emission factor method in 

§ 98.173(b)(2). 

(e) If you use the carbon mass balance 

method in § 98.173(b)(1) to determine 

CO2 emissions, you must report the 

following information for each process: 

(1) The carbon content of each process 

input and output used to determine CO2

emissions. 

(2) Whether the carbon content was 

determined from information from the 

supplier or by laboratory analysis, and 

if by laboratory analysis, the method 

used. 

(3) The annual volume of gaseous fuel 

(in standard cubic feet), the annual 

volume of liquid fuel (in gallons), and 

the annual mass (in metric tons) of all 

other process inputs and outputs used 

to determine CO2 emissions. 

(4) The molecular weight of gaseous 

fuels. 

(5) If you used the missing data 

procedures in § 98.175(b), you must 

report how the monthly mass for each 

process input or output with missing 

data was determined and the number of 

months the missing data procedures 

were used. 

(f) If you used the site-specific 

emission factor method in § 98.173(b)(2) 

to determine CO2 emissions, you must 

report the following information for 

each process: 

(1) The measured average hourly CO2

emission rate during the test (in metric 

tons per hour). 

(2) The average hourly feed or 

production rate (as applicable) during 

the test (in metric tons per hour). 

(3) The site-specific emission factor 

(in metric tons of CO2 per metric ton of 

feed or production, as applicable). 

(4) The annual feed or production rate 

(as applicable) used to estimate annual 

CO2 emissions (in metric tons). 

§ 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 (e) of 

this section, as applicable. Facilities that 

use CEMS to measure emissions must 

also retain records of the verification 

data required for the Tier 4 Calculating 

Methodology in § 98.36(e). 

(a) Records of all analyses and 

calculations conducted, including all 

information reported as required under 

§ 98.176. 

(b) When the carbon mass balance 

method is used to estimate emissions for 

a process, the monthly mass of each 

process input and output that are used 

to determine the annual mass. 

(c) Production capacity (in metric tons 

per year) for the production of taconite 

pellets, coke, sinter, iron, and raw steel. 

(d) Annual operating hours for 

taconite furnaces, coke oven batteries, 

sinter production, blast furnaces, direct 

reduced iron furnaces, and electric arc 

furnaces. 

(e) Facilities must keep records that 

include a detailed explanation of how 

company records or measurements are 

used to determine all sources of carbon 

input and output and the metric tons of 

coal charged to the coke ovens (e.g., 

weigh belts, a combination of measuring 

volume and bulk density). You also 

must document the procedures used to 

ensure the accuracy of the 

measurements of fuel usage including, 

but not limited to, calibration of 

weighing equipment, fuel flow meters, 

coal usage including, but not limited to, 

calibration of weighing equipment and 

other measurement devices. The 

estimated accuracy of measurements 

made with these devices must also be 

recorded, and the technical basis for 

these estimates must be provided. 

§ 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. 


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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 (a)(2). 

§ 98.182 GHGs to report. 

You must report: 

(a) Process CO2 emissions from each 

smelting furnace used for lead 

production. 

(b) CO2 combustion emissions from 

each smelting furnace used for lead 

production. 

(c) CH4 and N2O combustion 

emissions from each smelting furnace 

used for lead production. You must 

calculate and report these emissions 

under subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from 

each stationary combustion unit other 

than smelting furnaces used for lead 

production. You must report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

§ 98.183 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

smelting furnace using the procedure in 

paragraphs (a) and (b) of this section. 

(a) For each smelting furnace that 

meets the conditions specified in 

§ 98.33(b)(4)(ii) or (b)(4)(iii), you must 

calculate and report combined process 

and combustion CO2 emissions by 

operating and maintaining a CEMS to 

measure CO2 emissions according to the 

Tier 4 Calculation Methodology 

specified in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) For each smelting furnace that is 

not subject to the requirements in 

paragraph (a) of this section, calculate 

and report the process and combustion 

CO2 emissions from the smelting 

furnace by using the procedure in either 

paragraph (b)(1) or (b)(2) of this section. 

(1) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 

and maintaining a CEMS to measure 

CO2 emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(2) Calculate and report process and 

combustion CO2 emissions separately 

using the procedures specified in 

paragraphs (b)(2)(i) through (b)(2)(iii) of 

this section. 

(i) For each smelting furnace, 

determine the annual mass of carbon in 

each carbon-containing material, other 

than fuel, that is fed, charged, or 

otherwise introduced into the smelting 

furnace and estimate annual process 

CO2 emissions using Equation R–1 of 

this section. Carbon-containing 

materials include carbonaceous 

reducing agents. If you document that a 

specific material contributes less than 1 

percent of the total carbon into the 

process, you do not have to include the 

material in your calculation using 

Equation R–1 of this section. 

E 2000

2205 CO2

44

12

=× × × ( ) Ore C Scrap C Flux C Ore Scrap Flux + × ( ) + × ( ) + ( ) Carbon C Other C × Carbon Other + × ( ) ⎡

⎣ ⎤⎦ (Eq. R-1)

Where: 

ECO2 = Annual process CO2 emissions from 

an individual smelting furnace (metric 

tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

Ore = Annual mass of lead ore charged to the 

smelting furnace (tons). 

COre = Carbon content of the lead ore, from 

the carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

Scrap = Annual mass of lead scrap charged 

to the smelting furnace (tons). 

CScrap = Carbon content of the lead scrap, 

from the carbon analysis (percent by 

weight, expressed as a decimal fraction). 

Flux = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to the 

smelting furnace (tons). 

CFlux = Carbon content of the flux materials, 

from the carbon analysis (percent by 

weight, expressed as a decimal fraction). 

Carbon = Annual mass of carbonaceous 

materials (e.g., coal, coke) charged to the 

smelting furnace (tons). 

CCarbon = Carbon content of the carbonaceous 

materials, from the carbon analysis 

(percent by weight, expressed as a 

decimal fraction). 

Other = Annual mass of any other material 

containing carbon, other than fuel, fed, 

charged, or otherwise introduced into 

the smelting furnace (tons). 

COther = Carbon content of the other material 

from the carbon analysis results (percent 

by weight, expressed as a decimal 

fraction). 

(ii) Determine the combined annual 

process CO2 emissions from the 

smelting furnaces at your facility using 

Equation R–2 of this section. 

CO = E (Eq. R-2) 2 CO2

1

k

∑ k

Where: 

CO2 = Annual process CO2 emissions from 

smelting furnaces at facility used for lead 

production (metric tons). 

ECO2k = Annual process CO2 emissions from 

smelting furnace k calculated using 

Equation R–1 of this section (metric 

tons/year). 

k = Total number of smelting furnaces at 

facility used for lead production. 

(iii) Calculate and report under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) 

the combustion CO2 emissions from the 

smelting furnaces according to the 

applicable requirements in subpart C. 

§ 98.184 Monitoring and QA/QC 

requirements. 

If you determine process CO2

emissions using the carbon mass 

balance procedure in § 98.183(b)(2)(i) 

and (b)(2)(ii), you must meet the 

requirements specified in paragraphs (a) 

and (b) of this section. 

(a) Determine the annual mass for 

each material used for the calculations 

of annual process CO2 emissions using 

Equation R–1 of this subpart by 

summing the monthly mass for the 

material determined for each month of 

the calendar year. The monthly mass 

may be determined using plant 

instruments used for accounting 

purposes, including either direct 

measurement of the quantity of the 

material placed in the unit or by 

calculations using process operating 

information. 

(b) For each material identified in 

paragraph (a) of this section, you must 

determine the average carbon content of 


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the material consumed or used in the 

calendar year using the methods 

specified in either paragraph (b)(1) or 

(b)(2) of this section. If you document 

that a specific process input or output 

contributes less than one percent of the 

total mass of carbon into or out of the 

process, you do not have to determine 

the monthly mass or annual carbon 

content of that input or output. 

(1) Information provided by your 

material supplier. 

(2) Collecting and analyzing at least 

three representative samples of the 

material each year. The carbon content 

of the material must be analyzed at least 

annually using the methods (and their 

QA/QC procedures) specified in 

paragraphs (b)(2)(i) through (b)(2)(iii) of 

this section, as applicable. 

(i) ASTM E1941–04, Standard Test 

Method for Determination of Carbon in 

Refractory and Reactive Metals and 

Their Alloys (incorporated by reference, 

see § 98.7) for analysis of metal ore and 

alloy product. 

(ii) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7), 

for analysis of carbonaceous reducing 

agents and carbon electrodes. 

(iii) ASTM C25–06, Standard Test 

Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference, see 

§ 98.7) for analysis of flux materials 

such as limestone or dolomite. 

§ 98.185 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.183 is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in the 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) For each missing data for the 

carbon content for the smelting furnaces 

at your facility that estimate annual 

process CO2 emissions using the carbon 

mass balance procedure in 

§ 98.183(b)(2)(i) and (ii), 100 percent 

data availability is required. You must 

repeat the test for average carbon 

contents of inputs according to the 

procedures in § 98.184(b) if data are 

missing. 

(b) For missing records of the monthly 

mass of carbon-containing materials, the 

substitute data value must be based the 

best available estimate of the mass of the 

material from all available process data 

or data used for accounting purposes 

(such as purchase records). 

§ 98.186 Data reporting procedures. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) or (b) of this section, 

as applicable. 

(a) If a CEMS is used to measure CO2

emissions according to the requirements 

in § 98.183(a) or (b)(1), then you must 

report under this subpart the relevant 

information required by § 98.36 and the 

information specified in paragraphs 

(a)(1) through (a)(4) of this section. 

(1) Identification number of each 

smelting furnace. 

(2) Annual lead product production 

capacity (tons). 

(3) Annual production for each lead 

product (tons). 

(4) Total number of smelting furnaces 

at facility used for lead production. 

(b) If a CEMS is not used to measure 

CO2 emissions, and you measure CO2

emissions according to the requirements 

in § 98.183(b)(2)(i) and (b)(2)(ii), then 

you must report the information 

specified in paragraphs (b)(1) through 

(b)(9) of this section. 

(1) Identification number of each 

smelting furnace. (2) Annual process 

CO2 emissions (in metric tons) from 

each smelting furnace as determined by 

Equation R–1 of this subpart. 

(3) Annual lead product production 

capacity for the facility and each 

smelting furnace(tons). 

(4) Annual production for each lead 

product (tons). 

(5) Total number of smelting furnaces 

at facility used for production of lead 

products reported in paragraph (b)(4) of 

this section. 

(6) Annual material quantity for each 

material used for the calculation of 

annual process CO2 emissions using 

Equation R–1 of this subpart for each 

smelting furnace (tons). 

(7) Annual average of the carbon 

content determinations for each material 

used for the calculation of annual 

process CO2 emissions using Equation 

R–1 of this subpart for each smelting 

furnace. 

(8) List the method used for the 

determination of carbon content for 

each material reported in paragraph 

(b)(7) of this section (e.g., supplier 

provided information, analyses of 

representative samples you collected). 

(9) If you use the missing data 

procedures in § 98.185(b), you must 

report how the monthly mass of carboncontaining materials with missing data 

was determined and the number of 

months the missing data procedures 

were used. 

§ 98.187 Records that must be retained. 

In addition to the records required by 

§ 98.3(g), each annual report must 

contain the information specified in 

paragraphs (a) through (c) of this 

section, as applicable to the smelting 

furnaces at your facility. 

(a) If a CEMS is used to measure 

combined process and combustion CO2

emissions according to the requirements 

in § 98.183(a) or (b)(1), then you must 

retain the records required for the Tier 

4 Calculation Methodology in § 98.37 

and the information specified in 

paragraphs (a)(1) through (a)(3) of this 

section. 

(1) Monthly smelting furnace 

production quantity for each lead 

product (tons). 

(2) Number of smelting furnace 

operating hours each month. 

(3) Number of smelting furnace 

operating hours in calendar year. 

(b) If the carbon mass balance 

procedure is used to determine process 

CO2 emissions according to the 

requirements in § 98.183(b)(2)(i) and 

(b)(2)(ii), then you must retain under 

this subpart the records specified in 

paragraphs (b)(1) through (b)(5) of this 

section. 

(1) Monthly smelting furnace 

production quantity for each lead 

product (tons). 

(2) Number of smelting furnace 

operating hours each month. 

(3) Number of smelting furnace 

operating hours in calendar year. 

(4) Monthly material quantity 

consumed, used, or produced for each 

material included for the calculations of 

annual process CO2 emissions using 

Equation R–1 of this subpart (tons). 

(5) Average carbon content 

determined and records of the supplier 

provided information or analyses used 

for the determination for each material 

included for the calculations of annual 

process CO2 emissions using Equation 

R–1 of this subpart. 

(c) You must keep records that 

include a detailed explanation of how 

company records of measurements are 

used to estimate the carbon input to 

each smelting furnace, including 

documentation of any materials 

excluded from Equation R–1 of this 

subpart that contribute less than 1 

percent of the total carbon into or out 

of the process. You also must document 

the procedures used to ensure the 

accuracy of the measurements of 

materials fed, charged, or placed in an 

smelting furnace including, but not 

limited to, calibration of weighing 

equipment and other measurement 

devices. The estimated accuracy of 

measurements made with these devices 

must also be recorded, and the technical 


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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. 

(a) Lime manufacturing plants (LMPs) 

engage in the manufacture of a lime 

product (e.g., calcium oxide, highcalcium quicklime, calcium hydroxide, 

hydrated lime, dolomitic quicklime, 

dolomitic hydrate, or other products) by 

calcination of limestone, dolomite, 

shells or other cacareous substances as 

defined in 40 CFR 63.7081(a)(1). 

(b) This source category includes all 

LMPs unless the LMP is located at a 

kraft pulp mill, soda pulp mill, sulfite 

pulp mill, or only processes sludge 

containing calcium carbonate from 

water softening processes. The lime 

manufacturing source category consists 

of marketed and non-marketed lime 

manufacturing facilities. 

(c) Lime kilns at pulp and paper 

manufacturing facilities must report 

emissions under subpart AA of this part 

(Pulp and Paper Manufacturing). 

§ 98.191 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility is a 

lime manufacturing plant as defined in 

§ 98.190 and the facility meets the 

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

(a)(2). 

§ 98.192 GHGs to report. 

You must report: 

(a) CO2 process emissions from lime 

kilns. 

(b) CO2 emissions from fuel 

combustion at lime kilns. 

(c) N2O and CH4 emissions from fuel 

combustion at each lime kiln. You must 

report these emissions under 40 CFR 

part 98, subpart C (General Stationary 

Fuel Combustion Sources). 

(d) CO2, N2O, and CH4 emissions from 

each stationary fuel combustion unit 

other than lime kilns. You must report 

these emissions under 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources). 

(e) CO2 collected and transferred off 

site under 40 CFR part 98, following the 

requirements of subpart PP of this part 

(Suppliers of Carbon Dioxide (CO2)). 

§ 98.193 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from all 

lime kilns combined using the 

procedure in paragraphs (a) and (b) of 

this section. 

(a) If all lime kilns meet the 

conditions specified in § 98.33(b)(4)(ii) 

or (b)(4)(iii), you must calculate and 

report under this subpart the combined 

process and combustion CO2 emissions 

by operating and maintaining a CEMS to 

measure CO2 emissions according to the 

Tier 4 Calculation Methodology 

specified in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) If CEMS are not required to be 

used to determine CO2 emissions from 

all lime kilns under paragraph (a) of this 

section, then you must calculate and 

report the process and combustion CO2

emissions from the lime kilns by using 

the procedures in either paragraph (b)(1) 

or (b)(2) of this section. 

(1) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 

and maintaining a CEMS to measure 

CO2 emissions from all lime kilns 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(2) Calculate and report process and 

combustion CO2 emissions separately 

using the procedures specified in 

paragraphs (b)(2)(i) through (b)(2)(v) of 

this section. 

(i) You must calculate a monthly 

emission factor for each type of lime 

produced using Equation S–1 of this 

section. Calcium oxide and magnesium 

oxide content must be analyzed 

monthly for each lime type: 

EF SR CaO SR MgO LIME,i,n CaO i,n MgO i,n = ∗ ⎡( ) ( ) ∗ ⎣ ⎤

⎦ + ( ∗ 2000

2205

Eq. S-1)

Where: 

EFLIME,i,n = Emission factor for lime type i, for 

month n (metric tons CO2/ton lime). 

SRCaO = Stoichiometric ratio of CO2 and CaO 

for calcium carbonate [see Table S–1 of 

this subpart] (metric tons CO2/metric 

tons CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO 

for magnesium carbonate (See Table S– 

1 of this subpart) (metric tons CO2/metric 

tons MgO). 

CaOi,n = Calcium oxide content for lime type 

i, for month n, determined according to 

§ 98.194(c) (metric tons CaO/metric ton 

lime). 

MgOi,n = Magnesium oxide content for lime 

type i, for month n, determined 

according to § 98.194(c) (metric tons 

MgO/metric ton lime). 

2000/2205 = Conversion factor for metric 

tons to tons. 

(ii) You must calculate a monthly 

emission factor for each type of 

byproduct/waste sold (including 

lime kiln dust) using Equation S–2 

of this section: 

EF SR CaO SR MgO LKD,i,n CaO LKD,i,n MgO LKD,i,n = ∗ ⎡( ) ( ) ∗ ⎣ ⎤

⎦ + ∗ 2000

2205 (Eq. S-2)

Where: 

EFLKD,i,n = Emission factor for sold lime 

byproduct/waste type i, for month n 

(metric tons CO2/ton lime byproduct). 

SRCaO = Stoichiometric ratio of CO2 and CaO 

for calcium carbonate (see Table S–1 of 

this subpart((metric tons CO2/metric tons 

CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO 

for magnesium carbonate (See Table S– 

1 of this subpart) (metric tons CO2/metric 

tons MgO). 

CaOLKD,i,n = Calcium oxide content for sold 

lime byproduct/waste type i, for month 

n (metric tons CaO/metric ton lime). 

MgOLKD,i,n = Magnesium oxide content for 

sold lime byproduct/waste type i, for 

month n (metric tons MgO/metric ton 

lime). 

2000/2205 = Conversion factor for metric 

tons to tons. 

(iii) You must calculate the annual 

CO2 emissions from each type of 

byproduct/waste that is not sold 

(including lime kiln dust and scrubber 

sludge) using Equation S–3 of this 

section: 


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E SR CaO SR MgO M waste,i CaO waste,i MgO waste,i w = ∗ ⎡( ) ( ) ∗ ⎣ ⎤

⎦ + ∗ aste,i ∗ 2000

2205 (Eq. S-3)

Where: 

Ewaste,i = Annual CO2 emissions for unsold 

lime byproduct/waste type i (metric tons 

CO2). 

SRCaO = Stoichiometric ratio of CO2 and CaO 

for calcium carbonate (see Table S–1 of 

this subpart) (metric tons CO2/metric 

tons CaO). 

SRMgO = Stoichiometric ratio of CO2 and MgO 

for magnesium carbonate (See Table S– 

1 of this subpart) (metric tons CO2/metric 

tons MgO). 

CaOwaste,i = Calcium oxide content for unsold 

lime byproduct/waste type i (metric tons 

CaO/metric ton lime). 

MgOwaste,i = Magnesium oxide content for 

unsold lime byproduct/waste type i 

(metric tons MgO/metric ton lime). 

Mwaste,i = Annual weight or mass of unsold 

byproducts/wastes for lime type i (tons). 

2000/2205 = Conversion factor for metric 

tons to tons. 

(iv) You must calculate annual CO2

process emissions for all kilns using 

Equation S–4 of this section: 

E EF M EF M CO LIME,i,n LIME,i,n LKD,i,n LKD,i,n

i n

b

2

1

12

1

( ) ∗ + ∗ ) = =

∑∑ ∑ ∑ ∑ +

= = =

Ewaste,i

i

z

i n

t

1 1

12

1

(Eq. S-4)

Where: 

ECO2 = Annual CO2 process emissions from 

lime production from all kilns (metric 

tons/year). 

EFLIME,i,n = Emission factor for lime type i, in 

calendar month n (metric tons CO2/ton 

lime) from Equation S–1 of this section. 

MLIME,i,n = Weight or mass of lime type i in 

calendar month n (tons). 

EFLKD,i,n = Emission factor of byproducts/ 

wastes sold for lime type i in calendar 

month n, (metric tons CO2/ton 

byproduct/waste) from Equation S–2 of 

this section. 

MLKD,i,n = Monthly weight or mass of 

byproducts/waste sold (such as lime kiln 

dust, LKD) for lime type i in calendar 

month n (tons). 

Ewaste,i = Annual CO2 emissions for unsold 

lime byproduct/waste type i (metric tons 

CO2) from Equation S–3 of this section. 

t = Number of lime types 

b = Number of byproducts/wastes sold 

z = Number of byproducts/wastes not sold 

(v) Calculate and report under subpart 

C of this part (General Stationary Fuel 

Combustion Sources) the combustion 

CO2 emissions from each lime kiln 

according to the applicable 

requirements in subpart C. 

§ 98.194 Monitoring and QA/QC 

requirements. 

(a) You must determine the total 

quantity of each product type of lime 

and each calcined byproduct/waste 

(such as lime kiln dust) that is sold. The 

quantities of each should be directly 

measured monthly with the same plant 

instruments used for accounting 

purposes, including but not limited to, 

calibrated weigh feeders, rail or truck 

scales, and barge measurements. The 

direct measurements of each lime 

product shall be reconciled annually 

with the difference in the beginning of 

and end of year inventories for these 

products, when measurements represent 

lime sold. 

(b) You must determine the annual 

quantity of each calcined byproduct/ 

waste generated that is not sold by 

either direct measurement using the 

same instruments identified in 

paragraph (a) of this section or by using 

a calcined byproduct/waste generation 

rate. 

(c) You must determine the chemical 

composition (percent total CaO and 

percent total MgO) of each type of lime 

and each type of calcined byproduct/ 

waste sold according to paragraph (c)(1) 

or (c)(2) of this section. You must 

determine the chemical composition of 

each type of lime on a monthly basis. 

You must determine the chemical 

composition for each type of calcined 

byproduct/waste that is not sold on an 

annual basis. 

(1) ASTM C25–06 Standard Test 

Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference—see 

§ 98.7). 

(2) The National Lime Association’s 

CO2 Emissions Calculation Protocol for 

the Lime Industry English Units 

Version, February 5, 2008 RevisionNational Lime Association 

(incorporated by reference—see § 98.7). 

(d) You must use the analysis of 

calcium oxide and magnesium oxide 

content of each lime product collected 

during the same month as the 

production data in monthly 

calculations. 

(e) You must follow the quality 

assurance/quality control procedures 

(including documentation) in National 

Lime Association’s CO2 Emissions 

Calculation Protocol for the Lime 

Industry English Units Version, 

February 5, 2008 Revision—National 

Lime Association (incorporated by 

reference—see § 98.7). 

§ 98.195 Procedures for estimating 

missing data. 

For the procedure in § 98.193(b)(2), a 

complete record of all measured 

parameters used in the GHG emissions 

calculations is required (e.g., oxide 

content, quantity of lime products, etc.). 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in 

paragraphs (a) or (b) of this section. You 

must document and keep records of the 

procedures used for all such estimates. 

(a) For each missing value of the 

quantity of lime produced (by lime 

type), and quantity of byproduct/waste 

produced and sold, the substitute data 

value shall be the best available estimate 

based on all available process data or 

data used for accounting purposes. 

(b) For missing values related to the 

CaO and MgO content, you must 

conduct a new composition test 

according to the standard methods in 

§ 98.194 (c)(1) or (c)(2). 

§ 98.196 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) or (b) of this section, 

as applicable. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required by § 98.36 and the information 

listed in paragraphs (a)(1) through (a)(8) 

of this section. 

(1) Method used to determine the 

quantity of lime sold. 

(2) Method used to determine the 

quantity of lime byproduct/waste sold. 

(3) Beginning and end of year 

inventories for each lime product. 

(4) Beginning and end of year 

inventories for lime byproducts/wastes. 


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(5) Annual amount of lime byproduct/ 

waste sold, by type (tons). 

(6) Annual amount of lime product 

sold, by type (tons). 

(7) Annual amount of lime byproduct/ 

waste not sold, by type (tons). 

(8) Annual amount of lime product 

not sold, by type (tons). 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in paragraphs (b)(1) 

through (b)(17) of this section. 

(1) Annual CO2 process emissions 

from all kilns combined (metric tons). 

(2) Monthly emission factors for each 

lime type. 

(3) Monthly emission factors for each 

sold byproduct/waste by lime type. 

(4) Standard method used (ASTM or 

NLA testing method) to determine 

chemical compositions of each lime 

type and lime byproduct/waste type. 

(5) Monthly results of chemical 

composition analysis of each lime 

product and byproduct/waste sold. 

(6) Annual results of chemical 

composition analysis of each type of 

lime byproduct/waste not sold. 

(7) Method used to determine the 

quantity of lime sold. 

(8) Monthly amount of lime product 

sold, by type (tons). 

(9) Method used to determine the 

quantity of lime byproduct/waste sold. 

(10) Monthly amount of lime 

byproduct/waste sold, by type (tons). 

(11) Annual amount of lime 

byproduct/waste not sold (tons). 

(12) Monthly mass of each lime type 

produced (tons). 

(13) Beginning and end of year 

inventories for each lime product. 

(14) Beginning and end of year 

inventories for lime byproducts/wastes. 

(15) Annual lime production capacity 

(tons) per facility. 

(16) Number of times in the reporting 

year that missing data procedures were 

followed to measure lime production 

(months) or the chemical composition of 

lime products sold (months). 

(17) Indicate whether CO2 was used 

on-site (i.e. for use in a purification 

process). If CO2 was used on-site, 

provide the information in paragraphs 

(b)(17)(i) and (b)(17)(ii) of this section. 

(i) The annual amount of CO2

captured for use in the on-site process. 

(ii) The method used to determine the 

amount of CO2 captured. 

§ 98.197 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) Annual operating hours in 

calendar year. 

(b) Records of all analyses (e.g. 

chemical composition of lime products, 

by type) and calculations conducted. 

§ 98.198 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE S–1 TO SUBPART S OF PART

98—BASIC PARAMETERS FOR THE

CALCULATION OF EMISSION FACTORS FOR LIME PRODUCTION

Variable Stoichiometric 

ratio 

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

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

Subpart T—[Reserved] 

Subpart U—Miscellaneous Uses of 

Carbonate 

§ 98.210 Definition of the source category. 

(a) This source category includes any 

equipment that uses carbonates listed in 

Table U–1 in manufacturing processes 

that emit carbon dioxide. Table U–1 

includes the following carbonates: 

limestone, dolomite, ankerite, 

magnesite, siderite, rhodochrosite, or 

sodium carbonate. Facilities are 

considered to emit CO2 if they consume 

at least 2,000 tons per year of carbonates 

heated to a temperature sufficient to 

allow the calcination reaction to occur. 

(b) This source category does not 

include equipment that uses carbonates 

or carbonate containing minerals that 

are consumed in the production of 

cement, glass, ferroalloys, iron and steel, 

lead, lime, phosphoric acid, pulp and 

paper, soda ash, sodium bicarbonate, 

sodium hydroxide, or zinc. 

(c) This source category does not 

include carbonates used in sorbent 

technology used to control emissions 

from stationary fuel combustion 

equipment. Emissions from carbonates 

used in sorbent technology are reported 

under 40 CFR 98, subpart C (Stationary 

Fuel Combustion Sources). 

§ 98.211 Reporting threshold. 

You must report GHG emissions from 

miscellaneous uses of carbonate if your 

facility uses carbonates as defined in 

§ 98.210 of this subpart and the facility 

meets the requirements of either 

§ 98.2(a)(1) or (a)(2). 

§ 98.212 GHGs to report. 

You must report CO2 process 

emissions from all miscellaneous 

carbonate use at your facility as 

specified in this subpart. 

§ 98.213 Calculating GHG emissions. 

You must determine CO2 process 

emissions from carbonate use in 

accordance with the procedures 

specified in either paragraphs (a) or (b) 

of this section. 

(a) Calculate the process emissions of 

CO2 using calcination fractions with 

Equation U–1 of this section. 

ECO

i

n

2

2000

2205 1

= ∗ ∗∗

=

∑ 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 (decimal 

fraction). As an alternative to measuring 

the calcination fraction, a value of 1.0 

can be used. 

n = Number of carbonate types. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

(b) Calculate the process emissions of 

CO2 using actual mass of output 

carbonates with Equation U–2 of 

this section. 

ECO

j

n

k

m

2

1 1

2000

2205 = ∗ ( ) − ∗ ( ) ⎡

⎣

⎢

⎢

⎤

⎦

⎥

⎥

∗

= =

∑ M EF M EF (Eq. U-2 kk jj ∑ )


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Where: 

ECO2 = Annual CO2 mass emissions from 

consumption of carbonates (metric tons). 

Mk = Annual mass of input carbonate type k 

(tons). 

EFk = Emission factor for the carbonate type 

k, as specified in Table U–1 of this 

subpart (metric tons CO2/metric ton 

carbonate input). 

Mj = Annual mass of output carbonate type 

j (tons). 

EFj = Emission factor for the output 

carbonate type j, as specified in Table U– 

1 of this subpart (metric tons CO2/metric 

ton carbonate input). 

m = Number of input carbonate types. 

n = Number of output carbonate types. 

§ 98.214 Monitoring and QA/QC 

requirements. 

(a) The annual mass of carbonate 

consumed (for Equation U–1 of this 

subpart) or carbonate inputs (for 

Equation U–2 of this subpart) must be 

determined annually from monthly 

measurements using the same plant 

instruments used for accounting 

purposes including purchase records or 

direct measurement, such as weigh 

hoppers or weigh belt feeders. 

(b) The annual mass of carbonate 

outputs (for Equation U–2 of this 

subpart) must be determined annually 

from monthly measurements using the 

same plant instruments used for 

accounting purposes including purchase 

records or direct measurement, such as 

weigh hoppers or belt weigh feeders. 

(c) If you follow the procedures of 

§ 98.213(a), as an alternative to 

assuming a calcination fraction of 1.0, 

you can determine on an annual basis 

the calcination fraction for each 

carbonate consumed based on sampling 

and chemical analysis using a suitable 

method such as using an x-ray 

fluorescence standard method or other 

enhanced industry consensus standard 

method published by an industry 

consensus standard organization (e.g., 

ASTM, ASME, etc.). 

§ 98.215 Procedures for estimating 

missing data. 

(a) A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable, a 

substitute data value for the missing 

parameter shall be used in the 

calculations as specified in paragraph 

(b) of this section. You must document 

and keep records of the procedures used 

for all such estimates. 

(b) For each missing value of monthly 

carbonate consumed, monthly carbonate 

output, or monthly carbonate input, the 

substitute data value must be the best 

available estimate based on the all 

available process data or data used for 

accounting purposes. 

§ 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 (g) of this 

section at the facility level, as 

applicable. 

(a) Annual CO2 emissions from 

miscellaneous carbonate use (metric 

tons). 

(b) Annual mass of each carbonate 

type consumed (tons). 

(c) Measurement method used to 

determine the mass of carbonate. 

(d) Method used to calculate 

emissions. 

(e) If you followed the calculation 

method of § 98.213(b)(1)(i), you must 

report the information in paragraphs 

(e)(1) through (e)(3) of this section. 

(1) Annual carbonate consumption by 

carbonate type (tons). 

(2) Annual calcination fractions used 

in calculations. 

(3) If you determined the calcination 

fraction, indicate which standard 

method was used. 

(f) If you followed the calculation 

method of § 98.213(b)(1)(ii), you must 

report the information in paragraphs 

(f)(1) and (f)(2) of this section. 

(1) Annual carbonate input by 

carbonate type (tons). 

(2) Annual carbonate output by 

carbonate type (tons). 

(g) Number of times in the reporting 

year that missing data procedures were 

followed to measure carbonate 

consumption, carbonate input or 

carbonate output (months). 

§ 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 (d) 

of this section: 

(a) Monthly carbonate consumption 

(by carbonate type in tons). 

(b) You must document the 

procedures used to ensure the accuracy 

of the monthly measurements of 

carbonate consumption, carbonate input 

or carbonate output including, but not 

limited to, calibration of weighing 

equipment and other measurement 

devices. 

(c) Records of all analyses conducted 

to meet the requirements of this rule. 

(d) Records of all calculations 

conducted. 

§ 98.218 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE U–1 TO SUBPART U OF PART

98—CO2 EMISSION FACTORS FOR

COMMON CARBONATES

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 ............................. 0.47572 

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 

one or more trains to produce weak 

nitric acid (30 to 70 percent in strength). 

A nitric acid train produces weak nitric 

acid through the catalytic oxidation of 

ammonia. 

§ 98.221 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 

contains a nitric acid train and the 

facility meets the requirements of either 

§ 98.2(a)(1) or (a)(2). 

§ 98.222 GHGs to report. 

(a) You must report N2O process 

emissions from each nitric acid 

production train as required by this 

subpart. 

(b) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit by following the 

requirements of subpart C. 

§ 98.223 Calculating GHG emissions. 

(a) You must determine annual N2O 

process emissions from each nitric acid 

train according to paragraphs (a)(1) or 

(a)(2) of this section. 

(1) Use a site-specific emission factor 

and production data according to 

paragraphs (b) through (h) of this 

section. 

(2) Request Administrator approval 

for an alternative method of determining 

N2O emissions according to paragraphs 

(a)(2)(i) and (a)(2)(ii) of this section. 

(i) You must submit the request 

within 45 days following promulgation 

of this subpart or within the first 30 

days of each subsequent reporting year. 

(ii) If the Administrator does not 

approve your requested alternative 

method within 150 days of the end of 

the reporting year, you must determine 

the N2O emissions factor for the current 


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reporting period using the procedures 

specified in paragraph (a)(1) of this 

section. 

(b) You must conduct an annual 

performance test according to 

paragraphs (b)(1) through (b)(3) of this 

section. 

(1) You must measure N2O emissions 

from the absorber tail gas vent for each 

nitric acid train using the methods 

specified in § 98.224(b) through (d). 

(2) You must conduct the 

performance test under normal process 

operating conditions and without using 

N2O abatement technology (if 

applicable). 

(3) You must measure the production 

rate during the performance test and 

calculate the production rate for the test 

period in metric tons (100 percent acid 

basis) per hour. 

(c) You must determine an N2O 

emissions factor to use in Equation V– 

3 of this section according to paragraphs 

(c)(1) or (c)(2) of this section. 

(1) You may request Administrator 

approval for an alternative method of 

determining N2O concentration 

according to the procedures in 

paragraphs (a)(2)(i) and (a)(2)(ii) of this 

section. Alternative methods include 

the use of N2O CEMs. 

(2) Using the results of the 

performance test in paragraph (b) of this 

section, you must calculate an average 

site-specific emission factor for each 

nitric acid train ‘‘t’’ according to 

Equation V–1 of this section: 

EF

C Q

P

n

N Ot

N O n

2

2

7

1

1 14 10

=

∗× ∗ −

∑ . 

(Eq. V-1)

Where: 

EFN2Ot = Average site-specific N2O emissions 

factor for nitric acid train ‘‘t’’ (lb N2O 

generated/ton nitric acid produced, 100 

percent acid basis). 

CN2O = N2O concentration for each test run 

during the performance test (ppm N2O). 

1.14 × 10¥7 = Conversion factor (lb/dscf-ppm 

N2O). 

Q = Volumetric flow rate of effluent gas for 

each test run during the performance test 

(dscf/hr). 

P = Production rate for each test run during 

the performance test (tons nitric acid 

produced per hour, 100 percent acid 

basis). 

n = Number of test runs. 

(d) If applicable, you must determine 

the destruction efficiency for each N2O 

abatement technology according to 

paragraphs (d)(1), (d)(2), or (d)(3) of this 

section. 

(1) Use the manufacturer’s specified 

destruction efficiency. 

(2) Estimate the destruction efficiency 

through process knowledge. Examples 

of information that could constitute 

process knowledge include calculations 

based on material balances, process 

stoichiometry, or previous test results 

provided the results are still relevant to 

the current vent stream conditions. You 

must document how process knowledge 

(if applicable) was used to determine 

the destruction efficiency. 

(3) Calculate the destruction 

efficiency by conducting an additional 

performance test on the emissions 

stream following the N2O abatement 

technology. 

(e) If applicable, you must determine 

the abatement factor for each N2O 

abatement technology. The abatement 

factor is calculated for each nitric acid 

train according to Equation V–2 of this 

section. 

AF =

P N t

at Abate

at

P

(Eq. V-2)

Where: 

AFN t = Abatement factor of N2O abatement 

technology at nitric acid train ‘‘t’’ 

(fraction of annual production that 

abatement technology is operating). 

Pa t = Total annual nitric acid production 

from nitric acid train ‘‘t’’ (ton acid 

produced, 100 percent acid basis). 

Pa t Abate = Annual nitric acid production from 

nitric acid train ‘‘t’’ during which N2O 

abatement was used (ton acid produced, 

100 percent acid basis). 

(f) You must determine the annual 

amount of nitric acid produced and the 

annual amount of nitric acid produced 

while each N2O abatement technology is 

operating from each nitric acid train 

(100 percent basis). 

(g) You must calculate N2O emissions 

for each nitric acid train by multiplying 

the emissions factor (determined in 

Equation V–1 of this section) by the 

annual nitric acid production and 

accounting for N2O abatement, 

according to Equation V–3 of this 

section: 

EF

EF P DF AF

N Ot

N Ot at N t N t

N

z

2

2

1

1

2204 63 = ∗ ∗− ∗ ( ) ( )

=

∑ . (Eq. V-3)

Where: 

EN2Ot = N2O mass emissions per year for 

nitric acid train ‘‘t’’ (metric tons). 

EFN2Ot = Average site-specific N2O emissions 

factor for nitric acid train ‘‘t’’ (lb N2O 

generated/ton acid produced, 100 

percent acid basis). 

Pa t = Annual nitric acid production from the 

train ‘‘t’’ (ton acid produced, 100 percent 

acid basis). 

DFN t = Destruction efficiency of N2O 

abatement technology N that is used on 

nitric acid train ‘‘t’’ (percent of N2O 

removed from air stream). 

AFN t = Abatement factor of N2O abatement 

technology for nitric acid train ‘‘t’’ 

(fraction of annual production that 

abatement technology is operating). 

2204.63 = Conversion factor (lb/metric ton). 

z = Number of different N2O abatement 

technologies. 

(h) You must determine the annual 

nitric acid production emissions 

combined from all nitric acid trains at 

your facility using Equation V–4 of this 

section: 

N EN Ot

t

m

2 2

1

O =

=

∑ (Eq. V-4)


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Where: 

N2O = Annual process N2O emissions from 

nitric acid production facility (metric 

tons). 

EN2Ot = N2O mass emissions per year for 

nitric acid train ‘‘t’’ (metric tons). 

m = Number of nitric acid trains. 

§ 98.224 Monitoring and QA/QC 

requirements. 

(a) You must conduct a new 

performance test and calculate a new 

site-specific emissions factor according 

to a test plan as specified in paragraphs 

(a)(1) through (a)(3) of this section. 

(1) Conduct the performance test 

annually. 

(2) Conduct the performance test 

when your nitric acid production 

process is changed, specifically when 

abatement equipment is installed. 

(3) If you requested Administrator 

approval for an alternative method of 

determining N2O concentration under 

§ 98.223(a)(2), you must conduct the 

performance test if your request has not 

been approved by the Administrator 

within 150 days of the end of the 

reporting year in which it was 

submitted. 

(b) You must measure the N2O 

concentration during the performance 

test using one of the methods in 

paragraphs (b)(1) through (b)(3) of this 

section. 

(1) EPA Method 320 at 40 CFR part 

63, appendix A, Measurement of Vapor 

Phase Organic and Inorganic Emissions 

by Extractive Fourier Transform Infrared 

(FTIR) Spectroscopy. 

(2) ASTM D6348–03 Standard Test 

Method for Determination of Gaseous 

Compounds by Extractive Direct 

Interface Fourier Transform Infrared 

(FTIR) Spectroscopy (incorporated by 

reference in § 98.7). 

(3) An equivalent method, with 

Administrator approval. 

(c) You must determine the 

production rate(s) (100 percent basis) 

from each nitric acid train during the 

performance test according to 

paragraphs (c)(1) or (c)(2) of this section. 

(1) Direct measurement of production 

and concentration (such as using flow 

meters, weigh scales, for production and 

concentration measurements). 

(2) Existing plant procedures used for 

accounting purposes (i.e. dedicated 

tank-level and acid concentration 

measurements). 

(d) You must conduct all performance 

tests in conjunction with the applicable 

EPA methods in 40 CFR part 60, 

appendices A–1 through A–4. Conduct 

three emissions test runs of 1 hour each. 

All QA/QC procedures specified in the 

reference test methods and any 

associated performance specifications 

apply. For each test, the facility must 

prepare an emission factor 

determination report that must include 

the items in paragraphs (d)(1) through 

(d)(3) of this section. 

(1) Analysis of samples, 

determination of emissions, and raw 

data. 

(2) All information and data used to 

derive the emissions factor(s). 

(3) The production rate during each 

test and how it was determined. 

(e) You must determine the monthly 

nitric acid production and the monthly 

nitric acid production during which 

N2O abatement technology is operating 

from each nitric acid train according to 

the methods in paragraphs (c)(1) or 

(c)(2) of this section. 

(f) You must determine the annual 

nitric acid production and the annual 

nitric acid production during which 

N2O abatement technology is operating 

for each train by summing the 

respective monthly nitric acid 

production quantities. 

§ 98.225 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable, a 

substitute data value for the missing 

parameter shall be used in the 

calculations as specified in paragraphs 

(a) and (b) of this section. 

(a) For each missing value of nitric 

acid production, the substitute data 

shall be the best available estimate 

based on all available process data or 

data used for accounting purposes (such 

as sales records). 

(b) For missing values related to the 

performance test, including emission 

factors, production rate, and N2O 

concentration, you must conduct a new 

performance test according to the 

procedures in § 98.224 (a) through (d). 

§ 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 (o) of this 

section for each nitric acid production 

train. 

(a) Train identification number. 

(b) Annual process N2O emissions 

from each nitric acid train (metric tons). 

(c) Annual nitric acid production 

from each nitric acid train (tons, 100 

percent acid basis). 

(d) Annual nitric acid production 

from each nitric acid train during which 

N2O abatement technology is operating 

(ton acid produced, 100 percent acid 

basis). 

(e) Annual nitric acid production 

from the nitric acid facility (tons, 100 

percent acid basis). 

(f) Number of nitric acid trains. 

(g) Number of abatement technologies 

(if applicable). 

(h) Abatement technologies used (if 

applicable). 

(i) Abatement technology destruction 

efficiency for each abatement 

technology (percent destruction). 

(j) Abatement utilization factor for 

each abatement technology (fraction of 

annual production that abatement 

technology is operating). 

(k) Type of nitric acid process used 

for each nitric acid train (low, medium, 

high, or dual pressure). 

(l) Number of times in the reporting 

year that missing data procedures were 

followed to measure nitric acid 

production (months). 

(m) If you conducted a performance 

test and calculated a site-specific 

emissions factor according to 

§ 98.223(a)(1), each annual report must 

also contain the information specified in 

paragraphs (m)(1) through (m)(7) of this 

section for each nitric acid production 

facility. 

(1) Emission factor calculated for each 

nitric acid train (lb N2O/ton nitric acid, 

100 percent acid basis). 

(2) Test method used for performance 

test. 

(3) Production rate per test run during 

performance test (tons nitric acid 

produced/hr, 100 percent acid basis). 

(4) N2O concentration per test run 

during performance test (ppm N2O). 

(5) Volumetric flow rate per test run 

during performance test (dscf/hr). 

(6) Number of test runs during 

performance test. 

(7) Number of times in the reporting 

year that a performance test had to be 

repeated (number). 

(n) If you requested Administrator 

approval for an alternative method of 

determining N2O concentration under 

§ 98.223(a)(2), each annual report must 

also contain the information specified in 

paragraphs (n)(1) through (n)(4) of this 

section for each nitric acid production 

facility. 

(1) Name of alternative method. 

(2) Description of alternative method. 

(3) Request date. 

(4) Approval date. 

(o) Total pounds of synthetic fertilizer 

produced through and total nitrogen 

contained in that fertilizer. 

§ 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) 

through (g) of this section for each nitric 

acid production facility: 


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(a) Records of significant changes to 

process. 

(b) Documentation of how process 

knowledge was used to estimate 

abatement technology destruction 

efficiency (if applicable). 

(c) Performance test reports. 

(d) Number of operating hours in the 

calendar year for each nitric acid train 

(hours). 

(e) Annual nitric acid permitted 

production capacity (tons). 

(f) Measurements, records, and 

calculations used to determine reported 

parameters. 

(g) Documentation of the procedures 

used to ensure the accuracy of the 

measurements of all reported 

parameters, including but not limited to, 

calibration of weighing equipment, flow 

meters, and other measurement devices. 

The estimated accuracy of 

measurements made with these devices 

must also be recorded, and the technical 

basis for these estimates must be 

provided. 

§ 98.228 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

Subpart W—[Reserved] 

Subpart X—Petrochemical Production 

§ 98.240 Definition of the source category. 

(a) The petrochemical production 

source category consists of all processes 

that produce acrylonitrile, carbon black, 

ethylene, ethylene dichloride, ethylene 

oxide, or methanol, except as specified 

in paragraphs (b) through (f) of this 

section. The source category includes 

processes that produce the 

petrochemical as an intermediate in the 

onsite production of other chemicals as 

well as processes that produce the 

petrochemical as an end product for sale 

or shipment offsite. 

(b) A process that produces a 

petrochemical as a byproduct is not part 

of the petrochemical production source 

category. 

(c) A facility that makes methanol, 

hydrogen, and/or ammonia from 

synthesis gas is part of the 

petrochemical source category if the 

annual mass of methanol produced 

exceeds the individual annual mass 

production levels of both hydrogen 

recovered as product and ammonia. The 

facility is part of subpart P of this part 

(Hydrogen Production) if the annual 

mass of hydrogen recovered as product 

exceeds the individual annual mass 

production levels of both methanol and 

ammonia. The facility is part of subpart 

G of this part (Ammonia Manufacturing) 

if the annual mass of ammonia 

produced exceeds the individual annual 

mass production levels of both 

hydrogen recovered as product and 

methanol. 

(d) A direct chlorination process that 

is operated independently of an 

oxychlorination process to produce 

ethylene dichloride is not part of the 

petrochemical production source 

category. 

(e) A process that produces bone 

black is not part of the petrochemical 

source category. 

(f) A process that produces a 

petrochemical from bio-based feedstock 

is not part of the petrochemical 

production source category. 

§ 98.241 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 

contains a petrochemical process as 

specified in § 98.240, and the facility 

meets the requirements of either 

§ 98.2(a)(1) or (2). 

§ 98.242 GHGs to report. 

You must report the information in 

paragraphs (a) through (c) of this 

section: 

(a) CO2 CH4, and N2O process 

emissions from each petrochemical 

process unit. Process emissions include 

CO2 generated by reaction in the process 

and by combustion of process off-gas in 

stationary combustion units and flares. 

(1) If you comply with § 98.243(b) or 

(d), report under this subpart the 

calculated CO2, CH4, and N2O emissions 

for each stationary combustion source 

and flare that burns any amount of 

petrochemical process off-gas. 

(2) If you comply with § 98.243(c), 

report under this subpart the calculated 

CO2 emissions for each petrochemical 

process unit. 

(b) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units and flares. 

(1) If you comply with § 98.243(b) or 

(d), report these emissions from 

stationary combustion units that are 

associated with petrochemical process 

units and burn only supplemental fuel 

under subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

(2) If you comply with § 98.243(c), 

report CO2, CH4, and N2O combustion 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C only for the combustion of 

supplemental fuel. Determine the 

applicable Tier in subpart C of this part 

(General Stationary Fuel Combustion 

Sources) based on the maximum rated 

heat input capacity of the stationary 

combustion source. 

(c) CO2 captured. You must report the 

mass of CO2 captured under, subpart PP 

of this part (Suppliers of Carbon Dioxide 

(CO2) by following the requirements of 

subpart PP. 

§ 98.243 Calculating GHG emissions. 

(a) If you route all process vent 

emissions and emissions from 

combustion of process off-gas to one or 

more stacks and use CEMS on each 

stack to measure CO2 emissions (except 

flare stacks), then you must determine 

process-based GHG emissions in 

accordance with paragraph (b) of this 

section. Otherwise, determine processbased GHG emissions in accordance 

with the procedures specified in 

paragraph (c) or (d) of this section. 

(b) Continuous emission monitoring 

system (CEMS). Route all process vent 

emissions and emissions from 

combustion of process off-gas to one or 

more stacks and determine CO2

emissions from each stack (except flare 

stacks) according to the Tier 4 

Calculation Methodology requirements 

in subpart C of this part. For each stack 

(except flare stacks) that includes 

emissions from combustion of 

petrochemical process off-gas, calculate 

CH4 and N2O emissions in accordance 

with subpart C of this part (use the Tier 

3 methodology and emission factors for 

‘‘Petroleum’’ in Table C–2 of subpart C 

of this part). For each flare, calculate 

CO2, CH4, and N2O emissions using the 

methodology specified in § 98.253(b)(1) 

through (b)(3). 

(c) Mass balance for each 

petrochemical process unit. Calculate 

the emissions of CO2 from each process 

unit, for each calendar month as 

described in paragraphs (c)(1) through 

(c)(5) of this section. 

(1) For each gaseous and liquid 

feedstock and product, measure the 

volume or mass used or produced each 

calendar month with a flow meter by 

following the procedures specified in 

§ 98.244(b)(2). Alternatively, for liquids, 

you may calculate the volume used or 

collected in each month based on 

measurements of the liquid level in a 

storage tank at least once per month 

(and just prior to each change in 

direction of the level of the liquid) 

following the procedures specified in 

§ 98.244(b)(3). Fuels used for 

combustion purposes are not considered 

to be feedstocks. 

(2) For each solid feedstock and 

product, measure the mass used or 

produced each calendar month by 

following the procedures specified in 

§ 98.244(b)(1). 

(3) Collect a sample of each feedstock 

and product at least once per month and 

determine the carbon content of each 


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sample according to the procedures in 

§ 98.244(b)(4). Alternatively, you may 

use the results of analyses conducted by 

a fuel or feedstock supplier, provided 

the sampling and analysis are 

conducted at least once per month using 

any of the procedures specified in 

§ 98.244(b)(4). If multiple valid carbon 

content measurements are made during 

the monthly measurement period, 

average them arithmetically. 

(4) If you determine that the monthly 

average concentration of a specific 

compound in a feedstock or product is 

greater than 99.5 percent by volume (or 

mass for liquids and solids), then as an 

alternative to the sampling and analysis 

specified in paragraph (c)(3) of this 

section, you may calculate the carbon 

content assuming 100 percent of that 

feedstock or product is the specific 

compound during periods of normal 

operation. You must maintain records of 

any determination made in accordance 

with this paragraph (c)(4) along with all 

supporting data, calculations, and other 

information. This alternative may not be 

used for products during periods of 

operation when off-specification 

product is produced. You must 

reevaluate determinations made under 

this paragraph (c)(4) after any process 

change that affects the feedstock or 

product composition. You must keep 

records of the process change and the 

corresponding composition 

determinations. If the feedstock or 

product composition changes so that the 

average monthly concentration falls 

below 99.5 percent, you are no longer 

permitted to use this alternative 

method. 

(5) Calculate the CO2 mass emissions 

for each petrochemical process unit 

using Equations X–1 through X–4 of this 

section. 

(i) Gaseous feedstocks and products. 

Use Equation X–1 of this section to 

calculate the net annual carbon input or 

output from gaseous feedstocks and 

products. Note that the result will be a 

negative value if there are no gaseous 

feedstocks in the process but there are 

gaseous products. 

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 = ( ) ∗ ( ) ∗

( ) − ( ) ∗ ( ) ∗( )

VC i=

j or k

n

⎡

⎣

⎢

⎢

⎤

⎦

⎥

⎥

⎡

⎣

⎢

⎢

⎤

⎦

⎥ ∑ ∑ ⎥ =1 1

12

(Eq. X-1)

Where: 

Cg = Annual net contribution to calculated 

emissions from carbon (C) in gaseous 

materials (kilograms/year, kg/yr). 

(Fgf)i,n = Volume of gaseous feedstock i 

introduced in month ‘‘n’’ (standard cubic 

feet, scf). 

(CCgf)i,n = Average carbon content of the 

gaseous feedstock i for month ‘‘n’’ (kg C 

per kg of feedstock). 

(MWf)i = Molecular weight of gaseous 

feedstock i (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf per kg-mole at standard 

conditions). 

(Pgp)i,n = Volume of gaseous product i 

produced in month ‘‘n’’ (scf). 

(CCgp)i,n = Average carbon content of gaseous 

product i, including streams containing 

CO2 recovered for sale or use in another 

process, for month ‘‘n’’ (kg C per kg of 

product). 

(MWp)i = Molecular weight of gaseous 

product i (kg/kg-mole). 

j = Number of feedstocks. 

k = Number of products. 

(ii) Liquid feedstocks and products. 

Use Equation X–2 of this section to 

calculate the net carbon input or output 

from liquid feedstocks and products. 

Note that the result will be a negative 

value if there are no liquid feedstocks in 

the process but there are liquid 

products. 

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

j or k

= ( ) ∗ ( ) − ( ) ∗ ( ) ⎡

⎣⎢ ⎤

⎦⎥

⎡

⎣

∑

1

⎢

⎢

⎤

⎦

⎥ = ⎥ ∑

n 1

12

(Eq. X-2)

Where: 

Cl = Annual net contribution to calculated 

emissions from carbon in liquid 

materials, including liquid organic 

wastes (kg/yr). 

(Flf)i,n = Volume or mass of liquid feedstock 

i introduced in month ‘‘n’’ (gallons or 

kg). 

(CClf)i,n = Average carbon content of liquid 

feedstock i for month ‘‘n’’ (kg C per 

gallon or kg of feedstock). 

(Plp)i,n = Volume or mass of liquid product i 

produced in month ‘‘n’’ (gallons or kg). 

(CClp)i,n = Average carbon content of liquid 

product i, including organic liquid 

wastes, for month ‘‘n’’ (kg C per gallon 

or kg of product). 

j = Number of feedstocks. 

k = Number of products. 

(iii) Solid feedstocks and products. 

Use Equation X–3 of this section to 

calculate the net annual carbon input or 

output from solid feedstocks and 

products. Note that the result will be a 

negative value if there are no solid 

feedstocks in the process but there are 

solid products. 

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

j or k

= ( ) ∗ ( ) − ( ) ∗ ( ) ⎡

⎣⎢ ⎤

⎦⎥

⎧

⎨ ∑

1

⎪

⎩⎪

⎫

⎬

⎪

= ⎭⎪ ∑n 1

12

(Eq. X-3)

Where: 

Cs = Annual net contribution to calculated 

emissions from carbon in solid materials 

(kg/yr). 

(Fsf)i,n = Mass of solid feedstock i introduced 

in month ‘‘n’’ (kg). 

(CCsf)i,n = Average carbon content of solid 

feedstock i for month ‘‘n’’ (kg C per kg 

of feedstock). 

(Psp)i,n = Mass of solid product i produced in 

month ‘‘n’’ (kg). 

(CCsp)i,n = Average carbon content of solid 

product i in month ‘‘n’’ (kg C per kg of 

product). 

j = Number of feedstocks. 

k = Number of products. 

(iv) Annual emissions. Use the results 

from Equations X–1 through X–3 of this 

section, as applicable, in Equation X–4 

of this section to calculate annual CO2

emissions. 


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CO C C C 2 gls 0.001 44

12 = ∗∗ + + (Eq. X-4) ( )

Where: 

CO2 = Annual CO2 mass emissions from 

process operations and process off-gas 

combustion (metric tons/year). 

0.001 = Conversion factor from kg to metric 

tons. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of carbon (C) (kg/kgmole). 

(d) Optional combustion methodology 

for ethylene production processes. For 

any ethylene production process, 

calculate CO2 emissions from 

combustion of fuel that contains 

ethylene process off-gas using the Tier 

3 or Tier 4 methodology in subpart C of 

this part, and calculate CH4 and N2O 

emissions using the applicable 

procedures in § 98.33(c) (use the 

emission factors for ‘‘Petroleum’’ in 

Table C–2 of subpart C of this part 

(General Stationary Fuel Combustion 

Sources)). You are not required to use 

the same Tier for each stationary 

combustion unit that burns ethylene 

process off-gas. For each flare, calculate 

CO2, CH4, and N2O emissions using the 

methodology specified in § 98.253(b)(1) 

through (b)(3). 

§ 98.244 Monitoring and QA/QC 

requirements. 

(a) If you use CEMS to determine 

emissions from process vents, you must 

comply with the procedures specified in 

§ 98.34(c). 

(b) If you use the mass balance 

methodology in § 98.243(c), use the 

procedures specified in paragraphs 

(b)(1) through (b)(4) of this section to 

determine feedstock and product flows 

and carbon contents. 

(1) Operate and maintain belt scales 

or other weighing devices as described 

in Specifications, Tolerances, and Other 

Technical Requirements For Weighing 

and Measuring Devices NIST Handbook 

44 (2009) (incorporated by reference, see 

§ 98.7) or follow procedures specified by 

the measurement device manufacturer. 

Calibrate the measurement device 

according to the procedures specified by 

the method, the procedures specified by 

the manufacturer, or § 98.3(i). 

Recalibrate either biennially or at the 

minimum frequency specified by the 

manufacturer. 

(2) Operate and maintain all flow 

meters for gas and liquid feedstocks and 

products by following the procedures in 

§ 98.3(i) and using any of the flow meter 

methods specified in paragraphs (b)(2)(i) 

through (b)(2)(xv) of this section, as 

applicable, use a standard method 

published by a consensus-based 

standards organization (e.g., ASTM, 

API, etc.), or follow procedures 

specified by the flow meter 

manufacturer or § 98.3(i). Recalibrate 

each flow meter either biennially or at 

the minimum frequency specified by the 

manufacturer. 

(i) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi 

(incorporated by reference, see § 98.7). 

(ii) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters (incorporated by 

reference, see § 98.7). 

(iii) ASME MFC–5M–1985 

(Reaffirmed 1994) Measurement of 

Liquid Flow in Closed Conduits Using 

Transit-Time Ultrasonic Flowmeters 

(incorporated by reference, see § 98.7). 

(iv) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters (incorporated 

by reference, see § 98.7). 

(v) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see § 98.7). 

(vi) ASME MFC–9M–1988 

(Reaffirmed 2001) Measurement of 

Liquid Flow in Closed Conduits by 

Weighing Method (incorporated by 

reference, see § 98.7). 

(vii) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters (incorporated 

by reference, see § 98.7). 

(viii) ASME MFC–14M–2003 

(Reaffirmed 2008), Measurement of 

Fluid Flow Using Small Bore Precision 

Orifice Meters (incorporated by 

reference, see § 98.7). 

(ix) ASME MFC–16–2007 

Measurement of Liquid Flow in Closed 

Conduits with Electromagnetic 

Flowmeters (incorporated by reference, 

see § 98.7). 

(x) ASME MFC–18M–2001 

(Reaffirmed 2006), Measurement of 

Fluid Flow Using Variable Area Meters 

(incorporated by reference, see § 98.7). 

(xi) ASME MFC–22–2007 

Measurement of Liquid by Turbine 

Flowmeters (incorporated by reference, 

see § 98.7). 

(xii) AGA Report No. 3: Orifice 

Metering of Natural Gas and Other 

Related Hydrocarbon Fluids, Part 1: 

General Equations and Uncertainty 

Guidelines (1990), Part 2: Specification 

and Installation Requirements (2000) 

(incorporated by reference, see § 98.7). 

(xiii) AGA Transmission 

Measurement Committee Report No. 7: 

Measurement of Natural Gas by Turbine 

Meter (2006)/February (incorporated by 

reference, see § 98.7). 

(xiv) AGA Report No. 11: 

Measurement of Natural Gas by Coriolis 

Meter (2003) (incorporated by reference, 

see § 98.7). 

(xv) ISO 8316: Measurement of Liquid 

Flow in Closed Conduits—Method by 

Collection of the Liquid in a Volumetric 

Tank (1987–10–01) First Edition 

(incorporated by reference, see § 98.7). 

(3) Perform tank level measurements 

(if used to determine feedstock or 

product flows) according to any 

standard method published by a 

consensus-based standards organization 

(e.g., ASTM, API, etc.) or follow 

procedures specified by the 

measurement device manufacturer or 

§ 98.3(i). Calibrate the measurement 

devices prior to the effective date of the 

rule, and recalibrate either biennially or 

at the minimum frequency specified by 

the manufacturer or § 98.3(i). 

(4) Use any of the standard methods 

specified in paragraphs (b)(4)(i) through 

(b)(4)(x) of this section, as applicable, to 

determine the carbon content or 

composition of feedstocks and products 

and the average molecular weight of 

gaseous feedstocks and products. 

Calibrate instruments in accordance 

with the method and as specified in 

paragraphs (b)(4)(i) through (b)(4)(x), as 

applicable. For coal used as a feedstock, 

the samples for carbon content 

determinations shall be taken at a 

location that is representative of the coal 

feedstock used during the 

corresponding monthly period. For 

carbon black products, samples shall be 

taken of each grade or type of product 

produced during the monthly period. 

Samples of coal feedstock or carbon 

black product for carbon content 

determinations may be either grab 

samples collected and analyzed 

monthly or a composite of samples 

collected more frequently and analyzed 

monthly. Analyses conducted in 

accordance with methods specified in 

paragraphs (b)(4)(i) through (b)(4)(x) of 

this section may be performed by the 

owner or operator, by an indpendent 

laboratory, or by the supplier of a 

feedstock. 

(i) ASTM D1945–03, Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(ii) ASTM D6060–96 (Reapproved 

2001) Standard Practice for Sampling of 

Process Vents With a Portable Gas 


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Chromatograph (incorporated by 

reference, see § 98.7). 

(iii) ASTM D2505–88(Reapproved 

2004)e1 Standard Test Method for 

Ethylene, Other Hydrocarbons, and 

Carbon Dioxide in High-Purity Ethylene 

by Gas Chromatography (incorporated 

by reference, see § 98.7). 

(iv) ASTM UOP539–97 Refinery Gas 

Analysis by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(v) ASTM D3176–89 (Reapproved 

2002) Standard Practice Method for 

Ultimate Analysis of Coal and Coke 

(incorporated by reference, see § 98.7). 

(vi) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants (incorporated 

by reference, see § 98.7). 

(vii) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 

(viii) Methods 8031, 8021, or 8015 in 

‘‘Test Methods for Evaluating Solid 

Waste, Physical/Chemical Methods,’’ 

EPA Publication No. SW–846, Third 

Edition, September 1986, as amended 

by Update I, November 15, 1992. 

(ix) Method 18 at 40 CFR part 60, 

appendix A–6. 

(x) Performance Specification 9 in 40 

CFR part 60, appendix B for continuous 

online gas analyzers. The 7-day 

calibration error test period must be 

completed prior to the effective date of 

the rule. 

§ 98.245 Procedures for estimating 

missing data. 

For missing feedstock flow rates, 

product flow rates, and carbon contents, 

use the same procedures as for missing 

flow rates and carbon contents for fuels 

as specified in § 98.35. 

§ 98.246 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a), (b), or (c) of this 

section, as appropriate for each process 

unit. 

(a) If you use the mass balance 

methodology in § 98.243(c), you must 

report the information specified in 

paragraphs (a)(1) through (a)(10) of this 

section for each type of petrochemical 

produced, reported by process unit. 

(1) The petrochemical process unit ID 

number or other appropriate descriptor. 

(2) The type of petrochemical 

produced, names of other products, and 

names of carbon-containing feedstocks. 

(3) Annual CO2 emissions calculated 

using Equation X–4 of this subpart. 

(4) Each of the monthly volume, mass, 

and carbon content values used in 

Equations X–1 through X–3 of this 

subpart (i.e., the directly measured 

values, substitute values, or the 

calculated values based on other 

measured data such as tank levels or gas 

composition) and the molecular weights 

for gaseous feedstocks and products 

used in Equation X–1 of this subpart. 

Indicate whether you used the 

alternative to sampling and analysis 

specified in § 98.243(c)(4). 

(5) Annual quantity of each type of 

petrochemical produced from each 

process unit (metric tons). 

(6) Name of each method listed in 

§ 98.244 used to determine a measured 

parameter (or description of 

manufacturer’s recommended method). 

(7) The dates and summarized results 

(e.g., percent calibration error) of the 

calibrations of each measurement 

device. 

(8) Identification of each combustion 

unit that burned both process off-gas 

and supplemental fuel. 

(9) If you comply with the alternative 

to sampling and analysis specified in 

§ 98.243(c)(4), the amount of time 

during which off-specification product 

was produced, the volume or mass of 

off-specification product produced, and 

if applicable, the date of any process 

change that reduced the composition to 

less than 99.5 percent. 

(10) You may elect to report the flow 

and carbon content of wastewater, and 

you may elect to report the carbon 

content of hydrocarbons in fugitive 

emissions and in process vents that are 

not controlled with a combustion 

device. These values may be estimated 

based on engineering analyses. These 

values are not to be used in the mass 

balance calculation. 

(b) If you use CEMS to measure CO2

emissions in accordance with 

§ 98.243(b), then you must report the 

relevant information required under 

§ 98.36 for the Tier 4 Calculation 

Methodology and the information listed 

in paragraphs (b)(1) through (b)(6) of 

this section. 

(1) For CEMS used on stacks for 

stationary combustion units, report the 

relevant information required under 

§ 98.36 for the Tier 4 calculation 

methodology. 

(2) For CEMS used on stacks that are 

not used for stationary combustion 

units, report the information required 

under § 98.36(e)(2)(vi) and (vii). 

(3) The petrochemical process unit ID 

or other appropriate descriptor, and the 

type of petrochemical produced. 

(4) The CO2 emissions from each stack 

and the combined CO2 emissions from 

all stacks (except flare stacks) that 

handle process vent emissions and 

emissions from stationary combustion 

units that burn process off-gas for the 

petrochemical process unit. If a 

stationary combustion source serves 

multiple petrochemical process units or 

units other than the petrochemical 

process unit, estimate based on 

engineering judgment the fraction of 

fuel energy and emissions attributable to 

each petrochemical process unit. 

(5) The CH4 and N2O emissions from 

each stack and the combined CH4 and 

N2O emissions from all stationary 

combustion units that burn process offgas from the petrochemical process unit, 

the cumulative annual heat input used 

in Equation C–10 in § 98.33(c) of this 

subpart, and the annual flow of each 

fuel on which this heat input is based. 

(6) ID or other appropriate descriptor 

of each stationary combustion unit that 

burns process off-gas. 

(7) Information listed in § 98.256(e) of 

subpart Y of this part for each flare that 

burns process off-gas. 

(8) Annual quantity of each type of 

petrochemical produced from each 

process unit (metric tons). 

(c) If you comply with the combustion 

methodology specified in § 98.243(d), 

you must report under this subpart the 

information listed in paragraphs (c)(1) 

through (c)(4) of this section. 

(1) For each stationary combustion 

unit that burns ethylene process off-gas 

(or group of stationary sources with a 

common pipe), the relevant information 

listed in § 98.36 for the selected Tier 3 

or Tier 4 methodology. If a stationary 

combustion source serves multiple 

ethylene process units or units other 

than the ethylene process unit, estimate 

based on engineering judgment the 

fraction of fuel energy and emissions 

attributable to each ethylene process 

unit. 

(2) Information listed in § 98.256(e) 

for each flare that burns ethylene 

process off-gas. 

(3) Name and annual quantity of each 

feedstock. 

(4) Annual quantity of each type of 

petrochemical produced from each 

process unit (metric tons). 

§ 98.247 Records that must be retained. 

In addition to the recordkeeping 

requirements in § 98.3(g), you must 

retain the records specified in 

paragraphs (a) through (c) of this 

section, as applicable. 

(a) If you comply with the CEMS 

measurement methodology in 

§ 98.243(b), then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology in 

§ 98.37. 


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(b) If you comply with the mass 

balance methodology in § 98.243(c), 

then you must retain records of the 

information listed in paragraphs (b)(1) 

through (b)(3) of this section. 

(1) Results of feedstock or product 

composition determinations conducted 

in accordance with § 98.243(c)(4). 

(2) Start and end times and calculated 

carbon contents for time periods when 

off-specification product is produced, if 

you comply with the alternative 

methodology in § 98.243(c)(4) for 

determining carbon content of feedstock 

or product. 

(3) A part of the monitoring plan 

required under § 98.3(g)(5), record the 

estimated accuracy of measurement 

devices and the technical basis for these 

estimates. 

(c) If you comply with the combustion 

methodology in § 98.243(d), then you 

must retain under this subpart the 

records required for the Tier 3 and/or 

Tier 4 Calculation Methodologies in 

§ 98.37. 

§ 98.248 Definitions. 

Except as specified in this section, all 

terms used in this subpart have the 

same meaning given in the Clean Air 

Act and subpart A of this part. 

Product, as used in § 98.243, means 

each of the following carbon-containing 

outputs from a process: the 

petrochemical, recovered byproducts, 

and liquid organic wastes that are not 

incinerated onsite. Product does not 

include process vent emissions, fugitive 

emissions, or wastewater. 

Subpart Y—Petroleum Refineries 

§ 98.250 Definition of source category. 

(a) A petroleum refinery is any facility 

engaged in producing gasoline, gasoline 

blending stocks, naphtha, kerosene, 

distillate fuel oils, residual fuel oils, 

lubricants, or asphalt (bitumen) through 

distillation of petroleum or through 

redistillation, cracking, or reforming of 

unfinished petroleum derivatives, 

except as provided in paragraph (b) of 

this section. 

(b) For the purposes of this subpart, 

facilities that distill only pipeline 

transmix (off-spec material created 

when different specification products 

mix during pipeline transportation) are 

not petroleum refineries, regardless of 

the products produced. 

(c) This source category consists of 

the following sources at petroleum 

refineries: Catalytic cracking units; fluid 

coking units; delayed coking units; 

catalytic reforming units; coke calcining 

units; asphalt blowing operations; 

blowdown systems; storage tanks; 

process equipment components 

(compressors, pumps, valves, pressure 

relief devices, flanges, and connectors) 

in gas service; marine vessel, barge, 

tanker truck, and similar loading 

operations; flares; sulfur recovery 

plants; and non-merchant hydrogen 

plants (i.e., hydrogen plants that are 

owned or under the direct control of the 

refinery owner and operator). 

§ 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 (a)(2). 

§ 98.252 GHGs to report. 

You must report: 

(a) CO2, CH4, and N2O combustion 

emissions from stationary combustion 

units and from each flare. Calculate and 

report these emissions under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) by following the 

requirements of subpart C, except for 

CO2 emissions from combustion of 

refinery fuel gas. For CO2 emissions 

from combustion of fuel gas, use either 

equation C–5 in subpart C of this part 

or the Tier 4 methodology in subpart C 

of this part. You may aggregate units, 

monitor common stacks, or monitor 

common (fuel) pipes as provided in 

§ 98.36(c) when calculating and 

reporting emissions from stationary 

combustion units. 

(b) CO2, CH4, and N2O coke burn-off 

emissions from each catalytic cracking 

unit, fluid coking unit, and catalytic 

reforming unit under this subpart. 

(c) CO2 emissions from sour gas sent 

off site for sulfur recovery operations 

under this subpart. You must follow the 

calculation methodologies from 

§ 98.253(f) and the monitoring and QA/ 

QC methods, missing data procedures, 

reporting requirements, and 

recordkeeping requirements of this 

subpart. 

(d) CO2 process emissions from each 

on-site sulfur recovery plant under this 

subpart. 

(e) CO2, CH4, and N2O emissions from 

each coke calcining unit under this 

subpart. 

(f) CO2 and CH4 emissions from 

asphalt blowing operations under this 

subpart. 

(g) CH4 emissions from equipment 

leaks, storage tanks, loading operations, 

delayed coking units, and uncontrolled 

blowdown systems under this subpart. 

(h) CO2, CH4, and N2O emissions from 

each process vent not specifically 

included in paragraphs (a) through (g) of 

this section under this subpart. 

(i) CO2 and CH4 emissions from nonmerchant hydrogen production under 

this subpart. You must follow the 

calculation methodologies, monitoring 

and QA/QC methods, missing data 

procedures, reporting requirements, and 

recordkeeping requirements of subpart P 

of this part. 

§ 98.253 Calculating GHG emissions. 

(a) Calculate GHG emissions required 

to be reported in § 98.252(b) through (i) 

using the applicable methods in 

paragraphs (b) through (n) of this 

section. 

(b) For flares, calculate GHG 

emissions according to the requirements 

in paragraphs (b)(1) through (b)(3) of 

this section. 

(1) Calculate the CO2 emissions 

according to the applicable 

requirements in paragraphs (b)(1)(i) 

through (b)(1)(iii) of this section. 

(i) Flow measurement. If you have a 

continuous flow monitor on the flare, 

you must use the measured flow rates 

when the monitor is operational and the 

flow rate is within the calibrated range 

of the measurement device to calculate 

the flare gas flow. If you do not have a 

continuous flow monitor on the flare 

and for periods when the monitor is not 

operational or the flow rate is outside 

the calibrated range of the measurement 

device, you must use engineering 

calculations, company records, or 

similar estimates of volumetric flare gas 

flow. 

(ii) Heat value or carbon content 

measurement. If you have a continuous 

higher heating value monitor or gas 

composition monitor on the flare or if 

you monitor these parameters at least 

weekly, you must use the measured heat 

value or carbon content value in 

calculating the CO2 emissions from the 

flare using the applicable methods in 

paragraphs (b)(1)(ii)(A) and (b)(1)(ii)(B). 

(A) If you monitor gas composition, 

calculate the CO2 emissions from the 

flare using Equation Y–1 of this section. 

If daily or more frequent measurement 

data are available, you must use daily 

values when using Equation Y–1 of this 

section; otherwise, use weekly values. 


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CO Flare

MW

MVC

CC

p

p

p

p

n

2 =× × ×( ) × ×

⎡

⎣

⎢ ⎤

⎦

⎥

⎛

⎝

⎜

⎜ =

0 98 0 001 ∑ 44

12 1

. . ( ) ( ) ⎞

⎠

⎟

⎟ (Eq. Y-1)

Where: 

CO2 = Annual CO2 emissions for a specific 

fuel type (metric tons/year). 

0.98 = Assumed combustion efficiency of a 

flare. 

0.001 = Unit conversion factor (metric tons 

per kilogram, mt/kg). 

n = Number of measurement periods. The 

minimum value for n is 52 (for weekly 

measurements); the maximum value for 

n is 366 (for daily measurements during 

a leap year). 

p = Measurement period index. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

(Flare)p = Volume of flare gas combusted 

during measurement period (standard 

cubic feet per period, scf/period). If a 

mass flow meter is used, measure flare 

gas flow rate in kg/period and replace 

the term ‘‘(MW)p/MVC’’ with ‘‘1’’. 

(MW)p = Average molecular weight of the 

flare gas combusted during measurement 

period (kg/kg-mole). If measurements are 

taken more frequently than daily, use the 

arithmetic average of measurement 

values within the day to calculate a daily 

average. 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

(CC)p = Average carbon content of the flare 

gas combusted during measurement 

period (kg C per kg flare gas). If 

measurements are taken more frequently 

than daily, use the arithmetic average of 

measurement values within the day to 

calculate a daily average. 

(B) If you monitor heat content but do 

not monitor gas composition, calculate 

the CO2 emissions from the flare using 

Equation Y–2 of this section. If daily or 

more frequent measurement data are 

available, you must use daily values 

when using Equation Y–2 of this 

section; otherwise, use weekly values. 

CO Flare HHV EmF p p

p

n

2 =× × × × ⎡ (Eq. Y-2) ⎣ ⎤

⎦ =

0 98 0 001 ∑

1

. . ( )( )

Where: 

CO2 = Annual CO2 emissions for a specific 

fuel type (metric tons/year). 

0.98 = Assumed combustion efficiency of a 

flare. 

0.001 = Unit conversion factor (metric tons 

per kilogram, mt/kg). 

n = Number of measurement periods. The 

minimum value for n is 52 (for weekly 

measurements); the maximum value for 

n is 366 (for daily measurements during 

a leap year). 

p = Measurement period index. 

(Flare)p = Volume of flare gas combusted 

during measurement period (million 

(MM) scf/period). If a mass flow meter is 

used, you must also measure molecular 

weight and convert the mass flow to a 

volumetric flow as follows: Flare[MMscf] 

= 0.000001 × Flare[kg] × MVC/(MW)p, 

where MVC is the molar volume 

conversion factor (849.5 scf/kg-mole) and 

(MW)p is the average molecular weight of 

the flare gas combusted during 

measurement period (kg/kg-mole). 

(HHV)p = Higher heating value for the flare 

gas combusted during measurement 

period (British thermal units per scf, 

Btu/scf = MMBtu/MMscf). If 

measurements are taken more frequently 

than daily, use the arithmetic average of 

measurement values within the day to 

calculate a daily average. 

EmF = Default CO2 emission factor of 60 

kilograms CO2/MMBtu (HHV basis). 

(iii) Alternative to heat value or 

carbon content measurements. If you do 

not measure the higher heating value or 

carbon content of the flare gas at least 

weekly, determine the quantity of gas 

discharged to the flare separately for 

periods of routine flare operation and 

for periods of start-up, shutdown, or 

malfunction, and calculate the CO2

emissions as specified in paragraphs 

(b)(1)(iii)(A) through (b)(1)(iii)(C) of this 

section. 

(A) For periods of start-up, shutdown, 

or malfunction, use engineering 

calculations and process knowledge to 

estimate the carbon content of the flared 

gas for each start-up, shutdown, or 

malfunction event exceeding 500,000 

scf/day. 

(B) For periods of normal operation, 

use the average heating value measured 

for the fuel gas for the heating value of 

the flare gas. If heating value is not 

measured, the heating value may be 

estimated from historic data or 

engineering calculations. 

(C) Calculate the CO2 emissions using 

Equation Y–3 of this section. 

CO Flare HHV EmF Flare

MW

MVC Norm SSM p

p

2 =× × × × + × 0 98 0 001 ( ) ×

44

12 . . ( )

×

⎡

⎣

⎢ ⎤

⎦

⎥

⎛

⎝

⎜

⎜

⎞

⎠

⎟

⎟ =

∑ ( ) CC p

p

n

1

(Eq. Y-3)

Where: 

CO2 = Annual CO2 emissions for a specific 

fuel type (metric tons/year). 

0.98 = Assumed combustion efficiency of a 

flare. 

0.001 = Unit conversion factor (metric tons 

per kilogram, mt/kg). 

FlareNorm = Annual volume of flare gas 

combusted during normal operations 

from company records, (million (MM) 

standard cubic feet per year, MMscf/ 

year). 

HHV = Higher heating value for fuel gas or 

flare gas from company records (British 

thermal units per scf, Btu/scf = MMBtu/ 

MMscf). 

EmF = Default CO2 emission factor for flare 

gas of 60 kilograms CO2/MMBtu (HHV 

basis). 

n = Number of start-up, shutdown, and 

malfunction events during the reporting 

year exceeding 500,000 scf/day. 

p = Start-up, shutdown, and malfunction 

event index. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

(FlareSSM)p = Volume of flare gas combusted 

during indexed start-up, shutdown, or 

malfunction event from engineering 

calculations, (scf/event). 

(MW)p = Average molecular weight of the 

flare gas, from the analysis results or 

engineering calculations for the event 

(kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

(CC)p = Average carbon content of the flare 

gas, from analysis results or engineering 

calculations for the event (kg C per kg 

flare gas). 

(2) Calculate CH4 using Equation Y– 

4 of this section. 


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CH EmF

EmF (Eq. Y-4) 4

CH4 = × ⎛

⎝

⎜ ⎞

⎠

⎟ CO224 + × ××

0 02

0 98

16

44 CO fCH

.

.

Where: 

CH4 = Annual methane emissions from flared 

gas (metric tons CH4/year). 

CO2 = Emission rate of CO2 from flared gas 

calculated in paragraph (b)(1) of this 

section (metric tons/year). 

EmFCH4 = Default CH4 emission factor for 

‘‘PetroleumProducts’’ from Table C–2 of 

subpart C of this part (General Stationary 

Fuel Combustion Sources) (kg CH4/ 

MMBtu). 

EmF = Default CO2 emission factor for flare 

gas of 60 kg CO2/MMBtu (HHV basis). 

0.02/0.98 = Correction factor for flare 

combustion efficiency. 

16/44 = Correction factor ratio of the 

molecular weight of CH4 to CO2. 

fCH4 = Weight fraction of carbon in the flare 

gas prior to combustion that is 

contributed by methane from 

measurement values or engineering 

calculations (kg C in methane in flare 

gas/kg C in flare gas); default is 0.4. 

(3) Calculate N2O emissions using 

Equation Y–5 of this section. 

N O CO EmF

EmF (Eq. Y-5) 2 2

N2O = × ⎛

⎝

⎜ ⎞

⎠

⎟

Where: 

N2O = Annual nitrous oxide emissions from 

flared gas (metric tons N2O/year). 

CO2 = Emission rate of CO2 from flared gas 

calculated in paragraph (b)(1) of this 

section (metric tons/year). 

EmFN2O = Default N2O emission factor for 

‘‘PetroleumProducts’’ from Table C–2 of 

subpart C of this part (General Stationary 

Fuel Combustion Sources) (kg N2O/ 

MMBtu). 

EmF = Default CO2 emission factor for flare 

gas of 60 kg CO2/MMBtu (HHV basis). 

(c) For catalytic cracking units and 

traditional fluid coking units, calculate 

the GHG emissions using the applicable 

methods described in paragraphs (c)(1) 

through (c)(5) of this section. 

(1) If you operate and maintain a 

CEMS that measures CO2 emissions 

according to subpart C of this part 

(General Stationary Fuel Combustion 

Sources), you must calculate and report 

CO2 emissions as provided in 

paragraphs (c)(1)(i) and (c)(1)(ii) of this 

section. Other catalytic cracking units 

and traditional fluid coking units must 

either install a CEMS that complies with 

the Tier 4 Calculation Methodology in 

subpart C of this part (General 

Stationary Combustion Sources), or 

follow the requirements of paragraphs 

(c)(2) or (3) of this section. 

(i) Calculate CO2 emissions by 

following the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(ii) If a CO boiler or other postcombustion device is used, you must 

also calculate the CO2 emissions from 

the fuel fired to the CO boiler or postcombustion device using the applicable 

methods for stationary combustion units 

in subpart C of this part. Calculate the 

process emissions from the catalytic 

cracking unit or fluid coking unit as the 

difference in the CO2 CEMS emissions 

and the calculated combustion 

emissions associated with the CO boiler. 

(2) For catalytic cracking units and 

fluid coking units with rated capacities 

greater than 10,000 barrels per stream 

day (bbls/sd) that do not use a 

continuous CO2 CEMS for the final 

exhaust stack, you must continuously or 

no less frequently than hourly monitor 

the O2, CO2, and (if necessary) CO 

concentrations in the exhaust stack from 

the catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels and 

calculate the CO2 emissions according 

to the requirements of paragraphs 

(c)(2)(i) through (c)(2)(iii) of this section: 

(i) Calculate the CO2 emissions from 

each catalytic cracking unit and fluid 

coking unit using Equation Y–6 of this 

section. 

CO Q

CO CO

MVC r p

p

p

n

2

% 2 = ( ) × (Eq. Y-6) ( ) +

× ×

⎡

⎣

⎢

⎢

⎤

⎦

⎥

= ⎥

%

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 

there is no post-combustion device, 

assume %CO to be zero. 

44 = Molecular weight of CO2 (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

0.001 = Conversion factor (metric ton/kg). 

n = Number of hours in calendar year. 

(ii) Either continuously monitor the 

volumetric flow rate of exhaust gas from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

prior to the combustion of other fossil 

fuels or calculate the volumetric flow 

rate of this exhaust gas stream using 

Equation Y–7 of this section. 

Q

Q OQ

CO CO O r

a oxy oxy = ( ) ∗+ − ( ) ∗

− −−

79 100

100

%

% %% 2 2

(Eq. Y-7)

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). 


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%O2 = Hourly average percent oxygen 

concentration in exhaust gas stream from 

the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

%Ooxy = O2 concentration in oxygen enriched 

gas stream inlet to the fluid catalytic 

cracking unit regenerator or fluid coking 

unit burner based on oxygen purity 

specifications of the oxygen supply used 

for enrichment (percent by volume—dry 

basis). 

%CO2 = Hourly average percent CO2

concentration in the exhaust gas stream 

from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). 

%CO = Hourly average percent CO 

concentration in the exhaust gas stream 

from the fluid catalytic cracking unit 

regenerator or fluid coking unit burner 

(percent by volume—dry basis). When 

no auxiliary fuel is burned and a 

continuous CO monitor is not required 

under 40 CFR part 63 subpart UUU, 

assume %CO to be zero. 

(iii) If you have a CO boiler that uses 

auxiliary fuels or combusts materials 

other than catalytic cracking unit or 

fluid coking unit exhaust gas, you must 

determine the CO2 emissions resulting 

from the combustion of these fuels or 

other materials following the 

requirements in subpart C and report 

those emissions by following the 

requirements of subpart C of this part. 

(3) For catalytic cracking units and 

fluid coking units with rated capacities 

of 10,000 barrels per stream day (bbls/ 

sd) or less that do not use a continuous 

CO2 CEMS for the final exhaust stack, 

comply with the requirements in 

paragraph (c)(3)(i) of this section or 

paragraphs (c)(3)(ii) and (c)(3)(iii) of this 

section, as applicable. 

(i) If you continuously or no less 

frequently than daily monitor the O2, 

CO2, and (if necessary) CO 

concentrations in the exhaust stack from 

the catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels, you 

must calculate the CO2 emissions 

according to the requirements of 

paragraphs (c)(2)(i) through (c)(2)(iii) of 

this section, except that daily averages 

are allowed and the summation can be 

performed on a daily basis. 

(ii) If you do not monitor at least daily 

the O2, CO2, and (if necessary) CO 

concentrations in the exhaust stack from 

the catalytic cracking unit regenerator or 

fluid coking unit burner prior to the 

combustion of other fossil fuels, 

calculate the CO2 emissions from each 

catalytic cracking unit and fluid coking 

unit using Equation Y–8 of this section. 

CO Q CBF CC 2 unit 0 001 44

12

= × × ×× ( . ) (Eq. Y-8)

Where: 

CO2 = Annual CO2 mass emissions (metric 

tons/year). 

Qunit = Annual throughput of unit from 

company records (barrels (bbls) per year, 

bbl/yr). 

CBF = Coke burn-off factor from engineering 

calculations (kg coke per barrel of feed); 

default for catalytic cracking units = 7.3; 

default for fluid coking units = 11. 

0.001 = Conversion factor (metric ton/kg). 

CC = Carbon content of coke based on 

measurement or engineering estimate (kg 

C per kg coke); default = 0.94. 

44/12 = Ratio of molecular weight of CO2 to 

C (kg CO2 per kg C). 

(iii) If you have a CO boiler that uses 

auxiliary fuels or combusts materials 

other than catalytic cracking unit or 

fluid coking unit exhaust gas, you must 

determine the CO2 emissions resulting 

from the combustion of these fuels or 

other materials following the 

requirements in subpart C of this part 

(General Stationary Fuel Combustion 

Sources) and report those emissions by 

following the requirements of subpart C 

of this part. 

(4) Calculate CH4 emissions using 

either unit specific measurement data, a 

unit-specific emission factor based on a 

source test of the unit, or Equation Y– 

9 of this section. 

CH EmF

EmF (Eq. Y-9) 4

2

1

= ∗ ⎛

⎝

⎜ ⎞

⎠

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 (General Stationary 

Fuel Combustion Sources) (kg CO2/ 

MMBtu). 

EmF2 = Default CH4 emission factor for 

‘‘PetroleumProducts’’ from Table C–2 of 

subpart C of this part (General Stationary 

Fuel Combustion Sources) (kg CH4/ 

MMBtu). 

(5) Calculate N2O emissions using 

either unit specific measurement data, a 

unit-specific emission factor based on a 

source test of the unit, or Equation Y– 

10 of this section. 

N O EmF

EmF (Eq. Y-10) 2

3

1

= ∗ ⎛

⎝

⎜ ⎞

⎠

CO2 ⎟

Where: 

N2O = Annual nitrous oxide emissions from 

coke burn-off (mt N2O/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 (General Stationary 

Fuel Combustion Sources) (kg CO2/ 

MMBtu). 

EmF3 = Default N2O emission factor for 

‘‘PetroleumProducts’’ from Table C–2 of 

subpart C of this part (kg N2O/MMBtu). 

(d) For fluid coking units that use the 

flexicoking design, the GHG emissions 

from the resulting use of the low value 

fuel gas must be accounted for only 

once. Typically, these emissions will be 

accounted for using the methods 

described in subpart C of this part 

(General Stationary Fuel Combustion 

Sources). Alternatively, you may use the 

methods in paragraph (c) of this section 

provided that you do not otherwise 

account for the subsequent combustion 

of this low value fuel gas. 

(e) For catalytic reforming units, 

calculate the CO2 emissions using the 

applicable methods described in 

paragraphs (e)(1) through (e)(3) of this 

section and calculate the CH4 and N2O 

emissions using the methods described 

in paragraphs (c)(4) and (c)(5) of this 

section, respectively. 

(1) If you operate and maintain a 

CEMS that measures CO2 emissions 

according to subpart C of this part 

(General Stationary Fuel Combustion 

Sources), you must calculate CO2

emissions as provided in paragraphs 

(c)(1)(i) and (c)(1)(ii) of this section. 

Other catalytic reforming units must 

either install a CEMS that complies with 

the Tier 4 Calculation Methodology in 

subpart C of this part, or follow the 

requirements of paragraph (e)(2) or (e)(3) 

of this section. 

(2) If you continuously or no less 

frequently than daily monitor the O2, 

CO2, and (if necessary) CO 

concentrations in the exhaust stack from 

the catalytic reforming unit catalyst 

regenerator prior to the combustion of 

other fossil fuels, you must calculate the 

CO2 emissions according to the 

requirements of paragraphs (c)(2)(i) 

through (c)(2)(iii) of this section. 


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(3) Calculate CO2 emissions from the 

catalytic reforming unit catalyst 

regenerator using Equation Y–11 of this 

section. 

CO CB CC Q n

n

2

1

44

12 = ( ) × ×× 0 001 ⎡

⎣

⎢ ⎤

⎦ ∑ ⎥ . (Eq. Y-11)

Where: 

CO2 = Annual CO2 emissions (metric tons/ 

year). 

CBQ = Coke burn-off quantity per 

regeneration cycle from engineering 

estimates (kg coke/cycle). 

n = Number of regeneration cycles in the 

calendar year. 

CC = Carbon content of coke based on 

measurement or engineering estimate (kg 

C per kg coke); default = 0.94. 

44/12 = Ratio of molecular weight of CO2 to 

C (kg CO2 per kg C). 

0.001 = Conversion factor (metric ton/kg). 

(f) For on-site sulfur recovery plants, 

calculate and report CO2 process 

emissions from sulfur recovery plants 

according to the requirements in 

paragraphs (f)(1) through (f)(5) of this 

section. Combustion emissions from the 

sulfur recovery plant (e.g., from fuel 

combustion in the Claus burner or the 

tail gas treatment incinerator) must be 

reported under subpart C of this part 

(General Stationary Fuel Combustion 

Sources). For the purposes of this 

subpart, the sour gas stream for which 

monitoring is required according to 

paragraphs (f)(2) through (f)(5) of this 

section is not considered a fuel. 

(1) If you operate and maintain a 

CEMS that measures CO2 emissions 

according to subpart C of this part, you 

must calculate CO2 emissions under this 

subpart by following the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). You must 

monitor fuel use in the Claus burner, 

tail gas incinerator, or other combustion 

sources that discharge via the final 

exhaust stack from the sulfur recovery 

plant and calculate the combustion 

emissions from the fuel use according to 

subpart C of this part. Calculate the 

process emissions from the sulfur 

recovery plant as the difference in the 

CO2 CEMS emissions and the calculated 

combustion emissions associated with 

the sulfur recovery plant final exhaust 

stack. Other sulfur recovery plants must 

either install a CEMS that complies with 

the Tier 4 Calculation Methodology in 

subpart C, or follow the requirements of 

paragraphs (f)(2) through (f)(5) of this 

section. 

(2) Flow measurement. If you have a 

continuous flow monitor on the sour gas 

feed to the sulfur recovery plant, you 

must use the measured flow rates when 

the monitor is operational to calculate 

the sour gas flow rate. If you do not have 

a continuous flow monitor on the sour 

gas feed to the sulfur recovery plant, 

you must use engineering calculations, 

company records, or similar estimates of 

volumetric sour gas flow. 

(3) Carbon content. If you have a 

continuous gas composition monitor 

capable of measuring carbon content on 

the sour gas feed to the sulfur recovery 

plant or if you monitor gas composition 

for carbon content on a routine basis, 

you must use the measured carbon 

content value. Alternatively, you may 

develop a site-specific carbon content 

factor using limited measurement data 

or engineering estimates or use the 

default factor of 0.20. 

(4) Calculate the CO2 emissions from 

each sulfur recovery plant using 

Equation Y–12 of this section. 

CO F

MVC 2 =∗ ∗ ∗ SG C MF 44 0.001 (Eq. Y-12)

Where: 

CO2 = Annual CO2 emissions (metric tons/ 

year). 

FSG = Volumetric flow rate of sour gas feed 

(including sour water stripper gas) to the 

sulfur recovery plant (scf/year). 

44 = Molecular weight of CO2 (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

MFC = Mole fraction of carbon in the sour gas 

to the sulfur recovery plant (kg-mole C/ 

kg-mole gas); default = 0.20. 

0.001 = Conversion factor, kg to metric tons. 

(5) If tail gas is recycled to the front 

of the sulfur recovery plant and the 

recycled flow rate and carbon content is 

included in the measured data under 

paragraphs (f)(2) and (f)(3) of this 

section, respectively, then the annual 

CO2 emissions calculated in paragraph 

(f)(4) of this section must be corrected 

to avoid double counting these 

emissions. You may use engineering 

estimates to perform this correction or 

assume that the corrected CO2 emissions 

are 95 percent of the uncorrected value 

calculated using Equation Y–12 of this 

section. 

(g) For coke calcining units, calculate 

GHG emissions according to the 

applicable provisions in paragraphs 

(g)(1) through (g)(3) of this section. 

(1) If you operate and maintain a 

CEMS that measures CO2 emissions 

according to subpart C of this part, you 

must calculate and report CO2 emissions 

under this subpart by following the Tier 

4 Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). You must 

monitor fuel use in the coke calcining 

unit that discharges via the final exhaust 

stack from the coke calcining unit and 

calculate the combustion emissions 

from the fuel use according to subpart 

C of this part. Calculate the process 

emissions from the coke calcining unit 

as the difference in the CO2 CEMS 

emissions and the calculated 

combustion emissions associated with 

the coke calcining unit final exhaust 

stack. Other coke calcining units must 

either install a CEMS that complies with 

the Tier 4 Calculation Methodology in 

subpart C of this part, or follow the 

requirements of paragraph (g)(2) of this 

section. 

(2) Calculate the CO2 emissions from 

the coke calcining unit using Equation 

Y–13 of this section. 


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

44

12

∗∗ − + ( ) ( ) ∗ (Eq. Y-13)

Where: 

CO2 = Annual CO2 emissions (metric tons/ 

year). 

Min = Annual mass of green coke fed to the 

coke calcining unit from facility records 

(metric tons/year). 

CCGC = Average mass fraction carbon content 

of green coke from facility measurement 

data (metric ton carbon/metric ton green 

coke). 

Mout = Annual mass of marketable petroleum 

coke produced by the coke calcining unit 

from facility records (metric tons 

petroleum coke/year). 

Mdust = Annual mass of petroleum coke dust 

collected in the dust collection system of 

the coke calcining unit from facility 

records (metric ton petroleum coke dust/ 

year). 

CCMPC = Average mass fraction carbon 

content of marketable petroleum coke 

produced by the coke calcining unit from 

facility measurement data (metric ton 

carbon/metric ton petroleum coke). 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

(3) For all coke calcining units, use 

the CO2 emissions from the coke 

calcining unit calculated in paragraphs 

(g)(1) or (g)(2), as applicable, and 

calculate CH4 using the methods 

described in paragraph (c)(4) of this 

section and N2O emissions using the 

methods described in paragraph (c)(5) of 

this section. 

(h) For asphalt blowing operations, 

calculate GHG emissions according to 

the requirements in paragraph (j) of this 

section or according to the applicable 

provisions in paragraphs (h)(1) and 

(h)(2) of this section. 

(1) For uncontrolled asphalt blowing 

operations or asphalt blowing 

operations controlled by vapor 

scrubbing, calculate CO2 and CH4

emissions using Equations Y–14 and Y– 

15 of this section, respectively. 

CO Q EF 2 = × ( ) AB AB.CO (Eq. Y-14) 2

Where: 

CO2 = Annual CO2 emissions from 

uncontrolled asphalt blowing (metric 

tons CO2/year). 

QAB = Quantity of asphalt blown (million 

barrels per year, MMbbl/year). 

EFAB,CO2 = Emission factor for CO2 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CO2/MMbbl asphalt blown); default = 

1,100. 

CH Q EF 4 4 = × ( ) AB AB,CH (Eq. Y-15)

Where: 

CH4 = Annual methane emissions from 

uncontrolled asphalt blowing (metric 

tons CH4/year). 

QAB = Quantity of asphalt blown (million 

barrels per year, MMbbl/year). 

EFAB,CH4 = Emission factor for CH4 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CH4/MMbbl asphalt blown); default = 

580. 

(2) For asphalt blowing operations 

controlled by thermal oxidizer or flare, 

calculate CO2 and CH4 emissions using 

Equations Y–16 and Y–17 of this 

section, respectively, provided these 

emissions are not already included in 

the flare emissions calculated in 

paragraph (b) of this section or in the 

stationary combustion unit emissions 

required under subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

CO Q CEF 2 AB AB =× × × (Eq. Y-16) ⎛

⎝

⎜ ⎞

⎠

⎟ 0 98 44

12 .

Where: 

CO2 = Annual CO2 emissions from controlled 

asphalt blowing (metric tons CO2/year). 

0.98 = Assumed combustion efficiency of 

thermal oxidizer or flare. 

QAB = Quantity of asphalt blown (MMbbl/ 

year). 

CEFAB = Carbon emission factor from asphalt 

blowing from facility-specific test data 

(metric tons C/MMbbl asphalt blown); 

default = 2,750. 

44 = Molecular weight of CO2 (kg/kg-mole). 

12 = Atomic weight of C (kg/kg-mole). 

CH Q EF 4 4 =× × 0 02 . (Eq. Y-17) ( ) AB AB,CH

Where: 

CH4 = Annual methane emissions from 

controlled asphalt blowing (metric tons 

CH4/year). 

0.02 = Fraction of methane uncombusted in 

thermal oxidizer or flare based on 

assumed 98% combustion efficiency. 

QAB = Quantity of asphalt blown (million 

barrels per year, MMbbl/year). 

EFAB,CH4 = Emission factor for CH4 from 

uncontrolled asphalt blowing from 

facility-specific test data (metric tons 

CH4/MMbbl asphalt blown); default = 

580. 

(i) For delayed coking units, calculate 

the CH4 emissions from the 

depressurization of the coking unit 

vessel (i.e., the ‘‘coke drum’’) to 

atmosphere using either of the methods 

provided in paragraphs (i)(1) or (i)(2), 

provided no water or steam is added to 

the vessel once it is vented to the 

atmosphere. You must use the method 

in paragraph (i)(1) of this section if you 

add water or steam to the vessel after it 

is vented to the atmosphere. 

(1) Use the process vent method in 

paragraph (j) of this section and also 

calculate the CH4 emissions from the 

subsequent opening of the vessel for 

coke cutting operations using Equation 

Y–18 of this section. If you have coke 

drums or vessels of different 

dimensions, use Equation Y–18 for each 

set of coke drums or vessels of the same 

size and sum the resultant emissions 

across each set of coke drums or vessels 

to calculate the CH4 emissions for all 

delayed coking units. 

CH N H

P

f D

MVC

MF CV

4 = void CH 14.7 4

× × ( ) +× ×

×

×× × ⎛

⎝

⎜

⎜

⎞

⎠

14 7 16 0 001

2 . . π

4 ⎟

⎟ (Eq. Y-18)


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56457 

Where: 

CH4 = Annual methane emissions from the 

delayed coking unit vessel opening 

(metric ton/year). 

N = Cumulative number of vessel openings 

for all delayed coking unit vessels of the 

same dimensions during the year. 

H = Height of coking unit vessel (feet). 

PCV = Gauge pressure of the coking vessel 

when opened to the atmosphere prior to 

coke cutting or, if the alternative method 

provided in paragraph (i)(2) of this 

section is used, gauge pressure of the 

coking vessel when depressurization 

gases are first routed to the atmosphere 

(pounds per square inch gauge, psig). 

14.7 = Assumed atmospheric pressure 

(pounds per square inch, psi). 

fvoid = Volumetric void fraction of coking 

vessel prior to steaming (cf gas/cf of 

vessel); default = 0.6. 

D = Diameter of coking unit vessel (feet). 

16 = Molecular weight of CH4 (kg/kg-mole). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

MFCH4 = Mole fraction of methane in coking 

vessel gas (kg-mole CH4/kg-mole gas, wet 

basis); default value is 0.01. 

0.001 = Conversion factor (metric ton/kg). 

(2) Calculate the CH4 emissions from 

the depressurization vent and 

subsequent opening of the vessel for 

coke cutting operations using Equation 

Y–18 of this section and the pressure of 

the coking vessel when the 

depressurization gases are first routed to 

the atmosphere. If you have coke drums 

or vessels of different dimensions, use 

Equation Y–18 for each set of coke 

drums or vessels of the same size and 

sum the resultant emissions across each 

set of coke drums or vessels to calculate 

the CH4 emissions for all delayed coking 

units. 

(j) For each process vent not covered 

in paragraphs (a) through (i) of this 

section that can be reasonably expected 

to contain greater than 2 percent by 

volume CO2 or greater than 0.5 percent 

by volume of CH4 or greater than 0.01 

percent by volume (100 parts per 

million) of N2O, calculate GHG 

emissions using the Equation Y–19 of 

this section. You must use Equation Y– 

19 of this section for catalytic reforming 

unit depressurization and purge vents 

when methane is used as the purge gas 

or if you elected this method as an 

alternative to the methods in paragraphs 

(h)(1) or (h)(2) of this section. 

E VR MF MW

MVC x px VT

p

x p

p

N

= (Eq. Y-19)

=1

() () . × ( ) ×× × ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟ 0 001

Where: 

Ex = Annual emissions of each GHG from 

process vent (metric ton/yr). 

N = Number of venting events per year. 

P = Index of venting events. 

(VR)p = Average volumetric flow rate of 

process gas during the event (scf per 

hour). 

(MFx)p = Mole fraction of GHG x in process 

vent during the event (kg-mol of GHG x/ 

kg-mol vent gas). 

MWx = Molecular weight of GHG x (kg/kgmole); use 44 for CO2 or N2O and 16 for 

CH4. 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

(VT)p = Venting time for the event, (hours). 

0.001 = Conversion factor (metric ton/kg). 

(k) For uncontrolled blowdown 

systems, you must either use the 

methods for process vents in paragraph 

(j) of this section or calculate CH4

emissions using Equation Y–20 of this 

section. Blowdown systems where the 

uncondensed gas stream is routed to a 

flare or similar control device is 

considered to be controlled and is not 

required to estimate emissions under 

this paragraph (k). 

CH Q EF f MVC 4 = (Eq. Y-20) Re ××× 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–21 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-21)

Where: 

CH4 = Annual methane emissions from 

equipment leaks (metric tons/year). 

NCD = Number of atmospheric crude oil 

distillation columns at the facility. 

NPU1 = Cumulative number of catalytic 

cracking units, coking units (delayed or 

fluid), hydrocracking, and full-range 

distillation columns (including 

depropanizer and debutanizer 

distillation columns) at the facility. 

NPU2 = Cumulative number of hydrotreating/ 

hydrorefining units, catalytic reforming 

units, and visbreaking units at the 

facility. 

NH2 = Total number of hydrogen plants at the 

facility. 

NFGS = Total number of fuel gas systems at 

the facility. 

(m) For storage tanks, except as 

provided in paragraph (m)(3) of this 

section, calculate CH4 emissions using 

the applicable methods in paragraphs 

(m)(1) and (m)(2) of this section. 

(1) For storage tanks other than those 

processing unstabilized crude oil, you 

must either calculate CH4 emissions 

from storage tanks that have a vaporphase methane concentration of 0.5 

volume percent or more using tankspecific methane composition data 

(from measurement data or product 

knowledge) and the AP–42 emission 


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estimation methods provided in Section 

7.1 of the AP–42: ‘‘Compilation of Air 

Pollutant Emission Factors, Volume 1: 

Stationary Point and Area Sources’’, 

including TANKS Model (Version 

4.09D) or similar programs, or estimate 

CH4 emissions from storage tanks using 

Equation Y–22 of this section. 

CH Q 4 f = 0.1 (Eq. Y-22) ( ) × 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–23 of this section. 

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

16 ( ) × ×Δ × ×× (Eq. Y-23) 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). 

MVC = Molar volume conversion factor 

(849.5 scf/kg-mole). 

0.001 = Conversion factor (metric ton/kg). 

(3) You do not need to calculate CH4

emissions from storage tanks that meet 

any of the following descriptions: 

(i) Units permanently attached to 

conveyances such as trucks, trailers, rail 

cars, barges, or ships; 

(ii) Pressure vessels designed to 

operate in excess of 204.9 kilopascals 

and without emissions to the 

atmosphere; 

(iii) Bottoms receivers or sumps; 

(iv) Vessels storing wastewater; or 

(v) Reactor vessels associated with a 

manufacturing process unit. 

(n) For crude oil, intermediate, or 

product loading operations for which 

the equilibrium vapor-phase 

concentration of methane is 0.5 volume 

percent or more, calculate CH4

emissions from loading operations using 

product-specific, vapor-phase methane 

composition data (from measurement 

data or process knowledge) and the 

emission estimation procedures 

provided in Section 5.2 of the AP–42: 

‘‘Compilation of Air Pollutant Emission 

Factors, Volume 1: Stationary Point and 

Area Sources.’’ For loading operations 

in which the equilibrium vapor-phase 

concentration of methane is less than 

0.5 volume percent, you may assume 

zero methane emissions. 

§ 98.254 Monitoring and QA/QC 

requirements. 

(a) Fuel flow meters, gas composition 

monitors, and heating value monitors 

associated with stationary combustion 

sources must follow the monitoring and 

QA/QC requirements in § 98.34. 

(b) All flow meters, gas composition 

monitors, and heating value monitors 

that are used to provide data for the 

GHG emissions calculations in this 

subpart for sources other than stationary 

combustion sources shall be calibrated 

according to the procedures in the 

applicable methods specified in 

paragraphs (c) through (e) of this 

section, the procedures specified by the 

manufacturer, or §§ 98.3(i). Recalibrate 

each flow meter either biennially (every 

two years) or at the minimum frequency 

specified by the manufacturer. 

Recalibrate each gas composition 

monitor and heating value monitor 

either annually or at the minimum 

frequency specified by the 

manufacturer. 

(c) For flare or sour gas flow meters, 

operate and maintain the flow meter 

using any of the following methods, a 

method published by a consensus-based 

standards organization (e.g., ASTM, 

API, etc.) or follow the procedures 

specified by the flow meter 

manufacturer. Flow meters must have a 

rated accuracy of ± 5 percent or lower. 

(1) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi 

(incorporated by reference, see § 98.7). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters (incorporated by 

reference, see § 98.7). 

(3) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters (incorporated 

by reference, see § 98.7). 

(4) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see § 98.7). 

(5) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters (incorporated 

by reference, see § 98.7). 

(6) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters 

(incorporated by reference, see § 98.7). 

(7) ASME MFC–18M–2001 

Measurement of Fluid Flow Using 

Variable Area Meters (incorporated by 

reference, see § 98.7). 

(8) AGA Report No. 11 Measurement 

of Natural Gas by Coriolis Meter (2003) 

(incorporated by reference, see § 98.7). 

(d) Determine flare gas composition 

using any of the following methods. 

(1) Method 18 at 40 CFR part 60, 

appendix A–6. 

(2) ASTM D1945–03 Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(3) ASTM D1946–90 (Reapproved 

2006) Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(4) GPA 2261–00 Analysis for Natural 

Gas and Similar Gaseous Mixtures by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(5) UOP539–97 Refinery Gas Analysis 

by Gas Chromatography (incorporated 

by reference, see § 98.7). 

(e) Determine flare gas higher heating 

value using any of the following 

methods. 

(1) ASTM D4809–06 Standard Test 

Method for Heat of Combustion of 

Liquid Hydrocarbon Fuels by Bomb 

Calorimeter (Precision Method) 

(incorporated by reference, see § 98.7). 

(2) ASTM D240–02 (Reapproved 

2007) Standard Test Method for Heat of 

Combustion of Liquid Hydrocarbon 

Fuels by Bomb Calorimeter 

(incorporated by reference, see § 98.7). 

(3) ASTM D1826–94 (Reapproved 

2003) Standard Test Method for 

Calorific (Heating) Value of Gases in 

Natural Gas Range by Continuous 

Recording Calorimeter (incorporated by 

reference, see § 98.7). 


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(4) ASTM D3588–98 (Reapproved 

2003) Standard Practice for Calculating 

Heat Value, Compressibility Factor, and 

Relative Density of Gaseous Fuels 

(incorporated by reference, see § 98.7). 

(5) ASTM D4891–89 (Reapproved 

2006) Standard Test Method for Heating 

Value of Gases in Natural Gas Range by 

Stoichiometric Combustion 

(incorporated by reference, see § 98.7). 

(f) For exhaust gas flow meters used 

to comply with the requirements in 

§ 98.253(c)(2)(ii), install, operate, 

calibrate, and maintain exhaust gas flow 

meter according to the requirements in 

40 CFR 63.1572(c) or according to the 

following requirements. 

(1) Locate the flow meter(s) and other 

necessary equipment such as 

straightening vanes in a position that 

provides representative flow; reduce 

swirling flow or abnormal velocity 

distributions due to upstream and 

downstream disturbances. 

(2) Use a flow rate meter with an 

accuracy within ± 5 percent. 

(3) Use a continuous monitoring 

system capable of correcting for the 

temperature, pressure, and moisture 

content to output flow in dry standard 

cubic feet (standard conditions as 

defined in § 98.6). 

(4) Install, operate, and maintain each 

continuous monitoring system 

according to the manufacturer’s 

specifications and requirements. 

(g) For exhaust gas CO2/CO/O2

composition monitors used to comply 

with the requirements in § 98.253(c)(2), 

install, operate, calibrate, and maintain 

exhaust gas composition monitors 

according to the requirements in 40 CFR 

60.105a(b)(2) or 40 CFR 63.1572(a) or 

according to the manufacturer’s 

specifications and requirements. 

(h) Determine the mass of petroleum 

coke as required by Equation Y–13 of 

this subpart using mass measurement 

equipment meeting the requirements for 

commercial weighing equipment as 

described in Specifications, Tolerances, 

and Other Technical Requirements For 

Weighing and Measuring Devices, NIST 

Handbook 44 (2009) (incorporated by 

reference, see § 98.7). Calibrate the 

measurement device according to the 

procedures specified by the method, the 

procedures specified by the 

manufacturer, or § 98.3(i). Recalibrate 

either biennially or at the minimum 

frequency specified by the 

manufacturer. 

(i) Determine the carbon content of 

petroleum coke as required by Equation 

Y–13 of this subpart using any one of 

the following methods. Calibrate the 

measurement device according to 

procedures specified by the method or 

procedures specified by the 

measurement device manufacturer. 

(1) ASTM D3176–89 (Reapproved 

2002) Standard Practice for Ultimate 

Analysis of Coal and Coke (incorporated 

by reference, see § 98.7). 

(2) ASTM D5291–02 (Reapproved 

2007) Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Petroleum 

Products and Lubricants (incorporated 

by reference, see § 98.7). 

(3) ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 

(j) Determine the quantity of 

petroleum process streams using 

company records. These quantities 

include the quantity of asphalt blown, 

quantity of crude oil plus the quantity 

of intermediate products received from 

off site, and the quantity of unstabilized 

crude oil received at the facility. 

(k) The owner or operator shall 

document the procedures used to ensure 

the accuracy of the estimates of fuel 

usage, gas composition, and heating 

value including but not limited to 

calibration of weighing equipment, fuel 

flow meters, and other measurement 

devices. The estimated accuracy of 

measurements made with these devices 

shall also be recorded, and the technical 

basis for these estimates shall be 

provided. 

(l) All CO2 CEMS and flow rate 

monitors used for direct measurement of 

GHG emissions must comply with the 

QA procedures in § 98.34(c). 

§ 98.255 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required (e.g., 

concentrations, flow rates, fuel heating 

values, carbon content values). 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable (e.g., if a CEMS 

malfunctions during unit operation or if 

a required fuel sample is not taken), a 

substitute data value for the missing 

parameter shall be used in the 

calculations. 

(a) For stationary combustion sources, 

use the missing data procedures in 

subpart C of this part. 

(b) For each missing value of the heat 

content, carbon content, or molecular 

weight of the fuel, substitute the 

arithmetic average of the quality-assured 

values of that parameter immediately 

preceding and immediately following 

the missing data incident. If the ‘‘after’’ 

value is not obtained by the end of the 

reporting year, you may use the 

‘‘before’’ value for the missing data 

substitution. If, for a particular 

parameter, no quality-assured data are 

available prior to the missing data 

incident, the substitute data value shall 

be the first quality-assured value 

obtained after the missing data period. 

(c) For missing CO2, CO, O2, CH4, or 

N2O concentrations, gas flow rate, and 

percent moisture, the substitute data 

values shall be the best available 

estimate(s) of the parameter(s), based on 

all available process data (e.g., 

processing rates, operating hours, etc.). 

The owner or operator shall document 

and keep records of the procedures used 

for all such estimates. 

(d) For hydrogen plants, use the 

missing data procedures in subpart P of 

this part. 

§ 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 (q) of this 

section. 

(a) For combustion sources, follow the 

data reporting requirements under 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) For hydrogen plants, follow the 

data reporting requirements under 

subpart P of this part (Hydrogen 

Production). 

(c) [Reserved] 

(d) [Reserved] 

(e) For flares, owners and operators 

shall report: 

(1) The flare ID number (if 

applicable). 

(2) A description of the type of flare 

(steam assisted, air-assisted). 

(3) A description of the flare service 

(general facility flare, unit flare, 

emergency only or back-up flare). 

(4) The calculated CO2, CH4, and N2O 

annual emissions for each flare, 

expressed in metric tons of each 

pollutant emitted. 

(5) A description of the method used 

to calculate the CO2 emissions for each 

flare (e.g., reference section and 

equation number). 

(6) If you use Equation Y–1 of this 

subpart, the annual volume of flare gas 

combusted (in scf/year) and the annual 

average molecular weight (in kg/kgmole) and carbon content of the flare gas 

(in kg carbon per kg flare gas). 

(7) If you use Equation Y–2 of this 

subpart, the annual volume of flare gas 

combusted (in million (MM) scf/year) 

and the annual average higher heating 

value of the flare gas (in MMBtu per 

MMscf). 

(8) If you use Equation Y–3 of this 

subpart, the annual volume of flare gas 

combusted (in MMscf/year) during 


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normal operations, the annual average 

higher heating value of the flare gas (in 

MMBtu/MMscf), the number of SSM 

events exceeding 500,000 scf/day, and 

the volume of gas flared (in scf/event) 

and the average molecular weight (in 

kg/kg-mole) and carbon content of the 

flare gas (in kg carbon per kg flare) for 

each SSM event over 500,000 scf/day. 

(9) The fraction of carbon in the flare 

gas contributed by methane used in 

Equation Y–4 of this subpart and the 

basis for its value. 

(f) For catalytic cracking units, 

traditional fluid coking units, and 

catalytic reforming units, owners and 

operators shall report: 

(1) The unit ID number (if applicable). 

(2) A description of the type of unit 

(fluid catalytic cracking unit, thermal 

catalytic cracking unit, traditional fluid 

coking unit, or catalytic reforming unit). 

(3) Maximum rated throughput of the 

unit, in bbl/stream day. 

(4) The calculated CO2, CH4, and N2O 

annual emissions for each unit, 

expressed in metric tons of each 

pollutant emitted. 

(5) A description of the method used 

to calculate the CO2 emissions for each 

unit (e.g., reference section and equation 

number). 

(6) If you use a CEMS, the relevant 

information required under 

§ 98.36(e)(2)(vi) for the Tier 4 

Calculation Methodology, the CO2

annual emissions as measured by the 

CEMS (unadjusted to remove CO2

combustion emissions associated with a 

CO boiler, if present) and the process 

CO2 emissions as calculated according 

to § 98.253(c)(1)(ii). Report the CO2

annual emissions associated with fuel 

combustion under subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

(7) If you use Equation Y–6 of this 

subpart, the annual average exhaust gas 

flow rate, %CO2, and %CO. 

(8) If you use Equation Y–7 of this 

subpart, the annual average flow rate of 

inlet air and oxygen-enriched air, %O2, 

%Ooxy, %CO2, and %CO. 

(9) If you use Equation Y–8 of this 

subpart, the coke burn-off factor, annual 

throughput of unit, and the average 

carbon content of coke and the basis for 

the value. 

(10) Indicate whether you use a 

measured value, a unit-specific 

emission factor, or a default emission 

factor for CH4 emissions. If you use a 

unit-specific emission factor for CH4, 

report the units of measure for the unitspecific factor, the activity data for 

calculating emissions (e.g., if the 

emission factor is based on coke burnoff rate, the annual quantity of coke 

burned), and the basis for the factor. 

(11) Indicate whether you use a 

measured value, a unit-specific 

emission factor, or a default emission 

factor for N2O emissions. If you use a 

unit-specific emission factor for N2O, 

report the units of measure for the unitspecific factor, the activity data for 

calculating emissions (e.g., if the 

emission factor is based on coke burnoff rate, the annual quantity of coke 

burned), and the basis for the factor. 

(12) If you use Equation Y–11 of this 

subpart, the number of regeneration 

cycles during the reporting year, the 

average coke burn-off quantity per cycle, 

and the average carbon content of the 

coke. 

(g) For fluid coking unit of the 

flexicoking type, the owner or operator 

shall report: 

(1) The unit ID number (if applicable). 

(2) A description of the type of unit. 

(3) Maximum rated throughput of the 

unit, in bbl/stream day. 

(4) Indicate whether the GHG 

emissions from the low heat value gas 

are accounted for in subpart C of this 

part or § 98.253(c). 

(5) If the GHG emissions for the low 

heat value gas are calculated at the 

flexicoking unit, also report the 

calculated annual CO2, CH4, and N2O 

emissions for each unit, expressed in 

metric tons of each pollutant emitted, 

and the applicable equation input 

parameters specified in paragraphs (f)(7) 

through (f)(11) of this section. 

(h) For sulfur recovery plants and for 

emissions from sour gas sent off-site for 

sulfur recovery, the owner and operator 

shall report: 

(1) The plant ID number (if 

applicable). 

(2) Maximum rated throughput of 

each independent sulfur recovery plant, 

in metric tons sulfur produced/stream 

day. 

(3) The calculated CO2 annual 

emissions for each sulfur recovery plant, 

expressed in metric tons. The calculated 

annual CO2 emissions from sour gas 

sent off-site for sulfur recovery, 

expressed in metric tons. 

(4) If you use Equation Y–12 of this 

subpart, the annual volumetric flow to 

the sulfur recovery plant (in scf/year) 

and the annual average mole fraction of 

carbon in the sour gas (in kg-mole C/kgmole gas). 

(5) If you recycle tail gas to the front 

of the sulfur recovery plant, indicate 

whether the recycled flow rate and 

carbon content are included in the 

measured data under § 98.253(f)(2) and 

(3). Indicate whether a correction for 

CO2 emissions in the tail gas was used 

in Equation Y–12. If so, then report the 

value of the correction, the annual 

volume of recycled tail gas (in scf/year) 

and the annual average mole fraction of 

carbon in the tail gas (in kg-mole C/kgmole gas). Indicate whether you used 

the default (95%) or a unit specific 

correction, and if used, report the 

approach used. 

(6) If you use a CEMS, the relevant 

information required under 

§ 98.36(e)(2)(vi) for the Tier 4 

Calculation Methodology, the CO2

annual emissions as measured by the 

CEMS and the annual process CO2

emissions calculated according to 

§ 98.253(f)(1). Report the CO2 annual 

emissions associated with fuel 

combustion subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

(i) For coke calcining units, the owner 

and operator shall report: 

(1) The unit ID number (if applicable). 

(2) Maximum rated throughput of the 

unit, in metric tons coke calcined/ 

stream day. 

(3) The calculated CO2, CH4, and N2O 

annual emissions for each unit, 

expressed in metric tons of each 

pollutant emitted. 

(4) A description of the method used 

to calculate the CO2 emissions for each 

unit (e.g., reference section and equation 

number). 

(5) If you use Equation Y–13 of this 

subpart, annual mass and carbon 

content of green coke fed to the unit, the 

annual mass and carbon content of 

marketable coke produced, and the 

annual mass of coke dust collected in 

dust collection systems. 

(6) If you use a CEMS, the relevant 

information required under 

§ 98.36(e)(2)(vi) for the Tier 4 

Calculation Methodology, the CO2

annual emissions as measured by the 

CEMS and the annual process CO2

emissions calculated according to 

§ 98.253(g)(1). Report the CO2 annual 

emissions associated with fuel 

combustion under subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

(7) Indicate whether you use a 

measured value, a unit-specific 

emission factor or a default for CH4

emissions. If you use a unit-specific 

emission factor for CH4, the unitspecific emission factor for CH4, the 

units of measure for the unit-specific 

factor, the activity data for calculating 

emissions (e.g., if the emission factor is 

based on coke burn-off rate, the annual 

quantity of coke burned), and the basis 

for the factor. 

(8) If you use a site-specific emission 

factor in Equation Y–10 of this subpart, 

the site-specific emission factor and the 

basis of the factor. 

(j) For asphalt blowing operations, the 

owner or operator shall report: 


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(1) The unit ID number (if applicable). 

(2) The quantity of asphalt blown (in 

Million bbl) at the facility in the 

reporting year. 

(3) The type of control device used to 

reduce methane (and other organic) 

emissions from the unit. 

(4) The calculated annual CO2 and 

CH4 emissions for each unit, expressed 

in metric tons of each pollutant emitted. 

(5) If you use Equation Y–14 of this 

subpart, the CO2 emission factor used 

and the basis for the value. 

(6) If you use Equation Y–15 of this 

subpart, the CH4 emission factor used 

and the basis for the value. 

(7) If you use Equation Y–16 of this 

subpart, the carbon emission factor used 

and the basis for the value. 

(8) If you use Equation Y–17 of this 

subpart, the CH4 emission factor used 

and the basis for the value. 

(k) For delayed coking units, the 

owner or operator shall report: 

(1) The cumulative annual CH4

emissions (in metric tons of each 

pollutant emitted) for all delayed coking 

units at the facility. 

(2) A description of the method used 

to calculate the CH4 emissions for each 

unit (e.g., reference section and equation 

number). 

(3) The total number of delayed 

coking units at the facility, the total 

number of delayed coking drums at the 

facility, and for each coke drum or 

vessel: the dimensions, the typical 

gauge pressure of the coking drum when 

first vented to the atmosphere, typical 

void fraction, the typical drum outage 

(i.e. the unfilled distance from the top 

of the drum, in feet), and annual 

number of coke-cutting cycles. 

(4) For each set of coking drums that 

are the same dimensions: The number of 

coking drums in the set, the height and 

diameter of the coke drums (in feet), the 

cumulative number of vessel openings 

for all delayed coking drums in the set, 

the typical venting pressure (in psig), 

void fraction (in cf gas/cf of vessel), and 

the mole fraction of methane in coking 

gas (in kg-mole CF4/kg-mole gas, wet 

basis). 

(5) The basis for the volumetric void 

fraction of the coke vessel prior to 

steaming and the basis for the mole 

fraction of methane in the coking gas. 

(l) For process vents subject to 

§ 98.253(j), the owner or operator shall 

report: 

(1) The vent ID number (if applicable). 

(2) The unit or operation associated 

with the emissions. 

(3) The type of control device used to 

reduce methane (and other organic) 

emissions from the unit, if applicable. 

(4) The calculated annual CO2, CH4, 

and N2O emissions for each vent, 

expressed in metric tons of each 

pollutant emitted. 

(5) The annual volumetric flow 

discharged to the atmosphere (in scf), 

mole fraction of each GHG above the 

concentration threshold, and for 

intermittent vents, the number of 

venting events and the cumulative 

venting time. 

(m) For uncontrolled blowdown 

systems, the owner or operator shall 

report: 

(1) The cumulative annual CH4

emissions (in metric tons of each 

pollutant emitted) for uncontrolled 

blowdown systems. 

(2) The total quantity (in Million bbl) 

of crude oil plus the quantity of 

intermediate products received from offsite that are processed at the facility in 

the reporting year. 

(3) The methane emission factor used 

for uncontrolled blowdown systems and 

the basis for the value. 

(n) For equipment leaks, the owner or 

operator shall report: 

(1) The cumulative CH4 emissions (in 

metric tons of each pollutant emitted) 

for all equipment leak sources. 

(2) The method used to calculate the 

reported equipment leak emissions. 

(3) The number of each type of 

emission source listed in Equation Y–21 

of this subpart at the facility. 

(o) For storage tanks, the owner or 

operator shall report: 

(1) The cumulative annual CH4

emissions (in metric tons of each 

pollutant emitted) for all storage tanks, 

except for those used to process 

unstabilized crude oil. 

(2) The method used to calculate the 

reported storage tank emissions for 

storage tanks other than those 

processing unstabilized crude (AP–42, 

TANKS 4.09D, Equation Y–22 of this 

subpart, other). 

(3) The total quantity (in MMbbl) of 

crude oil plus the quantity of 

intermediate products received from offsite that are processed at the facility in 

the reporting year. 

(4) The cumulative CH4 emissions (in 

metric tons of each pollutant emitted) 

for storage tanks used to process 

unstabilized crude oil. 

(5) The method used to calculate the 

reported storage tank emissions for 

storage tanks processing unstabilized 

crude oil. 

(6) The quantity of unstabilized crude 

oil received during the calendar year (in 

MMbbl), the average pressure 

differential (in psi), and the mole 

fraction of CH4 in vent gas from the 

unstabilized crude oil storage tank, and 

the basis for the mole fraction. 

(7) The tank-specific methane 

composition data and the gas generation 

rate data, if you did not use Equation Y– 

23. 

(p) For loading operations, the owner 

or operator shall report: 

(1) The cumulative annual CH4

emissions (in metric tons of each 

pollutant emitted) for loading 

operations. 

(2) The quantity and types of 

materials loaded by vessel type (barge, 

tanker, marine vessel, etc.) that have an 

equilibrium vapor-phase concentration 

of methane of 0.5 volume percent or 

greater, and the type of vessels in which 

the material is loaded. 

(3) The type of control system used to 

reduce emissions from the loading of 

material with an equilibrium vaporphase concentration of methane of 0.5 

volume percent or greater, if any 

(submerged loading, vapor balancing, 

etc.). 

(q) Name of each method listed in 

§ 98.254 or a description of 

manufacturer’s recommended method 

used to determine a measured 

parameter. 

§ 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 the production unit or 

units identified by an individual 

identification number in an operating 

permit and/or any process unit or group 

of process units at a facility reacting 

phosphate rock from a common supply 

source with acid. 

§ 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 

(a)(2). 

§ 98.262 GHGs to report. 

(a) You must report CO2 process 

emissions from each wet-process 

phosphoric acid process line. 

(b) You must report under subpart C 

of this part (General Stationary Fuel 


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Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit following the 

requirements of subpart C of this part. 

§ 98.263 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

wet-process phosphoric acid process 

line using the procedures in either 

paragraph (a) or (b) of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining a CEMS 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the process CO2 emissions using 

the procedures in paragraphs (b)(1) and 

(b)(2) of this section. 

(1) Calculate and report the process 

CO2 emissions from each wet-process 

phosphoric acid process line using 

Equation Z–1 of this section: 

E IC P m n,i n,i

n

z

i

b

= ∗ ( ) ∗ ∗

= =

∑∑ 2000

2205 (Eq. Z-1) 44

12 1 1

Where: 

Em = Annual CO2 mass emissions from a wetprocess phosphoric acid process line m 

(metric tons). 

ICn,i = Inorganic carbon content of a grab 

sample batch of phosphate rock by origin 

i obtained during month n, from the 

carbon analysis results (percent by 

weight, expressed as a decimal fraction). 

Pn,i = Mass of phosphate rock by origin i 

consumed in month n by wet-process 

phosphoric acid process line m (tons). 

z = Number of months during which the 

process line m operates. 

b = Number of different types of phosphate 

rock in month, by origin. If the grab 

sample is a composite sample of rock 

from more than one origin, b=1. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(2) You must determine the total 

emissions from the facility using 

Equation Z–2 of this section: 

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. 

(c) If GHG emissions from a wetprocess phosphoric acid process line are 

vented through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraph 

(b) of this section shall not be used to 

calculate process emissions. The owner 

or operator shall report under this 

subpart the combined stack emissions 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part. 

§ 98.264 Monitoring and QA/QC 

requirements. 

(a) You must obtain a monthly grab 

sample of phosphate rock directly from 

the rock being fed to the process line. 

Conduct the representative bulk 

sampling using the applicable standard 

method in the Phosphate Mining States 

Methods Used and Adopted by the 

Association of Fertilizer and Phosphate 

Chemists AFPC Manual 10th Edition 

2009—Version 1.9 (incorporated by 

reference, see § 98.7). If phosphate rock 

is obtained from more than one origin 

in a month, you must obtain a sample 

from each origin of rock or obtain a 

composite representative sample. 

(b) You must determine the inorganic 

carbon content of each monthly grab 

sample of phosphate rock (consumed in 

the production of phosphoric acid) 

using the applicable standard method in 

the Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

AFPC Manual 10th Edition 2009— 

Version 1.9 (incorporated by reference, 

see § 98.7). 

(c) You must determine the mass of 

phosphate rock consumed each month 

(by origin) in each wet-process 

phosphoric acid process line. You can 

use existing plant procedures that are 

used for accounting purposes (such as 

sales records) or you can use data from 

existing monitoring equipment that is 

used to measure total mass flow of 

phosphorous-bearing feed under 40 CFR 

part 60 or part 63. 

§ 98.265 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations in § 98.263(b) is required. 

Therefore, whenever a quality-assured 

value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) For each missing value of the 

inorganic carbon content of phosphate 

rock (by origin), you must use the 

appropriate default factor provided in 

Table Z–1 of this subpart. Alternatively, 

the you must determine substitute data 

value by calculating the arithmetic 

average of the quality-assured values of 

inorganic carbon contents of phosphate 

rock of origin i (see Equation Z–1 of this 

subpart) from samples immediately 

preceding and immediately following 

the missing data incident. If no qualityassured data on inorganic carbon 

contents of phosphate rock of origin i 

are available prior to the missing data 

incident, the substitute data value shall 

be the first quality-assured value for 

inorganic carbon contents for phosphate 

rock of origin i obtained after the 

missing data period. 

(b) For each missing value of monthly 

mass consumption of phosphate rock 

(by origin), you must use the best 

available estimate based on all available 

process data or data used for accounting 

purposes. 

§ 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 (b) of this 

section. 

(a) Annual phosphoric acid 

production by origin (as listed in Table 

Z–1 to this subpart) of the phosphate 

rock (tons). 

(b) Annual phosphoric acid permitted 

production capacity (tons). 

(c) Annual arithmetic average percent 

inorganic carbon in phosphate rock 

from monthly records. 

(d) Annual phosphate rock 

consumption from monthly 

measurement records by origin, (as 


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listed in Table Z–1 to this subpart) 

(tons). 

(e) If you use a CEMS to measure CO2

emissions, then you must report the 

information in paragraphs (e)(1) and 

(e)(2) of this section. 

(1) The identification number of each 

wet-process phosphoric acid process 

line. 

(2) The annual CO2 emissions from 

each wet-process phosphoric acid 

process line (metric tons) and the 

relevant information required under 40 

CFR 98.36 (e)(2)(vi) for the Tier 4 

Calculation Methodology. 

(f) If you do not use a CEMS to 

measure emissions, then you must 

report the information in paragraphs 

(f)(1) through (f)(8) of this section. 

(1) Identification number of each wetprocess phosphoric acid process line. 

(2) Annual CO2 emissions from each 

wet-process phosphoric acid process 

line (metric tons) as calculated by 

Equation Z–1 of this subpart. 

(3) Annual phosphoric acid permitted 

production capacity (tons) for each wetprocess phosphoric acid process line 

(metric tons). 

(4) Method used to estimate any 

missing values of inorganic carbon 

content of phosphate rock for each wetprocess phosphoric acid process line. 

(5) Monthly inorganic carbon content 

of phosphate rock for each wet-process 

phosphoric acid process line (percent by 

weight, expressed as a decimal fraction). 

(6) Monthly mass of phosphate rock 

consumed by origin, (as listed in Table 

Z–1 of this subpart) in production for 

each wet-process phosphoric acid 

process line (tons). 

(7) Number of wet-process phosphoric 

acid process lines. 

(8) Number of times missing data 

procedures were used to estimate 

phosphate rock consumption (months) 

and inorganic carbon contents of the 

phosphate rock (months). 

§ 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 (c) of 

this section for each wet-process 

phosphoric acid production facility. 

(a) Monthly mass of phosphate rock 

consumed by origin (as listed in Table 

Z–1 of this subpart) (tons). 

(b) Records of all phosphate rock 

purchases and/or deliveries (if vertically 

integrated with a mine). 

(c) Documentation of the procedures 

used to ensure the accuracy of monthly 

phosphate rock consumption by origin, 

(as listed in Table Z–1 of this subpart). 

§ 98.268 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE Z–1 TO SUBPART Z OF PART

98—DEFAULT CHEMICAL COMPOSITION OF PHOSPHATE ROCK BY ORIGIN

Origin 

Total carbon 

(percent by 

weight) 

Central Florida .......................... 1.6 

North Florida ............................. 1.76 

North Carolina (Calcined) ......... 0.76 

Idaho (Calcined) ....................... 0.60 

Morocco .................................... 1.56 

Subpart AA—Pulp and Paper 

Manufacturing 

§ 98.270 Definition of source category. 

(a) The pulp and paper manufacturing 

source category consists of facilities that 

produce market pulp (i.e., stand-alone 

pulp facilities), manufacture pulp and 

paper (i.e., integrated facilities), produce 

paper products from purchased pulp, 

produce secondary fiber from recycled 

paper, convert paper into paperboard 

products (e.g., containers), or operate 

coating and laminating processes. 

(b) The emission units for which GHG 

emissions must be reported are listed in 

paragraphs (b)(1) through (b)(5) of this 

section: 

(1) Chemical recovery furnaces at 

kraft and soda mills (including recovery 

furnaces that burn spent pulping liquor 

produced by both the kraft and 

semichemical process). 

(2) Chemical recovery combustion 

units at sulfite facilities. 

(3) Chemical recovery combustion 

units at stand-alone semichemical 

facilities. 

(4) Pulp mill lime kilns at kraft and 

soda facilities. 

(5) Systems for adding makeup 

chemicals (CaCO3, Na2CO3) in the 

chemical recovery areas of chemical 

pulp mills. 

§ 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 (a)(2). 

§ 98.272 GHGs to report. 

You must report the emissions listed 

in paragraphs (a) through (f) of this 

section: 

(a) CO2, biogenic CO2, CH4, and N2O 

emissions from each kraft or soda 

chemical recovery furnace. 

(b) CO2, biogenic CO2, CH4, and N2O 

emissions from each sulfite chemical 

recovery combustion unit. 

(c) CO2, biogenic CO2, CH4, and N2O 

emissions from each stand-alone 

semichemical chemical recovery 

combustion unit. 

(d) CO2, biogenic CO2, CH4, and N2O 

emissions from each kraft or soda pulp 

mill lime kiln. 

(e) CO2 emissions from addition of 

makeup chemicals (CaCO3, Na2CO3) in 

the chemical recovery areas of chemical 

pulp mills. 

(f) CO2, CH4, and N2O combustion 

emissions from each stationary 

combustion unit. You must calculate 

and report these emissions under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

§ 98.273 Calculating GHG emissions. 

(a) For each chemical recovery 

furnace located at a kraft or soda 

facility, you must determine CO2, 

biogenic CO2, CH4, and N2O emissions 

using the procedures in paragraphs 

(a)(1) through (a)(3) of this section. CH4

and N2O emissions must be calculated 

as the sum of emissions from 

combustion of fossil fuels and 

combustion of biomass in spent liquor 

solids. 

(1) Calculate fossil fuel-based CO2

emissions from direct measurement of 

fossil fuels consumed and default 

emissions factors according to the Tier 

1 methodology for stationary 

combustion sources in § 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). 

(3) Calculate biogenic CO2 emissions 

and emissions of CH4 and N2O from 

biomass using measured quantities of 

spent liquor solids fired, site-specific 

HHV, and default or site-specific 

emissions factors, according to Equation 

AA–1 of this section: 

CO CH or N O from biomass Solids HHV EF 24 2 , , (Eq. = ∗ ∗∗ (. . ) 0 907 18 AA-1)


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Where: 

CO2, CH4, or N2O, from Biomass = Biogenic 

CO2 emissions or emissions of CH4 or 

N2O from spent liquor solids combustion 

(metric tons per year). 

Solids = Mass of spent liquor solids 

combusted (short tons per year) 

determined according to § 98.274(b). 

HHV = Annual high heat value of the spent 

liquor solids (mmBtu per kilogram) 

determined according to § 98.274(b). 

EF = Default emission factor for CO2, CH4, or 

N2O, from Table AA–1 of this subpart (kg 

CO2, CH4, or N2O per mmBtu). 

0.90718 = Conversion factor from short tons 

to metric tons. 

(b) For each chemical recovery 

combustion unit located at a sulfite or 

stand-alone semichemical facility, you 

must determine CO2, CH4, and N2O 

emissions using the procedures in 

paragraphs (b)(1) through (b)(4) of this 

section: 

(1) Calculate fossil CO2 emissions 

from fossil fuels from direct 

measurement of fossil fuels consumed 

and default emissions factors according 

to the Tier 1 Calculation Methodology 

for stationary combustion sources in 

§ 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). 

(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

12 Solids CC ( . ) 0 90718

Where: 

Biogenic CO2 = Annual CO2 mass emissions 

for spent liquor solids combustion 

(metric tons per year). 

Solids = Mass of the spent liquor solids 

combusted (short tons per year) 

determined according to § 98.274(b). 

CC = Annual carbon content of the spent 

liquor solids, determined according to 

§ 98.274(b) (percent by weight, expressed 

as a decimal fraction, e.g., 95% = 0.95). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

0.90718 = Conversion from short tons to 

metric tons. 

(4) Calculate CH4 and N2O emissions 

from biomass using Equation AA–1 of 

this section and the default CH4 and 

N2O emissions factors for kraft facilities 

in Table AA–1 of this subpart and 

convert the CH4 or N2O emissions to 

metric tons of CO2 equivalent by 

multiplying each annual CH4 and N2O 

emissions total by the appropriate global 

warming potential (GWP) factor from 

Table A–1 of subpart A of this part. 

(c) For each pulp mill lime kiln 

located at a kraft or soda facility, you 

must determine CO2, CH4, and N2O 

emissions using the procedures in 

paragraphs (c)(1) through (c)(3) of this 

section: 

(1) Calculate CO2 emissions from 

fossil fuel from direct measurement of 

fossil fuels consumed and default HHV 

and default emissions factors, according 

to the Tier 1 Calculation Methodology 

for stationary combustion sources in 

§ 98.33(a)(1); use the default HHV listed 

in Table C–1 of subpart C and the 

default CO2 emissions factors listed in 

Table AA–2 of this subpart. 

(2) Calculate CH4 and N2O emissions 

from fossil fuel from direct 

measurement of fossil fuels consumed, 

default HHV, and default emissions 

factors and convert to metric tons of CO2

equivalent according to the 

methodology for stationary combustion 

sources in § 98.33(c); use the default 

HHV listed in Table C–1 of subpart C 

and the default CH4 and N2O emissions 

factors listed in Table AA–2 of this 

subpart. 

(3) Biogenic CO2 emissions from 

conversion of CaCO3 to CaO are 

included in the biogenic CO2 estimates 

calculated for the chemical recovery 

furnace in paragraph (a)(3) of this 

section. 

(d) For makeup chemical use, you 

must calculate CO2 emissions by using 

direct or indirect measurement of the 

quantity of chemicals added and ratios 

of the molecular weights of CO2 and the 

makeup chemicals, according to 

Equation AA–3 of this section: 

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 

per year). 

M (NaCO3) = Make-up quantity of Na2CO3

used for the reporting year (metric tons 

per year). 

44 = Molecular weight of CO2. 

100 = Molecular weight of CaCO3. 

105.99 = Molecular weight of Na2CO3. 

§ 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) Fuel properties needed to perform 

the calculations in Equations AA–1 and 

AA–2 of this subpart must be 

determined according to paragraphs 

(b)(1) through (b)(3) of this section. 

(1) High heat values of black liquor 

must be determined no less than 

annually using T684 om–06 Gross 

Heating Value of Black Liquor, TAPPI 

(incorporated by reference, see § 98.7). If 

measurements are performed more 

frequently than annually, then the high 

heat value used in Equation AA–1 of 

this subpart must be based on the 

average of the representative 

measurements made during the year. 

(2) The annual mass of spent liquor 

solids must be determined using either 

of the methods specified in paragraph 

(b)(2)(i) or (b)(2)(ii) of this section. 

(i) Measure the mass of spent liquor 

solids annually (or more frequently) 

using T–650 om–05 Solids Content of 

Black Liquor, TAPPI (incorporated by 

reference in § 98.7). If measurements are 

performed more frequently than 

annually, then the mass of spent liquor 

solids used in Equation AA–1 of this 

subpart must be based on the average of 

the representative measurements made 

during the year. 

(ii) Determine the annual mass of 

spent liquor solids based on records of 

measurements made with an online 

measurement system that determines 


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the mass of spent liquor solids fired in 

a chemical recovery furnace or chemical 

recovery combustion unit. 

(3) Carbon analyses for spent pulping 

liquor must be determined no less than 

annually using ASTM D5373–08 

Standard Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). If 

measurements using ASTM D5373–08 

are performed more frequently than 

annually, then the spent pulping liquor 

carbon content used in Equation AA–2 

of this subpart must be based on the 

average of the representative 

measurements made during the year. 

(c) Each facility must keep records 

that include a detailed explanation of 

how company records of measurements 

are used to estimate GHG emissions. 

The owner or operator must also 

document the procedures used to ensure 

the accuracy of the measurements of 

fuel, spent liquor solids, and makeup 

chemical usage, including, but not 

limited to calibration of weighing 

equipment, fuel flow meters, and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices must be recorded and the 

technical basis for these estimates must 

be provided. The procedures used to 

convert spent pulping liquor flow rates 

to units of mass (i.e., spent liquor solids 

firing rates) also must be documented. 

(d) Records must be made available 

upon request for verification of the 

calculations and measurements. 

§ 98.275 Procedures for estimating 

missing data. 

A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions during unit 

operation or if a required sample is not 

taken), a substitute data value for the 

missing parameter shall be used in the 

calculations, according to the 

requirements of paragraphs (a) through 

(c) of this section: 

(a) There are no missing data 

procedures for measurements of heat 

content and carbon content of spent 

pulping liquor. A re-test must be 

performed if the data from any annual 

measurements are determined to be 

invalid. 

(b) For missing measurements of the 

mass of spent liquor solids or spent 

pulping liquor flow rates, use the lesser 

value of either the maximum mass or 

fuel flow rate for the combustion unit, 

or the maximum mass or flow rate that 

the fuel meter can measure. 

(c) For the use of makeup chemicals 

(carbonates), the substitute data value 

shall be the best available estimate of 

makeup chemical consumption, based 

on available data (e.g., past accounting 

records, production rates). The owner or 

operator shall document and keep 

records of the procedures used for all 

such estimates. 

§ 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 (k) of this section 

as applicable: 

(a) Annual emissions of CO2, biogenic 

CO2, CH4, biogenic CH4 N2O, and 

biogenic N2O (metric tons per year). 

(b) Annual quantities fossil fuels by 

type used in chemical recovery furnaces 

and chemical recovery combustion units 

in short tons for solid fuels, gallons for 

liquid fuels and scf for gaseous fuels. 

(c) Annual mass of the spent liquor 

solids combusted (short tons per year), 

and basis for determining the annual 

mass of the spent liquor solids 

combusted (whether based on T650 om05 Solids Content of Black Liquor, 

TAPPI (incorporated by reference, see 

§ 98.7) or an online measurement 

system). 

(d) The high heat value (HHV) of the 

spent liquor solids used in Equation 

AA–1 of this subpart (mmBtu per 

kilogram). 

(e) The default emission factor for 

CO2, CH4, or N2O, used in Equation AA– 

1 of this subpart (kg CO2, CH4, or N2O 

per mmBtu). 

(f) The carbon content (CC) of the 

spent liquor solids, used in Equation 

AA–2 of this subpart (percent by weight, 

expressed as a decimal fraction, e.g., 

95% = 0.95). 

(g) Annual quantities of fossil fuels by 

type used in pulp mill lime kilns in 

short tons for solid fuels, gallons for 

liquid fuels and scf for gaseous fuels. 

(h) Make-up quantity of CaCO3 used 

for the reporting year (metric tons per 

year) used in Equation AA–3 of this 

subpart. 

(i) Make-up quantity of Na2CO3 used 

for the reporting year (metric tons per 

year) used in Equation AA–3 of this 

subpart. 

(j) Annual steam purchases (pounds 

of steam per year). 

(k) Annual production of pulp and/or 

paper products produced (metric tons). 

§ 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 (f) 

of this section. 

(a) GHG emission estimates (including 

separate estimates of biogenic CO2) for 

each emissions source listed under 

§ 98.270(b). 

(b) Annual analyses of spent pulping 

liquor HHV for each chemical recovery 

furnace at kraft and soda facilities. 

(c) Annual analyses of spent pulping 

liquor carbon content for each chemical 

recovery combustion unit at a sulfite or 

semichemical pulp facility. 

(d) Annual quantity of spent liquor 

solids combusted in each chemical 

recovery furnace and chemical recovery 

combustion unit, and the basis for 

detemining the annual quantity of the 

spent liquor solids combusted (whether 

based on T650 om–05 Solids Content of 

Black Liquor, TAPPI (incorporated by 

reference, see § 98.7) or an online 

measurement system). If an online 

measurement system is used, you must 

retain records of the calculations used to 

determine the annual quantity of spent 

liquor solids combusted from the 

continuous measurements. 

(e) Annual steam purchases. 

(f) Annual quantities of makeup 

chemicals used. 

§ 98.278 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE AA–1 TO SUBPART AA OF PART 98—KRAFT PULPING LIQUOR EMISSIONS FACTORS FOR BIOMASS-BASED CO2, 

CH4, AND N2O 

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 


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TABLE AA–1 TO SUBPART AA OF PART 98—KRAFT PULPING LIQUOR EMISSIONS FACTORS FOR BIOMASS-BASED CO2, 

CH4, AND N2O—Continued 

Wood furnish 

Biomass-based emissions factors 

(kg/mmBtu HHV) 

CO2

a CH4 N2O 

Straw .................................................................................................................................................................... 95.1 

a Includes emissions from both the recovery furnace and pulp mill lime kiln. 

TABLE AA–2 TO SUBPART AA OF PART 98—KRAFT LIME KILN AND CALCINER EMISSIONS FACTORS FOR FOSSIL FUELBASED 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 0.0001 

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 

(a)(2). 

§ 98.282 GHGs to report. 

You must report: 

(a) CO2 and CH4 process emissions 

from all silicon carbide process units or 

furnaces combined. 

(b) CO2, CH4, and N2O emissions from 

each stationary combustion unit. You 

must report these emissions under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

§ 98.283 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

silicon carbide process unit or 

production furnace using the 

procedures in either paragraph (a) or (b) 

of this section. You must determine CH4

process emissions in accordance with 

the procedures specified in paragraph 

(d) of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining CEMS 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the process CO2 emissions using 

the procedures in paragraphs (b)(1) and 

(b)(2) of this section. 

(1) Use Equation BB–1 of this section 

to calculate the facility-specific 

emissions factor for determining CO2

emissions. The carbon content must be 

measured monthly and used to calculate 

a monthly CO2 emisssions factor: 

EF CCF CO n n 2, =∗ ∗ ⎛

⎝

⎜ ⎞

⎠

⎟ 0 65 . 44

12 (Eq. BB-1)

Where: 

EFCO2,n = CO2 emissions factor in month n 

(metric tons CO2/metric ton of petroleum 

coke consumed). 

0.65 = Adjustment factor for the amount of 

carbon in silicon carbide product 

(assuming 35 percent of carbon input is 

in the carbide product). 

CCFn = Carbon content factor for petroleum 

coke consumed in month n from the 

supplier or as measured by the 

applicable method incorporated by 

reference in § 98.7 according to 

§ 98.284(c) (percent by weight expressed 

as a decimal fraction). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

(2) Use Equation BB–2 of this section 

to calculate annual CO2 process 

emissions from all silicone carbide 

production: 

CO T EF n CO n

n

2

=1

= (Eq. BB-2) ⎡ ∗ ⎣ ⎤

⎦ ∑ ∗ 2,

2000

2205

12

Where: CO2 = Annual CO2 emissions from silicon 

carbide production facility (metric tons 

CO2). 

Tn = Petroleum coke consumption in month 

n (tons). 


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EFCO2,n = CO2 emissions factor from month 

n (calculated in Equation BB–1 of this 

section). 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

n = Number of month. 

(c) If GHG emissions from a silicon 

carbide production furnace or process 

unit are vented through the same stack 

as any combustion unit or process 

equipment that reports CO2 emissions 

using a CEMS that complies with the 

Tier 4 Calculation Methodology in 

subpart C of this part (General 

Stationary Fuel Combustion Sources), 

then the calculation methodology in 

paragraph (b) of this section shall not be 

used to calculate process emissions. The 

owner or operator shall report under 

this subpart the combined stack 

emissions according to the Tier 4 

Calculation Methodology in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part. 

(d) You must calculate annual process 

CH4 emissions from all silicon carbide 

production combined using Equation 

BB–3 of this section: 

CH Tn

n

4

=1

= ∗ ∑[ ] 10 2 ∗ ∗ (Eq. BB-3) 2000

2205

0 001

12

. .

Where: 

CH4 = Annual CH4 emissions from silicon 

carbide production facility (metric tons 

CH4). 

Tn = Petroleum coke consumption in month 

n (tons). 

10.2 = CH4 emissions factor (kg CH4/metric 

ton coke). 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

0.001 = Conversion factor from kilograms to 

metric tons. 

n = Number of month. 

§ 98.284 Monitoring and QA/QC 

requirements. 

(a) You must measure your 

consumption of petroleum coke using 

plant instruments used for accounting 

purposes including direct measurement 

weighing the petroleum coke fed into 

your process (by belt scales or a similar 

device) or through the use of purchase 

records. 

(b) You must document the 

procedures used to ensure the accuracy 

of monthly petroleum coke 

consumption measurements. 

(c) For CO2 process emissions, you 

must determine the monthly carbon 

content of the petroleum coke using 

reports from the supplier. Alternatively, 

facilities can measure monthly carbon 

contents of the petroleum coke using 

ASTM D3176–89 (Reapproved 2002) 

Standard Practice for Ultimate Analysis 

of Coal and Coke (incorporated by 

reference, see § 98.7) and ASTM D5373– 

08 Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Laboratory 

Samples of Coal (incorporated by 

reference, see § 98.7). 

(d) For quality assurance and quality 

control of the supplier data, you must 

conduct an annual measurement of the 

carbon content of the petroleum coke 

using ASTM D3176–89 and ASTM 

D5373–08 Standard Test Methods for 

Instrumental Determination of Carbon, 

Hydrogen, and Nitrogen in Laboratory 

Samples of Coal (incorporated by 

reference, see § 98.7). 

§ 98.285 Procedures for estimating 

missing data. 

For the petroleum coke input 

procedure in § 98.283(b), a complete 

record of all measured parameters used 

in the GHG emissions calculations is 

required (e.g., carbon content values, 

etc.). Therefore, whenever a qualityassured value of a required parameter is 

unavailable, a substitute data value for 

the missing parameter shall be used in 

the calculations as specified in the 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) For each missing value of the 

monthly carbon content of petroleum 

coke, the substitute data value shall be 

the arithmetic average of the qualityassured values of carbon contents 

immediately preceding and immediately 

following the missing data incident. If 

no quality-assured data on carbon 

contents are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value for carbon contents 

obtained after the missing data period. 

(b) For each missing value of the 

monthly petroleum coke consumption, 

the substitute data value shall be the 

best available estimate of the petroleum 

coke consumption based on all available 

process data or information used for 

accounting purposes (such as purchase 

records). 

§ 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) or (b) of this section, 

as applicable for each silicon carbide 

production facility. 

(a) If a CEMS is used to measure 

process CO2 emissions, you must report 

under this subpart the relevant 

information required for the Tier 4 

Calculation Methodology in § 98.36 and 

the information listed in this paragraph 

(a): 

(1) Annual consumption of petroleum 

coke (tons). 

(2) Annual production of silicon 

carbide (tons). 

(3) Annual production capacity of 

silicon carbide (tons). 

(b) If a CEMS is not used to measure 

process CO2 emissions, you must report 

the information listed in this paragraph 

(b) for all furnaces combined: 

(1) Monthly consumption of 

petroleum coke (tons). 

(2) Annual production of silicon 

carbide (tons). 

(3) Annual production capacity of 

silicon carbide (tons). 

(4) Carbon content factor of petroleum 

coke from the supplier or as measured 

by the applicable method in § 98.284(c) 

for each month (percent by weight 

expressed as a decimal fraction). 

(5) Whether carbon content of the 

petroleum coke is based on reports from 

the supplier or through self 

measurement using applicable ASTM 

standard method. 

(6) CO2 emissions factor calculated for 

each month (metric tons CO2/metric ton 

of petroleum coke consumed). 

(7) Sampling analysis results for 

carbon content of consumed petroleum 

coke as determined for QA/QC of 

supplier data under § 98.284(d) (percent 

by weight expressed as a decimal 

fraction). 

(8) Number of times in the reporting 

year that missing data procedures were 

followed to measure the carbon contents 

of petroleum coke (number of months) 

and petroleum coke consumption 

(number of months). 

§ 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) and (b) of 

this section for each silicon carbide 

production facility. 

(a) If a CEMS is used to measure CO2

emissions, you must retain under this 

subpart the records required for the Tier 

4 Calculation Methodology in § 98.37 


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and the information listed in this 

paragraph (a): 

(1) Records of all petroleum coke 

purchases. 

(2) Annual operating hours. 

(b) If a CEMS is not used to measure 

emissions, you must retain records for 

the information listed in this paragraph 

(b): 

(1) Records of all analyses and 

calculations conducted for reported data 

listed in § 98.286(b). 

(2) Records of all petroleum coke 

purchases. 

(3) Annual operating hours. 

§ 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) A soda ash manufacturing facility 

is any facility with a manufacturing line 

that produces soda ash by one of the 

methods in paragraphs (a)(1) through (3) 

of this section: 

(1) Calcining trona. 

(2) Calcining sodium sesquicarbonate. 

(3) Using a liquid alkaline feedstock 

process that directly produces CO2. 

(b) In the context of the soda ash 

manufacturing sector, ‘‘calcining’’ 

means the thermal/chemical conversion 

of the bicarbonate fraction of the 

feedstock to sodium carbonate. 

§ 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 

(a)(2). 

§ 98.292 GHGs to report. 

You must report: 

(a) CO2 process emissions from each 

soda ash manufacturing line combined. 

(b) CO2 combustion emissions from 

each soda ash manufacturing line. 

(c) CH4 and N2O combustion 

emissions from each soda ash 

manufacturing line. You must calculate 

and report these emissions under 

subpart C of this part (General 

Stationary Fuel Combustion Sources) by 

following the requirements of subpart C. 

(d) CO2, CH4, and N2O emissions from 

each stationary combustion unit other 

than soda ash manufacturing lines. You 

must calculate and report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

§ 98.293 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions from each 

soda ash manufacturing line using the 

procedures specified in paragraph (a) or 

(b) of this section. 

(a) For each soda ash manufacturing 

line that meets the conditions specified 

in § 98.33(b)(4)(ii) or (b)(4)(iii), you must 

calculate and report under this subpart 

the combined process and combustion 

CO2 emissions by operating and 

maintaining a CEMS to measure CO2

emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(b) For each soda ash manufacturing 

line that is not subject to the 

requirements in paragraph (a) of this 

section, calculate and report the process 

CO2 emissions from the soda ash 

manufacturing line by using the 

procedure in either paragraphs (b)(1), 

(b)(2), or (b)(3) of this section; and the 

combustion CO2 emissions using the 

procedure in paragraph (b)(4) of this 

section. 

(1) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions by operating 

and maintaining a CEMS to measure 

CO2 emissions according to the Tier 4 

Calculation Methodology specified in 

§ 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part (General Stationary Fuel 

Combustion Sources). 

(2) Use either Equation CC–1 or 

Equation CC–2 of this section to 

calculate annual CO2 process emissions 

from each manufacturing line that 

calcines trona to produce soda ash: 

E (Eq. CC-1) k = ⎡( ) ∗ ( ) ⎣ ⎤

⎦ ∗ ∗

=

∑ IC T T n t n n

2000

2205

0 097

1 1

12 .

E (Eq. CC-2) k = ⎡( ) ∗ ( ) ⎣ ⎤

⎦ ∗ ∗

=

∑ IC T sa n sa n n

2000

2205

0 138

1 1

12 .

Where: 

Ek = Annual CO2 process emissions from 

each manufacturing line, k (metric tons). 

(ICT)n = Inorganic carbon content (percent by 

weight, expressed as a decimal fraction) 

in trona input, from the carbon analysis 

results for month n. This represents the 

ratio of trona to trona ore. 

(ICsa)n = Inorganic carbon content (percent by 

weight, expressed as a decimal fraction) 

in soda ash output, from the carbon 

analysis results for month n. This 

represents the purity of the soda ash 

produced. 

(Tt)n = Mass of trona input in month n (tons). 

(Tsa)n = Mass of soda ash output in month n 

(tons). 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

0.097/1 = Ratio of ton of CO2 emitted for each 

ton of trona. 

0.138/1 = Ratio of ton of CO2 emitted for each 

ton of soda ash produced. 

(3) Site-specific emission factor 

method. Use Equations CC–3, CC–4, and 

CC–5 of this section to determine 

annual CO2 process emissions from 

manufacturing lines that use the liquid 

alkaline feedstock process to produce 

soda ash. You must conduct an annual 

performance test and measure CO2

emissions and flow rates at all process 

vents from the mine water stripper/ 

evaporator for each manufacturing line 

and calculate CO2 emissions as 

described in paragraphs (b)(3)(i) through 

(b)(3)(iv) of this section. 

(i) During the performance test, you 

must measure the process vent flow 

from each process vent during the test 

and calculate the average rate for the 

test period in metric tons per hour. 

(ii) Using the test data, you must 

calculate the hourly CO2 emission rate 

using Equation CC–3 of this section: 


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ER C x Q x CO co 2 2

9 4 = ∗ ⎡( ) 10000 2 59 10 44 60 4 53 10 ∗ ∗ ⎣ ⎤

⎦ ∗∗ ∗ − − . ( ) . (Eq. CC-3)

Where: 

ERCO2 = CO2 mass emission rate (metric tons/ 

hour). 

CCO2 = Hourly CO2 concentration (percent 

CO2) as determined by § 98.294(c). 

10000 = Parts per million per percent 

2.59 x 10¥9 = Conversion factor (poundsmole/dscf/ppm). 

44 = Pounds per pound-mole of carbon 

dioxide. 

Q = Stack gas volumetric flow rate per 

minute (dscfm). 

60 = Minutes per hour 

4.53 × 10 ¥4 = Conversion factor (metric tons/ 

pound) 

(iii) Using the test data, you must 

calculate a CO2 emission factor for the 

process using Equation CC–4 of this 

section: 

EF ER

V

CO

CO

t

2

2

4 4 53 10 =

( ) ∗ − . x

(Eq. CC-4)

Where: 

EFCO2 = CO2 emission factor (metric tons 

CO2/metric ton of process vent flow from 

mine water stripper/evaporator). 

ERCO2 = CO2 mass emission rate (metric tons/ 

hour). 

Vt = Process vent flow rate from mine water 

stripper/evaporator during annual 

performance test (pounds/hour). 

4.53 × 10¥4 = Conversion factor (metric tons/ 

pound) 

(iv) You must calculate annual CO2

process emissions from each 

manufacturing line using Equation CC– 

5 of this section: 

E EF V k CO a = ∗∗ ( ) ∗ 2 0.453 (Eq. CC-5) H

Where: 

Ek = Annual CO2 process emissions for each 

manufacturing line, k (metric tons). 

EFCO2 = CO2 emission factor (metric tons 

CO2/metric ton of process vent flow from 

mine water stripper/evaporator). 

Va = Annual process vent flow rate from 

mine water stripper/evaporator 

(thousand pounds/hour). 

H = Annual operating hours for the each 

manufacturing line. 

0.453 = Conversion factor (metric tons/ 

thousand pounds). 

(4) Calculate and report under subpart 

C of this part (General Stationary Fuel 

Combustion Sources) the combustion 

CO2, CH4, and N2O emissions in the 

soda ash manufacturing line according 

to the applicable requirements in 

subpart C. 

§ 98.294 Monitoring and QA/QC 

requirements. 

Section 98.293 provides three 

different procedures for emission 

calculations. The appropriate 

paragraphs (a) through (c) of this section 

should be used for the procedure 

chosen. 

(a) If you determine your emissions 

using § 98.293(b)(2) (Equation CC–1 of 

this subpart) you must: 

(1) Determine the monthly inorganic 

carbon content of the trona from a 

weekly composite analysis for each soda 

ash manufacturing line, using a 

modified version of ASTM E359–00 

(Reapproved 2005)e1, Standard Test 

Methods for Analysis of Soda Ash 

(Sodium Carbonate) (incorporated by 

reference, see § 98.7). ASTM E359– 

00(Reapproved 2005) e1 is designed to 

measure the total alkalinity in soda ash 

not in trona. The modified method of 

ASTM E359–00 adjusts the regular 

ASTM method to expresse the results in 

terms of trona. Although ASTM E359– 

00 (Reapproved 2005) e1 uses manual 

titration, suitable autotitrators may also 

be used for this determination. 

(2) Measure the mass of trona input 

produced by each soda ash 

manufacturing line on a monthly basis 

using belt scales or methods used for 

accounting purposes. 

(3) Document the procedures used to 

ensure the accuracy of the monthly 

measurements of trona consumed. 

(b) If you calculate CO2 process 

emissions based on soda ash production 

(§ 98.293(b)(2) Equation CC–2 of this 

subpart), you must: 

(1) Determine the inorganic carbon 

content of the soda ash (i.e., soda ash 

purity) using ASTM E359–00 

(Reapproved 2005) e1 Standard Test 

Methods for Analysis of Soda Ash 

(Sodium Carbonate) (incorporated by 

reference, see § 98.7). Although ASTM 

E359–00 (Reapproved 2005) e1 uses 

manual titration, suitable autotitrators 

may also be used for this determination. 

(2) Measure the mass of soda ash 

produced by each soda ash 

manufacturing line on a monthly basis 

using belt scales, by weighing the soda 

ash at the truck or rail loadout points of 

your facility, or methods used for 

accounting purposes. 

(3) Document the procedures used to 

ensure the accuracy of the monthly 

measurements of soda ash produced. 

(c) If you calculate CO2 emissions 

using the site-specific emission factor 

method in § 98.293(b)(3), you must: 

(1) Conduct an annual performance 

test that is based on representative 

performance (i.e., performance based on 

normal operating conditions) of the 

affected process. 

(2) Sample the stack gas and conduct 

three emissions test runs of 1 hour each. 

(3) Conduct the stack test using EPA 

Method 3A at 40 CFR part 60, appendix 

A–2 to measure the CO2 concentration, 

Method 2, 2A, 2C, 2D, or 2F at 40 CFR 

part 60, appendix A–1 or Method 26 at 

40 CFR part 60, appendix A–2 to 

determine the stack gas volumetric flow 

rate. All QA/QC procedures specified in 

the reference test methods and any 

associated performance specifications 

apply. For each test, the facility must 

prepare an emission factor 

determination report that must include 

the items in paragraphs (c)(3)(i) through 

(c)(3)(iii) of this section. 

(i) Analysis of samples, determination 

of emissions, and raw data. 

(ii) All information and data used to 

derive the emissions factor(s). 

(iii) You must determine the average 

process vent flow rate from the mine 

water stripper/evaporater during each 

test and document how it was 

determined. 

(4) You must also determine the 

annual vent flow rate from the mine 

water stripper/evaporater from monthly 

information using the same plant 

instruments or procedures used for 

accounting purposes (i.e., volumetric 

flow meter). 

§ 98.295 Procedures for estimating 

missing data. 

For the emission calculation 

methodologies in § 98.293(b)(2) and 

(b)(3), a complete record of all measured 

parameters used in the GHG emissions 

calculations is required (e.g., inorganic 

carbon content values, etc.). Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable, a 

substitute data value for the missing 

parameter shall be used in the 

calculations as specified in the 

paragraphs (a) through (d) of this 


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section. You must document and keep 

records of the procedures used for all 

such missing value estimates. 

(a) For each missing value of the 

weekly composite of inorganic carbon 

content of either soda ash or trona, the 

substitute data value shall be the 

arithmetic average of the quality-assured 

values of inorganic carbon contents 

from the week immediately preceding 

and the week immediately following the 

missing data incident. If no qualityassured data on inorganic carbon 

contents are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value for carbon contents 

obtained after the missing data period. 

(b) For each missing value of either 

the monthly soda ash production or the 

trona consumption, the substitute data 

value shall be the best available 

estimate(s) of the parameter(s), based on 

all available process data or data used 

for accounting purposes. 

(c) For each missing value collected 

during the performance test (hourly CO2

concentration, stack gas volumetric flow 

rate, or average process vent flow from 

mine water stripper/evaporator during 

performance test), you must repeat the 

annual performance test following the 

calculation and monitoring and QA/QC 

requirements under §§ 98.293(b)(3) and 

98.294(c). 

(d) For each missing value of the 

monthly process vent flow rate from 

mine water stripper/evaporator, the 

subsititute data value shall be the best 

available estimate(s) of the parameter(s), 

based on all available process data or 

the lesser of the maximum capacity of 

the system or the maximum rate the 

meter can measure. 

§ 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) or (b) of this section, 

as appropriate for each soda ash 

manufacturing facility. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required under § 98.36 and the 

following information in this paragraph 

(a): 

(1) Annual consumption of trona or 

liquid alkaline feedstock for each 

manufacturing line (metric tons). 

(2) Annual production of soda ash for 

each manufacturing line (tons). 

(3) Annual production capacity of 

soda ash for each manufacturing line 

(tons). 

(4) Identification number of each 

manufacturing line. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in this paragraph (b): 

(1) Identification number of each 

manufacturing line. 

(2) Annual process CO2 emissions 

from each soda ash manufacturing line 

(metric tons). 

(3) Annual production of soda ash 

(tons). 

(4) Annual production capacity of 

soda ash for each manufacturing line 

(tons). 

(5) Monthly consumption of trona or 

liquid alkaline feedstock for each 

manufacturing line (tons). 

(6) Monthly production of soda ash 

for each manufacturing line (metric 

tons). 

(7) Inorganic carbon content factor of 

trona or soda ash (depending on use of 

Equations CC–1 or CC–2 of this subpart) 

as measured by the applicable method 

in § 98.294(b) or (c) for each month 

(percent by weight expressed as a 

decimal fraction). 

(8) Whether CO2 emissions for each 

manufacturing line were calculated 

using a trona input method as described 

in Equation CC–1 of this subpart, a soda 

ash output method as described in 

Equation CC–2 of this subpart, or a sitespecific emission factor method as 

described in Equations CC–3 through 

CC–5 of this subpart. 

(9) Number of manufacturing lines 

located used to produce soda ash. 

(10) If you produce soda ash using the 

liquid alkaline feedstock process and 

use the site-specific emission factor 

method (§ 98.293(b)(3)) to estimate 

emissions then you must report the 

following relevant information: 

(i) Stack gas volumetric flow rate per 

minute (dscfm) 

(ii) Hourly CO2 concentration (percent 

CO2) 

(iii) CO2 emission factor (metric tons 

CO2/metric tons of process vent flow 

from mine water stripper/evaporator). 

(iv) CO2 mass emission rate (metric 

tons/hour). 

(v) Average process vent flow from 

mine water stripper/evaporater during 

performance test (pounds/hour). 

(vi) Annual process vent flow rate 

from mine stripper/evaporator 

(thousand pounds/hour). 

(vii) Annual operating hours for each 

manufacturing line used to produce 

soda ash using liquid alkaline feedstock 

(hours). 

(11) Number of times missing data 

procedures were used and for which 

parameter as specified in this paragraph 

(b)(11): 

(i) Trona or soda ash (number of 

months). 

(ii) Inorganic carbon contents of trona 

or soda ash (weeks). 

(iii) Process vent flow rate from mine 

water stripper/evaporator (number of 

months). 

(iv) Stack gas volumetric flow rate 

during performance test (number of 

times). 

(v) Hourly CO2 concentration (number 

of times). 

(vi) Average vent process vent flow 

rate from mine stripper/evaporator 

during performance test (number of 

times). 

§ 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) and (b) of 

this section for each soda ash 

manufacturing line. 

(a) If a CEMS is used to measure CO2

emissions, then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology 

specified in subpart C of this part and 

the information listed in this paragraph 

(a): 

(1) Monthly production of soda ash 

(tons) 

(2) Monthly consumption of trona or 

liquid alkaline feedstock (tons) 

(3) Annual operating hours (hours). 

(b) If a CEMS is not used to measure 

emissions, then you must retain records 

for the information listed in this 

paragraph (b): 

(1) Records of all analyses and 

calculations conducted for determining 

all reported data as listed in § 98.296(b). 

(2) If using Equation CC–1 or CC–2 of 

this subpart, weekly inorganic carbon 

content factor of trona or soda ash, 

depending on method chosen, as 

measured by the applicable method in 

§ 98.294(b) (percent by weight expressed 

as a decimal fraction). 

(3) Annual operating hours for each 

manufacturing line used to produce 

soda ash (hours). 

(4) You must document the 

procedures used to ensure the accuracy 

of the monthly trona consumption or 

soda ash production measurements 

including, but not limited to, calibration 

of weighing equipment and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices must also be recorded, 

and the technical basis for these 

estimates must be provided. 

(5) If you produce soda ash using the 

liquid alkaline feedstock process and 

use the site-specific emission factor 

method to estimate emissions 

(§ 98.293(b)(3)) then you must also 

retain the following relevant 

information: 

(i) Records of performance test results. 

(ii) You must document the 

procedures used to ensure the accuracy 


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of the annual average vent flow 

measurements including, but not 

limited to, calibration of flow rate 

meters and other measurement devices. 

The estimated accuracy of 

measurements made with these devices 

must also be recorded, and the technical 

basis for these estimates must be 

provided. 

§ 98.298 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

Subpart DD—[Reserved] 

Subpart EE—Titanium Dioxide 

Production 

§ 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 

contains a titanium dioxide production 

process and the facility meets the 

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

(a)(2). 

§ 98.312 GHGs to report. 

(a) You must report CO2 process 

emissions from each chloride process 

line as required in this subpart. 

(b) You must report CO2, CH4, and 

N2O emissions from each stationary 

combustion unit under subpart C of this 

part (General Stationary Fuel 

Combustion Sources) by following the 

requirements of subpart C. 

§ 98.313 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions for each 

chloride process line using the 

procedures in either paragraph (a) or (b) 

of this section. 

(a) Calculate and report under this 

subpart the process CO2 emissions by 

operating and maintaining a CEMS 

according to the Tier 4 Calculation 

Methodology specified in § 98.33(a)(4) 

and all associated requirements for Tier 

4 in subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the annual process CO2

emissions for each chloride process line 

by determining the mass of calcined 

petroleum coke consumed in each line 

as specified in paragraphs (b)(1) through 

(b)(3) of this section. Use Equation EE– 

1 of this section to calulate annual 

combined process CO2 emissions from 

all process lines and use Equation EE– 

2 of this section to calculate annual 

process CO2 emissions for each process 

line. If your facility generates carboncontaining waste, use Equation EE–3 of 

this section to estimate the annual 

quantity of carbon-containing waste 

generated and its carbon contents 

according to § 98.314(e) and (f): 

(1) You must calculate the annual CO2

process emissions from all process lines 

at the facility using Equation EE–1 of 

this section: 

CO Ep

p

m

2

1

=

=

∑ (Eq. EE-1)

Where: 

CO2 = Annual CO2 emissions from titanium 

dioxide production facility (metric tons/ 

year). 

Ep = Annual CO2 emissions from chloride 

process line p (metric tons), determined 

using Equation EE–2 of this section. 

p = Process line. 

m = Number of separate chloride process 

lines located at the facility. 

(2) You must calculate the annual CO2

process emissions from each process 

lines at the facility using Equation EE– 

2 of this section: 

E C CCF p p,n n

n

= ∗∗ ∗

=

∑ 44

12

2000

2205 (Eq. EE-2)

1

12

Where: 

Ep = Annual CO2 mass emissions from 

chloride process line p (metric tons). 

Cp,n = Calcined petroleum coke consumption 

for process line p in month n (tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion of tons to metric 

tons. 

CCFn = Carbon content factor for petroleum 

coke consumed in month n from the 

supplier or as measured by the 

applicable method incorporated by 

reference in § 98.7 according to 

§ 98.314(c) (percent by weight expressed 

as a decimal fraction). 

n = Number of month. 

(3) If facility generates carboncontaining waste, you must calculate 

the total annual quantity of carboncontaining waste produced from all 

process lines using Equation EE–3 of 

this section and its carbon contents 

according to § 98.314(e) and (f): 

TWC WCp n

p n

m

=

= =

∑∑ , (Eq. EE-3)

1

12

1

Where: 

TWC = Annual production of carboncontaining waste from titanium dioxide 

production facility (tons). 

WCp,n = Production of carbon-containing 

waste in month n from chloride process 

line p (tons). 

p = Process line. 

m = Total number of process lines. 

n = Number of month. 

(c) If GHG emissions from a chloride 

process line are vented through the 

same stack as any combustion unit or 

process equipment that reports CO2

emissions using a CEMS that complies 

with the Tier 4 Calculation 

Methodology in subpart C of this part 

(General Stationary Fuel Combustion 

Sources), then the calculation 

methodology in paragraph (b) of this 

section shall not be used to calculate 

process CO2 emissions. The owner or 

operator shall report under this subpart 

the combined stack emissions according 

to the Tier 4 Calculation Methodology 

in § 98.33(a)(4) and all associated 

requirements for Tier 4 in subpart C of 

this part. 

§ 98.314 Monitoring and QA/QC 

requirements. 

(a) You must measure your 

consumption of calcined petroleum 

coke using plant instruments used for 

accounting purposes including direct 

measurement weighing the petroleum 

coke fed into your process (by belt 

scales or a similar device) or through the 

use of purchase records. 

(b) You must document the 

procedures used to ensure the accuracy 

of monthly calcined petroleum coke 

consumption measurements. 

(c) You must determine the carbon 

content of the calcined petroleum coke 

each month based on reports from the 

supplier. Alternatively, facilities can 

measure monthly carbon contents of the 

petroleum coke using ASTM D3176–89 

(Reapproved 2002) Standard Practice for 

Ultimate Analysis of Coal and Coke 

(incorporated by reference, see § 98.7) 

and ASTM D5373–08 Standard Test 

Methods for Instrumental Determination 

of Carbon, Hydrogen, and Nitrogen in 

Laboratory Samples of Coal 

(incorporated by reference, see § 98.7). 


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(d) For quality assurance and quality 

control of the supplier data, you must 

conduct an annual measurement of the 

carbon content from a representative 

sample of the petroleum coke consumed 

using ASTM D3176–89 and ASTM 

D5373–08. 

(e) You must determine the quantity 

of carbon-containing waste generated 

from the each titanium production line 

dioxide using plant instruments used 

for accounting purposes including 

direct measurement weighing the 

carbon-containing waste not used 

during the process (by belt scales or a 

similar device) or through the use of 

sales records. 

(f) You must determine the carbon 

contents of the carbon-containing waste 

from each titanium production line on 

an annual basis by collecting and 

analyzing a representative sample of the 

material using ASTM D3176–89 and 

ASTM D5373–08. 

§ 98.315 Procedures for estimating 

missing data. 

For the petroleum coke input 

procedure in § 98.313(b), a complete 

record of all measured parameters used 

in the GHG emissions calculations is 

required (e.g., carbon content values, 

etc.). Therefore, whenever the 

monitoring and quality assurance 

procedures in § 98.315 cannot be 

followed, a substitute data value for the 

missing parameter shall be used in the 

calculations as specified in the 

paragraphs (a) through (c) of this 

section. You must document and keep 

records of the procedures used for all 

such estimates. 

(a) For each missing value of the 

monthly carbon content of calcined 

petroleum coke the substitute data value 

shall be the arithmetic average of the 

quality-assured values of carbon 

contents for the month immediately 

preceding and the month immediately 

following the missing data incident. If 

no quality-assured data on carbon 

contents are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value for carbon contents 

obtained after the missing data period. 

(b) For each missing value of the 

monthly calcined petroleum coke 

consumption and/or carbon-containing 

waste, the substitute data value shall be 

the best available estimate of the 

monthly petroleum coke consumption 

based on all available process data or 

information used for accounting 

purposes (such as purchase records). 

(c) For each missing value of the 

carbon content of carbon-containing 

waste, you must conduct a new analysis 

following the procedures in § 98.314(f). 

§ 98.316 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), each annual report 

must contain the information specified 

in paragraphs (a) or (b) of this section, 

as applicable for each titanium dioxide 

production line. 

(a) If a CEMS is used to measure CO2

emissions, then you must report the 

relevant information required under 

§ 98.36(e)(2)(vi) for the Tier 4 

Calculation Methodology and the 

following information in this paragraph 

(a). 

(1) Identification number of each 

process line. 

(2) Annual consumption of calcined 

petroleum coke (tons). 

(3) Annual production of titanium 

dioxide (tons). 

(4) Annual production capacity of 

titanium dioxide (tons). 

(5) Annual production of carboncontaining waste (tons), if applicable. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in this paragraph (b): 

(1) Identification number of each 

process line. 

(2) Annual CO2 emissions from each 

chloride process line (metric tons/year). 

(3) Annual consumption of calcined 

petroleum coke for each process line 

(tons). 

(4) Annual production of titanium 

dioxide for each process line (tons). 

(5) Annual production capacity of 

titanium dioxide for each process line 

(tons). 

(6) Calcined petroleum coke 

consumption for each process line for 

each month (tons). 

(7) Annual production of carboncontaining waste for each process line 

(tons), if applicable. 

(8) Monthly production of titanium 

dioxide for each process line (tons). 

(9) Monthly carbon content factor of 

petroleum coke from the supplier 

(percent by weight expressed as a 

decimal fraction). 

(10) Whether monthly carbon content 

of the petroleum coke is based on 

reports from the supplier or through self 

measurement using applicable ASTM 

standard methods. 

(11) Carbon content for carboncontaining waste (percent by weight 

expressed as a decimal fraction). 

(12) If carbon content of petroleum 

coke is based on self measurement, the 

ASTM standard methods used. 

(13) Sampling analysis results of 

carbon content of petroleum coke as 

determined for QA/QC of supplier data 

under § 98.314(d) (percent by weight 

expressed as a decimal fraction). 

(14) Number of separate chloride 

process lines located at the facility. 

(15) The number of times in the 

reporting year that missing data 

procedures were followed to measure 

the carbon contents of petroleum coke 

(number of months); petroleum coke 

consumption (number of months); 

carbon-containing waste generated 

(number of months); and carbon 

contents of the carbon-containing waste 

(number of times during year). 

§ 98.317 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 for each titanium dioxide 

production facility. 

(a) If a CEMS is used to measure CO2

emissions, then you must retain under 

this subpart required for the Tier 4 

Calculation Methodology in § 98.37 and 

the information listed in this paragraph 

(a): 

(1) Records of all calcined petroleum 

coke purchases. 

(2) Annual operating hours for each 

titanium dioxide process line. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must retain 

records for the information listed in this 

paraghraph: 

(1) Records of all calcined petroleum 

coke purchases (tons). 

(2) Records of all analyses and 

calculations conducted for all reported 

data as listed in § 98.316(b). 

(3) Sampling analysis results for 

carbon content of consumed calcined 

petroleum coke (percent by weight 

expressed as a decimal fraction). 

(4) Sampling analysis results for the 

carbon content of carbon containing 

waste (percent by weight expressed as a 

decimal fraction), if applicable. 

(5) Monthly production of carboncontaining waste (tons). 

(6) You must document the 

procedures used to ensure the accuracy 

of the monthly petroleum coke 

consumption and quantity of carboncontaining waste measurement 

including, but not limited to, calibration 

of weighing equipment and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices must also be recorded, 

and the technical basis for these 

estimates must be provided. 

(7) Annual operating hours for each 

titanium dioxide process line (hours). 

§ 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. 


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Subpart FF—[Reserved] 

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. 

You must report: 

(a) CO2 process emissions from each 

Waelz kiln and electrothermic furnace 

used for zinc production. 

(b) CO2, CH4, and N2O combustion 

emissions from each Waelz kiln. You 

must calculate and report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

(c) CO2, CH4, and N2O emissions from 

each stationary combustion unit other 

than Waelz kilns. You must report these 

emissions under subpart C of this part 

(General Stationary Fuel Combustion 

Sources) by following the requirements 

of subpart C. 

§ 98.333 Calculating GHG emissions. 

You must calculate and report the 

annual process CO2 emissions using the 

procedures specified in either paragraph 

(a) or (b) of this section. 

(a) Calculate and report under this 

subpart the process or combined process 

and combustion CO2 emissions by 

operating and maintaining a CEMS 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part (General 

Stationary Fuel Combustion Sources). 

(b) Calculate and report under this 

subpart the process CO2 emissions by 

following paragraphs (b)(1) and (b)(2) of 

this section. 

(1) For each Waelz kiln or 

electrothermic furnace at your facility 

used for zinc production, you must 

determine the mass of carbon in each 

carbon-containing material, other than 

fuel, that is fed, charged, or otherwise 

introduced into each Waelz kiln and 

electrothermic furnace at your facility 

for each year and calculate annual CO2

process emissions from each affected 

unit at your facility using Equation GG– 

1 of this section. For electrothermic 

furnaces, carbon containing input 

materials include carbon eletrodes and 

carbonaceous reducing agents. For 

Waelz kilns, carbon containing input 

materials include carbonaceous 

reducing agents. If you document that a 

specific material contributes less than 1 

percent of the total carbon into the 

process, you do not have to include the 

material in your calculation using 

Equation R–1 of § 98.183. 

E 44

12 CO2k =∗ ∗ ( ) ∗ ( ) +∗+

2000

2205

Zinc C Flux C Ele k Zinc k k Flux k ( )( ) ( ctrode C Carbon C k Electrode k k carbon k ⎡ ) () ∗ ( ) + ∗ ( ) ⎣ ⎤

⎦ (Eq. GG-1)

Where: 

ECO2k = Annual CO2 process emissions from 

individual Waelz kiln or electrothermic 

furnace ‘‘k’’ (metric tons). 

44/12 = Ratio of molecular weights, CO2 to 

carbon. 

2000/2205 = Conversion factor to convert 

tons to metric tons. 

(Zinc)k = Annual mass of zinc bearing 

material charged to kiln or furnace ’’k’’ 

(tons). 

(CZinc)k = Carbon content of the zinc bearing 

material, from the annual carbon 

analysis for kiln or furnace ‘‘k’’ (percent 

by weight, expressed as a decimal 

fraction). 

(Flux)k = Annual mass of flux materials (e.g., 

limestone, dolomite) charged to kiln or 

furnace ‘‘k’’ (tons). 

(CFlux)k = Carbon content of the flux materials 

charged to kiln or furnace ‘‘k’’, from the 

annual carbon analysis (percent by 

weight, expressed as a decimal fraction). 

(Electrode)k = Annual mass of carbon 

electrode consumed in kiln or furnace 

‘‘k’’ (tons). 

(CElectrode)k = Carbon content of the carbon 

electrode consumed in kiln or furnace 

‘‘k’’, from the annual carbon analysis 

(percent by weight, expressed as a 

decimal fraction). 

(Carbon)k = Annual mass of carbonaceous 

materials (e.g., coal, coke) charged to the 

kiln or furnace ‘‘k’’(tons). 

(CCarbon)k Carbon content of the carbonaceous 

materials charged to kiln or furnace, ‘‘k’’, 

from the annual carbon analysis (percent 

by weight, expressed as a decimal 

fraction). 

(2) You must determine the CO2

emissions from all of the Waelz kilns or 

electrothermic furnaces at your facility 

using Equation GG–2 of this section. 

CO ECO

k

n

2 2

1

=

=

∑ k (Eq. GG-2)

Where: 

CO2 = Annual combined CO2 emissions from 

all Waelz kilns or electrothermic 

furnaces (tons). 

ECO2k = Annual CO2 emissions from each 

Waelz kiln or electrothermic furnace k 

calculated using Equation GG–1 of this 

section (tons). 

n = Total number of Waelz kilns or 

electrothermic furnaces at facility used 

for the zinc production. 

(c) If GHG emissions from a Waelz 

kiln or electrothermic furnace are 

vented through the same stack as any 

combustion unit or process equipment 

that reports CO2 emissions using a 

CEMS that complies with the Tier 4 

Calculation Methodology in subpart C of 

this part (General Stationary Fuel 

Combustion Sources), then the 

calculation methodology in paragraph 

(b) of this section shall not be used to 

calculate process emissions. The owner 

or operator shall report under this 

subpart the combined stack emissions 

according to the Tier 4 Calculation 

Methodology in § 98.33(a)(4) and all 

associated requirements for Tier 4 in 

subpart C of this part. 

§ 98.334 Monitoring and QA/QC 

requirements. 

If you determine CO2 emissions using 

the carbon input procedure in 

§ 98.333(b)(1) and (b)(2), you must meet 

the requirements specified in 

paragraphs (a) and (b) of this section. 

(a) Determine the mass of each solid 

carbon-containing input material 

consumed using facility instruments, 

procedures, or records used for 

accounting purposes including direct 

measurement weighing or through the 

use of purchase records same plant 

instruments or procedures that are used 

for accounting purposes (such as weigh 

hoppers, belt weigh feeders, weighed 

purchased quantities in shipments or 

containers, combination of bulk density 

and volume measurements, etc.). Record 

the total mass for the materials 

consumed each calendar month and 

sum the monthly mass to determine the 

annual mass for each input material. 

(b) For each input material identified 

in paragraph (a) of this section, you 

must determine the average carbon 

content of the material consumed or 

used in the calendar year using the 

methods specified in either paragraph 

(b)(1) or (b)(2) of this section. 

(1) Information provided by your 

material supplier. 

(2) Collecting and analyzing at least 

three representative samples of the 

material using the appropriate testing 

method. For each carbon-containing 


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input material identified for which the 

carbon content is not provided by your 

material supplier, the carbon content of 

the material must be analyzed at least 

annually using the appropriate standard 

methods (and their QA/QC procedures), 

which are identified in paragraphs 

(b)(2)(i) through (b)(2)(iii) of this 

section, as applicable. If you document 

that a specific process input or output 

contributes less than one percent of the 

total mass of carbon into or out of the 

process, you do not have to determine 

the monthly mass or annual carbon 

content of that input or output. 

(i) Using ASTM E1941–04 Standard 

Test Method for Determination of 

Carbon in Refractory and Reactive 

Metals and Their Alloys (incorporated 

by reference, see § 98.7), analyze zinc 

bearing materials. 

(ii) Using ASTM D5373–08 Standard 

Test Methods for Instrumental 

Determination of Carbon, Hydrogen, and 

Nitrogen in Laboratory Samples of Coal 

(incorporated by reference, see § 98.7), 

analyze carbonaceous reducing agents 

and carbon electrodes. 

(iii) Using ASTM C25–06 Standard 

Test Methods for Chemical Analysis of 

Limestone, Quicklime, and Hydrated 

Lime (incorporated by reference, see 

§ 98.7), analyze 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 as specified in 

paragraphs (a) and (b) of this section. 

You must document and keep records of 

the procedures used for all such 

estimates. 

(a) For missing records of the carbon 

content of inputs for facilities that 

estimate emissions using the carbon 

input procedure in § 98.333(b); 100 

percent data availability is required. 

You must repeat the test for average 

carbon contents of inputs according to 

the procedures in § 98.335(b) if data are 

missing. 

(b) For missing records of the annual 

mass of carbon-containing inputs using 

the carbon input procedure in 

§ 98.333(b), the substitute data value 

must be based on the best available 

estimate of the mass of the input 

material from all available process data 

or information used for accounting 

purposes, such as purchase records. 

§ 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) or (b) of this section, 

as applicable, for each Waelz kiln or 

electrothermic furnace. 

(a) If a CEMS is used to measure CO2

emissions, then you must report under 

this subpart the relevant information 

required for the Tier 4 Calculation 

Methodology in § 98.37 and the 

information listed in this paragraph (a): 

(1) Annual zinc product production 

capacity (tons). 

(2) Annual production quantity for 

each zinc product (tons). 

(3) Annual facility production 

quantity for each zinc product (tons). 

(4) Number of Waelz kilns at each 

facility used for zinc production. 

(5) Number of electrothermic furnaces 

at each facility used for zinc production. 

(b) If a CEMS is not used to measure 

CO2 emissions, then you must report the 

information listed in this paragraph (b): 

(1) Kiln identification number and 

annual process CO2 emissions from each 

individual Waelz kiln or electrothermic 

furnace (metric tons). 

(2) Annual zinc product production 

capacity (tons). 

(3) Annual production quantity for 

each zinc product (tons). 

(4) Number of Waelz kilns at each 

facility used for zinc production. 

(5) Number of electrothermic furnaces 

at each facility used for zinc production. 

(6) Annual mass of each carboncontaining input material charged to 

each kiln or furnace (including zinc 

bearing material, flux materials (e.g., 

limestone, dolomite), carbon electrode, 

and other carbonaceous materials (e.g., 

coal, coke)) (tons). 

(7) Carbon content of each carboncontaining input material charged to 

each kiln or furnace (including zinc 

bearing material, flux materials, and 

other carbonaceous materials) from the 

annual carbon analysis for each kiln or 

furnace (percent by weight, expressed as 

a decimal fraction). 

(8) Whether carbon content of each 

carbon-containing input material 

charged to each kiln or furnace is based 

on reports from the supplier or through 

self measurement using applicable 

ASTM standard method. 

(9) If carbon content of each carboncontaining input material charged to 

each kiln or furnace is based on self 

measurement, the ASTM Standard Test 

Method used. 

(10) Carbon content of the carbon 

electrode used in each furnace from the 

annual carbon analysis (percent by 

weight, expressed as a decimal fraction). 

(11) Whether carbon content of the 

carbon electrode used in each furnace is 

based on reports from the supplier or 

through self measurement using 

applicable ASTM standard method. 

(12) If carbon content of carbon 

electrode used in each furnace is based 

on self measurement, the ASTM 

standard method used. 

(13) If you use the missing data 

procedures in § 98.335(b), you must 

report how the monthly mass of carboncontaining materials with missing data 

was determined and the number of 

months the missing data procedures 

were used. 

§ 98.337 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 (b) 

of this section for each zinc production 

facility. 

(a) If a CEMS is used to measure 

emissions, then you must retain under 

this subpart the records required for the 

Tier 4 Calculation Methodology in 

§ 98.37 and the information listed in 

this paragraph (a): 

(1) Monthly facility production 

quantity for each zinc product (tons). 

(2) Annual operating hours for all 

Waelz kilns and electrothermic furnaces 

used in zinc production. 

(b) If a CEMS is not used to measure 

emissions, you must also retain the 

records specified in paragraphs (b)(1) 

through (b)(7) of this section. 

(1) Records of all analyses and 

calculations conducted for data reported 

as listed in § 98.336(b). 

(2) Annual operating hours for Waelz 

kilns and electrothermic furnaces used 

in zinc production. 

(3) Monthly production quantity for 

each zinc product (tons). 

(4) Monthly mass of zinc bearing 

materials, flux materials (e.g., limestone, 

dolomite), and carbonaceous materials 

(e.g., coal, coke) charged to the kiln or 

furnace (tons). 

(5) Sampling and analysis records for 

carbon content of zinc bearing materials, 

flux materials (e.g., limestone, 

dolomite), carbonaceous materials (e.g., 

coal, coke), charged to the kiln or 

furnace (percent by weight, expressed as 

a decimal fraction). 

(6) Monthly mass of carbon electrode 

consumed in for each electrothermic 

furnace (tons). 

(7) Sampling and analysis records for 

carbon content of electrode materials. 

(8) You must keep records that 

include a detailed explanation of how 

company records of measurements are 

used to estimate the carbon input to 

each Waelz kiln or electrothermic 

furnace, as applicable to your facility, 

including documentation of any 

materials excluded from Equation GG– 


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1 of this subpart that contribute less 

than 1 percent of the total carbon inputs 

to the process. You also must document 

the procedures used to ensure the 

accuracy of the measurements of 

materials fed, charged, or placed in an 

affected unit including, but not limited 

to, calibration of weighing equipment 

and other measurement devices. The 

estimated accuracy of measurements 

made with these devices must also be 

recorded, and the technical basis for 

these estimates must be provided. 

§ 98.338 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

Subpart HH—Municipal Solid Waste 

Landfills 

§ 98.340 Definition of the source category. 

(a) This source category applies to 

municipal solid waste (MSW) landfills 

that accepted waste on or after January 

1, 1980. 

(b) This source category does not 

include hazardous waste landfills, 

construction and demolition landfills, 

or industrial landfills. 

(c) This source category consists of 

the following sources at municipal solid 

waste (MSW) landfills: Landfills, 

landfill gas collection systems, and 

landfill gas destruction devices 

(including flares). 

§ 98.341 Reporting threshold. 

You must report GHG emissions 

under this subpart if your facility 

contains a MSW landfill and the facility 

meets the requirements of § 98.2(a)(1). 

§ 98.342 GHGs to report. 

(a) You must report CH4 generation 

and CH4 emissions from landfills. 

(b) You must report CH4 destruction 

resulting from landfill gas collection 

and combustion systems. 

(c) You must report under subpart C 

of this part (General Stationary Fuel 

Combustion Sources) the emissions of 

CO2, CH4, and N2O from each stationary 

combustion unit following the 

requirements of subpart C. 

§ 98.343 Calculating GHG emissions. 

(a) For all landfills subject to the 

reporting requirements of this subpart, 

calculate annual modeled CH4

generation according to the applicable 

requirements in paragraphs (a)(1) 

through (a)(3) of this section. 

(1) Calculate annual modeled CH4

generation using Equation HH–1 of this 

section. 

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); 

default is 1. 

DOC = Degradable organic carbon from Table 

HH–1 of this subpart or measurement 

data, if available [fraction (metric tons C/ 

metric ton waste)]. 

DOCF = Fraction of DOC dissimilated 

(fraction); default is 0.5. 

F = Fraction by volume of CH4 in landfill gas 

from measurement data, if available 

(fraction); default is 0.5. 

k = Rate constant from Table HH–1 of this 

subpart or measurement data, if available 

(yr¥1). 

(2) For years when material-specific 

waste quantity data are available, apply 

Equation HH–1 of this section for each 

waste quantity type and sum the CH4

generation rates for all waste types to 

calculate the total modeled CH4

generation rate for the landfill. Use the 

appropriate parameter values for k, 

DOC, MCF, DOCF, and F shown in Table 

HH–1 of this subpart. The annual 

quantity of each type of waste disposed 

must be calculated as the sum of the 

daily quantities of waste (of that type) 

disposed. You may use the bulk waste 

parameters for a portion of your waste 

materials when using the materialspecific modeling approach for mixed 

waste streams that cannot be designated 

to a specific material type. For years 

when waste composition data are not 

available, use the bulk waste parameter 

values for k and L0 in Table HH–1 of 

this subpart for the total quantity of 

waste disposed in those years. 

(3) For years prior to reporting for 

which waste disposal quantities are not 

readily available, Wx shall be estimated 

using one of the applicable methods in 

paragraphs (a)(3)(i) through (a)(3)(iii) of 

this section. You must determine which 

method is most applicable to the 

conditions and disposal history of your 

facility and use that method to estimate 

waste disposal quantities. 

(i) Assume all prior year waste 

disposal quantities are the same as the 

waste quantity in the first reporting 

year. 

(ii) Use the estimated population 

served by the landfill in each year, the 

values for national average per capita 

waste generation, and fraction of 

generated waste disposed of in solid 

waste disposal sites found in Table HH– 

2 of this subpart, and calculate the 

waste quantity landfilled using Equation 

HH–2 of this section. 

W POP WGR SWDS xxx x =× ×

%

100% (Eq. HH-2)

Where: 

Wx = Quantity of waste placed in the landfill 

in year × (metric tons, wet basis). 

POPx = Population of served by the landfill 

in year × from city population, census 

data, or other estimates (capita). 

WGR = Average per capita waste generation 

rate for year x from Table HH–2 of this 

subpart (metric tons per capita per year, 

wet basis; tons/cap/yr). 

%SWDS = Percent of waste generated 

subsequently managed in solid waste 

disposal sites (i.e., landfills) for year × 

from Table HH–2 of this subpart. 

(iii) Use a constant average waste 

disposal quantity calculated using 

Equation HH–3 of this section for each 

year the landfill was in operation (i.e., 


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from first accepting waste until the last year for which waste disposal data is 

unavailable, inclusive). 

WAR LFC

YrData YrOpen = ( ) − +1 (Eq. HH-3)

Where: 

WAR = Annual average waste acceptance rate 

(metric tons per year). 

LFC = Landfill capacity or, for operating 

landfills, capacity of the landfill 

currently used from design drawings or 

engineering estimates (metric tons). 

YrData = Year in which the landfill last 

received waste or, for operating landfills, 

the year prior to the first reporting year 

when waste disposal data is first 

available from company records, or best 

available data. 

YrOpen = Year in which the landfill first 

received waste from company records or 

best available data. If no data are 

available for estimating YrOpen for a 

closed landfill, use 30 years as the 

default operating life of the landfill. 

(b) For landfills with gas collection 

systems, calculate the quantity of CH4

destroyed according to the requirements 

in paragraphs (b)(1) and (b)(2) of this 

section. 

(1) If you continuously monitor the 

flow rate, CH4 concentration, 

temperature, pressure, and moisture 

content of the landfill gas that is 

collected and routed to a destruction 

device (before any treatment equipment) 

using a monitoring meter specifically for 

CH4 gas, as specified in § 98.344, you 

must use this monitoring system and 

calculate the quantity of CH4 recovered 

for destruction using Equation HH–4 of 

this section. A fully integrated system 

that directly reports CH4 content 

requires no other calculation than 

summing the results of all monitoring 

periods for a given year. 

RV f C R

T

P

n H n o

n

n = ×− ⎡ ( ) ⎣ ⎤

⎦ ( ) × × × ×× ( )

% . ( )

( ) 1

100

0 0423 520

1

1 20 n atm , .

, 440 ( . 0 454

1 000 1

× ⎛

⎝

⎜ ⎞

⎠

⎟ =

∑ Eq

n

N

 HH-4)

Where: 

R = Annual quantity of recovered CH4 (metric 

tons CH4). 

N = Total number of measurement periods in 

a year. Use daily averaging periods for 

continuous monitoring system (N = 365). 

For weekly sampling, use N = 52. 

n = Index for measurement period. 

(V)n = Daily average volumetric flow rate for 

day n (acfm). If the flow rate meter 

automatically corrects for temperature 

and pressure, replace ‘‘520 °R/(T)n × (P)n/ 

1 atm’’ with ‘‘1’’. If the CH4

concentration is determined on a dry 

basis and the flow rate meter 

automatically corrects for moisture/ 

content, replace the term [1 ¥ (fH20)n] 

with 1. 

(fH2O)n = Daily average moisture content of 

landfill gas, volumetric basis (cubic feet 

water per cubic feet landfill gas). 

(C)n = Daily average CH4 concentration of 

landfill gas for day n (volume %, dry 

basis). If the CH4 concentration is 

determined on a wet basis, replace the 

term [1 ¥ (fH20)n] with 1. 

0.0423 = Density of CH4 lb/cf at 520 °R or 60 

°F and 1 atm. 

(T)n = Temperature at which flow is 

measured for day n (°R). 

(P)n = Pressure at which flow is measured for 

day n (atm). 

1,440 = Conversion factor (min/day). 

0.454/1,000 = Conversion factor (metric ton/ 

lb). 

(2) If you do not continuously monitor 

according to paragraph (b)(1) of this 

section, you must determine the flow 

rate, CH4 concentration, temperature, 

pressure, and moisture content of the 

landfill gas that is collected and routed 

to a destruction device (before any 

treatment equipment) at least weekly 

according to the requirements in 

paragraphs (b)(2)(i) through (b)(2)(iii) of 

this section and calculate the quantity of 

CH4 recovered for destruction using 

Equation HH–4 of this section. 

(i) Continuously monitor gas flow rate 

and determine the cumulative volume 

of landfill gas each week and the 

cumulative volume of landfill gas each 

year that is collected and routed to a 

destruction device (before any treatment 

equipment). Under this option, the gas 

flow meter is not required to 

automatically correct for temperature, 

pressure, or, if necessary, moisture 

content. If the gas flow meter is not 

equipped with automatic correction for 

temperature, pressure, or, if necessary, 

moisture content, you must determine 

these parameters as specified in 

paragraph (b)(2)(iii) of this section. 

(ii) Determine the CH4 concentration 

in the landfill gas that is collected and 

routed to a destruction device (before 

any treatment equipment) in a location 

near or representative of the location of 

the gas flow meter no less than weekly. 

(iii) If the gas flow meter is not 

equipped with automatic correction for 

temperature, pressure, or, if necessary, 

moisture content: 

(A) Determine the temperature, 

pressure in the landfill gas that is 

collected and routed to a destruction 

device (before any treatment equipment) 

in a location near or representative of 

the location of the gas flow meter no 

less than weekly. 

(B) If the CH4 concentration is 

determined on a dry basis, determine 

the moisture content in the landfill gas 

that is collected and routed to a 

destruction device (before any treatment 

equipment) in a location near or 

representative of the location of the gas 

flow meter no less than weekly 

(c) Calculate CH4 generation (adjusted 

for oxidation in cover materials) and 

actual CH4 emissions (taking into 

account any CH4 recovery, and 

oxidation in cover materials) according 

to the applicable methods in paragraphs 

(c)(1) through (c)(3) of this section. 

(1) Calculate CH4 generation, adjusted 

for oxidation, from the modeled CH4

(GCH4 from Equation HH–1 of this 

section) using Equation HH–5 of this 

section. 

MG G OX Eq = ×− CH4 ( ) ( . HH-5) 1

Where: 

MG = Methane generation, adjusted for 

oxidation, from the landfill in the 

reporting year (metric tons CH4). 

GCH4 = Modeled methane generation rate in 

reporting year from Equation HH–1 of 

this section (metric tons CH4). 

OX = Oxidation fraction. Use the default 

value of 0.1 (10%). 

(2) For landfills that do not have 

landfill gas collection systems, the CH4

emissions are equal to the CH4

generation (MG) calculated in Equation 

HH–5 of this section. 

(3) For landfills with landfill gas 

collection systems, calculate CH4

emissions using the methodologies 

specified in paragraphs (c)(3)(i) and 

(c)(3)(ii) of this section. 


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(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 f Eq = − ⎡( ) CH Dest × − ( ) +×− × ( ) ( ) ⎣ ⎤ 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. Use the oxidation 

fraction default value of 0.1 (10%). 

DE = Destruction efficiency (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99). If the gas is 

transported off-site for destruction, use 

DE = 1. 

fDest = Fraction of hours the destruction 

device was operating (annual operating 

hours/8760 hours per year). If the gas is 

destroyed in a back-up flare (or simlar 

device) or if the gas is transported off-site 

for destruction, use fDest = 1. 

(ii) Calculate CH4 generation and CH4

emissions using measured CH4 recovery 

and estimated gas collection efficiency 

and Equations HH–7 and HH–8 of this 

section. 

MG R

CE f OX Eq

c

= ×× −

Re

( ) (. 1 HH-7)

Emissions R

CE f

R OX R DE f

c

= Dest × − ⎛

⎝

⎜ ⎞

⎠

⎟× − ( ) +×− × ( ) ( ) ⎡

⎣

⎢

⎢

⎤

⎦

⎥

Re ⎥ 11 ( . Eq HH- ) 8

Where: 

MG = Methane generation, adjusted for 

oxidation, from the landfill in the 

reporting year (metric tons CH4). 

Emissions = Methane emissions from the 

landfill in the reporting year (metric tons 

CH4). 

R = Quantity of recovered CH4 from Equation 

HH–4 of this section (metric tons CH4). 

CE = Collection efficiency estimated at 

landfill, taking into account system 

coverage, operation, and cover system 

materials from Table HH–3 of this 

subpart. If area by soil cover type 

information is not available, use default 

value of 0.75 (CE4 in table HH–3 of this 

subpart) for all areas under active 

influence of the collection system. 

fRec = Fraction of hours the recovery system 

was operating (annual operating hours/ 

8760 hours per year). 

OX = Oxidation fraction. Use the oxidation 

fractions default value of 0.1 (10%). 

DE = Destruction efficiency, (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99). If the gas is 

transported off-site for destruction, use 

DE = 1. 

fDest = Fraction of hours the destruction 

device was operating (device operating 

hours/8760 hours per year). If the gas is 

destroyed in a back-up flare (or similar 

device) or if the gas is transported off-site 

for destruction, use fDest = 1. 

§ 98.344 Monitoring and QA/QC 

requirements. 

(a) The quantity of waste landfilled 

must be determined using mass 

measurement equipment meeting the 

requirements for commercial weighing 

equipment as described in 

‘‘Specifications, Tolerances, and Other 

Technical Requirements For Weighing 

and Measuring Devices’’ NIST 

Handbook 44 (2009)(incorporated by 

reference, see § 98.7). 

(b) For landfills with gas collection 

systems, install, operate, maintain, and 

calibrate a gas composition monitor 

capable of measuring the concentration 

of CH4 in the recovered landfill gas 

using one of the methods specified in 

paragraphs (b)(1) through (b)(6) of this 

section or as specified by the 

manufacturer. Gas composition 

monitors shall be calibrated prior to the 

first reporting year and recalibrated 

either annually or at the minimum 

frequency specified by the 

manufacturer, whichever is more 

frequent, or whenever the error in the 

midrange calibration check exceeds ± 10 

percent. 

(1) Method 18 at 40 CFR part 60, 

appendix A–6. 

(2) ASTM D1945–03, Standard Test 

Method for Analysis of Natural Gas by 

Gas Chromatography (incorporated by 

reference, see § 98.7). 

(3) ASTM D1946–90 (Reapproved 

2006), Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference, see § 98.7). 

(4) GPA Standard 2261–00, Analysis 

for Natural Gas and Similar Gaseous 

Mixtures by Gas Chromatography. 

(5) UOP539–97 Refinery Gas Analysis 

by Gas Chromatography (incorporated 

by reference, see § 98.7). 

(6) As an alternative to the gas 

chromatography methods provided in 

paragraphs (b)(1) through (b)(5) of this 

section, you may use total gaseous 

organic concentration analyzers and 

calculate the methane concentration 

following the requirements in 

paragraphs (b)(6)(i) through (b)(6)(iii) of 

this section. 

(i) Use Method 25A or 25B at 40 CFR 

part 60, appendix A–7 to determine 

total gaseous organic concentration. You 

must calibrate the instrument with 

methane and determine the total 

gaseous organic concentration as carbon 

(or as methane; K=1 in Equation 25A– 

1 of Method 25A at 40 CFR part 60, 

appendix A–7). 

(ii) Determine a non-methane organic 

carbon correction factor no less 

frequently than once a reporting year 

following the requirements in 

paragraphs (b)(6)(ii)(A) through 

(b)(6)(ii)(C) of this section. 

(A) Take a minimum of three grab 

samples of the landfill gas that is 

collected and routed to a destruction 

device (before any treatment equipment) 

with a minimum of 20 minutes between 

samples and determine the methane 

composition of the landfill gas using 

one of the methods specificed in 

paragraphs (b)(1) through (b)(5) of this 

section. 

(B) As soon as practical after each 

grab sample is collected and prior to the 

collection of a subsequent grab sample, 

determine the total gaseous organic 

concentration of the landfilll gas that is 


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collected and routed to a destruction 

device (before any treatment equipment) 

using either Method 25A or 25B at 40 

CFR part 60, appendix A–7 as specified 

in paragaph (b)(6)(i) of this section. 

(C) Determine the arithmetic average 

methane concentration and the 

arithmetic average total gaseous organic 

concentration of the samples analyzed 

according to paragraphs (b)(6)(ii)(A) and 

(b)(6)(ii)(B) of this section, respectively, 

and calculate the non-methane organic 

carbon correction factor as the ratio of 

the average methane concentration to 

the average total gaseous organic 

concentration. If the ratio exceeds 1, use 

1 for the non-methane organic carbon 

correction factor. 

(iii) Calculate the methane 

concentration as specified in Equation 

HH–9 of this section. 

C (Eq. HH-9) CH4 = × f C NMOC TGOC

Where: 

CCH4 = Methane concentration in the landfill 

gas (volume %). 

fNMOC = Non-methane organic carbon 

correction factor from the most recent 

determination of the non-methane 

organic carbon correction factor as 

specified in paragraph (b)(6)(ii) of this 

section (unitless). 

CTGOC = Total gaseous organic carbon 

concentration measured using Method 

25A or 25B at 40 CFR part 60, appendix 

A–7 during routine monitoring of the 

landfill gas (volume %). 

(c) For landfills with gas collection 

systems, install, operate, maintain, and 

calibrate a gas flow meter capable of 

measuring the volumetric flow rate of 

the recovered landfill gas using one of 

the methods specified in paragraphs 

(c)(1) through (c)(8) of this section or as 

specified by the manufacturer. Each gas 

flow meter shall be calibrated prior to 

the first year of reporting and 

recalibrated either biennially (every 2 

years) or at the minimum frequency 

specified by the manufacturer. Except as 

provided in § 98.343(b)(2)(i), each gas 

flow meter must be capable of correcting 

for the temperature and pressure and, if 

the gas composition monitor determines 

CH4 concentration on a dry basis, 

moisture content. 

(1) ASME MFC–3M–2004, 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi 

(incorporated by reference, see § 98.7). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997), Measurement of Gas Flow by 

Turbine Meters (incorporated by 

reference, see § 98.7). 

(3) ASME MFC–6M–1998, 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters (incorporated 

by reference, see § 98.7). 

(4) ASME MFC–7M–1987 (Reaffirmed 

1992), Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see § 98.7). 

(5) ASME MFC–11M–2006 

Measurement of Fluid Flow by Means of 

Coriolis Mass Flowmeters (incorporated 

by reference, see § 98.7). The mass flow 

must be corrected to volumetric flow 

based on the measured temperature, 

pressure, and gas composition. 

(6) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters 

(incorporated by reference, see § 98.7). 

(7) ASME MFC–18M–2001 

Measurement of Fluid Flow using 

Variable Area Meters (incorporated by 

reference, see § 98.7). 

(8) Method 2A or 2D at 40 CFR part 

60, appendix A–1. 

(d) All temperature and pressure 

monitors must be calibrated using the 

procedures and frequencies specified by 

the manufacturer. 

(e) The owner or operator shall 

document the procedures used to ensure 

the accuracy of the estimates of disposal 

quantities and, if applicable, gas flow 

rate, gas composition, temperature, and 

pressure measurements. These 

procedures include, but are not limited 

to, calibration of weighing equipment, 

fuel flow meters, and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices shall also be recorded, and 

the technical basis for these estimates 

shall be provided. 

§ 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 

the ‘‘after’’ value is not obtained by the 

end of the reporting year, you may use 

the ‘‘before’’ value for the missing data 

substitution. If, for a particular 

parameter, no quality-assured data are 

available prior to the missing data 

incident, the substitute data value shall 

be the first quality-assured value 

obtained after the missing data period. 

(b) For missing gas flow rates, the 

substitute data value shall be the 

arithmetic average of the quality-assured 

values of that parameter immediately 

preceding and immediately following 

the missing data incident. If the ‘‘after’’ 

value is not obtained by the end of the 

reporting year, you may use the 

‘‘before’’ value for the missing data 

substitution. If, for a particular 

parameter, no quality-assured data are 

available prior to the missing data 

incident, the substitute data value shall 

be the first quality-assured value 

obtained after the missing data period. 

(c) For missing daily waste disposal 

quantity data for disposal in reporting 

years, the substitute value shall be the 

average daily waste disposal quantity 

for that day of the week as measured on 

the week before and week after the 

missing daily data. 

§ 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) A classification of the landfill as 

‘‘open’’ (actively received waste in the 

reporting year) or ‘‘closed’’ (no longer 

receiving waste), the year in which the 

landfill first started accepting waste for 

disposal, the last year the landfill 

accepted waste (for open landfills, enter 

the estimated year of landfill closure), 

the capacity (in metric tons) of the 

landfill, an indication of whether 

leachate recirculation is used, and the 

waste disposal quantity for each year of 

landfilling. 

(b) Method for estimating waste 

disposal quantity, and reason for its 

selection. 

(c) Waste composition for each year of 

landfilling, if available, in percentage 

categorized as: 

(1) Municipal. 

(2) Biosolids or biological sludges. 

(3) Other, or more refined categories, 

such as those for which k rates are 

available in Table HH–1 of this subpart, 

and the method or basis for estimating 

waste composition. 

(d) For each waste type used to 

calculate CH4 generation using Equation 

HH–1 of this subpart, you must report: 

(1) Degradable organic carbon (DOC) 

value used in the calculations. 

(2) Decay rate (k) value used in the 

calculations. 

(e) Fraction of CH4 in landfill gas (F) 

and an indication of whether the 

fraction of CH4 was determined based 

on measured values or the default value. 

(f) The surface area of the landfill 

containing waste (in square meters), the 

cover types applicable to the landfill, 

the surface area and oxidation fraction 


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for each cover type used to calculate the 

average oxidation fraction, and the 

average oxidation fraction used in the 

calculations. 

(g) The modeled annual methane 

generation rate for the reporting year 

(metric tons CH4) calculated using 

Equation HH–1 of this subpart. 

(h) For landfills without gas collection 

systems, the annual methane emissions 

(i.e., the methane generation, adjusted 

for oxidation, calculated using Equation 

HH–5 of this subpart), reported in 

metric tons CH4. 

(i) For landfills with gas collection 

systems, you must report: 

(1) Total volumetric flow of landfill 

gas collected for destruction (cubic feet 

at 520 °R or 60 °F and 1 atm). 

(2) CH4 concentration of landfill gas 

collected for destruction (percent by 

volume). 

(3) Monthly average temperature for 

each month at which flow is measured 

for landfill gas collected for destruction, 

or statement that temperature is 

incorporated into internal calculations 

run by the monitoring equipment. 

(4) Monthly average pressure for each 

month at which flow is measured for 

landfill gas collected for destruction, or 

statement that temperature is 

incorporated into internal calculations 

run by the monitoring equipment. 

(5) An indication of whether 

destruction occurs at the landfill facility 

or off-site. If destruction occurs at the 

landfill facility, also report an 

indication of whether a back-up 

destruction device is present at the 

landfill, the annual operating hours for 

the primary destruction device, the 

annual operating hours for the back-up 

destruction device (if present), and the 

destruction efficiency used (percent). 

(6) Annual quantity of recovered CH4

(metric tons CH4) calculated using 

Equation HH–4 of this subpart. 

(7) A description of the gas collection 

system (manufacture, capacity, number 

of wells, etc.), the surface area (square 

meters) and estimated waste depth 

(meters) for each area specified in Table 

HH–3 of this subpart, the estimated gas 

collection system efficiency for landfills 

with this gas collection system, and the 

annual operating hours of the gas 

collection system. 

(8) Methane generation corrected for 

oxidation calculated using Equation 

HH–5 of this subpart, reported in metric 

tons CH4. 

(9) Methane generation (GCH4) value 

used as an input to Equation HH–6 of 

this subpart. Specify whether the value 

is modeled (GCH4 from HH–1 of this 

subpart) or measured (R from Equation 

HH–4 of this subpart). 

(10) Methane generation corrected for 

oxidation calculated using Equation 

HH–7 of this subpart, reported in metric 

tons CH4. 

(11) Methane emissions calculated 

using Equation HH–6 of this subpart, 

reported in metric tons CH4. 

(12) Methane emissions calculated 

using Equation HH–8 of this subpart, 

reported in metric tons CH4. 

§ 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, including the 

method or manufacturer’s specification 

used for calibration. 

§ 98.348 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS

Factor Default value Units 

Waste model—bulk waste option 

k (precipitation <20 inches/year and no leachate recirculation) 0.02 ......................................... yr¥1

k (precipitation 20–40 inches/year and no leachate recirculation).0.038 ....................................... yr¥1

k (precipitation >40 inches/year or for landfill areas with leachate recirculation).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 landfills 

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

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

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

Waste model—MSW using waste composition option 

DOC (food waste) ....................................................................... 0.15 ......................................... Weight fraction, wet basis 

DOC (garden) ............................................................................. 0.2 ........................................... Weight fraction, wet basis 

DOC (paper) ............................................................................... 0.4 ........................................... Weight fraction, wet basis 

DOC (wood and straw) ............................................................... 0.43 ......................................... Weight fraction, wet basis 

DOC (textiles) ............................................................................. 0.24 ......................................... Weight fraction, wet basis 

DOC (diapers) ............................................................................. 0.24 ......................................... Weight fraction, wet basis 

DOC (sewage sludge) ................................................................ 0.05 ......................................... Weight fraction, wet basis 

DOC (bulk waste) ....................................................................... 0.20 ......................................... Weight fraction, wet basis 

k (food waste) ............................................................................. 0.06 to 0.185a ......................... yr¥1

k (garden) .................................................................................... 0.05 to 0.10 a ........................... yr¥1

k (paper) ...................................................................................... 0.04 to 0.06 a ........................... yr¥1

k (wood and straw) ..................................................................... 0.02 to 0.03 a ........................... yr¥1

k (textiles) .................................................................................... 0.04 to 0.06 a ........................... yr¥1

k (diapers) ................................................................................... 0.05 to 0.10 a ........................... yr¥1

k (sewage sludge) ....................................................................... 0.06 to 0.185 a ......................... yr¥1

Calculating methane generation and emissions 

OX ............................................................................................... 0.1 ...........................................


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TABLE HH–1 TO SUBPART HH OF PART 98—EMISSIONS FACTORS, OXIDATION FACTORS AND METHODS—Continued 

Factor Default value Units 

DE ............................................................................................... 0.99 .........................................

a Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate and leachate recirculation is not 

used. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate or when leachate recirculation is used. 

TABLE HH–2 TO SUBPART HH OF PART 98—U.S. PER CAPITA WASTE DISPOSAL RATES

Year 

Waste per 

capita 

ton/cap/yr 

% to SWDS 

1950 ......................................................................................................................................................................... 0.63 100 

1951 ......................................................................................................................................................................... 0.63 100 

1952 ......................................................................................................................................................................... 0.63 100 

1953 ......................................................................................................................................................................... 0.63 100 

1954 ......................................................................................................................................................................... 0.63 100 

1955 ......................................................................................................................................................................... 0.63 100 

1956 ......................................................................................................................................................................... 0.63 100 

1957 ......................................................................................................................................................................... 0.63 100 

1958 ......................................................................................................................................................................... 0.63 100 

1959 ......................................................................................................................................................................... 0.63 100 

1960 ......................................................................................................................................................................... 0.63 100 

1961 ......................................................................................................................................................................... 0.64 100 

1962 ......................................................................................................................................................................... 0.64 100 

1963 ......................................................................................................................................................................... 0.65 100 

1964 ......................................................................................................................................................................... 0.65 100 

1965 ......................................................................................................................................................................... 0.66 100 

1966 ......................................................................................................................................................................... 0.66 100 

1967 ......................................................................................................................................................................... 0.67 100 

1968 ......................................................................................................................................................................... 0.68 100 

1969 ......................................................................................................................................................................... 0.68 100 

1970 ......................................................................................................................................................................... 0.69 100 

1971 ......................................................................................................................................................................... 0.69 100 

1972 ......................................................................................................................................................................... 0.70 100 

1973 ......................................................................................................................................................................... 0.71 100 

1974 ......................................................................................................................................................................... 0.71 100 

1975 ......................................................................................................................................................................... 0.72 100 

1976 ......................................................................................................................................................................... 0.73 100 

1977 ......................................................................................................................................................................... 0.73 100 

1978 ......................................................................................................................................................................... 0.74 100 

1979 ......................................................................................................................................................................... 0.75 100 

1980 ......................................................................................................................................................................... 0.75 100 

1981 ......................................................................................................................................................................... 0.76 100 

1982 ......................................................................................................................................................................... 0.77 100 

1983 ......................................................................................................................................................................... 0.77 100 

1984 ......................................................................................................................................................................... 0.78 100 

1985 ......................................................................................................................................................................... 0.79 100 

1986 ......................................................................................................................................................................... 0.79 100 

1987 ......................................................................................................................................................................... 0.80 100 

1988 ......................................................................................................................................................................... 0.80 100 

1989 ......................................................................................................................................................................... 0.85 84 

1990 ......................................................................................................................................................................... 0.84 77 

1991 ......................................................................................................................................................................... 0.78 76 

1992 ......................................................................................................................................................................... 0.76 72 

1993 ......................................................................................................................................................................... 0.78 71 

1994 ......................................................................................................................................................................... 0.77 67 

1995 ......................................................................................................................................................................... 0.72 63 

1996 ......................................................................................................................................................................... 0.71 62 

1997 ......................................................................................................................................................................... 0.72 61 

1998 ......................................................................................................................................................................... 0.78 61 

1999 ......................................................................................................................................................................... 0.78 60 

2000 ......................................................................................................................................................................... 0.84 61 

2001 ......................................................................................................................................................................... 0.95 63 

2002 ......................................................................................................................................................................... 1.06 66 

2003 ......................................................................................................................................................................... 1.06 65 

2004 ......................................................................................................................................................................... 1.06 64 

2005 ......................................................................................................................................................................... 1.06 64 

2006 ......................................................................................................................................................................... 1.06 64 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56481 

TABLE HH–3 TO SUBPART HH OF PART 98—LANDFILL GAS COLLECTION EFFICIENCIES

Description Landfill Gas Collection Efficiency 

A1: Area with no waste in-place .............................................................. Not applicable; do not use this area in the calculation. 

A2: Area without active gas collection, regardless of cover type ............

H2: Average depth of waste in area A2 ...................................................

CE2: 0%. 

A3: Area with daily soil cover and active gas collection ..........................

H3: Average depth of waste in area A3 ...................................................

CE3: 60%. 

A4: Area with an intermediate soil cover and active gas collection ........

H4: Average depth of waste in area A4 ...................................................

CE4: 75%. 

A5: Area with a final soil and geomembrane cover system and active 

gas collection.

H5: Average depth of waste in area A5 ...................................................

CE5: 95%. 

Area weighted average collection efficiency for landfills ......................... CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5)/(A2+A3+A4+A5). 

Subpart II—[Reserved] 

Subpart JJ—Manure Management 

§ 98.360 Definition of the source category. 

(a) This source category consists of 

livestock facilities with manure 

management systems that emit 25,000 

metric tons CO2e or more per year. 

(1) Table JJ–1 presents the minimum 

average annual animal population by 

animal group that is estimated to emit 

25,000 metric tons CO2e or more per 

year. Facilities with an average annual 

animal population, as described in 

§ 98.363(a)(1) and (2), below those listed 

in Table JJ–1 do not need to report 

under this rule. A facility with an 

annual animal population that exceeds 

those listed in Table JJ–1 should 

conduct a more thorough analysis to 

determine applicability. 

(2) (i) If a facility has more than one 

animal group present (e.g., swine and 

poultry), the facility must determine if 

they are required to report by 

calculating the combined animal group 

factor (CAGF) using equation JJ–1: 

CAGF

AAAP

APTL Animal Groups (Eq. JJ-1) AG, Facility

AG

= ⎛

⎝

⎜ ⎞

⎠ ∑ ⎟

Where: 

CAGF = Combined Animal Group Factor 

AAAPAG,Facility = Average annual animal 

population at the facility, by animal 

group 

APTL AG = Animal population threshold 

level, as specified in Table JJ–1 of this 

section 

(ii) If the calculated CAGF for a 

facility is less than 1, the facility is not 

required to report under this rule. If the 

CAGF is equal to or greater than 1, the 

facility must use more detailed 

applicability tables and tools to 

determine if they are required to report 

under this rule. 

(b) A manure management system 

(MMS) is a system that stabilizes and/ 

or stores livestock manure, litter, or 

manure wastewater in one or more of 

the following system components: 

Uncovered anaerobic lagoons, liquid/ 

slurry systems with and without crust 

covers (including but not limited to 

ponds and tanks), storage pits, digesters, 

solid manure storage, dry lots (including 

feedlots), high-rise houses for poultry 

production (poultry without litter), 

poultry production with litter, deep 

bedding systems for cattle and swine, 

manure composting, and aerobic 

treatment. 

(c) This source category does not 

include system components at a 

livestock facility that are unrelated to 

the stabilization and/or storage of 

manure such as daily spread or pasture/ 

range/paddock systems or land 

application activities or any method of 

manure utilization that is not listed in 

§ 98.360(b). 

(d) This source category does not 

include manure management activities 

located off site from a livestock facility 

or off-site manure composting 

operations. 

§ 98.361 Reporting threshold. 

Livestock facilities must report GHG 

emissions under this subpart if the 

facility meets the reporting threshold as 

defined in 98.360(a) above, contains a 

manure management system as defined 

in 98.360(b) above, and meets the 

requirements of § 98.2(a)(1). 

§ 98.362 GHGs to report. 

(a) Livestock facilities must report 

annual aggregate CH4 and N2O 

emissions for the following MMS 

components at the facility: 

(1) Uncovered anaerobic lagoons. 

(2) Liquid/slurry systems (with and 

without crust covers, and including but 

not limited to ponds and tanks). 

(3) Storage pits. 

(4) Digesters, including covered 

anaerobic lagoons. 

(5) Solid manure storage. 

(6) Dry lots, including feedlots. 

(7) High-rise houses for poultry 

production (poultry without litter) 

(8) Poultry production with litter. 

(9) Deep bedding systems for cattle 

and swine. 

(10) Manure composting. 

(11) Aerobic treatment. 

(b) A livestock facility that is subject 

to this rule only because of emissions 

from manure management system 

components is not required to report 

emissions from subparts C through PP 

(other than subpart JJ) of this part. 

(c) A livestock facility that is subject 

to this part because of emissions from 

source categories described in subparts 

C through PP of this part is not required 

to report emissions under subpart JJ of 

this part unless emissions from manure 

management systems are 25,000 metric 

tons CO2e per year or more. 

§ 98.363 Calculating GHG emissions. 

(a) For all manure management 

system components listed in 98.360(b) 

except digesters, estimate the annual 

CH4 emissions and sum for all the 

components to obtain total emissions 

from the manure management system 

for all animal types using Equation JJ– 

1. 


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CH Emissions (metric tons/yr) TVS 4 MMS animal types MMSC A = ⎡ ∑ ∑⎣ T MMSC

ss 0 AT MMSC

x VS

x VS x days/yr x B x MCF x kg

⎡(⎣

( ) () 1 365 0 662 − ) . CH /m x metric ton/1000 kg

(Eq. JJ-2)

4

3 1 ⎤

⎦

Where: 

MMSC = Manure management systems 

component. 

TVSAT = Total volatile solids excreted by 

animal type, calculated using Equation 

JJ–3 of this section (kg/day). 

VSMMSC = Fraction of the total manure for 

each animal type that is managed in 

MMS component MMSC, assumed to be 

equivalent to the fraction of VS in each 

MMS component. 

VSss = Volatile solids removal through solid 

separation; if solid separation occurs 

prior to the MMS component, use a 

default value from Table JJ–4 of this 

section; if no solid separation occurs, 

this value is set to 0. 

(B0)AT = Maximum CH4-producing capacity 

for each animal type, as specified in 

Table JJ–2 of this section (m3 CH4/kg 

VS). 

MCFMMSC = CH4 conversion factor for the 

MMS component, as specified in Table 

JJ–5 of this section (decimal). 

TVS Population TAM VS Eq AT AT AT AT = ×× /1000 3 ( . JJ- )

Where: 

TVSAT = Daily total volatile solids excreted 

per animal type (kg/day). 

PopulationAT = Average annual animal 

population contributing manure to the 

manure management system by animal 

type (head) (see description in 

§ 98.363(a)(i) and (ii) below). 

TAMAT = Typical animal mass for each 

animal type, using either default values 

in Table JJ–2 of this section or farmspecific data (kg/head). 

VSAT = Volatile solids excretion rate for each 

animal type, using default values in 

Table JJ–2 or JJ–3 of this section (kg VS/ 

day/1000 kg animal mass). 

(1) Average annual animal 

populations for static populations (e.g., 

dairy cows, breeding swine, layers) 

must be estimated by performing an 

animal inventory or review of facility 

records once each reporting year. 

(2) Average annual animal 

populations for growing populations 

(meat animals such as beef and veal 

cattle, market swine, broilers, and 

turkeys) must be estimated each year 

using the average number of days each 

animal is kept at the facility and the 

number of animals produced annually, 

and an equation similar or equal to 

Equation JJ–4 below, adapted from 

Equation 10.1 in 2006 IPCC Guidelines 

for National Greenhouse Gas 

Inventories, Volume 4, Chapter 10. 

PopulationAT = ×⎛

⎝

⎜ ⎞

⎠ Days onsite ⎟ NAPA

365 AT (Eq. JJ-4) AT

Where: 

PopulationAT = Average annual animal 

population (by animal type). 

Days onsiteAT = Average number of days the 

animal is kept at the facility, by animal 

type. 

NAPAAT = Number of animals produced 

annually, by animal type. 

(b) For each digester, calculate the 

total amount of CH4 emissions, and then 

sum the emissions from all digesters, as 

shown in Equation JJ–5 of this section. 

H Emissions CH C CH D CH L (Eq. JJ-5) 4 AD 4 4 4

1

AD

= −+ ∑( )

Where: 

CH4 EmissionsAD = CH4 emissions from 

anaerobic digestion (metric tons/yr). 

AD = Number of anaerobic digesters at the 

manure management facility. 

CH4C = CH4 flow to digester combustion 

device, calculated using Equation JJ–6 of 

this section (metric tons CH4/yr). 

CH4D = CH4 destruction at digesters, 

calculated using Equation JJ–11 of this 

section (metric tons CH4/yr) . 

CH4L = Leakage at digesters calculated using 

Equation JJ–12 of this section (metric 

tons CH4/yr). 

(1) For each digester, calculate the 

annual CH4 flow to the combustion 

device (CH4C) using Equation JJ–6 of 

this section. A fully integrated system 

that directly reports the quantity of CH4

flow to the digester combustion device 

requires only summing the results of all 

monitoring periods for a given year to 

obtain CH4C. 

CH C V C

100%

R

T

P

1 atm

 metric ton

1,000 po 4

o

=× × × × × 0 0423 520 0 454 . .

unds (Eq. JJ-6) ⎛

⎝

⎜ ⎞

⎠

⎟

Where: 

CH4C = CH4 flow to digester combustion 

device (metric tons CH4/yr). 

V = Average annual volumetric flow rate, 

calculated in Equation JJ–7 of this 

subsection (cubic feet CH4/yr). 

C = Average annual CH4 concentration of 

digester gas, calculated in Equation JJ–8 

of this section (%, wet basis). 

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

60 °F and 1 atm). 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56483 

T = Average annual temperature at which 

flow is measured, calculated in Equation 

JJ–9 of this section (°R). 

P = Average annual pressure at which flow 

is measured, calculated in Equation JJ–10 

of this section (atm). 

(2) For each digester, calculate the 

average annual volumetric flow rate, 

CH4 concentration of digester gas, 

temperature, and pressure at which flow 

are measured using Equations JJ–7 

through JJ–10 of this section. 

V

V minutes

day

OD (Eq. JJ-7)

n

n 1

OD

=

× ⎛

⎝

⎜ ⎞

⎠

⎟ =

∑ 1 440 ,

Where: 

V = Average annual volumetric flow rate 

(cubic feet CH4/yr). 

OD = Operating days, number of days per 

year that that the digester was operating 

(days/yr). 

Vn = Daily average volumetric flow rate for 

day n, as determined from daily 

monitoring as specified in § 98.364 

(acfm). 

C

C

OD (Eq. JJ-8)

n

n 1

OD

= =

∑

Where: 

C = Average annual CH4 concentration of 

digester gas (%, wet basis). 

OD = Operating days, number of days per 

year that the digester was operating 

(days/yr). 

Cn = Average daily CH4 concentration of 

digester gas for day n, as determined 

from daily monitoring as specified in 

§ 98.364 (%, wet basis). 

T

T

OD (Eq. JJ-9)

n

n 1

OD

= =

∑

Where: 

T = Average annual temperature at which 

flow is measured (°R). 

OD = Operating days, number of days per 

year that the digester was operating 

(days/yr). 

Tn = Temperature at which flow is measured 

for day n(°R). 

P

P

OD (Eq. JJ-10)

n

n 1

OD

= =

∑

Where: 

P = Average annual pressure at which flow 

is measured (atm). 

OD = Operating days, number of days per 

year that the digester was operating 

(days/yr). 

Pn = Pressure at which flow is measured for 

day n (atm). 

(3) For each digester, calculate the 

CH4 destruction at the digester 

combustion device using Equation JJ–11 

of this section. 

CH D CH C DE OH/Hours (Eq. JJ-11) 4 4 = ××

Where: 

CH4D = CH4 destruction at digester 

combustion device (metric tons/yr). 

CH4C = Annual quantity of CH4 flow to 

digester combustion device, as 

calculated in Equation JJ–6 of this 

section (metric tons CH4). 

DE = CH4 destruction efficiency from flaring 

or burning in engine (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99). If the gas is 

transported off-site for destruction, use 

DE = 1. 

OH = Number of hours combustion device is 

functioning in reporting year. 

Hours = Hours in reporting year. 

(4) For each digester, calculate the 

CH4 leakage using Equation JJ–12 of this 

section. 

CH L CH C

CE (Eq. JJ-12) 4 4 = ×− ⎛

⎝

⎜ ⎞

⎠

⎟ 1 1

Where: 

CH4L = Leakage at digesters (metric tons/yr). 

CH4C = Annual quantity of CH4 flow to 

digester combustion device, as 

calculated in Equation JJ–6 of this 

section (metric tons CH4). 

CE = CH4 collection efficiency of anaerobic 

digester, as specified in Table JJ–6 of this 

section (decimal). 

(c) For each MMS component, 

estimate the annual N2O emissions and 

sum for all MMS components to obtain 

total emissions from the manure 

management system for all animal types 

using Equation JJ–13 of this section. 

Direct N O Emissions (metric tons/year) 2 animal types = ∑ ∑ MMSC ⎡

⎣ ×

× − ( ) × ×

Nex AT N (Eq. JJ-13)

 1 N EF 365 da

ex,MMSC

ss MMSC ys/yr 44 N O/28 N O N 1 metric ton/1000 kg 2 2 ⎤

⎦ × −× ⎤

⎦

Where: 

Nex AT = Daily total nitrogen excreted per 

animal type, calculated using Equation 

JJ–14 of this section (kg N/day). 

Nex,MMSC = Fraction of the total manure for 

each animal type that is managed in 

MMS component MMSC, assumed to be 

equivalent to the fraction of Nex in each 

MMS component. 

Nss = Nitrogen removal through solid 

separation; if solid separation occurs 

prior to the MMS component, use a 

default value from Table JJ–4 of this 


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56484 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

section; if no solid separation occurs, 

this value is set to 0. 

EFMMSC = Emission factor for MMS 

component, as specified in Table JJ–7 of 

this section (kg N2O-N/kg N). 

N Population TAM N /1000 (Eq. JJ-14) ex AT AT AT AT = ××

Where: 

Nex AT = Total nitrogen excreted per animal 

type (kg/day). 

PopulationAT = Average annual animal 

population contributing manure to the 

manure management system by animal 

type (head) (see description in 

§ 98.363(a)(i) and (ii)). 

TAMAT = Typical animal mass by animal 

type, using either default values in Table 

JJ–2 of this section or farm-specific data 

(kg/head). 

NAT = Nitrogen excretion rate by animal type, 

using default values in Tables JJ–2 or JJ– 

3 of this section (kg N/day/1000 kg 

animal mass). 

(d) Estimate the annual total facility 

emissions using Equation JJ–15 of this 

section. 

Total Emissions (metric tons CO CH emissions + 2 4 MMS e yr / ) = ⎡(⎣ CH emissions x [Direct N O emissions 310] (Eq. JJ- 4 AD 2 ) 21 x 1 ] +5)

Where: 

CH4 emissionsMMS = From Equation JJ–2 of 

this section. 

CH4 emissionsAD = From Equation JJ–5 of this 

section. 

21 = Global Warming Potential of CH4. 

Direct N2O emissions = From Equation JJ–13 

of this section. 

310 = Global Warming Potential of N2O. 

§ 98.364 Monitoring and QA/QC 

requirements. 

(a) Perform an annual animal 

inventory or review of facility records 

(for static populations) or population 

calculation (for growing populations) to 

determine the average annual animal 

population for each animal type (see 

description in § 98.363(a)(1) and (2)). 

(b) Perform an analysis on your 

operation to determine the fraction of 

total manure by weight for each animal 

type that is managed in each on-site 

manure management system 

component. If your system changes from 

previous reporting periods, you must 

reevaluate the fraction of total manure 

managed in each system component. 

(c) The CH4 concentration of gas from 

digesters must be determined using 

ASTM D1946–90 (Reapproved 2006) 

Standard Practice for Analysis of 

Reformed Gas by Gas Chromatography 

(incorporated by reference see § 98.7). 

All gas composition monitors shall be 

calibrated prior to the first reporting 

year for biogas methane and carbon 

dioxide content using ASTM D1946–90 

(Reapproved 2006) Standard Practice for 

Analysis of Reformed Gas by Gas 

Chromatography (incorporated by 

reference see § 98.7)and recalibrated 

either annually or at the minimum 

frequency specified by the 

manufacturer, whichever is more 

frequent, or whenever the error in the 

midrange calibration check exceeds ± 10 

percent. All monitors shall be 

maintained as specified by the 

manufacturer. 

(d) All temperature and pressure 

monitors must be calibrated using the 

procedures and frequencies specified by 

the manufacturer. All equipment 

(temperature and pressure monitors) 

shall be maintained as specified by the 

manufacturer. 

(e) For digesters with gas collection 

systems, install, operate, maintain, and 

calibrate a gas flow meter capable of 

measuring the volumetric flow rate to 

provide data for the GHG emissions 

calculations, using the applicable 

methods specified in paragraphs (e)(1) 

through (e)(6) of this section or as 

specified by the manufacturer. 

(1) ASME MFC–3M–2004 

Measurement of Fluid Flow in Pipes 

Using Orifice, Nozzle, and Venturi 

(incorporated by reference, see § 98.7). 

(2) ASME MFC–4M–1986 (Reaffirmed 

1997) Measurement of Gas Flow by 

Turbine Meters (incorporated by 

reference, see § 98.7). 

(3) ASME MFC–6M–1998 

Measurement of Fluid Flow in Pipes 

Using Vortex Flowmeters (incorporated 

by reference, see § 98.7). 

(4) ASME MFC–7M–1987 (Reaffirmed 

1992) Measurement of Gas Flow by 

Means of Critical Flow Venturi Nozzles 

(incorporated by reference, see § 98.7). 

(5) ASME MFC–14M–2003 

Measurement of Fluid Flow Using Small 

Bore Precision Orifice Meters 

(incorporated by reference, see § 98.7). 

(6) ASME MFC–18M–2001 

Measurement of Fluid Flow using 

Variable Area Meters (incorporated by 

reference, see § 98.7). 

(f) If applicable, the owner or operator 

shall document the procedures used to 

ensure the accuracy of gas flow rate, gas 

composition, temperature, and pressure 

measurements. These procedures 

include, but are not limited to, 

calibration of fuel flow meters and other 

measurement devices. The estimated 

accuracy of measurements made with 

these devices shall also be recorded, and 

the technical basis for these estimates 

shall be provided. 

(g) Each gas flow meter shall be 

calibrated prior to the first reporting 

year and recalibrated either annually or 

at the minimum frequency specified by 

the manufacturer, whichever is more 

frequent. Each gas flow meter must have 

a rated accuracy of ± 5 percent or lower 

and be capable of correcting for the 

temperature and pressure and, if the gas 

composition monitor determines CH4

concentration on a dry basis, moisture 

content. 

§ 98.365 Procedures for estimating 

missing data. 

(a) A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions during unit 

operation or if a required fuel sample is 

not taken), a substitute data value for 

the missing parameter shall be used in 

the calculations, according to the 

requirements in paragraph (b) of this 

section. 

(b) For missing gas flow rates or CH4

content data, the substitute data value 

shall be the arithmetic average of the 

quality-assured values of that parameter 

immediately preceding and immediately 

following the missing data incident. If, 

for a particular parameter, no 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. 

(a) In addition to the information 

required by § 98.3(c), each annual report 

must contain the following information: 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56485 

(1) List of manure management 

system components at the facility. 

(2) Fraction of manure from each 

animal type that is handled in each 

manure management system 

component. 

(3) Average annual animal population 

(for each animal type) for static 

populations or the results of Equation 

JJ–4 for growing populations. 

(4) Average number of days that 

growing animals are kept at the facility 

(for each animal type). 

(5) The number of animals produced 

annually for growing populations (for 

each animal type). 

(6) Typical animal mass (for each 

animal type). 

(7) Total facility emissions (results of 

Equation JJ–15). 

(8) CH4 emissions from manure 

management system components listed 

in § 98.360(b), except digesters (results 

of Equation JJ–2). 

(9) VS value used (for each animal 

type). 

(10) B0 value used (for each animal 

type). 

(11) Methane conversion factor used 

for each MMS component. 

(12) Average ambient temperature 

used to select each methane conversion 

factor. 

(13) N2O emissions (results of 

Equation JJ–13). 

(14) N value used for each animal 

type. 

(15) N2O emission factor selected for 

each MMS component. 

(b) Facilities with anaerobic digesters 

must also report: 

(1) CH4 emissions from anaerobic 

digesters (results of Equation JJ–5). 

(2) CH4 flow to the digester 

combustion device for each digester 

(results of Equation JJ–6, or value from 

fully integrated monitoring system as 

described in 98.363(b)). 

(3) CH4 destruction for each digester 

(results of Equation JJ–11). 

(4) CH4 leakage for each digester 

(results of Equation JJ–12). 

(5) Total annual volumetric biogas 

flow for each digester (results of 

Equation JJ–7). 

(6) Average annual CH4 concentration 

for each digester (results of Equation JJ– 

8). 

(7) Average annual temperature at 

which gas flow is measured for each 

digester (results of Equation JJ–9). 

(8) Average annual gas flow pressure 

at which gas flow is measured for each 

digester (results of Equation JJ–10). 

(9) Destruction efficiency used for 

each digester. 

(10) Number of days per year that 

each digester was operating. 

(11) Collection efficiency used for 

each digester. 

§ 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, including the 

method or manufacturer’s specification 

used for calibration. 

§ 98.368 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE JJ–1 TO SUBPART JJ OF PART 98—ANIMAL POPULATION THRESHOLD LEVEL BELOW WHICH FACILITIES ARE NOT

REQUIRED TO REPORT EMISSIONS UNDER SUBPART JJ 1,2

Animal group 

Average annual animal 

population 

(Head) 3

Beef ...................................................................................................................................................................................................... 29,300 

Dairy ..................................................................................................................................................................................................... 3,200 

Swine ................................................................................................................................................................................................... 34,100 

Poultry: 

Layers ........................................................................................................................................................................................... 723,600 

Broilers .......................................................................................................................................................................................... 38,160,000 

Turkeys ......................................................................................................................................................................................... 7,710,000 

1The threshold head populations in this table were calculated using the most conservative assumptions (high VS and N values, maximum ambient temperatures, and the application of an uncertainty factor) to ensure that facilities at or near the 25,000 metric ton CO2e threshold level 

were not excluded from reporting. 2For facilities with more than one animal group present refer to § 98.360 (2) to estimate the combined animal group factor (CAGF), which is 

used to determine if a facility may be required to report. 3For all animal groups except dairy, the average annual animal population represents the total number of animals present at the facility. For 

dairy facilities, the average annual animal population represents the number of mature dairy cows present at the facility (note that heifers and 

calves were included in the emission estimates for dairy facilities using the assumption that the average annual animal population of heifers and 

calves at dairy facilities are equal to 30 percent of the mature dairy cow average annual animal population, therefore the average annual population for dairy facilities should not include heifers and calves, only dairy cows). 

TABLE JJ–2 TO SUBPART JJ OF PART 98—WASTE CHARACTERISTICS DATA

Animal type 

Typical animal 

mass 

(kg) 

Volatile solids excretion rate 

(kg VS/day/1000 kg animal mass) 

Nitrogen excretion rate 

(kg N/day/1000 kg animal mass) 

Maximum 

methane generation potential, Bo

(m3 CH4/kg 

VS added) 

Dairy Cows ..................................... 604 See Table JJ–3 .............................. See Table JJ–3 .............................. 0.24 

Dairy Heifers ................................... 476 See Table JJ–3 .............................. See Table JJ–3 .............................. 0.17 

Dairy Calves ................................... 118 6.41 ................................................ 0.30 ................................................ 0.17 

Feedlot Steers ................................ 420 See Table JJ–3 .............................. See Table JJ–3 .............................. 0.33 

Feedlot heifers ................................ 420 See Table JJ–3 .............................. See Table JJ–3 .............................. 0.33 

Market Swine <60 lbs ..................... 16 8.80 ................................................ 0.60 ................................................ 0.48 

Market Swine 60–119 lbs ............... 41 5.40 ................................................ 0.42 ................................................ 0.48 

Market Swine 120–179 lbs ............. 68 5.40 ................................................ 0.42 ................................................ 0.48 

Market Swine >180 lbs ................... 91 5.40 ................................................ 0.42 ................................................ 0.48 

Breeding Swine .............................. 198 2.60 ................................................ 0.24 ................................................ 0.48 


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TABLE JJ–2 TO SUBPART JJ OF PART 98—WASTE CHARACTERISTICS DATA—Continued 

Animal type 

Typical animal 

mass 

(kg) 

Volatile solids excretion rate 

(kg VS/day/1000 kg animal mass) 

Nitrogen excretion rate 

(kg N/day/1000 kg animal mass) 

Maximum 

methane generation potential, Bo

(m3 CH4/kg 

VS added) 

Feedlot Sheep ................................ 25 9.20 ................................................ 0.42 ................................................ 0.36 

Goats .............................................. 64 9.50 ................................................ 0.45 ................................................ 0.17 

Horses ............................................ 450 10.00 .............................................. 0.30 ................................................ 0.33 

Hens >/= 1 yr .................................. 1.8 10.09 .............................................. 0.83 ................................................ 0.39 

Pullets ............................................. 1.8 10.09 .............................................. 0.62 ................................................ 0.39 

Other Chickens ............................... 1.8 10.80 .............................................. 0.83 ................................................ 0.39 

Broilers ............................................ 0.9 15.00 .............................................. 1.10 ................................................ 0.36 

Turkeys ........................................... 6.8 9.70 ................................................ 0.74 ................................................ 0.36 

TABLE JJ–3 TO SUBPART JJ OF PART 98—STATE-SPECIFIC VOLATILE SOLIDS (VS) AND NITROGEN (N) EXCRETION

RATES FOR CATTLE

State 

Volatile solids excretion rate (kg VS/day/1000 

kg animal mass) 

Nitrogen excretion rate (kg VS/day/1000 kg 

animal mass) 

Dairy 

cows 

Dairy 

heifers 

Feedlot 

steer 

Feedlot 

heifers 

Dairy 

cows 

Dairy 

heifers 

Feedlot 

steer 

Feedlot 

heifers 

Alabama ........................................................... 8.40 8.35 4.27 4.74 0.50 0.46 0.36 0.38 

Alaska .............................................................. 7.30 8.35 4.15 4.58 0.45 0.46 0.35 0.37 

Arizona ............................................................. 10.37 8.35 3.91 4.27 0.58 0.46 0.33 0.34 

Arkansas .......................................................... 7.59 8.35 3.98 4.35 0.46 0.46 0.33 0.35 

California .......................................................... 10.02 8.35 3.96 4.33 0.56 0.46 0.33 0.34 

Colorado ........................................................... 10.25 8.35 3.97 4.34 0.58 0.46 0.33 0.35 

Connecticut ...................................................... 9.22 8.35 4.41 4.93 0.53 0.46 0.37 0.40 

Delaware .......................................................... 8.63 8.35 4.19 4.64 0.51 0.46 0.35 0.37 

Florida .............................................................. 8.90 8.35 4.15 4.58 0.52 0.46 0.35 0.37 

Georgia ............................................................ 9.07 8.35 4.18 4.63 0.53 0.46 0.35 0.37 

Hawaii .............................................................. 7.00 8.35 4.15 4.58 0.44 0.46 0.35 0.37 

Idaho ................................................................ 10.11 8.35 4.03 4.42 0.57 0.46 0.34 0.35 

Illinois ............................................................... 9.07 8.35 4.15 4.59 0.52 0.46 0.35 0.37 

Indiana ............................................................. 9.38 8.35 3.98 4.35 0.54 0.46 0.33 0.35 

Iowa .................................................................. 9.46 8.35 3.93 4.28 0.54 0.46 0.33 0.34 

Kansas ............................................................. 9.63 8.35 3.97 4.35 0.55 0.46 0.33 0.35 

Kentucky .......................................................... 7.89 8.35 4.20 4.65 0.48 0.46 0.35 0.37 

Louisiana .......................................................... 7.39 8.35 4.07 4.48 0.45 0.46 0.34 0.36 

Maine ............................................................... 8.99 8.35 4.07 4.47 0.52 0.46 0.34 0.36 

Maryland .......................................................... 9.02 8.35 4.05 4.45 0.52 0.46 0.34 0.35 

Massachusetts ................................................. 8.63 8.35 4.15 4.58 0.51 0.46 0.35 0.37 

Michigan ........................................................... 10.05 8.35 4.00 4.38 0.57 0.46 0.34 0.35 

Minnesota ......................................................... 9.17 8.35 3.89 4.24 0.53 0.46 0.33 0.34 

Mississippi ........................................................ 8.19 8.35 4.14 4.57 0.49 0.46 0.35 0.37 

Missouri ............................................................ 8.02 8.35 4.08 4.49 0.48 0.46 0.34 0.36 

Montana ........................................................... 9.03 8.35 4.23 4.69 0.52 0.46 0.36 0.38 

Nebraska .......................................................... 9.09 8.35 3.98 4.35 0.53 0.46 0.33 0.35 

Nevada ............................................................. 9.65 8.35 4.07 4.48 0.55 0.46 0.34 0.36 

New Hampshire ............................................... 9.44 8.35 3.94 4.30 0.54 0.46 0.33 0.34 

New Jersey ...................................................... 8.51 8.35 3.98 4.36 0.50 0.46 0.33 0.35 

New Mexico ..................................................... 10.34 8.35 3.88 4.22 0.58 0.46 0.32 0.33 

New York ......................................................... 9.42 8.35 3.75 4.05 0.54 0.46 0.31 0.32 

North Carolina .................................................. 9.38 8.35 4.20 4.65 0.55 0.46 0.35 0.37 

North Dakota .................................................... 8.40 8.35 3.88 4.22 0.50 0.46 0.32 0.34 

Ohio .................................................................. 9.01 8.35 3.96 4.33 0.52 0.46 0.33 0.34 

Oklahoma ......................................................... 8.58 8.35 3.98 4.35 0.50 0.46 0.33 0.35 

Oregon ............................................................. 9.40 8.35 4.06 4.46 0.54 0.46 0.34 0.36 

Pennsylvania .................................................... 9.26 8.35 3.98 4.35 0.53 0.46 0.33 0.35 

Rhode Island .................................................... 8.94 8.35 4.36 4.87 0.52 0.46 0.37 0.39 

South Carolina ................................................. 9.05 8.35 4.15 4.58 0.53 0.46 0.35 0.37 

South Dakota ................................................... 9.45 8.35 4.01 4.39 0.54 0.46 0.34 0.35 

Tennessee ....................................................... 8.60 8.35 4.48 5.02 0.51 0.46 0.38 0.40 

Texas ............................................................... 9.51 8.35 3.95 4.32 0.54 0.46 0.33 0.34 

Utah .................................................................. 9.70 8.35 3.88 4.22 0.55 0.46 0.32 0.34 

Vermont ............................................................ 9.03 8.35 4.10 4.52 0.52 0.46 0.34 0.36 

Virginia ............................................................. 9.02 8.35 3.98 4.35 0.53 0.46 0.33 0.35 

Washington ...................................................... 10.36 8.35 4.07 4.47 0.58 0.46 0.34 0.36 

West Virginia .................................................... 8.13 8.35 4.65 5.25 0.48 0.46 0.40 0.42 

Wisconsin ......................................................... 9.34 8.35 3.95 4.31 0.54 0.46 0.33 0.34 


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TABLE JJ–3 TO SUBPART JJ OF PART 98—STATE-SPECIFIC VOLATILE SOLIDS (VS) AND NITROGEN (N) EXCRETION

RATES FOR CATTLE—Continued 

State 

Volatile solids excretion rate (kg VS/day/1000 

kg animal mass) 

Nitrogen excretion rate (kg VS/day/1000 kg 

animal mass) 

Dairy 

cows 

Dairy 

heifers 

Feedlot 

steer 

Feedlot 

heifers 

Dairy 

cows 

Dairy 

heifers 

Feedlot 

steer 

Feedlot 

heifers 

Wyoming .......................................................... 9.29 8.35 4.17 4.61 0.53 0.46 0.35 0.37 

TABLE JJ–4 TO SUBPART JJ OF PART 98—VOLATILE SOLIDS AND NITROGEN REMOVAL THROUGH SOLIDS SEPARATION

Type of solids separation Volatile solids removal (decimal) 

Nitrogen removal 

(decimal) 

Gravity ...................................................................................................................................................... 0.60 0.60 

Mechanical: 

Stationary Screen ............................................................................................................................. 0.20 0.10 

Vibrating Screen ............................................................................................................................... 0.15 0.15 

Screw Press ..................................................................................................................................... 0.25 0.15 

Centrifuge ......................................................................................................................................... 0.50 0.25 

Roller drum ....................................................................................................................................... 0.25 0.15 

Belt press/screen .............................................................................................................................. 0.50 0.30 

BILLING CODE 6560–50–P 


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BILLING CODE 6560–50–C 


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TABLE JJ–6 TO SUBPART JJ OF PART 98—COLLECTION EFFICIENCIES OF ANAEROBIC DIGESTERS

Anaerobic digester type Cover type 

Methane collection efficiency 

Covered anaerobic lagoon (biogas capture) .............................. Bank to bank, impermeable ....................................................... 0.975 

Modular, impermeable ................................................................ 0.70 

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

TABLE JJ–7 TO SUBPART JJ OF PART

98—NITROUS OXIDE EMISSION FACTORS (KG N2O–N/KG KJDL N) 

Manure management system 

component 

N2O emission factor 

Uncovered anaerobic lagoon ... 0 

Liquid/Slurry (with crust cover) 0.005 

Liquid/Slurry (without crust 

cover) .................................... 0 

Storage pits .............................. 0.002 

Digesters ................................... 0 

Solid manure storage ............... 0.005 

Dry lots (including feedlots) ...... 0.02 

High-rise house for poultry 

(poultry without litter) ............ 0.001 

Poultry production with litter ..... 0.001 

Deep bedding for cattle and 

swine (active mix) ................. 0.07 

Deep bedding for cattle and 

swine (no mix) ....................... 0.01 

Manure Composting (in vessel) 0.006 

Manure Composting (intensive) 0.1 

Manure Composting (passive) 0.01 

Manure Composting (static) ..... 0.006 

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

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

Subpart KK—[Reserved] 

Subpart LL—Suppliers of Coal-based 

Liquid Fuels 

§ 98.380 Definition of the source category. 

This source category consists of 

producers, importers, and exporters of 

products listed in Table MM–1 of 

subpart MM that are coal-based (coal-toliquid products). 

(a) A producer is the owner or 

operator of a coal-to-liquids facility. A 

coal-to-liquids facility is any facility 

engaged in converting coal into liquid 

products using a process involving 

conversion of coal into gas and then into 

liquids (e.g., Fischer-Tropsch) or 

conversion of coal directly into liquids 

(i.e., direct liquefaction). 

(b) An importer or exporter shall have 

the same meaning given in § 98.6. 

§ 98.381 Reporting threshold. 

Any supplier of coal-to-liquid 

products 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 fossil-fuel 

products (besides coal or crude oil) that 

you produce, use as feedstock, import, 

or export during the calendar year. 

Additionally, producers must report 

CO2 emissions that would result from 

the complete combustion or oxidation of 

any biomass co-processed with fossil 

fuel-based feedstocks. 

§ 98.383 Calculating GHG emissions. 

You must follow the calculation 

methodologies of § 98.393 as if they 

applied to the appropriate coal-to-liquid 

product supplier (i.e., calculation 

methodologies for refiners apply to 

producers of coal-to-liquid products and 

calculation methodologies for importers 

and exporters of petroleum products 

apply to importers and exporters of 

coal-to-liquid products). 

(a) In calculation methodologies in 

§ 98.393 for petroleum products or 

petroleum-based products, suppliers of 

coal-to-liquid products shall also 

include coal-to-liquid products. 

(b) In calculation methodologies in 

§ 98.393 for non-crude feedstocks or 

non-crude petroleum feedstocks, 

producers of coal-to-liquid products 

shall also include coal-to-liquid 

products that enter the facility to be 

further processed or otherwise used on 

site. 

(c) In calculation methodologies in 

§ 98.393 for petroleum feedstocks, 

suppliers of coal-to-liquid products 

shall also include coal and coal-toliquid products that enter the facility to 

be further processed or otherwise used 

on site. 

§ 98.384 Monitoring and QA/QC 

requirements. 

You must follow the monitoring and 

QA/QC requirements in § 98.394 as if 

they applied to the appropriate coal-toliquid product supplier. Any monitoring 

and QA/QC requirement for petroleum 

products in § 98.394 also applies to 

coal-to-liquid products. 

§ 98.385 Procedures for estimating 

missing data. 

You must follow the procedures for 

estimating missing data in § 98.395 as if 

they applied to the appropriate coal-toliquid product supplier. Any procedure 

for estimating missing data for 

petroleum products in § 98.395 also 

applies to coal-to-liquid products. 

§ 98.386 Data reporting requirements. 

In addition to the information 

required by § 98.3(c), the following 

requirements apply: 

(a) Producers shall report the 

following information for each coal-toliquid facility: 

(1) For each product listed in Table 

MM–1 of subpart MM of this part that 

enters the coal-to-liquid facility to be 

further processed or otherwise used on 

site, report the annual quantity in metric 

tons or barrels by each quantity 

measurement standard method or other 

industry standard practice used. For 

natural gas liquids, quantity shall reflect 

the individual components of the 

product. 

(2) For each product listed in Table 

MM–1 of subpart MM of this part that 

enters the coal-to-liquid facility to be 

further processed or otherwise used on 

site, report the total annual quantity in 

metric tons or barrels. For natural gas 

liquids, quantity shall reflect the 

individual components of the product. 

(3) For each feedstock reported in 

paragraph (a)(2) that was produced by 

blending a fossil fuel-based product 

with a biomass-based product, report 

the percent of the volume reported in 

paragraph (a)(2) of this section that is 

fossil fuel-based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(1) of this section. 

(5) For each product (leaving the coalto-liquid facility) listed in Table MM–1 

of subpart MM of this part, report the 

annual quantity in metric tons or barrels 

by each quantity measurement standard 

method or other industry standard 

practice used. For natural gas liquids, 

quantity shall reflect the individual 

components of the product. 

(6) For each product (leaving the coalto-liquid facility) listed in Table MM–1 

of subpart MM of this part, report the 

total annual quantity in metric tons or 

barrels. For natural gas liquids, quantity 

shall reflect the individual components 

of the product. 

(7) For each product reported in 

paragraph (a)(6) of this section that was 

produced by blending a fossil fuel-based 


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product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (a)(6) of this 

section that is fossil fuel-based. 

(8) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(5) of this section. 

(9) For every feedstock reported in 

paragraph (a)(2) of this section for 

which Calculation Methodology 2 of 

subpart MM of this part was used to 

determine an emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percent mass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor. 

(10) For every non-solid feedstock 

reported in paragraph (a)(2) of this 

section for which Calculation 

Methodology 2 of subpart MM of this 

part was used to determine an emissions 

factor, report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(11) For every product reported in 

paragraph (a)(6) of this section for 

which Calculation Methodology 2 of 

this subpart was used to determine an 

emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percent mass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor. 

(12) For every non-solid product 

reported in paragraph (a)(6) of this 

section for which Calculation 

Methodology 2 of subpart MM of this 

part was used to determine an emissions 

factor, report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(13) For each specific type of biomass 

that enters the coal-to-liquid facility to 

be co-processed with fossil fuel-based 

feedstock to produce a product reported 

in paragraph (a)(6) of this section, report 

the annual quantity in metric tons or 

barrels by each quantity measurement 

standard method or other industry 

standard practice used. 

(14) For each specific type of biomass 

that enters the coal-to-liquid facility to 

be co-processed with fossil fuel-based 

feedstock to produce a product reported 

in paragraph (a)(6) of this section, report 

the total annual quantity in metric tons 

or barrels. 

(15) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(3) of this section. 

(16) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of 

this section, calculated according to 

§ 98.393(b) or (h). 

(17) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

product (leaving the coal-to-liquid 

facility) reported in paragraph (a)(6) of 

this section, calculated according to 

§ 98.393(a) or (h). 

(18) Annual CO2 emissions in metric 

tons that would result from the 

complete combustion or oxidation of 

each type of biomass feedstock coprocessed with fossil fuel-based 

feedstocks reported in paragraph (a)(3) 

of this section, calculated according to 

§ 98.393(c). 

(19) Annual CO2 emissions that 

would result from the complete 

combustion or oxidation of all products, 

calculated according to § 98.393(d). 

(20) Annual quantity of bulk NGLs in 

metric tons or barrels received for 

processing during the reporting year. 

(b) In addition to the information 

required by § 98.3(c), each importer 

shall report all of the following 

information at the corporate level: 

(1) For each product listed in Table 

MM–1 of subpart MM of this part, report 

the annual quantity in metric tons or 

barrels by each quantity measurement 

standard method or other industry 

standard practice used. For natural gas 

liquids, quantity shall reflect the 

individual components of the product. 

(2) For each product listed in Table 

MM–1 of subpart MM of this part, report 

the total annual quantity in metric tons 

or barrels. For natural gas liquids, 

quantity shall reflect the individual 

components of the product as listed in 

Table MM–1 of subpart MM of this part. 

(3) For each product reported in 

paragraph (b)(2) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (b)(2) of this 

section that is fossil fuel-based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (b)(1) of this section. 

(5) For each product reported in 

paragraph (b)(2) of this section for 

which Calculation Methodology 2 of 

this subpart used was used to determine 

an emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c) 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percent mass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons. 

(6) For each non-solid product 

reported in paragraph (b)(2) of this 

section for which Calculation 

Methodology 2 of this subpart was used 

to determine an emissions factor, report: 

(i) The density test results in metric 

tons ber barrel. 

(ii) The standard method used to test 

density. 

(7) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

imported product reported in paragraph 

(b)(2) of this section, calculated 

according to § 98.393(a). 

(8) The total sum of CO2 emissions 

that would result from the complete 

combustion or oxidation of all imported 

products, calculated according to 

§ 98.393(e). 

(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) For each product listed in Table 

MM–1 of subpart MM of this part, report 

the annual quantity in metric tons or 

barrels by each quantity measurement 

standard method or other industry 

standard practice used. For natural gas 

liquids, quantity shall reflect the 

individual components of the product. 

(2) For each product listed in table 

MM–1 of subpart MM of this part, report 

the total annual quantity in metric tons 

or barrels. For natural gas liquids, 

quantity shall reflect the individual 

components of the product. 

(3) For each product reported in 

paragraph (c)(2) of this section that was 

produced by blending a fossil fuel-based 

product with a biomass-based product, 

report the percent of the volume 

reported in paragraph (c)(2) of this 

section that is fossil fuel-based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (c)(1) of this section. 

(5) For each product reported in 

paragraph (c)(2) of this section for 

which Calculation Methodology 2 of 

this subpart was used to determine an 

emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 


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(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percent mass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons. 

(6) For each non-solid product 

reported in paragraph (c)(2) of this 

section for which Calculation 

Methodology 2 of this subpart used was 

used to determine an emissions factor, 

report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(7) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

exported product reported in paragraph 

(c)(2) of this section, calculated 

according to § 98.393(a). 

(8) Total sum of CO2 emissions that 

would result from the complete 

combustion or oxidation of all exported 

products, calculated according to 

§ 98.393(e). 

§ 98.387 Records that must be retained. 

You must retain records according to 

the requirements in § 98.397 as if they 

applied to the appropriate coal-to-liquid 

product supplier (e.g., retaining copies 

of all reports submitted to EPA under 

§ 98.386 and records to support 

information contained in those reports). 

Any records for petroleum products that 

are required to be retained in § 98.397 

are also required for coal-to-liquid 

products. 

§ 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 and 

natural gas liquids as listed in Table 

MM–1 of this subpart. 

(a) A petroleum refinery for the 

purpose of this subpart is any facility 

engaged in producing petroleum 

products through the distillation of 

crude oil. 

(b) A refiner is the owner or operator 

of a petroleum refinery. 

(c) Importer has the same meaning 

given in § 98.6 and includes any entity 

that imports petroleum products or 

natural gas liquids as listed in Table 

MM–1 of this subpart. Any blender or 

refiner of refined or semi-refined 

petroleum products shall be considered 

an importer if it otherwise satisfies the 

aforementioned definition. 

(d) Exporter has the same meaning 

given in § 98.6 and includes any entity 

that exports petroleum products or 

natural gas liquids as listed in Table 

MM–1 of this subpart. Any blender or 

refiner of refined or semi-refined 

petroleum products shall be considered 

an exporter if it otherwise satisfies the 

aforementioned definition. 

§ 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. 

Suppliers of petroleum products must 

report the CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product 

and natural gas liquid produced, used as 

feedstock, imported, or exported during 

the calendar year. Additionally, refiners 

must report CO2 emissions that would 

result from the complete combustion or 

oxidation of any biomass co-processed 

with petroleum feedstocks. 

§ 98.393 Calculating GHG emissions. 

(a) Calculation for individual 

products produced, imported, or 

exported. 

(1) Except as provided in paragraph 

(h) of this section, any refiner, importer, 

or exporter shall calculate CO2

emissions from each individual 

petroleum product and natural gas 

liquid using Equation MM–1 of this 

section. 

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

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product or 

natural gas liquid ‘‘i’’ (metric tons). 

Producti = Annual volume of product ‘‘i’’ 

produced, imported, or exported by the 

reporting party (barrels). For refiners, 

this volume only includes products ex 

refinery gate. For natural gas liquids, 

volumes shall reflect the individual 

components of the product as listed in 

Table MM–1 of this subpart. 

EFi = Product-specific CO2 emission factor 

(metric tons CO2 per barrel). 

(2) In the event that an individual 

petroleum product is produced as a solid 

rather than liquid any refiner, importer, or 

exporter shall calculate CO2 emissions using 

Equation MM–1 of this section. 

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product ‘‘i’’ 

(metric tons). 

Producti = Annual mass of product ‘‘i’’ 

produced, imported, or exported by the 

reporting party (metric tons). For 

refiners, this mass only includes 

products ex refinery gate. 

EFi = Product-specific CO2 emission factor 

(metric tons CO2 per metric ton of 

product). 

(b) Calculation for individual 

products that enter a refinery as a noncrude feedstock. 

(1) Except as provided in paragraph 

(h) of this section, 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 CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock 

‘‘j’’ (metric tons). 

Feedstockj = Annual volume of a petroleum 

product or natural gas liquid ‘‘j’’ that 

enters the refinery to be further refined 

or otherwise used on site (barrels). For 

natural gas liquids, volumes shall reflect 

the individual components of the 

product as listed in table MM–1 of this 

subpart. 

EFj = Feedstock-specific CO2 emission factor 

(metric tons CO2 per barrel). 

(2) In the event that a non-crude 

feedstock enters a refinery as a solid 

rather than liquid, the refiner shall 

calculate CO2 emissions using Equation 

MM–2 of this section. 

Where: 

CO2j = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock 

‘‘j’’ (metric tons). 

Feedstockj = Annual mass of a petroleum 

product ‘‘j’’ that enters the refinery to be 

further refined or otherwise used on site 

(metric tons). 

EFj = Feedstock-specific CO2 emission factor 

(metric tons CO2 per metric ton of 

feedstock). 

(c) Calculation for biomass coprocessed with petroleum feedstocks. 

(1) Refiners shall calculate CO2

emissions from each type of biomass 

that enters a refinery and is coprocessed with petroleum feedstocks 

using Equation MM–3 of this section. 

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

Where: 

CO2m = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each type of biomass ‘‘m’’ 

(metric tons). 

Biomassm = Annual volume of a specific type 

of biomass that enters the refinery and is 

co-processed with petroleum feedstocks 

to produce a petroleum product reported 

under paragraph (a) of this section 

(barrels). 


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EFm = Biomass-specific CO2 emission factor 

(metric tons CO2 per barrel). 

(2) In the event that biomass enters a 

refinery as a solid rather than liquid and 

is co-processed with petroleum 

feedstocks, the refiner shall calculate 

CO2 emissions from each type of 

biomass using Equation MM–3 of this 

section. 

Where: 

CO2m = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each type of biomass ‘‘m’’ 

(metric tons). 

Biomassm = Total annual mass of a specific 

type of biomass that enters the refinery 

to be co-processed with petroleum 

feedstocks to produce a petroleum 

product reported under paragraph (a) of 

this section (metric tons). 

EFm = Biomass-specific CO2 emission factor 

(metric tons CO2 per metric ton of 

biomass). 

(d) Summary calculation for refinery 

products. Refiners shall calculate 

annual CO2 emissions from all products 

using Equation MM–4 of this section. 

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

Where: 

CO2r = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of all petroleum products and 

natural gas liquids (ex refinery gate) 

minus non-crude feedstocks and any 

biomass to be co-processed with 

petroleum feedstocks. 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product or 

natural gas liquid ‘‘i’’ (metric tons). 

CO2j = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock 

‘‘j’’ (metric tons). 

CO2m = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each type of biomass ‘‘m’’ 

(metric tons). 

(e) Summary calculation for importer 

and exporter products. Importers and 

exporters shall calculate annual CO2

emissions from all petroleum products 

and natural gas liquids imported or 

exported, respectively, using Equations 

MM–1 and MM–5 of this section. 

CO CO Eq 2 2 x i = ∑( ) ( . MM-5)

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product or 

natural gas liquid ‘‘i’’ (metric tons). 

CO2x = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of all petroleum products and 

natural gas liquids. 

(f) Emission factors for petroleum 

products and natural gas liquids. The 

emission factor (EFi,j) for each 

petroleum product and natural gas 

liquid shall be determined using either 

of the calculation methods described in 

paragraphs (f)(1) or (f)(2) of this section. 

The same calculation method must be 

used for the entire quantity of the 

product for the reporting year. For 

refiners, the quantity of a product that 

enters a refinery (i.e., a non-crude 

feedstock) is considered separate from 

the quantity of a product ex refinery 

gate. 

(1) Calculation Method 1. For solid 

products, use the default carbon share 

factor (i.e., percent carbon by mass) in 

column B of Table MM–1 of this subpart 

for the appropriate product. For all 

other products, use the default CO2

emission factor listed in column C of 

Table MM–1 of this subpart for the 

appropriate product. 

(2) Calculation Method 2. 

(i) For solid products, develop 

emission factors according to Equation 

MM–6 of this section using a value of 

1 for density and direct measurements 

of carbon share according to methods 

set forth in § 98.394(c). For all other 

products, develop emission factors 

according to Equation MM–6 of this 

section using direct measurements of 

density and carbon share according to 

methods set forth in § 98.394(c). 

EF Density i j, = Carbon Share /12) (Eq. MM-6) (44

Where: 

EFi,j = Emission factor of the petroleum 

product or natural gas liquid (metric tons 

CO2 per barrel or per metric ton of 

product). 

Density = Density of the petroleum product 

or natural gas liquid (metric tons per 

barrel for non-solid products, 1 for solid 

products). 

Carbon share = Percent of total mass that 

carbon represents in the petroleum 

product or natural gas liquid, expressed 

as a fraction (e.g., 75% would be 

expressed as 0.75 in the above equation). 

44/12 = Conversion factor for carbon to 

carbon dioxide. 

(ii) If you use a standard method that 

involves gas chromatography to 

determine the percent mass of each 

component in a product, calculate the 

product’s carbon share using Equation 

MM–7 of this section. 

Carbon Share %Composition %Mass (Eq. MM-7) = ∑( ) i...n i...n 

Where: 

Carbon Share = Percent of total mass that 

carbon represents in the petroleum 

product or natural gas liquid. 

%Composition i* * *n = Percent of total 

mass that each molecular component in 

the petroleum product or natural gas 

liquid represents as determined by the 

procedures in the selected standard 

method. 

%Massi* * *n = Percent of total mass that 

carbon represents in each molecular 

component of the petroleum product or 

natural gas liquid. 

(g) Emission factors for biomass coprocessed with petroleum feedstocks. 

Refiners shall use the most appropriate 

default CO2 emission factor (EFm) for 

biomass in Table MM–2 of this subpart 

to calculate CO2 emissions in paragraph 

(c) of this section. 

(h) Special procedures for blended 

biomass-based fuels. In the event that 

some portion of a petroleum product is 

biomass-based and was not derived by 

co-processing biomass and petroleum 

feedstocks together (i.e., the petroleum 

product was produced by blending a 


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petroleum-based product with a 

biomass-based fuel), the reporting party 

shall calculate emissions for the 

petroleum product according to one of 

the methods in paragraphs (h)(1) 

through (h)(4) of this section, as 

appropriate. 

(1) A reporter using Calculation 

Methodology 1 to determine the 

emission factor of a petroleum product 

shall calculate the CO2 emissions 

associated with that product using 

Equation MM–8 of this section in place 

of Equation MM–1 of this section. 

CO oduct EF Vol Eq 2i ii i = Pr % ( . MM-8)

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each petroleum product ‘‘i’’ 

(metric tons). 

Producti = Annual volume of each petroleum 

product ‘‘i’’ produced, imported, or 

exported by the reporting party (barrels). 

For refiners, this volume only includes 

products ex refinery gate. 

EFi = Petroleum product-specific CO2

emission factor (metric tons CO2 per 

barrel) from Table MM–1 of this subpart. 

%Voli = Percent volume of product ‘‘i’’ that 

is petroleum-based, including 2.5% of 

the volume of any ethanol product 

blended into a petroleum-based product 

to represent the denaturant in that 

ethanol product, expressed as a fraction 

(e.g., 75% would be expressed as 0.75 in 

the above equation). 

(2) A refinery using Calculation 

Methodology 1 of this subpart to 

determine the emission factor of a noncrude petroleum feedstock shall 

calculate the CO2 emissions associated 

with that feedstock using Equation MM– 

9 of this section in place of Equation 

MM–2 of this section. 

CO Feedstock EF Vol Eq 2 j ji j = % ( . MM-9)

Where: 

CO2j = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock 

‘‘j’’ (metric tons). 

Feedstockj = Annual volume of each 

petroleum product ‘‘j’’ that enters the 

refinery as a feedstock to be further 

refined or otherwise used on site 

(barrels). 

EFj = Non-crude petroleum feedstock-specific 

CO2 emission factor (metric tons CO2 per 

barrel). 

%Volj = Percent volume of feedstock ‘‘j’’ that 

is petroleum-based, including 2.5% of 

the volume of any ethanol product 

blended with the petroleum-based 

product to represent the denaturant in 

that ethanol product, expressed as a 

fraction (e.g., 75% would be expressed as 

0.75 in the above equation). 

(3) A reporter using Calculation 

Methodology 2 of this subpart to 

determine the emission factor of a 

petroleum product must calculate the 

CO2 emissions associated with that 

product using Equation MM–10 of this 

section in place of Equation MM–1 of 

this section. 

CO oduct EF oduct EF Vol Eq 2i ii im m = ( ) Pr Pr % ( . − ( ) MM-10)

Where: 

CO2i = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each product ‘‘i’’ (metric 

tons). 

Producti = Annual volume of each petroleum 

product ‘‘i’’ produced, imported, or 

exported by the reporting party (barrels). 

For refiners, this volume only includes 

products ex refinery gate. 

EFi = Product-specific CO2 emission factor 

(metric tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table 

MM–2 of this subpart that most closely 

represents the component of product ‘‘i’’ 

that is biomass-based. 

%Volm = Percent volume of petroleum 

product ‘‘i’’ that is biomass-based, not 

including 2.5% of the volume of any 

ethanol product blended with the 

petroleum-based product, which 

represents the denaturant in that ethanol 

product, expressed as a fraction (e.g., 

75% would be expressed as 0.75 in the 

above equation). 

(4) A refiner using Calculation 

Methodology 2 of this subpart to 

determine the emission factor of a noncrude petroleum feedstock must 

calculate the CO2 emissions associated 

with that feedstock using Equation MM– 

11 of this section in place of Equation 

MM–2 of this section. 

CO Feedstock EF Feedstock EF Vol Eq 2 j jj im m = ( ) − ( ) % ( . MM-11)

Where: 

CO2j = Annual CO2 emissions that would 

result from the complete combustion or 

oxidation of each non-crude feedstock 

‘‘j’’ (metric tons). 

Feedstockj = Annual volume of each 

petroleum product ‘‘j’’ that enters the 

refinery to be further refined or 

otherwise used on site (barrels). 

EFj = Feedstock-specific CO2 emission factor 

(metric tons CO2 per barrel). 

EFm = Default CO2 emission factor from Table 

MM–2 of this subpart that most closely 

represents the component of petroleum 

product ‘‘j’’ that is biomass-based. 

%Volm = Percent volume of non-crude 

feedstock ‘‘j’’ that is biomass-based, not 

including 2.5% of the volume of any 

ethanol product blended with the 

petroleum-based product, which 

represents the denaturant in that ethanol 

product, expressed as a fraction (e.g., 

75% would be expressed as 0.75 in the 

above equation). 

§ 98.394 Monitoring and QA/QC 

requirements. 

(a) Determination of quantity. 

(1) The quantity of petroleum 

products, natural gas liquids, biomass, 

and crude oil shall be determined as 

follows: 

(i) Where an appropriate standard 

method published by a consensus-based 

standards organization exists, such a 

method shall be used. Consensus-based 


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standards organizations include, but are 

not limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(ii) Where no appropriate standard 

method developed by a consensus-based 

standards organization exists, industry 

standard practices shall be followed. 

(iii) For products that are liquid at 60 

degrees Fahrenheit and one standard 

atmosphere, all measurements of 

quantity shall be temperature-adjusted 

and pressure-adjusted to these 

conditions. For all other products, 

reporters shall use appropriate standard 

conditions specified in the standard 

method; if temperature and pressure 

conditions are not specified in the 

standard method or if a reporter uses an 

industry standard practice to determine 

quantity, the reporter shall use 

appropriate standard conditions 

according to established industry 

practices. 

(2) All measurement equipment 

(including, but not limited to, flow 

meters and tank gauges) used for 

compliance with this subpart shall be 

appropriate for the standard method or 

industry standard practice followed 

under paragraph (a)(1)(i) or (a)(1)(ii) of 

this section. 

(b) Equipment Calibration. 

(1) All measurement equipment shall 

be calibrated prior to its first use for 

reporting under this subpart, using an 

appropriate standard method published 

by a consensus based standards 

organization or according to the 

equipment manufacturer’s directions. 

(2) Measurement equipment shall be 

recalibrated at the minimum frequency 

specified by the standard method used 

or by the equipment manufacturer’s 

directions. 

(c) Procedures for Calculation 

Methodology 2 of this subpart. 

(1) Reporting parties shall collect one 

sample of each petroleum product or 

natural gas liquid on any day of each 

calendar month of the reporting year in 

which the quantity of that product was 

measured in accordance with the 

requirements of this subpart. For 

example, if a given product was 

measured as entering the refinery 

continuously throughout the reporting 

year, twelve samples of that product 

shall be collected over the reporting 

year, one on any day of each calendar 

month of that year. If a given product 

was only measured from April 15 

through June 10 of the reporting year, a 

refiner would collect three samples 

during that year, one during each of the 

calendar months of April, May and June 

on a day when the product was 

measured as either entering or exiting 

the refinery. Each sample shall be 

collected using an appropriate standard 

method published by a consensus-based 

standards organization. 

(2) Mixing and handling of samples 

shall be performed using an appropriate 

standard method published by a 

consensus-based standards organization. 

(3) Density measurement. 

(i) For all products that are not solid, 

reporters shall test for density using an 

appropriate standard method published 

by a consensus-based standards 

organization. 

(ii) The density value for a given 

petroleum product shall be generated by 

either making a physical composite of 

all of the samples collected for the 

reporting year and testing that single 

sample or by measuring the individual 

samples throughout the year and 

defining the representative density 

value for the sample set by numerical 

means, i.e., a mathematical composite. If 

a physical composite is chosen as the 

option to obtain the density value, the 

reporter shall submit each of the 

individual samples collected during the 

reporting year to the laboratory 

responsible for generating the composite 

sample. 

(iii) For physical composites, the 

reporter shall handle the individual 

samples and the laboratory shall mix 

them in accordance with an appropriate 

standard method published by a 

consensus-based standards organization. 

(iv) All measurements of density shall 

be temperature-adjusted and pressureadjusted to the conditions assumed for 

determining the quantities of the 

product reported under this subpart. 

(4) Carbon share measurement. 

(i) Reporters shall test for carbon 

share using an appropriate standard 

method published by a consensus-based 

standards organization. 

(ii) If a standard method that involves 

gas chromatography is used to 

determine the percent mass of each 

component in a product, the molecular 

formula for each component shall be 

obtained from the information provided 

in the standard method and the atomic 

mass of each element in a given 

molecular component shall be obtained 

from the periodic table of the elements. 

(iii) The carbon share value for a 

given petroleum product shall be 

generated by either making a physical 

composite of all of the samples collected 

for the reporting year and testing that 

single sample or by measuring the 

individual samples throughout the year 

and defining the representative carbon 

share value for the sample set by 

numerical means, i.e., a mathematical 

composite. If a physical composite is 

chosen as the option to obtain the 

carbon share value, the reporter shall 

submit each of the individual samples 

collected during the reporting year to 

the laboratory responsible for generating 

the composite sample. 

(iv) For physical composites, the 

reporter shall handle the individual 

samples and the laboratory shall mix 

them in accordance with an appropriate 

standard method published by a 

consensus-based standards organization. 

(d) Measurement of API gravity and 

sulfur content of crude oil. 

(1) Samples of each batch of crude oil 

shall be taken according to an 

appropriate standard method published 

by a consensus-based standards 

organization. 

(2) Samples shall be handled 

according to an appropriate standard 

method published by a consensus-based 

standards organization. 

(3) API gravity shall be measured 

using an appropriate standard method 

published by a consensus-based 

standards organization. 

(4) Sulfur content shall be measured 

using an appropriate standard method 

published by a consensus-based 

standards organization. 

(5) All measurements shall be 

temperature-adjusted and pressureadjusted to the conditions assumed for 

determining the quantities of crude oil 

reported under this subpart. 

§ 98.395 Procedures for estimating 

missing data. 

(a) Determination of quantity. 

Whenever the quality assurance 

procedures in § 98.394(a) cannot be 

followed to measure the quantity of one 

or more petroleum products, natural gas 

liquids, types of biomass, feedstocks, or 

crude oil batches during any period 

(e.g., if a meter malfunctions), the 

following missing data procedures shall 

be used: 

(1) For quantities of a product that are 

purchased or sold, a period of missing 

data shall be substituted using a 

reporter’s established procedures for 

billing purposes in that period as agreed 

to by the party selling or purchasing the 

product. 

(2) For quantities of a product that are 

not purchased or sold but of which the 

custody is transferred, a period of 

missing data shall be substituted using 

a reporter’s established procedures for 

tracking purposes in that period as 

agreed to by the party involved in 

custody transfer of the product. 


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(b) Determination of emission factor. 

Whenever any of the procedures in 

§ 98.394(c) cannot be followed to 

develop an emission factor for any 

reason, Calculation Methodology 1 of 

this subpart must be used in place of 

Calculation Methodology 2 of this 

subpart for the entire reporting year. 

(c) Determination of API gravity and 

sulfur content of crude oil. For missing 

data on sulfur content or API gravity, 

the substitute data value shall be the 

arithmetic average of the quality-assured 

values of API gravity or sulfur content 

in the batch preceding and the batch 

immediately following the missing data 

incident. If no quality-assured data are 

available prior to the missing data 

incident, the substitute data value shall 

be the first quality-assured values for 

API gravity and sulfur content obtained 

from the batch after the missing data 

period. 

§ 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) For each petroleum product or 

natural gas liquid listed in table MM–1 

of this subpart that enters the refinery to 

be further refined or otherwise used on 

site, report the annual quantity in metric 

tons or barrels by each quantity 

measurement standard method or other 

industry standard practice used. For 

natural gas liquids, quantity shall reflect 

the individual components of the 

product. 

(2) For each petroleum product or 

natural gas liquid listed in Table MM– 

1 of this subpart that enters the refinery 

to be further refined or otherwise used 

on site, report the annual quantity in 

metric tons or barrels. For natural gas 

liquids, quantity shall reflect the 

individual components of the product. 

(3) For each feedstock reported in 

paragraph (a)(2) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (a)(2) of 

this section that is petroleum-based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(1) of this section. 

(5) For each petroleum product and 

natural gas liquid (ex refinery gate) 

listed in Table MM–1 of this subpart, 

report the annual quantity in metric 

tons or barrels by each quantity 

measurement standard method or other 

industry standard practice used. For 

natural gas liquids, quantity shall reflect 

the individual components of the 

product. 

(6) For each petroleum product and 

natural gas liquid (ex refinery gate) 

listed in Table MM–1 of this subpart, 

report the annual quantity in metric 

tons or barrels. For natural gas liquids, 

quantity shall reflect the individual 

components of the product. 

(7) For each product reported in 

paragraph (a)(6) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (a)(6) of 

this section that is petroleum-based. 

(8) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(5) of this section. 

(9) For every feedstock reported in 

paragraph (a)(2) of this section for 

which Calculation Methodology 2 of 

this subpart was used to determine an 

emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c) 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percentmass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons. 

(10) For every non-solid feedstock 

reported in paragraph (a)(2) of this 

section for which Calculation 

Methodology 2 of this subpart was used 

to determine an emissions factor, report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(11) For every petroleum product and 

natural gas liquid reported in paragraph 

(a)(6) of this section for which 

Calculation Methodology 2 of this 

subpart was used to determine an 

emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percentmass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

(12) For every non-solid petroleum 

product and natural gas liquid reported 

in paragraph (a)(6) for which 

Calculation Method 2 was used to 

determine an emissions factor, report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(13) For each specific type of biomass 

that enters the refinery to be coprocessed with petroleum feedstocks to 

produce a petroleum product reported 

in paragraph (a)(6) of this section, report 

the annual quantity in metric tons or 

barrels by each quantity measurement 

standard method or other industry 

standard practice used. 

(14) For each specific type of biomass 

that enters the refinery to be coprocessed with petroleum feedstocks to 

produce a petroleum product reported 

in paragraph (a)(6) of this section, report 

the annual quantity in metric tons or 

barrels. 

(15) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(13) of this section. 

(16) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

petroleum product and natural gas 

liquid (ex refinery gate) reported in 

paragraph (a)(6) of this section, 

calculated according to § 98.393(a) or 

(h). 

(17) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

feedstock reported in paragraph (a)(2) of 

this section, calculated according to 

§ 98.393(b) or (h). 

(18) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each type of 

biomass feedstock co-processed with 

petroleum feedstocks reported in 

paragraph (a)(13) of this section, 

calculated according to § 98.393(c). 

(19) The sum of CO2 emissions that 

would result from the complete 

combustion or oxidation of all products, 

calculated according to § 98.393(d). 

(20) All of the following information 

for all crude oil feedstocks used at the 

refinery: 

(i) Batch volume in barrels. 

(ii) API gravity of the batch at the 

point of entry at the refinery. 

(iii) Sulfur content of the batch at the 

point of entry at the refinery. 

(iv) Country of origin of the batch, if 

known. 

(21) The quantity of bulk NGLs in 

metric tons or barrels received for 

processing during the reporting year. 

(b) In addition to the information 

required by § 98.3(c), each importer 

shall report all of the following 

information at the corporate level: 

(1) For each petroleum product and 

natural gas liquid listed in Table MM– 

1 of this subpart, report the annual 

quantity in metric tons or barrels by 

each quantity measurement standard 

method or other industry standard 

practice used. For natural gas liquids, 


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quantity shall reflect the individual 

components of the product. 

(2) For each petroleum product and 

natural gas liquid listed in Table MM– 

1 of this subpart, report the annual 

quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect 

the individual components of the 

product as listed in Table MM–1 of this 

subpart. 

(3) For each product reported in 

paragraph (b)(2) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (b)(2) of 

this section that is petroleum-based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (b)(1) of this section. 

(5) For each product reported in 

paragraph (b)(2) of this section for 

which Calculation Methodology 2 of 

this subpart used was used to determine 

an emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percent mass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

(6) For each non-solid product 

reported in paragraph (b)(2) of this 

section for which Calculation 

Methodology 2 of this subpart was used 

to determine an emissions factor, report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(7) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of each 

imported petroleum product and natural 

gas liquid reported in paragraph (b)(2) of 

this section, calculated according to 

§ 98.393(a). 

(8) The sum of CO2 emissions that 

would result from the complete 

combustion oxidation of all imported 

products, calculated according to 

§ 98.393(e). 

(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) For each petroleum product and 

natural gas liquid listed in Table MM– 

1 of this subpart, report the annual 

quantity in metric tons or barrels by 

each quantity measurement standard 

method or other industry standard 

practice used. For natural gas liquids, 

quantity shall reflect the individual 

components of the product. 

(2) For each petroleum product and 

natural gas liquid listed in Table MM– 

1 of this subpart, report the annual 

quantity in metric tons or barrels. For 

natural gas liquids, quantity shall reflect 

the individual components of the 

product. 

(3) For each product reported in 

paragraph (c)(2) of this section that was 

produced by blending a petroleumbased product with a biomass-based 

product, report the percent of the 

volume reported in paragraph (c)(2) of 

this section that is petroleum based. 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (c)(1) of this section. 

(5) For each product reported in 

paragraph (c)(2) of this section for 

which Calculation Methodology 2 of 

this subpart was used to determine an 

emissions factor, report: 

(i) The number of samples collected 

according to § 98.394(c). 

(ii) The sampling standard method 

used. 

(iii) The carbon share test results in 

percentmass. 

(iv) The standard method used to test 

carbon share. 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

(6) For each non-solid product 

reported in paragraph (c)(2) of this 

section for which Calculation 

Methodology 2 of this subpart used was 

used to determine an emissions factor, 

report: 

(i) The density test results in metric 

tons per barrel. 

(ii) The standard method used to test 

density. 

(7) The CO2 emissions in metric tons 

that would result from the complete 

combustion or oxidation of for each 

exported petroleum product and natural 

gas liquid reported in paragraph (c)(2) of 

this section, calculated according to 

§ 98.393(a). 

(8) The sum of CO2 emissions that 

would result from the complete 

combustion or oxidation of all exported 

products, calculated according to 

§ 98.393(e). 

§ 98.397 Records that must be retained. 

(a) All reporters shall retain copies of 

all reports submitted to EPA under 

§ 98.396. In addition, all reporters shall 

maintain sufficient records to support 

information contained in those reports, 

including but not limited to information 

on the characteristics of their feedstocks 

and products. 

(b) Reporters shall maintain records to 

support quantities that are reported 

under this subpart, including records 

documenting any estimations of missing 

data and the number of calendar days in 

the reporting year for which substitute 

data procedures were followed. For all 

quantities of petroleum products, 

natural gas liquids, biomass, and 

feedstocks, reporters shall maintain 

metering, guaging, and other records 

normally maintained in the course of 

business to document product and 

feedstock flows including the date of 

initial calibration and the frequency of 

recalibration for the measurement 

equipment used 

(c) Reporters shall retain laboratory 

reports, calculations and worksheets 

used to estimate the CO2 emissions of 

the quantities of petroleum products, 

natural gas liquids, biomass, and 

feedstocks reported under this subpart. 

(d) Reporters shall maintain 

laboratory reports, calculations and 

worksheets used in the measurement of 

density and carbon share for any 

petroleum product or natural gas liquid 

for which CO2 emissions were 

calculated using Calculation 

Methodology 2. 

(e) Reporters shall maintain laboratory 

reports, calculations and worksheets 

used in the measurement of API gravity 

and sulfur content for every crude oil 

batch reported under this subpart. 

(f) Estimates of missing data shall be 

documented and records maintained 

showing the calculations. 

(g) Reporters described in this subpart 

shall also retain all records described in 

§ 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. 


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TABLE MM–1 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR PETROLEUM PRODUCTS AND NATURAL GAS

LIQUIDS 1 2

Products 

Column A: 

density 

(metric tons/ 

bbl) 

Column B: 

carbon 

share 

(% of mass) 

Column C: 

emission 

factor 

(metric tons 

CO2/bbl) 

Finished Motor Gasoline 

Conventional—Summer 

Regular ............................................................................................................................................. 0.1181 86.66 0.3753 

Midgrade ........................................................................................................................................... 0.1183 86.63 0.3758 

Premium ........................................................................................................................................... 0.1185 86.61 0.3763 

Conventional—Winter 

Regular ............................................................................................................................................. 0.1155 86.50 0.3663 

Midgrade ........................................................................................................................................... 0.1161 86.55 0.3684 

Premium ........................................................................................................................................... 0.1167 86.59 0.3705 

Reformulated—Summer 

Regular ............................................................................................................................................. 0.1167 86.13 0.3686 

Midgrade ........................................................................................................................................... 0.1165 86.07 0.3677 

Premium ........................................................................................................................................... 0.1164 86.00 0.3670 

Reformulated—Winter 

Regular ............................................................................................................................................. 0.1165 86.05 0.3676 

Midgrade ........................................................................................................................................... 0.1165 86.06 0.3676 

Premium ........................................................................................................................................... 0.1166 86.06 0.3679 

Gasoline—Other ...................................................................................................................................... 0.1185 86.61 0.3763 

Blendstocks 

CBOB—Summer 

Regular ............................................................................................................................................. 0.1181 86.66 0.3753 

Midgrade ........................................................................................................................................... 0.1183 86.63 0.3758 

Premium ........................................................................................................................................... 0.1185 86.61 0.3763 

CBOB—Winter 

Regular ............................................................................................................................................. 0.1155 86.50 0.3663 

Midgrade ........................................................................................................................................... 0.1161 86.55 0.3684 

Premium ........................................................................................................................................... 0.1167 86.59 0.3705 

RBOB—Summer 

Regular ............................................................................................................................................. 0.1167 86.13 0.3686 

Midgrade ........................................................................................................................................... 0.1165 86.07 0.3677 

Premium ........................................................................................................................................... 0.1164 86.00 0.3670 

RBOB—Winter 

Regular ............................................................................................................................................. 0.1165 86.05 0.3676 

Midgrade ........................................................................................................................................... 0.1165 86.06 0.3676 

Premium ........................................................................................................................................... 0.1166 86.06 0.3679 

Blendstocks—Other ................................................................................................................................. 0.1185 86.61 0.3763 

Oxygenates 

Methanol .................................................................................................................................................. 0.1268 37.48 0.1743 

GTBA ....................................................................................................................................................... 0.1257 64.82 0.2988 

MTBE ....................................................................................................................................................... 0.1181 68.13 0.2950 

ETBE ........................................................................................................................................................ 0.1182 70.53 0.3057 

TAME ....................................................................................................................................................... 0.1229 70.53 0.3178 

DIPE ......................................................................................................................................................... 0.1156 70.53 0.2990 

Distillate Fuel Oil 

Distillate No. 1 

Ultra Low Sulfur ................................................................................................................................ 0.1346 86.40 0.4264 

Low Sulfur ......................................................................................................................................... 0.1346 86.40 0.4264 

High Sulfur ........................................................................................................................................ 0.1346 86.40 0.4264 

Distillate No. 2 

Ultra Low Sulfur ................................................................................................................................ 0.1342 87.30 0.4296 

Low Sulfur ......................................................................................................................................... 0.1342 87.30 0.4296 

High Sulfur ........................................................................................................................................ 0.1342 87.30 0.4296 

Distillate Fuel Oil No. 4 ............................................................................................................................ 0.1452 86.47 0.4604 

Residual Fuel Oil No. 5 (Navy Special) .................................................................................................. 0.1365 85.67 0.4288 

Residual Fuel Oil No. 6 (a.k.a. Bunker C) .............................................................................................. 0.1528 84.67 0.4744 

Kerosene-Type Jet Fuel .......................................................................................................................... 0.1294 86.30 0.4095 

Kerosene .................................................................................................................................................. 0.1346 86.40 0.4264 

Diesel—Other .......................................................................................................................................... 0.1452 86.47 0.4604 

Petrochemical Feedstocks 


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TABLE MM–1 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR PETROLEUM PRODUCTS AND NATURAL GAS

LIQUIDS 1 2—Continued 

Products 

Column A: 

density 

(metric tons/ 

bbl) 

Column B: 

carbon 

share 

(% of mass) 

Column C: 

emission 

factor 

(metric tons 

CO2/bbl) 

Naphthas (< 401 °F) ......................................................................................................................... 0.1158 84.11 0.3571 

Other Oils (> 401 °F) ........................................................................................................................ 0.1390 87.30 0.4450 

Unfinished Oils 

Heavy Gas Oils ........................................................................................................................................ 0.1476 85.80 0.4643 

Residuum ................................................................................................................................................. 0.1622 85.70 0.5097 

Other Petroleum Products and Natural Gas Liquids 

Aviation Gasoline ..................................................................................................................................... 0.1120 85.00 0.3490 

Special Naphthas ..................................................................................................................................... 0.1222 84.76 0.3798 

Lubricants ................................................................................................................................................ 0.1428 85.80 0.4492 

Waxes ...................................................................................................................................................... 0.1285 85.30 0.4019 

Petroleum Coke ....................................................................................................................................... 0.1818 92.28 0.6151 

Asphalt and Road Oil .............................................................................................................................. 0.1634 83.47 0.5001 

Still Gas ................................................................................................................................................... 0.1405 77.70 0.4003 

Ethane ...................................................................................................................................................... 0.0866 79.89 0.2537 

Ethylene ................................................................................................................................................... 0.0903 85.63 0.2835 

Propane ................................................................................................................................................... 0.0784 81.71 0.2349 

Propylene ................................................................................................................................................. 0.0803 85.63 0.2521 

Butane ...................................................................................................................................................... 0.0911 82.66 0.2761 

Butylene ................................................................................................................................................... 0.0935 85.63 0.2936 

Isobutane ................................................................................................................................................. 0.0876 82.66 0.2655 

Isobutylene ............................................................................................................................................... 0.0936 85.63 0.2939 

Pentanes Plus .......................................................................................................................................... 0.1055 83.63 0.3235 

Miscellaneous Products ........................................................................................................................... 0.1380 85.49 0.4326 

1 In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM–1 of this subpart represents only the 

petroleum-based components. 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. 

TABLE MM–2 TO SUBPART MM OF PART 98—DEFAULT FACTORS FOR BIOMASS-BASED FUELS AND BIOMASS

Biomass-based fuel and biomass 

Column A: 

Density 

(metric tons/ 

bbl) 

Column B: 

Carbon 

share 

(% of mass) 

Column C: 

Emission 

factor 

(metric tons 

CO2/bbl) 

Ethanol (100%) ........................................................................................................................................ 0.1267 52.14 0.2422 

Biodiesel (100%, methyl ester) ................................................................................................................ 0.1396 77.30 0.3957 

Rendered Animal Fat ............................................................................................................................... 0.1333 76.19 0.3724 

Vegetable Oil ........................................................................................................................................... 0.1460 76.77 0.4110 

Subpart NN—Suppliers of Natural Gas 

and Natural Gas Liquids 

§ 98.400 Definition of the source category. 

This supplier category consists of 

natural gas liquids fractionators and 

local natural gas distribution 

companies. 

(a) Natural gas liquids fractionators 

are installations that fractionate natural 

gas liquids (NGLs) into their consitutent 

liquid products (ethane, propane, 

normal butane, isobutane or pentanes 

plus) for supply to downstream 

facilities. 

(b) Local Distribution Companies 

(LDCs) are companies that own or 

operate distribution pipelines, not 

interstate pipelines or intrastate 

pipelines, that physically deliver 

natural gas to end users and that are 

regulated as separate operating 

companies by State public utility 

commissions or that operate as 

independent municipally-owned 

distribution systems. 

(c) This supply category does not 

consist of the following facilities: 

(1) Field gathering and boosting 

stations. 

(2) Natural gas processing plants that 

separate NGLs from natural gas and 

produce bulk or y-grade NGLs but do 

not fractionate these NGLs into their 

constituent products. 

(3) Facilities that meet the definition 

of refineries and report under subpart 

MM of this part. 

(4) Facilities that meet the definition 

of petrochemical plants and report 

under subpart X of this part. 

§ 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) NGL fractionators must report the 

CO2 emissions that would result from 

the complete combustion or oxidation of 

the annual quantity of ethane, propane, 

normal butane, isobutane, and pentanes 


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plus that is produced and sold or 

delivered to others. 

(b) LDCs must report the CO2

emissions that would result from the 

complete combustion or oxidation of the 

annual volumes of natural gas provided 

to end-users on their distribution 

systems. 

§ 98.403 Calculating GHG emissions. 

(a) LDCs and fractionators shall, for 

each individual product reported under 

this part, calculate the estimated CO2

emissions that would result from the 

complete combustion or oxidation of the 

products supplied using either of 

Calculation Methodology 1 or 2 of this 

subpart: 

(1) Calculation Methodology 1. NGL 

fractionators shall estimate CO2

emissions that would result from the 

complete combustion or oxidation of the 

product(s) supplied using Equation NN– 

1 of this section. LDCs shall estimate 

CO2 emissions that would result from 

the complete combustion or oxidation of 

the product received at the city gate 

using Equation NN–1. For each product, 

use the default value for higher heating 

value and CO2 emission factor in Table 

NN–1 of this subpart. Alternatively, for 

each product, a reporter-specific higher 

heating value and CO2 emission factor 

may be used, in place of one or both 

defaults provided they are developed 

using methods outlined in § 98.404. For 

each product, you must use the same 

volume unit throughout the equation. 

CO x Fuel HHV EF Eq 2i hh

3 =1 10− ∑ h ( . NN-1)

Where: 

CO2i = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of each product ‘‘h’’ for 

redelivery to all recipients (metric tons). 

Fuel = Total annual volume of product ‘‘h’’ 

supplied (volume per year, in Mscf for 

natural gas and bbl for NGLs). 

HHV = Higher heating value of product ‘‘h’’ 

supplied (MMBtu/Mscf or MMBtu/bbl). 

EFh = CO2 emission factor of product ‘‘h’’ (kg 

CO2/MMBtu). 

1 x 10¥3 = Conversion factor from kilograms 

to metric tons (MT/kg). 

(2) Calculation Methodology 2. NGL 

fractionators shall estimate CO2

emissions that would result from the 

complete combustion or oxidation of the 

product(s) supplied using Equation NN– 

2 of this section. LDCs shall estimate 

CO2 emissions that would result from 

the complete combustion or oxidation of 

the product received at the city gate 

using Equation NN–2. For each product, 

use the default CO2 emission factor 

found in Table NN–2 of this subpart. 

Alternatively, for each product, a 

reporter-specific CO2 emission factor 

may be used in place of the default 

factor, provided it is developed using 

methods outlined in § 98.404. For each 

product, you must use the same volume 

unit throughout the equation. 

CO Eq 2i = ∗ ∑Fuel EF 2 h h

h

( . NN- )

Where: 

CO2i = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of each product ‘‘h’’ (metric 

tons) 

Fuel = Total annual volume of product ‘‘h’’ 

supplied (bbl or Mscf per year) 

EFh = CO2 emission factor of product ‘‘h’’ 

(MT CO2/bbl, or MT CO2/Mscf) 

(b) Each LDC shall follow the 

procedures below. 

(1) For natural gas that is received for 

redelivery to downstream gas 

transmission pipelines and other local 

distribution companies, use eEquation 

NN–3 of this section and the default 

values for the CO2 emission factors 

found in Table NN–2 of this subpart. 

Alternatively, reporter-specific CO2

emission factors may be used, provided 

they are developed using methods 

outlined in § 98.404. 

CO Fuel EF Eq 2 j = (. ) NN-3

Where: 

CO2j = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas for redelivery to 

transmission pipelines or other LDCs 

(metric tons). 

Fuel = Total annual volume of natural gas 

supplied (Mscf per year). 

EF = Fuel-specific CO2 emission factor (MT 

CO2/Mscf). 

(2)(i) For natural gas delivered to each 

meter registering a supply equal to or 

greater than 460,000 Mscf per year, use 

Equation NN–4 of this section and the 

default values for the CO2 emission 

factors found in Table NN–2 of this 

subpart. 

(ii) Alternatively, reporter-specific 

CO2 emission factors may be used, 

provided they are developed using 

methods outlined in § 98.404. 

CO Fuel EF Eq 2k = (. ) NN-4

Where: 

CO2k = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas received by endusers that receive a supply equal to or 

greater than 460,000 Mscf per year 

(metric tons). 

Fuel = Total annual volume of natural gas 

supplied (Mscf per year). 

EF = Fuel-specific CO2 emission factor (MT 

CO2/Mscf). 

(3) For natural gas received by the 

LDC at the city gate that is injected into 

on-system storage, and/or liquefied and 

stored, use Equation NN–5 of this 

section and the default value for the CO2

emission factors found in Table NN–2 of 

this subpart. Alternatively, a reporterspecific CO2 emission factor may be 

used, provided it is developed using 

methods outlined in § 98.404. 

CO Fuel Fuel EF Eq 2 12 l = − [ ] (. ) NN-5

Where: 

CO2l = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of the net natural gas that is 

liquefied and/or stored and not used for 

deliveries by the LDC within the 

reported year (metric tons). 

Fuel1 = Total annual volume of natural gas 

received by the LDC at the city gate and 

stored on-system or liquefied and stored 

in the reportng year (Mscf per year). 

Fuel2 = Total annual volume of natural gas 

that is used for deliveries in the 

reporting year that was not otherwise 

accounted for in Equation NN–1 or NN– 

2 of this section (Mscf per year). This 

primarily includes natural gas previously 

stored on-system or liquefied and stored 

that is removed from storage and used 

for deliveries to customers or other LDCs 

by the LDC within the reporting year. 

This also includes natural gas that 

bypassed the city gate and was delivered 

directly to LDC systems from producers 

or natural gas processing plants from 

local production. 

EF = Fuel-specific CO2 emission factor (MT 

CO2/Mscf). 


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(4) Calculate the total CO2 emissions 

that would result from the complete 

combustion or oxidation of the annual 

supply of natural gas to end-users using 

Equation NN–6 of this section. 

CO CO CO CO (Eq. NN-6) 2 2i 2j 2k = −− − ∑∑ ∑ ∑ CO2l

Where: 

CO2 = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas delivered to LDC 

customers not covered in paragraph 

(b)(2) of this section (metric tons). 

CO2i = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas received at the 

city gate as calculated in paragraph (a)(1) 

or (a)(2) of this section (metric tons). 

CO2j = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas delivered to 

transmission pipelines or other LDCs as 

calculated in paragraph (b)(1) of this 

section (metric tons). 

CO2k = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas received by endusers that receive a supply equal to or 

greater than 460,000 Mscf per year as 

calculated in paragraph (b)(2) of this 

section (metric tons). 

CO2l = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas received by the 

LDC and liquefied and/or stored but not 

used for deliveries within the reported 

year as calculated in paragraph (b)(3) of 

this section (metric tons). 

(c) Each NGL fractionator shall follow 

the following procedures. 

(1)(i) For fractionated NGLs received 

by the reporter from other NGL 

fractionators, you shall use Equation 

NN–7 of this section and the default 

values for the CO2 emission factors 

found in Table NN–2 of this subpart. 

(ii) Alternatively, reporter-specific 

CO2 emission factors may be used, 

provided they are developed using 

methods outlined in § 98.404. 

CO Eq 2m = ∑Fuel EF NN- ) 7 g g 

g

( .

Where: 

CO2m = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of each fractionated NGL 

product ‘‘g’’ received from other 

fractionators (metric tons). 

Fuelg = Total annual volume of each NGL 

product ‘‘g’’ received (bbls). 

EF = Fuel-specific CO2 emission factor (MT 

CO2/bbl). 

(2) Calculate the total CO2 equivalent 

emissions that would result from the 

combustion or oxidation of fractionated 

NGLs supplied less the quantity 

received by other fractionators using 

Equation NN–8 of this section. 

CO CO CO (Eq. NN-8) 2 2i 2j = − ∑ ∑

Where: 

CO2 = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of fractionated NGLs delivered 

to customers or on behalf of customers 

(metric tons). 

CO2i = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of fractionated NGLs delivered 

to all customers as calculated in 

paragraph (a)(1) or (a)(2) of this section 

(metric tons). 

CO2m = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of fractionated NGLs received 

from other fractionators and calculated 

in paragraph (c)(1) of this section (metric 

tons). 

§ 98.404 Monitoring and QA/QC 

requirements. 

(a) Determination of quantity. 

(1) NGL fractionators and LDCs shall 

determine the quantity of NGLs and 

natural gas using methods in common 

use in the industry for billing purposes 

as audited under existing Sarbanes 

Oxley regulationn. 

(i) Where an appropriate standard 

method published by a consensus-based 

standards organization exists, such a 

method shall be used. Consensus-based 

standards organizations include, but are 

not limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(ii) Where no appropriate standard 

method developed by a consensus-based 

standards organization exists, industry 

standard practices shall be followed. 

(2) NGL fractionators and LDCs shall 

base the minimum frequency of the 

product quantity measurements, to be 

summed to the annual quantity 

reported, on the reporter’s standard 

practices for commercial operations. 

(i) For NGL fractionators the 

minimum frequency of measurements 

shall be the measurements taken at 

custody transfers summed to the annual 

reportable volume. 

(ii) For natural gas the minimum 

frequency of measurement shall be 

based on the LDC’s standard 

measurement schedules used for billing 

purposes and summed to the annual 

reportable volume. 

(3) NGL fractionators shall use 

measurement for NGLs at custody 

tranfer meters or at such meters that are 

used to determine the NGL product slate 

delivered from the fractionation facility. 

(4) If a NGL fractionator supplies a 

product not listed in Table NN–1 of this 

subpart that is a mixture or blend of two 

or more products listed in Tables NN– 

1 and NN–2 of this subpart, the NGL 

fractionator shall report the quantities of 

the constituents of the mixtures or 

blends separately. 

(5) For an LDC using Equation NN–1 

or NN–2 of this subpart, the point(s) of 

measurement for the natural gas volume 

supplied shall be the LDC city gate 

meter(s). 

(i) If the LDC makes its own quantity 

measurements according to established 

business practices, its own 

measurements shall be used. 

(ii) If the LDC does not make its own 

quantity measurements according to 

established business practices, it shall 

use its delivering pipeline invoiced 

measurements for natural gas deliveries 

to the LDC city gate, used in 

determining daily system sendout. 

(6) An LDC using Equation NN–3 of 

this subpart shall measure natural gas at 

the custody transfer meters. 

(7) An LDC using Equation NN–4 of 

this subpart shall measure natural gas at 

the customer meters. The reporter shall 

consider the volume delivered through 

a single particluar meter at a single 

particular location as the volume 

delivered to an individual end-user. 

(8) An LDC using Equation NN–5 of 

this subpart shall measure natural gas as 

follows: 


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(i) Fuel1 shall be measured at the onsystem storage injection meters and/or 

at the meters measuring natural gas to 

be liquefied. 

(ii) Fuel2 shall be measured at the 

meters used for measuring on-system 

storage withdrawals and/or LNG 

vaporization injection. If Fuel2 is from a 

source other than storage, the 

appropriate meter shall be used to 

measure the quantity. 

(9) An LDC shall measure all natural 

gas under the following standard 

industry temperature and pressure 

conditions: Cubic foot of gas at a 

temperature of 60 degrees Fahrenheit 

and at an absolute pressure of fourteen 

and seventy-three hundredths (14.73) 

pounds per square inch. 

(b) Determination of higher heating 

values (HHV). 

(1) When a reporter uses the default 

HHV provided in this section to 

calculate Equation NN–1 of this subpart, 

the appropriate value shall be taken 

from Table NN–1 of this subpart. 

(2) When a reporter uses a reporterspecific HHV to calculate Equation NN– 

1 of this subpart, an appropriate 

standard test published by a consensusbased standards organization shall be 

used. Consensus-based standards 

organizations include, but are not 

limited to, the following: AGA and GPA. 

(i) If an LDC makes its own HHV 

measurements according to established 

business practices, then its own 

measurements shall be used. 

(ii) If an LDC does not make its own 

measurements according to established 

business practices, it shall use its 

delivering pipeline measurements. 

(c) Determination of emission factor 

(EF). 

(1) When a reporter used the default 

EF provided in this section to calculate 

Equation NN–1 of this subpart, the 

appropriate value shall be taken from 

Table NN–1 of this subpart. 

(2) When a reporter used the default 

EF provided in this section to calculate 

Equation NN–2, NN–3, NN–4, NN–5, or 

NN–7 of this subpart, the appropriate 

value shall be taken from Table NN–2 of 

this subpart. 

(3) When a reporter uses a reporterspecific EF, the reporter shall use an 

appropriate standard method published 

by a consensus-based standards 

organization to conduct compositional 

analysis necessary to determine 

reporter-specific CO2 emission factors. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: AGA and GPA. 

(d) Equipment Calibration. 

(1) Equipment used to measure 

quantities in Equations NN–1, NN–2, 

and NN–5 of this subpart shall be 

calibrated prior to its first use for 

reporting under this subpart, using a 

suitable standard method published by 

a consensus based standards 

organization or according to the 

equipment manufacturer’s directions. 

(2) Equipment used to measure 

quantities in Equations NN–1, NN–2, 

and NN–5 of this subpart shall be 

recalibrated at the frequency specified 

by the standard method used or by the 

manufacturer’s directions. 

§ 98.405 Procedures for estimating 

missing data. 

(a) Whenever a quality-assured value 

of the quantity of natural gas liquids or 

natural gas supplied during any period 

is unavailable (e.g., if a flow meter 

malfunctions), a substitute data value 

for the missing quantity measurement 

must be used in the calculations 

according to paragraphs (b) and (c) of 

this section. 

(b) Determination of quantity. 

(1) NGL fractionators shall substitute 

meter records provided by pipeline(s) 

for all pipeline receipts of NGLs; by 

manifests for deliveries made to trucks 

or rail cars; or metered quantities 

accepted by the entities purchasing the 

output from the fractionator whether by 

pipeline or by truck or rail car. In cases 

where the metered data from the 

receiving pipeline(s) or purchasing 

entities are not available, fractionators 

may substitute estimates based on 

contract quantities required to be 

delivered under purchase or delivery 

contracts with other parties. 

(2) LDCs shall either substitute their 

delivering pipeline metered deliveries at 

the city gate or substitute nominations 

and scheduled delivery quantities for 

the period when metered values of 

actual deliveries are not available. 

(c) Determination of HHV and EF. 

(1) Whenever an LDC that makes its 

own HHV measurements according to 

established business practices cannot 

follow the quality assurance procedures 

for developing a reporter-specific HHV, 

as specified in § 98.404, during any 

period for any reason, the reporter shall 

use either its delivering pipeline 

measurements or the default HHV 

provided in Table NN–1 of this part for 

that period. 

(2) Whenever an LDC that does not 

make its own HHV measurements 

according to established business 

practices or an NGL fractionator cannot 

follow the quality assurance procedures 

for developing a reporter-specific HHV, 

as specified in § 98.404, during any 

period for any reason, the reporter shall 

use the default HHV provided in Table 

NN–1 of this part for that period. 

(3) Whenever a NGL fractionator 

cannot follow the quality assurance 

procedures for developing a reporterspecific HHV, as specified in § 98.404, 

during any period for any reason, the 

NGL fractionator shall use the default 

HHV provided in Table NN–1 of this 

part for that period. 

(4) Whenever a reporter cannot follow 

the quality assurance procedures for 

developing a reporter-specific EF, as 

specified in § 98.404, during any period 

for any reason, the reporter shall use the 

default EF provided in § 98.408 for that 

period. 

§ 98.406 Data reporting requirements. 

(a) In addition to the information 

required by § 98.3(c), the annual report 

for each NGL fractionator covered by 

this rule shall contain the following 

information. 

(1) Annual quantity (in barrels) of 

each NGL product supplied to 

downstream facilities in the following 

product categories: ethane, propane, 

normal butane, isobutane, and pentanes 

plus. 

(2) Annual quantity (in barrels) of 

each NGL product received from other 

NGL fractionators in the following 

product categories: ethane, propane, 

normal butane, isobutane, and pentanes 

plus. 

(3) Annual volumes in Mscf of natural 

gas received for processing. 

(4) Annual quantity (in barrels) of ygrade, bulk NGLs received from others 

for fractionation. 

(5) Annual quantity (in barrels) of 

propane that the NGL fractionator 

odorizes at the facility and delivers to 

others. 

(6) Annual CO2 emissions (metric 

tons) that would result from the 

complete combustion or oxidation of the 

quantities in paragraphs (b)(1) and (b)(2) 

of this section, calculated in accordance 

with § 98.403(a) and (c)(1). 

(7) Annual CO2 mass emissions 

(metric tons) that would result from the 

combustion or oxidation of fractionated 

NGLs supplied less the quantity 

received by other fractionators, 

calculated in accordance with 

§ 98.403(c)(2). 

(8) The specific industry standard 

used to measure each quantity reported 

in paragraph (a)(1) of this section. 

(9) If the LNG fractionator developed 

reporter-specific EFs or HHVs, report 

the following: 

(i) The specific industry standard(s) 

used to develop reporter-specific higher 

heating value(s) and/or emission 

factor(s), pursuant to § 98.404(b)(2) and 

(c)(3). 

(ii) The developed HHV(s). 

(iii) The developed EF(s). 


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(b) In addition to the information 

required by § 98.3(c), the annual report 

for each LDC shall contain the following 

information. 

(1) Annual volume in Mscf of natural 

gas received by the LDC at its city gate 

stations for redelivery on the LDC’s 

distribution system, including for use by 

the LDC. 

(2) Annual volume in Mscf of natural 

gas placed into storage. 

(3) Annual volume in Mscf of 

vaporized liquefied natural gas (LNG) 

produced at on-system vaporization 

facilities for delivery on the distribution 

system that is not accounted for in 

paragraph (b)(1) of this section. 

(4) Annual volume in Mscf of natural 

gas withdrawn from on-system storage 

(that is not delivered to the city gate) for 

delivery on the distribution system. 

(5) Annual volume in Mscf of natural 

gas delivered directly to LDC systems 

from producers or natural gas 

processing plants from local production. 

(6) Annual volume in Mscf of natural 

gas delivered to downstream gas 

transmission pipelines and other local 

distribution companies. 

(7) Annual volume in Mscf of natural 

gas delivered by LDC to each meter 

registering supply equal to or greater 

than 460,000 Mcsf during the calendar 

year. 

(8) The total annual CO2 mass 

emissions (metric tons) associated with 

the volumes in paragraphs (b)(1) 

through (b)(7) of this section, calculated 

in accordance with § 98.403(a) and 

(b)(1) through (b)(3). 

(9) Annual CO2 emissions (metric 

tons) that would result from the 

complete combustion or oxidation of the 

annual supply of natural gas to endusers registering less than 460,000 Mcsf, 

calculated in accordance with 

§ 98.403(b)(4). 

(10) The specific industry standard 

used to develop the volume reported in 

paragraph (b)(1) of this section. 

(11) If the LDC developed reporterspecific EFs or HHVs, report the 

following: 

(i) The specific industry standard(s) 

used to develop reporter-specific higher 

heating value(s) and/or emission 

factor(s), pursuant to § 98.404 (b)(2) and 

(c)(3). 

(ii) The developed HHV(s). 

(iii) The developed EF(s). 

(12) The customer name, address, and 

meter number of each meter reading 

used to report in paragraph (b)(7) of this 

section. 

(i) If known, report the EIA 

identification number of each LDC 

customer. 

(ii) [Reserved] 

(13) The annual volume in Mscf of 

natural gas delivered by the local 

distribution company to each of the 

following end-use categories. For 

definitions of these categories, refer to 

EIA Form 176 (Annual Report of Natural 

Gas and Supplemental Gas Supply & 

Disposition) and Instructions. 

(i) Residential consumers. 

(ii) Commercial consumers. 

(iii) Industrial consumers. 

(iv) Electricity generating facilities. 

(c) Each reporter shall report the 

number of days in the reporting year for 

which substitute data procedures were 

used for the following purpose: 

(1) To measure quantity. 

(2) To develop HHV(s). 

(3) To develop EF(s). 

§ 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 and 

showing the calculations of the values 

used for the missing data. 

(c) Calculations and worksheets used 

to estimate CO2 emissions for the 

volumes reported under this part. 

(d) Records related to the large endusers identified in § 98.406(b)(6). 

(e) Records relating to measured Btu 

content or carbon content showing 

specific industry standards used to 

develop reporter-specific higher heating 

values and emission factors. 

(f) Records of such audits as required 

by Sarbanes Oxley regulations on the 

accuracy of measurements of volumes of 

natural gas and NGLs delivered to 

customers or on behalf of customers. 

§ 98.408 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

TABLE NN–1 TO SUBPART NN OF PART 98—DEFAULT FACTORS FOR CALCULATION METHODOLOGY 1 OF THIS SUBPART

Fuel Default high heating value factor 

Default CO2

emission 

factor 

(kg CO2/ 

MMBtu) 

Natural Gas .................................................................................. 1.027 MMBtu/Mscf ........................................................................ 53.02 

Propane ........................................................................................ 3.836 MMBtu/bbl .......................................................................... 63.02 

Normal butane .............................................................................. 4.326 MMBtu/bbl .......................................................................... 64.93 

Ethane .......................................................................................... 3.082 MMBtu/bbl .......................................................................... 59.58 

Isobutane ...................................................................................... 3.974 MMBtu/bbl .......................................................................... 65.08 

Pentanes plus ............................................................................... 4.620 MMBtu/bbl .......................................................................... 66.90 

TABLE NN–2 TO SUBPART NN OF PART 98—LOOKUP DEFAULT VALUES FOR CALCULATION METHODOLOGY 2 OF THIS

SUBPART

Fuel Unit 

Default CO2

emission 

value 

(MT CO2/ 

Unit) 

Natural Gas .................................................................................. Mscf .............................................................................................. 0.054452 

Propane ........................................................................................ Barrel ............................................................................................ 0.241745 

Normal butane .............................................................................. Barrel ............................................................................................ 0.280887 

Ethane .......................................................................................... Barrel ............................................................................................ 0.183626 

Isobutane ...................................................................................... Barrel ............................................................................................ 0.258628 


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TABLE NN–2 TO SUBPART NN OF PART 98—LOOKUP DEFAULT VALUES FOR CALCULATION METHODOLOGY 2 OF THIS

SUBPART—Continued 

Fuel Unit 

Default CO2

emission 

value 

(MT CO2/ 

Unit) 

Pentanes plus ............................................................................... Barrel ............................................................................................ 0.309078 

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 GHG 

includes the manufacture of a 

fluorinated GHG for use in a process 

that will result in its transformation 

either at or outside of the production 

facility. Producing a fluorinated GHG 

also includes the creation of a 

fluorinated GHG (with the exception of 

HFC–23) that is captured and shipped 

off site for any reason, including 

destruction. Producing a fluorinated 

GHG does not include the reuse or 

recycling of a fluorinated GHG, the 

creation of HFC–23 during the 

production of HCFC–22, or the creation 

of by-products that are released or 

destroyed at the production facility. 

(c) To produce nitrous oxide means to 

produce nitrous oxide by thermally 

decomposing ammonium nitrate 

(NH4NO3). Producing nitrous oxide does 

not include the reuse or recycling of 

nitrous oxide or the creation of 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) Calculate the total mass of each 

fluorinated GHG or nitrous oxide 

produced annually, except for amounts 

that are captured solely to be shipped 

off site for destruction, by using 

Equation OO–1 of this section: 

P Pp

p

n

=

=

∑

1

( . Eq OO-1)

P = Mass of fluorinated GHG or nitrous oxide 

produced annually. 

Pp = Mass of fluorinated GHG or nitrous 

oxide produced over the period ‘‘p’’. 

(b) Calculate the total mass of each 

fluorinated GHG or nitrous oxide 

produced over the period ‘‘p’’ by using 

Equation OO–2 of this section: 

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) Calculate the total mass of each 

fluorinated GHG or nitrous oxide 

transformed by using Equation OO–3 of 

this section: 

T=FT ∗ ET ( . 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). 

ET = The fraction of the fluorinated GHG 

or nitrous oxide fed into the 

transformation process that is 

transformed in the process (metric 

tons). 

(d) Calculate the total mass of each 

fluorinated GHG destroyed by using 

Equation OO–4 of this section: 

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 

using flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of one percent of full scale or 

better. 

(b) The mass of any used fluorinated 

GHGs or used nitrous oxide added back 

into the production process upstream of 

the output measurement in paragraph 

(a) of this section shall be measured 

using flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of one percent of full scale or 

better. If the mass in paragraph (a) of 

this section is measured by weighing 

containers that include returned heels 

as well as newly produced fluorinated 

GHGs, the returned heels shall be 

considered used fluorinated GHGs for 

purposes of this paragraph (b) of this 

section and § 98.413(b). 

(c) The mass of fluorinated GHGs or 

nitrous oxide fed into the 

transformation process shall be 

measured using flowmeters, weigh 

scales, or a combination of volumetric 

and density measurements with an 

accuracy and precision of one percent of 

full scale or better. 

(d) The fraction of the fluorinated 

GHGs or nitrous oxide fed into the 

transformation process that is actually 

transformed shall be estimated 

considering yield calculations or 

quantities of unreacted fluorinated 

GHGs or nitrous oxide permanently 

removed from the process and 

recovered, destroyed, or emitted. 

(e) The mass of fluorinated GHG or 

nitrous oxide sent to another facility for 

transformation shall be measured using 

flowmeters, weigh scales, or a 

combination of volumetric and density 

measurements with an accuracy and 

precision of one percent of full scale or 

better. 


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(f) The mass of fluorinated GHG sent 

to another facility for destruction shall 

be measured using flowmeters, weigh 

scales, or a combination of volumetric 

and density measurements with an 

accuracy and precision of one percent of 

full scale or better. If the measured mass 

includes more than trace concentrations 

of materials other than the fluorinated 

GHG, the concentration of the 

fluorinated GHG shall be estimated 

considering current or previous 

representative concentration 

measurements and other relevant 

process information. This concentration 

(mass fraction) shall be multiplied by 

the mass measurement to obtain the 

mass of the fluorinated GHG sent to 

another facility for destruction. 

(g) You must estimate the share of the 

mass of fluorinated GHGs in paragraph 

(f) of this section that is comprised of 

fluorinated GHGs that are not included 

in the mass produced in § 98.413(a) 

because they are removed from the 

production process as by-products or 

other wastes. 

(h) The mass of fluorinated GHGs fed 

into the destruction device shall be 

measured using flowmeters, weigh 

scales, or a combination of volumetric 

and density measurements with an 

accuracy and precision of one percent of 

full scale or better. If the measured mass 

includes more than trace concentrations 

of materials other than the fluorinated 

GHG being destroyed, the 

concentrations of fluorinated GHG being 

destroyed shall be estimated 

considering current or previous 

representative concentration 

measurements and other relevant 

process information. This concentration 

(mass fraction) shall be multiplied by 

the mass measurement to obtain the 

mass of the fluorinated GHG destroyed. 

(i) Very small quantities of fluorinated 

GHGs that are difficult to measure 

because they are entrained in other 

media such as destroyed filters and 

destroyed sample containers are exempt 

from paragraphs (f) and (h) of this 

section. 

(j) You must estimate the share of the 

mass of fluorinated GHGs in paragraph 

(h) of this section that is comprised of 

fluorinated GHGs that are not included 

in the mass produced in § 98.413(a) 

because they are removed from the 

production process as by-products or 

other wastes. 

(k) For purposes of Equation OO–4 of 

this subpart, the destruction efficiency 

can be equated to the destruction 

efficiency determined during a previous 

performance test of the destruction 

device or, if no performance test has 

been done, the destruction efficiency 

provided by the manufacturer of the 

destruction device. 

(l) In their estimates of the mass of 

fluorinated GHGs destroyed, fluorinated 

GHG production facilities that destroy 

fluorinated GHGs shall account for any 

temporary reductions in the destruction 

efficiency that result from any startups, 

shutdowns, or malfunctions of the 

destruction device, including departures 

from the operating conditions defined in 

state or local permitting requirements 

and/or oxidizer manufacturer 

specifications. 

(m) Calibrate all flow meters, weigh 

scales, and combinations of volumetric 

and density measures that are used to 

measure or calculate quantities that are 

to be reported under this subpart prior 

to the first year for which GHG 

emissions are reported under this part. 

Calibrations performed prior to the 

effective date of this rule satisfy this 

requirement. Recalibrate all flow meters, 

weigh scales, and combinations of 

volumetric and density measures at the 

minimum frequency specified by the 

manufacturer. Use NIST-traceable 

standards and suitable methods 

published by a consensus standards 

organization (e.g., ASTM, ASME, ISO, 

or others). 

§ 98.415 Procedures for estimating 

missing data. 

(a) A complete record of all measured 

parameters used in the GHG emissions 

calculations is required. Therefore, 

whenever a quality-assured value of a 

required parameter is unavailable (e.g., 

if a meter malfunctions), a substitute 

data value for the missing parameter 

shall be used in the calculations, 

according to paragraph (b) of this 

section. 

(b) For each missing value of the mass 

produced, fed into the production 

process (for used material being 

reclaimed), fed into the transformation 

process, fed into destruction devices, 

sent to another facility for 

transformation, or sent to another 

facility for destruction, the substitute 

value of that parameter shall be a 

secondary mass measurement where 

such a measurement is available. For 

example, if the mass produced is 

usually measured with a flowmeter at 

the inlet to the day tank and that 

flowmeter fails to meet an accuracy or 

precision test, malfunctions, or is 

rendered inoperable, then the mass 

produced may be estimated by 

calculating the change in volume in the 

day tank and multiplying it by the 

density of the product. Where a 

secondary mass measurement is not 

available, the substitute value of the 

parameter shall be an estimate based on 

a related parameter. For example, if a 

flowmeter measuring the mass fed into 

a destruction device is rendered 

inoperable, then the mass fed into the 

destruction device may be estimated 

using the production rate and the 

previously observed relationship 

between the production rate and the 

mass flow rate into the destruction 

device. 

§ 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: 

(1) Mass in metric tons of each 

fluorinated GHG or nitrous oxide 

produced at that facility by process, 

except for amounts that are captured 

solely to be shipped off site for 

destruction. 

(2) Mass in metric tons of each 

fluorinated GHG or nitrous oxide 

transformed at that facility, by process. 

(3) Mass in metric tons of each 

fluorinated GHG destroyed at that 

facility, except fluorinated GHGs not 

included in the calculation of mass 

produced in § 98.413(a) because they are 

removed from the production process as 

by-products or other wastes. Quantities 

to be reported under this paragraph 

(a)(3) of this section could include, for 

example, quantities that are returned to 

the facility for reclamation but are found 

to be irretrievably contaminated and are 

therefore destroyed. 

(4) Mass in metric tons of each 

fluorinated GHG that is destroyed at that 

facility except GHGs not included in the 

calculation of mass produced in 

§ 98.413(a) because they are removed 

from the production process as 

byproducts or other wastes. 

(5) Total mass in metric tons of each 

fluorinated GHG or nitrous oxide sent to 

another facility for transformation. 

(6) Total mass in metric tons of each 

fluorinated GHG sent to another facility 

for destruction, except fluorinated GHGs 

that are not included in the mass 

produced in § 98.413(a) because they are 

removed from the production process as 

by-products or other wastes. Quantities 

to be reported under this paragraph 

(a)(6) could include, for example, 

fluorinated GHGs that are returned to 

the facility for reclamation but are found 

to be irretrievably contaminated and are 

therefore sent to another facility for 

destruction. 

(7) Total mass in metric tons of each 

fluorinated GHG that is sent to another 

facility for destruction and that is not 

included in the mass produced in 

§ 98.413(a) because it is removed from 


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the production process as a byproduct 

or other waste. 

(8) Total mass in metric tons of each 

reactant fed into the F–GHG or nitrous 

oxide production process, by process. 

(9) Total mass in metric tons of the 

reactants, by-products, and other wastes 

permanently removed from the F–GHG 

or nitrous oxide production process, by 

process. 

(10) For transformation processes that 

do not produce an F–GHG or nitrous 

oxide, mass in metric tons of any 

fluorinated GHG or nitrous oxide fed 

into the transformation process, by 

process. 

(11) Mass in metric tons of each 

fluorinated GHG fed into the destruction 

device. 

(12) Mass in metric tons of each 

fluorinated GHG or nitrous oxide that is 

measured coming out of the production 

process, by process. 

(13) Mass in metric tons of each used 

fluorinated GHGs or nitrous oxide 

added back into the production process 

(e.g., for reclamation), including 

returned heels in containers that are 

weighed to measure the mass in 

§ 98.414(a), by process. 

(14) Names and addresses of facilities 

to which any nitrous oxide or 

fluorinated GHGs were sent for 

transformation, and the quantities 

(metric tons) of nitrous oxide and of 

each fluorinated GHG that were sent to 

each for transformation. 

(15) Names and addresses of facilities 

to which any fluorinated GHGs were 

sent for destruction, and the quantities 

(metric tons) of nitrous oxide and of 

each fluorinated GHG that were sent to 

each for destruction. 

(16) Where missing data have been 

estimated pursuant to § 98.415, the 

reason the data were missing, the length 

of time the data were missing, the 

method used to estimate the missing 

data, and the estimates of those data. 

(b) A fluorinated GHG production 

facility or importer that destroys 

fluorinated GHGs shall submit a onetime report containing the following 

information: 

(1) Destruction efficiency (DE) of each 

destruction unit. 

(2) Methods used to determine the 

destruction efficiency. 

(3) Methods used to record the mass 

of fluorinated GHG destroyed. 

(4) Chemical identity of the 

fluorinated GHG(s) used in the 

performance test conducted to 

determine DE. 

(5) Name of all applicable federal or 

state regulations that may apply to the 

destruction process. 

(6) If any process changes affect unit 

destruction efficiency or the methods 

used to record mass of fluorinated GHG 

destroyed, then a revised report must be 

submitted to reflect the changes. The 

revised report must be submitted to EPA 

within 60 days of the change. 

(c) A bulk importer of fluorinated 

GHGs or nitrous oxide shall submit an 

annual report that summarizes their 

imports at the corporate level, except for 

shipments including less than 250 

metric tons of CO2e, transshipments, 

and heels that meet the conditions set 

forth at § 98.417(e). The report shall 

contain the following information for 

each import: 

(1) Total mass in metric tons of 

nitrous oxide and each fluorinated GHG 

imported in bulk. 

(2) Total mass in metric tons of 

nitrous oxide and each fluorinated GHG 

imported in bulk and sold or transferred 

to persons other than the importer for 

use in processes resulting in the 

transformation or destruction of the 

chemical. 

(3) Date on which the fluorinated 

GHGs or nitrous oxide were imported. 

(4) Port of entry through which the 

fluorinated GHGs or nitrous oxide 

passed. 

(5) Country from which the imported 

fluorinated GHGs or nitrous oxide were 

imported. 

(6) Commodity code of the fluorinated 

GHGs or nitrous oxide shipped. 

(7) Importer number for the shipment. 

(8) Total mass in metric tons of each 

fluorinated GHG destroyed by the 

importer. 

(9) If applicable, the names and 

addresses of the persons and facilities to 

which the nitrous oxide or fluorinated 

GHGs were sold or transferred for 

transformation, and the quantities 

(metric tons) of nitrous oxide and of 

each fluorinated GHG that were sold or 

transferred to each facility for 

transformation. 

(10) If applicable, the names and 

addresses of the persons and facilities to 

which the nitrous oxide or fluorinated 

GHGs were sold or transferred for 

destruction, and the quantities (metric 

tons) of nitrous oxide and of each 

fluorinated GHG that were sold or 

transferred to each facility for 

destruction. 

(d) A bulk exporter of fluorinated 

GHGs or nitrous oxide shall submit an 

annual report that summarizes their 

exports at the corporate level, except for 

shipments including less than 250 

metric tons of CO2e, transshipments, 

and heels. The report shall contain the 

following information for each export: 

(1) Total mass in metric tons of 

nitrous oxide and each fluorinated GHG 

exported in bulk. 

(2) Names and addresses of the 

exporter and the recipient of the 

exports. 

(3) Exporter’s Employee Identification 

Number. 

(4) Commodity code of the fluorinated 

GHGs and nitrous oxide shipped. 

(5) Date on which, and the port from 

which, fluorinated GHGs and nitrous 

oxide were exported from the United 

States or its territories. 

(6) Country to which the fluorinated 

GHGs or nitrous oxide were exported. 

(e) By April 1, 2011, a fluorinated 

GHG production facility shall submit a 

one-time report describing the following 

information: 

(1) The method(s) by which the 

producer in practice measures the mass 

of fluorinated GHGs produced, 

including the instrumentation used 

(Coriolis flowmeter, other flowmeter, 

weigh scale, etc.) and its accuracy and 

precision. 

(2) The method(s) by which the 

producer in practice estimates the mass 

of fluorinated GHGs fed into the 

transformation process, including the 

instrumentation used (Coriolis 

flowmeter, other flowmeter, weigh 

scale, etc.) and its accuracy and 

precision. 

(3) The method(s) by which the 

producer in practice estimates the 

fraction of fluorinated GHGs fed into the 

transformation process that is actually 

transformed, and the estimated 

precision and accuracy of this estimate. 

(4) The method(s) by which the 

producer in practice estimates the 

masses of fluorinated GHGs fed into the 

destruction device, including the 

method(s) used to estimate the 

concentration of the fluorinated GHGs 

in the destroyed material, and the 

estimated precision and accuracy of this 

estimate. 

(5) The estimated percent efficiency of 

each production process for the 

fluorinated GHG produced. 

§ 98.417 Records that must be retained. 

(a) In addition to the data required by 

§ 98.3(g), the fluorinated GHG 

production facility shall retain the 

following records: 

(1) Dated records of the data used to 

estimate the data reported under 

§ 98.416. 

(2) Records documenting the initial 

and periodic calibration of the gas 

chromatographs, weigh scales, 

flowmeters, and volumetric and density 

measures used to measure the quantities 

reported under this subpart, including 

the industry standards or manufacturer 

directions used for calibration pursuant 

to § 98.414(j) and (k). 

(b) In addition to the data required by 

paragraph (a) of this section, the 


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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 (e). 

(c) In addition to the data required by 

§ 98.3(g), the bulk importer shall retain 

the following records substantiating 

each of the imports that they report: 

(1) A copy of the bill of lading for the 

import. 

(2) The invoice for the import. 

(3) The U.S. Customs entry form. 

(d) In addition to the data required by 

§ 98.3(g), the bulk exporter shall retain 

the following records substantiating 

each of the exports that they report: 

(1) A copy of the bill of lading for the 

export and 

(2) The invoice for the import. 

(e) Every person who imports a 

container with a heel that is not 

reported under § 98.416(c) shall keep 

records of the amount brought into the 

United States that document that the 

residual amount in each shipment is 

less than 10 percent of the volume of the 

container and will: 

(1) Remain in the container and be 

included in a future shipment. 

(2) Be recovered and transformed. 

(3) Be recovered and destroyed. 

(4) Be recovered and included in a 

future shipment. 

§ 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) Facilities with production process 

units that capture a CO2 stream for 

purposes of supplying CO2 for 

commercial applications or that capture 

and maintain custody of a CO2 stream 

in order to sequester or otherwise inject 

it underground. Capture refers to the 

initial separation and removal of CO2

from a manufacturing process or any 

other process. 

(2) Facilities with CO2 production 

wells that extract or produce a CO2

stream for purposes of supplying CO2

for commercial applications or that 

extract and maintain custody of a CO2

stream in order to sequester or 

otherwise inject it underground. 

(3) Importers or exporters of bulk CO2. 

(b) This source category is focused on 

upstream supply. It does not cover: 

(1) Storage of CO2 above ground or in 

geologic formations. 

(2) Use of CO2 in enhanced oil and gas 

recovery. 

(3) Transportation or distribution of 

CO2. 

(4) Purification, compression, or 

processing of CO2. 

(5) On-site use of CO2 captured on 

site. 

(c) This source category does not 

include CO2 imported or exported in 

equipment, such as fire extinguishers. 

§ 98.421 Reporting threshold. 

Any supplier of CO2 who meets the 

requirements of § 98.2(a)(4) of subpart A 

of this part must report the mass of CO2

captured, extracted, imported, or 

exported. 

§ 98.422 GHGs to report. 

(a) Mass of CO2 captured from each 

production process unit. 

(b) Mass of CO2 extracted from each 

CO2 production wells. 

(c) Mass of CO2 imported. 

(d) Mass of CO2 exported. 

§ 98.423 Calculating CO2 supply. 

(a) Calculate the annual mass of CO2

captured, extracted, imported, or 

exported through each flow meter in 

accordance with the procedures 

specified in either paragraph (a)(1) or 

(a)(2) of this section. If multiple flow 

meters are used, you shall calculate the 

annual mass of CO2 for all flow meters 

according to the procedures specified in 

paragraph (a)(3) of this section. 

(1) For each mass flow meter, you 

shall calculate quarterly the mass of CO2

in a CO2 stream in metric tons, prior to 

any subsequent purification, processing, 

or compressing, by multiplying the mass 

flow by the composition data, according 

to Equation PP–1 of this section. Mass 

flow and composition data 

measurements shall be made in 

accordance with § 98.424 of this 

subpart. 

CO Eq 2 u

1

4

2 , , = ∗ ( .

=

∑ Q C p,u CO

p p,u PP-1)

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

through flow meter u. 

CCO2,p,u = Quarterly CO2 concentration 

measurement in flow for flow meter u in 

quarter p (wt. %CO2). 

Qp,u = Quarterly mass flow rate measurement 

for flow meter u in quarter p (metric 

tons). 

p = Quarter of the year. 

u = Flow meter. 

(2) For each volumetric flow meter, 

you shall calculate quarterly the mass of 

CO2 in a CO2 stream in metric tons, 

prior to any subsequent purification, 

processing, or compressing, by 

multiplying the volumetric flow by the 

concentration and density data, 

according to Equation PP–2 of this 

section. Volumetric flow, concentration 

and density data measurements shall be 

made in accordance with § 98.424 of 

this section. 

CO Eq 2 u

1

4

2 2 , , = ∗∗ ( .

=

∑ Q C p CO

p p Dp PP- )

Where: 

CO2,u = Annual mass of CO2 (metric tons) 

through flow meter u. 

CCO2,p = Quarterly CO2 concentration 

measurement in flow for flow meter u in 

quarter p (wt. % CO2). 

Qp = Quarterly volumetric flow rate 

measurement for flow meter u in quarter 

p (standard cubic meters). 

Dp = Quarterly CO2 stream density 

measurement for flow meter u in quarter 

p (metric tons per standard cubic meter). 

p = Quarter of the year. 

u = Flow meter. 

(3) To aggregate data, sum the mass of 

CO2 for all flow meters in accordance 

with Equation PP–3 of this section. 


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CO CO Eq u

U

2 2

1

= 3

=

∑ , ( . PP- )

p

Where: 

CO2 = Annual mass of CO2 (metric tons) 

through all flow meters. 

CO2,u = Annual mass of CO2 (metric tons) 

through flow meter u. 

u = Flow meter. 

(b) Importers or exporters that import 

or export CO2 in containers shall 

calculate the total mass of CO2 imported 

or exported in metric tons, prior to any 

subsequent purification, processing, or 

compressing, based on summing the 

mass in each CO2 container using weigh 

bills, scales, or load cells according to 

Equation PP–4 of this section. 

CO Eq 2

1

= 4

=

∑ Q

p

I

( . PP- )

Where: 

CO2 = Annual mass of CO2 (metric tons). 

Q = Annual mass in all CO2 containers 

imported or exported during the 

reporting year (metric tons). 

§ 98.424 Monitoring and QA/QC 

requirements. 

(a) Determination of quantity. 

(1) Reporters that have a mass flow 

meter or volumetric flow meter installed 

to measure the flow of a CO2 stream 

shall base calculations in § 98.423 of 

this subpart on the installed mass flow 

or volumetric flow meters. 

(2) Reporters that do not have a mass 

flow meter or volumetric flow meter 

installed to measure the flow of the CO2

stream shall base calculations in 

§ 98.423 of this subpart on the flow of 

gas transferred off site using a mass flow 

meter or a volumetric flow meter 

located at the point of off-site transfer. 

(3) Importers or exporters that import 

or export CO2 in containers shall 

measure the mass in each CO2 container 

using weigh bills, scales, or load cells 

and sum the mass in all containers 

imported or exported during the 

reporting year. 

(4) All flow meters, scales, and load 

cells used to measure quantities that are 

reported in § 98.423 of this subpart shall 

be operated and calibrated according to 

the following procedure: 

(i) You shall use an appropriate 

standard method published by a 

consensus-based standards organization 

if such a method exists. Consensusbased standards organizations include, 

but are not limited to, the following: 

ASTM International, the American 

National Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(ii) Where no appropriate standard 

method developed by a consensus-based 

standards organization exists, you shall 

follow industry standard practices. 

(iii) You must ensure that any flow 

meter calibrations performed are NIST 

traceable. 

(5) Reporters using Equation PP–2 of 

this subpart shall measure the density of 

the CO2 stream on a quarterly basis in 

order to calculate the mass of the CO2

stream according to the following 

procedure: 

(i) You shall use an appropriate 

standard method published by a 

consensus-based standards organization 

to measure density if such a method 

exists. Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International, the American National 

Standards Institute (ANSI), the 

American Gas Association (AGA), the 

American Society of Mechanical 

Engineers (ASME), the American 

Petroleum Institute (API), and the North 

American Energy Standards Board 

(NAESB). 

(ii) Where no appropriate standard 

method developed by a consensus-based 

standards organization exists, you shall 

follow industry standard practices. 

(b) Determination of concentration. 

(1) Reporters using Equation PP–1 or 

PP–2 of this subpart shall sample the 

CO2 stream on a quarterly basis to 

determine the composition of the CO2

stream. 

(2) Methods to measure the 

composition of the CO2 stream must 

conform to applicable chemical 

analytical standards. Acceptable 

methods include U.S. Food and Drug 

Administration food-grade 

specifications for CO2 (see 21 CFR 

184.1250) and ASTM standard E1747– 

95 (Reapproved 2005) Standard Guide 

for Purity of Carbon Dioxide Used in 

Supercritical Fluid Applications 

(incorporated by reference, see § 98.7 of 

subpart A of this part). 

§ 98.425 Procedures for estimating 

missing data. 

(a) Whenever the quality assurance 

procedures in § 98.424(a) of this subpart 

cannot be followed to measure quarterly 

mass flow or volumetric flow of CO2, 

the most appropriate of the following 

missing data procedures shall be 

followed: 

(1) A quarterly CO2 mass flow or 

volumetric flow value that is missing 

may be substituted with a quarterly 

value measured during another quarter 

of the current reporting year. 

(2) A quarterly CO2 mass flow or 

volumetric flow value that is missing 

may be substituted with a quarterly 

value measured during the same quarter 

from the past reporting year. 

(3) If a mass or volumetric flow meter 

is installed to measure the CO2 stream, 

you may substitute data from a mass or 

volumetric flow meter measuring the 

CO2 stream transferred for any period 

during which the installed meter is 

inoperable. 

(4) The mass or volumetric flow used 

for purposes of product tracking and 

billing according to the reporter’s 

established procedures may be 

substituted for any period during which 

measurement equipment is inoperable. 

(b) Whenever the quality assurance 

procedures in § 98.424(b) of this subpart 

cannot be followed to determine 

concentration of the CO2 stream, the 

most appropriate of the following 

missing data procudures shall be 

followed: 

(1) A quarterly concentration value 

that is missing may be substituted with 

a quarterly value measured during 

another quarter of the current reporting 

year. 

(2) A quarterly concentration value 

that is missing may be substituted with 

a quarterly value measured during the 

same quarter from the previous 

reporting year. 

(3) The concentration used for 

purposes of product tracking and billing 

according to the reporter’s established 

procedures may be substituted for any 

quarterly value. 

(c) Missing data on density of the CO2

stream shall be substituted with 

quarterly or annual average values from 

the previous calendar year. 

§ 98.426 Data reporting requirements. 

In addition to the information 

required by § 98.3(c) of subpart A of this 

part, the annual report shall contain the 

following information, as applicable: 

(a) If you use Equation PP–1 of this 

subpart, report the following 

information for each mass flow meter: 

(1) Annual mass in metric tons of CO2.

(2) Quarterly mass flow of CO2.

(3) Quarterly concentration of the CO2

stream. 

(4) The standard used to measure CO2

concentration. 

(b) If you use Equation PP–2 of this 

subpart, report the following 

information for each volumetric flow 

meter: 

(1) Annual mass in metric tons of CO2.

(2) Quarterly volumetric flow of CO2.

(3) Quarterly concentration of the CO2

stream. 

(4) Quarterly density of the CO2

stream. 


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(5) The method used to measure 

density. 

(6) The standard used to measure CO2

concentration. 

(c) If you use Equation PP–3 of this 

subpart, report the annual CO2 mass in 

metric tons from all flow meters. 

(d) If you use Equation PP–4 of this 

subpart, report at the corporate level the 

annual mass of CO2 in metric tons in all 

CO2 containers that are imported or 

exported. 

(e) Each reporter shall report the 

following information: 

(1) The type of equipment used to 

measure the total flow of the CO2 stream 

or the total mass in CO2 containers. 

(2) The standard used to operate and 

calibrate the equipment reported in 

(e)(1) of this section. 

(3) The number of days in the 

reporting year for which substitute data 

procedures were used for the following 

purpose: 

(i) To measure quantity. 

(ii) To measure concentration. 

(iii) To measure density. 

(f) Report the aggregated annual 

quantity of CO2 in metric tons that is 

transferred to each of the following end 

use applications, if known: 

(1) Food and beverage. 

(2) Industrial and municipal water/ 

wastewater treatment. 

(3) Metal fabrication, including 

welding and cutting. 

(4) Greenhouse uses for plant growth. 

(5) Fumigants (e.g., grain storage) and 

herbicides. 

(6) Pulp and paper. 

(7) Cleaning and solvent use. 

(8) Fire fighting. 

(9) Transportation and storage of 

explosives. 

(10) Enhanced oil and natural gas 

recovery. 

(11) Long-term storage (sequestration). 

(12) Research and development. 

(13) Other. 

(g) Each production process unit that 

captures a CO2 stream for purposes of 

supplying CO2 for commercial 

applications or in order to sequester or 

otherwise inject it underground when 

custody of the CO2 is maintained shall 

report the percentage of that stream, if 

any, that is biomass-based during the 

reporting year. 

§ 98.427 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 (c) of this 

section, as applicable. 

(a) The owner or operator of a facility 

containing production process units 

must retain quarterly records of 

captured or transferred CO2 streams and 

composition. 

(b) The owner or operator of a CO2

production well facility must maintain 

quarterly records of the mass flow or 

volumetric flow of the extracted or 

transferred CO2 stream and 

concentration and density if volumetric 

flow meters are used. 

(c) Importers or exporters of CO2 must 

retain annual records of the mass flow, 

volumetric flow, and mass of CO2

imported or exported. 

§ 98.428 Definitions. 

All terms used in this subpart have 

the same meaning given in the Clean Air 

Act and subpart A of this part. 

PART 1033—[AMENDED] 

■ 21. The authority citation for part 

1033 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 22. 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) Report measured CO2, N2O, and 

CH4 as described in § 1033.235. Small 

manufacturers/remanufacturers may 

omit reporting N2O and CH4. 

* * * * * 

■ 23. Section 1033.235 is amended by 

adding paragraph (i) to read as follows: 

§ 1033.235 Emission testing required for 

certification. 

* * * * * 

(i) Measure CO2 with each test. 

Measure CH4 with each low-hour 

certification test using the procedures 

specified in 40 CFR part 1065 starting in 

the 2012 model year. Also measure N2O 

with each low-hour certification test 

using the procedures specified in 40 

CFR part 1065 for any engine family that 

depends on NOx aftertreatment to meet 

emission standards. Small 

manufacturers/remanufacturers may 

omit measurement of N2O and CH4. Use 

the same units and modal calculations 

as for your other results to report a 

single weighted value for CO2, N2O, and 

CH4. Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/bhp– 

hr. 

(2) Round N2O to the nearest 0.001 g/ 

bhp–hr. 

(3) Round CH4 to the nearest 0.001g/ 

bhp–hr. 

Subpart F—[Amended] 

■ 24. Section 1033.501 is amended by 

revising paragraph (a) introductory text 

to read as follows: 

§ 1033.501 General provisions. 

(a) Except as specified in this subpart, 

use the equipment and procedures for 

compression-ignition engines in 40 CFR 

part 1065 to determine whether your 

locomotives meet the duty-cycle 

emission standards in § 1033.101. Use 

the applicable duty cycles specified in 

this subpart. Measure emissions of all 

the pollutants we regulate in § 1033.101 

plus CO2. Measure N2O, and CH4 as 

described in § 1033.235. The general test 

procedure is the procedure specified in 

40 CFR part 1065 for steady-state 

discrete-mode cycles. However, if you 

use the optional ramped modal cycle in 

§ 1033.520, follow the procedures for 

ramped modal testing in 40 CFR part 

1065. The following exceptions from the 

1065 procedures apply: 

* * * * * 

Subpart J—[Amended] 

■ 25. 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] 

■ 26. The authority citation for part 

1039 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 27. 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 


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procedures of subpart F of this part. We 

may ask you to send other information 

to confirm that your tests were valid 

under the requirements of this part and 

40 CFR part 1065. 

(2) Report measured CO2, N2O, and 

CH4 as described in § 1039.235. Smallvolume engine manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 28. 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) Measure CO2 and CH4 with each 

low-hour certification test using the 

procedures specified in 40 CFR part 

1065 in the 2011 and 2012 model years, 

respectively. Also measure N2O with 

each low-hour certification test using 

the procedures specified in 40 CFR part 

1065 starting in the 2013 model year for 

any engine family that depends on NOx 

aftertreatment to meet emission 

standards. Small-volume engine 

manufacturers may omit measurement 

of N2O and CH4. These measurements 

are not required for NTE testing. Use the 

same units and modal calculations as 

for your other results to report a single 

weighted value for each constituent. 

Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

(3) Round CH4 to the nearest 0.001g/ 

kW-hr. 

Subpart F—[Amended] 

■ 29. Section 1039.501 is amended by 

revising paragraph (a) to read as follows: 

§ 1039.501 How do I run a valid emission 

test? 

(a) Use the equipment and procedures 

for compression-ignition engines in 40 

CFR part 1065 to determine whether 

engines meet the duty-cycle emission 

standards in subpart B of this part. 

Measure the emissions of all the exhaust 

constituents subject to emissions 

standards as specified in 40 CFR part 

1065. Measure CO2, N2O, and CH4 as 

described in § 1039.235. Use the 

applicable duty cycles specified in 

§§ 1039.505 and 1039.510. 

* * * * * 

Subpart I—[Amended] 

■ 30. 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] 

■ 31. The authority citation for part 

1042 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 32. 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) Report measured CO2, N2O, and 

CH4 as described in § 1042.235. Smallvolume engine manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 33. Section 1042.235 is amended by 

adding paragraph (g) to read as follows: 

§ 1042.235 Emission testing required for a 

certificate of conformity. 

* * * * * 

(g) Measure CO2 with each low-hour 

certification test using the procedures 

specified in 40 CFR part 1065 starting in 

the 2011 model year. Also measure CH4

from Category 1 and Category 2 engines 

with each low-hour certification test 

using the procedures specified in 40 

CFR part 1065 starting in the 2012 

model year. Measure N2O from Category 

1 and Category 2 engines with each lowhour certification test using the 

procedures specified in 40 CFR part 

1065 for any engine family that depends 

on NOx aftertreatment to meet emission 

standards. Small-volume engine 

manufacturers may omit measurement 

of N2O and CH4. These measurements 

are not required for NTE testing. Use the 

same units and modal calculations as 

for your other results to report a single 

weighted value for each constituent. 

Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

(3) Round CH4 to the nearest 0.001 g/ 

kW-hr. 

Subpart F—[Amended] 

■ 34. Section 1042.501 is amended by 

revising paragraph (a) to read as follows: 

§ 1042.501 How do I run a valid emission 

test? 

(a) Use the equipment and procedures 

for compression-ignition engines in 40 

CFR part 1065 to determine whether 

Category 1 and Category 2 engines meet 

the duty-cycle emission standards in 

§ 1042.101(a). Measure the emissions of 

all exhaust constituents subject to 

emissions standards as specified in 40 

CFR part 1065. Measure CO2, N2O, and 

CH4 as described in § 1042.235. Use the 

applicable duty cycles specified in 

§ 1042.505. 

* * * * * 

Subpart J—[Amended] 

■ 35. 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] 

■ 36. The authority citation for part 

1045 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 37. 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. 


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(2) Report measured CO2, N2O, and 

CH4 as described in § 1045.235. Smallvolume engine manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 38. 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 and CH4 with each 

low-hour certification test using the 

procedures specified in 40 CFR part 

1065 starting in the 2011 and 2012 

model years, respectively. Also measure 

N2O with each low-hour certification 

test using the procedures specified in 40 

CFR part 1065 starting in the 2013 

model year for any engine family that 

depends on NOX aftertreatment to meet 

emission standards. Small-volume 

engine manufacturers may omit 

measurement of N2O and CH4. These 

measurements are not required for NTE 

testing. Use the same units and modal 

calculations as for your other results to 

report a single weighted value for each 

constituent. Round the final values as 

follows: 

(1) Round CO2 to the nearest 1 g/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

(3) Round CH4 to the nearest 0.001 g/ 

kW-hr. 

Subpart F—[Amended] 

■ 39. Section 1045.501 is amended by 

revising paragraph (b) to read as follows: 

§ 1045.501 How do I run a valid emission 

test? 

* * * * * 

(b) General requirements. Use the 

equipment and procedures for sparkignition engines in 40 CFR part 1065 to 

determine whether engines meet the 

duty-cycle emission standards in 

§§ 1045.103 and 1045.105. Measure the 

emissions of all exhaust constituents 

subject to emissions standards as 

specified in 40 CFR part 1065. Measure 

CO2, N2O, and CH4 as described in 

§ 1045.235. Use the applicable duty 

cycles specified in § 1045.505. Section 

1045.515 describes the supplemental 

procedures for evaluating whether 

engines meet the not-to-exceed emission 

standards in § 1045.107. 

* * * * * 

PART 1048—[AMENDED] 

■ 40. The authority citation for part 

1048 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 41. Section 1048.205 is amended by 

revising paragraph (s) to read as follows: 

§ 1048.205 What must I include in my 

application? 

* * * * * 

(s) Report test results as follows: 

(1) Report all test results involving 

measurement of pollutants for which 

emission standards apply. Include test 

results from invalid tests or from any 

other tests, whether or not they were 

conducted according to the test 

procedures of subpart F of this part. We 

may ask you to send other information 

to confirm that your tests were valid 

under the requirements of this part and 

40 CFR part 1065. 

(2) Report measured CO2, N2O, and 

CH4 as described in § 1048.235. Smallvolume engine manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 42. 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) Measure CO2 and CH4 with each 

low-hour certification test using the 

procedures specified in 40 CFR part 

1065 starting in the 2011 and 2012 

model years, respectively. Also measure 

N2O with each low-hour certification 

test using the procedures specified in 40 

CFR part 1065 starting in the 2013 

model year for any engine family that 

depends on NOx aftertreatment to meet 

emission standards. Small-volume 

engine manufacturers may omit 

measurement of N2O and CH4. These 

measurements are not required for 

measurements using field-testing 

procedures. Use the same units and 

modal calculations as for your other 

results to report a single weighted value 

for each constituent. Round the final 

values as follows: 

(1) Round CO2 to the nearest 1 g/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

(3) Round CH4 to the nearest 0.001g/ 

kW-hr. 

Subpart F—[Amended] 

■ 43. Section 1048.501 is amended by 

revising paragraph (a) to read as follows: 

§ 1048.501 How do I run a valid emission 

test? 

(a) Use the equipment and procedures 

for spark-ignition engines in 40 CFR 

part 1065 to determine whether engines 

meet the duty-cycle emission standards 

in § 1048.101(a) and (b). Measure the 

emissions of all the pollutants we 

regulate in § 1048.101 using the 

sampling procedures specified in 40 

CFR part 1065. Measure CO2, N2O, and 

CH4 as described in § 1048.235. Use the 

applicable duty cycles specified in 

§§ 1048.505 and 1048.510. 

* * * * * 

Subpart I—[Amended] 

■ 44. 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] 

■ 45. The authority citation for part 

1051 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 46. 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) Report measured CO2, N2O, and 

CH4 as described in § 1051.235. Smallvolume manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 47. 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) Measure CO2 and CH4 with each 

low-hour certification test using the 

procedures specified in 40 CFR part 

1065 starting in the 2011 and 2012 


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model years, respectively. Also measure 

N2O with each low-hour certification 

test using the analytical equipment and 

procedures specified in 40 CFR part 

1065 starting in the 2013 model year for 

any engine family that depends on NOx 

aftertreatment to meet emission 

standards. Small-volume manufacturers 

may omit measurement of N2O and CH4; 

other manufacturers may provide 

appropriate data and/or information and 

omit measurement of N2O and CH4 as 

described in 40 CFR 1065.5. Use the 

same units and modal calculations as 

for your other results to report a single 

weighted value for each constituent. 

Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/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 0.001 g/ 

kW-hr or 0.001 g/km, as appropriate. 

Subpart F—[Amended] 

■ 48. Section 1051.501 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 1051.501 What procedures must I use to 

test my vehicles or engines? 

* * * * * 

(a) Snowmobiles. For snowmobiles, 

use the equipment and procedures for 

spark-ignition engines in 40 CFR part 

1065 to determine whether your 

snowmobiles meet the duty-cycle 

emission standards in § 1051.103. 

Measure the emissions of all the 

pollutants we regulate in § 1051.103. 

Measure CO2, N2O, and CH4 as 

described in § 1051.235. Use the duty 

cycle specified in § 1051.505. 

(b) Motorcycles and ATVs. For 

motorcycles and ATVs, use the 

equipment, procedures, and duty cycle 

in 40 CFR part 86, subpart F, to 

determine whether your vehicles meet 

the exhaust emission standards in 

§ 1051.105 or § 1051.107. Measure the 

emissions of all the pollutants we 

regulate in § 1051.105 or § 1051.107. 

Measure CO2, N2O, and CH4 as 

described in § 1051.235. If we allow you 

to certify ATVs based on engine testing, 

use the equipment, procedures, and 

duty cycle described or referenced in 

the section that allows engine testing. 

For motorcycles with engine 

displacement at or below 169 cc and all 

ATVs, use the driving schedule in 

paragraph (c) of appendix I to 40 CFR 

part 86. For all other motorcycles, use 

the driving schedule in paragraph (b) of 

Appendix I to part 86. With respect to 

vehicle-speed governors, test 

motorcycles and ATVs in their 

ungoverned configuration, unless we 

approve in advance testing in a 

governed configuration. We will only 

approve testing in a governed 

configuration if you can show that the 

governor is permanently installed on all 

production vehicles and is unlikely to 

be removed in use. With respect to 

engine-speed governors, test 

motorcycles and ATVs in their governed 

configuration. Run the test engine, with 

all emission-control systems operating, 

long enough to stabilize emission levels; 

you may consider emission levels stable 

without measurement if you accumulate 

12 hours of operation. 

* * * * * 

Subpart I—[Amended] 

■ 49. 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] 

■ 50. The authority citation for part 

1054 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart C—[Amended] 

■ 51. 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) Report measured CO2, N2O, and 

CH4 as described in § 1054.235. Smallvolume engine manufacturers may omit 

reporting N2O and CH4. 

* * * * * 

■ 52. 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 and CH4 with each 

low-hour certification test using the 

procedures specified in 40 CFR part 

1065 starting in the 2011 and 2012 

model years, respectively. Also measure 

N2O with each low-hour certification 

test using the procedures specified in 40 

CFR part 1065 starting in the 2013 

model year for any engine family that 

depends on NOx aftertreatment to meet 

emission standards. Small-volume 

engine manufacturers may omit 

measurement of N2O and CH4. Use the 

same units and modal calculations as 

for your other results to report a single 

weighted value for each constituent. 

Round the final values as follows: 

(1) Round CO2 to the nearest 1 g/kWhr. 

(2) Round N2O to the nearest 0.001 g/ 

kW-hr. 

(3) Round CH4 to the nearest 0.001 g/ 

kW-hr. 

Subpart F—[Amended] 

■ 53. Section 1054.501 is amended by 

revising paragraph (b)(1) to read as 

follows: 

§ 1054.501 How do I run a valid emission 

test? 

* * * * * 

(b) * * * 

(1) Measure the emissions of all 

exhaust constituents subject to 

emissions standards as specified in 

§ 1054.505 and 40 CFR part 1065. 

Measure CO2, N2O, and CH4 as 

described in § 1054.235. See § 1054.650 

for special provisions that apply for 

variable-speed engines (including 

engines shipped without governors). 

* * * * * 

PART 1065—[AMENDED] 

■ 54. The authority citation for part 

1065 continues to read as follows: 

Authority: 42 U.S.C. 7401–7671q. 

Subpart A—[Amended] 

■ 55. Section 1065.5 is amended by 

revising paragraph (a)(3) to read as 

follows: 

§ 1065.5 Overview of this part 1065 and its 

relationship to the standard-setting part. 

(a) * * * 

(3) Which exhaust constituents do I 

need to measure? Measure all exhaust 

constituents that are subject to emission 

standards, any other exhaust 

constituents needed for calculating 

emission rates, and any additional 


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exhaust constituents as specified in the 

standard-setting part. Alternatively, you 

may omit the measurement of N2O and 

CH4 for an engine, provided it is not 

subject to an N2O or CH4 emission 

standard. If you omit the measurement 

of N2O and CH4, you must provide other 

information and/or data that will give us 

a reasonable basis for estimating the 

engine’s emission rates. 

* * * * * 

Subpart C—[Amended] 

■ 56. The center heading ‘‘NOx

Measurements’’ preceding § 1065.270 is 

revised to read as follows: 

NOX and N2O Measurements 

■ 57. A new § 1065.275 is added under 

the center heading ‘‘NOx and N2O 

Measurements’’ to read as follows: 

§ 1065.275 N2O measurement devices. 

(a) General component requirements. 

We recommend that you use an analyzer 

that meets the specifications in Table 1 

of § 1065.205. Note that your system 

must meet the linearity verification in 

§ 1065.307. 

(b) Instrument types. You may use any 

of the following analyzers to measure 

N2O: 

(1) Nondispersive infra-red (NDIR) 

analyzer. You may use an NDIR 

analyzer that has compensation 

algorithms that are functions of other 

gaseous measurements and the engine’s 

known or assumed fuel properties. The 

target value for any compensation 

algorithm is 0.0% (that is, no bias high 

and no bias low), regardless of the 

uncompensated signal’s bias. 

(2) Fourier transform infra-red (FTIR) 

analyzer. You may use an FTIR analyzer 

that has compensation algorithms that 

are functions of other gaseous 

measurements and the engine’s known 

or assumed fuel properties. The target 

value for any compensation algorithm is 

0.0% (that is, no bias high and no bias 

low), regardless of the uncompensated 

signal’s bias. Use appropriate analytical 

procedures for interpretation of infrared 

spectra. For example, EPA Test Method 

320 is considered a valid method for 

spectral interpretation (see http://www.

epa.gov/ttn/emc/methods/

method320.html). 

(3) Photoacoustic analyzer. You may 

use a photoacoustic analyzer that has 

compensation algorithms that are 

functions of other gaseous 

measurements. The target value for any 

compensation algorithm is 0.0% (that is, 

no bias high and no bias low), regardless 

of the uncompensated signal’s bias. Use 

an optical wheel configuration that 

gives analytical priority to measurement 

of the least stable components in the 

sample. Select a sample integration time 

of at least 5 seconds. Take into account 

sample chamber and sample line 

volumes when determining flush times 

for your instrument. 

(4) Gas chromatograph analyzer. You 

may use a gas chromatograph with an 

electron-capture detector (GC–ECD) to 

measure N2O concentrations of diluted 

exhaust for batch sampling. 

(i) You may use a packed or porous 

layer open tubular (PLOT) column 

phase of suitable polarity and length to 

achieve adequate resolution of the N2O 

peak for analysis. Examples of 

acceptable columns are a PLOT column 

consisting of bonded polystyrenedivinylbenzene or a Porapack Q packed 

column. Take the column temperature 

profile and carrier gas selection into 

consideration when setting up your 

method to achieve adequate N2O peak 

resolution. 

(ii) Use good engineering judgment to 

zero your instrument and correct for 

drift. You do not need to follow the 

specific procedures in § 1065.530 and 

§ 1065.550(b) that would otherwise 

apply. For example, you may perform a 

span gas measurement before and after 

sample analysis without zeroing. Use 

the average area counts of the pre-span 

and post-span measurements to generate 

a response factor (area counts/span gas 

concentration), which you then 

multiply by the area counts from your 

sample to generate the sample 

concentration. 

(c) Interference validation. Perform 

interference validation for NDIR, FTIR, 

and photoacoustic analyzers using the 

procedures of § 1065.375. Interference 

validation is not required for GC–ECD. 

Certain interference gases can positively 

interfere with NDIR, FTIR, and 

photoacoustic analyzers by causing a 

response similar to N2O. When running 

the interference verification for these 

analyzers, use interference gases as 

follows: 

(1) The interference gases for NDIR 

analyzers are CO, CO2, H2O, CH4 and 

SO2. Note that interference species, with 

the exception of H2O, are dependent on 

the N2O infrared absorption band 

chosen by the instrument manufacturer 

and should be determined dently for 

each analyzer. 

(2) Use good engineering judgment to 

determine interference gases for FTIR. 

Note that interference species, with the 

exception of H2O, are dependent on the 

N2O infrared absorption band chosen by 

the instrument manufacturer and should 

be determined independently for each 

analyzer. 

(3) The interference gases for 

photoacoustic analyzers are CO, CO2, 

and H2O. 

Subpart D—[Amended] 

■ 58. Section 1065.303 is revised to read 

as follows: 

§ 1065.303 Summary of required 

calibration and verifications 

The following table summarizes the 

required and recommended calibrations 

and verifications described in this 

subpart and indicates when these have 

to be performed: 

TABLE 1 OF § 1065.303–SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS

Type of calibration or verification Minimum frequency a

§ 1065.305: Accuracy, repeatability and noise ............................. Accuracy: Not required, but recommended for initial installation. 

Repeatability: Not required, but recommended for initial installation. 

Noise: Not required, but recommended for initial installation. 

§ 1065.307: Linearity .................................................................... Speed: Upon initial installation, within 370 days before testing and after major 

maintenance. 

Torque: Upon initial installation, within 370 days before testing and after major 

maintenance. 

Electrical power: Upon initial installation, within 370 days before testing and 

after major maintenance. 

Clean gas and diluted exhaust flows: Upon initial installation, within 370 days 

before testing and after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance. 


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TABLE 1 OF § 1065.303–SUMMARY OF REQUIRED CALIBRATION AND VERIFICATIONS—Continued 

Type of calibration or verification Minimum frequency a

Raw exhaust flow: Upon initial installation, within 185 days before testing and 

after major maintenance, unless flow is verified by propane check or by carbon or oxygen balance. 

Gas analyzers: Upon initial installation, within 35 days before testing and after 

major maintenance. 

FTIR and photoacoustic analyzers: Upon initial installation, within 370 days 

before testing and after major maintenance. 

GC–ECD: Upon initial installation and after major maintenance. 

PM balance: Upon initial installation, within 370 days before testing and after 

major maintenance. 

Stand-alone pressure and temperature: Upon initial installation, within 370 

days before testing and after major maintenance. 

§ 1065.308: Continuous gas analyzer system response and updating-recording verification—for gas analyzers not continuously compensated for other gas species.Upon initial installation or after system modification that would effect response. 

§ 1065.309: Continuous gas analyzer system-response and updating-recording verification—for gas analyzers continuously 

compensated for other gas species.

Upon initial installation or after system modification that would effect response. 

§ 1065.310: Torque ....................................................................... Upon initial installation and after major maintenance. 

§ 1065.315: Pressure, temperature, dewpoint .............................. Upon initial installation and after major maintenance. 

§ 1065.320: Fuel flow ................................................................... Upon initial installation and after major maintenance. 

§ 1065.325: Intake flow ................................................................. Upon initial installation and after major maintenance. 

§ 1065.330: Exhaust flow ............................................................. Upon initial installation and after major maintenance. 

§ 1065.340: Diluted exhaust flow (CVS) ....................................... Upon initial installation and after major maintenance. 

§ 1065.341: CVS and batch sampler verification b ....................... Upon initial installation, within 35 days before testing, and after major maintenance. 

§ 1065.345: Vacuum leak ............................................................. Before each laboratory test according to subpart F of this part and before 

each field test according to subpart J of this part. 

§ 1065.350: CO2 NDIR H2O interference ..................................... Upon initial installation and after major maintenance. 

§ 1065.355: CO NDIR CO2 and H2O interference ....................... Upon initial installation and after major maintenance. 

§ 1065.360: FID calibration, THC FID optimization, and THC 

FID verification..

Calibrate all FID analyzers: upon initial installation and after major maintenance. 

Optimize and determine CH4 response for THC FID analyzers: 

upon initial installation and after major maintenance. 

Verify CH4 response for THC FID analyzers: upon initial installation, within 

185 days before testing, and after major maintenance. 

§ 1065.362: Raw exhaust FID O2 interference ............................. For all FID analyzers: upon initial installation, and after major maintenance. 

For THC FID analyzers: upon initial installation, after major maintenance, and 

after FID optimization according to § 1065.360. 

§ 1065.365: Nonmethane cutter penetration ................................ Upon initial installation, within 185 days before testing, and after major maintenance. 

§ 1065.370: CLD CO2 and H2O quench ....................................... Upon initial installation and after major maintenance. 

§ 1065.372: NDUV HC and H2O interference .............................. Upon initial installation and after major maintenance. 

§ 1065.375: N2O analyzer interference ........................................ Upon initial installation and after major maintenance. 

§ 1065.376: Chiller NO2 penetration ............................................. Upon initial installation and after major maintenance. 

§ 1065.378: NO2-to-NO converter conversion .............................. Upon initial installation, within 35 days before testing, and after major maintenance. 

§ 1065.390: PM balance and weighing ........................................ Independent verification: upon initial installation, within 370 days before testing, and after major maintenance. 

Zero, span, and reference sample verifications: within 12 hours of weighing, 

and after major maintenance. 

§ 1065.395: Inertial PM balance and weighing ............................ Independent verification: upon initial installation, within 370 days before testing, and after major maintenance. 

Other verifications: upon initial installation and after major maintenance. 

aPerform calibrations and verifications more frequently, according to measurement system manufacturer instructions and good engineering 

judgment. bThe CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or 

oxygen of the intake air, fuel, and diluted exhaust. bThe CVS verification described in § 1065.341 is not required for systems that agree within ± 2% based on a chemical balance of carbon or 

oxygen of the intake air, fuel, and diluted exhaust. 

■ 59. Section 1065.307 is amended by 

revising paragraph (c)(6) to read as 

follows: 

§ 1065.307 Linearity verification. 

* * * * * 

(c) * * * 

(6) For all measured quantities, use 

instrument manufacturer 

recommendations and good engineering 

judgment to select reference values, yrefi, 

that cover a range of values that you 

expect would prevent extrapolation 

beyond these values during emission 

testing. We recommend selecting a zero 

reference signal as one of the reference 

values of the linearity verification. For 

stand-alone pressure and temperature 

linearity verifications and for GC–ECD 

linearity verifications, we recommend at 

least three reference values. For all other 

linearity verifications select at least ten 

reference values. 

* * * * * 

■ 60. Section 1065.365 is amended by 

revising paragraphs (d), (e), and (f) to 

read as follows: 


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§ 1065.365 Nonmethane cutter penetration 

fractions. 

* * * * * 

(d) Procedure for a FID calibrated 

with the NMC. The method described in 

this paragraph (d) is recommended over 

the procedures specified in paragraphs 

(e) and (f) of this section. If your FID 

arrangement is such that a FID is always 

calibrated to measure CH4 with the 

NMC, then span that FID with the NMC 

using a CH4 span gas, set the product of 

that FID’s CH4 response factor and CH4

penetration fraction, RFPFCH4[NMC–FID], 

equal to 1.0 for all emission 

calculations, and determine its 

combined ethane (C2H6) response factor 

and penetration fraction, 

RFPFC2H6[NMC–FID] as follows: 

(1) Select CH4 and C2H6 analytical gas 

mixtures and ensure that both mixtures 

meet the specifications of § 1065.750. 

Select a CH4 concentration that you 

would use for spanning the FID during 

emission testing and select a C2H6

concentration that is typical of the peak 

NMHC concentration expected at the 

hydrocarbon standard or equal to the 

THC analyzer’s span value. 

(2) Start, operate, and optimize the 

nonmethane cutter according to the 

manufacturer’s instructions, including 

any temperature optimization. 

(3) Confirm that the FID analyzer 

meets all the specifications of 

§ 1065.360. 

(4) Start and operate the FID analyzer 

according to the manufacturer’s 

instructions. 

(5) Zero and span the FID with the 

nonmethane cutter as you would during 

emission testing. Span the FID through 

the cutter by using CH4 span gas. 

(6) Introduce the C2H6 analytical gas 

mixture upstream of the nonmethane 

cutter. Use good engineering judgment 

to address the effect of hydrocarbon 

contamination if your point of 

introduction is vastly different from the 

point of zero/span gas introduction. 

(7) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the 

nonmethane cutter and to account for 

the analyzer’s response. 

(8) While the analyzer measures a 

stable concentration, record 30 seconds 

of sampled data. Calculate the 

arithmetic mean of these data points. 

(9) Divide the mean C2H6

concentration by the reference 

concentration of C2H6, converted to a C1

basis. The result is the C2H6 combined 

response factor and penetration fraction, 

RFPFC2H6[NMC–FID]. Use this combined 

response factor and penetration fraction 

and the product of the CH4 response 

factor and CH4 penetration fraction, 

RFPFCH4[NMC–FID], set to 1.0 in emission 

calculations according to 

§ 1065.660(b)(2)(i), § 1065.660(c)(1)(i), or 

§ 1065.665, as applicable. 

(e) Procedure for a FID calibrated with 

propane, bypassing the NMC. If you use 

a single FID for THC and CH4

determination with an NMC that is 

calibrated with propane, C3H8, by 

bypassing the NMC, determine its 

penetration fractions, PFC2H6[NMC–FID]

and PFCH4[NMC–FID], as follows: 

(1) Select CH4 and C2H6 analytical gas 

mixtures and ensure that both mixtures 

meet the specifications of § 1065.750. 

Select a CH4 concentration that you 

would use for spanning the FID during 

emission testing and select a C2H6

concentration that is typical of the peak 

NMHC concentration expected at the 

hydrocarbon standard or equal to the 

THC analyzer’s span value. 

(2) Start and operate the nonmethane 

cutter according to the manufacturer’s 

instructions, including any temperature 

optimization. 

(3) Confirm that the FID analyzer 

meets all the specifications of 

§ 1065.360. 

(4) Start and operate the FID analyzer 

according to the manufacturer’s 

instructions. 

(5) Zero and span the FID as you 

would during emission testing. Span the 

FID by bypassing the cutter and by 

using C3H8 span gas. 

(6) Introduce the C2H6 analytical gas 

mixture upstream of the nonmethane 

cutter. Use good engineering judgment 

to address the effect of hydrocarbon 

contamination if your point of 

introduction is vastly different from the 

point of zero/span gas introduction. 

(7) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the 

nonmethane cutter and to account for 

the analyzer’s response. 

(8) While the analyzer measures a 

stable concentration, record 30 seconds 

of sampled data. Calculate the 

arithmetic mean of these data points. 

(9) Reroute the flow path to bypass 

the nonmethane cutter, introduce the 

C2H6 analytical gas mixture, and repeat 

the steps in paragraph (e)(7) through 

(e)(8) of this section. 

(10) Divide the mean C2H6

concentration measured through the 

nonmethane cutter by the mean C2H6

concentration measured after bypassing 

the nonmethane cutter. The result is the 

C2H6 penetration fraction, 

PFC2H6[NMC–FID]. Use this penetration 

fraction according to 

§ 1065.660(b)(2)(ii), § 1065.660(c)(1)(ii), 

or § 1065.665, as applicable. 

(11) Repeat the steps in paragraphs 

(e)(6) through (e)(10) of this section, but 

with the CH4 analytical gas mixture 

instead of C2H6. The result will be the 

CH4 penetration fraction, PFCH4[NMC–FID]. 

Use this penetration fraction according 

to § 1065.660(b)(2)(ii), 

§ 1065.660(c)(1)(ii), or § 1065.665, as 

applicable. 

(f) Procedure for a FID calibrated with 

methane, bypassing the NMC. If you use 

a FID with an NMC that is calibrated 

with methane, CH4, by bypassing the 

NMC, determine its combined ethane 

(C2H6) response factor and penetration 

fraction, RFPFC2H6[NMC–FID], as well as 

its CH4 penetration fraction, 

PFCH4[NMC–FID], as follows: 

(1) Select CH4 and C2H6 analytical gas 

mixtures and ensure that both mixtures 

meet the specifications of § 1065.750. 

Select a CH4 concentration that you 

would use for spanning the FID during 

emission testing and select a C2H6

concentration that is typical of the peak 

NMHC concentration expected at the 

hydrocarbon standard or equal to the 

THC analyzer’s span value. 

(2) Start and operate the nonmethane 

cutter according to the manufacturer’s 

instructions, including any temperature 

optimization. 

(3) Confirm that the FID analyzer 

meets all the specifications of 

§ 1065.360. 

(4) Start and operate the FID analyzer 

according to the manufacturer’s 

instructions. 

(5) Zero and span the FID as you 

would during emission testing. Span the 

FID by bypassing the cutter and by 

using CH4 span gas. Note that you must 

span the FID on a C1 basis. For example, 

if your span gas has a methane reference 

value of 100 μmol/mol, the correct FID 

response to that span gas is 100 μmol/ 

mol because there is one carbon atom 

per CH4 molecule. 

(6) Introduce the C2H6 analytical gas 

mixture upstream of the nonmethane 

cutter. Use good engineering judgment 

to address the effect of hydrocarbon 

contamination if your point of 

introduction is vastly different from the 

point of zero/span gas introduction. 

(7) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the 

nonmethane cutter and to account for 

the analyzer’s response. 

(8) While the analyzer measures a 

stable concentration, record 30 seconds 

of sampled data. Calculate the 

arithmetic mean of these data points. 

(9) Divide the mean C2H6

concentration by the reference 

concentration of C2H6, converted to a C1

basis. The result is the C2H6 combined 

response factor and penetration fraction, 

RFPFC2H6[NMC–FID]. Use this combined 

response factor and penetration fraction 

according to § 1065.660(b)(2)(iii), 


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§ 1065.660(c)(1)(iii), or § 1065.665, as 

applicable. 

(10) Introduce the CH4 analytical gas 

mixture upstream of the nonmethane 

cutter. Use good engineering judgment 

to address the effect of hydrocarbon 

contamination if your point of 

introduction is vastly different from the 

point of zero/span gas introduction. 

(11) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the 

nonmethane cutter and to account for 

the analyzer’s response. 

(12) While the analyzer measures a 

stable concentration, record 30 seconds 

of sampled data. Calculate the 

arithmetic mean of these data points. 

(13) Reroute the flow path to bypass 

the nonmethane cutter, introduce the 

CH4 analytical gas mixture, and repeat 

the steps in paragraphs (e)(11) and (12) 

of this section. 

(14) Divide the mean CH4

concentration measured through the 

nonmethane cutter by the mean CH4

concentration measured after bypassing 

the nonmethane cutter. The result is the 

CH4 penetration fraction, PFCH4[NMC–FID]. 

Use this penetration fraction according 

to § 1065.660(b)(2)(iii), 

§ 1065.660(c)(1)(iii), or § 1065.665, as 

applicable. 

■ 61. The center heading ‘‘NOX

MEASUREMENTS’’ preceding 

§ 1065.370 is revised to read as follows: 

NOX and N2O Measurements 

■ 62. A new § 1065.375 is added under 

the center header ‘‘NOX and N2O 

Measurements’’ to read as follows: 

§ 1065.375 Interference verification for N2O 

analyzers. 

(a) Scope and frequency. See 

§ 1065.275 to determine whether you 

need to verify the amount of 

interference after initial analyzer 

installation and after major 

maintenance. 

(b) Measurement principles. 

Interference gasses can positively 

interfere with certain analyzers by 

causing a response similar to N2O. If the 

analyzer uses compensation algorithms 

that utilize measurements of other gases 

to meet this interference verification, 

simultaneously conduct these other 

measurements to test the compensation 

algorithms during the analyzer 

interference verification. 

(c) System requirements. Analyzers 

must have combined interference that is 

within (0.0 ± 1.0) μmol/mol. We 

strongly recommend a lower 

interference that is within (0.0 ± 0.5) 

μmol/mol. 

(d) Procedure. Perform the 

interference verification as follows: 

(1) Start, operate, zero, and span the 

N2O analyzer as you would before an 

emission test. If the sample is passed 

through a dryer during emission testing, 

you may run this verification test with 

the dryer if it meets the requirements of 

§ 1065.342. Operate the dryer at the 

same conditions as you will for an 

emission test. You may also run this 

verification test without the sample 

dryer. 

(2) Create a humidified test gas by 

bubbling a multi component span gas 

that incorporates the target interference 

species and meets the specifications in 

§ 1065.750 through distilled water in a 

sealed vessel. If the sample is not passed 

through a dryer during emission testing, 

control the vessel temperature to 

generate an H2O level at least as high as 

the maximum expected during emission 

testing. If the sample is passed through 

a dryer during emission testing, control 

the vessel temperature to generate an 

H2O level at least as high as the level 

determined in § 1065.145(e)(2) for that 

dryer. Use interference span gas 

concentrations that are at least as high 

as the maximum expected during 

testing. 

(3) Introduce the humidified 

interference test gas into the sample 

system. You may introduce it 

downstream of any sample dryer, if one 

is used during testing. 

(4) If the sample is not passed through 

a dryer during this verification test, 

measure the water mole fraction, xH2O, 

of the humidified interference test gas as 

close as possible to the inlet of the 

analyzer. For example, measure 

dewpoint, Tdew, and absolute pressure, 

ptotal, to calculate xH2O. Verify that the 

water content meets the requirement in 

paragraph (d)(2) of this section. If the 

sample is passed through a dryer during 

this verification test, you must verify 

that the water content of the humidified 

test gas downstream of the vessel meets 

the requirement in paragraph (d)(2) of 

this section based on either direct 

measurement of the water content (e.g., 

dewpoint and pressure) or an estimate 

based on the vessel pressure and 

temperature. Use good engineering 

judgment to estimate the water content. 

For example, you may use previous 

direct measurements of water content to 

verify the vessel’s level of saturation. 

(5) If a sample dryer is not used in this 

verification test, use good engineering 

judgment to prevent condensation in the 

transfer lines, fittings, or valves from the 

point where xH2O is measured to the 

analyzer. We recommend that you 

design your system so that the wall 

temperatures in the transfer lines, 

fittings, and valves from the point where 

xH2O is measured to the analyzer are at 

least 5 °C above the local sample gas 

dewpoint. 

(6) Allow time for the analyzer 

response to stabilize. Stabilization time 

may include time to purge the transfer 

line and to account for analyzer 

response. 

(7) While the analyzer measures the 

sample’s concentration, record its 

output for 30 seconds. Calculate the 

arithmetic mean of this data. 

(8) The analyzer meets the 

interference verification if the result of 

paragraph (d)(7) of this section meets 

the tolerance in paragraph (c) of this 

section. 

(9) You may also run interference 

procedures separately for individual 

interference gases. If the interference gas 

levels used are higher than the 

maximum levels expected during 

testing, you may scale down each 

observed interference value by 

multiplying the observed interference 

by the ratio of the maximum expected 

concentration value to the actual value 

used during this procedure. You may 

run separate interference concentrations 

of H2O (down to 0.025 mol/mol H2O 

content) that are lower than the 

maximum levels expected during 

testing, but you must scale up the 

observed H2O interference by 

multiplying the observed interference 

by the ratio of the maximum expected 

H2O concentration value to the actual 

value used during this procedure. The 

sum of the scaled interference values 

must meet the tolerance specified in 

paragraph (c) of this section. 

Subpart F—[Amended] 

■ 63. Section 1065.550 is amended by 

revising paragraphs (b) introductory text 

and (b)(1), adding and reserving 

paragraph (b)(3), and adding paragraph 

(b)(4) to read as follows: 

§ 1065.550 Gas analyzer range validation, 

drift validation, and drift correction. 

* * * * * 

(b) Drift validation and drift 

correction. Calculate two sets of brakespecific emission results for each test 

interval. Calculate one set using the data 

before drift correction and calculate the 

other set after correcting all the data for 

drift according to § 1065.672. Use the 

two sets of brake-specific emission 

results to validate the duty cycle for 

drift as follows: 

(1) The duty cycle is validated for 

drift if you satisfy one of the following 

criteria: 

(i) For each test interval of the duty 

cycle and for each measured exhaust 

constituent, the difference between the 

uncorrected and the corrected brakeVerDate Nov<24>2008 17:39 Oct 29, 2009 Jkt 220001 PO 00000 Frm 00257 Fmt 4701 Sfmt 4700 E:\FR\FM\30OCR2.SGM 30OCR2

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specific emission values over the test 

interval is within ±4% of the 

uncorrected value or applicable 

emission standard, whichever is greater. 

This requirement also applies for CO2, 

whether or not an emission standard 

applies for CO2. Where no emission 

standard applies for CO2, the difference 

must be within ±4% of the uncorrected 

value. See paragraph (b)(4) of this 

section for exhaust constituents other 

than CO2 for which no emission 

standard applies. 

(ii) For the entire duty cycle and for 

each regulated pollutant, the difference 

between the uncorrected and corrected 

composite brake-specific emission 

values over the entire duty cycle is 

within ±4% of the uncorrected value or 

the applicable emission standard, 

whichever is greater. Note that for 

purposes of drift validation using 

composite brake-specific emission 

values over the entire duty cycle, leave 

unaltered any negative emission results 

over a given test interval (i.e., do not set 

them to zero). A third calculation of 

composite brake-specific emission 

values is required for final reporting. 

This calculation uses drift-corrected 

mass (or mass rate) values from each test 

interval and sets any negative mass (or 

mass rate) values to zero before 

calculating the composite brake-specific 

emission values over the entire duty 

cycle. This requirement also applies for 

CO2, whether or not an emission 

standard applies for CO2. Where no 

emission standard applies for CO2, the 

difference must be within ±4% of the 

uncorrected value. See paragraph (b)(3) 

of this section for exhaust constituents 

other than CO2 for which no emission 

standard applies. 

* * * * * 

(3) [Reserved] 

(4) The provisions of paragraph (b)(3) 

of this section apply for measurement of 

pollutants other than CO2 for which no 

emission standard applies. You may use 

measurements that do not meet the drift 

validation criteria specified in 

paragraph (b)(1) of this section. For 

example, this allowance may be 

appropriate for measuring and reporting 

very low concentrations of CH4 and N2O 

as long as no emission standard applies 

for these compounds. 

Subpart G—[Amended] 

■ 64. Section 1065.601 is amended by 

revising paragraph (a)(1) to read as 

follows: 

§ 1065.601 Overview. 

(a) * * * 

(1) Use the signals recorded before, 

during, and after an emission test to 

calculate brake-specific emissions of 

each measured exhaust constituent. 

* * * * * 

■ 65. Section 1065.660 is amended by 

revising paragraphs (a), (b) introductory 

text, (b)(1), (b)(2), and (b)(3) 

introductory text, and adding paragraph 

(c) to read as follows: 

§ 1065.660 THC, NMHC, and CH4

determination. 

(a) THC determination and THC/CH4

initial contamination corrections. (1) If 

we require you to determine THC 

emissions, calculate xTHC[THC–FID]cor

using the initial THC contamination 

concentration xTHC[THC¥FID]init from 

§ 1065.520 as follows: 

xx x THC[THC-FID]cor THC[THC-FID]uncor THC[THC-FID] init = − Eq. 1065.660-1

Example: 

xTHCuncor = 150.3 μmol/mol 

xTHCinit = 1.1 μmol/mol 

xTHCcor = 150.3¥1.1 

xTHCcor = 149.2 μmol/mol 

(2) For the NMHC determination 

described in paragraph (b) of this 

section, correct xTHC[THC–FID] for initial 

HC contamination using Eq. 1065.660– 

1. You may correct xTHC[NMC–FID] for 

initial contamination of the CH4 sample 

train using Eq. 1065.660–1, substituting 

in CH4 concentrations for THC. 

(3) For the CH4 determination 

described in paragraph (c) of this 

section, you may correct xTHC[NMC–FID]

for initial contamination of the CH4

sample train using Eq. 1065.660–1, 

substituting in CH4 concentrations for 

THC. 

(b) NMHC determination. Use one of 

the following to determine NMHC 

concentration, xNMHC: 

(1) If you do not measure CH4, you 

may determine NMHC concentrations as 

described in § 1065.650(c)(1)(vi). 

(2) For nonmethane cutters, calculate 

xNMHC using the nonmethane cutter’s 

penetration fractions (PF) of CH4 and 

C2H6 from § 1065.365, and using the HC 

contamination and dry-to-wet corrected 

THC concentration xTHC[THC–FID]cor as 

determined in paragraph (a) of this 

section. 

(i) Use the following equation for 

penetration fractions determined using 

an NMC configuration as outlined in 

§ 1065.365(d): 

x

RF NMHC

THC[THC-FID]cor THC[NMC-FID]cor CH4[THC-FID]

1 = − ⋅−

x x RF

PF RF C2H6[NMC-FID] CH4[THC-FID]

Eq. 1065.660-2 ⋅

Where: 

xNMHC = concentration of NMHC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the NMC FID 

during sampling through the NMC. 

RFCH4[THC–FID] = response factor of THC FID 

to CH4, according to § 1065.360(d). 

RFPFC2H6[NMC–FID] = nonmethane cutter 

combined ethane response factor and 

penetration fraction, according to 

§ 1065.365(d). 

Example: 

xTHC[THC–FID]cor = 150.3 μmol/mol 

xTHC[NMC–FID]cor = 20.5 μmol/mol 

RFPFC2H6[NMC–FID] = 0.019 

RFCH4[THC–FID] = 1.05 

xNMHC = − ⋅

− ⋅

150 3 20 5 1 05

1 0 019 1 05

. ..

. .

xNMHC = 131.4 μmol/mol 

(ii) For penetration fractions 

determined using an NMC configuration 

as outlined in section § 1065.365(e), use 

the following equation: 


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x

PF NMHC

THC[THC-FID]cor CH4[NMC-FID]cor THC[NMC-FID]

CH

= x PF x ⋅ −

4[NMC-FID] C2H6[NMC-FID]

Eq. 1065.660-3 − PF

Where: 

xNMHC = concentration of NMHC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

PFCH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to 

§ 1065.365(e). 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the THC FID 

during sampling through the NMC. 

PFC2H6[NMC–FID] = nonmethane cutter ethane 

penetration fraction, according to 

§ 1065.365(e). 

Example: 

xTHC[THC–FID]cor = 150.3 μmol/mol 

PFCH4[NMC–FID] = 0.990 

xTHC[NMC–FID]cor = 20.5 μmol/mol 

PFC2H6[NMC–FID] = 0.020 

xNMHC = ⋅ −

−

150 3 0 990 20 5

0 990 0 020

.. .

. .

xNMHC = 132.3 μmol/mol 

(iii) For penetration fractions 

determined using an NMC configuration 

as outlined in § 1065.365(f), use the 

following equation: 

xNMHC

THC[THC-FID]cor CH4[NMC-FID] THC[NMC-FID]cor C = x PF x RF ⋅− ⋅ H4[THC-FID]

PF RFPF RF CH4[NMC-FID] C2H6[NMC-FID] CH4[THC-FID − ⋅ ]

Eq. 1065.660-4

Where: 

xNMHC = concentration of NMHC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

PFCH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to 

§ 1065.365(f). 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the THC FID 

during sampling through the NMC. 

RFPFC2H6[NMC–FID] = nonmethane cutter CH4

combined ethane response factor and 

penetration fraction, according to 

§ 1065.365(f). 

RFCH4[THC–FID] = response factor of THC FID 

to CH4, according to § 1065.360(d). 

Example: 

xTHC[THC–FID]cor = 150.3 μmol/mol 

PFCH4[NMC–FID] = 0.990 

xTHC[NMC–FID]cor = 20.5 μmol/mol 

RFPFC2H6[NMC–FID] = 0.019 

RFCH4[THC–FID] = 0.980 

xNMHC = ⋅ −⋅

− ⋅

150 3 0 990 20 5 0 980

0 990 0 019 0 980

.. ..

. ..

xNMHC = 132.5 μmol/mol 

(3) For a gas chromatograph, calculate 

xNMHC using the THC analyzer’s response 

factor (RF) for CH4, from § 1065.360, and the 

HC contamination and dry-to-wet corrected 

initial THC concentration xTHC[THC–FID]cor as 

determined in paragraph (a) of this section as 

follows: 

* * * * * 

(c) CH4 determination. Use one of the 

following methods to determine CH4

concentration, xCH4: 

(1) For nonmethane cutters, calculate xCH4

using the nonmethane cutter’s penetration 

fractions (PF) of CH4 and C2H6 from 

§ 1065.365, using the dry-to-wet corrected 

CH4 concentration xTHC[NMC–FID]cor as 

determined in paragraph (a) of this section 

and optionally using the CH4 contamination 

correction under paragraph (a) of this section. 

(i) Use the following equation for 

penetration fractions determined using an 

NMC configuration as outlined in 

§ 1065.365(d): 

xCH4

THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID] = − ⋅

−

x x RFPF

1 RFPF RF C2H6[NMC-FID] CH4[THC-FID]

Eq. 1065.660-6 ⋅

Where: 

xCH4 = concentration of CH4. 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the NMC FID 

during sampling through the NMC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

RFPFC2H6[NMC–FID] = the combined ethane 

response factor and penetration fraction 

of the nonmethane cutter, according to 

§ 1065.365(d). 

RFCH4[THC–FID] = response factor of THC FID 

to CH4, according to § 1065.360(d). 

Example: 

xTHC[NMC–FID]cor = 10.4 μmol/mol 

xTHC[THC–FID]cor = 150.3 μmol/mol 

RFPFC2H6[NMC–FID] = 0.019 

RFCH4[THC–FID] = 1.05 

xCH4 = − ⋅

− ⋅

10 4 150 3 0 019

1 0 019 1 05

. ..

. .

xCH4 = 7.69 μmol/mol 

(ii) For penetration fractions determined 

using an NMC configuration as outlined in 

§ 1065.365(e), use the following equation: 

x

RF CH4

THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID]

CH

= x x PF − ⋅

4[THC-FID] CH4[NMC-FID] C2H6[NMC-FID]

Eq. 1065.660-7 ⋅ − ( ) PF PF

Where: 

xCH4 = concentration of CH4. 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the NMC FID 

during sampling through the NMC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

PFC2H6[NMC–FID] = nonmethane cutter ethane 

penetration fraction, according to 

§ 1065.365(e). 

RFCH4[THC–FID] = response factor of THC FID 

to CH4, according to § 1065.360(d). 

PFCH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to 

§ 1065.365(e). 

Example: 

xTHC[NMC–FID]cor = 10.4 μmol/mol 

xTHC[THC–FID]cor = 150.3 μmol/mol 

PFC2H6[NMC–FID] = 0.020 

RFCH4[THC–FID] = 1.05 


ER30OC09.182</MATH> ER30OC09.183</MATH> ER30OC09.184</MATH> ER30OC09.185</MATH> ER30OC09.186</MATH> ER30OC09.187</MATH> ER30OC09.188</MATH>sroberts on DSKD5P82C1PROD with RULES
56518 Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 

PFCH4[NMC–FID] = 0.990 

xCH4 = − ⋅

⋅ −

10 4 150 3 0 020

1 05 0 990 0 020

. ..

. (. . )

xCH4 = 7.25 μmol/mol 

(iii) For penetration fractions determined 

using an NMC configuration as outlined in 

§ 1065.365(f), use the following equation: 

x

RF

PF CH4

THC[NMC-FID]cor THC[THC-FID]cor C2H6[NMC-FID] = x x PF − ⋅

CH4[NMC-FID] C2H6[NMC-FID] CH4[THC-FID]

Eq. 1065.660 − ⋅ RF RF PF -8

Where: 

xCH4 = concentration of CH4. 

xTHC[NMC–FID]cor = concentration of THC, HC 

contamination (optional) and dry-to-wet 

corrected, as measured by the NMC FID 

during sampling through the NMC. 

xTHC[THC–FID]cor = concentration of THC, HC 

contamination and dry-to-wet corrected, 

as measured by the THC FID during 

sampling while bypassing the NMC. 

RFPFC2H6[NMC–FID] = the combined ethane 

response factor and penetration fraction 

of the nonmethane cutter, according to 

§ 1065.365(f). 

PFCH4[NMC–FID] = nonmethane cutter CH4

penetration fraction, according to 

§ 1065.365(f). 

RFCH4[THC–FID] = response factor of THC FID 

to CH4, according to § 1065.360(d). 

Example: 

xTHC[NMC–FID]cor = 10.4 μmol/mol 

xTHC[THC–FID]cor = 150.3 μmol/mol 

RFPFC2H6[NMC–FID] = 0.019 

PFCH4[NMC–FID] = 0.990 

RFCH4[THC–FID] = 1.05 

xCH4 = − ⋅

− ⋅

10 4 150 3 0 019

0 990 0 019 1 05

. ..

. ..

xCH4 = 7.78 μmol/mol 

(2) For a gas chromatograph, xCH4 is the 

actual dry-to-wet corrected CH4

concentration as measured by the analyzer. 

Subpart H—[Amended] 

■ 66. 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. 

N2O2 ................................................................... ≤ 0.05 μmol/mol ............................................... ≤ 0.05 μmol/mol. 

1We do not require these levels of purity to be NIST-traceable. 

2The N2O limit applies only if the standard-setting part requires you to report N2O. 

* * * * * 

(3) * * * 

(xi) N2O, balance purified synthetic 

air. 

* * * * * 

■ 67. 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. 

* * * * * 

■ 68. Section 1065.1005 is amended by 

revising paragraphs (b), (f)(2), and (g) to 

read as follows: 

§ 1065.1005 Symbols, abbreviations, 

acronyms, and units of measure. 

* * * * * 

(b) Symbols for chemical species. This 

part uses the following symbols for 

chemical species and exhaust 

constituents: 

Symbol Species 

Ar ................... argon. 

C .................... carbon. 

CH4 ................ methane. 

C2H6 ............... ethane. 

C3H8 ............... propane. 

C4H10 .............. butane. 

C5H12 .............. pentane. 

CO .................. carbon monoxide. 

CO2 ................ carbon dioxide. 

H .................... atomic hydrogen. 

H2 ................... molecular hydrogen. 

H2O ................ water. 

He .................. helium. 

85Kr ................ krypton 85. 

N2 ................... molecular nitrogen. 

Symbol Species 

NMHC ............ nonmethane hydrocarbon. 

NMHCE .......... nonmethane hydrocarbon 

equivalent. 

NO .................. nitric oxide. 

NO2 ................ nitrogen dioxide. 

NOX ................ oxides of nitrogen. 

N2O ................ nitrous oxide. 

NOTHC .......... nonoxygenated hydrocarbon. 

O2 ................... molecular oxygen. 

OHC ............... oxygenated hydrocarbon. 

210Po .............. polonium 210. 

PM .................. particulate mass. 

S ..................... sulfur. 

SO2 ................ sulfur dioxide. 

THC ................ total hydrocarbon. 

ZrO2 ............... zirconium dioxide. 

* * * * * 

(f) * * * 

(2) This part uses the following molar 

masses or effective molar masses of 

chemical species: 


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Federal Register / Vol. 74, No. 209 / Friday, October 30, 2009 / Rules and Regulations 56519 

Symbol Quantity g/mol 

(10¥3.kg.mol¥ 1) 

Mair ........................................................... molar mass of dry air ................................................................................................. 28.96559 

MAr ........................................................... molar mass of argon .................................................................................................. 39.948 

MC ............................................................. molar mass of carbon ................................................................................................ 12.0107 

MCO ........................................................... molar mass of carbon monoxide ................................................................................ 28.0101 

MCO2 ......................................................... molar mass of carbon dioxide .................................................................................... 44.0095 

MH ............................................................ molar mass of atomic hydrogen ................................................................................. 1.00794 

MH2 ........................................................... molar mass of molecular hydrogen ............................................................................ 2.01588 

MH2O ......................................................... molar mass of water ................................................................................................... 18.01528 

MHe ........................................................... molar mass of helium ................................................................................................. 4.002602 

MN ............................................................ molar mass of atomic nitrogen ................................................................................... 14.0067 

MN2 ........................................................... molar mass of molecular nitrogen .............................................................................. 28.0134 

MNMHC ...................................................... effective molar mass of nonmethane hydrocarbon 2 ................................................. 13.875389 

MNMHCE .................................................... effective molar mass of nonmethane equivalent hydrocarbon 2 ................................ 13.875389 

MNOx ......................................................... effective molar mass of oxides of nitrogen 3 .............................................................. 46.0055 

MN2O ......................................................... effective molar mass of nitrous oxide ........................................................................ 44.0128 

MO ............................................................ molar mass of atomic oxygen .................................................................................... 15.9994 

MO2 ........................................................... molar mass of molecular oxygen ............................................................................... 31.9988 

MC3H8 ........................................................ molar mass of propane .............................................................................................. 44.09562 

MS ............................................................. molar mass of sulfur ................................................................................................... 32.065 

MTHC ......................................................... effective molar mass of total hydrocarbon 2 ............................................................... 13.875389 

MTHCE ....................................................... effective molar mass of total hydrocarbon equivalent 2 ............................................. 13.875389 

1See paragraph (f)(1) of this section for the composition of dry air 

2The effective molar masses of THC, THCE, NMHC, and NMHCE are defined by an atomic hydrogen-to-carbon ratio, a, of 1.85 3The effective molar mass of NOx is defined by the molar mass of nitrogen dioxide, NO2

* * * * * 

(g) Other acronyms and abbreviations. 

This part uses the following additional 

abbreviations and acronyms: 

ASTM American Society for Testing 

and Materials. 

BMD bag mini-diluter. 

BSFC brake-specific fuel consumption. 

CARB California Air Resources Board. 

CFR Code of Federal Regulations. 

CFV critical-flow venturi. 

CI compression-ignition. 

CITT Curb Idle Transmission Torque. 

CLD chemiluminescent detector. 

CVS constant-volume sampler. 

DF deterioration factor. 

ECM electronic control module. 

EFC electronic flow control. 

EGR exhaust gas recirculation. 

EPA Environmental Protection 

Agency. 

FEL Family Emission Limit 

FID flame-ionization detector. 

GC gas chromatograph. 

GC–ECD gas chromatograph with an 

electron-capture detector. 

IBP initial boiling point. 

ISO International Organization for 

Standardization. 

LPG liquefied petroleum gas. 

NDIR nondispersive infrared. 

NDUV nondispersive ultraviolet. 

NIST National Institute for Standards 

and Technology. 

PDP positive-displacement pump. 

PEMS portable emission measurement 

system. 

PFD partial-flow dilution. 

PMP Polymethylpentene. 

pt. a single point at the mean value 

expected at the standard. 

PTFE polytetrafluoroethylene 

(commonly known as TeflonTM). 

RE rounding error. 

RMC ramped-modal cycle. 

RMS root-mean square. 

RTD resistive temperature detector. 

SSV subsonic venturi. 

SI spark-ignition. 

UCL upper confidence limit. 

UFM ultrasonic flow meter. 

U.S.C. United States Code. 

[FR Doc. E9–23315 Filed 10–29–09; 8:45 am] 

BILLING CODE 6560–50–P 


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