Vol. 78 Friday, 

No. 230 November 29, 2013 

Part VI 

Environmental Protection Agency 

40 CFR Part 98 

2013 Revisions to the Greenhouse Gas Reporting Rule and Final 

Confidentiality Determinations for New or Substantially Revised Data 

Elements; Final Rule 


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71904 Federal Register / Vol. 78, No. 230 / Friday, November 29, 2013 / Rules and Regulations 

ENVIRONMENTAL PROTECTION 

AGENCY 

40 CFR Part 98 

[EPA–HQ–OAR–2012–0934; FRL–9902–95– 

OAR ] 

RIN 2060–AR52 

2013 Revisions to the Greenhouse Gas 

Reporting Rule and Final 

Confidentiality Determinations for New 

or Substantially Revised Data 

Elements 

AGENCY: Environmental Protection 

Agency (EPA). 

ACTION: Final rule. 

SUMMARY: The EPA is amending the 

Greenhouse Gas Reporting Rule to 

implement technical corrections, 

clarifying revisions, and other 

amendments to improve the quality and 

consistency of the data collected by the 

EPA. Among other changes, the EPA is 

amending the Rule’s table of global 

warming potentials to revise the values 

for certain greenhouse gases. This action 

also establishes confidentiality 

determinations for the reporting of new 

or substantially revised data elements 

(i.e., requiring additional or different 

data to be reported) contained in these 

final amendments to the Greenhouse 

Gas Reporting Rule. 

DATES: This final rule is effective on 

January 1, 2014. 

ADDRESSES: All documents in the docket 

are listed in the http://

www.regulations.gov index. Although 

listed in the index, some information is 

not publicly available, e.g., confidential 

business information (CBI) or other 

information whose disclosure is 

restricted by statute. Certain other 

material, such as copyrighted material, 

will be publicly available only in hard 

copy. Publicly available docket 

materials are available either 

electronically in http://

www.regulations.gov or in hard copy at 

the Air Docket, EPA/DC, William 

Jefferson Clinton Building (WJC) West 

Building, Room 3334, 1301 Constitution 

Ave. NW., Washington, DC. This Docket 

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

p.m., Monday through Friday, excluding 

legal holidays. The telephone number 

for the Public Reading Room is (202) 

566–1744 and the telephone number for 

the Air Docket is (202) 566–1742. 

FOR FURTHER GENERAL 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; email address: 

GHGReportingRule@epa.gov. For 

technical information, please go to the 

Greenhouse Gas Reporting Rule Program 

Web site http://www.epa.gov/

ghgreporting/index.html. To submit a 

question, select Rule Help Center, 

followed by Contact Us. 

Worldwide Web (WWW). In addition 

to being available in the docket, an 

electronic copy of this final rule will 

also be available through the WWW. 

Following the Administrator’s signature, 

a copy of this action will be posted on 

EPA’s greenhouse gas reporting rule 

Web site at http://www.epa.gov/

ghgreporting/index.html. 

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 CAA 

section 307(d) apply to ‘‘such other 

actions as the Administrator may 

determine’’). These are amendments to 

existing regulations and affect certain 

owners and operators of facilities that 

directly emit greenhouse gases (GHGs) 

as well as certain suppliers. Regulated 

categories and examples of affected 

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. 

Acid Gas Injection Projects ............................... 211111 or 

211112 

Projects that inject natural gas containing CO2 underground. 

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. 

CO2 Enhanced Oil and Gas Recovery Projects 211 Oil and gas extraction projects using CO2 enhanced oil and gas recovery. 

Electrical Equipment Use .................................. 221121 Electric bulk power transmission and control facilities. 

Electrical Equipment Manufacture or Refurbishment.33531 Power transmission and distribution switchgear and specialty transformers 

manufacturing facilities. 

Electronics Manufacturing ................................. 334111 Microcomputers manufacturing facilities. 

334413 Semiconductor, photovoltaic (solid-state) device manufacturing facilities. 

334419 LCD unit screens manufacturing facilities. MEMS manufacturing facilities. 

Ethanol Production ............................................ 325193 Ethyl alcohol manufacturing facilities. 

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

Fluorinated GHG Production ............................. 325120 Industrial gases manufacturing facilities. 

Food Processing ................................................ 311611 Meat processing facilities. 


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TABLE 1—EXAMPLES OF AFFECTED ENTITIES BY CATEGORY—Continued 

Category NAICS Examples of affected facilities 

311411 Frozen fruit, juice, and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

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

327213 Glass container manufacturing facilities. 

327212 Other pressed and blown glass and glassware manufacturing facilities. 

GS Sites ............................................................. NA CO2 geologic sequestration projects. 

HFC–22 Production and HFC–23 Destruction .. 325120 Chlorodifluoromethane manufacturing facilities. 

Hydrogen Production ......................................... 325120 Hydrogen manufacturing facilities. 

Importers and Exporters of Pre-charged Equipment and Closed-Cell Foams.423730 

333415 

Air-conditioning equipment (except room units) merchant wholesalers. 

Air-conditioning equipment (except motor vehicle) manufacturing. 

423620 Air-conditioners, room, merchant wholesalers. 

443111 Household Appliance Stores. 

326150 Polyurethane foam products manufacturing. 

335313 Circuit breakers, power, manufacturing. 

423610 Circuit breakers merchant wholesalers. 

Industrial Waste Landfills ................................... 562212 Solid waste landfills. 

221320 Sewage treatment facilities. 

322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

Industrial Wastewater Treatment ....................... 322110 Pulp mills. 

322121 Paper mills. 

322122 Newsprint mills. 

322130 Paperboard mills. 

311611 Meat processing facilities. 

311411 Frozen fruit, juice, and vegetable manufacturing facilities. 

311421 Fruit and vegetable canning facilities. 

325193 Ethanol manufacturing facilities. 

324110 Petroleum refineries. 

Iron and Steel Production .................................. 331111 Integrated iron and steel mills, steel companies, sinter plants, blast furnaces, 

basic oxygen process furnace shops. 

Lead Production ................................................. 331419 Primary lead smelting and refining facilities. 

331492 Secondary lead smelting and refining facilities. 

Lime Production ................................................. 327410 Calcium oxide, calcium hydroxide, dolomitic hydrates manufacturing facilities. 

Magnesium Production ...................................... 331419 Primary refiners of nonferrous metals by electrolytic methods.

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

221320 Sewage treatment 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. 

325182 Carbon black manufacturing facilities. 

Petroleum Refineries ......................................... 324110 Petroleum refineries. 

Petroleum and Natural Gas Systems ................ 486210 Pipeline transportation of natural gas. 

221210 Natural gas distribution facilities. 

211 Extractors of crude petroleum and natural gas. 

211112 Natural gas liquid extraction facilities. 

Phosphoric Acid Production .............................. 325312 Phosphoric acid manufacturing facilities. 

Pulp and Paper Manufacturing .......................... 322110 Pulp mills. 

322121 Paper mills. 

322130 Paperboard mills. 

Soda Ash Manufacturing ................................... 325181 Alkalies and chlorine manufacturing facilities. 

Silicon Carbide Production ................................ 327910 Silicon carbide abrasives manufacturing facilities. 

Sulfur Hexafluoride (SF6) from Electrical Equipment.221121 Electric bulk power transmission and control facilities. 

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

Underground Coal Mines ................................... 212113 Underground anthracite coal mining operations. 

212112 Underground bituminous coal mining operations. 

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

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

Suppliers of Industrial Greenhouse Gases ....... 325120 Industrial gas manufacturing facilities. 

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

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

211112 Natural gas liquid extraction facilities. 

Suppliers of Carbon Dioxide (CO2) ................... 325120 Industrial gas manufacturing facilities. 


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1Omnipoint Corp. v. FCC, 78 F3d 620, 630 (D.C. 

Cir. 1996), quoting U.S. v. Gavrilovic, 551 F.2d 

1099, 1105 (8th Cir. 1977). 

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. Types of facilities different from 

those listed in the table could also be 

subject to reporting requirements. To 

determine whether you are affected by 

this action, you should carefully 

examine the applicability criteria found 

in 40 CFR part 98, subpart A or the 

relevant criteria in the sections related 

to suppliers and direct emitters of 

GHGs. 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. 

What is the effective date? The final 

rule is effective on January 1, 2014. 

Section 553(d) of the Administrative 

Procedure Act (APA), 5 U.S.C. Chapter 

5, generally provides that rules may not 

take effect earlier than 30 days after they 

are published in the Federal Register. 

EPA is issuing this final rule under 

section 307(d)(1) of the Clean Air Act, 

which states: ‘‘The provisions of section 

553 through 557 * * * of Title 5 shall 

not, except as expressly provided in this 

section, apply to actions to which this 

subsection applies.’’ Thus, section 

553(d) of the APA does not apply to this 

rule. EPA is nevertheless acting 

consistently with the purposes 

underlying APA section 553(d) in 

making this rule effective on January 1, 

2014. Section 5 U.S.C. 553(d)(3) allows 

an effective date less than 30 days after 

publication ‘‘as otherwise provided by 

the agency for good cause found and 

published with the rule.’’ As explained 

below, EPA finds that there is good 

cause for this rule to become effective 

on January 1, 2014, even though this 

may result in an effective date fewer 

than 30 days from date of publication in 

the Federal Register. 

While this action is being signed prior 

to December 1, 2013, there is likely to 

be a significant delay in the publication 

of this rule as it contains complex 

equations and tables and is relatively 

long. As an example, then-Acting 

Administrator Bob Perciasepe signed 

the proposed 2013 Revisions Rule on 

March 8, 2013, but the proposed rule 

was not published in the Federal 

Register until April 2, 2013. Further, we 

anticipate that the partial federal 

government shutdown from October 1 to 

October 16, 2013, may have caused a 

backlog in the Federal Register 

publication process that may cause 

additional delays. The purpose of the 

30-day waiting period prescribed in 5 

U.S.C. 553(d) is to give affected parties 

a reasonable time to adjust their 

behavior and prepare before the final 

rule takes effect. 

To employ the 5 U.S.C. 553(d)(3) 

‘‘good cause’’ exemption, an agency 

must ‘‘balance the necessity for 

immediate implementation against 

principles of fundamental fairness 

which require that all affected persons 

be afforded a reasonable amount of time 

to prepare for the effective date of its 

ruling.’’ 1 Where, as here, the final rule 

will be signed and made available on 

the EPA Web site more than 30 days 

before the effective date, but where the 

publication is likely to be delayed due 

to the complexity and length of the rule, 

the regulated entities are afforded this 

reasonable amount of time. This is 

particularly true given that most of the 

revisions being made in this package 

provide flexibilities to sources covered 

by the reporting rule or require no 

additional action by affected sources. 

Those amendments that increase burden 

affect a very small number of new 

facilities and include flexibility 

provisions such as Best Available 

Monitoring Methods. We balance these 

circumstances with the need for the 

amendments to be effective by January 

1, 2014; a delayed effective day would 

result in regulatory uncertainty, 

program disruption, and an inability to 

have the amendments (many of which 

clarify requirements, relieve burden, 

and/or are made at the request of the 

regulated facilities) effective for the 

2014 reporting year. Accordingly, we 

find good cause exists to make this rule 

effective on January 1, 2014, consistent 

with the purposes of 5 U.S.C. 553(d)(3). 

Judicial Review. Under CAA section 

307(b)(1), judicial review of this final 

rule is available only by filing a petition 

for review in the U.S. Court of Appeals 

for the District of Columbia Circuit (the 

Court) by January 28, 2014. 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. Section 307(d)(7)(B) of 

the CAA also provides a mechanism for 

the EPA to convene a proceeding for 

reconsideration, ‘‘[i]f the person raising 

an objection can demonstrate to EPA 

that it was impracticable to raise such 

objection within [the period for public 

comment] or if the grounds for such 

objection arose after the period for 

public comment (but within the time 

specified for judicial review) and if such 

objection is of central relevance to the 

outcome of the rule.’’ Any person 

seeking to make such a demonstration to 

us should submit a Petition for 

Reconsideration to the Office of the 

Administrator, Environmental 

Protection Agency, Room 3000, William 

Jefferson Clinton Building, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20460, with a copy to the person 

listed in the preceding FOR FURTHER

INFORMATION CONTACT section, and the 

Associate General Counsel for the Air 

and Radiation Law Office, Office of 

General Counsel (Mail Code 2344A), 

Environmental Protection Agency, 1200 

Pennsylvania Ave. NW., Washington, 

DC 20004. Note that 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 the EPA to 

enforce these requirements. 

Acronyms and Abbreviations. The 

following acronyms and abbreviations 

are used in this document. 

APA Administrative Procedure Act 

AR4 Fourth Assessment Report 

ASTM American Society for Testing and 

Materials 

BACT Best available control technology 

BAMM best available monitoring methods 

CAA Clean Air Act 

CAMD Clean Air Markets Division 

CBI confidential business information 

CEMS continuous emissions monitoring 

system 

CFR Code of Federal Regulations 

CH4 methane 

CO2 carbon dioxide 

CO2e carbon dioxide equivalent 

DOC degradable organic carbon 

DOE Department of Energy 

EAF electric arc furnace 

e-GGRT Electronic Greenhouse Gas 

Reporting Tool 

EIA Energy Information Administration 

EPA U.S. Environmental Protection Agency 

FBC fluidized bed combustor 

FLIGHT Facility Level Information on 

Green House Gases Tool 

FR Federal Register 

F–GHG fluorinated greenhouse gas 

F–HTF fluorinated heat transfer fluid 

GHG greenhouse gas 

GHGRP Greenhouse Gas Reporting Program 

GWP global warming potential 

HFC hydrofluorocarbon 

Hg mercury 

HHV high heat value 

HQ Headquarters 

ICR Information Collection Request 

IPCC Intergovernmental Panel on Climate 

Change 

ISBN International Standard Book Number 

LDC Local Distribution Company 

LPG liquid petroleum gases 

Mscf thousand standard cubic feet 

MSHA Mine Safety and Health 

Administration 

MSW municipal solid waste 

N2O nitrous oxide 

NAICS North American Industry 

Classification System 

NASA National Aeronautics and Space 

Administration 


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NGL natural gas liquid 

NSPS New Source Review Performance 

Standards 

NTTAA National Technology Transfer and 

Advancement Act of 1995 

OAQPS Office of Air Quality Planning and 

Standards 

OMB Office of Management and Budget 

ORIS Office of the Regulatory Information 

System 

PAL plant-wide applicability limits 

PFC perfluorocarbon 

PSD prevention of significant deterioration 

PTE potential to emit 

QA/QC quality assurance/quality control 

R&D Research and Development 

RFA Regulatory Flexibility Act 

SAR Second Assessment Report 

SF6 sulfur hexafluoride 

SIP State implementation plan 

TAR Third Assessment Report 

TPY tons per year 

UNFCCC United Nations Framework 

Convention on Climate Change 

U.S. United States 

UMRA Unfunded Mandates Reform Act of 

1995 

XML extensible markup language 

Organization of This Document. The 

following outline is provided to aid in 

locating information in this preamble. 

I. Background 

A. How is this preamble organized? 

B. Background on the Action 

C. Legal Authority 

D. What GWP values are addressed in this 

notice? 

II. Overview of Final Corrections and Other 

Amendments and Responses to Public 

Comment 

A. Subpart A—General Provisions 

a. Summary of Comments and Responses 

on the Revision of the GHGRP to 

Complement the Inventory and the Use 

of IPCC AR4 GWPs 

B. Subpart C—General Stationary Fuel 

Combustion Sources 

C. Subpart H—Cement Production 

D. Subpart K—Ferroalloy Production 

E. Subpart L—Fluorinated Gas Production 

F. Subpart N—Glass Production 

G. Subpart O—HFC-22 Production and 

HFC-23 Destruction 

H. Subpart P—Hydrogen Production 

I. Subpart Q—Iron and Steel Production 

J. Subpart W—Petroleum and Natural Gas 

Systems 

K. Subpart X—Petrochemical Production 

L. Subpart Y—Petroleum Refineries 

M. Subpart Z—Phosphoric Acid 

Production 

N. Subpart AA—Pulp and Paper 

Manufacturing 

O. Subpart BB—Silicon Carbide 

Production 

P. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

Q. Subpart FF—Underground Coal Mines 

R. Subpart HH—Municipal Solid Waste 

Landfills 

S. Subpart LL—Suppliers of Coal-Based 

Liquid Fuels 

T. Subpart MM—Suppliers of Petroleum 

Products 

U. Subpart NN—Suppliers of Natural Gas 

and Natural Gas Liquids 

V. Subpart PP—Suppliers of Carbon 

Dioxide 

W. Subpart QQ—Importers and Exporters 

of Fluorinated Greenhouse Gases 

Contained in Pre-Charged Equipment or 

Closed-Cell Foams 

X. Subpart RR—Geologic Sequestration of 

Carbon Dioxide 

Y. Subpart SS—Electrical Equipment 

Manufacture or Refurbishment 

Z. Subpart TT—Industrial Waste Landfills 

AA. Subpart UU—Injection of Carbon 

Dioxide 

BB. Other Technical Corrections 

CC. Subpart I Correction 

III. Schedule for the Final Amendments and 

Republication of Emission Estimates for 

Prior Year Reports 

A. Schedule for Final Amendments and 

Significant Comments 

B. Republication of Emissions Estimates for 

Prior Year Reports and Significant 

Comments 

IV. Confidentiality Determinations 

A. Final Confidentiality Determinations for 

New and Revised Data Elements 

B. Public Comments on the Proposed 

Confidentiality Determinations and 

Responses to Public Comment 

V. Impacts of the Final Rule 

A. Impacts of the Final Amendments Due 

to Revised Global Warming Potentials 

B. What are the impacts of the other 

amendments and revisions in this final 

rule? 

C. Summary of Comments and Responses 

Regarding Impacts 

VI. Statutory and Executive Order Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

B. Paperwork Reduction Act 

C. Regulatory Flexibility Act (RFA) 

D. Unfunded Mandates Reform Act 

(UMRA) 

E. Executive Order 13132: Federalism 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

H. Executive Order 13211: Actions That 

Significantly Affect Energy Supply, 

Distribution, or Use 

I. National Technology Transfer and 

Advancement Act 

J. Executive Order 12898: Federal Actions 

To Address Environmental Justice in 

Minority Populations and Low-Income 

Populations 

K. Congressional Review Act 

I. Background 

A. How is this preamble organized? 

The first section of this preamble 

provides background information 

regarding the origin of the final 

amendments. This section also 

discusses the EPA’s legal authority 

under the Clean Air Act to promulgate 

and amend the Greenhouse Gas 

Reporting Rule (40 CFR part 98, 

hereinafter referred to as ‘‘Part 98’’). 

Section II of this preamble contains 

information on the final revisions to 

Part 98 and is organized by Part 98 

subpart. It also describes the major 

changes made to each source category 

since proposal and provides a brief 

summary of significant public 

comments and the EPA’s responses on 

issues specific to each source category. 

Section III of this preamble discusses 

the effective date of the revisions for 

new and existing reporters and the 

EPA’s intent to publish a version of the 

Greenhouse Gas Reporting Program 

(GHGRP) data for the reporting years 

2010, 2011, and 2012 to reflect a 

consistent time-series. Section IV of this 

preamble discusses the confidentiality 

determinations for new or substantially 

revised (i.e., requiring additional or 

different data to be reported) data 

reporting elements. Section V of this 

preamble discusses the impacts of the 

final amendments, including the impact 

of revised global warming potentials 

(GWPs) on new and existing reporters. 

Finally, Section VI of this preamble 

describes the statutory and executive 

order requirements applicable to this 

action. 

B. Background on the Action 

Part 98 was initially published in the 

Federal Register on October 30, 2009 

(74 FR 56260). Part 98 became effective 

on December 29, 2009, and requires 

reporting of GHGs from certain facilities 

and suppliers. Subsequent notices were 

published in 2010 promulgating the 

requirements for subparts T, FF, II, and 

TT (75 FR 39736, July 12, 2010); 

subparts I, L, DD, QQ, and SS (75 FR 

74774, December 1, 2010); and subparts 

RR and UU (75 FR 75060, December 1, 

2010). A number of subparts have been 

revised since promulgation (75 FR 

79092, December 17, 2010; 76 FR 73866, 

November 29, 2011;77 FR 10373, 

February 22, 2012; 77 FR 51477, August 

24, 2012; and subpart I, signed by the 

Administrator on August 16, 2013). 

On April 2, 2013, the EPA proposed 

amendments to provisions in Part 98 in 

the ‘‘2013 Revisions to the Greenhouse 

Gas Reporting Rule and Proposed 

Confidentiality Determinations for New 

or Substantially Revised Data Elements’’ 

(hereinafter ‘‘2013 Revisions proposal’’) 

(77 FR 19802). The EPA is finalizing 

those amendments in this action, with 

certain changes following consideration 

of comments submitted. Responses to 

significant comments submitted on the 

proposed amendments can be found in 

Section II of this preamble. 

C. Legal Authority 

The EPA is finalizing these rule 

amendments under its existing CAA 


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2 IPCC Fourth Assessment Report (AR4), 2007. 

Climate Change 2007: The Physical Science Basis. 

Contribution of Working Group I to the Fourth 

Assessment Report of the Intergovernmental Panel 

on Climate Change [Core Writing Team, Pachauri, 

R.K and Reisinger, A. (eds.)]. IPCC, Geneva, 

Switzerland, 104 pp. 

3 Fluorinated greenhouse gases, as defined in 40 

CFR 98.6, include sulfur hexafluoride, nitrogen 

trifluoride, and any fluorocarbon except for 

authority provided in CAA section 114. 

As stated in the preamble to the 2009 

final GHG reporting rule (74 FR 56260, 

October 30, 2009), CAA section 

114(a)(1) provides the EPA broad 

authority to require the information 

required to be gathered by this rule 

because such data inform and are 

relevant to the EPA’s carrying out a 

wide variety of CAA provisions. See the 

preambles to the proposed (74 FR 

16448, April 10, 2009) and final Part 98 

(74 FR 56260) for further information. 

In addition, the EPA is finalizing 

confidentiality determinations for 

certain new or substantially revised data 

elements required under the proposed 

GHG Reporting Rule under its 

authorities provided in sections 114, 

301 and 307 of the CAA. As mentioned 

above, CAA section 114 provides the 

EPA authority to collect the information 

in Part 98. Section 114(c) requires that 

EPA make publicly available 

information obtained under section 114 

except for information (excluding 

emission data) that qualifies for 

confidential treatment. The 

Administrator has determined that this 

final rule is subject to the provisions of 

section 307(d) of the CAA. 

D. What GWP values are addressed in 

this notice? 

In the 2013 Revisions proposal, the 

EPA proposed to amend Table A–1 to 

Subpart A, General Provisions, Part 98 

(hereinafter referred to as ‘‘Table A–1’’) 

to revise the GWP values for certain 

GHGs that have been included in the 

Intergovernmental Panel for Climate 

Change (IPCC) Fourth Assessment 

Report (hereinafter referred to as ‘‘IPCC 

AR4’’ or ‘‘AR4’’) 2 and to add GWPs for 

26 additional fluorinated GHGs that are 

not currently included in the table. The 

GWPs in Table A–1 are used to convert 

the emissions and supply data for each 

greenhouse gas into carbon dioxide 

equivalents (CO2e). 

As part of this action, the EPA is 

finalizing amendments to Table A–1 to 

revise the GWPs of certain GHGs that 

are already listed in the table to 

incorporate GWPs from the IPCC AR4. 

The EPA is finalizing these changes for 

two reasons. First, the revisions improve 

the quality of reported emissions and 

supply by reflecting improved scientific 

understanding of direct and indirect 

radiative forcing and atmospheric 

lifetimes of certain GHGs. Second, for 

these GHGs, the revisions ensure 

comparability of data collected in the 

GHGRP to the Inventory of U.S. 

Greenhouse Gas Emissions and Sinks 

(hereinafter referred to as ‘‘Inventory’’) 

that the EPA compiles annually to meet 

international commitments and to GHG 

inventories prepared by other countries. 

After carefully considering comments 

received, the EPA is not finalizing in 

this rulemaking the GWPs for the 26 

additional fluorinated GHGs not 

included in the IPCC AR4 that we 

proposed in the 2013 Revisions 

proposal. Based on comments that EPA 

should not include compounds that are 

not included in an IPCC study or peerreviewed, as well as comments on 

permitting applicability, the EPA is 

reevaluating its approach to assigning 

GWPs for compounds not included in 

the IPCC AR4 and may address these 

compounds in a separate future action. 

II. Overview of Final Corrections and 

Other Amendments and Responses to 

Public Comment 

The EPA is finalizing technical 

corrections, clarifying revisions, and 

other amendments to Part 98 to improve 

the quality and consistency of the data 

collected by the EPA. Many of the 

changes proposed were in response to 

feedback received from stakeholders 

during program implementation. 

Sections II.A through II.AA of this 

preamble describe the more substantive 

corrections, clarifying, and other 

amendments that we are finalizing for 

each subpart, including changes that 

affect the applicability of a subpart, 

changes that affect the applicability of a 

calculation method to a specific source 

at a facility, changes or corrections to 

calculation methods that substantially 

revise the calculation method or output 

of the equation, revisions to data 

reporting requirements that 

substantively clarify the reported data 

element or introduce a new data 

element, clarifications of general 

monitoring and quality assurance 

requirements, and changes to add new 

definitions. We have summarized the 

amendments to each subpart in the 

memorandum, ‘‘Final Table of 2013 

Revisions to the Greenhouse Gas 

Reporting Rule’’ (hereinafter referred to 

as the ‘‘Table of 2013 Revisions’’) 

available in the docket for this 

rulemaking (EPA–HQ–OAR–2012– 

0934). The Table of 2013 Revisions 

describes each final change within a 

subpart and includes many minor 

revisions that were proposed but are not 

discussed in detail in this preamble 

(e.g., straightforward clarifications of 

requirements to better reflect the EPA’s 

intent, simple corrections to calculation 

terms or cross-references that do not 

affect the output of calculations, 

harmonizing changes within a subpart 

(such as changes to terminology), simple 

editorial and minor error corrections, or 

removal of redundant text). These minor 

revisions are not discussed in this 

preamble because they do not 

substantially change the applicability, 

calculation, monitoring, recordkeeping, 

or reporting requirements of Part 98. 

The Table of 2013 Revisions also 

provides the existing rule text, the 

finalized changes, and indications of 

which amendments are being finalized 

as proposed and which amendments 

differ from the changes proposed in the 

2013 Revisions proposal. 

The amendments described in this 

preamble are listed in this section by 

subpart. The amendments to each 

subpart are followed by a summary of 

the major comments on those 

amendments and the EPA’s responses. 

Minor comments received on the 

proposed amendments and the EPA’s 

responses are available in the docket to 

this rulemaking (EPA–HQ–OAR–2011– 

0934). Some of the comments received 

on the proposed amendments included 

commenter suggestions of additional 

revisions to Part 98 that were beyond 

the scope of the proposed rulemaking. 

These additional revisions are identified 

in Sections II.K, II.N, II.R, and II.BB of 

this preamble. Although we are not 

including the suggested revisions in this 

final rule, the EPA reserves its 

discretion to consider these comments 

in any future rulemaking. 

A complete listing of all comments 

and the EPA’s responses is located in 

the comment response document in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934. 

Additional rationale for these 

amendments is available in the 

preamble to the proposed rule 

(78 FR 19802). 

A. Subpart A—General Provisions 

1. Summary of Final Amendments to 

Subpart A—Global Warming Potentials 

In this action, we are revising Table 

A–1 to subpart A of Part 98 by updating 

the GWP values of certain compounds. 

These changes affect facilities and 

suppliers under Part 98 reporting the 

following greenhouse gases: Methane 

(CH4), nitrous oxide (N2O), sulfur 

hexafluoride (SF6), certain 

hydrofluorocarbons (HFCs), certain 

perfluorocarbons (PFCs), and certain 

other fluorinated greenhouse gases 

(F–GHGs).3


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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. 

4Each chemical substance has a universal, unique 

identifier maintained in the Chemical Abstracts 

Service (CAS) Registry and known as the 

substance’s CAS Number. See http://www.cas.org/

content/chemical-substances. 

As proposed, we are revising GWPs 

for GHGs already in Table A–1 to reflect 

more accurate GWPs from the IPCC AR4 

to better characterize the climate 

impacts of individual GHGs and to 

ensure continued consistency with 

other U.S. climate programs, including 

the Inventory. The amendments to the 

GWPs in Table A–1 that we are 

finalizing in this notice are discussed in 

Section II.A.1 of this preamble. The 

EPA’s response to comments received 

on the proposed revisions to Table A– 

1 are in Section II.A.2 of this preamble. 

The schedule for implementing these 

amendments is discussed in Section 

III.A of this preamble. Section III.B of 

this preamble clarifies that the EPA is 

not requiring the revision of reports 

previously submitted to reflect the 

revised GWPs in Table A–1 or other 

amendments in this final rulemaking. 

Prior year reports, using original GWPs, 

will remain publicly available. 

However, the EPA will also publish a 

version of the CO2e emissions and 

supply estimates for the reporting years 

2010, 2011, and 2012 using the revised 

GWPs in Table A–1. This will allow the 

Agency and public to view and compare 

trends in GHG data, beginning with the 

first year of GHGRP reporting, using 

consistent GWPs and without placing 

any additional burden on reporters. 

As discussed in the preamble to the 

2013 Revisions proposal, the revisions 

to the GWPs in Table A–1 will change 

not only the amount of CO2e reported by 

existing reporters but also change the 

number of reporters subject to Part 98. 

Some facilities to which the rule did not 

previously apply will now meet the 

thresholds for reporting based on 

increases in calculated CO2e. The EPA 

received specific comments regarding 

the expansion of applicability that could 

occur in certain sectors due to the 

revision of the GWP for methane and 

due to certain sector-specific 

applicability and reporting 

characteristics. For Municipal Solid 

Waste (MSW) Landfills, commenters 

raised a specific concern related to the 

applicability for certain closed landfills 

that would become subject to Part 98 

due to the revised GWP for methane. To 

address this concern, the EPA is 

amending subpart HH, which covers 

MSW Landfills, as discussed in Section 

II.R of this preamble. 

The EPA has also updated the impacts 

analysis to address comments received 

on the proposed rule regarding 

compliance costs and to incorporate 

data from the 2011 reporting year that 

became available following the 

publication of the proposed rule. The 

impacts of the final amendments for 

affected subparts, including the number 

of new reporters for each subpart, are 

discussed in Section V of this preamble. 

Summary of Final Amendments to 

Global Warming Potentials. For 

compounds that are included in the 

IPCC AR4, the EPA is adopting the AR4 

GWPs as proposed. This approach will 

increase the accuracy of the CO2e 

estimates reported and is in keeping 

with the Agency’s intent to have the 

GHGRP complement data compiled for 

the annual Inventory and other EPA 

programs. Table 2 of this preamble lists 

the final GWP values for each GHG. As 

discussed in Section I.D of this 

preamble, the EPA may address 

compounds that are not included in 

AR4 in a separate action. 

TABLE 2—GHGS WITH REVISED GWPS FOR TABLE A–1 

Name CAS No.4

Global 

warming 

potential 

Methane ................................................................................................................................................................... 74–82–8 25 

Nitrous oxide ............................................................................................................................................................ 10024–97–2 298 

HFC-23 .................................................................................................................................................................... 75–46–7 14,800 

HFC-32 .................................................................................................................................................................... 75–10–5 675 

HFC-41 .................................................................................................................................................................... 593–53–3 92 

HFC-125 .................................................................................................................................................................. 354–33–6 3,500 

HFC-134 .................................................................................................................................................................. 359–35–3 1,100 

HFC-134a ................................................................................................................................................................ 811–97–2 1,430 

HFC-143 .................................................................................................................................................................. 430–66–0 353 

HFC-143a ................................................................................................................................................................ 420–46–2 4,470 

HFC-152a ................................................................................................................................................................ 75–37–6 124 

HFC-227ea .............................................................................................................................................................. 431–89–0 3,220 

HFC-236fa ............................................................................................................................................................... 690–39–1 9,810 

HFC-245ca ............................................................................................................................................................... 679–86–7 693 

HFC-43–10mee ....................................................................................................................................................... 138495–42–8 1,640 

Sulfur hexafluoride ................................................................................................................................................... 2551–62–4 22,800 

PFC-14 (Perfluoromethane) .................................................................................................................................... 75–73–0 7,390 

PFC-116 (Perfluoroethane) ..................................................................................................................................... 76–16–4 12,200 

PFC-218 (Perfluoropropane) ................................................................................................................................... 76–19–7 8,830 

PFC-3-1-10 (Perfluorobutane) ................................................................................................................................. 355-25-9 8,860 

Perfluorocyclobutane ............................................................................................................................................... 115–25–3 10,300 

PFC-4-1-12 (Perfluoropentane) ............................................................................................................................... 678–26–2 9,160 

PFC-5-1-14 (Perfluorohexane) ................................................................................................................................ 355–42–0 9,300 

We are not revising GWPs for the 

remaining compounds in Table A–1, 

which were promulgated in the original 

final Part 98 rulemaking. Because the 

remaining F–GHGs in Table A–1 were 

not addressed by the IPCC’s Second 

Assessment Report (SAR) at the time 

that the original Part 98 was finalized, 

the EPA promulgated GWPs for these 

compounds from the IPCC AR4 in the 

October 30, 2009 final Part 98. The only 

exception was the GWP for sevoflurane, 

which was not available in the SAR or 

AR4; the EPA promulgated the GWP for 

sevoflurane based on a peer-reviewed 

study. 

The EPA received multiple comments 

on the proposed revisions of the GWPs 


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5Parties to the UNFCCC, including the U.S., have 

agreed to submit annual reports in 2015 and future 

years using GWP values from the IPCC AR4. 

6The President’s Climate Action Plan, Executive 

Office of the President, June 2013, p. 4, http://

www.whitehouse.gov/sites/default/files/image/

president27sclimateactionplan.pdf; Jonathan 

Pershing, Clarification of the U.S. Economy-Wide 

Target, http://unfccc.int/files/bodies/awg-lca/

application/pdf/20120517_usa_0940.pdf; and 

UNFCCC GE.11–70204, Subsidiary Body for 

Scientific and Technological Advice 34th Session, 

6–16 June 2011, Compilation of economy-wide 

emission reduction targets to be implemented by 

Parties included in Annex I to the Convention, 

FCCC/SB/2011/INF.1/Rev.1, pp. 7–8, http://

unfccc.int/resource/docs/2011/sb/eng/inf01r01.pdf. 

in Table A–1. In some cases, 

commenters disagreed with the need to 

update the GHGRP to match the values 

used in the Inventory or disagreed with 

the use of AR4 values. For example, we 

received multiple comments requesting 

that the EPA consider more recently 

published values, or wait until the 

publication of the IPCC Fifth 

Assessment Report (hereinafter referred 

to as ‘‘AR5’’) to amend the GWPs in 

Table A–1. As discussed in the 

preamble to the proposed rule, the EPA 

is adopting AR4 values for certain 

compounds currently in Table A–1 to 

increase the accuracy of the CO2e 

estimates collected under the GHGRP to 

better inform EPA policies. The AR4 

GWPs will complement the reporting 

metrics used in other U.S. climate 

programs, including the Inventory that 

is submitted to the United Nations 

Framework Convention on Climate 

Change (UNFCCC).5 The AR4 GWPs 

will also ensure the compatibility of 

Part 98 with the President’s Climate 

Action Plan and the U.S. commitment to 

GHG emission reductions to the United 

Nations, both of which reiterate 

President Obama’s 2009 pledge that the 

U.S. would reduce its GHG emissions by 

17 percent below 2005 levels by 2020, 

which both the U.S. and United Nations 

will assess using AR4 GWPs.6 We view 

AR5 values as unlikely to come into use 

by the UNFCCC or other widespread use 

for several years. For example, the IPCC 

finalized AR4 in 2007 but the UNFCCC 

has adopted these values for parties’ 

Inventory submissions just starting in 

2015. Therefore, for those compounds in 

Table A–1 for which a GWP is available 

in the AR4, we are adopting the AR4 

values as proposed and are not adopting 

GWPs from AR5. See Section II.A.2.a of 

this preamble for the EPA’s response to 

comments related to the adoption of 

AR4 GWPs. 

We are not including GWPs from the 

World Meteorological Organization 

(WMO) Scientific Assessment of Ozone 

Depletion: 2010 (Global Ozone Research 

and Monitoring Project-Report No. 52, 

516 pp., Geneva, Switzerland, 2011) in 

this final rule. In the proposed rule, the 

EPA sought comment on whether GWPs 

for fluorinated ethers and alcohols from 

the WMO Scientific Assessment should 

be adopted in Table A–1. We did not 

receive any comments related to the 

WMO on this rulemaking; without any 

commenter support, we have decided 

not to adopt GWPs from that assessment 

at this time. 

The subpart W calculations for annual 

mass of GHG emissions for gas 

pneumatic device venting and natural 

gas driven pneumatic pump venting in 

CO2e are calculated using a conversion 

factor that was developed using the 

methane GWP from Table A–1. In 

addition, subpart W total GHG 

emissions are calculated using an 

equation that references numeric GWPs, 

instead of directly referencing Table A– 

1. Because the GWP values that inform 

the methane calculations in these three 

equations reference the previous GWP 

value, each equation needs to be 

amended separately to account for the 

change in the numeric GWP value for 

methane in Table A–1. While the EPA 

proposed that the new GWP apply 

throughout all of Part 98, the EPA did 

not specifically propose amendments to 

the regulatory text referencing the 

numeric GWP in these three discrete 

equations. In addition to finalizing the 

GWP value for methane in Table A–1, 

we are also amending the methane 

conversion factor and methane GWP 

used in three subpart W equations to 

ensure the correct GWP value for 

methane in Table A–1 is used in these 

calculations. See Section II.J of this 

preamble for more information. 

2. Summary of Comments and 

Responses—Global Warming Potentials 

a. Summary of Comments and 

Responses on the Revision of the 

GHGRP To Complement the Inventory 

and the Use of IPCC AR4 GWPs 

This section summarizes the 

significant comments and responses 

related to the revision of the GHGRP to 

incorporate AR4 GWP values in Table 

A–1 to complement the Inventory. See 

the comment response document in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses. 

Comment: Four commenters 

expressed support for the EPA’s 

proposal to revise the GHGRP to 

complement the Inventory. One 

commenter stated that the revision to 

the GWP of methane will enable the 

EPA to use the subpart W reported data 

to update the annual Inventory. They 

noted that the subpart W data will 

improve the accuracy of the Inventory’s 

estimated methane emissions for the 

natural gas sector. Several commenters 

supported adoption of AR4 GWP values, 

because the IPCC is the international 

leader in assessing climate change and 

determining a scientifically based and 

standardized list of GHGs and 

associated GWPs. These commenters 

reiterated that the EPA’s commitment to 

report emissions using IPCC methods is 

well articulated in the preamble to the 

proposed rule, which states that the 

EPA is proposing revisions to Table A– 

1 ‘‘to ensure continued consistency with 

the Inventory as the Inventory begins to 

use GWPs from the IPCC Fourth 

Assessment Report’’ (77 FR 19807). 

Three commenters disagreed with 

EPA’s proposal to incorporate AR4 GWP 

values. These commenters asserted that 

there is not a strong scientific basis for 

updating the GWPs in Table A–1 to 

subpart A of Part 98 to reflect the values 

adopted in the AR4. The commenters 

contended that the proposed GWPs are 

not necessarily improved or more 

technically precise than the values EPA 

has already adopted. The commenters 

noted that the IPCC AR4 discussed some 

of the uncertainties associated with the 

AR4 GWPs. They stated that the GWPs 

adopted by the IPCC are derived using 

certain simplifications that have been 

the subject of criticism and that 

shortcomings in scientific knowledge 

make objective assessment of GHG 

impacts difficult. 

Some commenters suggested that the 

EPA wait to revise Table A–1 until after 

IPCC AR5 is released. These 

commenters contended that 

international reporting data are outdated 

(for instance, they stated that GWPs 

from the IPPC Second Assessment 

Report, which was finalized in 1995, are 

required to be used for inventory 

reporting until 2015, when values from 

AR4, which was finalized in 2007, will 

be substituted), and are concerned that 

AR5 would not be incorporated into 

inventory reporting until 2020 or later. 

They asserted that the EPA’s logic in 

proposing to replace the GWP values in 

the SAR with those in the AR4 should 

apply equally to replacing the GWP 

values from the AR4 with those in the 

AR5 when they become available. They 

stated that U.S. national and state 

regulation must be based on the latest 

and most robust scientific consensus of 

climate science, including appropriate 

GWPs, and that the advance of U.S. 

science and regulatory policy should 

not be slowed by a non-identical 

international emission reporting process 

designed for other purposes. 

Commenters also disputed the EPA’s 

rationale of being bound by UNFCCC 

reporting guidelines to use AR4 GWPs 


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7 IPCC TAR WG1 (2001), Houghton, J.T.; Ding, Y.; 

Griggs, D.J.; Noguer, M.; van der Linden, P.J.; Dai, 

X.; Maskell, K.; and Johnson, C.A., ed., Climate 

Change 2001: The Scientific Basis, Contribution of 

Working Group I to the Third Assessment Report 

of the Intergovernmental Panel on Climate Change, 

Cambridge University Press, ISBN0–521–80767–0 

(pb: 0–521–01495–6), p. 385. 

8 IPCC TAR WG1, p. 386. 

9 IPCC Fourth Assessment Report (AR4), 2007. 

Climate Change 2007: The Physical Science Basis. 

Contribution of Working Group I to the Fourth 

Assessment Report of the Intergovernmental Panel 

on Climate Change [Core Writing Team, Pachauri, 

R.K and Reisinger, A. (eds.)]. IPCC, Geneva, 

Switzerland, p. 211. 

10AR4, p. 211. 11AR4, p. 214. 

starting in 2015 for purposes of annual 

reports of national GHG inventories to 

the UNFCCC. One commenter stated 

that not incorporating AR5 GWPs is 

unreasonable and will potentially 

compromise the integrity of the GHGRP 

and future regulatory efforts based 

thereon. While the commenter 

acknowledged the benefit in reporting 

national inventories from around the 

world on a consistent basis, they 

maintained that the published GHGRP 

data and the national GHG inventory are 

produced for different purposes and 

need not use the same GWP values. The 

commenter stated that the programs do 

not cover the same emissions or 

emission sources, noting, for example, 

that the GHGRP requires reporting of a 

wide variety of pollutants that are not 

required to be included in the national 

inventories reported to UNFCCC. 

Response: As described in the 

preamble of the proposed GHG 

Reporting Rule (74 FR 16448, April 10, 

2009), the GHGRP is intended to 

provide data to support EPA climate 

policy and to supplement and 

complement existing U.S. government 

programs related to climate policy and 

research, including the Inventory 

submitted to the UNFCCC. The GHGRP 

provides data to develop and inform the 

Inventory and other U.S. federal and 

state climate programs by advancing the 

understanding of emission processes 

and monitoring methodologies for 

particular source categories or sectors. 

For example, GHGRP data published 

through the EPA’s Facility Level 

Information on Green House gases Tool 

(FLIGHT) may be used by state and local 

entities to better understand the 

contribution of emissions from specific 

regional industries, or by EPA 

regulatory programs to review emissions 

from certain facilities within an 

industry to inform policy decisions. The 

GHGRP also complements the Inventory 

and other U.S. programs by providing 

data from individual facilities and 

suppliers above certain thresholds. 

Collected facility, unit, and processlevel GHG data from the GHGRP 

supplements national statistics and 

improves the emission estimates 

presented in the Inventory. During the 

development of Part 98, the EPA 

generally proposed and finalized 

estimation methodologies and reporting 

metrics that were based on recent 

scientific data and that were consistent 

with the international reporting 

standards under the UNFCCC and the 

Inventory. 

The goal of Part 98 is to collect data 

of sufficient accuracy and quality to 

inform future climate policy 

development. In this final rule, the EPA 

is adopting the proposed AR4 values in 

Table A–1 to ensure more accurate CO2e 

emission and supply estimates are 

collected for the GHGRP. As noted in 

the preamble to the proposed 

amendments (78 FR 19808), the IPCC 

AR4 GWPs reflect advances in scientific 

knowledge on the radiative efficiencies 

and atmospheric lifetimes of carbon 

dioxide and certain greenhouse gases, 

taking into account the increase in 

modeled atmospheric CO2

concentrations since the SAR was 

published. The GWP of a given gas is 

dependent on the radiative efficiency of 

that gas, the lifetime of that gas, and any 

indirect forcing effects of that gas, all 

relative to the same values for carbon 

dioxide. The IPCC Third Assessment 

Report (TAR) used updated values of 

these factors to provide more accurate 

GWPs than did the IPCC SAR, and 

similarly the IPCC Fourth Assessment 

Report (AR4) was an improvement over 

the TAR. The TAR stated that GWP 

updates were made for those chemicals 

‘‘where significantly different new 

laboratory or radiative transfer results 

have been published.’’ 7 In addition, the 

TAR notes that the radiative efficiency 

of several gases, including CO2, depend 

on the background concentration. As the 

background concentration rises, the 

radiative efficiency of an additional 

increment of that gas decreases. Due to 

updated background concentrations and 

other updates, the TAR calculated a 

value for the reference CO2 gas that was 

13 percent smaller than the similar 

calculation for the SAR; because all 

GWPs are calculated with reference to 

CO2, this increases other GWPs 

proportionally.8 The AR4 calculation for 

the reference CO2 gas, taking into 

account the continued increase in 

background concentration, was 8.7 

percent lower than the TAR value.9 The 

AR4 also relied on a number of 

publications that used experiments to 

improve the estimates of the radiative 

efficiencies of a number of the 

fluorinated compounds, with changes of 

up to 40 percent in those values for 

some compounds.10 In addition, 

improved estimates of the effects of 

methane on stratospheric water vapor, 

itself a greenhouse gas, led to an 

increase in the factor used to estimate 

the GWP of methane due to that effect 

of 15 percent rather than 5 percent as in 

the TAR and SAR.11

As such, each successive assessment 

provides more accurate GWP estimates 

as experiments and improved 

computational methods lead to more 

accurate estimates of the radiative 

efficiencies, atmospheric lifetimes, and 

indirect effects of the various gases. 

Additionally, the more recent 

assessments reflect more up-to-date 

background concentrations, which are 

necessary for accurately calculating the 

radiative efficiency of the different 

gases. The AR4 GWPs for these F–GHGs 

are therefore more accurate for 

comparison of the climate impacts of 

individual GHGs than the values from 

the IPCC SAR that were originally 

adopted in Table A–1, and are more 

appropriate for supporting the overall 

goals of the GHGRP. For the reasons 

stated above, we disagree with the 

commenters that stated there is not a 

strong scientific basis for updating the 

GWPs in Table A–1 to reflect the values 

in the IPCC AR4. 

In the development of the 2009 final 

reporting rule, the EPA responded to 

concerns regarding the use of the GWP 

metric and determined that GWP is the 

most prudent and appropriate approach 

for comparison of the climate impacts of 

individual greenhouse gases that have 

varying radiative efficiencies and 

atmospheric lifetimes (see Volume 2 of 

USEPA’s Response to Public Comments 

on the Mandatory Greenhouse Gas 

Reporting Rule: Selection of Reporting 

Thresholds, Greenhouses Gases, and De 

Minimis Provisions, Docket Id. No. 

EPA–HQ–OAR–2008–0508–2259). The 

GWP metric inherently reflects the 

atmospheric life-span of GHGs and is an 

internationally accepted standard 

recognized and utilized by the IPCC, 

UNFCCC, and Kyoto Protocol. 

As discussed in the preamble to the 

proposed amendments, one of the 

reasons we proposed AR4 GWPs for the 

chemicals currently in Table A–1 was to 

maintain consistency with the Inventory 

and similar U.S. domestic programs. 

This is consistent with our approach to 

date under the GHGRP; in the 2009 final 

reporting rule, the EPA specifically 

chose to use GWPs published in the 

IPCC Second Assessment Report for 

GHGs included in that report to allow 

comparisons between the Inventory, 

other U.S. climate programs, and the 

GHGRP. The EPA has received 


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12The President’s Climate Action Plan, Executive 

Office of the President, June 2013, p. 4, http://

www.whitehouse.gov/sites/default/files/image/

president27sclimateactionplan.pdf; Jonathan 

Pershing, Clarification of the U.S. Economy-Wide 

Target, http://unfccc.int/files/bodies/awg-lca/

application/pdf/20120517_usa_0940.pdf; and 

UNFCCC GE.11–70204, Subsidiary Body for 

Scientific and Technological Advice 34th Session, 

6–16 June 2011, Compilation of economy-wide 

emission reduction targets to be implemented by 

Parties included in Annex I to the Convention, 

FCCC/SB/2011/INF.1/Rev.1, pp. 7–8, http://

unfccc.int/resource/docs/2011/sb/eng/inf01r01.pdf. 

13While the AR5 GWPs have not been publicly 

available during the development of this rule, the 

GWPs published in a recent article are likely to be 

the basis of updated GWPs in AR5. See Hodnebrog, 

;., M. Etminan, J. S. Fuglestvedt, G. Marston, G. 

Myhre, C. J. Nielsen, K. P. Shine, and T. J. 

Wallington, ‘‘Global Warming Potentials and 

Radiative Efficiencies of Halocarbons and Related 

Compounds: A Comprehensive Review,’’ Reviews of 

Geophysics, Accepted manuscript online: 24 APR 

2013. 

14AR4 was published in 2007 and is being 

adopted for Inventory reporting starting in 2015. 

‘‘Revision of the UNFCCC reporting guidelines on 

annual inventories for Parties included in Annex I 

to the Convention,’’ FCCC/CP/2011/9/Add.2, 

Decision 6/CP 17, 15 March 2012, available at 

http://unfccc.int/resource/docs/2011/cop17/eng/

09a02.pdf#page=23. AR5 is anticipated to be 

published in late 2013; adoption of AR5 for 

Inventory reporting is likely to be on a similar 

timeframe, if at all. 

encouragement from stakeholders to 

continue to use GHG data from the 

GHGRP to complement and support 

development of the Inventory, such as 

for improvements to emissions 

estimates from the petroleum and 

natural gas production source 

categories. Using consistent GWPs 

allows for more efficient review of data 

collected through the GHGRP and other 

U.S. climate programs and reduces the 

potential errors that may arise when 

comparing multiple data sets or 

converting GHG emissions or supply 

based on separate GWPs. It also reduces 

the burden for reporters and agencies to 

keep track of separate GWPs when 

submitting information to these 

programs. 

As discussed in the preamble to the 

proposed amendments, countries that 

submit inventories to the UNFCCC have 

decided to begin using GWP values from 

the IPCC AR4 for annual inventories 

submitted in 2015 and expected to 

continue to use the AR4 GWPs for 

several years thereafter. Accordingly, 

the United States has a policy 

commitment to begin using GWP values 

from the IPCC AR4 for annual 

inventories submitted in 2015 and 

beyond. Because one of the purposes of 

the GHGRP is to supplement the 

Inventory, the EPA determined that it is 

most appropriate to adopt the AR4 

GWPs for the compounds currently in 

Table A–1 for the annual GHGRP 

reports submitted in 2014, in order to 

meet the needs of the Inventory 

timeframe. As noted in Section II.A.1 of 

this preamble, use of the AR4 GWPs 

will also ensure compatibility of the 

GHGRP with the President’s Climate 

Action Plan and the U.S. commitment to 

GHG emission reductions to the United 

Nations.12

The EPA agrees with commenters that 

using the latest and most robust GWPs 

from the IPCC AR5 for the compounds 

currently in Table A–1, once AR5 is 

published, could lead to more accurate 

assessments of climate impacts in the 

future. We considered waiting until 

publication of AR5 values and adopting 

those values for Table A–1, as suggested 

by commenters. We balanced the 

benefits of adopting more recent GWPs 

to better characterize national GHG 

emissions and inform EPA policies with 

the benefit of retaining consistency 

across national and international 

programs, particularly the Inventory, for 

compounds that are included in AR4, 

and we believe that a potential gain in 

accuracy does not justify the loss of 

consistency with UNFCCC reporting 

(and associated policy analysis) that 

would result.13 Specifically, we 

considered that even though we 

anticipate that the AR5 GWPs will be 

published in coming months, the AR5 

assessment has not been yet adopted by 

the UNFCCC or other national or 

international programs and is not likely 

to be in the near future.14 Wholesale 

adoption of AR5 GWPs by the GHGRP 

while other EPA and international 

programs are using AR4 GWPs likely 

would cause stakeholder confusion, 

create an ongoing need to explain the 

distinction in GWPs in subsequent 

actions, and complicate decisionmaking. 

The adoption of AR4 GWPs for those 

compounds currently in Table A–1 will 

improve the GHGRP, and by extension, 

EPA climate policies, by incorporating 

more scientifically accurate GWPs than 

the SAR values originally adopted in 

Table A–1. This approach also ensures 

that the GHGRP uses widely relied on, 

published, peer-reviewed GWP data. As 

discussed in the next comment and 

response, the EPA may consider 

adoption of AR5 GWPs or other GWP 

values for compounds currently listed 

in Table A–1 if these values are adopted 

by the UNFCCC and the global 

community. 

Comment: Several commenters were 

concerned about the frequency with 

which the EPA intends to update Table 

A–1 in the future. One commenter 

contended that the EPA’s proposed 

GWP revisions will not achieve 

consistency with the Inventory because 

it would create confusion across 

reporting years. The commenter stated 

that industry should not have to adjust 

data collection and reporting protocols 

due to revised GWPs after only three 

years of reporting. Commenters were 

concerned that frequent future revisions 

to GWPs would place unnecessary 

burdens on reporters and would affect 

other regulatory programs that rely on 

the Part 98 GWPs, such as the title V 

and Prevention of Significant 

Deterioration (PSD) permitting programs 

under the EPA’s Tailoring Rule (75 FR 

31532, June 3, 2010). Two additional 

commenters expressed concern that 

future revisions to the GWP values by 

the IPCC would drive further rule 

revisions by the EPA. The commenters 

stated that if the EPA’s desire is to 

ensure consistency between the 

Inventory and GHGRP, future changes to 

the GWP values seem inevitable. They 

stated that these changes, if adopted, 

may require sources to constantly 

change their data gathering and 

evaluation protocols for reporting and 

require sources to continually revise (or 

have the EPA revise) their prior year 

submissions. 

Response: At the time that Part 98 was 

proposed, it was the EPA’s intent to 

require reporting of emissions of 

individual gases as well as emissions in 

CO2e. We explained that because GHGs 

have different heat trapping capacities, 

they are not directly comparable 

without translating them into common 

units (74 FR 16453, April 10, 2009). We 

intended at that time to allow for future 

updates of the GWPs in Table A–1 to 

reflect advances in the scientific 

research on the heat trapping capacities 

of individual gases. For example, in the 

proposed 2009 GHG Reporting Rule, the 

EPA explained the collection of 

individual gas emissions and 

conversion of emissions to CO2e and 

noted that ‘‘reporting the quantity and 

type of gas emitted allows for future 

recalculation of CO2e emissions in the 

event that GWP factors change’’ (74 FR 

16448, April 10, 2009). 

As discussed in this section of this 

preamble, we have determined that it is 

appropriate to update certain GWP 

values already in Table A–1 to the IPCC 

AR4 values, adopted by the UNFCCC for 

national inventory reporting beginning 

in 2015, at this time. However, as stated 

in the preamble to the 2013 Revisions 

proposal, the EPA does not intend to 

revise the GWPs in Table A–1 each time 

new data are published in the scientific 

literature. Instead, we intend to update 

GWPs periodically in the future as the 

UNFCCC reporting guidelines change 

(i.e., when the UNFCCC adopts values 

from a future IPCC assessment for 


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15Shindell, D. T., Faluvegi, G., Koch, D. M., 

Schmidt, G. A., Unger, N., & Bauer, S. E. (2009). 

Improved attribution of climate forcing to 

emissions. Science, 326(5953), 716–718. 

16 IPCC, Climate Change 1994: Radiative Forcing 

of Climate Change and an Evaluation of the IPCC 

IS92 Emission Scenarios 229. (John T. Houghton et 

al., ed., Cambridge University Press 1995). 

compounds that are currently listed in 

AR4) and possibly as updated GWPs for 

new compounds are published in IPCC 

or WMO assessments or in other peerreviewed literature. We note that there 

are generally significant lag times in 

adoption of new values by the UNFCCC. 

In the past, the parties to the UNFCCC 

have only infrequently updated the 

GWPs that countries use to report their 

GHG emissions (i.e., less than once 

every 10 years). Significant time may 

pass between publication of peerreviewed GWPs, their adoption into 

IPCC scientific assessments of GWPs, 

and their subsequent adoption into the 

UNFCCC reporting guidelines. With 

these considerations, we will continue 

to weigh the benefits of updating the 

GHGRP GWPs to more current values 

against the benefits of maintaining the 

values used by the international 

reporting community and the values 

used in other U.S. climate programs, 

such as the joint EPA and National 

Highway Traffic Safety Administration 

(NHTSA) Light-Duty Vehicle GHG 

Emission Standards. The latter benefits 

include minimizing confusion and 

policy uncertainty. However, we 

consider periodic updates to Table A–1 

to be necessary to ensure that the 

GHGRP incorporates scientific advances 

in climate science to best inform EPA 

policies and programs, such as 

regulatory options and voluntary 

reduction partnerships, and to provide 

accurate information to other 

stakeholders. We also acknowledge that 

although the GHGRP may collect and 

publish data using the AR4 GWPs or 

GWPs published in other peer-reviewed 

literature, the EPA and other 

policymakers may analyze the data 

collected using other GWPs as desired. 

For example, we received comments 

that the EPA should finalize the GWP 

values from IPCC AR5 when they are 

released (discussed above in this section 

of the preamble); while we are instead 

finalizing the GWP values from AR4, the 

GHGRP data is presented in a manner 

that stakeholders can calculate CO2

other GWPS as desired. 

The EPA recognizes that for some 

subparts, adoption of higher GWPs for 

certain compounds in Table A–1 (e.g., 

methane) could potentially place some 

facilities above the reporting threshold 

for Part 98 and increase the number of 

facilities that are affected by other EPA 

or state programs that have thresholds 

that rely on the GWPs in Table A–1 

(e.g., EPA’s Tailoring Rule) (see Section 

II.A.2.c and Section V of this 

preamble).We acknowledge that 

frequent adoption of new GWP values 

could also disrupt the continuity of data 

across a time-series, making it more 

difficult for regulatory agencies and 

stakeholders to analyze and compare 

previously reported data. The EPA is 

addressing that concern for these final 

amendments by publishing a consistent 

time series with the revised GWPs while 

maintaining the certified emission 

reports; see Section III.B of this 

preamble for more information. With 

these considerations, the Agency 

intends to balance the need to update 

Table A–1 to incorporate scientific 

advancements with the impact on the 

number of reporters subject to Part 98, 

the accuracy of reported emissions, and 

the impacts to other regulatory 

programs. 

b. Summary of Comments and 

Responses on the Use of 100-Year GWPs 

Comment: One commenter agreed that 

the 100-year GWPs should be updated, 

but objected to the value the EPA 

proposed for methane, stating that the 

GWP of 25 (from the IPCC AR4) is out 

of date. The commenter stated that 

subsequent to the completion of AR4, 

the National Aeronautics and Space 

Administration (NASA) published an 

article in Science (Shindell, 2009) 15

further updating the value for methane’s 

100-year GWP to incorporate net direct 

and indirect radiative forcing impacts 

from aerosols, which the prior AR4 

estimates did not contemplate. This 

commenter contended that the EPA 

should adopt NASA’s GWP of 33 for 

methane on a 100-year time horizon. 

Otherwise, the commenter maintained, 

known net impacts from aerosols will be 

ignored in the reported (calculated) 

emissions values, and decision-makers 

will not be informed of the correct 

impact of sources of methane emissions 

when developing climate action plans. 

The commenter stated that if the EPA 

does not use NASA’s GWP value, then 

the agency should wait until the release 

of the IPCC AR5 and use that report’s 

GWP for methane. 

Several commenters requested that 

the EPA reconsider our prior decision to 

adopt only a 100-year GWP for methane. 

While many commenters supported the 

EPA’s use of 100-year GWPs in the rule, 

we received a number of generalized 

messages requesting that we use 20-year 

GWP values in addition to the 100-year 

values. These commenters believe the 

use of the 20-year GWPs in the GHGRP 

would have important policy 

implications, because the exclusive use 

of a 100-year GWP implies that the only 

period of concern for climate change is 

100 years. The EPA received five unique 

comment letters recommending that 

facility and supplier CO2e emissions 

data be calculated using both the 100- 

year GWP and 20-year GWP. One 

commenter added that facilities emitting 

25,000 tons CO2e per year (calculated 

using either a 100-year or 20-year GWP) 

should be required to report under Part 

98. Another commenter requested that 

the EPA use only the 20-year values, 

instead of the 100-year values. 

Several commenters referenced a 

variety of articles, studies, and 

conference proceedings supporting the 

idea that the reduction of methane is 

critical to slow down the rate of global 

warming and to reduce future peak 

temperatures. They believe the 100-year 

GWP the EPA uses de-emphasizes the 

importance and potential benefits of 

reducing the emissions of methane. 

Two commenters disagreed with the 

EPA’s rationale for requiring reporting 

based solely on 100-year GWP values, 

which is to maintain consistency with 

the UNFCCC’s agreement to report 

national inventories for international 

purposes based on the 100-year GWP. 

Another commenter argued the GHGRP 

is intended to inform regulation of 

GHGs under the CAA. This commenter 

notes the IPCC has stated, ‘‘if the policy 

emphasis is to help guard against the 

possible occurrence of potentially 

abrupt, non-linear climate responses in 

the relatively near future, then a choice 

of a 20-year time horizon would yield 

an index that is relevant to making such 

decisions regarding appropriate 

greenhouse gas abatement strategies.’’ 16

Other commenters supported the EPA’s 

adoption of the AR4 GWP for methane 

of 25, which is based on the 100-year 

time horizon. 

Response: As noted in the ‘‘Response 

to Comments on Final Rule, Volume 3: 

General Monitoring Approach, the Need 

for Detailed Reporting, and Other 

General Rationale Comments’’ (see 

Docket Id. No EPA–HQ–OAR–2008– 

0508–2260), the EPA selected the 100- 

year GWPs because these values are the 

internationally accepted standard for 

reporting GHG emissions. For example, 

the parties to the UNFCCC agreed to use 

GWPs that are based on a 100-year time 

period for preparing national 

inventories, and the reports submitted 

by other signatories to the UNFCCC use 

GWPs based on a 100-year time period, 

including the GWP for methane and 

certain GHGs identified as short-lived 


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17Shindell, D. T., Faluvegi, G., Koch, D. M., 

Schmidt, G. A., Unger, N., & Bauer, S. E. (2009). 

Improved attribution of climate forcing to 

emissions. Science, 326(5953), 716–718. 

18E.g., U.S. Leadership on the Global Methane 

Initiative (http://www.epa.gov/globalmethane/) and 

Climate and Clean Air Coalition to Reduce ShortLived Climate Pollutants (http://www.state.gov/r/

pa/prs/ps/2012/02/184055.htm). 

climate pollutants. These values were 

subsequently adopted and used in 

multiple EPA climate initiatives, 

including the EPA’s SNAP program and 

the Inventory, as well as EPA voluntary 

reduction partnerships (e.g., Natural Gas 

STAR). The EPA noted at the time that 

Part 98 was finalized that alternative 

metrics for comparing the potential 

climate impacts of different GHGs were 

being considered by the IPCC. However, 

the IPCC has not made a 

recommendation regarding adoption of 

the 20-year metric. Furthermore, 

although the UNFCCC has updated the 

international reporting guidelines to 

reference GWPs from AR4 for the year 

2015 and beyond, the guidelines 

continue to specify GWPs with a 100- 

year time horizon. We have reviewed 

the NASA Science publication (Shindell 

et al., 2009) 17 referenced by the 

commenter that provides a 100-year 

GWP for methane of 33. However, as 

discussed above, the EPA has decided to 

adopt AR4 values across the board 

because it is beneficial for both 

regulatory agencies and industry to use 

the same GWP values for these GHG 

compounds because it allows for more 

efficient review of data collected 

through the GHGRP and other U.S. 

climate programs, reduces potential 

errors that may arise when comparing 

multiple data sets or converting GHG 

emissions or supply based on separate 

GWPs, and reduces the burden for 

reporters and agencies to keep track of 

separate GWPs. 

Regarding the use of 20-year GWPs, 

human-influenced climate change 

occurs on both short (decadal) and long 

(millennial) timescales. While there is 

no single best way to value both short 

and long-term impacts in a single 

metric, the 100-year GWP is a 

reasonable approach that has been 

widely accepted by the international 

community. If the EPA were to adopt a 

20-year GWP solely for methane, or for 

certain other compounds, it would 

introduce a metric that is inconsistent 

with both the GWPs used for the 

remaining Table A–1 gases and with the 

reporting guidelines issued by the 

UNFCCC and used by the Inventory and 

other EPA programs. Additionally, the 

EPA and other federal agencies, 

calculating the impact of short-lived 

climate forcers using 100-year GWPs, 

are making reduction of short-lived 

climate forcers a priority.18 For the 

reasons described above, the EPA is 

retaining a 100-year time horizon as the 

standard metric for defining GWPs in 

the GHGRP. 

c. Summary of Comments and 

Responses on the Relationship of the 

Final Rule to Other EPA Programs (e.g., 

Tailoring Rule Programs) or State 

Programs 

This section summarizes the 

significant comments and responses 

related to the relationship between the 

final rule and other EPA programs. See 

the comment response document in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to this 

topic. 

Comment: Several commenters noted 

that changes to the GWPs in Table A– 

1 and any changes to the gases listed in 

Table A–1 create discontinuities in the 

assessment of emissions under 

permitting rules, which can create shifts 

in permitting requirements. In the case 

of title V permitting, commenters stated 

that facilities that become subject to title 

V as the result of revisions to Table A– 

1 should be allowed at least one year 

from the publication date of the 

revisions to assess the impact of the 

changes, submit a title V application, or 

apply for a synthetic minor limit to 

avoid title V. Commenters further stated 

that if a source has taken a synthetic 

minor limit on its CO2e emissions to 

remain below the title V applicability 

threshold and is unable to meet the 

synthetic minor limit due to the 

revisions to the GWPs, then facilities 

should have a one year period to assess 

emissions, determine if the synthetic 

minor permit is no longer viable, and 

apply for the appropriate permit. 

Commenters stressed that there should 

be no penalty for non-compliance with 

the synthetic minor limit or title V 

permitting requirement. Commenters 

expressed similar concerns regarding 

new construction and modifications 

becoming subject to PSD requirements 

due to revisions to GWP values. 

Some commenters argued revisions to 

the GWP values impact compliance 

with existing CO2e permit limits for PSD 

avoidance, Best Available Control 

Technology (BACT), and plant-wide 

applicability limits (PAL). They also 

requested sources be allowed to 

continue using the old GWP values for 

a period of one year, so that affected 

facilities may seek revisions to their 

permits, redeterminations, or 

recalculation of these limits, as 

applicable. The commenters 

recommended a provision designed to 

allow facilities time to incrementally 

adjust to changes in the current rules be 

made available if a change in the GWPs 

presents a problem for meeting a PAL 

that cannot be resolved. 

One commenter asserted that while 

section 114 of the CAA, 42 U.S.C. 7414, 

is cited as the basis for the proposed 

rule, section 114 does not empower the 

EPA to change the thresholds for major 

source determinations under other 

programs, such as the Prevention of 

Significant Deterioration (PSD) and title 

V permitting programs. The commenter 

explained that section 114 governs 

recordkeeping and inspections, and that 

it allows the EPA to require sources to 

provide data about air emissions. The 

commenter stated that the amendments 

to the GWP values affect the major 

source and permitting thresholds and 

therefore, any changes to Table A–1 

must be proposed and finalized under 

the EPA’s authority to implement the 

relevant permitting program. 

Specifically, the commenter asserted 

that amendments to the PSD program 

must be made pursuant to CAA sections 

160–169, the Indian Country minor 

source rule must be amended pursuant 

to CAA sections 171–179B, and the title 

V program must be amended pursuant 

to CAA sections 501–507. The 

commenter stated that revisions to Table 

A–1 should be evaluated and processed 

by EPA’s Office of Air Quality Planning 

and Standards (OAQPS) because 

OAQPS published the Tailoring Rule 

and traditionally handles substantive 

permitting regulations. Several 

commenters requested the EPA provide 

clear guidance in the final rule 

addressing how PSD and title V issues 

resulting from GWP revisions should be 

handled. 

Response: As the EPA noted in the 

preamble to the Tailoring Rule (75 FR 

31514, June 3, 2010), the Tailoring Rule 

codifies Table A–1 to Subpart A of 40 

CFR part 98 for the purpose of 

calculating emissions of CO2e for 

determining Prevention of Significant 

Deterioration (PSD) and title V 

applicability for GHG (75 FR 31522). 

This approach was adopted in lieu of 

codifying IPCC values, which may 

change more frequently over time, and 

to provide certainty as to which GWP 

values need to be used. We explained, 

‘‘[a]ny changes to Table A–1 of the 

mandatory GHG reporting rule 

regulatory text must go through an 

appropriate regulatory process. In this 

manner, the values used for the 

permitting programs will reflect the 

latest values adopted for usage by the 

EPA after a regulatory process and will 

be consistent with those values used in 


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19Action To Ensure Authority To Implement 

Title V Permitting Programs Under the Greenhouse 

Gas Tailoring Rule (75 FR 82254, Dec. 30, 2010). 

20 In general, a source has up to one year to either 

apply for a title V permit, or be issued a synthetic 

minor permit to avoid title V applicability (but 

merely applying for a synthetic minor permit 

within 12 months is not sufficient to avoid title V 

applicability). 

the EPA’s mandatory GHG reporting 

rule’’ (75 FR 31532). Furthermore, this 

Part 98 notice-and-comment process 

‘‘will ensure advance notice of such a 

change’’ for sources that may be subject 

to the Tailoring Rule. See U.S. EPA, 

‘‘Prevention of Significant Deterioration 

and Title V GHG Tailoring Rule: EPA’s 

Response to Public Comments,’’ May 

2010 (Docket Id. No. EPA–HQ–OAR– 

2009–0517–19181), p. 101, n.5. Thus, as 

the EPA noted in the proposal to these 

Part 98 revisions, because permitting 

applicability is based partly on CO2e 

emissions, an amendment to Table A–1 

may affect program applicability for a 

source. 

The EPA disagrees with the 

commenter who asserted that the EPA is 

changing the thresholds for major 

source determinations under the PSD 

and title V permitting programs in this 

rule. The Tailoring Rule references GWP 

values from Part 98 Table A–1 and uses 

them to calculate CO2e emissions 

values, so the GWP changes in this final 

rule may affect the calculation of GHG 

emissions for individual sources relative 

to those thresholds. However, this final 

rule does not modify the major source 

thresholds of the PSD and title V 

permitting programs or any other EPA 

program, nor does it modify the ‘‘subject 

to regulation’’ thresholds for GHG 

established under the Tailoring Rule. 

The EPA acknowledges that 

amendments to Table A–1 may result in 

an existing facility becoming subject to 

title V permitting. A stationary source 

may be a major source subject to title V 

permitting requirements solely on the 

basis of its GHG emissions, provided the 

source’s emissions exceed the 

thresholds established in the Tailoring 

Rule. GHG emission sources that emit or 

have the potential to emit (PTE) at least 

100,000 (tons per year) TPY CO2e 

(calculated using GWPs), and also emit 

or have the PTE 100 TPY of GHGs on 

a mass basis (calculated without GWPs) 

are required to obtain a title V permit if 

they do not already have one. 

While the EPA does not believe that 

many sources will change their title V 

applicability status as a result of this 

Table A–1 revision, it is conceivable 

that an existing source with a PTE just 

beneath the title V thresholds on a CO2e 

basis may find that the revised GWP 

values result in a PTE calculation that 

makes the source a ‘‘major source’’ 

under title V. This determination would 

depend on what GHG compound(s) the 

source emits, the amount of the 

compound emitted, and if the GWP of 

the compound is increasing or 

decreasing. For example, a hypothetical 

source that emits only methane and no 

other GHG compounds or other 

regulated NSR pollutants has a PTE of 

90,000 TPY CO2e in 2012 and is 

therefore not a title V major source. 

However, in 2014, once the new GWPs 

are effective for this hypothetical 

source, it could have emissions that 

make it a major source of GHG under 

title V, because its mass emissions are 

at least 100 TPY and its calculated PTE 

would be approximately 107,000 TPY 

CO2e as a result of methane’s GWP 

increasing from 21 to 25 (assuming the 

source does not take a restriction on its 

methane emissions). 

A source applying for a title V permit 

for the first time must submit its permit 

application within 12 months after the 

source ‘‘becomes subject to the 

[operating] permit program’’ or such 

earlier time that the permitting authority 

may require (see 40 CFR 70.5(a)(1)). As 

the EPA noted in the title V Narrowing 

Rule,19 a source ‘‘becomes subject to’’ 

title V permitting when there is an EPApromulgated or approved permit 

program ‘‘applicable to the source.’’ See 

75 FR 82259, n. 8; CAA section 503(a). 

Thus, the exact date that the new GWPs 

will become effective for purposes of 

title V applicability may vary, 

depending on the status of the 

applicable title V program as it relates 

to GHG sources and on how the GWPs 

are incorporated into the applicable title 

V permit program. For example, the 

federal part 71 permit program will 

begin using the revised GWPs upon the 

effective date of this rule, and some 

states may similarly have title V 

programs that automatically update the 

GWP values. However, other states may 

have approved title V programs that 

require revision to use the revised GWP 

values for title V permitting, or may 

even still lack authority to permit major 

sources of GHG under title V. In the 

example above, the hypothetical source 

of methane whose PTE calculation 

increased to 107,000 TPY CO2e would 

have up to a year from becoming subject 

to title V permitting under the 

applicable title V program to submit an 

application for a title V operating 

permit. 

A source may be able to avoid the 

requirement to have a title V permit if 

it has been issued a synthetic minor 

source permit that limits its PTE below 

the major source thresholds (including 

the CO2e-based ‘‘subject to regulation’’ 

threshold) for title V applicability.20 It 

may be advisable for the terms of the 

synthetic minor permit to impose limits 

on GHGs on a mass basis, rather than a 

CO2e basis (even where the purpose of 

the permit is to limit a source’s PTE 

below 100,000 CO2e). For such massbased limits, a change in the GWP of the 

pollutant does not render the source out 

of compliance with the synthetic minor 

source limit, although the source may 

need to obtain a revised synthetic minor 

source limit to maintain its synthetic 

minor source status and avoid the need 

for a title V permit as a major source 

(i.e., if the change in GWPs makes the 

source a title V major source under the 

conditions of the original minor source 

permit). 

The EPA recognizes that there also 

may be synthetic minor source permit 

limits that are established solely in 

terms of CO2e. This may occur at a 

source that emits multiple GHG 

compounds and seeks flexibility in 

managing its GHG emissions. In such 

cases, the source should analyze any 

permit and regulatory provisions 

governing the calculation of CO2e for 

purposes of compliance with the permit. 

Even where the calculation of CO2e 

under those provisions would change 

for a source, the EPA believes most 

sources will still be able to comply with 

its synthetic minor source permit 

because there is no GWP change for CO2

and the change in GWP for the other 

GHG compounds is generally small. 

Thus, we do not expect the GWP 

revisions to significantly alter CO2e 

emissions for most types of sources, 

particularly sources in which most of 

their GHG emissions result from fuel 

combustion. However, where a source 

anticipates difficulty in compliance 

with its synthetic minor source limit, it 

should work with its permitting 

authority to revise its permit to ensure 

compliance with the requirements of the 

permit and of title V. 

The EPA also acknowledges that this 

action will affect the applicability of the 

PSD permit program for the proposed 

construction of new sources and 

proposed modifications of existing 

sources. As of the effective date of the 

Part 98 rule revisions, proposed sources 

and proposed modifications, including 

proposed PALs and PAL renewals, will 

need to calculate their GHG PTE and 

determine PSD applicability based on 

the revised GWPs. However, PSD 

permitting obligations should not be 

affected for a source or modification that 

has either already obtained a PSD 

permit or begun actual construction at a 

time when it was legitimately 


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considered a source that did not require 

a PSD permit (See 75 FR 51593–94, 

August 20, 2010). This approach is 

consistent with our PSD permitting 

regulations that provide: ‘‘[n]o new 

major stationary source or major 

modification to which the requirements 

of paragraphs (j) through (r)(5) of this 

section apply shall begin actual 

construction without a permit that states 

the major stationary source or major 

modification will meet those 

requirements’’ 40 CFR 51.166(a)(7)(iii); 

40 CFR 52.21(a)(2)(iii). We do not 

interpret these provisions to prevent a 

source or modification from continuing 

construction when that source or 

modification has been legitimately 

determined not to trigger PSD 

permitting obligations and has begun 

actual construction before the effective 

date of the Part 98 regulations. 

Similarly, we do not interpret these 

provisions to prevent a source with a 

PSD permit issued before the Part 98 

regulations become effective from 

beginning or continuing construction 

under that permit, as long as that permit 

has not expired. 

Likewise, the GWP revisions should 

not affect past permitting actions for a 

source that has obtained a final PSD 

permit before these revisions to Part 98 

become effective, regardless of whether 

or not that PSD permit included GHG 

limits. The EPA generally does not 

require reopening or revision of PSD 

permits that are issued prior to the 

effective date of a new requirement. See 

75 FR 31593; Memorandum from John 

S. Seitz, Director OAQPS, New Source 

Review (NSR) Program Transitional 

Guidance, page 6 (March 11, 1991). 

Consistent with this approach, PSD 

permits based on earlier GWPs that are 

issued in final form prior to the effective 

date of these Part 98 rule revisions 

would not have to be revised or 

reopened solely due to the promulgation 

and effectiveness of these Part 98 rule 

revisions. Furthermore, compliance 

with final PSD permits that include 

BACT limits based on CO2e, PALs based 

on CO2e, and with other permit 

conditions that utilize GWPs from Table 

A–1 may be determined based on the 

GWPs that were in effect at the time of 

permit issuance (even if the permit does 

not specify the applicable GWP value). 

While adoption of the Part 98 

revisions will automatically apply in 

some PSD permit programs, other 

programs will have to engage in a state 

implementation plan (SIP) adoption 

process. Specifically, these new GWP 

values will apply immediately upon the 

effective date of this rule for PSD 

programs administered by EPA Regions 

and for those administered by 

‘‘delegated’’ states that rely upon 40 

CFR 52.21, as well as in any state with 

a SIP that automatically updates when 

either 40 CFR sections 51.166 or 52.21 

are revised (e.g., the state regulations 

incorporate by reference 40 CFR 52.21 

without specifying an ‘‘as of’’ date of 

incorporation). However, some states 

will need to adopt the changes to the 

GWPs into their SIP before they become 

effective in their state permitting 

programs. This provides additional 

transitional time for sources in those 

states to comply with the required 

changes before the GWPs become 

effective in those states. 

Likewise, as noted above, revisions to 

the GWPs will occur automatically for 

federal title V permitting. Some states 

may also have title V permit programs 

that automatically update, while other 

states may require revisions to their 

approved title V permit programs before 

the GWP revisions become effective for 

purposes of title V permitting. 

Given the transitional times discussed 

above, we anticipate that most facilities 

will have a period to incrementally 

adjust to the changes in this final rule. 

Because development of the 2015 

Inventory will rely in part on data from 

the GHGRP reports submitted in 2014, 

it is prudent for existing GHGRP 

reporters to calculate facility GHG 

emissions or supply using the revised 

GWPs in Table A–1 for their reporting 

year 2013 annual reports. Accordingly, 

the EPA is finalizing the schedule for 

the final amendments to Part 98 as 

proposed, and is not finalizing a 

transitional period. See Section III.A of 

this preamble for additional 

information. 

Regarding the requests for the EPA to 

provide guidance, as we noted in the 

Response to Public Comments on the 

Tailoring Rule,’’[i]n the event that we 

propose a change to GWP values, we 

will work with permitting authorities as 

necessary to provide guidance to 

sources on transitional issues’’ Docket 

Id. No. EPA–HQ–OAR–2009–0517– 

19181, p. 101 (footnote). A number of 

EPA offices, including OAQPS, have 

worked collaboratively in developing 

this response. Thus, in addition to the 

guidance provided in this preamble 

regarding the application of the Table 

A–1 revision to state PSD and title V 

programs and to previously-issued 

preconstruction permits, the EPA will 

continue to work with permitting 

authorities to address implementation 

concerns, as needed. 

Comment: Several commenters 

expressed concern that the proposed 

rule appeared to propose retroactively 

applying amended GWPs to prior year 

reports. The commenters also stated that 

the EPA did not provide a regulatory 

analysis of how retroactively applying 

GWPs would affect PSD or title V 

permitting obligations. Five commenters 

expressed concern that the proposed 

revisions to Table A–1 could result in 

enforcement actions associated with 

previous determinations under these 

regulatory programs. These commenters 

expressed concern that such a change 

would stall current permit projects and 

possibly reopen existing permits that 

were previously approved. In particular, 

some commenters were concerned about 

the impact on landfills, which require 

permits to install combustion devices 

for compliance under New Source 

Performance Standards (NSPS) and for 

landfill gas renewable energy projects. 

They recommended that the EPA clarify 

that any changes to the GWPs and GHG 

reporting requirements would not be 

applied retroactively to prior 

determinations made under PSD, title V, 

or any other regulatory programs that 

rely on the GWP values in Table A–1. 

Response: The EPA did not intend to 

suggest in the proposed rule that the 

revised GWPs in Table A–1 would be 

retroactively applied under the PSD and 

title V permitting programs or for any 

other regulatory purpose. Thus, as 

explained above, PSD permits based on 

earlier GWPs that are issued in final 

form (to landfills or to other types of 

sources) prior to the effective date of 

these Part 98 rule revisions would not 

have to be revised or reopened solely 

due to the promulgation and 

effectiveness of these Part 98 rule 

revisions. Moreover, as to the 

commenter’s concern regarding the 

impact on landfills, we note that, 

generally because reductions in 

methane will be credited more highly in 

PSD applicability determinations, we 

would expect these project to be less, 

rather than more, likely to trigger PSD 

were the revised Table A–1 values to 

apply. 

As discussed above, we do not see 

any cause to deviate from our historical 

practice of not requiring PSD permits to 

be reopened or amended to incorporate 

requirements that take effect after the 

permit is issued. With these 

considerations, the EPA does not expect 

the revised GWPs to be applied 

retroactively to prior PSD and title V 

permitting determinations made based 

on prior years’ GHG emissions, though 

these revisions will apply to permitting 

determinations made after the effective 

date of these Part 98 rule revisions, as 

described above. As such, we do not 

expect that facilities will be subject to 

the reopening of a previously approved 

PSD or title V permit solely based on 


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21We are finalizing confidentiality 

determinations for the revised data element in 40 

CFR 98.3(c)(1). See Section V of this preamble for 

additional information. 

22Available at http://www.epa.gov/airmarkets/

business/docs/forms/CertofRepFINAL.pdf. 

23We are finalizing confidentiality 

determinations for the new data elements in 40 CFR 

98.3(c)(13) and 40 CFR 98.36. See Section V of this 

preamble for additional information. 

application of the amended GWPs in 

Table A–1 to prior years’ emissions. 

For example, assume that a new major 

stationary source gets a PSD permit in 

2011, undergoing a BACT analysis for 

GHGs. The permit that establishes the 

source’s CO2e emission limit(s) are 

based on the Table A–1 values that are 

in place at the time of permit issuance 

(i.e., from the 2009 GHG reporting rule). 

In 2014, after the effective date of the 

2013 Table A–1 revisions, the source 

would continue to determine 

compliance with their PSD permit by 

the original permit conditions that 

based applicability and BACT limits on 

the GWP values in the 2009 GHG 

reporting rule. Then, in 2015, the 

company submits a PSD permit 

application to undergo a modification at 

the source. In order to determine PSD 

applicability for the project, the 

applicant and permitting authority 

should use the most updated values of 

GWPs that are in effect, which at this 

point would be the GWP values in the 

2013 Table A–1 revisions. Assuming 

that this source is in a state that 

automatically updates its SIP when the 

federal rules are amended, it would 

determine its emissions increase from 

the 2015 proposed modification (e.g., 

‘‘baseline actual emissions’’ and 

‘‘projected actual emissions’’) by using 

the GWP values in the 2013 Table A–1 

revisions. 

Comment: Several commenters 

expressed concerns with how state and 

regional programs that rely on the GWP 

values in Part 98 may be affected by the 

EPA’s revisions to Table A–1. One 

commenter was particularly concerned 

about the potential of increased 

complexity in comparing emissions 

between programs and between 

reporting years. For example, the 

commenter notes that some states have 

incorporated the GWP values in Part 98 

into their state reporting programs to 

reduce the reporting burden. The 

commenter explained that these states 

will either have to propose and approve 

rule changes to update their GWP values 

to match those in Part 98 or certain 

facilities will be required to report two 

sets of CO2e data: One to the EPA and 

one to the state or local program. The 

commenter recommends that, in order 

to ensure consistent reporting across 

federal, state and regional reporting 

programs, the agency must ensure that 

the reporting revisions currently and in 

the future are well-coordinated with 

state and local reporting programs. 

Response: As noted in the preamble to 

the final 2009 Part 98 (74 FR 56260), the 

EPA has intended to periodically update 

Table A–1 when GWP values are 

evaluated or re-evaluated by the 

scientific community. The revised GWP 

values in Table A–1 will likely result in 

changes to the CO2e estimates of GHGs 

emitted or supplied. As noted by the 

commenters, the revisions may affect 

the state and regional programs that rely 

on the GWP values in Table A–1.The 

EPA recognizes the importance of state 

and local GHG programs in evaluating 

regional GHG emissions and in 

implementing GHG reduction strategies. 

In reviewing Table A–1, the EPA 

considered the benefits of having 

consistent GWPs across federal, state, 

and regional programs. In particular, we 

recognize that using consistent GWPs 

across these programs increases the ease 

with which agencies can analyze local 

emissions in light of national estimates. 

As discussed in Section II.A.2.a of this 

preamble, the EPA balanced the benefits 

of updating the GHGRP GWPs to more 

current values with the U.S. 

commitment to maintain consistency 

with values used by the UNFCCC and 

the values used in other U.S. climate 

programs. The EPA’s primary goal in 

updating Table A–1 is to ensure that the 

GHGRP incorporates scientific advances 

in climate science to better inform EPA 

policies and programs. As noted 

previously, we recognize that frequent 

updates to Table A–1 may cause 

confusion or create difficulties with 

reviewing prior year data based on 

different GWP values. Because of these 

concerns, we do not intend to update 

Table A–1 frequently (see Section 

II.A.2.a of this preamble for additional 

information). Although the EPA 

anticipates making periodic updates 

that increase the accuracy of the 

GHGRP, we anticipate balancing the 

frequency of these changes with the 

impacts to federal, state, and local 

programs. 

We note that the applicability, 

compliance schedule, calculation 

methodologies, or any other 

requirements established under these 

non-Part 98 programs are outside the 

scope of these amendments. Concerns 

related to implementation and 

compliance with other state and 

regional programs that rely on Table A– 

1 cannot be addressed through Part 98. 

However, the EPA intends to work with 

state and regional programs to address 

implementation concerns. As noted in 

the response above, it is likely that some 

PSD SIPs will need to be revised as a 

result of this action, since some state 

rules do not automatically update when 

Part 98 is updated. 

3. Summary of Other Corrections and 

Final Amendments to Subpart A 

In addition to the amendments to 

global warming potentials in Table A– 

1, we are also finalizing corrections and 

other clarifications to certain provisions 

of subpart A of Part 98. The more 

substantive corrections, clarifying, and 

other amendments to subpart A are 

found here. We are finalizing all of the 

minor corrections to subpart A 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

The EPA has finalized, with revisions, 

the amendment to require facilities to 

report their latitude and longitude if the 

facility does not have a physical street 

address. The EPA received comment 

that the rule should specify the precise 

latitude and longitude that should be 

reported (i.e., centroid of the plant or 

part of the ‘‘administration building’’). 

As a result of this comment we revised 

the requirement to clarify that facilities 

required to submit a latitude and 

longitude should report the geographic 

centroid or center point of the facility.21

The final amendments replace the 

proposed term, ‘‘ORIS code,’’ with the 

term ‘‘plant code,’’ and the proposed 

definition has been revised to include 

both facilities that have been assigned a 

Plant ID code by the Department of 

Energy’s (DOE) Energy Information 

Administration (EIA) and those have not 

been assigned this code but that 

otherwise report to EPA’s Clean Air 

Markets Division (CAMD) and so have 

been assigned a plant code by CAMD. 

The final amendments reflect a 

definition of ‘‘plant code’’ under 40 CFR 

98.6 that is largely derived from the 

definition of this term on the Certificate 

of Representation (EPA Form 7610–1 

(Revised 8–2011)) 22 that is used for 

domestic NOX and SO2 trading 

programs. The associated reporting 

requirement that was originally 

proposed at 40 CFR 98.3(c)(13) has been 

divided into a general facility-level 

reporting requirement under subpart A 

(to identify reporters who have been 

assigned a plant code) and 

configuration-level requirements to 

report the code under subparts C and 

D.23

The EPA is not finalizing the 

definition of ‘‘Fluidized Bed Combustor 

(FBC)’’ because the associated subpart C 

emissions factors are not being finalized 

at this time. See Section II.B of this 


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preamble for more information about 

the FBC-specific emission factors. 

We are finalizing a provision, as 

proposed, to include instructions for the 

reporting of a United States parent 

company legal name and address. The 

final amendments to the parent 

company reporting requirements under 

40 CFR 98.3(c)(11)(viii) reflect that 

reporters are required to use any 

common naming rules or guidelines 

provided via the Electronic Greenhouse 

Gas Reporting Tool (e-GGRT) in 

formatting and submitting their parent 

company names. This will ensure 

consistent reporting of a given parent 

company name between different 

facilities with that parent company and 

transparency of which facility’s or 

supplier’s emissions may, in whole or in 

part, be attributed to a given parent 

company. This amendment is being 

finalized as proposed. 

The EPA is also finalizing the 

following amendments as proposed. We 

are amending 40 CFR 98.3(h)(4) to 

clarify the provisions for requesting an 

extension of the 45-day period for 

submission of revised reports in 40 CFR 

98.3(h)(1) and (2). Finally, we are 

revising the definitions of 

‘‘degasification system’’, ‘‘ventilation 

well or shaft’’, and ‘‘ventilation system’’ 

to more closely align with common 

terminology used in the coal mining 

industry (subpart FF). 

4. Summary of Comments and 

Responses—Other Corrections and 

Amendments to Subpart A 

This section summarizes the 

significant comments and responses 

related to the proposed corrections and 

amendments to subpart A. See the 

comment response document for 

subpart A in Docket Id. No. EPA–HQ– 

OAR–2012–0934 for a complete listing 

of all comments and responses related 

to subpart A. 

Comment: Many commenters 

supported the requirement for 

electricity generators to report their 

ORIS codes, but requested clarifications 

or revisions to the proposal. 

Commenters pointed out that the 

definition should be revised to indicate 

that ORIS codes can have up to five 

digits, and several commenters pointed 

out that the proposed definition reflects 

that these codes are plant-level 

attributes while the proposed language 

of the reporting requirement described 

the codes as unit-level attributes. One 

commenter recommended that the rule 

clearly restrict the ORIS code reporting 

requirement to power plants which are 

subject to both EIA’s Form 860 reporting 

requirements and to 40 CFR part 98. 

Another commenter stated that the 

proposal would require operators to 

report the same ORIS code for each unit 

at a single facility. 

Response: The final amendments do 

not define the term ‘‘ORIS code’’ but 

instead define the term ‘‘plant code’’ 

based largely on the following definition 

from the Certificate of Representation 

(EPA Form 7610–1 (Revised 8–2011)) 

used for the EPA’s NOX and SO2 trading 

programs: 

A plant code is a 4 or 5 digit number 

assigned by the Department of Energy’s 

(DOE) Energy Information Administration 

(EIA) to facilities that generate electricity. For 

older facilities, ‘‘plant code’’ is synonymous 

with ‘‘ORISPL’’ and ‘‘Facility’’ codes. If the 

facility generates electricity but no plant code 

has been assigned, or if there is uncertainty 

regarding what the plant code is, send an 

email to the EIA. The email address is EIA860@eia.gov. For facilities that do not 

produce electricity, use the facility identifier 

assigned by EPA (beginning with ‘‘88’’). 

Due to the recurring comment that an 

ORIS code is a plant-level attribute that 

was proposed as a unit-level reporting 

requirement, the final amendments 

clarify that the plant code should, in 

fact, be reported at the unit-level or 

configuration-level under Part 98 

because of differences between EIA 

conventions for delineating plant-sites 

and the definition of ‘‘facility’’ under 40 

CFR 98.6. Reporting of the plant code at 

the unit-level or configuration-level is 

necessary because some groups of 

combustion units that are under 

common control are considered to be 

multiple plant-sites by EIA. For 

example, the generating facility assigned 

EIA plant code 3250 is a generating 

plant with 12 peaking units that is 

adjacent to a base load plant assigned 

EIA plant code 3251. Because these two 

EIA plant-sites are adjacent and owned 

by the same utility company, they are 

considered a single ‘‘facility’’ as that 

term is defined in 40 CFR 98.6. While 

one commenter’s statement that all units 

at a single facility would report the 

same ORIS code is valid for the majority 

of Part 98 facilities, this statement is not 

universally valid. The final rule clarifies 

these points. However, because plant 

codes are being treated as unit-level 

attributes under Part 98, the associated 

reporting requirements are being 

promulgated with other unit-level 

requirements under subpart C. 

Comment: Two commenters 

expressed concern that the EPA would 

use the new provision in 40 CFR 

98.3(c)(11)(vii) to assign parent 

companies to a given facility or supplier 

or make changes to a facility or 

supplier’s certified report after it is 

submitted. It was also noted that the 

EPA did not indicate if the company 

naming convention would be revised for 

previously submitted reports or only 

apply to reports submitted going 

forward. 

Response: The EPA notes that the 

proposed language ‘‘standardized 

conventions for the naming of a parent 

company’’ refers to the style guide 

currently referenced as a suggested 

template for parent company reporting 

in e-GGRT. This style guide covers 

items such as common punctuation and 

abbreviation use in parent company 

names and is included to avoid having 

facilities with the same parent company 

report that parent company in different 

formats (i.e. ABC Corp. vs. ABC 

Corporation vs. A.B.C. Corp.). The list of 

parent companies provided in e-GGRT 

provides a list of company names that 

are already formatted in-line with the 

style guide. Currently, reporters have 

the option to use a parent company 

name on the provided list or enter a 

separate parent company name if their 

parent company is not listed on the 

provided list. Those two options would 

remain in place with this change, and 

reporters will not be limited to only 

selecting a parent company from the list 

provided in e-GGRT. This change does 

require that, if a reporter does not 

choose a company on the list provided 

in e-GGRT, they must follow the style 

guide to ensure their parent company 

name is entered in a manner consistent 

with other reporters. Again, the style 

guide is limited to formatting 

requirements, such as punctuation and 

abbreviation (i.e., U.S. vs. US vs. United 

States). 

This change does not give the EPA 

permission to alter the parent company 

information certified and submitted by 

reporters. If, in the process of future 

report verification, EPA notes that the 

style guide was not followed, then the 

EPA may ask the reporter to correct the 

parent company name to adhere to the 

format in the style guide. In this 

situation, the reporter would make any 

changes to the reported parent company 

name, not EPA. The EPA does not 

intend to require resubmission of 

reports for previous years solely to 

update the parent company name to 

comply with this new provision. 

The conventions in the style guide are 

consistent with other EPA programs, 

such as the Toxics Release Inventory, 

which provides consistency for those 

parent companies that report under 

multiple programs. For the reasons and 

clarifying statements mentioned above, 

the EPA is finalizing this regulatory text 

change as proposed. 

Comment: One commenter objected to 

EPA’s proposal to revise the parent 

company requirements under 40 CFR 


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24M.A. Wojtowicz, et al., Combustion of Coal as 

a Source of N2O Emission, 34 Fuel Processing Tech. 

1(1993), EPA–HQ–OAR–2012–0934–0029. 

25R.A. Brown, et al., N2O Emissions from 

Fluidized Bed Combustion, Proceedings of the 11th 

International Meeting on Fluidized Bed 

Combustion, March 1991. 

98.3(c)(11) without first completing a 

revised Information Collection Request 

(ICR). 

Response: The regulatory text related 

to standardizing of parent company 

names does not add any new reporting 

requirements to subpart A. Rather, it 

clarifies the format used for submitting 

parent company names under 40 CFR 

98.3(c)(11) to provide consistency for 

both reporters and the public viewing 

the data. Because this change is a 

formatting change for an existing 

requirement, the EPA has determined an 

ICR amendment is not required. 

B. Subpart C—General Stationary Fuel 

Combustion Sources 

1. Summary of Final Amendments 

We are generally finalizing revisions 

to the requirements of 40 CFR part 98, 

subpart C (General Stationary Fuel 

Combustion Sources) as proposed. The 

revisions clarify the use of the Tier 

methodologies and update high heat 

value (HHV) and emission factors for 

several fuels. The more substantive 

corrections, clarifying, and other 

amendments to subpart C are found 

here. We are finalizing all of the minor 

corrections to subpart C presented in the 

Table of 2013 Revisions as proposed 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

First, we are finalizing a change to 40 

CFR 98.33(b)(1), as proposed, that will 

allow the Tier 1 methodology to be used 

for Table C–1 fuels that are combusted 

in a unit with a maximum rated heat 

input capacity greater than 250 million 

Btus per hour, if the fuel provides less 

than 10 percent of the annual heat input 

to the unit and the use of Tier 4 is not 

required. 

As previously discussed in Section 

II.A.3 of this preamble, the proposed 

requirement for certain facilities to 

report their plant code(s) (as defined 

under 40 CFR 98.6) is being finalized as 

unit-level and configuration-level 

reporting requirements under subpart C. 

The final amendments require reporting 

of this code at the unit-level or 

configuration-level in the applicable 

methodology-specific paragraphs in 

subpart C (i.e., paragraphs for Tiers 1– 

3, Tier 4, common pipe, common stack, 

aggregation of units, and Part 75 

reporting methodologies) in order to 

facilitate cross-referencing GHGRP data 

with other publicly available state and 

federal data resources. The plant code 

reporting requirement applies to each 

stationary combustion source (i.e., each 

individual unit and each group of units 

reported as a configuration) that 

includes at least one combustion unit 

that has been assigned a plant code. 

We are not finalizing the proposed 

change to the default biogenic fraction 

of CO2 for MSW. After consideration of 

public comments, the EPA performed an 

analysis that supports retaining the 

existing default MSW biogenic CO2

fraction of 0.6. (See ‘‘Analysis of Default 

Biogenic CO2 Fraction for Municipal 

Solid Waste (MSW)’’, June 24, 2013 in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). 

We are revising Table C–1 as 

proposed to update the HHV and/or 

emission factors for several fuels. The 

amendments to Table C–1, as discussed 

in the memorandum ‘‘Review and 

Evaluation of 40 CFR Part 98 CO2

Emission Factors for EPW07072 To 45’’ 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934), include: (1) Replacing 

‘‘Wood and Wood Residuals’’ with 

‘‘Wood and Wood Residuals (dry 

basis),’’ with a footnote containing an 

equation that can be used to adjust the 

HHV value for any moisture content; (2) 

replacing ‘‘Biogas (captured methane)’’ 

with two types of biogas: ‘‘Landfill Gas’’ 

and ‘‘Other Biomass Gases;’’ (3) revising 

the HHV and/or emission factors for 

liquid petroleum gases (LPG) and LPG 

components including propane, ethane, 

ethylene, isobutane, isobutylene, 

butane, and butylene; (4) correcting the 

emission factor for coke and revising the 

name to ‘‘coal coke’’ to differentiate it 

from ‘‘petroleum coke;’’ (5) updating 

emission factors for the four types of 

coal and the four types of mixed coals; 

(6) revising the HHV for the biomass 

fuel ‘‘solid byproducts;’’ and, (7) 

finalizing minor changes to the HHV 

and/or emission factors for natural gas, 

used oil, natural gasoline, petrochemical 

feedstocks, unfinished oils, crude oil, 

and tires. 

We are revising Table C–2 to add CH4

and N2O emission factors for ‘‘fuel gas’’ 

and ‘‘wood and wood residuals’’, as 

proposed. 

The EPA is not finalizing the 

proposed addition of waste coals (waste 

anthracite (culm) and waste bituminous 

(gob)) to Table C–1, and is not finalizing 

the proposed FBC-specific N2O 

emission factors for coal and waste coal 

to Table C–2. As discussed in the 

preamble to the proposed rule, the EPA 

reviewed multiple studies that indicate 

N2O emissions from these units when 

burning coal and waste coal are 

significantly higher than from 

conventional combustion technologies. 

We received comments that included 

additional data, which is discussed in 

Section II.B.2 of this preamble. The EPA 

will study this data to inform any future 

rulemaking to address this issue. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart C. See the comment response 

document for subpart C in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart C. 

Comment: Two commenters stated 

that the Wojtowicz study 24 used by the 

EPA to develop the proposed N2O 

emission factors for FBCs is not relevant 

to the large-scale FBC systems that are 

subject to Part 98. These commenters 

also provided a field study 25 of FBC 

emissions conducted by R.A. Brown, et 

al. Because the Brown study documents 

N2O emission rates that are lower than 

the proposed emission factors, these 

commenters expressed concerns that the 

proposed N2O emission factors will over 

estimate emissions from FBCs, and they 

concluded that the underlying 

Wojtowicz study should not be used to 

develop emission estimates for largescale FBC systems. These commenters 

also believe that the EPA did not 

include in the docket a detailed 

description of the methodology used to 

derive the N2O emission factors from 

the Wojtowicz study. 

Response: The EPA appreciates the 

N2O emissions and operating data from 

the Brown study provided by the 

commenters. We are not finalizing the 

proposed FBC-specific emission factors 

to allow time to study the additional 

data provided with the comments. 

Comment: Several commenters 

disagreed with the EPA’s proposal to 

reduce the default MSW biogenic CO2

fraction from 0.60 to 0.55 and requested 

that the EPA use the actual MSW 

fractions reported by all municipal 

waste combustors (MWCs) for the first 

three years of the GHGRP (2010–2012) 

to determine an appropriate default. 

Response: In response to these 

comments, the EPA performed an 

analysis of all quarterly MSW biogenic 

CO2 fractions (determined using ASTM 

D7459–08 and ASTM D6866–08) 

submitted through the GHGRP in 

reporting years 2010 through 2012. 

Quarterly MSW biogenic CO2 fractions 

were averaged for each MWC to 

determine each unit’s annual average 

MSW biogenic CO2 fraction. The 

weighted average (based on the reported 


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unit level biogenic CO2 emissions) for 

all MWC annual averages was 

determined to be 0.62. The result of this 

analysis supports retaining the existing 

default MSW biogenic CO2 fraction of 

0.60. (See ‘‘Analysis of Default Biogenic 

CO2 Fraction for Municipal Solid Waste 

(MSW)’’, June 24, 2013 in Docket Id. No. 

EPA–HQ–OAR–2012–0934). 

C. Subpart H—Cement Production 

We are finalizing one revision to the 

reporting requirements of 40 CFR part 

98, subpart H (Cement Production), as 

proposed. We are amending 40 CFR 

98.86(a)(2) to require reporting of 

facility-wide cement production. This 

change will provide consistency in the 

reporting requirements for facilities 

using continuous emissions monitoring 

system (CEMS) and not using CEMS. 

The EPA received one comment 

supporting the proposed change to 

subpart H. 

D. Subpart K—Ferroalloy Production 

We are finalizing two corrections to 

subpart K of Part 98 (Ferroalloy 

Production) as proposed. First, we are 

correcting Equation K–3 to revise the 

numerical term ‘‘2000/2205’’ to 

‘‘2/2205’’. Next, we are amending 40 

CFR 98.116(e) to require the reporting of 

the annual process CH4 emissions (in 

metric tons) from each electric arc 

furnace (EAF) used for the production of 

any ferroalloy listed in Table K–1 of 

subpart K of Part 98. These amendments 

are necessary for consistent reporting of 

CH4 emissions from all ferroalloy 

production facilities. The EPA received 

no comments on the proposed changes 

to subpart K. 

E. Subpart L—Fluorinated Gas 

Production 

The EPA is amending subpart L of 

Part 98 (Fluorinated Gas Production) to 

extend temporary, less detailed 

reporting requirements for fluorinated 

gas producers for an additional year, as 

proposed. The extension requires the 

same less detailed reporting for 

reporting year 2013 as for reporting 

years 2011 and 2012. The extension 

allows the EPA, as well as stakeholders, 

to consider the various options for 

reporting emissions under subpart L. 

We are finalizing all of the minor 

corrections to subpart L presented in the 

Table of 2013 Revisions as proposed 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934). The EPA received no 

comments objecting to the proposed 

changes to subpart L. 

F. Subpart N—Glass Production 

We are finalizing several clarifying 

revisions to subpart N of Part 98 (Glass 

Production) as proposed. The more 

substantive corrections, clarifying, and 

other amendments to subpart N are 

found here. We are finalizing all of the 

minor corrections to subpart N 

presented in the Table of 2013 Revisions 

as proposed. The EPA received no 

comments objecting to the proposed 

changes to subpart N. 

We are revising 40 CFR 98.144(b) as 

proposed to specify that reporters 

determining the carbonate-based 

mineral mass fraction must use 

sampling methods that specify X-ray 

fluorescence. 

Additionally, we are removing ASTM 

D6349–09 and ASTM D3682–01 from 

the requirements in 98.144(b) as 

proposed. These amendments allow 

reporters flexibility in choosing a 

sampling method (because multiple Xray fluorescence methods are available). 

For measurements made in the emission 

reporting year 2013 or prior years, 

reporters continue to have the option to 

use ASTM D6349–09 and ASTM 

D3682–01. Reporters are not required to 

revise previously submitted annual 

reports. Facilities have the option, but 

are not required, to use the newly 

proposed option for the reports 

submitted to EPA in 2013. 

G. Subpart O—HFC–22 Production and 

HFC–23 Destruction 

The EPA is finalizing clarifying 

amendments and other corrections to 

subpart O (HFC–22 Production and 

HFC–23 Destruction) as proposed. The 

more substantive corrections, clarifying, 

and other amendments to subpart O are 

found in this section. We are finalizing 

all of the minor corrections to subpart 

O presented in the Table of 2013 

Revisions as proposed. 

We are adding a sentence to 40 CFR 

98.156(c) to clarify how to report the 

HFC–23 concentration at the outlet of 

the destruction device in the event that 

the concentration falls below the 

detection limit of the measuring device. 

The final rule clarifies that in this 

situation, facilities are required to report 

the detection limit of the measuring 

device and that the concentration was 

below that detection limit. The EPA 

received no comments on the proposed 

changes to subpart O. 

H. Subpart P—Hydrogen Production 

1. Summary of Final Amendments 

The EPA is finalizing the corrections 

and clarifications to subpart P as 

proposed. The more substantive 

corrections, clarifying, and other 

amendments to subpart P are found 

here. Additional minor corrections, 

including minor edits to the final rule, 

are presented in the Table of 2013 

Revisions (see Docket Id. No. EPA–HQ– 

OAR–2012–0934). The EPA received no 

comments objecting to the proposed 

changes to subpart P. 

We are finalizing 40 CFR 98.163(b), as 

proposed, to clarify that when the fuel 

and feedstock material balance 

approach is followed, the average 

carbon content and molecular weight for 

each month used in Equations P–1, P– 

2, or P–3 may be based on analyses 

performed annually or analyses 

performed more frequently than 

monthly (based on the requirements of 

40 CFR 98.164(b)). Additionally, we are 

revising the term definitions in 

Equations P–1, P–2, and P–3 to remove 

references to the frequency of analyses 

in equation terms ‘‘CCn’’ and ‘‘MWn’’ in 

Equation P–1 and equation term ‘‘CCp’’ 

in Equations P–2 and P–3, since the 

analysis frequencies are not described in 

the introductory text at 40 CFR 

98.163(b), as discussed above. 

The final amendments to subpart P 

include revising the equation term 

‘‘Fdstckn’’ in Equations P–1 and P–2 and 

revising the language in paragraphs 40 

CFR 98.166(b)(2) and (b)(5). These 

changes optionally allow the gaseous or 

liquid feedstock quantity to be 

measured on a mass basis in addition to 

the already-specified volumetric basis. 

The change to the equation term 

‘‘Fdstckn’’ is consistent with changes 

made to subpart X, and allows the 

results from flow meters that measure 

gas and liquid materials on a mass basis 

to be used directly in Equation P–1 or 

P–2 without first having to perform unit 

conversions. All changes add flexibility 

for reporters, and should lead to fewer 

reporting errors. 

We are modifying 40 CFR 98.164(b)(5) 

as proposed by allowing a facility to 

analyze fuels and feedstocks using 

chromatographic analysis, whether 

continuous or non-continuous. 

Additionally, we are moving 

recordkeeping requirements 40 CFR 

98.164(c) and (d) to new paragraphs 40 

CFR 98.167(c) and (d) in 40 CFR 98.167 

(Records that must be retained). Finally, 

we are revising 40 CFR 98.166(a)(2) and 

(a)(3) to remove the requirement to 

report hydrogen and ammonia 

production for all units combined. 

These amendments are finalized as 

proposed. The EPA received no 

comments objecting to the proposed 

changes to subpart P. 

2. Summary of Comments and 

Responses 

See the comment response document 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to 


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subpart P. The EPA received only 

supportive comments for subpart P, 

therefore, there are no changes from 

proposal to the final rule based on these 

comments. 

I. Subpart Q—Iron and Steel Production 

1. Summary of Final Amendments 

The EPA is finalizing clarifying 

amendments to subpart Q (Iron and 

Steel Production) as proposed. The 

more substantive corrections, clarifying, 

and other amendments to subpart Q are 

found here. We are finalizing all of the 

minor corrections presented in the 

Table of 2013 Revisions as proposed 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

We are amending the definition of the 

iron and steel production source 

category in subpart Q, 40 CFR 98.170, as 

proposed, to include direct reduction 

furnaces not co-located with an 

integrated iron and steel manufacturing 

process. We are amending Equation Q– 

5 in subpart Q to account for the use of 

gaseous fuels in EAFs. Specifically, we 

are modifying Equation Q–5 by adding 

terms to account for the amount of 

gaseous fuel combusted and the carbon 

content of the gaseous fuel. We are also 

amending Equation Q–5 by correcting 

the term ‘‘Cf’’ to ‘‘Cflux’’ and the term 

‘‘Cc’’ to ‘‘Ccarbon’’ to match those 

presented in the definitions, and to add 

a closing bracket at the end of the 

equation. These amendments are 

finalized as proposed. 

We are revising 40 CFR 98.173(d) as 

proposed to clarify when the Tier 4 

calculation methodology must be used 

to calculate and report combined stack 

emissions. The amendment clarifies that 

the Tier 4 calculation methodology 

should be used (and emissions reported 

under subpart C of Part 98) if the GHG 

emissions from a taconite indurating 

furnace, basic oxygen furnace, nonrecovery coke oven battery, sinter 

process, EAF, decarburization vessel, or 

direct reduction furnace are vented 

through a stack equipped with a CEMS 

that complies with the Tier 4 

methodology in subpart C of this part, 

or 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. 

We are amending 40 CFR 98.174(c)(2) 

as proposed by removing the term 

‘‘furnace’’ from the statement ‘‘For the 

furnace exhaust,’’ because 

decarburization vessels are not furnaces. 

We are also amending 40 CFR 

98.174(c)(2) by dividing (c)(2) into two 

separate sub paragraphs to separately 

specify the sampling time for 

continuously charged EAFs. We are 

removing the term ‘‘production cycles’’ 

for continuous EAFs and provide 

owners or operators with the option of 

sampling for a period spanning at least 

three hours. These amendments are 

finalized as proposed. 

We are amending 40 CFR 98.175(a) as 

proposed to clarify that 100 percent data 

availability is not required for process 

inputs and outputs that contribute less 

than one percent of the total mass of 

carbon into or out of the process. 

Similarly, we are finalizing the 

amendment to 40 CFR 98.176(e) 

clarifying that the reporting 

requirements of 40 CFR 98.176(e) do not 

apply to process inputs and outputs that 

contribute less than one percent of the 

total mass of carbon into or out of the 

process. 

2. Summary of Comments and 

Responses 

See the comment response document 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to 

subpart Q. The EPA received only 

supportive comments for subpart Q, 

therefore, there are no changes from 

proposal to the final rule based on these 

comments. 

J. Subpart W—Petroleum and Natural 

Gas Systems 

The EPA is amending subpart W to 

incorporate minor revisions to three 

equations for consistency with the 

revisions to Table A–1 that we are 

finalizing in this action. The subpart W 

calculations for annual mass of GHG 

emissions for gas pneumatic device 

venting and natural gas driven 

pneumatic pump venting in CO2e are 

calculated using a conversion factor that 

was developed using the methane GWP 

from Table A–1. The affected equations 

are Equation W–1, which calculates the 

mass of CO2e using a conversion factor 

(Convi) that is developed from the 

methane GWP; Equation W–2, which 

also calculates the mass of CO2e using 

a conversion factor (Convi) that is 

developed from the methane GWP; and 

Equation W–36 in 40 CFR 

98.233(u)(2)(v), which incorporates 

numeric GWPs for CH4 and N2O. 

Because the GWP values that inform the 

methane calculations in these three 

equations reference the previous GWP 

value, each equation needs to be 

amended separately to change the 

numeric GWP. While the EPA proposed 

that the new GWP apply throughout all 

of Part 98, the EPA did not specifically 

propose amendments to the regulatory 

text referencing the numeric GWP in 

these three discrete equations. In 

addition to finalizing the GWP value for 

methane in Table A–1, we are also 

amending the methane conversion 

factor and methane GWP used in these 

three subpart W equations to ensure the 

correct GWP value for methane in Table 

A–1 is used in these calculations. 

K. Subpart X—Petrochemical 

Production 

1. Summary of Final Amendments 

The EPA is finalizing corrections and 

clarifications to subpart X. The more 

substantive corrections, clarifying, and 

other amendments to subpart X are 

found here. Additional minor 

corrections to subpart X, including 

changes to the final rule, are discussed 

in the Table of 2013 Revisions (see 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). 

We are finalizing several amendments 

to subpart X as proposed. We are 

revising the calculation methodology in 

40 CFR 98.243(b) for CH4 and N2O 

emissions from burning process off-gas 

for reporters using the CEMS method to 

determine CO2 emissions; the revision 

requires reporters to use Equation C–10 

of subpart C of Part 98. Reporters must 

use the cumulative annual heat input 

from combustion of the off-gas (mmBtu) 

and fuel gas emission factors from Table 

C–2 to calculate emissions of CH4 and 

N2O. We are revising 40 CFR 

98.243(c)(3) and 40 CFR 98.244(b)(4) to 

allow subpart X reporters that use the 

mass balance calculation method to 

obtain carbon content measurements 

from a customer of the product. 

Additionally, we are revising 40 CFR 

98.243(c)(4) to allow the alternative 

sampling requirements to be used 

during all times that the average 

monthly concentration is above 99.5 

percent of a single compound for 

reporters using the mass balance 

calculation method. We are also 

replacing the Equation X–1 parameters 

‘‘(MWf)i’’ and ‘‘(MWp)i’’ with parameters 

‘‘(MWf)i,n’’ and ‘‘(MWp)i,n’’, respectively, 

and adding the associated equation term 

definitions, and revising the definitions 

for the terms ‘‘Cg’’, ‘‘(Fgf)i,n’’ and 

‘‘(Pgp)i,n’’ in Equation X–1 as proposed. 

We are revising the test method 

description for chromatographic 

analysis in 40 CFR 98.244(b)(4)(xiii) to 

remove the word ‘‘gas’’. We are also 

modifying 40 CFR 98.244(b)(4)(xv) to 

allow additional methods for the 

analysis of carbon black feedstock oils 

and carbon black products. We are 

revising the missing data procedures in 

40 CFR 98.245 to clarify that the 

procedures for missing fuel carbon 

contents in 40 CFR 98.35(b)(1) are to be 

used only for missing feedstock and 


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26We are finalizing confidentiality 

determinations for the revised data element in 40 

CFR 98.246(b)(4). See Section V of this preamble for 

additional information. 

product carbon contents, and the 

procedures for missing fuel usage in 40 

CFR 98.35(b)(2) are to be used to 

develop substitute values for missing 

feedstock and product flow rates. We 

are also adding missing data 

requirements for missing flare data and 

for missing molecular weights for 

gaseous feedstocks and products. These 

amendments are finalized as proposed. 

We are finalizing two amendments to 

clarify the reporting requirements of 40 

CFR 98.246(a)(6) for reporters using the 

mass balance method. Specifically, we 

are amending 40 CFR 98.246(a)(6) to 

require reporters to report the name of 

each method that is used to determine 

carbon content or molecular weight in 

accordance with 40 CFR 98.244(b)(4). 

We are also requiring reporters to 

describe each type of device used to 

determine flow or mass (e.g., flow meter 

or weighing device) and identify the 

method used to determine flow or mass 

for each device in accordance with 40 

CFR 98.244(b)(1) through (b)(3). We are 

revising 40 CFR 98.246(a)(8) to specify 

that reporters using the mass balance 

calculation method must identify 

combustion units outside of the 

petrochemical process unit that burned 

process off-gas. These amendments are 

finalized as proposed. 

As proposed, we are removing the 

requirements in 40 CFR 98.246(b)(4) and 

(b)(5) to report CO2, CH4, and N2O 

emissions from each CEMS location and 

the requirement to report the aggregated 

total emissions from all CEMS locations. 

In 40 CFR 98.246(b)(5) we are removing 

the requirements to report inputs to 

Equation C–8. Instead of the Equation 

C–8 inputs, reporters will report the 

total annual heat input for Equation C– 

10, as required in 40 CFR 98.35(c)(2). 

Finally, we are removing the 

requirement to identify each stationary 

combustion unit that burns 

petrochemical process off-gas. These 

amendments are finalized as proposed. 

The final amendments include several 

changes to proposed language to better 

reflect our intent but that do not change 

the underlying requirement. For 

example, a proposed change in 40 CFR 

98.242(b)(2) specified that emissions 

from burning petrochemical process offgas in any combustion unit are not to be 

reported under subpart C. The final 

amendments clarify that ‘‘any 

combustion unit’’ includes combustion 

units that are not part of the 

petrochemical process unit. 

The final amendments to subpart X 

include changes to the proposed quality 

assurance/quality control (QA/QC) 

requirements for flare gas monitoring 

instruments. After consideration of a 

public comment, we are specifying in 

the final amendments (40 CFR 

98.244(c)) that reporters using the 

methodology in 40 CFR 98.243(b) or (d) 

must be complying with all applicable 

QA/QC requirements in 40 CFR 

98.254(b) through (e) for flare gas 

monitoring instruments beginning no 

later than January 1, 2015. The proposed 

amendments did not specify when 

reporters would be required to comply 

with these requirements. The final 

amendments also clarify that QA/QC 

requirements for flare gas monitoring 

instruments apply in the same manner 

as under other subparts such as subpart 

Y. Specifically, if a facility has installed 

a flare gas monitor, then specified QA/ 

QC requirements apply to that monitor. 

However, if the reporter estimates a flare 

gas characteristic based on engineering 

records or other information, as allowed 

under 40 CFR 98.253(b)(1) through 

(b)(3), then the QA/QC requirements in 

40 CFR 98.254(b) through (e) do not 

apply. 

The final amendments include 

changes to clarify the reporting 

requirements in 40 CFR 98.246(a)(9) for 

reporters using the alternative to 

sampling and analysis in 40 CFR 

98.243(c)(4). The proposed changes to 

this section addressed various reporting 

requirements related to off-spec 

production of a product. The final 

amendments clarify that the off-spec 

production reporting requirements 

apply only if the alternative 

methodology is being used for the 

product in question. The purpose of the 

off-spec reporting is to ensure that 

appropriate carbon content values are 

being used. Carbon content of a 

feedstock is not affected by process 

upsets that result in off-spec product. 

Thus, there is no need to report off-spec 

product when the alternative 

methodology is being used only for a 

feedstock. This section of subpart X also 

requires reporting of the dates of any 

process changes that reduce the 

composition of the primary component 

in the subject stream to less than 99.5 

percent. According to 40 CFR 

98.243(c)(4), the alternative 

methodology is not allowed if the 

‘‘average monthly’’ concentration falls 

below 99.5 percent. Thus, to make the 

two sections consistent, the final 

amendments to 40 CFR 98.246(a)(9) 

require reporting of dates of process 

changes that cause the ‘‘monthly 

average’’ composition to fall below 99.5 

percent. 

The final amendments also include 

changes to 40 CFR 98.246(b)(4). The 

proposed amendments to this section 

required reporting of an estimate of the 

fraction of total CO2 emissions 

measured by the CEMS that is 

‘‘attributable to the petrochemical 

process unit.’’ After further 

consideration, we determined that the 

term ‘‘attributable to’’ may be 

ambiguous. Therefore, the final 

amendments clarify that the emissions 

to use in estimating the fraction include 

both CO2 directly emitted by the process 

plus CO2 generated by combustion of 

off-gas from the petrochemical process 

unit.26 The final amendments also 

include several additional changes 

throughout subpart X to replace 

incorrect paragraph references as well as 

to fix formatting, typographical, and 

grammatical errors. All of these changes, 

as well as the changes that are described 

in more detail above, are presented in 

the Table of Revisions to this 

rulemaking (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

The EPA received two suggested 

revisions for subpart X that are beyond 

the scope of this rulemaking. These 

included a request to report vinyl 

chloride monomer production in lieu of 

ethylene dichloride production, and a 

request for alternative options for 

determining and reporting carbon 

content of small feedstock streams 

(streams that constitute less than 0.5% 

of the total feedstock flow on an annual 

basis). Although we are not including 

the suggested revisions in this final rule, 

the EPA is considering these comments 

for inclusion in a future rulemaking. See 

the comment response document for 

subpart X in Docket Id. No. EPA–HQ– 

OAR–2012–0934 for additional 

information. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart X. See the comment response 

document for subpart X in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart X. 

Comment: One commenter stated that 

the EPA should provide additional time 

for reporters to add any existing flare 

gas monitoring instrumentation to the 

GHG Monitoring Plan and into existing 

maintenance database systems to ensure 

that they are calibrated in accordance 

with the new QA/QC requirements in 40 

CFR 98.244(c). The commenter stated 

that the compliance date should be no 

earlier than July 1, 2014. 

Response: We agree with the 

commenter that some time is needed for 


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reporters to modify their monitoring 

plans and maintenance systems if they 

are not already implementing 

procedures consistent with the new 

requirements. Although compliance 

could be achieved any time during a 

year, for reporting purposes we have set 

the compliance date at the beginning of 

a reporting year. While we considered 

setting the compliance date on January 

1, 2014, we determined that that date 

would not provide sufficient time for all 

facilities to come into compliance with 

these requirements. We determined that 

January 1, 2015 would provide 

sufficient time for all facilities to come 

into compliance regardless of the 

number of flares they use or the number 

of monitoring instruments that they use. 

L. Subpart Y—Petroleum Refineries 

1. Summary of Final Amendments 

The EPA is finalizing changes, 

technical corrections, and clarifying 

amendments to subpart Y (Petroleum 

Refineries) as proposed. The more 

substantive corrections, clarifying, and 

other amendments to subpart Y are 

found here. Additional minor 

corrections, including changes to the 

final rule, are presented in the Table of 

2013 Revisions (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

As proposed, we are revising in 40 

CFR 98.252(a) the reference to the 

default emission factors for ‘‘Petroleum 

(All fuel types in Table C–1)’’ to ‘‘Fuel 

Gas’’ and in 40 CFR 98.253(b)(2) and 

(b)(3) from ‘‘Petroleum Products’’ to 

‘‘Fuel Gas’’ for calculation of CH4 and 

N2O from combustion of fuel gas. 

We are revising 40 CFR 98.253(f)(2), 

(f)(3), and (f)(4) and the terms ‘‘FSG’’ and 

‘‘MFc’’ in Equation Y–12 as proposed to 

clarify the calculation methods for 

sulfur recovery plants to address both 

on-site and off-site sulfur recovery 

plants. We are also revising the 

reporting requirements in 40 CFR 

98.256(h) as proposed in order to clarify 

the reporting requirements for on-site 

and off-site units. 

As proposed, we are clarifying 40 CFR 

98.253(j) regarding when Equation Y–19 

must be used for calculation of CH4 and 

CO2 emissions. The change clarifies that 

Equation Y–19 must be used to calculate 

CH4 emissions if the reporter elected to 

use the method in 40 CFR 98.253(i)(1), 

and may be used to calculate CO2 and/ 

or CH4 emissions, as applicable, if the 

reporter elects this method as an 

alternative to the methods in paragraphs 

(f), (h), or (k) of 40 CFR 98.253. We are 

also clarifying reporting requirements to 

40 CFR 98.256(j) and (k) as proposed to 

specify that when Equation Y–19 is 

used for asphalt blowing operations or 

delayed coking units, the facility must 

report the relevant information required 

under 40 CFR 98.256(l)(5) rather than all 

of the reporting elements in 40 CFR 

98.256(l). 

2. Summary of Comments and 

Responses 

See the comment response document 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to 

subpart Y. The EPA did not receive any 

significant comments on this subpart 

and there are no changes from proposal 

to the final rule based on these 

comments. 

M. Subpart Z—Phosphoric Acid 

Production 

1. Summary of Final Amendments 

The EPA is finalizing the amendments 

to subpart Z (Phosphoric Acid 

Production) as proposed. The more 

substantive corrections, clarifying, and 

other amendments to subpart Z of Part 

98 are discussed in this section. 

Additional minor corrections are 

discussed in the Table of 2013 Revisions 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934). We are finalizing all of the 

minor corrections presented in the 

Table of 2013 Revisions as proposed. 

The EPA received one comment 

requesting clarification on the proposed 

changes to subpart Z. See the comment 

response document in Docket Id. No. 

EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart Z. 

We are amending 40 CFR 

98.263(b)(1)(ii) and the description of 

‘‘CO2n,i’’ as proposed to indicate that the 

sampling method provides CO2 content, 

and not emissions. We are also revising 

40 CFR 98.266(b) as proposed to require 

that the annual report must include the 

annual phosphoric acid production 

capacity (tons), rather than the annual 

permitted phosphoric acid production 

capacity. Finally, we are amending 40 

CFR 98.266 as proposed to add a 

requirement to report the number of 

times missing data procedures were 

used to estimate the CO2 content of the 

phosphate rock. 

2. Summary of Comments and 

Responses 

See the comment response document 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to 

subpart Z. The EPA did not receive any 

significant comments for this subpart, 

therefore, there are no changes from 

proposal to the final rule based on these 

comments. 

N. Subpart AA—Pulp and Paper 

Manufacturing 

1. Summary of Final Amendments 

The EPA is finalizing the corrections 

and clarifications to subpart AA as 

proposed and is removing the subpart 

AA requirement to report paper 

production in response to public 

comments. The more substantive 

corrections, clarifying, and other 

amendments to subpart AA of Part 98 

are discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 

Revisions. 

As proposed, we are amending 40 

CFR 98.276(k) to clarify the EPA’s intent 

regarding the annual pulp and/or paper 

production information that must be 

reported. In the final amendments, we 

are eliminating the requirement to 

report paper production and further 

clarifying that the pulp production total 

to be reported under subpart AA 

includes only virgin chemical pulp 

produced onsite. 

We are revising Tables AA–1 and 

AA–2 as proposed to include the CH4

and N2O emission factors for each 

individual fuel and adding kraft lime 

kiln N2O factors. 

We are also revising Table AA–2 to (1) 

Amend the title to remove the reference 

to fossil fuel since the table also 

includes a biomass fuel (i.e., biogas); (2) 

specify that the emission factors for 

residual and distillate oil apply for any 

type of residual (no. 5 or 6) or distillate 

(no. 1, 2 or 4) fuel oil; and (3) add a row 

to specify that the Table C–2 emission 

factor for CH4 and the Table C–2 

emission factors for CH4 and N2O may 

be used, respectively, for lime kilns and 

calciners combusting fuels (e.g., 

propane, used oil, and lubricants) that 

are not listed in Table AA–2. 

The EPA received one comment 

suggesting a revision to subpart AA that 

is beyond the scope of this rulemaking. 

Specifically, the commenter requested 

revisions to the missing data reporting 

requirements for spent liquor solids in 

40 CFR 98.275. Although we are not 

including the suggested revisions in this 

final rule, the EPA is considering these 

comments for inclusion in a future 

rulemaking. See the comment response 

document for subpart AA in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for 

additional information. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart AA. See the comment response 

document for subpart AA in Docket Id. 


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No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart AA. 

Comment: A commenter requested 

clarification regarding inclusion of nonchemical pulp (e.g., mechanical pulp) in 

the pulp production total to be reported. 

The commenter also requested that 

paper production be eliminated from 

the subpart AA reporting requirements 

because paper production does not 

relate to GHG emissions generated in 

the pulp mill and reported under 

subpart AA. 

Response: In the final amendments 

we are clarifying that the pulp 

production total to be reported is the 

total air-dried, unbleached virgin 

chemical pulp produced onsite during 

the reporting year and that mechanical 

pulp does not need to be included in the 

total. Greenhouse gas emissions 

reported under subpart AA depend on 

the amount of pulp produced using 

chemical (e.g., kraft, soda, sulfite, and 

semichemical) pulping processes. 

Emissions associated with onsite energy 

generation for mechanical pulping are 

reported under subpart C of Part 98 

(Stationary Combustion). Reporting the 

total annual production of air-dried 

unbleached virgin chemical pulp 

provides a common pulp reporting basis 

regardless of production processes (e.g., 

bleaching, secondary fiber pulping, and 

paper making) that happen downstream 

of the virgin chemical pulping process 

where the subpart AA GHG emissions 

are generated. 

Mills with positive subpart AA 

emissions should always report a 

positive virgin chemical pulp 

production value. In the final 

amendments we removed the proposed 

requirement to report a positive (nonzero) value for pulp production because 

some mills may wish to report zero pulp 

production in conjunction with zero 

subpart AA emissions in years when 

they do not produce any virgin chemical 

pulp. 

We also examined the correlation 

between paper production and subpart 

AA emissions and agree that additional 

information would need to be collected 

for GHG emissions to be meaningfully 

normalized based on paper production. 

The tonnage of paper produced does not 

necessarily relate to the subpart AA 

GHG emissions generated in the 

chemical pulp mill. Paper is often 

produced using combinations of 

chemical pulp, non-chemical pulp, and 

secondary (recycled) fiber that may be 

either purchased or produced onsite, 

along with clay fillers, on-machine 

coatings, and other additives that 

contribute to the metric tons of paper 

produced. Bleaching processes that 

occur between the pulp and paper 

production areas of integrated pulp 

mills result in a slight loss of virgin 

pulp tonnage, further reducing the 

correlation between chemical pulp mill 

emissions reported under subpart AA 

and paper production. Furthermore, the 

paper production data reported under 

subpart AA provides an incomplete 

picture of GHG emissions normalized 

per metric ton of paper produced 

because reporting of paper production is 

not required under Part 98 for mills that 

do not report under subpart AA, such as 

mechanical pulp mills and mills that 

manufacture paper from purchased pulp 

(e.g., paper-only mills that report under 

subpart C). For these reasons, we have 

eliminated reporting of paper 

production from subpart AA in the final 

amendments. The EPA may consider at 

a later date whether it is necessary to 

propose new reporting requirements 

under Part 98 that would allow for a 

refined normalization of GHG emissions 

per ton of paper produced for all types 

of pulp and paper mills. 

O. Subpart BB—Silicon Carbide 

Production 

We are finalizing several revisions to 

subpart BB of Part 98 (Silicon Carbide 

Production) as proposed. The more 

substantive corrections, clarifying, and 

other amendments to subpart BB of Part 

98 are discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed. 

We are revising 40 CFR 98.282(a) to 

remove the requirement for silicon 

carbide production facilities to report 

CH4 emissions from silicon carbide 

process units or furnaces. We are 

removing 40 CFR 98.283(d) to remove 

the CH4 calculation methodology. As 

discussed in the preamble to the 

proposed amendments (78 FR 19802, 

April 2, 2013), the EPA has determined 

that the requirement to report CH4

emissions is not necessary to 

understand the emissions profile of the 

industry. 

Reporters must continue to monitor 

and report CO2 emissions from silicon 

carbide process units and production 

furnaces. We are revising 40 CFR 98.283 

so that CO2 emissions are to be 

calculated and reported for all process 

units and furnaces combined. The final 

rule revises 40 CFR 98.283 for 

consistency with the reporting 

requirements of 40 CFR 98.286. These 

amendments are finalized as proposed. 

The EPA received no comments on the 

proposed changes. 

P. Subpart DD—Electrical Transmission 

and Distribution Equipment Use 

We are finalizing two substantive 

corrections to subpart DD (Electrical 

Transmission and Distribution 

Equipment Use) as proposed. We are 

revising 40 CFR 98.304(c)(1) and (c)(2) 

to correct the accuracy and precision 

requirements for weighing cylinders 

from ‘‘2 pounds of the scale’s capacity’’ 

to ‘‘2 pounds of true weight’’. The EPA 

received no comments objecting to the 

proposed changes. 

Q. Subpart FF—Underground Coal 

Mines 

We are finalizing multiple 

amendments to subpart FF of Part 98 

(Underground Coal Mines) as proposed. 

The final amendments clarify certain 

provisions and equation terms, 

harmonize reporting requirements, and 

improve verification of annual GHG 

reports. The more substantive 

corrections, clarifying, and other 

amendments to subpart FF of Part 98 are 

discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed. 

We are revising the terminology in 

subpart FF provisions in 40 CFR 

98.320(b), 40 CFR 98.322(b) and (d), 40 

CFR 98.323(c), 40 CFR 98.324(b) and (c), 

and 40 CFR 98.326(r) as proposed to 

adopt terminology that more accurately 

reflects industry operation. Specifically, 

for ventilation systems, we have 

replaced the terminology ‘‘wells’’ with 

‘‘ventilation system shafts’’ or ‘‘vent 

holes’’, and for degasification systems, 

we have replaced the terminology 

‘‘shafts’’ with ‘‘gob gas vent holes’’. We 

have also revised the term ‘‘flaring’’ to 

clarify that mine ventilation air is 

destroyed using a ventilation air 

methane (VAM) oxidizer. 

We are revising the reporting 

requirements of subpart FF as proposed 

to include additional data elements that 

will allow the EPA to verify the data 

submitted, perform a year to year 

comparison of the data, and assess the 

reasonableness of the data reported. The 

additional data elements are included in 

revised 40 CFR 98.326(h), (i), (j), (o), (r), 

and new requirement (t) include: The 

moisture correction factor used in the 

emissions equations, units of measure 

for the volumetric flow rates reported, 

method of determining the gas 

composition, the start date and close 

date of each well, shaft, or vent hole, 

and the number of days the well, shaft, 

or vent hole was in operation during the 

reporting year. We are also adding a 

requirement (40 CFR 98.326(t)) for a 

reporting mine to provide the 


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27We are finalizing confidentiality 

determinations for the new and significantly 

revised data elements in 40 CFR 98.326. See Section 

V of this preamble for additional information. 

28We are finalizing confidentiality 

determinations for the revised data elements in 40 

CFR 98.346(i)(5), (i)(6), and (i)(7). See Section IV.A 

of this preamble for additional information. 

identification number assigned to it by 

the Mine Safety and Health 

Administration (MSHA). The reporting 

requirements have also been updated to 

harmonize with changes to the 

calculation methods as itemized in the 

Table of 2013 Revisions (see Docket Id. 

No. EPA–HQ–2012–0934). These 

amendments are finalized as 

proposed.27

The EPA received no comments to the 

proposed changes. However, one 

reporting requirement that was 

proposed to be added as 40 CFR 

98.326(t), the amount of CH4 routed to 

each destruction device, was 

subsequently discovered to be 

redundant with information already 

collected under the rule, namely, 40 

CFR 98.326(c) quarterly CH4 destruction 

at each ventilation and degasification 

system destruction device or point of 

offsite transport. Therefore, the 

proposed requirement is no longer being 

added. Additionally, the new reporting 

requirement to provide the 

identification number assigned by 

MSHA is now numbered as 40 CFR 

98.326(t), instead of 40 CFR 98.326(u) as 

it was proposed. 

R. Subpart HH—Municipal Solid Waste 

Landfills 

1. Summary of Final Amendments 

We are finalizing several amendments 

to 40 CFR Part 98, subpart HH 

(Municipal Solid Waste Landfills) to 

clarify equations and amend monitoring 

requirements to reduce burden for 

reporters, where appropriate. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). We are finalizing 

amendments to the definition of the 

DOC term (degradable organic carbon) 

for Equation HH–1, as proposed, to 

indicate that the DOC values for a waste 

type must be selected from Table HH– 

1. We are also finalizing amendments, 

as proposed, to the definition of the 

term ‘‘F’’ in Equation HH–1 (fraction by 

volume of CH4 in the landfill gas) to 

specify that this term must be corrected 

to zero percent (0%) oxygen and 

finalizing amendments to the 

monitoring requirements at 40 CFR 

98.344(e) to specify how to correct this 

term to zero percent (0%) oxygen. 

We are finalizing amendments, as 

proposed, to change the minimum CH4

concentration monitoring frequency in 

recovered landfill gas from weekly to 

monthly. We are retaining the 

requirement, as proposed, to have 14 

days between monthly sampling events 

if only one sample is collected per 

calendar month. 

We are finalizing revisions to the 

definition of oxidation fraction in 

Equations HH–5, HH–6, HH–7, and HH– 

8 of subpart HH to refer to the oxidation 

fractions in Table HH–4 (although, as 

discussed below, we are revising Table 

HH–4 based on comments received). We 

are finalizing revisions to Equations 

HH–6, HH–7, and HH–8 to generalize 

these equations in the event that the 

landfill contains multiple landfill gas 

collection system measurement 

locations and/or multiple destruction 

devices. While we are finalizing 

amendments to nearly all of the terms 

for Equations HH–6, HH–7, and HH–8 

as proposed, we are further revising the 

proposed definition fDest,n in Equations 

HH–6 and HH–8 to delete the phrase 

‘‘. . . is destroyed in a back-up flare (or 

similar device) or if the gas . . .’’ Since 

the revised equations explicitly consider 

on-site back-up control devices, it is no 

longer necessary to assume fDest = 1 

when a back-up flare is used. We are 

also finalizing proposed revisions to the 

reporting requirements associated with 

fDest,n in 40 CFR 98.346(i)(5). As 

proposed, we are finalizing amendments 

to generalize the reporting requirements 

for each measurement location. 

Additionally, based on the revisions to 

fDest,n outlined above, we are replacing 

requirements to report operating hours 

for the ‘‘primary’’ and ‘‘back-up’’ 

destruction device and a single value of 

destruction efficiency with 

requirements to report the number of 

destruction devices and the operating 

hours and destruction efficiency for 

each device associated with a given 

measurement location. We are also 

finalizing amendments to 40 CFR 

98.346(i)(6) and 40 CFR 98.346(i)(7) to 

clarify that methane recovery calculated 

using Equation HH–4 is to be reported 

separately for each measurement 

location.28 We are finalizing 

amendments as proposed to revise ‘‘in 

reporting years’’ to ‘‘in the reporting 

year’’ in the first sentence in 40 CFR 

98.345(c). We are also finalizing, as 

proposed, amendments to move the 

reporting elements pertaining to the 

methane correction factor (MCF) from 

paragraph (d)(1) to paragraph (e). 

We are finalizing numerous revisions 

to the proposed oxidation fractions in 

Table HH–4. First, we are specifying 

that the oxidation fractions based on 

methane flux are only applicable for the 

2013 reporting year and subsequent 

reporting years and that an oxidation 

fraction of 0.10 must be used for 

reporting years prior to 2013. We are 

also specifying that, for the 2013 

reporting year and subsequent reporting 

years, owners or operators of landfills 

that do not have a soil cover of at least 

twenty-four inches in depth for a 

majority of the landfill area containing 

waste must use an oxidation fraction of 

0.10 and owners or operators of landfills 

that have a geomembrane cover with 

less than 12 inches of soil must use an 

oxidation fraction of 0.0. We are 

allowing owners or operators of landfills 

to use the default oxidation fraction of 

0.10 (except for geomembane covers 

with less than 12 inches of soil) without 

determining their methane flux rate in 

lieu of the new oxidation fractions 

based on methane flux rates. This limits 

any additional burden associated with 

determining the methane flux rates to 

only those owners or operators of 

landfills that elect to use the new 

methane flux-dependent oxidation 

fractions. 

While we are finalizing the methane 

flux-dependent oxidation fraction 

values as proposed, we are limiting to 

some extent, considering the public 

comments received, the landfills that 

can use these new methane fluxdependent oxidation fractions to those 

that have cover soils of 24 inches or 

more over a majority of the landfill area 

containing waste. Nearly all of the data 

upon which the new methane fluxdependent oxidation fractions were 

based were for landfills with soil covers 

over 30 inches in depth, so it is 

reasonable to limit the use of the new 

methane flux-dependent oxidation 

fractions to landfills with similar soil 

cover systems. 

We are revising the definition of the 

term GCH4 (modeled methane generation 

rate) in the footnote to Table HH–4 to 

indicate that the modeled methane 

generation rate is determined from 

Equation HH–1 of subpart HH or 

Equation TT–1 of subpart TT, as 

applicable, because Table HH–4 is 

referenced in subpart TT and owners or 

operators of industrial waste landfills 

must use Equation TT–1 rather than 

Equation HH–1 to determine the 

modeled methane generation rate. 

We are making one revision to subpart 

HH based on comments received on the 

expansion of applicability that will 

occur in the MSW Landfill sector due to 

the revision of the GWP for methane to 

the IPCC AR4 value. Specifically, we are 

providing a very limited exclusion 

within 40 CFR 98.340 for certain closed 

landfills that have not previously had to 


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report under subpart HH, but would 

newly be required to report starting in 

reporting year 2014 because the 

amended methane GWP causes them to 

exceed the 25,000 metric tons CO2e 

emissions threshold for the first time. 

We have added this exclusion to reduce 

the burden for these closed landfills, 

who would otherwise be required to 

estimate historical waste quantities and 

develop their first annual report. See 

Section II.R.2 of this preamble for 

additional information. 

Finally, the EPA received one 

comment on subpart HH on the need to 

revisit the k-value decay rates used in 

the first order decay model for wet 

landfills, although we did not propose 

to revise these values. Although we are 

not including the suggested revisions in 

this final rule, the EPA may consider 

these comments for inclusion in a future 

rulemaking. See the comment response 

document for subpart HH in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for 

additional information. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart HH. See the comment response 

document for subpart HH in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart HH. 

Comment: Several commenters noted 

that the proposed revised definition of 

fDest,n for Equations HH–6 and HH–8 

includes a special provision when gas is 

destroyed in a ‘‘back-up flare (or similar 

device).’’ The commenters stated that 

this distinction is an artifact of the 

original rule and is no longer necessary 

because the proposed revisions to HH– 

6 and HH–8 properly account for 

multiple control devices regardless of 

the amount of time any given control 

device operates during the year, or 

whether it is considered a primary or 

backup device. Therefore, the 

commenters recommended deleting the 

phase ‘‘is destroyed in a back-up flare 

(or similar device) or if the gas’’ from 

the definition of fDest,n. 

Response: We agree with the 

commenters. Because Equations HH–6 

and HH–8 have been generalized to 

directly account for on-site back-up 

destruction devices, the default of 1 is 

no longer necessary in the definition of 

fDest,n for these devices. The phrase 

requested to be deleted has been 

removed from the definition of fDest,n in 

today’s final rule. In addition, we found 

that the reporting requirements in 40 

CFR 98.346(i)(5) still had reporting 

requirements for ‘‘back-up’’ destruction 

devices. We proposed to revise this 

paragraph to require reporting for each 

measurement location, but considering 

the public comments and the revised 

definition for fDest,n in these final 

amendments, we also find that the 

reporting requirements in 40 CFR 

98.346(i)(5) for ‘‘back-up destruction 

devices’’ is confusing and obsolete. 

Therefore, based on our proposed 

revisions to Equations HH–6 and HH–8 

and our proposed revisions to 40 CFR 

98.346(i)(5), considering these public 

comments, we are finalizing the 

reporting requirements related to fDest,n

in the today’s final rule as follows: ‘‘If 

destruction occurs at the landfill 

facility, also report for each 

measurement location the number of 

destruction devices associated with that 

measurement location and the annual 

operating hours and the destruction 

efficiency (percent) for each destruction 

device associated with that 

measurement location.’’ 

In our review of the reporting 

requirements corresponding to the 

revisions to Equations HH–6 and HH–8 

in response to these comments, we also 

found that, when there are multiple 

methane recovery measurement 

locations, the methane recovery should 

be reported for each measurement 

location. We consider that 40 CFR 

98.343(b)(1) and (2) require use of 

Equation HH–4 separately for each 

monitoring location (e.g., 40 CFR 

98.343(b)(1) requires owners or 

operators of MSW landfills that have 

continuous monitoring systems to ‘‘. . . 

use this monitoring system and 

calculate the quantity of CH4 recovered 

for destruction using Equation HH–4 of 

this section.’’). It is also clear that the 

methane recovery and the fraction of 

hours the recovery system operated 

needs to be determined separately for 

each measurement location as these are 

separate inputs for Equations HH–6 and 

HH–8, as amended, when multiple 

measurement locations are used. For eGGRT to perform the necessary 

calculations and to support verification 

of reported methane generation and 

emissions, the measurement locationspecific recovery values need to be 

reported. Therefore, based on our 

review of the reporting requirements 

corresponding to the revisions to 

Equations HH–6 and HH8 in response to 

these comments, we are also finalizing 

amendments to 40 CFR 98.346(i)(6) to 

specify that the annual quantity of 

recovered CH4 calculated using 

Equation HH–4 must be reported for 

each measurement location and to 40 

CFR 98.346(i)(7) to specify that the 

annual operating hours of the gas 

collection system must be reported for 

each measurement location. 

Comment: Several commenters 

expressed support of the revisions to 

allow methane concentration 

measurements to be performed monthly 

rather than weekly; however, these 

commenters objected to the inclusion of 

the 14 day interval between monthly 

samples (if only one sample is collected 

per calendar month). The commenters 

stated that the EPA’s analysis of three 

years of data provided for 395 landfills 

showed that there is very little 

variability in methane concentration 

across either weekly or monthly 

measurements. Some of the commenters 

also stated that qualified personnel 

properly trained in instrument 

calibration, sample measurement, and 

documentation procedures must be used 

to collect the readings for QA purposes 

and the 14 day limitation significantly 

and unnecessarily complicates 

scheduling of required personnel. 

Finally, a commenter argued that, for 

destruction devices that operate only 

intermittently (a common occurrence), it 

may not be possible to take a monthly 

reading at least fourteen days apart due 

to the operating schedule of the device. 

For example, if a device only operates 

for several days at the end of one month 

and the beginning of the next month, it 

would be impossible to acquire a 

reading for each month at least 14 days 

apart. For these reasons, the 

commenters suggested that the proposed 

14 day interval between monthly 

samples be deleted from the rule. 

Response: As described in the memo 

‘‘Review of Weekly Landfill Gas 

Volumetric Flow and Methane 

Concentration’’ (dated October 18, 2012 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934), our analysis concluded there was 

an increase in the uncertainty of the 

annual methane recovery estimate if the 

sampling frequency was reduced from 

weekly to monthly, but that the increase 

in the uncertainty was acceptable given 

the significant reduction in sampling 

and analysis costs. In our analysis, we 

used monthly data readings that were a 

minimum of four weeks apart. That is, 

the monthly analysis assumed the 

measurement readings were taken at 

discrete monthly intervals. If no 

intervening interval is included, one 

could collect one sample near midnight 

on the last day of the month and a 

second sample just after midnight (i.e., 

the morning on the first day of the 

month), which would effectively be 

equivalent to monitoring bi-monthly. 

Further analysis of the same set of 

landfill data suggests the deletion of a 

minimum interval between monthly 

samples further increases the 


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uncertainty of the resulting recovery 

estimates without reducing costs for the 

landfill owner or operator (See 

‘‘Uncertainty of Monthly Landfill Gas 

Methane Concentration Measurements,’’ 

June 7, 2013 in Docket Id. No. EPA–HQ– 

OAR–2012–0934). Thus, while the 

variability in the methane composition 

may be limited, it is still somewhat 

variable and reducing the sampling 

frequency will increase the uncertainty 

of the methane recovery values. Without 

a significant corresponding reduction in 

burden, this increase in uncertainty 

cannot be justified. 

It is not clear how reducing the 

monitoring frequency to monthly with a 

minimum of a 14 day interval would be 

onerous for scheduling purposes given 

that the previous requirement was 

weekly monitoring with a minimum of 

3 days between samples (note: the 

existing rule has a similar minimum 3 

day interval between weekly samples). 

Based on the weekly data provided by 

the landfill representatives, it appears 

that most landfills were able to collect 

weekly measurement data and most 

recovery systems operated 

continuously. The weekly data also 

suggest that there are very few instances 

(one landfill, for two month interval) 

where calendar month sampling could 

be accomplished only during the last 

week of one month and the first week 

of this month. Based on the weekly 

monitoring data, there does not appear 

to be any issue with collecting monthly 

samples at least 14 days apart. 

We note that, like the previous weekly 

monitoring requirement, there are 

missing data procedures for assessing 

the composition of the landfill gas if no 

sample could be collected during the 

calendar month. We do note that there 

were some landfills that did not operate 

their collection system for an entire 

month. In this case, the methane 

concentration is not a critical parameter 

since any concentration times zero flow 

equals zero methane recovery. 

Because the fourteen day period 

between monthly measurements limits 

the uncertainty of the methane recovery 

value and with no real increase in the 

cost of compliance, we are finalizing 

this requirement as proposed. 

Comment: Several commenters 

supported the proposed provisions to 

determine oxidation fractions on a sitespecific basis based on the methane flux 

rate. However, a few commenters 

indicated that the proposed higher 

oxidation fractions would result in 

erroneously low methane emissions. 

While many of the arguments regarding 

under-predicting methane emissions 

focused on factors other than the 

oxidation fraction (i.e., the methane 

recovery factors and the decay rate 

constants, which were not issues 

opened in the proposed amendments), 

two commenters noted that oxidation 

only occurs in landfill covers that are 

comprised of soil with the necessary 

depth, porosity, temperature and 

microbial population to effect oxidation. 

These commenters noted that landfills 

with composite or geomembrane covers 

that do not have a soil cover or a 

sufficient soil cover will not have any 

surface oxidation. One commenter 

indicated that the tests upon which the 

revised factors are based were 

conducted primarily on systems with 

landfill gas collection systems and wellengineered cover systems so the data 

were not representative of typical 

landfills. 

One commenter noted that, in order to 

streamline the calculations and to use a 

consistent basis from year to year, the 

EPA should allow the reporter an option 

to continue to use an oxidation factor of 

0.1. 

Response: We appreciate the support 

of commenters that agreed with the 

proposed provisions to determine 

oxidation fractions on a site-specific 

basis based on the methane flux rate. 

We agree that the site-specific oxidation 

fraction should improve the methane 

emission estimates for facilities with 

low methane flux rates and sufficient 

soil cover to effect oxidation. However, 

we also agree with the commenters who 

noted that oxidation must be predicated 

on the presence of sufficient soil cover. 

We reviewed the available data upon 

which the proposed oxidation fractions 

were based. Nearly all of the recent tests 

were conducted using distinct location 

measurement techniques (surface air, 

chamber or soil probe measurements) 

and all measurements were made in 

areas that had a soil cover system of 30 

inches or more. While we would have 

preferred to have more ‘‘full-plume’’ 

tests, which would better characterize 

the oxidation fraction over the entire 

landfill area, the surface and flux 

chamber measurements are not biased 

provided the surface locations are 

randomly selected and a sufficient 

number of measurements are made. We 

expect that most landfills will have 

intermediate or final soil covers over 

most of the areas of the landfill that 

contain waste, so these tests are 

generally applicable to most landfills. 

However, Table HH–4, as proposed, 

contained no restrictions on the use of 

the new methane flux-dependent 

oxidation fractions so it is conceivable 

that landfills that predominately have a 

daily soil cover could use these 

oxidation fractions that were developed 

for landfills with a much deeper cover 

soil layer. Therefore, we have revised 

Table HH–4 to limit the applicability of 

the new methane flux-dependent 

oxidation fractions to owners or 

operators of landfills that have a soil 

cover of at least 24 inches in depth for 

a majority of the landfill containing 

waste. We are also adding a new 

oxidation fraction for landfills that have 

a geomembrane cover and less than 12 

inches of cover soil. Starting with the 

2013 reporting year, these landfills must 

use an oxidation fraction of zero. 

We agree that the oxidation study data 

are heavily weighted to landfills with 

gas collection systems, which is why we 

do not support the average oxidation 

fractions by soil type presented in the 

summary table of the SWICS addendum. 

We note that all but one of the average 

oxidation fractions by soil type 

presented in the summary table of the 

SWICS addendum are greater than the 

0.35 oxidation fraction proposed for 

landfills with ‘‘low flux rates’’ and all of 

them are higher than the 0.25 oxidation 

fraction proposed for landfills with 

‘‘medium flux rates.’’ By grouping the 

oxidation data into bins based on the 

methane flux rate (prior to any 

oxidation), we avoid the obvious bias in 

the average oxidation fractions as 

recommended in the SWICS addendum 

caused by the preponderance of studies 

conducted at landfills with gas 

collection systems. Although there are 

fewer measurements in the high 

methane flux range (i.e., greater the 70 

grams methane per square meter per 

day) as compared to number of 

measurements in the other methane flux 

bins, there are a sufficient number of 

test runs in each bin to adequately 

characterize the average oxidation 

fraction for each bin. Therefore, we 

maintain that the oxidation fractions 

grouped into bins by methane flux rates 

provides the most accurate and 

unbiased means of estimating oxidation 

fractions for landfills based on the 

available data. 

Finally, we agree that for many 

landfills that do not have gas collection 

systems, the new oxidation fractions 

based on methane flux rates is not likely 

to significantly alter their predicted 

methane emissions compared to using 

the general oxidation fraction default of 

0.10. Therefore, we also include in 

Table HH–4 the option for any landfill 

owner of operator, except those of 

landfills with geomembrane covers with 

little cover soil, to simply use the 

default oxidation fraction of 0.10 

without the need to calculate methane 

flux rates. 

Comment: One commenter requested 

that the EPA clarify in the final rule that 

the proposed revised oxidation factor 


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approach for calculating CH4 emissions 

be used for reporting years 2013 and 

forward, and not require facilities to 

revise emissions data from reporting 

years 2010–2012. Such retroactive 

revisions would be time-consuming and 

expensive while resulting in minimal 

changes to reported emissions. 

Response: As indicated in our 

response to similar comments on the 

general reporting requirements in 

Section III.B of this preamble, these 

final amendments do not require facility 

owners or operators to resubmit 

previous annual reports. In the case of 

the oxidation factor, this value only 

impacts the emissions for the current 

reporting year and subsequent reporting 

years. Landfill owners or operators will 

not be required to determine methane 

fluxes for previous annual reports and 

revise those reports if a different 

oxidation factor applies. We have 

revised Table HH–4 to clarify that an 

oxidation factor of 0.1 must be used for 

reports prior to the 2013 reporting year 

and that the new oxidation factors can 

only be used starting with the 2013 and 

later reporting years. 

Comment: One commenter noted that 

an expansion of applicability that will 

occur in the MSW Landfill sector due to 

the revision of the GWP for methane 

that would not occur in certain other 

sectors (e.g., subpart FF: Underground 

Coal Mines, subpart NN: Natural Gas) 

because those sectors’ applicability 

threshold is not based on CO2e 

emissions. The commenter described 

requiring reporting from more very 

small landfills and requiring other very 

small closed landfills to continue 

reporting as costly and of limited policy 

relevance. The commenter further noted 

that the applicability determination for 

MSW Landfills is already based on the 

methane generation level, which was 

converted to tons CO2e so that 

emissions of CO2 from stationary 

combustion sources are not considered 

in determining applicability under the 

rule. 

Given the increased cost and limited 

utility of these ‘‘side effects’’ of revising 

the GWPs, the commenter 

recommended that the EPA establish 

both a methane-based reporting 

threshold for subpart HH to replace the 

CO2e based reporting threshold and a 

methane-based requirement for exiting 

the program. The commenter stated that 

changes are easily implemented by 

simply establishing a methane reporting 

threshold of 1190 metric tons/year or 

more and by adding new language to 

clarify off-ramp provisions for both the 

five-year exit threshold (1190 metric 

tons CH4) and the three-year exit 

threshold (714 tons metric tons CH4). 

The commenter noted that subpart 

HH facilities would still calculate and 

report methane as well as CO2e 

emissions for EPA inventory purposes 

but rule applicability and program exit 

provisions would be based upon 

methane emissions, not CO2e. 

According to the commenter, the 

proposed exit provisions do not 

consider ancillary subpart C 

anthropogenic emissions because MSW 

Landfills that meet the exit provisions 

are very small and primarily closed 

landfills, and they do not operate 

subpart C devices. The commenter 

described subpart C emissions as either 

non-existent or at such negligible 

amount that including these emissions 

would not prevent a subpart HH facility 

from exiting the program. Therefore, 

according to the commenter, subpart HH 

reporters would not exit the program 

prematurely due to exclusion of subpart 

C anthropogenic emissions. 

According to the commenter, a 

methane based reporting threshold 

would allow the Agency to avoid 

increasing the reporting program burden 

for the MSW landfill sector and the EPA 

staff. It would also prevent subjecting 

additional small and primarily closed 

landfills with negligible emissions to 

reporting requirements and new 

compliance costs. Existing reporters 

would not be delayed five additional 

years or more from exiting the reporting 

program. It also, according to the 

commenter, would allow the EPA to 

meet national and global inventory 

program commitments without 

needlessly affecting GHG MRR 

applicability. 

Response: As a programmatic issue, 

we have determined that the 25,000 tons 

CO2e reporting threshold is a reasonable 

reporting threshold. Because MSW 

landfills are primarily a methane 

emissions source and the size of the 

landfill is expected to be correlated with 

its methane generation, we did establish 

applicability based on methane 

generation as calculated using the 

methods specified in subpart HH. 

However, the threshold value for 

reporting has always been the CO2e of 

that methane generation at a value of 

25,000 metric tons CO2e, which is 

consistent with most other subparts in 

Part 98. 

As noted in the preamble to the 

proposed rule, the revised GWP for 

methane more accurately reflects the 

estimated radiative forcing effects of 

methane emissions. We also noted in 

the preamble to the proposed rule that 

revisions to the GWP values would 

cause a number of facilities to have to 

newly report under subpart W: 

Petroleum and Natural Gas Systems, 

subpart II: Industrial Wastewater 

Treatment, and subpart TT: Industrial 

Waste Landfills, in addition to subpart 

HH. We specifically estimated the 

number of new reporters by subpart, the 

additional costs incurred for all new 

reporters in each subpart, and the 

additional emissions reported under the 

GHGRP for each subpart. Based on the 

cost estimates provided in the preamble 

to the proposed rule, the costs per ton 

of newly reported CO2e for MSW 

landfills were among the lowest of any 

of the subparts projected to have an 

increase in the number of reporters due 

to the revisions to GWP values in Table 

A–1. Therefore, we do not agree that the 

revision to the GWP for methane unduly 

burdens owner or operators of MSW 

landfills in general. 

We project most of the new reporters 

to be open landfills that reach the 

reporting threshold a year or two earlier 

than they would otherwise (without the 

revision in GWP values). We see no 

need to alter the reporting threshold for 

these open landfills. Emissions from 

open landfills generally increase every 

year, so the change in the GWP of 

methane may cause them to report one 

year earlier, but that is a small 

incremental burden over the facility’s 

expected annual reports over the 

following years. We see advantages to 

open landfills reporting into the 

program earlier based on the revised 

GWP for both nationwide inventory 

purposes and policy matters. Therefore, 

we are not providing a blanket 

applicability change in terms of 

methane generation. 

We also do not find merit in the 

argument that the terms of the off-ramp 

provisions should be changed to 

methane emissions. Besides neglecting 

the stationary combustion source CO2

emissions, which may, as the 

commenter noted, be small, we find that 

the ‘‘additional years of reporting’’ do 

not constitute a significant increase in 

burden. Landfills on the off-ramp 

provisions are expected to have no real 

monitoring requirements under subpart 

HH since waste is no longer received at 

the landfill and the gas collection 

system (if once present) will generally 

not be operated given the declining 

methane generation. Consequently, all 

of the data they would need to 

determine their subpart HH emissions 

will already be in the e-GGRT system. 

The e-GGRT system will automatically 

carry forward the historical waste 

disposal records and perform the 

necessary calculations. The landfill 

owner or operator will only need to 

review, verify, and submit the report. 

While the landfill may have to submit 


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a few additional annual reports, the 

additional burden incurred is minimal. 

On the other hand, there may be a 

limited number of small, older, closed 

landfills that have not previously had to 

report under subpart HH that would be 

required to newly report in 2014 by 

exceeding the 25,000 metric tons CO2e 

emissions threshold for the first time 

solely due to the increase in the GWP 

of methane. We expect very few small, 

older, closed landfills would have the 

specific characteristics to have to newly 

report solely due to the increase in the 

GWP of methane; however, for these 

closed landfills, it would be a 

substantial additional burden to 

estimate historical waste quantities and 

develop their first annual report. As 

these landfills are closed, they no longer 

have a source of revenue from waste 

disposal fees, and the burden of 

reporting would be greater for them than 

for reporters with active revenue. 

Furthermore, these closed landfills will 

have declining emissions in all future 

years since they are no longer receiving 

waste and additional methane is not 

being produced. The first consequence 

of these declining emissions is that 

these reporters would provide data for 

only a few years until they can exit the 

program because their emissions are 

below threshold levels for the required 

period of time. The second consequence 

is that it is extremely unlikely that the 

information collected from these closed 

landfills would be useful when 

considering future policy options. The 

minor incremental improvement to 

overall emission totals for this sector 

does not warrant the disproportionate 

burden that would imposed on these 

older, small, closed facilities for 

information that is not useful for policy 

purposes. Consequently, we consider it 

reasonable to provide a very limited 

exclusion within subpart HH to reduce 

the burden for these specific older, 

small, closed landfills. Specifically, we 

are finalizing an amendment to 40 CFR 

98.340 to modify paragraph (a) to 

specify that the source category does not 

include MSW landfills that have not 

received waste on or after January 1, 

2013, and that had CH4 generation, as 

determined using both Equation HH–5 

and Equation HH–7 of this subpart, of 

less than 1,190 metric tons of CH4 in the 

2013 reporting year, and that were not 

required to submit an annual report 

under any requirement of Part 98 in the 

reporting years prior to 2013. 

In conclusion, we maintain that the 

revised GWP values in Table A–1 of 

Subpart A more accurately reflect the 

climate impacts of methane emissions 

and that the existing applicability 

threshold for MSW landfills in subpart 

A in terms of CO2e emissions is 

reasonable. We have adequately 

considered the impacts of the revisions 

of the GWP of methane on MSW 

landfills (as well as other subparts in 

Part 98) and have concluded that these 

impacts are reasonable. However, we are 

providing a specific exclusion for 

certain small, older, closed MSW 

landfills that did not previously have to 

report to eliminate the impacts of the 

revisions to the GWP of methane for 

these landfills. Finally, we are not 

making any revisions to off-ramp 

provisions for subpart HH as requested 

by the commenter. 

S. Subpart LL—Suppliers of Coal-based 

Liquid Fuels 

We are finalizing multiple revisions to 

40 CFR part 98, subpart LL (Suppliers 

of Coal-based Liquid Fuels). This 

section includes the more substantive 

corrections, clarifying, and other 

amendments to subpart LL. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

As proposed, we are removing the 

requirements at 40 CFR 98.386(a)(1), 

(a)(5), (a)(13), (b)(1), and (c)(1) for each 

facility, importer, and exporter to report 

the annual quantity of each product or 

natural gas liquid on the basis of the 

measurement method used. The EPA 

received no comments to the proposed 

changes. 

T. Subpart MM—Suppliers of Petroleum 

Products 

1. Summary of Final Amendments 

We are finalizing revisions to 40 CFR 

part 98, subpart MM (Suppliers of 

Petroleum Products) as proposed to 

clarify requirements and amend data 

reporting requirements to reduce burden 

for reporters. Based on a comment 

received, we are also removing the 

requirement to report a complete list of 

methods used to measure the annual 

quantities reported for each product or 

natural gas liquid. The more substantive 

corrections, clarifications, and other 

amendments to subpart MM are found 

here. Additional minor corrections, 

including changes to the final rule, are 

presented in the Table of 2013 Revisions 

(see Docket Id. No. EPA–HQ–OAR– 

2012–0934). 

We are finalizing the amendments to 

clarify the equation term for ‘‘Producti’’ 

at 40 CFR 98.393(a)(1) and (a)(2) to 

exclude those products that entered the 

refinery but are not reported under 40 

CFR 98.396(a)(2) as proposed. 

We are finalizing as proposed the 

harmonizing changes to 40 CFR 

98.394(b)(3) to make the equipment 

calibration requirements for petroleum 

products suppliers consistent with other 

Part 98 calibration requirements. 

We are removing as proposed the 

requirements of 40 CFR 98.396(a)(1), 

(a)(5), (a)(13), (b)(1), and (c)(1) for each 

facility, importer, and exporter to report 

the annual quantity of each petroleum 

product or natural gas liquid on the 

basis of the measurement method used. 

We are also removing the requirements 

of 40 CFR 98.396(a)(4), (a)(8), (a)(15), 

(b)(4), and (c)(4) for each facility, 

importer, and exporter to report a 

complete list of methods used to 

measure the annual quantities reported 

for each product or natural gas liquid. 

We are eliminating as proposed the 

reporting requirement for individual 

batches of crude oil feedstocks. The 

reporting requirements for crude oil at 

40 CFR 98.396(a)(20) are changed, as 

proposed, to require only the annual 

quantity of crude oil. 

We are eliminating the requirement to 

measure the API gravity and the sulfur 

content of each batch of crude oil at 40 

CFR 98.394(d) as proposed. We are also 

removing, as proposed, the requirement 

at 40 CFR 98.394(a)(1) that a standard 

method by a consensus-based standards 

organization be used to measure crude 

oil on site at a refinery, if such a method 

exists. Other associated changes to the 

rule to harmonize with this change 

include removing the definition of 

‘‘batch’’ from 40 CFR 98.398, removing 

the procedures for estimating missing 

data for determination of API gravity 

and sulfur content at 40 CFR 98.395(c), 

and the recordkeeping requirement for 

crude oil quantities at 40 CFR 98.397(b). 

We are including, as proposed, the 

definitions of natural gas liquids (NGL) 

and bulk NGLs in the subpart MM 

definitions at 40 CFR 98.398 to clarify 

the distinction between NGL and bulk 

NGL for reporting purposes under 

subpart MM. We are also clarifying, as 

proposed, the reporting requirements for 

bulk NGLs and NGLs. We are 

modifying, as proposed, the requirement 

at 40 CFR 98.396(a)(22) to specify that 

NGLs reported in 40 CFR 98.396(a)(2) 

should not be reported again in 40 CFR 

98.396(a)(22). 

We are revising, as proposed, the 

default density and emission factors in 

Table MM–1 for propane, propylene, 

ethane, ethylene, isobutane, 

isobutylene, butane, and butylene. 

Please refer to the preamble to the 

proposed rule (78 FR 19802, April 2, 

2013) for additional information 

regarding the amendments to subpart 

MM. 


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29We are finalizing confidentiality 

determinations for significantly revised data 

element in 40 CFR 98.406. See Section V of this 

preamble for additional information. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart MM. See the comment response 

document for subpart MM in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart MM. The 

majority of comments received on 

subpart MM supported the proposed 

revisions. A small number of comments 

were received requesting additional 

revisions to the reporting requirements 

that were not proposed. No comments 

were received opposing the proposed 

revisions. 

Comment: We received several 

comments supporting the EPA’s 

proposed revision to eliminate reporting 

of product volumes by measurement 

method, but one commenter suggested 

that the requirement to report a list of 

methods used to measure the annual 

product quantities reported should also 

be eliminated as it is tangential to the 

GHG emissions data. 

Response: While the list of 

measurement methods would help the 

EPA assess the appropriateness of the 

standard methods and industry 

practices that individual reporters 

select, to further reduce the burden on 

reporters, the EPA incorporated the 

commenter’s proposed changes because 

the EPA agrees that the list is tangential 

to the GHG emissions data when 

considered along with the other 

revisions to subpart MM that are being 

finalized. The EPA will not require that 

petroleum product suppliers report the 

standard method or industry standard 

practice used to measure product 

quantities that are reported to the EPA. 

U. Subpart NN—Suppliers of Natural 

Gas and Natural Gas Liquids 

1. Summary of Final Amendments 

We are finalizing several amendments 

to 40 CFR part 98, subpart NN 

(Suppliers of Natural Gas and Natural 

Gas Liquids) to clarify reporting 

requirements and improve data quality, 

where appropriate. Additional minor 

corrections, including changes to the 

final rule, are presented in the Table of 

2013 Revisions (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). We are 

finalizing, as proposed, the amendments 

to the definition of Local Distribution 

Companies (LDCs) in 40 CFR 98.400(b) 

to coincide with the definition of LDCs 

in 40 CFR 98.230(a)(8) (40 CFR part 98, 

subpart W) to clarify that for LDCs 

operating in multiple states, operations 

in each state are considered a separate 

LDC. We are also finalizing, as 

proposed, the revision to clarify that 

interstate and intrastate pipelines 

delivering natural gas directly to major 

industrial users or to farm taps upstream 

of the LDC inlet are not included in the 

definition of an LDC. 

We are finalizing, with revisions, the 

proposal to change the way LDCs report 

the annual volume of natural gas 

delivered to each large end-user 

registering supply equal to or greater 

than 460,000 thousand standard cubic 

feet (Mscf) during the calendar year. The 

EPA had previously proposed changing 

this requirement so that if an LDC 

knows that a group of meters serves one 

particular facility receiving a total of 

greater than 460,000 Mscf during the 

year, the LDC would be required to 

report those deliveries per facility rather 

than per meter. The EPA received two 

comments that the proposed 

amendments did not make it clear how 

LDCs could ensure compliance, 

specifically, commenters stated it was 

unclear how much research an LDC 

should do in order to back up an 

assertion that the LDC does not ‘‘know’’ 

whether a series of meters serves one 

large facility. The commenters suggested 

that the EPA modify the proposed text 

to state that the reporting be done at the 

facility level only if the LDC ‘‘knows 

based on readily available information 

that multiple meters serve one end user 

facility.’’ As a result of this comment, 

the EPA has finalized language to state 

that an LDC must report the large enduser in this manner if the LDC ‘‘knows 

based on readily available information 

in the LDCs possession’’ that multiple 

meters serve an individual end-user 

facility to clarify our intention that new 

research is not required on the behalf of 

the LDC to determine which meters 

serve which facilities. Further, the 

commenters expressed concern that the 

terms ‘‘customer’’ and ‘‘end user 

facility’’ were used inconsistently in the 

rule and preamble and suggested the 

term ‘‘end user facility’’ be used 

throughout to improve clarity. As a 

result of this comment, the EPA has 

modified the final rule to consistently 

refer to such end-users as ‘‘large endusers.’’ In 98.404(b)(2)(i), the EPA has 

defined a large end-user as any facility 

receiving greater than or equal to 

460,000 Mscf of natural gas per year, or, 

if the LDC does not know the total 

quantity of gas delivered to the end-user 

facility based on readily available 

information in the LDC’s possession, 

any single meter at an end-user facility 

to which the LDC delivers equal to or 

greater than 460,000 Mscf per year. The 

term ‘‘large end-user’’ was added 

throughout the regulatory text to replace 

‘‘end-user’’, as appropriate, and 

references to this definition were 

inserted as appropriate to reduce 

confusion and increase consistency and 

clarity. 

We are finalizing, as proposed, the 

revision to replace Equation NN–5 with 

two Equations, NN–5a and NN–5b, to 

allow LDCs to more accurately calculate 

the amount of carbon dioxide associated 

with the net change in natural gas stored 

on system and natural gas received by 

the LDC that bypassed the city gate. The 

EPA is also finalizing the harmonizing 

revisions to Equation NN–6 that 

incorporates the two proposed NN–5 

equations. 

Additionally, we are finalizing, as 

proposed, the revision to require natural 

gas liquids fractionators to report the 

quantity of o-grade, y-grade, and other 

types of bulk NGLs received and the 

quantity of these NGLs not fractionated, 

but supplied downstream.29

Finally, we are finalizing, as 

proposed, the changes to the default 

HHV and emission factors in Table NN– 

1 and NN–2 for LPGs including 

propane, ethane, isobutane and butane, 

as well as the factors for natural gas. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to the proposed amendments to 

subpart NN. See the comment response 

document for subpart NN in Docket Id. 

No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to subpart NN. 

Comment: The EPA received four 

comment letters regarding the proposed 

amendments to subpart NN. While most 

of the comments supported the EPA’s 

amendments, we received two comment 

letters expressing concern that the 

proposed amendments to the LDC 

reporting requirements for natural gas 

supplied to large end-users (i.e., those 

meters or facilities receiving more than 

460,000 Mscf per year) are confusing 

and lacked clarity. The commenters 

noted the phrases ‘‘customer meter’’ and 

‘‘end-user facility’’ were used 

inconsistently throughout the rule. They 

believe this inconsistency could be 

confusing to reporters. To improve 

clarity, the commenters recommended 

the term ‘‘end-user facility’’ be used 

throughout the rule. The commenters 

are also concerned the proposed phrase 

‘‘if known’’ in 40 CFR 98.406(b)(7) does 

not provide sufficient clarity regarding 


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the level of research required by LDCs 

to determine which meters supply 

natural gas to each large end-user 

facility. They noted that LDCs often 

send one bill to a company’s main office 

reflecting gas usage for all facilities 

across a state and in such cases gas 

usage from one individual facility may 

not be readily known. The commenter 

suggested the phrase ‘‘if known’’ be 

replaced with ‘‘if known based on 

readily available information.’’ One 

commenter suggested the ‘‘end-user’’ be 

defined as ‘‘a single service address’’ to 

avoid confusion with the EIA Form 176 

reporting of natural gas supply by enduser categories. Finally, one commenter 

was concerned about the reporting 

burden associated with determining 

total fuel deliveries to facilities with 

many meters, especially those facilities 

with many meters that receive only a 

small quantity of gas (less than 50,000 

Mscf). The commenter suggested that 

only meters which record an annual 

total of 50,000 Mscf or greater per year 

be included in the total reported 

deliveries to a large end-user facility. 

Response: In the existing rule, LDCs 

are required to report natural gas 

delivered to individual meters that 

received equal to or more than 460,000 

Mscf per calendar year. Under Part 98, 

the CO2 quantity reported by LDCs 

associated with deliveries to large enduse meters (i.e., the value calculated 

using Equation NN–4) has been 

collected because the large end-user 

facilities that receive gas through these 

meters report GHG emissions from 

natural gas combustion to the EPA in 

other subparts of Part 98. With the 

information collected in Equation NN– 

4, the EPA has been able to quantify a 

significant portion of the total CO2 that 

is double reported by LDCs and large 

end-user facilities. This has helped the 

EPA to estimate the total national CO2

emissions from natural gas combustion 

reported under the GHGRP. 

As we noted in the preamble to the 

proposed amendments, this approach 

did not always address the overlap in 

CO2 reported by LDCs in subpart NN 

and large end-user facilities subject to 

other subparts of Part 98 (for example 

subpart C or D). For example, in 

situations where 460,000 Mscf or more 

of natural gas is supplied to a single 

large end-user facility in a calendar year 

by a series or group of meters, where 

each individual meter receives less than 

460,000 Mscf, the CO2 associated with 

this gas was not reported under subpart 

NN, and the quantity of overlap could 

not be determined. To improve the 

quality of the national CO2 emissions 

estimate for natural gas combustion, we 

are finalizing the proposed amendments 

requiring LDCs to report the quantity of 

natural gas delivered to each facility 

known by the LDC to receive equal to 

or greater than the 460,000 Mscf per 

year, with some clarifications. The EPA 

is not requiring LDCs undertake any 

new research to determine which meters 

supply gas to each large end-user 

facility. Rather LDCs should use the 

information already available to them in 

their existing records (e.g., meter 

addresses or billing records). If an LDC 

has insufficient information to make the 

determination, they may continue to 

report data for each gas meter that 

receives equal to or greater than 460,000 

Mscf per year. To clarify our intention, 

we agreed with the commenter and have 

amended 40 CFR 98.403(b)(2)(i) to 

define the term ‘‘large end-user’’ as 

either any large end-user facility 

receiving greater than or equal to 

460,000 Mscf of natural gas per year or 

a single meter receiving equal to or 

greater than 460,000 Mscf per year when 

the LDC does not know the total 

quantity of gas delivered to the facility, 

based on readily available information 

in the LDC’s possession. We revised 40 

CFR 98.404 and 40 CFR 98.406 to make 

those sections consistent with the 

changes made in 40 CFR 98.403(b)(2). 

The EPA considered using the term 

‘‘single service address’’ to refer to 

facilities that receive equal to or greater 

than 460,000 Mscf per year as suggested 

by one commenter as a means of 

reducing potential confusion between 

natural gas supply data reported under 

40 CFR 98.406(b)(7) for individual large 

end-users (either a facility or meter) and 

natural gas reported under 40 CFR 

98.403(b)(13) for the EIA end-use 

categories. However, we decided not to 

make this change since the new 

definition added to 40 CFR 

98.403(b)(2)(i) should reduce the 

likelihood that reporters will confuse 

the two reporting requirements. Also, 

the term ‘‘facility’’ is already defined in 

Part 98 and used consistently 

throughout the rule. We were concerned 

that introducing a new term to refer to 

a facility could result in greater 

confusion as the suggested change 

would make subpart NN inconsistent 

with other subparts of the rule. 

The EPA disagrees with the 

commenter’s recommendation that 

LDCs be required to report only meters 

with fuel usage of 50,000 Mscf or greater 

for large end-user facilities that exceed 

the reporting threshold in aggregate and 

have multiple meters. We disagree with 

this recommendation for several 

reasons. First, the approach suggested 

by the commenter would compromise 

the quality and usefulness of the data 

collected. The EPA’s intention in 

collecting these data is to quantify the 

overlap in reported CO2 between 

subpart NN and other subparts in 

estimating total U.S. CO2 emissions 

from natural gas combustion. Under the 

subparts applicable to large end-user 

facilities, direct emitters report 

emissions for all combustion units and 

processes located at their facility, 

regardless of the quantity of emissions 

from the unit or process. Therefore, if 

LDCs did not report the CO2 quantity 

associated with gas delivered through 

small meters, the overlap could not be 

properly determined. While the impact 

on the CO2 quantity for an individual 

facility would be small, the impact on 

the quality of national CO2 estimates 

would be more significant and would be 

difficult to quantify. Since Part 98 

requires direct emitters to report all 

emissions from combustion sources, 

allowing LDCs to report natural gas 

supplied to some but not all meters 

located at large end-user facilities would 

result in an overestimate of national CO2

emissions from natural gas combustion. 

It is EPA’s intention to quantify national 

CO2 emissions from natural gas 

combustion as accurately as possible. 

Second, under the suggested 

approach, the reporter would be 

required to determine the quantity of 

natural gas flowing through each of 

these meters to assess whether it 

exceeds the 50,000 Mscf threshold, 

which means the quantity of gas flowing 

through each meter would still need to 

be determined under the commenter’s 

proposed approach as it is under the 

final rule. The methodology used to 

calculate the CO2 quantity associated 

with this gas is simple, once the 

quantity of fuel has been determined 

(fuel quantity times an emission factor 

and heating rate, which may be default 

factors). Therefore, the EPA has 

determined that there is not a significant 

burden associated with calculating and 

reporting this CO2 quantity. 

Finally, the suggested approach to 

require that only gas delivered through 

a meter with a fuel usage of 50,000 Mscf 

per year or greater be reported would 

result in additional reporting burden for 

many LDCs. This is the case, for 

example, when the total quantity of gas 

delivered to a customer is known based 

on billing records or other information. 

Requiring LDCs to evaluate, and 

subtract out, the usage for each 

individual meter that supplies a single 

large end-user facility with less than 

50,000 Mscf per year could be time 

consuming. This evaluation would need 

to be completed for each reporting year, 

since the gas delivered through a 

particular meter may be above the 

threshold one year and below the 


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30The EPA is also finalizing a data category and 

confidentiality determination for this data element. 

See the Confidentiality Determinations 

Memorandum, ‘‘Final data category assignments 

and confidentiality determinations for (Docket Id. 

No. EPA–HQ–OAR–2012–0934). 

threshold the next year. We anticipate 

that the process of evaluating and 

subtracting out the gas supplied to 

smaller meters, as recommended by the 

commenter, would require considerable 

additional work for LDCs. 

V. Subpart PP—Suppliers of Carbon 

Dioxide 

We are finalizing three substantive 

amendments to subpart PP of Part 98 

(Suppliers of Carbon Dioxide) as 

proposed. One additional minor 

correction, discussed in the Table of 

Revisions (see Docket Id. No. EPA–HQ– 

OAR–2012–0934), is finalized as 

proposed. 

We are amending 40 CFR 

98.423(a)(3)(i) as proposed to clarify that 

facilities with CO2 production wells that 

extract or produce a CO2 stream may use 

Equation PP–3a to aggregate the total 

annual mass of CO2 from multiple 

extracted streams. This clarifying 

change increases the reporting 

flexibility for facilities with CO2

production wells by allowing them to 

aggregate CO2 emissions from multiple 

CO2 streams. 

We are also amending the reporting 

requirements of 40 CFR 98.426(f)(10) 

and (f)(11) as proposed, which require 

reporting the aggregated annual CO2

quantities transferred to enhanced oil 

and natural gas recovery or geologic 

sequestration. The final rule 

amendments clarify that these end use 

application options reflect injection of 

CO2 to geologic sequestration or 

enhanced oil recovery as covered by 40 

CFR part 98, subparts RR and UU, 

respectively. The EPA received no 

comments on the proposed changes. 

W. Subpart QQ—Importers and 

Exporters of Fluorinated Greenhouse 

Gases Contained in Pre-Charged 

Equipment or Closed-Cell Foams 

1. Summary of Final Amendments 

The EPA is finalizing multiple 

revisions to subpart QQ (Importers and 

Exporters of Fluorinated Greenhouse 

Gases Contained in Pre-Charged 

Equipment or Closed-Cell Foams) as 

proposed. The more substantive 

corrections, clarifying, and other 

amendments to subpart QQ are 

discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

We are correcting the equation term 

‘‘St’’ in Equations QQ–1 and QQ–2 as 

proposed to clarify that the input may 

be mass (charge per piece of equipment) 

or density (charge per cubic foot of 

foam, kg per cubic foot). We are 

amending an example within the 

definition of ‘‘closed-cell foam’’ at 40 

CFR 98.438 as proposed. We are 

replacing the term ‘‘appliance’’ with the 

term ‘‘equipment’’ at 40 CFR 

98.436(a)(3), (a)(4), (a)(6)(ii), (a)(6)(iii), 

(b)(3), (b)(4), (b)(6)(ii), and (b)(6)(iii). We 

are revising the reporting requirements 

for 40 CFR 98.436(a)(6)(iii) and (b)(6)(iii) 

as proposed to match the reported data 

element to the units required to be 

reported. The revision is a change from 

‘‘mass in CO2e’’ to ‘‘density in CO2e.’’ 

We are amending the definition of ‘‘precharged electrical equipment 

component’’ at 40 CFR 98.438 as 

proposed. 

Finally, we are removing the 

following reporting requirements to 

alleviate burden on reporters as 

proposed: 40 CFR 98.436(a)(5), (a)(6)(iv), 

(b)(5), and (b)(6)(iv). Please refer to the 

preamble to the proposed rule (78 FR 

19802, April 2, 2013) for additional 

information regarding the amendments. 

The EPA received no comments 

opposing the proposed changes to 

subpart QQ. 

2. Summary of Comments and 

Responses 

See the comment response document 

in Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a complete listing of all 

comments and responses related to 

subpart QQ. The EPA did not receive 

any significant comments on the 

proposed changes and there are no 

changes to the rule based on these 

comments. 

X. Subpart RR—Geologic Sequestration 

of Carbon Dioxide 

We are finalizing corrections to 

subpart RR of Part 98 (Geologic 

Sequestration of Carbon dioxide). The 

more substantive corrections, clarifying, 

and other amendments to subpart RR 

are discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

As proposed, we are adding a 

requirement for facilities to report the 

standard or method used to calculate 

the mass or volume of contents in 

containers that is redelivered to another 

facility without being injected into the 

well.30 The EPA received no comments 

on the proposed changes. 

Y. Subpart SS—Electrical Equipment 

Manufacture or Refurbishment 

We are finalizing clarifying 

amendments and other corrections to 

subpart SS of Part 98 (Electrical 

Equipment Manufacture or 

Refurbishment). The more substantive 

corrections, clarifying, and other 

amendments to subpart SS are 

discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

We are harmonizing 40 CFR 98.453(d) 

and 40 CFR 98.453(h) as proposed to 

clarify the options available to estimate 

the mass of SF6 and PFCs disbursed to 

customers in new equipment. The final 

rule corrects inconsistencies between 

paragraphs so that all options are clearly 

identified as available. 

We are adding text to 40 CFR 

98.453(d) to include the options to use 

the nameplate capacity of the 

equipment by itself and to use the 

nameplate capacity along with a 

calculation of the partial shipping 

charge. We are also revising 40 CFR 

98.453(h) to clarify that these 

calculation requirements only apply 

where reporters choose to estimate the 

mass of SF6 or PFCs disbursed to 

customers in new equipment using the 

nameplate capacity of the equipment, 

either by itself or together with a 

calculation of the partial shipping 

charge. These amendments are finalized 

as proposed. The EPA received no 

comments on the proposed changes. 

Z. Subpart TT—Industrial Waste 

Landfills 

1. Summary of Final Amendments 

We are finalizing several amendments 

to 40 CFR part 98, subpart TT to clarify 

and correct calculation methods, 

provide additional flexibility for certain 

monitoring requirements, and clarify 

reporting requirements. We are 

finalizing, as proposed, the minor 

corrections discussed in the Table of 

2013 Revisions (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). We are finalizing 

amendments, as proposed, to revise the 

definition of the term ‘‘DOCF’’ in 

Equation TT–1 when a 60-day anaerobic 

biodegradation test is used as well as 

revisions to Equation TT–7, which is 

used to determine a waste streamspecific DOC value when a facility 

performs a 60-day anaerobic 

biodegradation test. 

We are finalizing revisions to 40 CFR 

98.464(b) and (c) to broaden the 

provisions to determine volatile solids 

concentration for historically managed 

waste streams. The revisions to 40 CFR 


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31We are finalizing confidentiality 

determinations for the significantly revised data 

elements in 40 CFR 98.466. See Section V of this 

preamble for additional information. 

98.464(b) are being finalized as 

proposed. The revisions to 40 CFR 

98.464(c) are being finalized as 

proposed except that we are deleting the 

proposed phrase ‘‘but was not received 

during the first reporting year’’ to 

broaden the applicability of these 

provisions in consideration of the 

public comments received. 

We are finalizing amendments to 40 

CFR 98.466(b)(1), as proposed, to clarify 

that waste quantities for inert waste 

steams must be reported. We are also 

finalizing amendments to the reporting 

requirements specific to Equations TT– 

4a and TT–4b in 40 CFR 98.466(c)(4), as 

proposed.31

We are finalizing amendments, as 

proposed, to revise the oxidation 

fraction default value (‘‘OX’’) in 

Equation TT–6 to reference the default 

values in Table HH–4; however, there 

are a number of revisions to Table HH– 

4 from the proposed table upon 

consideration of the public comments 

received. These revisions include 

limiting the new oxidation factors to 

landfills with soil covers of at least 24 

inches for a majority of the landfill area 

containing waste, allowing the 

continued use of the 0.10 default 

oxidation factor, and clarifying that the 

modeled methane generation term for 

facilities subject to subpart TT is the 

result from Equation TT–1, not Equation 

HH–1. Please see Section II.R of this 

preamble for more details regarding 

these revisions. 

We are finalizing amendments, as 

proposed to Table TT–1 of subpart TT 

of Part 98 to include an ‘‘industrial 

sludge category’’ and to clarify certain 

industry default DOC values were 

applicable to wastes ‘‘other than 

industrial sludge.’’ Based on public 

comments received, we are adding a 

definition of ‘‘industrial sludge’’ to 40 

CFR 98.468 to clarify what waste 

streams are included in this waste 

category. 

2. Summary of Comments and 

Responses 

Several comments were received from 

industrial waste landfill owners or 

operators regarding the proposed 

oxidation fractions assigned by methane 

flux rates in Table HH–3. These 

comments and responses are included 

in Section II.R. of this preamble. The 

significant comments and responses 

related to other proposed amendments 

to subpart TT are summarized in this 

section. See the comment response 

document in Docket Id. No. EPA–HQ– 

OAR–2012–0934 for a complete listing 

of all comments and responses related 

to subpart TT. 

Comment: A commenter noted that 

the original subpart TT regulations 

allowed facilities to develop a DOC for 

use when estimating emissions from 

historic waste deposits. According to 

the commenter, it appeared that once 

such a DOC was developed, the same 

DOC was required to be used for these 

historic deposits in all future reports 

under the Greenhouse Gas Reporting 

Rule, even if better information became 

available. The commenter pointed to 40 

CFR 98.463(a)(3), particularly the 

passage: ‘‘The historical values for DOC 

or DOCx must be developed only for the 

first annual report required for the 

industrial waste landfill; and used for 

all subsequent annual reports (e.g., if 

DOC for year x = 1990 was determined 

to be 0.15 in the first reporting year, you 

must use 0.15 for the 1990 DOC value 

for all subsequent annual reports).’’ The 

commenter stated that this was not 

reasonable since facilities had relatively 

little time to develop such historical 

DOCs, following the EPA’s protocol, for 

the first required reporting of landfill 

methane emissions under a new 

reporting scheme and procedures. 

Making those initial determinations 

unchangeable, the commenter noted, 

would not make sense when the EPA is 

revising DOCs applicable to various 

wastes landfilled in the forest products 

industry. 

The commenter further asserted that 

this interpretation that the historical 

DOC that the facility first chose is fixed 

for all time appears to be at odds with 

40 CFR98.3(h), which requires a facility 

to submit a revised report if the facility 

becomes aware of a substantive error in 

the prior report—which presumably 

could include an error in the DOC 

applied to historical deposits in the 

landfill. The commenter pointed to a 

response to a question from the EPA eGGRT Help Desk, which indicated that 

a facility could recalculate and resubmit 

an annual GHG report if it determined 

that there is a more accurate method for 

estimating emissions, which could 

include a more accurate DOC than what 

was used in the past. 

Response: The requirements in 40 

CFR 98.463(a) to determine the 

historical waste quantities and DOC 

values for the first annual report and to 

use those values for all subsequent 

annual reports is based on the need to 

have a single, consistent waste disposal 

timeline across annual reports. The 

requirement was also intended to make 

it clear that owners or operators of 

landfills did not have to recalculate an 

average DOC value determined 

according to the provisions in 40 CFR 

98.463(a)(3)(iv) if additional 

measurements are made for subsequent 

reporting years. The EPA did not intend, 

however, to prevent landfill owners and 

operators from correcting known errors 

or inaccuracies in the historical waste 

disposal quantities or DOC values. For 

example, if DOC values are determined 

using the anaerobic degradation method 

for the first time in the 2013 reporting 

year and that determination indicates 

that the historical DOC values used are 

in error, we do not interpret the 

language in 40 CFR 98.463(a)(3) to 

prevent correction of these historical 

DOC values. We note that the language 

in 40 CFR 98.463(a)(2) and (3) 

specifically uses the phrase ‘‘for the first 

annual report’’ and does not require that 

the measurements be made in the ‘‘first 

reporting year.’’ That is, we interpret the 

language used in 40 CFR 98.463(a)(2) 

and (3) to require a consistent historical 

time series for waste quantities and DOC 

values be used in all annual reports. 

Revisions to the historical waste 

quantities and DOC values are 

permissible, but the entire time series of 

annual reports must be revised and 

resubmitted so that they are consistent 

with the revised ‘‘first annual report.’’ 

However, we do not agree that the 

proposed language in 40 CFR 98.464(c) 

effectively limits the applicability of the 

methods to determine historical DOC 

values to waste streams that were not 

received ‘‘during the first reporting 

year.’’ Although this provision was 

specifically added to address comments 

that some waste streams that were 

historically managed in the landfill 

were not generated during the first 

reporting year, it is unnecessary to limit 

the use of these methods to only waste 

streams that were not received in the 

first reporting year. Specifically, we 

acknowledge that the anaerobic test 

method was not included in subpart TT 

until late 2011, so that this method 

could not be used to establish waste 

stream-specific DOC values for the first 

annual report. We did not intend to 

limit the use of the anaerobic test 

method to only those streams that were 

not received during the first reporting 

year. Therefore, we are revising the 

proposed language at 40 CFR 98.464(c) 

to delete the phrase ‘‘but was not 

received during the first reporting year’’ 

to remove this restriction. Therefore, 

facilities can use test data from more 

recent years to revise the historical 

waste records provided that all annual 

reports are revised to use the same 

historical waste records. However, we 

also clarify, per our original intent, that 


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32The EPA is also finalizing category assignments 

and confidentiality determinations for new and 

revised data elements in the Confidentiality 

Determinations Memorandum(Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

33 Id. 

it is not necessary to revise these 

historical DOC values (and all historical 

annual reports) each year new DOC 

measurements are made. Thus, the 

owner or operator can choose to use 

‘‘current reporting year’’ DOC 

measurement values only for the current 

reporting year. Alternatively, the owner 

or operator can use the new information 

to revise the historical waste values, but 

then they must revise and resubmit all 

previous annual reports so that the 

historical waste records for all annual 

reports are consistent with the records 

used in the ‘‘first annual report.’’ 

Comment: A commenter noted that 

they have several waste streams that 

have DOC values more similar to the 

new default for industrial sludge than 

the defaults for waste streams ‘‘(other 

than sludge).’’ The commenter stated 

that the approach to DOCs that EPA has 

proposed would therefore continue to 

overstate substantially the GHG 

emissions from industrial waste 

landfills. The commenter suggested that 

the EPA either add more detailed DOC 

waste stream defaults to Table TT–1 or 

clarify that the term ‘‘industrial sludge’’ 

(which is undefined in the proposed 

rule) is intended to encompass materials 

that meet the common, dictionary 

meaning of ‘‘sludge’’ (e.g., ‘‘thick, soft, 

wet mud or a similar viscous mixture of 

liquid and solid components, especially 

the product of an industrial or refining 

process’’), as well as the meaning the 

EPA often gives to ‘‘sludge,’’ i.e. residue 

removed from wastewater treatment or 

air pollution control equipment. This 

would then allow industrial waste 

landfill owners or operators to apply the 

‘‘industrial sludge’’ DOC to a wider 

array of waste streams. 

Response: With respect to adding 

more detailed waste stream-specific 

DOC defaults to Table TT–1, we note 

that industrial waste landfill owners 

and operators may elect to determine a 

waste stream specific DOC value 

specific for their operations. We 

included in subpart TT a series of 

simple and inexpensive tests by which 

landfill owners and operators may elect 

to develop more accurate DOC values, 

as well as a more detailed anaerobic 

degradation tests if even more accurate 

values are desired. Landfill owners or 

operators that have a significant 

quantity of waste that is not wellcharacterized by the Table TT–1 

defaults may elect to determine their 

own waste stream-specific DOC value to 

use in their emission calculations. As 

noted in our previous response, if these 

site-specific values are determined for 

the first time in the 2013 reporting year, 

the landfill owner or operator can elect 

to (but is not required to) revise their 

historical DOC values and resubmit all 

previous annual reports based on the 

revised historical DOC values. 

The EPA is willing to consider 

expanding the list of default DOC values 

in Table TT–1 to include additional 

waste streams that are commonly found 

at industrial landfills. We are willing to 

work with the commenter and other 

stakeholders to gather further 

information to support the change 

requested and examine whether it 

should be included in a future 

rulemaking. However, the information 

provided by the commenter is new, 

contains only limited data, and was not 

part of the original proposal. Additional 

DOC test data for these waste streams 

from a larger and more representative 

sample of facilities would greatly inform 

such a decision. 

With respect to the lack of a definition 

of ‘‘industrial sludge,’’ we agree that 

clarity is needed. This category was 

specifically added to address concerns 

regarding inconsistencies with the DOC 

values for industrial waste in the 2006 

IPCC Guidelines. The 2006 IPCC 

Guidelines appears to refer to ‘‘sludge’’ 

in reference to wastewater treatment 

sludges. As the ‘‘industrial sludge’’ 

waste category was specifically added to 

provide consistency with the 2006 IPCC 

Guidelines, we are adding a definition 

of ‘‘industrial sludge’’ to clarify that this 

term specifically refers to sludges 

collected in wastewater treatment 

systems or sludges from ‘‘wet’’ air 

control systems (e.g., wet scrubbers). 

Specifically, ‘‘Industrial sludge means 

the residual, semi-solid material left 

from industrial wastewater treatment 

processes or wet air pollution control 

devices (e.g., wet scrubbers). Industrial 

sludge includes underflow material 

collected in primary or secondary 

clarifiers, settling basins, or 

precipitation tanks as well as dredged 

materials from wastewater tanks or 

impoundments. Industrial sludge also 

includes the semi-solid material 

remaining after these materials are 

dewatered via a belt press, centrifuge, or 

similar dewatering process.’’ The EPA 

believes that the definition suggested by 

the commenter is overly broad and 

could encompass materials not intended 

to be covered. As stated above, the EPA 

is willing to work with stakeholders to 

gather and analyze information needed 

to further refine the list of default DOC 

values in Table TT–1. 

AA. Subpart UU—Injection of Carbon 

Dioxide 

We are finalizing amendments to 40 

CFR part 98, subpart UU (Injection of 

Carbon Dioxide). The more substantive 

corrections, clarifying, and other 

amendments to subpart UU are 

discussed in this section. We are 

finalizing all of the minor corrections 

presented in the Table of 2013 Revisions 

as proposed (see Docket Id. No. EPA– 

HQ–OAR–2012–0934). 

The EPA is adding a requirement to 

subpart UU for a facility to report the 

purpose of CO2 injection (i.e., Research 

and Development (R&D) project 

exemption from subpart RR, enhanced 

oil or gas recovery, acid gas disposal, or 

some other reason).32 We are adding a 

requirement for facilities to report the 

standard or method used to calculate 

the parameters for CO2 received in 

containers.33 These amendments are 

finalized as proposed. The EPA received 

no comments on the proposed changes. 

BB. Other Technical Corrections 

1. Summary of Final Amendments 

The EPA is finalizing minor 

corrections to subparts E, G, S, V, and 

II of Part 98 as proposed. The changes 

to these subparts are provided in the 

Table of Revisions for this rulemaking, 

available in Docket Id. No. EPA–HQ– 

OAR–2012–0934, and include clarifying 

requirements to better reflect the EPA’s 

intent, corrections to calculation terms 

or cross-references that do not revise the 

output of calculations, harmonizing 

changes within a subpart (such as 

changes to terminology), simple typo or 

error corrections, and removal of 

redundant text. 

2. Summary of Comments and 

Responses 

This section summarizes the 

significant comments and responses 

related to minor corrections to subparts 

E, G, S, V, and II. The EPA received one 

comment related to subpart G. See the 

comment response document in Docket 

Id. No. EPA–HQ–OAR–2012–0934. 

Comment: One commenter asked that 

the EPA revise subpart G to require the 

reporting of CO2 emitted directly to the 

atmosphere from the synthetic ammonia 

production process. 

The commenter noted that the CO2

captured during ammonia production 

and used to produce urea ‘‘does not 

contribute to the CO2 emission estimates 

for ammonia production.’’ The 

commenter reasoned that reporting the 

CO2 which is bound in urea, as required 

under subpart G, is inconsistent with 

other source categories covered by the 

rule, and is contrary to EPA’s 


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methodology used in the Inventory. The 

commenter also noted that the structure 

of subpart G is similar to the structure 

of subpart P, but should be revised to be 

similar to the structure of subpart X. 

The commenter argued that sources in 

subpart G should be allowed to ‘‘reduce 

their CO2 reporting for CO2 in urea’’ in 

the same way that sources in subpart X 

are allowed to ‘‘reduce their carbon 

reporting for carbon in products.’’ 

Response: The EPA acknowledges the 

commenter’s suggested revisions to the 

language in subpart G to require 

reporting only CO2 that is emitted 

directly to the atmosphere from 

ammonia manufacturing rather than 

reporting CO2 that is bound in the urea 

that is produced from ammonia at some 

facilities. However, the comment falls 

outside of the scope of this rulemaking. 

The EPA had proposed clarifications to 

40 CFR 98.76(b)(13) of subpart G but 

had not proposed any revisions to the 

calculation and monitoring methods 

described in the rule. Therefore, the 

EPA is not proposing any revisions in 

response to this comment at this time. 

However, the commenter has raised a 

consistency issue within Part 98, that 

subpart G facilities currently are 

required to report CO2 that is bound in 

urea rather than emitted directly to the 

atmosphere, that merits evaluation and 

requires further analysis by the EPA. 

Prior to any modification of the rule 

language, the EPA will comprehensively 

assess the implications of such a change 

to the rule and propose any such 

revisions for public comment. This will 

ensure that the EPA is not introducing 

new or additional issues for facilities 

reporting under subpart G and other 

similar subparts, especially in the 

treatment of emissions that are collected 

onsite for other uses. 

CC. Subpart I Correction 

Following signature of the final rule 

titled, ‘‘Greenhouse Gas Reporting 

Program: Final Amendments and 

Confidentiality Determinations for 

Electronics Manufacturing’’ [78 FR 

68162] (‘‘final subpart I rule’’), the EPA 

identified an inconsistency between the 

preamble and final rule text. In the 

preamble, we stated that we were 

finalizing the requirements for the 

triennial technology report in section 

98.96(y) as proposed, which was our 

intention. However, a sentence was 

inadvertently added to 98.96(y)(3)(i) in 

the final subpart I rule. In today’s final 

rule, we are correcting this error to 

finalize 98.96(y)(3)(i) as proposed in 

‘‘Greenhouse Gas Reporting Program: 

Proposed Amendments and 

Confidentiality Determinations for 

Subpart I’’ [77 FR 63538]. 

III. Schedule for the Final Amendments 

and Republication of Emission 

Estimates for Prior Year Reports 

A. Schedule for Final Amendments and 

Significant Comments 

1. Summary of Final Amendments 

This section describes when the final 

amendments become effective for 

existing reporters and new facilities that 

are required to report as a result of the 

amendments to Table A–1. This section 

also discusses final amendments to 

subpart A for the use of best available 

monitoring methods (BAMM) by new 

reporters and the EPA’s intentions for 

republishing emissions estimates for the 

2010, 2011, and 2012 reporting years 

that reflect the changes in GWPs, based 

on the annual reports previously 

submitted by existing reporters. 

Existing Reporters. The final rule 

requires that existing GHGRP reporters 

begin using the updated GWPs in Table 

A–1 for their reporting year 2013 annual 

reports, which must be submitted by 

March 31, 2014, as proposed. We have 

determined that it is feasible for existing 

reporters to implement the final rule 

changes for the 2013 reporting year 

because these revisions do not require 

changes to the data collection and 

calculation methodologies in the 

existing rule. The EPA does not 

anticipate that the revised GWPs in 

Table A–1 will require any existing 

reporters to report under new subparts. 

The EPA received no comments 

identifying such a reporter. Such a 

reporter, if one exists, is not required to 

report for any past years under any 

subparts for which the reporter’s 

emissions newly exceed a reporting 

threshold, and may use the BAMM 

provisions described below. 

Reporters subject to any subpart of 

Part 98 for the first time. We are 

finalizing the schedule for reporters that 

become newly subject to any subpart as 

proposed. The final rule requires 

reporters who are newly required to 

report under any subpart of Part 98 as 

a result of the changes to Table A–1 to 

begin collecting data on January 1, 2014 

for the 2014 reporting year. These 

reporters are required to submit their 

first reports, covering the 2014 reporting 

year, by March 31, 2015. This schedule 

allows time for reporters to acquire, 

install, and calibrate any necessary 

monitoring equipment for the subparts 

to which they are subject in the 2014 

reporting year. 

As proposed, we are adding provision 

40 CFR 98.3(l) to subpart A to allow 

reporters who are required to newly 

report under any subpart solely as a 

result of the revised GWPs in Table A– 

1 to have the option of using BAMM 

from January 1, 2014 to March 31, 2014 

for any parameter that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

a relevant subpart. We are allowing 

reporters to use BAMM during the 

January 1, 2014 to March 31, 2014 time 

period without submitting a formal 

request to the EPA. Reporters will also 

have the opportunity to request an 

extension for the use of BAMM beyond 

March 31, 2014; those owners or 

operators must submit a request to the 

Administrator by January 31, 2014. The 

EPA does not anticipate allowing the 

use of BAMM for reporters subject to 

any subpart of Part 98 for the first time 

as a result of Table A–1 changes beyond 

December 31, 2014. The final schedule 

will allow five to six months after 

publication of this final rule to prepare 

for data collection while automatically 

being able to use BAMM, which is 

consistent with prior BAMM schedules. 

These provisions provide additional 

flexibility for new reporters and do not 

supersede existing subpart-specific 

BAMM requirements (e.g., the ability to 

request BAMM beyond 2011 for subpart 

W reporters (see 40 CFR 98.1(b)). This 

additional time for new reporters to 

comply with the monitoring methods in 

Part 98 will allow many facilities to 

install the necessary monitoring 

equipment during other planned (or 

unplanned) process unit downtime, 

thus avoiding process interruptions. 

2. Summary of Comments and 

Responses—Schedule 

Comment: One commenter 

recommended that the effective date for 

the revised and new GWPs be 12 

months after the new values are 

finalized. The commenter stated that a 

one-year transition would allow 

reporters to address compliance issues 

related to GHG reporting, GHG 

permitting, and related projects that 

may arise due to the revised GWPs. The 

commenter stated that delaying 

implementation of GWPs for one year is 

reasonable because the changes will 

create compliance problems. The 

commenter asserted that it is not 

appropriate to apply the revised GWPs 

to 2013 emissions, given that the 

rulemaking affects who must report and 

the gases that must be reported. The 

commenter suggested that the new 

GWPs be used starting in reporting year 

2014. 

Some commenters stated that 

companies and facilities will have to 

reprogram their data acquisition, 

analysis, and reporting systems to 

incorporate revised emission factors, 

revised emission estimation methods, 


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and revised reporting requirements. 

Commenters suggested that the final 

rule should defer the reporting deadline 

for 2013 emissions, suggesting 

increments of at least three or six 

months after the final revisions are 

published in the Federal Register. 

Commenters expressed concern about 

the time required to implement the final 

rule changes into existing reporting 

systems, particularly with respect to 

making changes to internal reporting 

systems to align with EPA’s final 

extensible markup language (XML) 

schema or reporting forms. 

Response: Because the revised GWPs 

finalized in this rule are only for 

compounds that are already listed in 

Table A–1, reporters do not have to 

provide additional information for their 

reporting year 2013 reports and there is 

no additional burden associated with 

calculating CO2e using the revised 

GWPs. In this final rule, we are not 

incorporating GWPs from the additional 

26 compounds that we proposed to add 

to Table A–1 in the proposed 2013 

Revisions Rule (see Section I.D. of this 

preamble). As discussed in the preamble 

to the 2013 Revisions proposal, the EPA 

intends to use data from the reporting 

year 2013 GHGRP reports to supplement 

the top-down national estimate and 

develop the 2015 Inventory. Therefore, 

and because the final GWP changes add 

no burden to existing reporters, we are 

requiring existing GHGRP reporters to 

calculate GHG emissions and supply 

using the revised GWPs from AR4 

beginning with RY 2013 reports, which 

must be submitted by March 31, 2014. 

New reporters who are required to 

report under Part 98 as a result of the 

changes to Table A–1 are required to 

begin collecting data on January 1, 2014 

and must submit their first annual 

reports by March 31, 2015. We have 

included provisions in 40 CFR 98.3(l) to 

allow new reporters to have the option 

of using BAMM from January 1, 2014 to 

March 31, 2014, and to request extended 

BAMM beyond March 31, 2014, which 

will allow additional time for facilities 

to prepare for data collection. For 

concerns regarding the schedule and 

how this final rule impacts the Tailoring 

Rule and permitting programs, see 

Section II.A.2.b of this preamble. 

The EPA disagrees with the 

commenters’ recommendations to 

extend the reporting deadline to 

accommodate changes to revised 

emission factors, revised emission 

estimation methods, and revised 

reporting requirements. We expect that 

the final rule changes for the 2013 

reporting year are feasible to implement 

prior to the March 31, 2014 reporting 

deadline. These changes are consistent 

with the data collection and calculation 

methodologies in the existing rule, and 

primarily provide additional 

clarifications or flexibility regarding 

existing regulatory requirements and do 

not add new monitoring requirements. 

Therefore, they do not substantially 

affect the information that must be 

collected. Where calculation equations 

are modified, the changes clarify 

equation terms or simplify the 

calculations and do not require any 

additional data monitoring. Because 

reporters are not required to actually 

submit reporting year 2013 reports until 

March 31, 2014, reporters will have 

adequate time to adjust their internal 

reporting programs to the finalized 

amendments before the reporting 

deadline. 

We note that many reporters use the 

e-GGRT Web-forms or spreadsheets 

developed by the EPA for preparing 

submitting their annual reports. The 

changes to the GWP values finalized in 

this rule will have minimal impact on 

these reporters since the CO2e values are 

automatically calculated for reporters 

using these reporting forms. While we 

agree that reporters using the XML 

format to report emissions will need to 

make revisions, we anticipate that there 

is sufficient time to make these changes 

and submit annual reports by the March 

31, 2014 deadline for reporting year 

2013 data. The EPA will ensure that the 

e-GGRT reporting system is modified in 

a timely manner so as to not shorten the 

window for data reporting. The EPA 

acknowledges commenters’ concerns 

regarding the XML reporting schema. 

The EPA will work to finalize the XML 

schema as early as possible to allow 

reporters adequate time to complete and 

upload their XML reports. 

Comment: One commenter 

recommends that the criteria in 

proposed 40 CFR 93.3(l)(2)(ii) associated 

with BAMM requests be revised to take 

into consideration other considerations, 

such as safety, that may warrant the use 

of BAMM. The commenter requests that 

the EPA provide additional flexibility 

for use of BAMM under 40 CFR 98.3(l); 

ensure that BAMM is accessible beyond 

2014; ensure that 40 CFR 93.3(l) criteria 

do not conflict with or supersede other 

subpart-specific BAMM provisions; and, 

if BAMM provisions in both subpart A 

and subpart W apply, clarify and 

harmonize requirements and schedules 

under the two subparts, especially for 

the first and second reporting years for 

new reporters. The commenter further 

requested that reporters who must 

comply with subpart W should have the 

option to use BAMM from January 1, 

2014 to June 30, 2014 without having to 

request EPA approval. 

Response: The BAMM provisions in 

40 CFR 98.3(l) of subpart A allow new 

reporters subject to any subpart under 

Part 98 who would be required to report 

as a result of the proposed new or 

revised GWPs to have the option to use 

BAMM from January 1, 2014 to March 

31, 2014 for any parameter that cannot 

reasonably be measured according to the 

monitoring and QA/QC requirements of 

the relevant subpart. These new 

reporters are allowed to use BAMM 

during the January 1, 2014 to March 31, 

2014 time period without making a 

formal request to the EPA. Reporters 

may also request an extension for the 

use of BAMM beyond March 31, 2014 

by submitting a request to and receiving 

approval from the Administrator in 

accordance with the provisions in 40 

CFR 98.3(l)(2). We do not anticipate 

permitting the use of BAMM under the 

provisions of 40 CFR 98.3(l)(2) beyond 

December 31, 2014. Under the 

provisions of 40 CFR 98.3(l)(2), new 

reporters have more than a year to 

comply with the monitoring and QA/QC 

requirements of the applicable subparts. 

We consider this time period sufficient 

for facilities subject to the rule for the 

first time in 2014 to acquire, install, and 

calibrate monitoring equipment to meet 

the monitoring and QA/QC 

requirements of the rule. This time 

period is the same as was allowed for 

the initial reporting years. 

As noted by the commenter, the EPA 

promulgated additional subpart-specific 

BAMM provisions for those subparts 

with unique or unusual situations that 

would make compliance with the 

monitoring and QA/QC procedures in 

those subparts challenging (e.g., 

subparts I, L, and W). These subpartspecific provisions allow for additional 

use of BAMM that is not provided under 

the General Provisions. Under these 

existing subpart-specific BAMM 

provisions, a reporter subject to the 

subpart may request approval to use 

BAMM for unique and extreme 

circumstances, such as safety concerns, 

technical infeasibility, or inconsistency 

with other local, State or Federal 

regulations. For example, pursuant to 40 

CFR 98.234(f)(8), a reporter subject to 

subpart W may use BAMM beyond 2011 

if it receives approval from the EPA. 

The new BAMM provisions in the 

General Provisions, 40 CFR 98.3(l) do 

not supersede any of these previously 

promulgated subpart-specific BAMM 

requirements (see 40 CFR 98.1(b)). Since 

the deadline to submit subpart W 

BAMM requests covered in 40 CFR 

98.234(f)(8) for the 2014 reporting year 

has passed, a facility that becomes 

newly subject to subpart W of Part 98 


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will be able to use BAMM without 

making a formal request between 

January 1, 2014 and March 31, 2014 

under the provisions for new reporters 

in 40 CFR 98.3(l). This reporter may 

seek approval to use BAMM after this 

period (between April 1, 2014 and 

December 31, 2014) under 40 CFR 

98.3(l) by submitting an extension 

request no later than 60 days after the 

effective date of the final rule. However, 

for the 2015 reporting year and forward, 

the new reporter should request 

approval to further continue using 

BAMM under subpart W by following 

the provisions covered in subpart W, 40 

CFR 98.234(f)(8). 

We decided not to extend the time 

period during which BAMM may be 

used without seeking EPA approval 

despite the commenter’s 

recommendation. Extending the 

deadline to June 30, 2014 as suggested 

by the commenter would likely result in 

some facilities taking longer to comply 

with the rule than is actually necessary. 

When facilities use BAMM, the quality 

of the reported emissions is impacted. 

Our aim in setting a March 31, 2014 

deadline for using BAMM without prior 

EPA approval is to balance the EPA’s 

need for high-quality data of known 

accuracy against the reporter’s need for 

sufficient time to install, test, and 

calibrate new monitoring equipment. 

For most Part 98 subparts, reporters 

should have little problem complying 

with the monitoring provisions by the 

March 31, 2014 deadline. By requiring 

reporters to apply for approval to use 

BAMM beyond March 31, 2014, the EPA 

will be able to ensure that BAMM is 

used only in those situations and times 

periods where its use is necessary. 

B. Republication of Emissions Estimates 

for Prior Year Reports and Significant 

Comments 

1. Summary of Republication of 

Emission Estimates for 2010, 2011, and 

2012 

In the proposed rule, we presented 

two options for the revision and 

republication of the CO2e estimates from 

annual reports for reporting years 2010, 

2011, and 2012 using the proposed GWP 

values in Table A–1. Under Option 1, 

reporters who submitted annual reports 

for the reporting years 2010, 2011, and 

2012 would be required to resubmit 

their prior year reports using the builtin calculation methods in the EPA’s 

Electronic Greenhouse Gas Reporting 

Tool (e-GGRT) to convert reported 

quantities of GHGs to CO2e. Under 

Option 2, the EPA would independently 

recalculate revised CO2e emissions from 

the prior year reports for each facility 

using the revised GWPs in Table A–1. 

Under this scenario, each reporter 

would be able to view the EPA’s 

revision of its emission or supply totals 

in previously submitted 2010, 2011, and 

2012 reports through e-GGRT. The 

reporter would not be able to comment 

on or change the revised estimate. 

The EPA received several comments 

on these proposed options. In general, 

commenters were concerned about the 

impact of revising totals from prior year 

reports that had previously been 

published. Commenters also expressed 

concern that facilities would be liable 

for changes to applicability under Part 

98 or other EPA programs if the CO2e 

totals in their annual reports for 2010 

through 2012 were recalculated. Of 

those commenters that supported 

Option 2, several recommended that the 

EPA allow reporters to comment on the 

revised CO2e estimates prior to 

publication. These comments and the 

EPA’s response to these comments are 

described in detail in Section III.B.2 of 

this preamble. 

After reviewing the comments 

submitted by stakeholders, the EPA is 

finalizing Option 2. Due to concerns 

raised by commenters, we are clarifying 

in this final rule that we do not intend 

to revise the annual reports submitted 

and certified by reporters for reporting 

years 2010, 2011, and 2012 to reflect the 

revised GWPs finalized in this 

rulemaking. Prior year reports, using 

original GWPs, will remain publicly 

available. The EPA will also publish a 

version of the CO2e emissions and 

supply estimates for the reporting years 

2010, 2011, and 2012 using the revised 

GWPs in Table A–1. The EPA will 

clearly label the information as a 

product of EPA analysis, conducted to 

reflect a consistent time-series of carbon 

dioxide equivalent (i.e., emissions from 

the start of the program using the 

amended GWPs). Under this approach, 

the EPA’s analysis will supplement, not 

revise or supersede, the previously 

published data. This will allow the 

Agency and public to view and compare 

trends in GHG data, beginning with the 

first year of GHGRP reporting, using 

consistent GWPs and without placing 

any additional burden on reporters. See 

Section III.B.2 for additional 

information on the EPA’s revised 

approach. 

2. Summary of Comments and 

Responses—Republication of Emission 

Estimates for Prior Year Reports 

This section summarizes the 

significant comments and responses 

related to EPA’s proposal to publish 

recalculated emissions from 2010, 2011, 

and 2012 reporting years. See the 

comment response document in Docket 

Id. No. EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to emissions 

recalculations for prior reporting years. 

Comment: Several commenters 

requested that, if the EPA chooses to 

proceed with revising the CO2e 

emission estimates in annual reports for 

prior reporting years using the proposed 

revised GWP values, the EPA should 

pursue this through Option 2 as 

described in the proposal preamble 

(where the EPA would itself calculate 

the revised CO2e emissions), rather than 

mandating that reporters revise their 

prior reports. Many commenters 

preferred Option 2 because it would not 

place added burden on reporters to 

recalculate previously reported data. 

One commenter stated that Option 2 

would enable the EPA to automatically 

revise CO2e emissions without the need 

for company review, pointing out that a 

programming modification would easily 

update emissions data universally 

without the need for responses from 

each individual facility and eliminate 

the time consuming reentry of data at 

the plant level. Another commenter 

insisted that the EPA must publish the 

revised estimates with a caveat 

explaining how the estimates were 

obtained and explaining that the 

emission values are not those submitted 

and certified by reporters. 

One commenter suggested the EPA 

revise the emissions data (as described 

in Option 2) and then present it in the 

published database as a parallel metric, 

leaving the certified facility-reported 

data unchanged. The commenter 

explained that this approach would 

ensure that a facility’s reported emission 

data appropriately remains the official 

emission report for that facility while 

creating a ‘‘continuous’’ emission series 

dating to reporting year 2010. Another 

commenter suggested including the 

revised estimates on FLIGHT and listing 

both the previous and new GWPs. The 

commenter noted that addressing the 

emissions in this way would eliminate 

the need to revise even more reports if 

the EPA decides to update the GWPs 

again in the future. 

Many commenters opposed both 

options, asserting that retroactively 

revising data submitted in prior reports 

would undermine regulatory and 

business certainty. Commenters stated 

that it is inappropriate to require that 

emission estimates previously 

calculated in good faith be reassessed 

based on a revised rule. The 

commenters maintained that either 

option would create a substantial 

reporting burden without any real 

benefit. One commenter argued that 


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either option could have the unintended 

consequence of altering GHG mitigation 

strategies currently being deployed by 

facilities. Several commenters opposed 

recalculating prior reporting year 

emissions because these emissions are 

in the public domain, and the GWP 

values used to derive them were also 

used by sources for purposes of 

evaluating applicability of PSD and title 

V under the Tailoring Rule. Commenters 

argued that changing the emission totals 

that have already been published would 

also undermine transparency in the 

regulatory process and the public’s 

confidence in the overall database. 

Commenters also disagreed that these 

revisions would allow for the 

comparison of emission data submitted 

for those reporting years with data 

submitted for reporting year 2013 and 

future reporting years. Some 

commenters indicated that the EPA has 

neglected to consider other proposed 

significant changes that can affect the 

overall emission estimates, citing, for 

example, the proposal to increase the 

cover methane oxidation rates at 

landfills from 10 percent to up to 35 

percent. The commenters contended 

that revised GHG emissions data will 

have little value if revisions address one 

change (e.g., GWP values) but not others 

(e.g., revised emission factors or 

oxidation rates). Another commenter 

emphasized the impacts of the 

retroactive application of changes on 

other EPA regulations as well as state 

programs such as California’s AB 32 

GHG reduction program. Commenters 

recommended that new GWPs, and in 

fact all revisions within the GHG 

Reporting Rule, be applied 

prospectively to future emission reports, 

contending that this is more logical from 

a legal, scientific, and workload 

perspective. Finally, no commenter 

supported Option 1. 

Response: After reviewing the 

comments submitted by stakeholders, 

we have selected Option 2 as the best 

means of meeting the need for GHG 

emissions data that accurately reflect 

the relative effect of each GHG. Option 

2 will allow the EPA to provide a 

complete, consistent data set for prior 

years with the amended GWPs, 

including reports submitted for facilities 

and suppliers that have ceased 

operations, for comparison to data 

reported for 2013 and future years 

without increasing the burden on 

reporters or revising previously 

submitted reports. 

In response to the concerns raised by 

commenters, we emphasize that 

although we will recalculate the 2010 

through 2012 CO2e values using the 

revised GHGs, we will not be making 

revisions to the annual reports 

submitted and certified by reporters to 

reflect the revised GWPs finalized in 

this rulemaking. We intend to publish 

the submitted and certified annual 

reports in FLIGHT and publish a version 

of the CO2e emissions and supply 

estimates for the reporting years 2010, 

2011, and 2012 using the revised GWPs 

in Table A–1 separately. The EPA will 

clearly delineate data submitted to the 

EPA by reporters and data recalculated 

by EPA. The revised emission and 

supply estimates will be used to create 

a consistent time series of CO2e 

estimates using the amended GWPs. We 

may present the annual report totals and 

the revised CO2e estimates in parallel 

thru FLIGHT; however, any revised 

CO2e values published will be clearly 

identified with a caveat explaining how 

the revised CO2e values were calculated 

and the reason why the values were 

recalculated. As such, the dataset 

provided will be an analysis of the data 

submitted by reporters, and will not 

constitute changes to the annual reports. 

The certified 2010 through 2012 reports 

(excluding confidential business 

information) will continue to be made 

available to the public through our Web 

site and will reflect the data as reported 

and certified by the reporter. 

This approach allows the EPA to 

publish revised emission and supply 

totals without increasing burden on 

reporters for the submittal of revised 

reports and allows for comparison of 

emissions on an individual facility basis 

from reporting years 2010 through 2012 

with those published in 2013 and 

beyond. This revised CO2e data will 

provide a more accurate picture of 

facility-level emissions for each 

industry over time. 

This approach also clarifies that the 

GWPs finalized in this rulemaking are 

only applied prospectively, and do not 

affect the applicability for reporters that 

was determined for prior years. The 

revised emission and supply totals for 

years 2010 through 2012 will be wholly 

separate from the published values 

supplied by reporters for annual reports 

that may be used by sources for 

purposes of evaluating applicability of 

under other GHG programs, such as the 

EPA’s Tailoring Rule. As discussed in 

Section II.A.2.c of this preamble, 

applicability determinations and 

permits issued prior to the effective date 

of the revised Table A–1 will not be 

affected by the new GWPs. Therefore, 

the revised totals will not retroactively 

affect determinations of permitting 

applicability. 

We disagree with the commenters’ 

statement that the decision to 

recalculate CO2e values for 2010 

through 2012 creates confusion, 

undermines regulatory or business 

certainty, or will alter GHG mitigation 

methods. No additional burden is 

placed on reporters since reporters are 

not required to resubmit reports for 

2010 through 2012 reporting years. In 

the 2013 reporting year and subsequent 

years, reporters will use the revised 

GWP values in Table A–1 of subpart A 

to calculate emissions in CO2e. In most 

cases, however, reporters use the eGGRT webforms or spreadsheets that 

automatically calculate CO2e values 

based on the GHG emissions and supply 

data entered by the facility. Only 

facilities that use the XML schema for 

reporting will need to make revisions 

for the 2013 reporting year. 

We note that the reported emissions 

of each individual GHG emitted by the 

facility or supplied by a supplier for 

reporting years 2010, 2011, and 2012 

remain unchanged. Only the relative 

weighting of the impacts of each GHG 

are changed by revisions to the GWPs. 

Using consistent and up-to-date GWP 

values, reviewed and approved by the 

scientific community, enables us to 

better evaluate the relative impact of 

GHG emissions on global warming, 

make better informed decisions on 

future mitigation methods, and track 

emission trends. 

Although the EPA is revising the 

GWPs and making other minor rule 

revisions in this final rule, none of these 

changes apply retroactively to reporters. 

The EPA is not requiring new reporters 

who became subject to reporting only as 

the result of changes in the GWP values 

to submit reports for previous reporting 

years. Nor are we requiring existing 

reporters to submit and certify revised 

annual reports for previous reporting 

years or review and certify revised CO2e 

values calculated by the EPA. 

Comment: Although most 

commenters supported Option 2 (either 

outright or as compared to Option 1), 

many suggested that EPA provide an 

opportunity for reporting entities to 

review and provide comment on CO2e 

values recalculated by the EPA before 

those values are published. These 

commenters stated that review is 

important to avoid errors being made in 

the published data. Some commenters 

also stated that reporters should be 

given the option to voluntarily revise 

their previous annual reports 

themselves. 

Response: The EPA intends to provide 

an opportunity for facilities to view 

their recalculated facility-level CO2e 

totals before publication. The Agency 

does not believe it will be useful to 

formally solicit comments on the 

recalculated GWPs. Because application 


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of the new GWPs will be a very simple 

recalculation that has no bearing on a 

facility’s annual report, the EPA does 

not want to place any additional burden 

on reporters. However, if a reporter were 

to find an error, we would as always 

welcome feedback through our Help 

Desk. We do not plan to make a formal 

solicitation for comment from reporters 

prior to publication of the recalculated 

CO2e emissions and supply because 

these republished values will be clearly 

labeled as the results of EPA analysis to 

avoid their confusion with the certified 

emissions reports submitted by 

facilities. The EPA will review the 

recalculated CO2e values to ensure they 

are accurate before making them 

available to the public. We have decided 

not to allow reporters to submit revised 

certified reports for reporting years 

2010, 2011, and 2012 with CO2e values 

calculated using the revised GWPs. 

Based on the comments we received on 

Option 1, we consider it unlikely that 

many reporters would voluntarily revise 

their 2010 through 2012 reports, and to 

allow a few reporters to do so would be 

confusing to the public when reviewing 

non-CBI versions of the annual reports 

published on our Web site. 

IV. Confidentiality Determinations 

A. Final Confidentiality Determinations 

for New and Revised Data Elements 

The EPA received only supportive 

comments on the proposed 

confidentiality determinations, and is 

finalizing the confidentiality 

determinations as proposed for all but 2 

of the new and substantially revised 

data elements that were proposed. The 

EPA is not finalizing two proposed data 

elements: one in subpart AA, annual 

production of paper products exiting the 

paper machine(s) prior to application of 

any off-machine coatings (40 CFR 

98.276(k)(2) proposed) as discussed in 

Section II.N of this preamble; and one 

in subpart FF, amount of CH4 routed to 

each destruction device (40 CFR 

98.326(t) proposed) as discussed in 

Section II.Q of this preamble. As a 

result, the EPA is not finalizing category 

assignments or confidentiality 

determinations for these two data 

elements. 

In addition, there are some data 

elements in subparts A, C, X, FF, HH, 

NN, and TT that have been clarified 

since proposal, although the same 

information will be collected. These 

data elements and how they have been 

clarified in the final rule are listed in 

the following table. Because the 

information to be collected has not 

changed since proposal, we are 

finalizing the proposed confidentiality 

determinations for these data elements 

as proposed (see Table 3 of this 

preamble). 

TABLE 3—REVISED DATA ELEMENTS WITH FINAL CATEGORY ASSIGNMENT AND CONFIDENTIALITY DETERMINATION

Citation 

Data category assigned to during 

proposal 

Data element description, as proposed Data element description, as finalized 

40 CFR 98.3(c)(1) (proposed); 40 CFR 

98.3(c)(1) (finalized).

Facility and Unit 

Identifier Information.

If a facility does not have a physical 

street address, then the facility must 

provide the latitude and longitude 

representing the location of facility 

operations in decimal degree format.

If the facility does not have a physical 

street address, then the facility must 

provide the latitude and longitude 

representing the geographic centroid 

or center point of facility operations 

in decimal degree format. 

40 CFR 98.3(c)(13) (proposed); 40 CFR 

98.3(c)(13) and (e.g., annual operation hours of the gas collection system (98.346(i)(7)), 40 CFR 

98.36(b)(11), 40 CFR 98.36 (c) (1)(xi), 

40 CFR 98.36 (c)(2)(x), 40 CFR 98.36 

(c)(3)(x), 40 CFR 98.36 (d)(1)(x), 40 

CFR 98.36 (d)(2)(ii)(J), and 40 CFR 

98.36 (d)(2)(iii)(J) (finalized).

Facility and Unit 

Identifier Information.

For combustion units used to generate 

electricity for delivery to the grid, 

ORIS code for each combustion unit 

serving an electric generator.

An indication of whether the facility includes one or more plant sites that 

have been assigned a ‘‘plant code’’ 

(as defined under 40 CFR 98.6) by 

either the Department of Energy’s 

(DOE) Energy Information Administration (EIA) or by the EPA’s Clean 

Air Markets Division (CAMD). 40 

CFR 98.36(b)(11): Plant code (as 

defined in 98.6), 40 CFR 

98.36(c)(1)(xi): Plant code (as defined in 98.6), 40 CFR 

98.36(c)(2)(x): Plant code (as defined in 98.6), 40 CFR 

98.36(c)(3)(x): Plant code (as defined in 98.6), 40 CFR 

98.36(d)(1)(x): Plant code (as defined in 98.6), 40 CFR 

98.36(d)(2)(ii)(J): Plant code (as defined in 98.6), 40 CFR 98.36(d) 

(2)(iii)(J): Plant code (as defined in 

98.6). 

40 CFR 98.246(b)(4) (proposed); 40 

CFR 98.246(b)(4) finalized.

Emissions .............. For each CEMS monitoring location 

that meets the conditions in paragraph (b)(2) or (3) of this section, 

provide an estimate based on engineering judgment of the fraction of 

the total CO2 emissions that is attributable to the petrochemical process 

unit.

For each CEMS monitoring location 

that meets the conditions in paragraph (b)(2) or (3) of this section, 

provide an estimate based on engineering judgment of the fraction of 

the total CO2 emissions that results 

from CO2 directly emitted by the petrochemical process unit plus CO2

generated by the combustion of offgas from the petrochemical process 

unit. 


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TABLE 3—REVISED DATA ELEMENTS WITH FINAL CATEGORY ASSIGNMENT AND CONFIDENTIALITY DETERMINATION— 

Continued 

Citation 

Data category assigned to during 

proposal 

Data element description, as proposed Data element description, as finalized 

40 CFR 98.326(r)(2)(proposed); 40 CFR 

98.326(r)(2) (finalized).

Unit/process Operating Characteristics That are 

Not Inputs to 

Emission Equations; Not Emissions Data and 

Not CBI.

Start date of each well and shaft ......... Start date of each well, shaft, and vent 

hole. 

40 CFR 98.326(r)(2) (proposed); 40 

CFR 98.326(r)(2) (finalized). 

Close date of each well and shaft ....... Close date of each well, shaft, and 

vent hole. 

40 CFR 98.326(r)(3) (proposed); 40 

CFR 98.326(r)(3) (finalized). 

Number of days each or shaft was in 

operation during the reporting year.

Number of days each well, shaft, or 

vent hole was in operation during 

the reporting year. 

40 CFR 98.466(h) (proposed); 40 CFR 

98.466(h)(1) (finalized).

Emissions .............. For landfills with gas collection systems, methane generation, using 

equation TT–6.

For landfills with gas collection systems, methane generation, adjusted 

for oxidation, calculated using equation TT–6. 

40 CFR 98.466(h) (proposed); 40 CFR 

98.466(h)(2) (finalized).

Inputs to Emission 

Equations.

For landfills with gas collection systems, oxidation factor.For landfills with gas collection systems, oxidation factor used in Equation TT–6. 

40 CFR 98.406(b)(7) .............................. Customer and Vendor Information.LCDs: Annual volume in Mscf of natural gas delivered by the LDC to 

each sales or transportation customer’s facility that received from the 

LDC deliveries equal to or greater 

than 460,000 Mscf during the calendar year, if known; otherwise, the 

annual volume in Mscf of natural 

gas delivered by the LDC to each 

meter registering supply equal to or 

greater than 460,000 Mscf during 

the calendar year.

LCDs: Annual volume in Mscf of natural gas delivered by the LDC to 

each large end-user as defined in 40 

CFR 98.403(b)(2)(i). 

40 CFR 98.406(b)(12) ............................ Customer and Vendor Information.LCDs: Meter number for each enduser reported in paragraph (b)(7).LCDs: Meter number for each large 

end-user reported in paragraph 

(b)(7). 

40 CFR 98.406(b)(12) ............................ Customer and Vendor Information.LCDs: Whether the quantity of natural 

gas reported in paragraph (b)(7) is 

the total quantity delivered or the 

quantity delivered to a specific meter.

LCDs: Whether the quantity of natural 

gas reported in paragraph (b)(7) is 

the total quantity delivered or the 

quantity delivered to a large enduser’s facility, or the quantity delivered to a specific meter located at 

the facility. 

In the proposed rule, the EPA 

assigned thirteen proposed new data 

elements to the inputs to emission 

equations data category and received no 

comment on the proposed category 

assignments. As discussed above, one 

proposed new data element, from 

subpart FF, which was proposed to be 

assigned to the inputs to emission 

equations category is no longer included 

in this action. Additionally, as 

discussed in Section II.R of this 

preamble, the final revision to 40 CFR 

98.346(i) includes three more new data 

elements than were proposed in subpart 

HH. The current rule had assumed only 

one measurement location and two 

possible destruction devices and 

therefore required reporting of only the 

operating hours for the ‘‘primary’’ and 

‘‘back-up’’ destruction devices and a 

single value for destruction efficiency 

and methane recovery using Equation 

HH–4, all of which were categorized as 

inputs to emission equations. With 

these final revisions, the EPA is now 

requiring facilities to report the number 

of destruction devices and the operating 

hours and destruction efficiency for 

each device associated with a given 

measurement location (40 CFR 

98.346(i)(5) and (7)). The EPA is also 

finalizing an amendment that methane 

recovery calculated using Equation HH– 

4 be reported separately for each 

measurement location (40 CFR 

98.346(i)(6)). Because the three 

additional data elements are the same 

type of information as had been 

collected previously, the only difference 

being that they are now collected by 

measurement location, the EPA 

similarly assigns them to the inputs to 

emission equations data category in the 

final rule. As a result, there are now a 

total of 15 new data elements assigned 

to the inputs to emission equations 

category. 

The EPA had previously expressed an 

intent to conduct an ‘‘in-depth 

evaluation of the potential impact from 

the release of inputs to equations’’ 

(76FR 53057 and 53060, August 25, 

2011); (77 FR 48072, August 13, 2012). 

We conducted an evaluation of these 

fifteen new inputs following the process 

outline in the memorandum ‘‘Process 

for Evaluating and Potentially 

Amending Part 98 Inputs to Emission 

Equations’’ (Docket Id. No. EPA–HQ– 

OAR–2010–0929). This evaluation is 

summarized in the memorandum 

‘‘Summary of Evaluation of ‘Inputs to 


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Emission Equations’ Data Elements 

Added with the 2013 Revisions to the 

Greenhouse Gas Reporting Rule.’’ (See 

Docket Id. No. EPA–HQ–OAR–2012– 

0934.) 

Please see the memorandum titled 

‘‘Final data category assignments and 

confidentiality determinations for new 

and substantially revised data elements 

in the ‘2013 Revisions to the 

Greenhouse Gas Reporting Rule and 

Confidentiality Determinations for New 

or Substantially Revised Data 

Elements’ ’’ (‘‘Confidentiality 

Determinations Memorandum’’) in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934 for a list of the new or 

substantially revised data elements, 

their final category assignments, and 

their confidentiality determinations 

(whether categorical or individual) 

except for those assigned to the inputs 

to equations category. 

B. Public Comments on the Proposed 

Confidentiality Determinations and 

Responses to Public Comment 

The EPA is finalizing all 

confidentiality determinations as they 

were proposed. Please refer to the 

preamble to the proposed rule (77 FR 

63570) for additional information 

regarding the proposed confidentiality 

determinations. For comments and 

responses regarding confidentiality 

determinations for new and revised data 

elements, please refer to the comment 

response document in Docket Id. No. 

EPA–HQ–OAR–2012–0934. 

V. Impacts of the Final Rule 

A. Impacts of the Final Amendments 

Due to Revised Global Warming 

Potentials 

This section of the preamble examines 

the costs and economic impacts of the 

final rulemaking and the estimated 

economic impacts of the rule on affected 

entities, including estimated impacts on 

small entities. 

As discussed in the proposed rule, the 

amendments to Table A–1 of Part 98 

may affect both the number of facilities 

required to report under Part 98 and the 

quantities of GHGs reported. This is 

because the GWPs in Table A–1 are 

used to calculate emissions (or supply) 

of GHGs in CO2e for determination of 

whether a facility meets a CO2e-based 

threshold and is required to report and 

to calculate total facility emissions for 

submittal in the annual report. The 

amendments to Table A–1 include 

adopting GWPs that generally are higher 

than the values currently in the table 

and will result in higher reported 

emissions of CO2e for facilities that emit 

compounds for which the revised GWP 

is greater. In some cases, this will 

increase the number of facilities 

required to report under Part 98 and the 

total emissions reported for these 

facilities. 

The EPA received several comments 

on the impacts of the proposed rule. 

Specifically, we received comments 

stating that EPA significantly 

underestimated both the number of 

newly subject subpart HH MSW 

Landfills and the added costs of 

compliance imposed on both new and 

existing reporters, who are affected by 

the increase in the GWP for methane. As 

a result of these comments, the EPA has 

revised the impacts analysis for subpart 

HH, Municipal Landfills. The EPA has 

also updated the impacts assessment to 

calculate the total emissions increase 

from all reporters using 2011 reported 

data that became available following the 

publication of the proposed rule. In the 

proposed rule, the impacts assessment 

for the subparts that began reporting in 

RY 2011 relied on information from the 

EPA’s Economic Impacts Analyses and 

technical support documents for each of 

those subparts from the final Part 98. 

The new data is based on emissions 

estimates and data submitted in 2011 

annual reports and is more accurate for 

the purposes of calculating the impacts 

from this final rule. We have also 

revised the analysis to exclude the 26 

additional fluorinated GHGs that were 

proposed to be included in Table A–1, 

as we are not finalizing GWPs for these 

compounds in this rulemaking (see 

Section I.D of this preamble). Although 

some commenters requested that the 

impacts analysis should include the 

costs associated with implementation 

issues related to other EPA programs 

(e.g., EPA’s Tailoring Rule), we have 

determined that it is not appropriate to 

include these impacts under this Part 98 

rulemaking. See Section V.C of this 

preamble for the EPA’s response to 

these comments. 

The final amendments to Table A–1 

will result in a collective increase in 

annual reported emissions from all 

subparts of more than 79 million metric 

tons CO2e (a 1.1 percent increase in 

existing emissions), which the EPA has 

concluded more accurately reflects the 

estimated radiative forcing from the 

emissions reported under Part 98. The 

increase includes 4.8 million metric 

tons CO2e from an estimated 184 

additional facilities that may be newly 

required to report under Part 98 based 

on the revised GWPs. The number of 

new reporters estimated, the estimated 

increase in emissions or supply from 

existing reporters (reporters who 

submitted 2010 and 2011 reports) and 

new reporters, and the estimated total 

change in source category emissions or 

supply for each subpart are summarized 

in the memorandum ‘‘Assessment of 

Emissions and Cost Impacts of 2013 

Revisions to the Greenhouse Gas 

Reporting Rule and Confidentiality 

Determinations for New or Substantially 

Revised Data Elements’’ (hereinafter 

referred to as ‘‘Impacts Analysis’’) (see 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). 

Additional reporters are expected to 

report under subparts I, W, HH, II, OO, 

and TT due to an increase in the 

number of facilities exceeding the CO2e 

threshold. The majority of these 

additional reporters are be expected 

from subpart W, Petroleum and Natural 

Gas Systems, and subpart HH, 

Municipal Solid Waste Landfills. There 

are no expected additional reporters 

from the remaining subparts. The 

revisions do not reduce the number of 

reporters that meet CO2e thresholds for 

any subpart. A detailed analysis of the 

impacts for each subpart, including the 

number of additional reporters 

expected, the quantities of annual GHGs 

reported, and the compliance costs for 

expected additional reporters, is 

included in the Impacts Analysis for the 

final rule (see Docket Id. No. EPA–HQ– 

OAR–2012–0934). 

The total cost of compliance for the 

additional reporters is expected to be 

$2.2 million for the first year and $1.3 

million per year for subsequent years. 

The annual costs for the additional 

reporters is an approximate increase of 

1.3 percent above the existing reporters 

cost of compliance with Part 98. The 

costs of the final amendments and the 

associated methodology are summarized 

in Section V.A.2 of this preamble. 

1. How were the number of reporters 

and the change in annual emissions or 

supply estimated? 

As in the proposed rule, the EPA 

evaluated the number of reporters 

affected by the final amendments by 

examining the 2010 and 2011 reporters 

that are already required to report under 

Part 98. For the number of affected 

facilities, the EPA examined available 

e–GGRT data from the 2010 and 2011 

reporting years and summary data that 

were developed to support the existing 

Part 98 to determine the number of 

existing affected facilities. We then 

evaluated the number of additional 

facilities that are required to report 

under each subpart by determining what 

additional facilities could exceed Part 

98 source category thresholds, using the 

criteria presented in the 2013 Revisions 

proposal (see 78 FR 19841, April 2, 

2013). The subparts that could have new 

reporters as a result of the changes to 


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Table A–1 are subparts I, W, HH, II, OO, 

and TT. We identified the number of 

additional reporters expected under 

each subpart following the methodology 

outlined in the proposed rule (78 FR 

19841). 

The EPA determined the estimated 

increases in reported emissions for each 

subpart by examining the available data 

from facilities that submitted an annual 

report for reporting year 2011. For these 

reporters, we estimated the increase in 

calculated emissions from each facility 

by adjusting the reported GHG mass 

emissions to CO2e using the proposed 

AR4 GWPs. We also estimated the 

increase in emissions that would result 

from additional reporters in each 

subpart expected to exceed the source 

category threshold. For those facilities, 

the available source-specific emissions 

data for the expected new reporters was 

calculated in terms of CO2e and the 

estimated emissions were included in 

the total source category emissions. 

Additional information on the EPA’s 

analysis of the estimated number of 

reporters and the increase in reported 

CO2e for each subpart is in the Impacts 

Analysis for the final rule (see Docket 

Id. No. EPA–HQ–OAR–2012–0934). 

2. How were the costs of this final rule 

estimated? 

The compliance costs associated with 

the final amendments were determined 

for those additional reporters who are 

required to submit an annual report 

under Part 98. The total compliance 

costs for additional reporters are 

estimated to be $2.2 million for the first 

year and $1.3 million for subsequent 

years (2011 dollars). 

Costs for additional reporters are 

summarized in Table 4 of this preamble, 

which presents the first-year and 

subsequent-year costs for each source 

category. To estimate the cost impacts 

for additional reporters, the EPA used 

the same methodology from the 2013 

Revisions proposal. In addition to the 

costs for new reporters, the EPA 

estimated costs for closed landfills, or 

landfills expected to close within the 

next ten years, that would have an 

extended number of years of required 

reporting due to the increase in the 

GWP for methane. The cost for these 

additional years of reporting is included 

in Table 4 of this preamble. Costs are 

not included for landfills that were 

closed prior to January 1, 2013, have not 

previously reported under Part 98, and 

who generated less than 1,190 metric 

tons of CH4 in the 2010, 2011, 2012 and 

2013 reporting years. Landfills meeting 

these conditions are not required to 

report per the final revisions to subpart 

HH applicability (see Section II.R of this 

preamble for additional information). 

TABLE 4—COST IMPACTS OF FINAL AMENDMENTS FOR ADDITIONAL REPORTERS

Subpart 

Number of additional reporters due to revised GWP 

Incremental 

cost impact for 

additional reporters ($/yr 

for first year) 

Incremental 

cost impact for 

additional reporters ($/yr 

for subsequent 

years) 

I—Electronics Manufacturing ....................................................................................................... 4 129,500 237,000 

W—Petroleum & Natural Gas Systems ...................................................................................... 99 1,648,000 772,000 

HH—Municipal Solid Waste Landfills .......................................................................................... 57 246,000 182,200 

II—Industrial Wastewater ............................................................................................................. 2 10,800 10,500 

OO—Industrial GHG Suppliers .................................................................................................... 3 13,100 10,000 

TT—Industrial Waste Landfills ..................................................................................................... 19 112,000 98,050 

Total ...................................................................................................................................... 184 2,195,400 1,316,750 

aSubpart HH cost impact includes the reporting costs for 43 closed landfills that will exit the reporting program later than expected. Similarly, 

subpart TT cost impact includes the cost for 8 closed facilities. 

For existing reporters that have 

submitted an annual report for reporting 

year 2010 or 2011, there will be no 

significant cost impacts resulting from 

the proposed amendments to Table A– 

1; using the revised GWPs does not 

affect the cost of monitoring and 

recordkeeping and does not materially 

affect the cost for calculating emissions 

for these facilities. See the Impacts 

Analysis (Docket Id. No. EPA–HQ– 

OAR–2012–0934) for more details. 

B. What are the impacts of the other 

amendments and revisions in this final 

rule? 

There are no other changes from 

proposed rule to the impacts from the 

remaining amendments and revisions in 

this final rule. This final rule continues 

to include clarifications to terms and 

definitions for certain emission 

equations, simplifications to calculation 

methods and data reporting 

requirements, or corrections for 

consistency between provisions within 

a subpart or between subparts in Part 

98. These amendments do not 

fundamentally affect the applicability, 

monitoring requirements, or data 

collected and reported, or increase the 

recordkeeping and reporting burden 

associated with Part 98. Additionally, 

the final confidentiality determinations 

for new or substantially revised data 

elements do not affect whether and how 

data are reported and therefore, do not 

impose any additional burden on 

sources. See the EPA’s full analysis of 

the additional impacts of the 

corrections, clarifying, and other 

amendments in the Impacts Analysis in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). 

C. Summary of Comments and 

Responses Regarding Impacts 

This section summarizes the 

significant comments and responses 

related to the impacts and burden of the 

proposed revisions. See the comment 

response document in Docket Id. No. 

EPA–HQ–OAR–2012–0934 for a 

complete listing of all comments and 

responses related to the impacts of this 

rulemaking. 

Comment: Several commenters argued 

that the proposed rule does not 

calculate the complete cost of amending 

Table A–1, stating that the proposal 

merely estimates the costs that would be 

incurred by facilities that become 

subject to the Reporting Rule due to the 

amended GWP values. The commenters 

explained that the EPA should also 

calculate the costs incurred by facilities 

that become major sources of GHGs as 

a result of the amended GWP values and 

solicit public comment on the new cost 

calculations. The commenters asserted 

that the costs of performing a PSD 

review and obtaining a title V permit are 

substantial, and that the costs of 

obtaining a synthetic minor permit, 

while lower, are not insignificant. In 


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addition, commenters pointed out that 

some projects will be delayed or 

modified because of the requirement to 

obtain a permit before commencing 

construction, and that costs are 

especially significant in cases where a 

company planned and designed a 

project with the expectation that the 

facility would be a minor source for 

purposes of PSD, but must now conduct 

a PSD review because the facility is a 

major source under the new GWP 

values. One commenter stated that these 

added burdens are unwarranted, 

particularly since the added burdens are 

not a response to any increase in 

emissions. Other commenters 

maintained that it is insufficient for the 

EPA to simply state that EPA will work 

with permitting authorities and other 

stakeholders as necessary to provide 

guidance, that the EPA must provide 

some meaningful analysis of the impacts 

on these changes on regulators and 

industry under other affected regulatory 

programs, and that issues and concerns 

needing guidance should be addressed 

through public comment before 

promulgation of the final rule. 

Response: The EPA disagrees with 

commenters that the Impacts Analysis 

for the GHG Reporting Rule must 

include the costs incurred by facilities 

that become major sources of GHGs as 

a result of the amended GWP values. 

The cost impacts and burden associated 

with exceeding permitting thresholds 

were analyzed under the Tailoring Rule. 

Even though the Tailoring Rule analysis 

was based on the GWP values that were 

effective at the time of the analysis 

(from the 2009 GHG Reporting Rule), we 

do not believe that the amended GWP 

values would significantly change the 

Tailoring Rule analysis and the overall 

conclusions on permitting burden relief 

reached in terms of establishing 

thresholds for GHG permitting. 

With regard to the commenters’ 

suggestion that some projects will be 

delayed or modified because of the 

amended GWP values, the EPA believes 

that permit applicants who may be 

potentially impacted by the amended 

GWP changes have been made aware of 

the anticipated GWP changes through 

the notice and comment regulatory 

process of amending Part 98. The effects 

of the updates to Table A–1 on the 

Tailoring Rule were addressed in the 

Response to Public Comments on the 

Tailoring Rule (see Docket Id. No. EPA– 

HQ–OAR–2009–0517–19181, p. 101): 

‘‘Any changes to Table A–1 of the 

mandatory GHG reporting rule 

regulatory text must go through an 

appropriate notice-and-comment 

regulatory process. . . . the lead time 

for adopting changes to that rule will 

provide a transition time to address 

implementation concerns raised by 

commenters.’’ 

As noted in Section II.A.2.c of this 

preamble, to the extent that a Table A– 

1 amendment raises permitting 

implementation questions or concerns, 

the EPA will work with permitting 

authorities and other stakeholders as 

necessary to provide guidance on their 

issues and concerns. 

Comment: Several comments stated 

that the EPA did not accurately assess 

the impact of the GWP revisions on 

MSW landfills. Commenters indicated 

that the EPA significantly 

underestimated both the number of 

newly subject subpart HH MSW 

Landfills and the added costs of 

compliance imposed by these changes 

on both new and existing reporters. The 

commenters disputed the EPA’s 

conclusion in the Impacts Analysis 

accompanying the proposal that no 

closed landfills would be affected by the 

change in GWPs. According to 

commenters, several closed landfills 

with methane generations between 

21,000 and 24,999 metric tons/year 

CO2e could exceed the threshold due to 

the proposed revision of the GWP for 

methane. One commenter claimed that, 

although emissions from these landfills 

will steadily decline, they could be 

required to report for at least three to 

five years as a result of the revised GWP 

for methane, and would thus face a 

significant impact. Commenters also 

pointed out that this situation is also 

likely to arise for small municipalities 

that own closed facilities. 

Commenters also stated that the EPA 

failed to recognize that revising GWPs 

will delay the date by which lowemitting MSW landfills can exit the 

reporting program. They explained that 

while the proposal Impacts Analysis 

estimated methane generation at a 

closed landfill decreases 18% in 5 years, 

an increase in GWP from 21 to 25 will 

increase modeled emissions by 20% and 

will therefore delay exit from the 

reporting program obligations by more 

than 5 years. 

Commenters also asserted that EPA 

underestimated the cost of complying 

with the proposed amended reporting 

requirements under subpart HH. They 

stated that, based on industry reporting 

experience, they believe actual annual 

costs to comply with the monitoring 

recordkeeping and reporting 

requirements are four to five times 

higher than the EPA estimates in Table 

11 of the proposal preamble and Tables 

4–1 and 6–16 of the Impacts Analysis, 

which state the incremental annual cost 

impact for new subpart HH reporters is 

$309,700 (or $5,434 per facility) for the 

initial year of reporting and $137,500 (or 

$2,413 per site) in subsequent years of 

reporting (2011 US Dollars). Two 

commenters attested that data they had 

submitted to the EPA previously on 

ongoing reporting showed that the 

annual cost per landfill for subsequent 

years of reporting ranged from $10,000 

to $15,000 per site. One commenter 

stated that the EPA also did not account 

for the cost of responding to EPA 

questions raised on facility reports, 

which require a facility to respond 

within 45 days and may require 

corrections and report re-submittal. 

Response: Upon further analysis, the 

EPA agrees that there may be closed 

landfills with methane generation 

between 21,000 and 24,999 metric tons/ 

year CO2e, and that under the proposed 

rule these closed facilities would be 

subject to new reporting requirements. 

For this reason, a provision has been 

included in the final amendments to 

subpart HH that specifically exempts 

landfills that did not accept waste on or 

after January 1, 2013 and had methane 

generation less than 1,190 metric tons of 

methane (25,000 CO2e). See Section II.R 

of this preamble for additional 

discussion. 

The EPA also agrees that the 

economic impact assessment for the 

changes to the GWP of methane did not 

include the cost that closed, or soon to 

be closed, landfills would incur due to 

the extended number of years that 

reporting will be required. In response 

to this comment, we have estimated that 

there are approximately 196 closed 

MSW landfills, and 233 open MSW 

landfills, expected to close within the 

next ten years, that will be required to 

submit reports for an additional 5 years. 

Of these facilities, we estimated there 

are 43 facilities that will incur one or 

more additional years of reporting 

within the next ten years. The average 

additional annual cost for these 

facilities is estimated at $37,360. The 

EPA has also made a similar estimate of 

costs for industrial landfills (subpart 

TT), and has concluded that there are 

eight facilities that may be required to 

report for one or more additional years 

within the next ten years. The annual 

average cost associated with these 

reports is $12,000. The details of these 

changes to the cost impact are available 

in the Impacts Analysis in Docket Id. 

No. EPA–HQ–OAR–2012–0934. 

With regard to the comment that the 

EPA underestimated the cost to submit 

reports for all facilities and that the 

costs incurred by facilities are four to 

five times higher than the EPA 

originally estimated, this information 

was taken into consideration in the most 

recent Information Collection Request 


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(ICR) (see Docket Id. No. EPA–HQ– 

OAR–2012–0333) and no changes were 

made to the estimated cost to report 

based on the information submitted (see 

EPA’s response to comments on the 

GHGRP renewal ICR, dated May 2013, 

in Docket Id. No. EPA–HQ–OAR–2012– 

0333). The major factor influencing the 

cost from both companies was the 

frequency of monitoring required for 

estimating emissions from Municipal 

Solid Waste Landfills (subpart HH). The 

EPA disagrees with the feedback 

provided. In making the cost estimates, 

the EPA assumes that the operators will 

pick the lowest cost operations for 

monitoring emissions. Part of this 

assumption includes that landfill 

operators will be visiting the landfills at 

least once a week under normal 

operation to check and maintain 

equipment. The majority of landfills in 

the U.S. are active and would not 

require additional visits to monitor 

emissions. We concluded, after 

evaluating comments about 

underestimating the reporting burden, 

that the Agency’s methodology and 

assumptions used in the Economic 

Impact Analysis were sound and relied 

on the best available data. Therefore, it 

is reasonable of EPA to use the 

Economic Impact Analysis to estimate 

total cost burden on landfills affected by 

the changes to the revised GWP, and the 

Economic Impact Analysis provides a 

reasonable characterization of costs and 

adequate explanation of how the costs 

were estimated. As we discussed in 

Section VII of the final Part 98 preamble 

(74 FR 56362, October 30, 2009), the 

EPA collected and evaluated cost data 

from multiple sources, thoroughly 

reviewed the input received through 

public comments, and weighed the 

analysis against this input. 

Comment: Some commenters asserted 

that any time the EPA changes factors to 

be used in estimating a facility’s GHG 

emissions for reporting purposes (such 

as GWPs, fuel emission factors, or high 

heating values), companies have to 

expend substantial efforts to revise 

systems they have developed and put in 

place, often at considerable cost, to 

collect the required information, apply 

the GHG emission estimation methods 

the EPA requires, and consolidate and 

report GHG emission estimates to the 

EPA. They explained that in addition to 

imposing substantial burdens on 

businesses and public and private 

institutions, it also introduces the 

potential for errors every time existing 

reporting systems have to be modified. 

The commenters argued that the EPA is 

neglecting to account for the costs 

incurred by existing reporters to 

implement these changes. 

One commenter contended that, if the 

primary use for GHG emissions reported 

under the GHGRP is for comparative 

purposes (i.e. determining trends in 

GHG emissions, comparing U.S. 

emissions to those of other countries, 

etc.), making relatively small revisions 

to the methods for calculating estimated 

GHG emissions is not going to produce 

a benefit that warrants the burden 

imposed on regulated facilities to adjust 

to those revisions. The commenter 

recommended that the EPA not 

promulgate future changes to GWPs, nor 

other changes to the methodologies for 

estimating GHG emissions in the 

Greenhouse Gas Reporting Rule, if the 

change is unlikely to produce more than 

a five percent change in estimated 

emissions. 

Response: As the EPA stated in the 

preamble for the proposed amendments 

(78 FR 19802, April 2, 2013), the 

amendments reflect the EPA’s 

engagement with reporters and 

stakeholders and our understanding of 

the technical challenges and burden 

associated with implementation of Part 

98 provisions. The changes improve the 

GHGRP by clarifying compliance 

obligations and reducing confusion for 

reporters, improving the consistency of 

the data collected, and ensuring that 

data collected through the GHGRP is 

representative of industry and 

comparable to other inventories. The 

proposed changes simplify data 

collection and reporting for reporters 

and reduce the burden associated with 

implementing certain provisions of 40 

CFR part 98. These clarifications and 

corrections do not fundamentally affect 

the applicability, monitoring 

requirements, or data collected and 

reported or increase the recordkeeping 

and reporting burden associated with 

Part 98. The EPA estimated the impacts 

of the corrections, clarifying, and other 

amendments in the Impacts Analysis in 

Docket Id. No. EPA–HQ–OAR–2012– 

0934 and determined that the impacts 

from these changes to each subpart was 

minimal. As such, the EPA has 

determined the amendments to the final 

rule do not present an undue cost 

burden on reporters. 

VI. Statutory and Executive Order 

Reviews 

A. Executive Order 12866: Regulatory 

Planning and Review and Executive 

Order 13563: Improving Regulation and 

Regulatory Review 

This action is not a ‘‘significant 

regulatory action’’ under the terms of 

Executive Order 12866 (58 FR 51735, 

October 4, 1993) and is therefore not 

subject to review under Executive 

Orders 12866 and 13563 (76 FR 3821, 

January 21, 2011). This action (1) 

clarifies or changes specific provisions 

in the Greenhouse Gas Reporting Rule, 

including amending Table A–1 of 

Subpart A to incorporate revised GWPs 

from the IPCC AR4, and (2) finalizes 

confidentiality determinations for the 

reporting of new or substantially revised 

(i.e., requiring additional or different 

data to be reported) data elements 

contained in the final amendments. The 

EPA prepared an analysis of the 

potential compliance costs associated 

with the final amendments and 

amendments to revise global warming 

potentials in subpart A. This analysis is 

contained in the Impacts Analysis (see 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). A copy of the analysis is 

available in the docket for this action 

and the analysis is briefly summarized 

here. The total compliance costs for 

additional reporters are $1,316,700 

($2011). The highest costs are 

anticipated for 99 facilities affected by 

subpart W, Petroleum and Natural Gas 

Systems, ($772,000), 4 facilities affected 

by subpart I, Electronics Manufacturing 

($237,000), and 57 facilities affected by 

subpart HH, Municipal Solid Waste 

Landfills ($182,200). New facilities 

required to report under subparts II, OO, 

and TT incur a combined cost of 

$118,550. The final confidentiality 

determinations for new and 

substantially revised data elements do 

not increase the existing compliance 

costs. The compliance costs associated 

with the final amendments are less than 

the significance threshold of $100 

million per year. The compliance costs 

for individual facilities are not expected 

to impose a significant economic 

burden. 

B. Paperwork Reduction Act 

The Office of Management and Budget 

(OMB) has approved the information 

collection requirements for 40 CFR part 

98 under the provisions of the 

Paperwork Reduction Act, 44 U.S.C. 

3501 et seq., and has assigned OMB 

control number 2060–0629, ICR 

2300.10. The OMB control numbers for 

EPA’s regulations in 40 CFR are listed 

in 40 CFR part 9. The revisions in this 

final action result in a small increase in 

burden, and the ICR will be modified to 

reflect this burden change. 

This action finalizes amended GWP 

values in subpart A and other 

corrections and harmonizing revisions, 

and finalizes confidentiality 

determinations for the reporting of new 

or substantially revised (i.e., requiring 

additional or different data to be 


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reported) data elements contained in the 

final amendments. These final 

amendments and confidentiality 

determinations do not make any 

substantive changes to the reporting 

requirements in any of the subparts for 

which amendments are being finalized. 

The final amendments to subpart A 

include revision of existing GWPs in 

Table A–1 of subpart A. As discussed in 

Section V of this preamble, the final 

amendments could affect the total 

number of facilities reporting under Part 

98 and increase the collective annual 

emissions or supply reported. The EPA 

prepared an analysis of the compliance 

costs associated with the final 

amendments to Table A–1 in the 

Impacts Analysis (see Docket Id. No. 

EPA–HQ–OAR–2012–0934). 

Other amendments to subpart A 

include adding requirements that 

provide reporters instruction regarding 

reporting of location, ownership, and 

facility identification (i.e., reporting of 

plant codes). The remaining changes 

also include revising and adding 

definitions. The revisions are 

clarifications or require reporting of 

information that facilities are expected 

to have readily available (e.g., latitude 

and longitude of the facility, unit-level 

and configuration-level ‘‘plant code’’), 

and are not expected to result in 

significant burden for reporters. 

The amendments to the reporting 

requirements in the source categoryspecific subparts generally do not 

change the nature of the data reported 

and are not anticipated to result in 

significant burden for reporters. For 

example, several of the amendments are 

clarifications or corrections to existing 

reporting requirements. For example, for 

subpart H, the EPA is requiring 

reporting of annual, facility-wide 

cement production instead of monthly, 

kiln-specific cement production for 

facilities that use a CEMS to measure 

CO2 emissions. Because facilities are 

already expected to track facility-wide 

cement production for budgeting 

purposes, we do not expect this revision 

to result in any additional burden for 

cement production facilities. In some 

cases we are including reporting 

requirements for data that are already 

collected by reporters. For instance, for 

subpart RR, the EPA is adding a 

reporting requirement for facilities to 

report the standard or method used to 

calculate the mass or volume of contents 

in containers that is redelivered to 

another facility without being injected 

into the well. The new data element 

does not require additional data 

collection or monitoring from reporters, 

and is not a significant change. 

The EPA is also finalizing changes 

that would reduce the reporting burden. 

For example, for subpart BB (Silicon 

Carbide Production), the EPA is 

removing the requirement for facilities 

to report CH4 emissions from silicon 

carbide process units or furnaces. 

Additionally, the EPA is amending 

subpart BB such that facilities would 

calculate and report CO2 emissions for 

all process units and furnaces 

combined, instead of each process unit 

or production furnace. We expect that 

both of these major changes will reduce 

the reporting burden for facilities 

subject to subpart BB. 

Additional changes to the reporting 

requirements in each subpart are 

detailed in the Impacts Analysis (see 

Docket Id. No. EPA–HQ–OAR–2012– 

0934). 

C. Regulatory Flexibility Act (RFA) 

The Regulatory Flexibility Act (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 impact 

of this final rule on small entities, small 

entity is defined as: (1) A small business 

as defined by the Small Business 

Administration’s regulations at 13 CFR 

121.201; (2) a small governmental 

jurisdiction that is a government of a 

city, county, town, school district or 

special district with a population of less 

than 50,000; and (3) a small 

organization that is any not-for-profit 

enterprise which is independently 

owned and operated and is not 

dominant in its field. 

After considering the economic 

impacts of today’s final rule on small 

entities, I certify that this action will not 

have a significant economic impact on 

a substantial number of small entities. 

The small entities directly regulated by 

this final rule are small businesses. We 

have determined that up to 80 small 

municipal solid waste landfills, 

representing up to a 1 percent increase 

in regulated businesses in this industry, 

will experience an impact of 0.02 to 0.6 

percent of revenues; up to 3 suppliers of 

industrial GHGs, representing up to a 

0.85 percent increase in regulated 

businesses in this industry, will 

experience an impact of 0.02 to 0.14 

percent of revenues; and that up to 27 

industrial waste landfills (primarily colocated with food processing facilities), 

representing up to a 7.3 percent increase 

in regulated businesses in this industry, 

will experience an impact of 0.01 to 

0.48 percent of revenues. 

Although this final rule will not have 

a significant economic impact on a 

substantial number of small entities, the 

EPA nonetheless has tried to reduce the 

impact of Part 98 on small entities. For 

example, the EPA conducted several 

meetings with industry associations to 

discuss regulatory options and the 

corresponding burden on industry, such 

as recordkeeping and reporting. The 

EPA continues to conduct significant 

outreach on Part 98 and maintains an 

‘‘open door’’ policy for stakeholders to 

help inform the EPA’s understanding of 

key issues for the industries. 

D. Unfunded Mandates Reform Act 

(UMRA) 

The final rule amendments and 

confidentiality determinations do not 

contain a federal mandate that may 

result in expenditures of $100 million or 

more for state, local, and tribal 

governments, in the aggregate, or the 

private sector in any one year. Thus, the 

final rule amendments and 

confidentiality determinations are not 

subject to the requirements of section 

202 and 205 of the UMRA. 

This final rule is also not subject to 

the requirements of section 203 of 

UMRA because it contains no regulatory 

requirements that might significantly or 

uniquely affect small governments. The 

final rule amends specific provisions in 

subpart A, General Provisions, to reflect 

global warming potentials that have 

been published by the IPCC. Also in this 

action, the EPA is revising specific 

provisions to provide clarity on what is 

to be reported. In some cases, the EPA 

has increased flexibility in the selection 

of methods used for calculating and 

monitoring GHGs. Therefore, this action 

is not subject to the requirements of 

section 203 of the UMRA. 

E. Executive Order 13132: Federalism 

This action does not have federalism 

implications. It will not have substantial 

direct effects on the States, on the 

relationship between the national 

government and the States, or on the 

distribution of power and 

responsibilities among the various 

levels of government, as specified in 

Executive Order 13132. 

The final amendments and 

confidentiality determinations apply 

directly to facilities that directly emit 

greenhouses gases or that are suppliers 

of greenhouse gases. They do not apply 

to governmental entities unless the 

government entity owns a facility that 


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directly emits greenhouse gases above 

threshold levels (such as a landfill or 

large combustion device), so relatively 

few government facilities would be 

affected. Moreover, for government 

facilities that are subject to the rule, the 

final revisions will not have a 

significant cost impact. This regulation 

also does not limit the power of States 

or localities to collect GHG data and/or 

regulate GHG emissions. Thus, 

Executive Order 13132 does not apply 

to this action. 

In the spirit of Executive Order 13132, 

and consistent with EPA policy to 

promote communications between EPA 

and State and local governments, the 

EPA specifically solicited comment on 

the proposed action from State and local 

officials. The EPA carefully considered 

the comments received in developing 

this final rule, including providing 

regulatory flexibility for certain 

municipally-owned solid waste landfills 

under subpart HH. 

F. Executive Order 13175: Consultation 

and Coordination With Indian Tribal 

Governments 

This action does not have tribal 

implications, as specified in Executive 

Order 13175 (65 FR 67249, November 9, 

2000). The final amendments and 

confidentiality determinations apply 

directly to facilities that directly emit 

greenhouses gases or that are suppliers 

of greenhouse gases. They would not 

have tribal implications unless the tribal 

entity owns a facility that directly emits 

greenhouse gases above threshold levels 

(such as a landfill or large combustion 

device). Relatively few tribal facilities 

would be affected. Thus, Executive 

Order 13175 does not apply to this 

action. 

G. Executive Order 13045: Protection of 

Children From Environmental Health 

Risks and Safety Risks 

The EPA interprets Executive Order 

13045 (62 FR 19885, April 23, 1997) as 

applying only to those regulatory 

actions that concern health or safety 

risks, such that the analysis required 

under section 5–501 of the Executive 

Order has the potential to influence the 

regulation. This action is not subject to 

Executive Order 13045 because it does 

not establish an environmental standard 

intended to mitigate health or safety 

risks. 

H. Executive Order 13211: Actions that 

Significantly Affect Energy Supply, 

Distribution, or Use 

This action is not subject to Executive 

Order 13211 (66 FR 28355 (May 22, 

2001)), because it is not a significant 

regulatory action under Executive Order 

12866. 

I. National Technology Transfer and 

Advancement Act 

Section 12(d) of the National 

Technology Transfer and Advancement 

Act of 1995 (NTTAA), Public Law 104– 

113 (15 U.S.C. 272 note) directs the 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 the 

EPA to provide Congress, through OMB, 

explanations when the Agency decides 

not to use available and applicable 

voluntary consensus standards. 

This final rule does not involve any 

new technical standards, but allows for 

greater flexibility for reporters to use 

consensus standards where they are 

available. Therefore, the EPA did not 

consider the use of specific voluntary 

consensus standards. 

J. Executive Order 12898: Federal 

Actions to Address Environmental 

Justice in Minority Populations and 

Low-Income Populations 

Executive Order 12898 (59 FR 7629, 

(February 16, 1994) establishes Federal 

executive policy on environmental 

justice. Its main provision directs 

Federal agencies, to the greatest extent 

practicable and permitted by law, to 

make environmental justice part of their 

mission by identifying and addressing, 

as appropriate, disproportionately high 

and adverse human health or 

environmental effects of their programs, 

policies, and activities on minority 

populations and low-income 

populations in the United States. 

The 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 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. The 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 United States prior to 

publication of the rule in the Federal 

Register. A Major rule cannot take effect 

until 60 days after it is published in the 

Federal Register. This action is not a 

‘‘major rule’’ as defined by 5 U.S.C. 

804(2). This rule will be effective on 

January 1, 2014. 

List of Subjects 40 CFR Part 98 

Environmental protection, 

Administrative practice and procedure, 

Greenhouse gases, Reporting and 

recordkeeping requirements. 

Dated: November 15, 2013. 

Gina McCarthy, 

Administrator. 

For the reasons stated in the 

preamble, title 40, chapter I, of the Code 

of Federal Regulations is amended as 

follows: 

PART 98—MANDATORY 

GREENHOUSE GAS REPORTING 

■ 1. The authority citation for part 98 

continues to read as follows: 

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

Subpart A—[Amended] 

■ 2. Section 98.3 is amended by: 

■ a. Revising paragraph (c)(1). 

■ b. Adding paragraphs (c)(11)(viii) and 

(c)(13). 

■ c. Revising paragraphs (h)(4) and 

(j)(3)(ii). 

■ d. Adding paragraphs (k) and (l). 

The revisions and additions read as 

follows: 

§ 98.3 What are the general monitoring, 

reporting, recordkeeping and verification 

requirements of this part? 

* * * * * 

(c) * * * 

(1) Facility name or supplier name (as 

appropriate), and physical street address 

of the facility or supplier, including the 

city, State, and zip code. If the facility 

does not have a physical street address, 

then the facility must provide the 

latitude and longitude representing the 

geographic centroid or center point of 

facility operations in decimal degree 

format. This must be provided in a 

comma-delimited ‘‘latitude, longitude’’ 

coordinate pair reported in decimal 

degrees to at least four digits to the right 

of the decimal point. 

* * * * * 

(11) * * * 

(viii) The facility or supplier must 

refer to the reporting instructions of the 


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electronic GHG reporting tool regarding 

standardized conventions for the 

naming of a parent company. 

* * * * * 

(13) An indication of whether the 

facility includes one or more plant sites 

that have been assigned a ‘‘plant code’’ 

(as defined under § 98.6) by either the 

Department of Energy’s Energy 

Information Administration or by the 

EPA’s Clean Air Markets Division. 

* * * * * 

(h) * * * 

(4) Notwithstanding paragraphs (h)(1) 

and (2) of this section, upon request by 

the owner or operator, the 

Administrator may provide reasonable 

extensions of the 45-day period for 

submission of the revised report or 

information under paragraphs (h)(1) and 

(2) of this section. If the Administrator 

receives a request for extension of the 

45-day period, by email to an address 

prescribed by the Administrator prior to 

the expiration of the 45-day period, the 

extension request is deemed to be 

automatically granted for 30 days. The 

Administrator may grant an additional 

extension beyond the automatic 30-day 

extension if the owner or operator 

submits a request for an additional 

extension and the request is received by 

the Administrator at least 5 business 

days prior to the expiration of the 

automatic 30-day extension, provided 

the request demonstrates that it is not 

practicable to submit a revised report or 

information under paragraphs (h)(1) and 

(2) within 75 days. The Administrator 

will approve the extension request if the 

request demonstrates to the 

Administrator’s satisfaction that it is not 

practicable to collect and process the 

data needed to resolve potential 

reporting errors identified pursuant to 

paragraphs (h)(1) or (2) of this section 

within 75 days. 

* * * * * 

(j) * * * 

(3) * * * 

(ii) Any subsequent extensions to the 

original request must be submitted to 

the Administrator within 4 weeks of the 

owner or operator identifying the need 

to extend the request, but in any event 

no later than 4 weeks before the date for 

the planned process equipment or unit 

shutdown that was provided in the 

original or most recently approved 

request. 

* * * * * 

(k) Revised global warming potentials 

and special provisions for reporting year 

2013. This paragraph (k) applies to 

owners or operators of facilities or 

suppliers that first become subject to 

any subpart of part 98 solely due to an 

amendment to Table A–1 of this 

subpart. 

(1) A facility or supplier that was not 

subject to any subpart of part 98 for 

reporting year 2012, but first becomes 

subject to any subpart of part 98 due to 

a change in the GWP for one or more 

compounds in Table A–1 of this 

subpart, Global Warming Potentials, is 

not required to submit an annual GHG 

report for reporting year 2013. 

(2) A facility or supplier that is 

subject to a subpart of part 98 for 

reporting year 2012, but first becomes 

subject to any subpart of part 98 due to 

a change in the GWP for one or more 

compounds in Table A–1 of this 

subpart, is not required to include those 

subparts for which the facility is subject 

only due to the change in the GWP in 

the annual GHG report submitted for 

reporting year 2013. 

(3) Starting on January 1, 2014, 

facilities or suppliers identified in 

paragraphs (k)(1) or (2) of this section 

must start monitoring and collecting 

GHG data in compliance with the 

applicable subparts of part 98 for which 

the facility is subject due to the change 

in the GWP for the annual greenhouse 

gas report for reporting year 2014, 

which is due by March 31, 2015. 

(l) Special provision for best available 

monitoring methods in 2014. This 

paragraph (l) applies to owners or 

operators of facilities or suppliers that 

first become subject to any subpart of 

part 98 due to an amendment to Table 

A–1 of this subpart, Global Warming 

Potentials. 

(1) Best available monitoring 

methods. From January 1, 2014 to 

March 31, 2014, owners or operators 

subject to this paragraph (l) may use 

best available monitoring methods for 

any parameter (e.g., fuel use, feedstock 

rates) 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, 2014. Starting no later than 

April 1, 2014, 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 

provided in paragraph (l)(2) of this 

section. Best available monitoring 

methods means any of the following 

methods: 

(i) Monitoring methods currently used 

by the facility that do not meet the 

specifications of a 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, 2014. 

(i) Timing of request. The extension 

request must be submitted to EPA no 

later than January 31, 2014. 

(ii) Content of request. Requests must 

contain the following information: 

(A) A list of specific items 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 that 

the needed equipment could not be 

obtained and installed before April 1, 

2014. 

(D) If the reason for the extension is 

that the equipment cannot be purchased 

and delivered by April 1, 2014, 

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 November 29, 2013 

and April 1, 2014, 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. 


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(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, 2014. The use of 

best available methods under this 

paragraph (l) will not be approved 

beyond December 31, 2014. 

■ 3. Section 98.6 is amended by: 

■ a. Revising the definitions for 

‘‘Continuous bleed’’, ‘‘Degasification 

system’’, and ‘‘Intermittent bleed 

pneumatic devices’’. 

■ b. Adding the definition of ‘‘Plant 

code’’ in alphabetical order. 

■ c. Revising the term ‘‘Ventilation well 

or shaft’’ to read ‘‘Ventilation hole or 

shaft’’ and revising the definition of the 

term. 

■ d. Revising the definition of 

‘‘Ventilation system’’. 

The revisions and addition read as 

follows: 

§ 98.6 Definitions. 

* * * * * 

Continuous bleed means a continuous 

flow of pneumatic supply natural gas to 

the process control device (e.g. level 

control, temperature control, pressure 

control) where the supply gas pressure 

is modulated by the process condition, 

and then flows to the valve controller 

where the signal is compared with the 

process set-point to adjust gas pressure 

in the valve actuator. 

* * * * * 

Degasification system means the 

entirety of the equipment that is used to 

drain gas from underground coal mines. 

This includes all degasification wells 

and gob gas vent holes at the 

underground coal mine. Degasification 

systems include gob and premine 

surface drainage wells, gob and premine 

in-mine drainage wells, and in-mine gob 

and premine cross-measure borehole 

wells. 

* * * * * 

Intermittent bleed pneumatic devices 

mean automated flow control devices 

powered by pressurized natural gas and 

used for automatically maintaining a 

process condition such as liquid level, 

pressure, delta-pressure and 

temperature. These are snap-acting or 

throttling devices that discharge all or a 

portion of the full volume of the 

actuator intermittently when control 

action is necessary, but does not bleed 

continuously. 

* * * * * 

Plant code means either of the 

following: 

(1) The Plant ID code assigned by the 

Department of Energy’s Energy 

Information Administration. The Energy 

Information Administration Plant ID 

code is also referred to as the ‘‘ORIS 

code’’, ‘‘ORISPL code’’, ‘‘Facility ID’’, or 

‘‘Facility code’’, among other names. 

(2) If a Plant ID code has not been 

assigned by the Department of Energy’s 

Energy Information Administration, 

then plant code means a code beginning 

with ‘‘88’’ assigned by the EPA’s Clean 

Air Markets Division for electronic 

reporting. 

* * * * * 

Ventilation hole or shaft means a vent 

hole or shaft employed at an 

underground coal mine to serve as the 

outlet or conduit to move air from the 

ventilation system out of the mine. 

Ventilation system means a system 

that is used to control the concentration 

of methane and other gases within mine 

working areas through mine ventilation, 

rather than a mine degasification 

system. A ventilation system consists of 

fans that move air through the mine 

workings to dilute methane 

concentrations. 

* * * * * 

§ 98.7 [Amended] 

■ 4. Section 98.7 is amended by 

removing and reserving paragraph (n). 

■ 5. Table A–1 to Subpart A is revised 

to read as follows: 

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 a 25 

Nitrous oxide ...................................................................................... 10024–97–2 N2O a 298 

HFC–23 .............................................................................................. 75–46–7 CHF3 a 14,800 

HFC–32 .............................................................................................. 75–10–5 CH2F2 a 675 

HFC–41 .............................................................................................. 593–53–3 CH3F a 92 

HFC–125 ............................................................................................ 354–33–6 C2HF5 a 3,500 

HFC–134 ............................................................................................ 359–35–3 C2H2F4 a 1,100 

HFC–134a .......................................................................................... 811–97–2 CH2FCF3 a 1,430 

HFC–143 ............................................................................................ 430–66–0 C2H3F3 a 353 

HFC–143a .......................................................................................... 420–46–2 C2H3F3 a 4,470 

HFC–152 ............................................................................................ 624–72–6 CH2FCH2F 53 

HFC–152a .......................................................................................... 75–37–6 CH3CHF2 a 124 

HFC–161 ............................................................................................ 353–36–6 CH3CH2F 12 

HFC–227ea ........................................................................................ 431–89–0 C3HF7 a 3,220 

HFC–236cb ........................................................................................ 677–56–5 CH2FCF2CF3 1,340 

HFC–236ea ........................................................................................ 431–63–0 CHF2CHFCF3 1,370 

HFC–236fa ......................................................................................... 690–39–1 C3H2F6 a 9,810 

HFC–245ca ........................................................................................ 679–86–7 C3H3F5 a 693 

HFC–245fa ......................................................................................... 460–73–1 CHF2CH2CF3 1,030 

HFC–365mfc ...................................................................................... 406–58–6 CH3CF2CH2CF3 794 

HFC–43–10mee ................................................................................. 138495–42–8 CF3CFHCFHCF2CF3 a 1,640 

Sulfur hexafluoride ............................................................................. 2551–62–4 SF6 a 22,800 

Trifluoromethyl sulphur pentafluoride ................................................ 373–80–8 SF5CF3 17,700 

Nitrogen trifluoride ............................................................................. 7783–54–2 NF3 17,200 

PFC–14 (Perfluoromethane) .............................................................. 75–73–0 CF4 a 7,390 

PFC–116 (Perfluoroethane) ............................................................... 76–16–4 C2F6 a 12,200 

PFC–218 (Perfluoropropane) ............................................................ 76–19–7 C3F8 a 8,830 

Perfluorocyclopropane ....................................................................... 931–91–9 C–C3F6 17,340 

PFC–3–1–10 (Perfluorobutane) ......................................................... 355–25–9 C4F10 a 8,860 


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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.) 

PFC–318 (Perfluorocyclobutane) ...................................................... 115–25–3 C–C4F8 a 10,300 

PFC–4–1–12 (Perfluoropentane) ....................................................... 678–26–2 C5F12 a 9,160 

PFC–5–1–14 (Perfluorohexane, FC–72) ........................................... 355–42–0 C6F14 a 9,300 

PFC–9–1–18 ...................................................................................... 306–94–5 C10F18 7,500 

HCFE–235da2 (Isoflurane) ................................................................ 26675–46–7 CHF2OCHClCF3 350 

HFE–43–10pccc (H–Galden 1040x, HG–11) .................................... E1730133 CHF2OCF2OC2F4OCHF2 1,870 

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

HFE–134 (HG–00) ............................................................................. 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 ................................................................................... 134769–21–4 CF3CF2OCF2CHF2 919 

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

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

HFE–347mcc3 (HFE–7000) .............................................................. 375–03–1 CH3OCF2CF2CF3 575 

HFE–347mcf2 .................................................................................... 171182–95–9 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 ..................................................................................... 50807–77–7 CHF2CH2OCF2CHF2 265 

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

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

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

HFE–449s1 (HFE–7100) ................................................................... 163702–07–6 C4F9OCH3 297 

Chemical blend .................................................................................. 163702–08–7 (CF3)2CFCF2OCH3

HFE–569sf2 (HFE–7200) .................................................................. 163702–05–4 C4F9OC2H5 59 

Chemical blend .................................................................................. 163702–06–5 (CF3)2CFCF2OC2H5

Sevoflurane (HFE–347mmz1) ........................................................... 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 (HT–70) ............................................................................... NA CF3OCF(CF3)CF2OCF2OCF3 10,300 

aThe GWP for this compound is different than the GWP in the version of Table A–1 to subpart A of part 98 published on October 30, 2009. 

■ 6. Table A–6 is amended by removing 

the entry for 98.466(c)(1) and revising 

the entries for 98.346(d)(1), 98.346(e), 

98.346(i)(5), 98.346(i)(7), and 

98.466(d)(3) to read as follows: 

TABLE A–6 TO SUBPART A OF PART 98—DATA ELEMENTS THAT ARE INPUTS TO EMISSION EQUATIONS AND FOR WHICH

THE REPORTING DEADLINE IS MARCH 31, 2013 

Subpart Rule citation 

(40 CFR part 98) 

Specific data elements for which reporting date is March 31, 2013 (‘‘All’’ means all data elements in the cited 

paragraph are not required to be reported until March 31, 2013) 

******

HH ........ 98.346(d)(1) Only degradable organic carbon (DOC) value, and fraction of DOC dissimilated (DOCF) values. 

******

HH ........ 98.346(e) Only fraction of CH4 in landfill gas and methane correction factor (MCF) values. 

******

HH ........ 98.346(i)(5) Only annual operating hours for the destruction devices located at the landfill facility, and the destruction efficiency for the destruction devices associated with that measurement location. 


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71950 Federal Register / Vol. 78, No. 230 / Friday, November 29, 2013 / Rules and Regulations 

TABLE A–6 TO SUBPART A OF PART 98—DATA ELEMENTS THAT ARE INPUTS TO EMISSION EQUATIONS AND FOR WHICH

THE REPORTING DEADLINE IS MARCH 31, 2013—Continued 

Subpart Rule citation 

(40 CFR part 98) 

Specific data elements for which reporting date is March 31, 2013 (‘‘All’’ means all data elements in the cited 

paragraph are not required to be reported until March 31, 2013) 

******

HH ........ 98.346(i)(7) Only surface area specified in Table HH–3, estimated gas collection system efficiency, and annual operating 

hours of the gas collection system for each measurement locations. 

******

TT ......... 98.466(d)(3) Only degradable organic carbon (DOCx) value for each waste stream used in calculations. 

Table A–7 to Subpart A of Part 98

[Amended] 

■ 7. Table A–7 is amended by removing 

the entries for 98.256(o)(6) and 

98.256(o)(7). 

Subpart C—[AMENDED] 

■ 8. Section 98.33 is amended by adding 

paragraph (b)(1)(viii) and revising 

paragraphs (b)(3)(ii)(A) and (e)(1)(ii) to 

read as follows: 

§ 98.33 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(viii) May be used for the combustion 

of a fuel listed in Table C–1 if the fuel 

is combusted in a unit with a maximum 

rated heat input capacity greater than 

250 mmBtu/hr (or, pursuant to 

§ 98.36(c)(3), in a group of units served 

by a common supply pipe, having at 

least one unit with a maximum rated 

heat input capacity greater than 250 

mmBtu/hr), provided that both of the 

following conditions apply: 

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

(B) The fuel provides less than 10 

percent of the annual heat input to the 

unit, or if § 98.36(c)(3) applies, to the 

group of units served by a common 

supply pipe. 

* * * * * 

(3) * * * 

(ii) * * * 

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

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

(b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this 

section. 

* * * * * 

(e) * * * 

(1) * * * 

(ii) The procedures in paragraph (e)(4) 

of this section. 

* * * * * 

■ 9. Section 98.36 is amended by: 

■ a. Revising paragraph (b)(3). 

■ b. Adding paragraphs (b)(11), 

(c)(1)(xi), (c)(2)(x), and (c)(2)(xi). 

■ c. Revising the next to last sentence of 

paragraph (c)(3) introductory text. 

■ d. Adding paragraphs (c)(3)(x), 

(d)(1)(x), (d)(2)(ii)(J), and (d)(2)(iii)(J). 

The revisions and additions read as 

follows: 

§ 98.36 Data reporting requirements. 

* * * * * 

(b) * * * 

(3) Maximum rated heat input 

capacity of the unit, in mmBtu/hr. 

* * * * * 

(11) If applicable, the plant code (as 

defined in § 98.6). 

(c) * * * 

(1) * * * 

(xi) If applicable, the plant code (as 

defined in § 98.6). 

(2) * * * 

(x) Reserved. 

(xi) If applicable, the plant code (as 

defined in § 98.6). 

(3) * * * As a second example, in 

accordance with § 98.33(b)(1)(v), Tier 1 

may be used regardless of unit size 

when natural gas is transported through 

the common pipe, if the annual fuel 

consumption is obtained from gas 

billing records in units of therms or 

mmBtu. * * * 

* * * * * 

(x) If applicable, the plant code (as 

defined in § 98.6). 

* * * * * 

(d) * * * 

(1) * * * 

(x) If applicable, the plant code (as 

defined in § 98.6). 

(2) * * * 

(ii) * * * 

(J) If applicable, the plant code (as 

defined in § 98.6). 

(iii) * * * 

(J) If applicable, the plant code (as 

defined in § 98.6). 

* * * * * 

■ 10. Table C–1 to Subpart C is revised 

to read as follows: 

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

Fuel type Default high 

heat value 

Default CO2

emission 

factor 

Coal and coke mmBtu/short 

ton 

kg CO2/ 

mmBtu 

Anthracite ................................................................................................................................................................. 25.09 ................ 103.69 

Bituminous ............................................................................................................................................................... 24.93 ................ 93.28 

Subbituminous ......................................................................................................................................................... 17.25 ................ 97.17 

Lignite ....................................................................................................................................................................... 14.21 ................ 97.72 

Coal Coke ................................................................................................................................................................ 24.80 ................ 113.67 

Mixed (Commercial sector) ...................................................................................................................................... 21.39 ................ 94.27 

Mixed (Industrial coking) .......................................................................................................................................... 26.28 ................ 93.90 

Mixed (Industrial sector) ........................................................................................................................................... 22.35 ................ 94.67 

Mixed (Electric Power sector) .................................................................................................................................. 19.73 ................ 95.52 


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

Continued 

Fuel type Default high 

heat value 

Default CO2

emission 

factor 

Natural gas mmBtu/scf kg CO2/ 

mmBtu 

(Weighted U.S. Average) 1.026 × 10¥3 53.06 

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 

Used Oil ................................................................................................................................................................... 0.138 ................ 74.00 

Kerosene .................................................................................................................................................................. 0.135 ................ 75.20 

Liquefied petroleum gases (LPG) 1 .......................................................................................................................... 0.092 ................ 61.71 

Propane 1 .................................................................................................................................................................. 0.091 ................ 62.87 

Propylene 2 ............................................................................................................................................................... 0.091 ................ 67.77 

Ethane 1 .................................................................................................................................................................... 0.068 ................ 59.60 

Ethanol ..................................................................................................................................................................... 0.084 ................ 68.44 

Ethylene 2 ................................................................................................................................................................. 0.058 ................ 65.96 

Isobutane 1 ............................................................................................................................................................... 0.099 ................ 64.94 

Isobutylene 1 ............................................................................................................................................................. 0.103 ................ 68.86 

Butane 1 .................................................................................................................................................................... 0.103 ................ 64.77 

Butylene 1 ................................................................................................................................................................. 0.105 ................ 68.72 

Naphtha (<401 deg F) ............................................................................................................................................. 0.125 ................ 68.02 

Natural Gasoline ...................................................................................................................................................... 0.110 ................ 66.88 

Other Oil (>401 deg F) ............................................................................................................................................ 0.139 ................ 76.22 

Pentanes Plus .......................................................................................................................................................... 0.110 ................ 70.02 

Petrochemical Feedstocks ....................................................................................................................................... 0.125 ................ 71.02 

Petroleum Coke ....................................................................................................................................................... 0.143 ................ 102.41 

Special Naphtha ....................................................................................................................................................... 0.125 ................ 72.34 

Unfinished Oils ......................................................................................................................................................... 0.139 ................ 74.54 

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 ................ 74.54 

Other fuels—solid mmBtu/short 

ton 

kg CO2/ 

mmBtu 

Municipal Solid Waste .............................................................................................................................................. 9.95 3 ............... 90.7 

Tires ......................................................................................................................................................................... 28.00 ................ 85.97 

Plastics ..................................................................................................................................................................... 38.00 ................ 75.00 

Petroleum Coke ....................................................................................................................................................... 30.00 ................ 102.41 

Other 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 

Propane Gas ............................................................................................................................................................ 2.516 × 10¥3 ... 61.46 

Fuel Gas 4 ................................................................................................................................................................ 1.388 × 10¥3 ... 59.00 

Biomass fuels—solid mmBtu/short 

ton 

kg CO2/ 

mmBtu 

Wood and Wood Residuals (dry basis) 5 ................................................................................................................. 17.48 ................ 93.80 

Agricultural Byproducts ............................................................................................................................................ 8.25 .................. 118.17 

Peat .......................................................................................................................................................................... 8.00 .................. 111.84 

Solid Byproducts ...................................................................................................................................................... 10.39 ................ 105.51 


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71952 Federal Register / Vol. 78, No. 230 / Friday, November 29, 2013 / Rules and Regulations 

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

Continued 

Fuel type Default high 

heat value 

Default CO2

emission 

factor 

Biomass fuels—gaseous mmBtu/scf kg CO2/ 

mmBtu 

Landfill Gas .............................................................................................................................................................. 0.485 × 10¥3 ... 52.07 

Other Biomass Gases .............................................................................................................................................. 0.655 × 10¥3 ... 52.07 

Biomass Fuels—Liquid mmBtu/gallon kg CO2/ 

mmBtu 

Ethanol ..................................................................................................................................................................... 0.084 ................ 68.44 

Biodiesel (100%) ...................................................................................................................................................... 0.128 ................ 73.84 

Rendered Animal Fat ............................................................................................................................................... 0.125 ................ 71.06 

Vegetable Oil ........................................................................................................................................................... 0.120 ................ 81.55 

1The HHV for components of LPG determined at 60 °F and saturation pressure with the exception of ethylene. 2Ethylene HHV determined at 41 °F (5 °C) and saturation pressure. 3 Use of this default HHV is allowed only for: (a) Units that combust MSW, do not generate steam, and are allowed to use Tier 1; (b) units that 

derive no more than 10 percent of their annual heat input from MSW and/or tires; and (c) small batch incinerators that combust no more than 

1,000 tons of MSW per year. 4 Reporters subject to subpart X of this part that are complying with § 98.243(d) or subpart Y of this part may only use the default HHV and the 

default CO2 emission factor for fuel gas combustion under the conditions prescribed in § 98.243(d)(2)(i) and (d)(2)(ii) and § 98.252(a)(1) and 

(a)(2), respectively. Otherwise, reporters subject to subpart X or subpart Y shall use either Tier 3 (Equation C–5) or Tier 4. 5 Use the following formula to calculate a wet basis HHV for use in Equation C–1: HHVw = ((100 ¥ M)/100)*HHVd where HHVw = wet basis 

HHV, M = moisture content (percent) and HHVd = dry basis HHV from Table C–1. 

■ 11. Table C–2 to Subpart C is revised 

to read as follows: 

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¥02 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

Fuel Gas ....................................................................................................................................................................... 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, except wood and wood residuals) ............................................. 3.2 × 10¥02 4.2 × 10¥03

Wood and wood residuals ............................................................................................................................................ 7.2 × 10¥03 3.6 × 10¥03

Biomass Fuels—Gaseous (All fuel types in Table C–1) .............................................................................................. 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. 

Subpart E—[AMENDED] 

■ 12. Section 98.53 is amended by: 

■ a. Revising paragraph (b)(3) and 

paragraph (d) introductory text. 

■ b. Revising paragraph (e) and 

Equation E–2 in paragraph (e). 

■ c. Revising the parameters ‘‘DF’’ and 

‘‘AF’’ of Equation E–3a in paragraph 

(g)(1). 

■ d. Revising the parameters ‘‘DF1’’, 

‘‘AF1’’, ‘‘DF2’’, ‘‘AF2’’, ‘‘DFN’’, and 

‘‘AFN’’ of Equation E–3b in paragraph 

(g)(2). 

■ e. Revising the parameters ‘‘DFN’’, 

‘‘AFN’’, and ‘‘FCN’’ of Equation E–3c in 

paragraph (g)(3). 

The revisions read as follows: 

§ 98.53 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(3) You must measure the adipic acid 

production rate during the test and 

calculate the production rate for the test 

period in tons per hour. 

* * * * * 

(d) If the adipic acid production unit 

exhausts to any N2O abatement 

technology ‘‘N’’, you must determine 

the destruction efficiency according to 

paragraphs (d)(1), (d)(2), or (d)(3) of this 

section. 

* * * * * 

(e) If the adipic acid production unit 

exhausts to any N2O abatement 

technology ‘‘N’’, you must determine 

the annual amount of adipic acid 

produced while N2O abatement 

technology ‘‘N’’ is operating according 

to § 98.54(f). Then you must calculate 

the abatement factor for N2O abatement 

technology ‘‘N’’ according to Equation 

E–2 of this section. 


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* * * * * 

(g) * * * 

(1) * * * 

* * * * * 

DF = Destruction efficiency of N2O abatement 

technology ‘‘N’’ (decimal fraction of N2O 

removed from vent stream). 

AF = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of time that the abatement 

technology is operating). 

* * * * * 

(2) * * * 

* * * * * 

DF1 = Destruction efficiency of N2O 

abatement technology 1 (decimal fraction 

of N2O removed from vent stream). 

AF1 = Abatement utilization factor of N2O 

abatement technology 1 (decimal fraction 

of time that abatement technology 1 is 

operating). 

DF2 = Destruction efficiency of N2O 

abatement technology 2 (decimal fraction 

of N2O removed from vent stream). 

AF2 = Abatement utilization factor of N2O 

abatement technology 2 (decimal fraction 

of time that abatement technology 2 is 

operating). 

DFN = Destruction efficiency of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of time that abatement 

technology N is operating). 

* * * * * 

(3) * * * 

* * * * * 

DFN = Destruction efficiency of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of time that the abatement 

technology is operating). 

FCN = Fraction control factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of total emissions from unit ‘‘z’’ 

that are sent to abatement technology 

‘‘N’’). 

* * * * * 

■ 13. Section 98.54 is amended by 

revising paragraphs (e) and (f) to read as 

follows: 

§ 98.54 Monitoring and QA/QC 

requirements. 

* * * * * 

(e) You must determine the monthly 

amount of adipic acid produced. You 

must also determine the monthly 

amount of adipic acid produced during 

which N2O abatement technology is 

operating. These monthly amounts are 

determined according to the methods in 

paragraphs (c)(1) or (c)(2) of this section. 

(f) You must determine the annual 

amount of adipic acid produced. You 

must also determine the annual amount 

of adipic acid produced during which 

N2O abatement technology is operating. 

These are determined by summing the 

respective monthly adipic acid 

production quantities determined in 

paragraph (e) of this section. 

Subpart G—[AMENDED] 

■ 14. Section 98.73 is amended by: 

■ a. Revising paragraph (b)(4) 

introductory text and revising Equation 

G–4. 

■ b. Revising Equation G–5 and by 

removing parameter ‘‘n’’ of Equation G– 

5 and adding in its place parameter ‘‘j’’. 

■ c. Revising the parameter ‘‘ECO2k’’ of 

Equation G–5 in paragraph (b)(5). 

The revisions read as follows: 

§ 98.73 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(4) You must calculate the annual 

process CO2 emissions from each 

ammonia processing unit k at your 

facility according to Equation G–4 of 

this section: 

* * * * * (5) * * * 

* * * * * 

ECO2k = Annual CO2 emissions from each 

ammonia processing unit k (metric tons). 

* * * * * 

j = Total number of ammonia processing 

units. 

* * * * * 

■ 15. Section 98.75 is amended by 

revising paragraph (b) to read as follows: 

§ 98.75 Procedures for estimating missing 

data. 

* * * * * 

(b) For missing feedstock supply rates 

used to determine monthly feedstock 

consumption, you must determine the 

best available estimate(s) of the 

parameter(s), based on all available 

process data. 

■ 16. Section 98.76 is amended by 

revising paragraphs (a) introductory 

text, (b) introductory text, and (b)(13) to 

read as follows: 

§ 98.76 Data reporting requirements. 

* * * * * 

(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 information in 

paragraphs (a)(1) and (2) of this section: 

* * * * * 

(b) If a CEMS is not used to measure 

emissions, then you must report all of 

the following information in this 

paragraph (b): 

* * * * * 

(13) Annual CO2 emissions (metric 

tons) from the steam reforming of a 

hydrocarbon or the gasification of solid 

and liquid raw material at the ammonia 

manufacturing process unit used to 

produce urea and the method used to 

determine the CO2 consumed in urea 

production. 

Subpart H—[AMENDED] 

■ 17. Section 98.86 is amended by 

revising paragraph (a)(2) to read as 

follows: 


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71954 Federal Register / Vol. 78, No. 230 / Friday, November 29, 2013 / Rules and Regulations 

§ 98.86 Data reporting requirements. 

* * * * * 

(a) * * * 

(2) Annual facility cement 

production. 

* * * * * 

Subpart I—[AMENDED] 

■ 18. Section 98.96 is amended by 

revising paragraph (y)(3)(i) to read as 

follows: 

§ 98.96 Data reporting requirements. 

* * * * * 

(y) * * * 

(3) * * * 

(i) The testing of tools to determine 

the potential effect on current 

utilization and by-product formation 

rates and destruction or removal 

efficiency values under the new 

conditions. 

* * * * * 

Subpart K—[AMENDED] 

■ 19. Section 98.113 is amended by 

revising Equation K–3 and by removing 

the parameter ‘‘2000/2205’’ of Equation 

K–3 and adding in its place the 

parameter ‘‘2/2205’’ to read as follows: 

§ 98.113 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(1) * * * 

* * * * * 

2/2205 = Conversion factor to convert kg 

CH4/ton of product to metric tons CH4. 

* * * * * 

■ 20. Section 98.116 is amended by 

adding paragraph (e)(2) to read as 

follows: 

§ 98.116 Data reporting requirements. 

* * * * * 

(e) * * * 

(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. 

* * * * * 

Subpart L—[AMENDED] 

■ 21. Section 98.126 is amended by 

revising paragraphs (j) introductory text, 

(j)(1), and (j)(3)(i) to read as follows: 

§ 98.126 Data reporting requirements. 

* * * * * 

(j) Special provisions for reporting 

years 2011, 2012, and 2013 only. For 

reporting years 2011, 2012, and 2013, 

the owner or operator of a facility must 

comply with paragraphs (j)(1), (j)(2), and 

(j)(3) of this section. 

(1) Timing. The owner or operator of 

a facility is not required to report the 

data elements at § 98.3(c)(4)(iii) and 

paragraphs (a)(2), (a)(3), (a)(4), (a)(6), (b), 

(c), (d), (e), (f), (g), and (h) of this section 

until the later of March 31, 2015 or the 

date set forth for that data element at 

§ 98.3(c)(4)(vii) and Table A–7 of 

Subpart A of this part. 

* * * * * 

(3) * * * 

(i) If you choose to use a default GWP 

rather than your best estimate of the 

GWP for fluorinated GHGs whose GWPs 

are not listed in Table A–1 of Subpart 

A of this part, use a default GWP of 

10,000 for fluorinated GHGs that are 

fully fluorinated GHGs and use a default 

GWP of 2000 for other fluorinated 

GHGs. 

* * * * * 

Subpart N—[AMENDED] 

■ 22. Section 98.143 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraph (b) introductory 

text. 

■ c. Revising the parameters ‘‘MFi’’ and 

‘‘Fi’’ of Equation N–1 in paragraph 

(b)(2)(iv). 

The revisions read as follows: 

§ 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) through 

(c) of this section. 

* * * * * 

(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 paragraph 

(b)(2) of this section, except as specified 

in paragraph (c) of this section. 

* * * * * 

(2) * * * 

(iv) * * * 

* * * * * 

MFi = Annual average decimal mass fraction 

of carbonate-based mineral i in 

carbonate-based raw material i. 

* * * * * 

Fi = Decimal fraction of calcination achieved 

for carbonate-based raw material i, 

assumed to be equal to 1.0. 

* * * * * 

■ 23. Section 98.144 is amended by 

revising paragraph (b) to read as follows: 

§ 98.144 Monitoring and QA/QC 

requirements. 

* * * * * 

(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 using consensus standards that 

specify X-ray fluorescence. For 

measurements made in years prior to 

the emissions reporting year 2014, you 

may also use 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) or ASTM D6349– 

09 Standard Test Method for 

Determination of Major and Minor 

Elements in Coal, Coke, and Solid 

Residues from Combustion of Coal and 

Coke by Inductively Coupled Plasma— 

Atomic Emission Spectrometry 

(incorporated by reference, see § 98.7). 

* * * * * 

■ 24. Section 98.146 is amended by 

revising paragraphs (b)(4), (6), and (7) to 

read as follows: 

§ 98.146 Data reporting requirements. 

* * * * * 

(b) * * * 

(4) Carbonate-based mineral decimal 

mass fraction for each carbonate-based 

raw material charged to a continuous 

glass melting furnace. 

* * * * * 

(6) The decimal 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 decimal 

fraction of calcination. 

* * * * * 

■ 25. Section 98.147 is amended by 

revising paragraph (b)(5) to read as 

follows: 

§ 98.147 Records that must be retained. 

* * * * * 


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(b) * * * 

(5) The decimal 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. 

* * * * * 

Subpart O—[AMENDED] 

■ 26. Section 98.153 is amended by: 

■ a. Revising paragraph (c) introductory 

text. 

■ b. Revising paragraph (d) introductory 

text. 

■ c. Revising the parameter ‘‘ED’’ of 

Equation O–5 in paragraph (d). 

The revisions read as follows: 

§ 98.153 Calculating GHG emissions. 

* * * * * 

(c) For HCFC–22 production facilities 

that do not use a destruction device or 

that have a destruction device that is not 

directly connected to the HCFC–22 

production equipment, HFC–23 

emissions shall be estimated using 

Equation O–4 of this section: 

* * * * * 

(d) For HCFC–22 production facilities 

that use a destruction device connected 

to the HCFC–22 production equipment, 

HFC–23 emissions shall be estimated 

using Equation O–5 of this section: 

* * * * * 

ED = Mass of HFC–23 emitted annually from 

destruction device (metric tons), 

calculated using Equation O–8 of this 

section. 

* * * * * 

■ 27. Section 98.154 is amended by 

revising paragraph (j) to read as follows: 

§ 98.154 Monitoring and QA/QC 

requirements. 

* * * * * 

(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 (i) 

of this section. 

* * * * * 

■ 28. Section 98.156 is amended by 

revising paragraph (c) to read as follows: 

§ 98.156 Data reporting requirements. 

* * * * * 

(c) Each HFC–23 destruction facility 

shall report the concentration (mass 

fraction) of HFC–23 measured at the 

outlet of the destruction device during 

the facility’s annual HFC–23 

concentration measurements at the 

outlet of the device. If the concentration 

of HFC–23 is below the detection limit 

of the measuring device, report the 

detection limit and that the 

concentration is below the detection 

limit. 

* * * * * 

Subpart P—[AMENDED] 

■ 29. Section 98.163 is amended by: 

■ a. Revising paragraph (b) introductory 

text. 

■ b. Revising the parameters ‘‘Fdstkn’’, 

‘‘CCn’’, and ‘‘MWn’’ of Equation P–1 in 

paragraph (b)(1). 

■ c. Revising the parameters ‘‘Fdstkn’’ 

and ‘‘CCn’’ of Equation P–2 in paragraph 

(b)(2). 

■ d. Revising the parameters ‘‘Fdstkn’’ 

and ‘‘CCn’’ of Equation P–3 in paragraph 

(b)(3). 

The revisions read as follows: 

§ 98.163 Calculating GHG emissions. 

* * * * * 

(b) Fuel and feedstock material 

balance approach. Calculate and report 

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 

(3) of this section. The carbon content 

and molecular weight shall be obtained 

from the analyses conducted in 

accordance with § 98.164(b)(2), (b)(3), or 

(b)(4), as applicable, or from the missing 

data procedures in § 98.165. If the 

analyses are performed annually, then 

the annual value shall be used as the 

monthly average. If the analyses are 

performed more frequently than 

monthly, use the arithmetic average of 

values obtained during the month as the 

monthly average. 

(1) * * * 

* * * * * 

Fdstkn = Volume or mass of the gaseous fuel 

or feedstock used in month n (scf (at 

standard conditions of 68 °F and 

atmospheric pressure) or kg of fuel or 

feedstock). 

CCn = Average carbon content of the gaseous 

fuel or feedstock for month n (kg carbon 

per kg of fuel or feedstock). 

MWn = Average molecular weight of the 

gaseous fuel or feedstock for month n 

(kg/kg-mole). If you measure mass, the 

term ‘‘MWn/MVC’’ is replaced with ‘‘1’’. 

* * * * * 

(2) * * * 

* * * * * 

Fdstkn = Volume or mass of the liquid fuel 

or feedstock used in month n (gallons or 

kg of fuel or feedstock). 

CCn = Average carbon content of the liquid 

fuel or feedstock, for month n (kg carbon 

per gallon or kg of fuel or feedstock). 

* * * * * 

(3) * * * 

* * * * * 

Fdstkn = Mass of solid fuel or feedstock used 

in month n (kg of fuel or feedstock). 

CCn = Average carbon content of the solid 

fuel or feedstock, for month n (kg carbon 

per kg of fuel or feedstock). 

* * * * * 

■ 30. Section 98.164 is amended by: 

■ a. Revising paragraphs (b)(3), (b)(4), 

and (b)(5) introductory text. 

■ b. Removing paragraphs (c) and (d). 

The revisions read as follows: 

§ 98.164 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(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 and feedstocks 

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 and feedstocks 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. 

Alternatively, you may use the results of 

chromatographic analysis of the fuel 

and feedstock, provided that the 

chromatograph is operated, maintained, 

and calibrated according to the 

manufacturer’s instructions; and the 

methods used for operation, 

maintenance, and calibration of the 

chromatograph are documented in the 

written monitoring plan for the unit 

under § 98.3(g)(5). 

* * * * * 

■ 31. Section 98.166 is amended by 

revising paragraphs (a)(2), (a)(3), (b)(2), 

and (b)(5) to read as follows: 

§ 98.166 Data reporting requirements. 

* * * * * 

(a) * * * 

(2) Annual quantity of hydrogen 

produced (metric tons) for each process 

unit. 

(3) Annual quantity of ammonia 

produced (metric tons), if applicable, for 

each process unit. 

(b) * * * 

(2) Monthly consumption of each fuel 

and feedstock used for hydrogen 

production and its type (scf or kg of 

gaseous fuels and feedstocks, gallons or 


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kg of liquid fuels and feedstocks, kg of 

solid fuels and feedstocks). 

* * * * * 

(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 or kg of liquid fuels 

and feedstocks). 

* * * * * 

■ 32. Section 98.167 is amended by 

adding paragraphs (c) and (d) to read as 

follows: 

§ 98.167 Records that must be retained. 

* * * * * 

(c) For units using the calculation 

methodologies described in § 98.163(b), 

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 § 98.163(b), 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. 

Subpart Q—[AMENDED] 

■ 33. Section 98.170 is amended by 

revising the first sentence to read as 

follows: 

§ 98.170 Definition of the source category. 

The iron and steel production source 

category includes facilities with any of 

the following processes: taconite iron 

ore processing, integrated iron and steel 

manufacturing, cokemaking not 

collocated with an integrated iron and 

steel manufacturing process, direct 

reduction furnaces not collocated with 

an integrated iron and steel 

manufacturing process, and electric arc 

furnace (EAF) steelmaking not 

collocated with an integrated iron and 

steel manufacturing process. * * * 

■ 34. Section 98.173 is amended by: 

■ a. Revising the parameters ‘‘(Fs)’’, 

‘‘(Csf)’’, ‘‘(Fg)’’, ‘‘(Fl)’’, ‘‘(C0)’’, ‘‘(Cp)’’, and 

‘‘(CR)’’ of Equation Q–1 in paragraph 

(b)(1)(i). 

■ b. Revising the parameters ‘‘(CIron)’’, 

‘‘(CScrap)’’, ‘‘(CFlux)’’, ‘‘(CCarbon)’’, 

‘‘(CSteel)’’, ‘‘(CSlag)’’, and ‘‘(CR)’’ of 

Equation Q–2 in paragraph (b)(1)(ii). 

■ c. Revising the parameters ‘‘(CCoal)’’, 

‘‘(CCoke)’’, and ‘‘(CR)’’ of Equation Q–3 in 

paragraph (b)(1)(iii). 

■ d. Revising the parameters ‘‘(Fg)’’, 

‘‘(CFeed)’’, ‘‘(CSinter)’’, and ‘‘(CR)’’ of 

Equation Q–4 in paragraph (b)(1)(iv). 

■ e. Revising Equation Q–5 and the 

definitions in Equation Q–5 in 

paragraph (b)(1)(v). 

■ f. Revising Equation Q–6 and revising 

the parameters ‘‘(CSteelin)’’, ‘‘(CSteelout)’’, 

and ‘‘(CR)’’ of Equation Q–6 in 

paragraph (b)(1)(vi). 

■ g. Revising the parameters ‘‘(Fg)’’, 

‘‘(COre)’’, ‘‘(CCarbon)’’, ‘‘(COther)’’, ‘‘(CIron)’’, 

‘‘(CNM)’’, and ‘‘(CR)’’ of Equation Q–7 in 

paragraph (b)(1)(vii). 

■ h. Revising paragraphs (c) and (d). 

The revisions read as follows: 

§ 98.173 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(i) * * * 

* * * * * 

(Fs) = Annual mass of the solid fuel used 

(metric tons). 

(Csf) = Carbon content of the solid fuel, from 

the fuel analysis (expressed as a decimal 

fraction). 

(Fg) = Annual volume of the gaseous fuel 

used (scf). 

* * * * * 

(Fl) = Annual volume of the liquid fuel used 

(gallons). 

* * * * * 

(C0) = Carbon content of the greenball 

(taconite) pellets, from the carbon 

analysis results (expressed as a decimal 

fraction). 

* * * * * 

(Cp) = Carbon content of the fired pellets, 

from the carbon analysis results 

(expressed as a decimal fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

(ii) * * * 

* * * * * 

(CIron) = Carbon content of the molten iron, 

from the carbon analysis results 

(expressed as a decimal fraction). 

* * * * * 

(CScrap) = Carbon content of the ferrous scrap, 

from the carbon analysis results 

(expressed as a decimal fraction). 

* * * * * 

(CFlux) = Carbon content of the flux materials, 

from the carbon analysis results 

(expressed as a decimal fraction). 

* * * * * 

(CCarbon) = Carbon content of the 

carbonaceous materials, from the carbon 

analysis results (expressed as a decimal 

fraction). 

* * * * * 

(CSteel) = Carbon content of the steel, from the 

carbon analysis results (expressed as a 

decimal fraction). 

* * * * * 

(CSlag) = Carbon content of the slag, from the 

carbon analysis (expressed as a decimal 

fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

(iii) * * * 

* * * * * 

(CCoal) = Carbon content of the coal, from the 

carbon analysis results (expressed as a 

decimal fraction). 

* * * * * 

(CCoke) = Carbon content of the coke, from the 

carbon analysis results (expressed as a 

decimal fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

(iv) * * * 

* * * * * 

(Fg) = Annual volume of the gaseous fuel 

used (scf). 

* * * * * 

(CFeed) = Carbon content of the mixed sinter 

feed materials that form the bed entering 

the sintering machine, from the carbon 

analysis results (expressed as a decimal 

fraction). 

* * * * * 

(CSinter) = Carbon content of the sinter pellets, 

from the carbon analysis results 

(expressed as a decimal fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

(v) For EAFs, estimate CO2 emissions 

using Equation Q–5 of this section. 


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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 

(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 

(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 

(expressed as a decimal fraction). 

(Electrode) = Annual mass of carbon 

electrode consumed (metric tons). 

(CElectrode) = Carbon content of the carbon 

electrode, from the carbon analysis 

results (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 (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 (expressed as a 

decimal fraction). 

(Fg) = Annual volume of the gaseous fuel 

used (scf at 60 degrees F and one 

atmosphere). 

(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 

(836.6 scf per kg-mole at standard 

conditions of 60 degrees F and one 

atmosphere). 

(0.001) = Conversion factor from kg to metric 

tons. 

(Slag) = Annual mass of slag produced by the 

furnace (metric tons). 

(CSlag) = Carbon content of the slag, from the 

carbon analysis results (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 (expressed as a decimal fraction). 

(vi) * * * 

* * * * * 

(CSteelin) = Carbon content of the molten steel 

before decarburization, from the carbon 

analysis results (expressed as a decimal 

fraction). 

(CSteelout) = Carbon content of the molten steel 

after decarburization, from the carbon 

analysis results (expressed as a decimal 

fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

(vii) * * * 

* * * * * 

(Fg) = Annual volume of the gaseous fuel 

used (scf). 

* * * * * 

(COre) = Carbon content of the iron ore or iron 

ore pellets, from the carbon analysis 

results (expressed as a decimal fraction). 

* * * * * 

(CCarbon) = Carbon content of the 

carbonaceous materials, from the carbon 

analysis results (expressed as a decimal 

fraction). 

* * * * * 

(COther) = Average carbon content of the other 

materials charged to the furnace, from 

the carbon analysis results (expressed as 

a decimal fraction). 

* * * * * 

(CIron) = Carbon content of the iron, from the 

carbon analysis results (expressed as a 

decimal fraction). 

* * * * * 

(CNM) = Carbon content of the non-metallic 

materials, from the carbon analysis 

results (expressed as a decimal fraction). 

* * * * * 

(CR) = Carbon content of the air pollution 

control residue, from the carbon analysis 

results (expressed as a decimal fraction). 

* * * * * 

(c) You must determine emissions of 

CO2 from the coke pushing process in 

mtCO2e by multiplying the metric tons 

of coal charged to the by-product 

recovery and non-recovery 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, decarburization 

vessel, or direct reduction furnace are 

vented through a stack equipped with a 

CEMS that complies with the Tier 4 

methodology in subpart C of this part, 

or 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 

comply with all associated requirements 

for Tier 4 in subpart C of this part 

(General Stationary Fuel Combustion 

Sources). 

■ 35. Section 98.174 is amended by 

adding a sentence to the end of 

paragraph (b)(1) and revising paragraph 

(c)(2) to read as follows: 

§ 98.174 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(1) * * * No determination of the 

mass of steel output from 

decarburization vessels is required. 

* * * * * 

(c) * * * 

(2)(i) For the exhaust from basic 

oxygen furnaces, EAFs, 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 


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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. 

(ii) For the exhaust from continuously 

charged EAFs, sample the exhaust for a 

period spanning at least three hours. 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. 

* * * * * 

■ 36. Section 98.175 is amended by 

revising paragraph (a) to read as follows: 

§ 98.175 Procedures for estimating 

missing data. 

* * * * * 

(a) Except as provided in 

§ 98.174(b)(4), 100 percent data 

availability is required 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 facilities that estimate 

emissions using the site-specific 

emission factor procedure in 

§ 98.173(b)(2). 

* * * * * 

■ 37. Section 98.176 is amended by 

revising paragraph (e) introductory text 

to read as follows: 

§ 98.176 Data reporting requirements. 

* * * * * 

(e) If you use the carbon mass balance 

method in § 98.173(b)(1) to determine 

CO2 emissions, you must, except as 

provided in § 98.174(b)(4), report the 

following information for each process: 

* * * * * 

■ 38. Section 98.177 is amended by 

revising paragraph (b) to read as follows: 

§ 98.177 Records that must be retained. 

* * * * * 

(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, except 

that no determination of the mass of 

steel output from decarburization 

vessels is required. 

* * * * * 

Subpart S—[AMENDED] 

■ 39. Section 98.190 is amended by 

revising paragraph (a) to read as follows: 

§ 98.190 Definition of the source category. 

(a) Lime manufacturing plants (LMPs) 

engage in the manufacture of a lime 

product by calcination of limestone, 

dolomite, shells or other calcareous 

substances as defined in 40 CFR 

63.7081(a)(1). 

* * * * * 

■ 40. Section 98.193 is amended by: 

■ a. Revising paragraph (a). 

■ b. Revising paragraph (b)(1). 

■ c. Revising paragraph (b)(2) 

introductory text. 

■ d. Revising paragraph (b)(2)(ii) 

introductory text. 

■ e. Revising the parameters ‘‘EFLKD,i,n’’, 

‘‘CaOLKD,i,n’’ and ‘‘MgOLKD,i,n’’ of 

Equation S–2 in paragraph (b)(2)(ii). 

■ f. Revising paragraph (b)(2)(iii) 

introductory text. 

■ g. Revising the parameters ‘‘Ewaste,i’’, 

‘‘CaOwaste,i’’, ‘‘MgOwaste,i’’, and ‘‘Mwaste,i’’ 

of Equation S–3 in paragraph (b)(2)(iii). 

■ h. Revising paragraph (b)(2)(iv) 

introductory text. 

■ i. Revising the parameters ‘‘ECO2’’, 

‘‘EFLKD,i,n’’, ‘‘MLKD,i,n’’, ‘‘Ewaste,i’’, ‘‘b’’ 

and ‘‘z’’ of Equation S–4 in paragraph 

(b)(2)(iv). 

The revisions read as follows: 

§ 98.193 Calculating GHG emissions. 

* * * * * 

(a) If all lime kilns meet 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 

from all lime kilns 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) * * * 

(1) Calculate and report under this 

subpart the combined process and 

combustion CO2 emissions from all lime 

kilns 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 from all lime 

kilns separately using the procedures 

specified in paragraphs (b)(2)(i) through 

(v) of this section. 

* * * * * 

(ii) You must calculate a monthly 

emission factor for each type of calcined 

byproduct or waste sold (including lime 

kiln dust) using Equation S–2 of this 

section: 

* * * * * 

EFLKD,i,n = Emission factor for calcined lime 

byproduct or waste type i sold, for 

month n (metric tons CO2/ton lime 

byproduct). 

CaOLKD,i,n = Calcium oxide content for 

calcined lime byproduct or waste type i 

sold, for month n (metric tons CaO/

metric ton lime). 

MgOLKD,i,n = Magnesium oxide content for 

calcined lime byproduct or waste type i 

sold, for month n (metric tons MgO/

metric ton lime). 

* * * * * 

(iii) You must calculate the annual 

CO2 emissions from each type of 

calcined byproduct or waste that is not 

sold (including lime kiln dust and 

scrubber sludge) using Equation S–3 of 

this section: 

* * * * * 

Ewaste,i = Annual CO2 emissions for calcined 

lime byproduct or waste type i that is not 

sold (metric tons CO2). 

* * * * * 

CaOwaste,i = Calcium oxide content for 

calcined lime byproduct or waste type i 

that is not sold (metric tons CaO/metric 

ton lime). 

MgOwaste,i = Magnesium oxide content for 

calcined lime byproduct or waste type i 

that is not sold (metric tons MgO/metric 

ton lime). 

Mwaste,i = Annual weight or mass of calcined 

byproducts or wastes for lime type i that 

is not sold (tons). 

* * * * * 

(iv) You must calculate annual CO2

process emissions for all lime kilns 

using Equation S–4 of this section: 

* * * * * 

ECO2 = Annual CO2 process emissions from 

lime production from all lime kilns 

(metric tons/year). 

* * * * * 

EFLKD,i,n = Emission factor of calcined 

byproducts or wastes sold for lime type 

i in calendar month n, (metric tons CO2/ 

ton byproduct or waste) from Equation 

S–2 of this section. 

MLKD,i,n = Monthly weight or mass of 

calcined byproducts or waste sold (such 

as lime kiln dust, LKD) for lime type i 

in calendar month n (tons). 

Ewaste,i = Annual CO2 emissions for calcined 

lime byproduct or waste type i that is not 

sold (metric tons CO2) from Equation S– 

3 of this section. 

* * * * * 

b = Number of calcined byproducts or wastes 

that are sold. 

z = Number of calcined byproducts or wastes 

that are not sold. 

* * * * * 

■ 41. Section 98.194 is amended by 

revising paragraphs (a), (b), and (c) 

introductory text to read as follows: 

§ 98.194 Monitoring and QA/QC 

requirements. 

(a) You must determine the total 

quantity of each type of lime product 

that is produced and each calcined 

byproduct or waste (such as lime kiln 

dust) that is sold. The quantities of each 

should be directly measured monthly 


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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 or 

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 or waste 

generation rate. 

(c) You must determine the chemical 

composition (percent total CaO and 

percent total MgO) of each type of lime 

product that is produced and each type 

of calcined byproduct or waste sold 

according to paragraph (c)(1) or (2) of 

this section. You must determine the 

chemical composition of each type of 

lime product that is produced and each 

type of calcined byproduct or waste sold 

on a monthly basis. You must determine 

the chemical composition for each type 

of calcined byproduct or waste that is 

not sold on an annual basis. 

* * * * * 

■ 42. Section 98.195 is amended by 

revising paragraph (a) to read as follows: 

§ 98.195 Procedures for estimating 

missing data. 

* * * * * 

(a) For each missing value of the 

quantity of lime produced (by lime 

type), and quantity of calcined 

byproduct or 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. 

* * * * * 

■ 43. Section 98.196 is amended by 

revising paragraphs (a)(1), (a)(2), (a)(4), 

(a)(5), (a)(7), (b)(1) through (6), (b)(9) 

through (11), and (b)(14) to read as 

follows: 

§ 98.196 Data reporting requirements. 

* * * * * 

(a) * * * 

(1) Method used to determine the 

quantity of lime that is produced and 

quantity of lime that is sold. 

(2) Method used to determine the 

quantity of calcined lime byproduct or 

waste sold. 

* * * * * 

(4) Beginning and end of year 

inventories for calcined lime byproducts 

or wastes sold, by type. 

(5) Annual amount of calcined lime 

byproduct or waste sold, by type (tons). 

* * * * * 

(7) Annual amount of calcined lime 

byproduct or waste that is not sold, by 

type (tons). 

* * * * * 

(b) * * * 

(1) Annual CO2 process emissions 

from all lime kilns combined (metric 

tons). 

(2) Monthly emission factors (metric 

ton CO2/ton lime product) for each lime 

product type produced. 

(3) Monthly emission factors for each 

calcined byproduct or waste by lime 

type that is sold. 

(4) Standard method used (ASTM or 

NLA testing method) to determine 

chemical compositions of each lime 

type produced and each calcined lime 

byproduct or waste type. 

(5) Monthly results of chemical 

composition analysis of each type of 

lime product produced and calcined 

byproduct or waste sold. 

(6) Annual results of chemical 

composition analysis of each type of 

lime byproduct or waste that is not sold. 

* * * * * 

(9) Method used to determine the 

quantity of calcined lime byproduct or 

waste sold. 

(10) Monthly amount of calcined lime 

byproduct or waste sold, by type (tons). 

(11) Annual amount of calcined lime 

byproduct or waste that is not sold, by 

type (tons). 

* * * * * 

(14) Beginning and end of year 

inventories for calcined lime byproducts 

or wastes sold. 

* * * * * 

Subpart V—[AMENDED] 

■ 44. Section 98.222 is amended by 

revising paragraph (a) to read as follows: 

§ 98.222 GHGs to report. 

(a) You must report N2O process 

emissions from each nitric acid train as 

required by this subpart. 

* * * * * 

■ 45. Section 98.223 is amended by: 

■ a. Revising paragraphs (b) 

introductory text, (b)(1), (b)(3), (d) 

introductory text, and (e) introductory 

text. 

■ b. Removing the parameter ‘‘Pa,N’’ of 

Equation V–2 in paragraph (e) and 

adding in its place the parameter ‘‘Pt,N’’. 

■ c. Revising parameters ‘‘EN2Ot’’, ‘‘Pt’’, 

‘‘DF’’, and ‘‘AF’’ of Equation V–3a in 

paragraph (g)(1). 

■ d. Revising paragraph (g)(2) 

introductory text. 

■ e. Revising parameters ‘‘EN2Ot’’, 

‘‘EFN2O,t’’, ‘‘Pt’’, ‘‘DF1’’, ‘‘AF1’’, ‘‘DF2’’, 

‘‘AF2’’, ‘‘DFN’’, and ‘‘AFN’’ of Equation 

V–3b in paragraph (g)(2). 

■ f. Revising paragraph (g)(3) 

introductory text. 

■ g. Revising parameters ‘‘EN2Ot’’, 

‘‘EFN2O,t’’, ‘‘Pt’’, ‘‘DFN’’, ‘‘AFN’’, and 

‘‘FCN’’ of Equation V–3c in paragraph 

(g)(3). 

■ h. Revising parameter ‘‘EN2Ot’’ of 

Equation V–3d in paragraph (g)(4). 

■ i. Revising paragraph (i). 

The revisions read as follows: 

§ 98.223 Calculating GHG emissions. 

* * * * * 

(b) You must conduct an annual 

performance test for each nitric acid 

train according to paragraphs (b)(1) 

through (3) of this section. 

(1) You must conduct the 

performance test at the absorber tail gas 

vent, referred to as the test point, for 

each nitric acid train according to 

§ 98.224(b) through (f). If multiple nitric 

acid trains exhaust to a common 

abatement technology and/or emission 

point, 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 multiple 

processes are operating and base the 

site-specific emission factor on the 

combined production rate of the 

multiple nitric acid trains. 

* * * * * 

(3) You must measure the production 

rate during the performance test and 

calculate the production rate for the test 

period in tons (100 percent acid basis) 

per hour. 

* * * * * 

(d) If nitric acid train ‘‘t’’ exhausts to 

any N2O abatement technology ‘‘N’’, you 

must determine the destruction 

efficiency for each N2O abatement 

technology ‘‘N’’ according to paragraphs 

(d)(1), (2), or (3) of this section. 

* * * * * 

(e) If nitric acid train ‘‘t’’ exhausts to 

any N2O abatement technology ‘‘N’’, you 

must determine the annual amount of 

nitric acid produced on nitric acid train 

‘‘t’’ while N2O abatement technology 

‘‘N’’ is operating according to 

§ 98.224(f). Then you must calculate the 

abatement utilization factor for each 

N2O abatement technology ‘‘N’’ for each 

nitric acid train ‘‘t’’ according to 

Equation V–2 of this section. 

* * * * * 

Pt,N = Annual nitric acid production from 

nitric acid train ‘‘t’’ during which N2O 

abatement technology ‘‘N’’ was 

operational (ton acid produced, 100 

percent acid basis). 

* * * * * 

(g) * * * 


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(1) * * * 

* * * * * 

EN2Ot = Annual N2O mass emissions from 

nitric acid train ‘‘t’’ according to this 

Equation V–3a (metric tons). 

* * * * * 

Pt = Annual nitric acid production from 

nitric acid train ‘‘t’’ (ton acid produced, 

100 percent acid basis). 

DF = Destruction efficiency of N2O abatement 

technology N that is used on nitric acid 

train ‘‘t’’ (decimal fraction of N2O 

removed from vent stream). 

AF = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ for nitric acid 

train ‘‘t’’ (decimal fraction of annual 

production during which abatement 

technology is operating). 

* * * * * 

(2) If multiple N2O abatement 

technologies are located in series after 

your test point, you must use the 

emissions factor (determined in 

Equation V–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

nitric acid production (determined in 

paragraph (i) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation V–3b of this 

section: 

* * * * * 

EN2Ot = Annual N2O mass emissions from 

nitric acid train ‘‘t’’ according to this 

Equation V–3b (metric tons). 

EFN2O,t = N2O emissions factor for nitric acid 

train ‘‘t’’ (lb N2O/ton nitric acid 

produced). 

Pt = Annual nitric acid produced from nitric 

acid train ‘‘t’’ (ton acid produced, 100 

percent acid basis). 

DF1 = Destruction efficiency of N2O 

abatement technology 1 (decimal fraction 

of N2O removed from vent stream). 

AF1 = Abatement utilization factor of N2O 

abatement technology 1 (decimal fraction 

of time that abatement technology 1 is 

operating). 

DF2 = Destruction efficiency of N2O 

abatement technology 2 (decimal fraction 

of N2O removed from vent stream). 

AF2 = Abatement utilization factor of N2O 

abatement technology 2 (decimal fraction 

of time that abatement technology 2 is 

operating). 

DFN = Destruction efficiency of N2O 

abatement technology N (decimal 

fraction of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O 

abatement technology N (decimal 

fraction of time that abatement 

technology N is operating). 

* * * * * 

(3) If multiple N2O abatement 

technologies are located in parallel after 

your test point, you must use the 

emissions factor (determined in 

Equation V–1 of this section), the 

destruction efficiency (determined in 

paragraph (d) of this section), the annual 

nitric acid production (determined in 

paragraph (i) of this section), and the 

abatement utilization factor (determined 

in paragraph (e) of this section), 

according to Equation V–3c of this 

section: 

* * * * * 

EN2Ot = Annual N2O mass emissions from 

nitric acid train ‘‘t’’ according to this 

Equation V–3c (metric tons). 

EFN2O,t = N2O emissions factor for nitric acid 

train ‘‘t’’ (lb N2O/ton nitric acid 

produced). 

Pt = Annual nitric acid produced from nitric 

acid train ‘‘t’’ (ton acid produced, 100 

percent acid basis). 

DFN = Destruction efficiency of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of N2O removed from vent 

stream). 

AFN = Abatement utilization factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of time that abatement 

technology ‘‘N’’ is operating). 

FCN = Fraction control factor of N2O 

abatement technology ‘‘N’’ (decimal 

fraction of total emissions from nitric 

acid train ‘‘t’’ that are sent to abatement 

technology ‘‘N’’). 

* * * * * 

(4) * * * 

* * * * * 

EN2Ot = Annual N2O mass emissions from 

nitric acid train ‘‘t’’ according to this 

Equation V–3d (metric tons). 

* * * * * 

(i) You must determine the total 

annual amount of nitric acid produced 

on each nitric acid train ‘‘t’’ (tons acid 

produced, 100 percent acid basis), 

according to § 98.224(f). 

■ 46. Section 98.224 is amended by 

revising paragraphs (c) introductory 

text, (e), and (f) to read as follows: 

§ 98.224 Monitoring and QA/QC 

requirements. 

* * * * * 

(c) You must determine the 

production rate(s) (100 percent acid 

basis) from each nitric acid train during 

the performance test according to 

paragraphs (c)(1) or (2) of this section. 

* * * * * 

(e) You must determine the total 

monthly amount of nitric acid 

produced. You must also determine the 

monthly amount of nitric acid produced 

while N2O abatement technology is 

operating from each nitric acid train. 

These monthly amounts are determined 

according to the methods in paragraphs 

(c)(1) or (2) of this section. 

(f) You must determine the annual 

amount of nitric acid produced. You 

must also determine the annual amount 

of nitric acid produced while N2O 

abatement technology is operating for 

each nitric acid train. These annual 

amounts are determined by summing 

the respective monthly nitric acid 

quantities determined in paragraph (e) 

of this section. 

■ 47. Section 98.226 is amended by: 

■ a. Revising paragraph (a). 

■ b. Adding reserved paragraph (o). 

■ c. Revising paragraph (p). 

The revisions and addition read as 

follows: 

§ 98.226 Data reporting requirements. 

* * * * * 

(a) Nitric Acid train identification 

number. 

* * * * * 

(p) Fraction control factor for each 

abatement technology (percent of total 

emissions from the nitric acid train that 

are sent to the abatement technology) if 

Equation V–3c is used. 

Subpart W—[Amended] 

■ 48. Section 98.233 is amended by: 

■ a. Revising parameter ‘‘Convi’’ of 

Equation W–1 in paragraph (a). 

■ b. Revising parameter ‘‘Convi’’ of 

Equation W–2 in paragraph (c). 

■ c. Revising parameter ‘‘GWP’’ of 

Equation W–36 in paragraph (v). 

The revisions read as follows: 

§ 98.233 Calculating GHG emissions. 

* * * * * 

(a) * * * 

Convi = Conversion from standard cubic feet 

to metric tons CO2e; 0.000479 for CH4, 

and 0.00005262 for CO2. 

* * * * * 

(c) * * * 

Convi = Conversion from standard cubic feet 

to metric tons CO2e; 0.000479 for CH4, 

and 0.00005262 for CO2. 

* * * * * 

(v) * * * 

GWP = Global warming potential, 1 for CO2,

25 for CH4, and 298 for N2O. 

* * * * * 

Subpart X—[AMENDED] 

■ 49. Section 98.242 is amended by 

revising paragraph (b)(2) to read as 

follows: 

§ 98.242 GHGs to report. 

* * * * * 

(b) * * * 

(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 for all fuels, except 


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emissions from burning petrochemical 

process off-gas in any combustion unit, 

including units that are not part of the 

petrochemical process unit, are not to be 

reported under subpart C of this part. 

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. 

* * * * * 

■ 50. Section 98.243 is amended by: 

■ a. Revising paragraph (b). 

■ b. Revising paragraphs (c)(3) and (4). 

■ c. Revising the equation terms ‘‘Cg’’, 

‘‘(Fgf)i,n’’, and ‘‘(Pgp)i,n’’ of Equation X–1 

in paragraph (c)(5)(i). 

■ d. Removing the equation term 

‘‘(MWf)I’’ of Equation X–1 and adding in 

its place the parameter ‘‘(MWf)i,n’’ and 

defining the new parameter in the 

equation terms. 

■ e. Removing the equation term 

‘‘(MWp)I’’ of Equation X–1 and adding in 

its place the parameter ‘‘(MWp)i,n’’ and 

defining the new parameter in the 

equation terms. 

■ f. Revising paragraph (d)(3)(i). 

The revisions read as follows: 

§ 98.243 Calculating GHG emissions. 

* * * * * 

(b) Continuous emission monitoring 

system (CEMS). Route all process vent 

emissions and emissions from stationary 

combustion units that burn any amount 

of process off-gas to one or more stacks 

and determine GHG emissions as 

specified in paragraphs (b)(1) through 

(3) of this section. 

(1) Determine CO2 emissions from 

each stack (except flare stacks) 

according to the Tier 4 Calculation 

Methodology requirements in subpart C 

of this part. 

(2) 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 Equation C–10 and the 

‘‘fuel gas’’ emission factors in Table C– 

2 of subpart C of this part). 

(3) For each flare, calculate CO2, CH4, 

and N2O emissions using the 

methodology specified in § 98.253(b)(1) 

through (3). 

(c) * * * 

(3) Collect a sample of each feedstock 

and product at least once per month and 

determine the carbon content of each 

sample according to the procedures of 

§ 98.244(b)(4). If multiple valid carbon 

content measurements are made during 

the monthly measurement period, 

average them arithmetically. However, if 

a particular liquid or solid feedstock is 

delivered in lots, and if multiple 

deliveries of the same feedstock are 

received from the same supply source in 

a given calendar month, only one 

representative sample is required. 

Alternatively, you may use the results of 

analyses conducted by a feedstock 

supplier, or product customer, provided 

the sampling and analysis is conducted 

at least once per month using any of the 

procedures specified in § 98.244(b)(4). 

(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, then as an alternative to the 

sampling and analysis specified in 

paragraph (c)(3) of this section, you may 

determine carbon content in accordance 

with paragraphs (c)(4)(i) through (iii) of 

this section. 

(i) Calculate the carbon content 

assuming 100 percent of that feedstock 

or product is the specific compound. 

(ii) Maintain records of any 

determination made in accordance with 

this paragraph (c)(4) along with all 

supporting data, calculations, and other 

information. 

(iii) Reevaluate determinations made 

under this paragraph (c)(4) after any 

process change that affects the feedstock 

or product composition. 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) * * * 

(i) * * * 

* * * * * 

Cg = Annual net contribution to calculated 

emissions from carbon (C) in gaseous 

materials, including streams containing 

CO2 recovered for sale or use in another 

process (kg/yr). 

(Fgf)i,n = Volume or mass of gaseous feedstock 

i introduced in month ‘‘n’’ (scf or kg). If 

you measure mass, the term (MWf)i,n/

MVC is replaced with ‘‘1’’. 

* * * * * 

(MWf)i,n = Molecular weight of gaseous 

feedstock i in month ‘‘n’’(kg/kg-mole). 

* * * * * 

(Pgp)i,n = Volume or mass of gaseous product 

i produced in month ‘‘n’’ (scf or kg). If 

you measure mass, the term (MWp)i,n/

MVC is replaced with ‘‘1’’. 

* * * * * 

(MWp)i,n = Molecular weight of gaseous 

product i in month ‘‘n’’ (kg/kg-mole). 

* * * * * 

(d) * * * 

(3) * * * 

(i) For all gaseous fuels that contain 

ethylene process off-gas, use the 

emission factors for ‘‘Fuel Gas’’ in Table 

C–2 of subpart C of this part (General 

Stationary Fuel Combustion Sources). 

* * * * * 

■ 51. Section 98.244 is amended by: 

■ a. Revising paragraph (b)(4) 

introductory text, and paragraphs 

(b)(4)(xiii), (b)(4)(xiv), and (b)(4)(xv)(A). 

■ b. Adding paragraph (c). 

The revisions and addition read as 

follows: 

§ 98.244 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) * * * 

(4) Beginning January 1, 2010, use any 

applicable methods specified in 

paragraphs (b)(4)(i) through (xv) of this 

section to determine the carbon content 

or composition of feedstocks and 

products and the average molecular 

weight of gaseous feedstocks and 

products. Calibrate instruments in 

accordance with paragraphs (b)(4)(i) 

through (xv) of this section, 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 (xv) of this 


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section may be performed by the owner 

or operator, by an independent 

laboratory, by the supplier of a 

feedstock, or by a product customer. 

* * * * * 

(xiii) The results of chromatographic 

analysis of a feedstock or product, 

provided that the chromatograph is 

operated, maintained, and calibrated 

according to the manufacturer’s 

instructions. 

(xiv) The results of mass spectrometer 

analysis of a feedstock or product, 

provided that the mass spectrometer is 

operated, maintained, and calibrated 

according to the manufacturer’s 

instructions. 

(xv) * * * 

(A) An industry standard practice or 

a method published by a consensusbased standards organization if such a 

method exists for carbon black feedstock 

oils and carbon black products. 

Consensus-based standards 

organizations include, but are not 

limited to, the following: ASTM 

International (100 Barr Harbor Drive, 

P.O. Box CB700, West Conshohocken, 

Pennsylvania 19428–B2959, (800) 262– 

1373, http://www.astm.org), the 

American National Standards Institute 

(ANSI, 1819 L Street, NW., 6th floor, 

Washington, DC 20036, (202) 293–8020, 

http://www.ansi.org), the American Gas 

Association (AGA, 400 North Capitol 

Street NW., 4th Floor, Washington, DC 

20001, (202) 824–7000, http://

www.aga.org), the American Society of 

Mechanical Engineers (ASME, Three 

Park Avenue, New York, NY 10016– 

5990, (800) 843–2763, http://

www.asme.org), the American 

Petroleum Institute (API, 1220 L Street 

NW., Washington, DC 20005–4070, 

(202) 682–8000, http://www.api.org), 

and the North American Energy 

Standards Board (NAESB, 801 Travis 

Street, Suite 1675, Houston, TX 77002, 

(713) 356–0060, http://www.naesb.org). 

The method(s) used shall be 

documented in the monitoring plan 

required under § 98.3(g)(5). 

* * * * * 

(c) If you comply with § 98.243(b) or 

(d), conduct monitoring and QA/QC for 

flares in accordance with § 98.254(b) 

through (e) for each flare gas flow meter, 

gas composition meter, and/or heating 

value monitor that you use to comply 

with § 98.253(b)(1) through (b)(3). You 

must implement all applicable QA/QC 

requirements specified in this paragraph 

(c) beginning no later than January 1, 

2015. 

■ 52. Section 98.245 is revised to read 

as follows: 

§ 98.245 Procedures for estimating 

missing data. 

For missing feedstock and product 

flow rates, use the same procedures as 

for missing fuel usage as specified in 

§ 98.35(b)(2). For missing feedstock and 

product carbon contents and missing 

molecular weights for gaseous 

feedstocks and products, use the same 

procedures as for missing carbon 

contents and missing molecular weights 

for fuels as specified in § 98.35(b)(1). 

For missing flare data, follow the 

procedures in § 98.255(b) and (c). 

■ 53. Section 98.246 is amended by: 

■ a. Revising paragraphs (a)(6), (a)(8), 

(a)(9), (a)(11) introductory text, 

(a)(11)(iii), and (b)(2) through (5). 

■ b. Removing and reserving paragraph 

(b)(6). 

■ c. Revising paragraph (c)(4). 

The revisions read as follows: 

§ 98.246 Data reporting requirements. 

* * * * * 

(a) * * * 

(6) For each feedstock and product, 

provide the information specified in 

paragraphs (a)(6)(i) through (a)(6)(iii) of 

this section. 

(i) Name of each method used to 

determine carbon content or molecular 

weight in accordance with 

§ 98.244(b)(4); 

(ii) Description of each type of device 

(e.g., flow meter, weighing device) used 

to determine flow or mass in accordance 

with § 98.244(b)(1) through (3). 

(iii) Identification of each method 

(i.e., method number, title, or other 

description) used to determine flow or 

mass in accordance with § 98.244(b)(1) 

through (3). 

* * * * * 

(8) Identification of each combustion 

unit that burned both process off-gas 

and supplemental fuel, including 

combustion units that are not part of the 

petrochemical process unit. 

(9) The number of days during which 

off-specification product was produced 

if the alternative to sampling and 

analysis specified in § 98.243(c)(4) is 

used for a product, and, if applicable, 

the date of any process change that 

reduced the monthly average 

composition to less than 99.5 percent 

for each product or feedstock for which 

you comply with the alternative to 

sampling and analysis specified in 

§ 98.243(c)(4). 

* * * * * 

(11) If you determine carbon content 

or composition of a feedstock or product 

using a method under 

§ 98.244(b)(4)(xv)(B), report the 

information listed in paragraphs 

(a)(11)(i) through (a)(11)(iii) of this 

section. Include the information in 

paragraph (a)(11)(i) of this section in 

each annual report. Include the 

information in paragraphs (a)(11)(ii) and 

(a)(11)(iii) of this section only in the 

first applicable annual report, and 

provide any changes to this information 

in subsequent annual reports. 

* * * * * 

(iii) An explanation of why an 

alternative to the methods listed in 

§§ 98.244(b)(4)(i) through (xiv) is 

needed. 

(b) * * * 

(2) For CEMS used on stacks that 

include emissions from stationary 

combustion units that burn any amount 

of off-gas from the petrochemical 

process, report the relevant information 

required under § 98.36(c)(2) and 

(e)(2)(vi) for the Tier 4 calculation 

methodology. Sections 98.36(c)(2)(ii) 

and (c)(2)(ix) do not apply for the 

purposes of this subpart. 

(3) For CEMS used on stacks that do 

not include emissions from stationary 

combustion units, report the 

information required under 

§ 98.36(b)(6), (b)(7), and (e)(2)(vi). 

(4) For each CEMS monitoring 

location that meets the conditions in 

paragraph (b)(2) or (3) of this section, 

provide an estimate based on 

engineering judgment of the fraction of 

the total CO2 emissions that results from 

CO2 directly emitted by the 

petrochemical process unit plus CO2

generated by the combustion of off-gas 

from the petrochemical process unit. 

(5) For each CEMS monitoring 

location that meets the conditions in 

paragraph (b)(2) of this section, report 

the CH4 and N2O emissions expressed in 

metric tons of each gas. For each CEMS 

monitoring location, provide an 

estimate based on engineering judgment 

of the fraction of the total CH4 and N2O 

emissions that is attributable to 

combustion of off-gas from the 

petrochemical process unit. 

* * * * * 

(c) * * * 

(4) Name and annual quantity of each 

feedstock (metric tons). 

* * * * * 

■ 54. Section 98.247 is amended by 

revising paragraphs (b) introductory 

text, (b)(2), and (b)(3) to read as follows: 

§ 98.247 Records that must be retained. 

* * * * * 

(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 (4) of this section. 

* * * * * 


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(2) Start and end times 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 product. 

(3) As 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. 

* * * * * 

■ 55. Section 98.248 is amended by 

revising the definition of ‘‘Product’’ to 

read as follows: 

§ 98.248 Definitions. 

* * * * * 

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 

combusted onsite. Product does not 

include process vent emissions, fugitive 

emissions, or wastewater. 

Subpart Y—[AMENDED] 

■ 56. Section 98.252 is amended by 

revising the parenthetical phrase 

preceding the last two sentences in 

paragraph (a) introductory text and 

revising paragraph (i) to read as follows: 

§ 98.252 GHGs to report. 

* * * * * 

(a) * * * (Use the default CH4 and 

N2O emission factors for ‘‘Fuel Gas’’ in 

Table C–2 of this part. For Tier 3, use 

either the default high heat value for 

fuel gas in Table C–1 of subpart C of this 

part or a calculated HHV, as allowed in 

Equation C–8 of subpart C of this part.) 

* * * 

* * * * * 

(i) CO2 emissions from non-merchant 

hydrogen production process units (not 

including hydrogen produced from 

catalytic reforming units) following the 

calculation methodologies, monitoring 

and QA/QC methods, missing data 

procedures, reporting requirements, and 

recordkeeping requirements of subpart P 

of this part. 

■ 57. Section 98.253 is amended by: 

■ a. Revising the parameter ‘‘EmFCH4’’ to 

Equation Y–4 in paragraph (b)(2) and 

‘‘EmFN2O’’ to Equation Y–5 in paragraph 

(b)(3). 

■ b. Revising paragraphs (f)(2) and (3). 

■ c. Revising paragraph (f)(4) 

introductory text and the parameters 

‘‘FSG’’ and ‘‘MFc’’ to Equation Y–12. 

■ d. Revising paragraphs (j) introductory 

text, (k) introductory text, and (m) 

introductory text. 

The revisions read as follows: 

§ 98.253 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(2) * * * 

* * * * * 

EmFCH4 = Default CH4 emission factor for 

‘‘Fuel Gas’’ from Table C–2 of subpart C 

of this part (General Stationary Fuel 

Combustion Sources) (kg CH4/MMBtu). 

* * * * * 

(3) * * * 

* * * * * 

EmFN2O = Default N2O emission factor for 

‘‘Fuel Gas’’ from Table C–2 of subpart C 

of this part (General Stationary Fuel 

Combustion Sources) (kg N2O/MMBtu). 

* * * * * 

(f) * * * 

(2) Flow measurement. If you have a 

continuous flow monitor on the sour gas 

feed to the sulfur recovery plant or the 

sour gas feed sent for off-site sulfur 

recovery, 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 or the 

sour gas feed sent for off-site sulfur 

recovery, 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 the sour gas feed sent for offsite for sulfur recovery, 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 sitespecific 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 on-site sulfur recovery plant and 

for sour gas sent off-site for sulfur 

recovery using Equation Y–12 of this 

section. 

* * * * * 

FSG = Volumetric flow rate of sour gas 

(including sour water stripper gas) fed to 

the sulfur recovery plant or the sour gas 

feed sent off-site for sulfur recovery (scf/ 

year). 

* * * * * 

MFC = Mole fraction of carbon in the sour gas 

fed to the sulfur recovery plant or the 

sour gas feed sent off-site for sulfur 

recovery (kg-mole C/kg-mole gas); 

default = 0.20. 

* * * * * 

(j) For each process vent not covered 

in paragraphs (a) through (i) of this 

section that can reasonably be expected 

to contain greater than 2 percent by 

volume CO2 or greater than 0.5 percent 

by volume of CH4 or greater than 0.01 

percent by volume (100 parts per 

million) of N2O, calculate GHG 

emissions using Equation Y–19 of this 

section. You must also use Equation Y– 

19 of this section to calculate CH4

emissions for catalytic reforming unit 

depressurization and purge vents when 

methane is used as the purge gas, CH4

emissions if you elected to use the 

method in paragraph (i)(1) of this 

section, and CO2 and/or CH4 emissions, 

as applicable, if you elected this method 

as an alternative to the methods in 

paragraphs (f), (h), or (k) of this section. 

* * * * * 

(k) For uncontrolled blowdown 

systems, you must calculate CH4

emissions either using the methods for 

process vents in paragraph (j) of this 

section regardless of the CH4

concentration or using Equation Y–20 of 

this section. Blowdown systems where 

the uncondensed gas stream is routed to 

a flare or similar control device are 

considered to be controlled and are not 

required to estimate emissions under 

this paragraph (k). 

* * * * * 

(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 (2) of this section. 

* * * * * 

■ 58. Section 98.256 is amended by: 

■ a. Revising paragraphs (f)(6), (h) 

introductory text, and (h)(2) through (6). 

■ b. Adding paragraph (j)(10). 

■ c. Revising paragraph (k)(4). 

■ d. Adding paragraph (k)(6). 

■ e. Revising paragraph (o)(4)(vi). 

■ f. Removing and reserving paragraphs 

(o)(5) through (7). 

The revisions and additions read as 

follows: 

§ 98.256 Data reporting requirements. 

* * * * * 

(f) * * * 

(6) If you use a CEMS, the relevant 

information required under § 98.36 for 

the Tier 4 Calculation Methodology, the 

CO2 annual emissions as measured by 

the CEMS (unadjusted to remove CO2

combustion emissions associated with 

additional units, if present) and the 

process CO2 emissions as calculated 

according to § 98.253(c)(1)(ii). Report 

the CO2 annual emissions associated 

with sources other than those from the 

coke burn-off in accordance with the 


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applicable subpart (e.g., subpart C of 

this part in the case of a CO boiler). 

* * * * * 

(h) For on-site sulfur recovery plants 

and for emissions from sour gas sent offsite for sulfur recovery, the owner and 

operator shall report: 

* * * * * 

(2) For each on-site sulfur recovery 

plant, the maximum rated throughput 

(metric tons sulfur produced/stream 

day), a description of the type of sulfur 

recovery plant, and an indication of the 

method used to calculate CO2 annual 

emissions for the sulfur recovery plant 

(e.g., CO2 CEMS, Equation Y–12, or 

process vent method in § 98.253(j)). 

(3) The calculated CO2 annual 

emissions for each on-site 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 on-site and off-site sulfur recovery 

plant (in scf/year), the molar volume 

conversion factor (in scf/kg-mole), and 

the annual average mole fraction of 

carbon in the sour gas (in kg-mole C/kgmole gas). 

(5) If you recycle tail gas to the front 

of an on-site 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 a unit specific 

correction is used, report the approach 

used. 

(6) If you use a CEMS, the relevant 

information required under § 98.36 for 

the Tier 4 Calculation Methodology, the 

CO2 annual emissions as measured by 

the CEMS and the annual process CO2

emissions calculated according to 

§ 98.253(f)(1). Report the CO2 annual 

emissions associated with fuel 

combustion in accordance with subpart 

C of this part (General Stationary Fuel 

Combustion Sources). 

* * * * * 

(j) * * * 

(10) If you use Equation Y–19 of this 

subpart, the relevant information 

required under paragraph (l)(5) of this 

section. 

(k) * * * 

(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 CH4/kg-mole gas, wet 

basis). 

* * * * * 

(6) If you use Equation Y–19 of this 

subpart, the relevant information 

required under paragraph (l)(5) of this 

section for each set of coke drums or 

vessels of the same size. 

* * * * * 

(o) * * * 

(4) * * * 

(vi) If you did not use Equation Y–23, 

the tank-specific methane composition 

data and the annual gas generation 

volume (scf/yr) used to estimate the 

cumulative CH4 emissions for storage 

tanks used to process unstabilized crude 

oil. 

* * * * * 

Subpart Z—[AMENDED] 

■ 59. Section 98.263 is amended by 

revising paragraph (b)(1)(ii) introductory 

text and the parameter ‘‘CO2n,i’’ of 

Equation Z–1b to read as follows: 

§ 98.263 Calculating GHG emissions. 

* * * * * 

(b) * * * 

(1) * * * 

(ii) If your process measurement 

provides the CO2 content directly as an 

output, calculate and report the process 

CO2 emissions from each wet-process 

phosphoric acid process line using 

Equation Z–1b of this section: 

* * * * * 

CO2n,i = Carbon dioxide content of a grab 

sample batch of phosphate rock by origin 

i obtained during month n (percent by 

weight, expressed as a decimal fraction). 

* * * * * 

■ 60. Section 98.264 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 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 

before it enters the mill using one of the 

following methods. You may conduct 

the representative bulk sampling using 

a method published by a consensus 

standards organization, or you may use 

industry consensus standard practice 

methods, including but not limited to 

the Phosphate Mining States Methods 

Used and Adopted by the Association of 

Fertilizer and Phosphate Chemists 

(AFPC). 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 carbon 

dioxide or inorganic carbon content of 

each monthly grab sample of phosphate 

rock (consumed in the production of 

phosphoric acid). You may use a 

method published by a consensus 

standards organization, or you may use 

industry consensus standard practice 

methods, including but not limited to 

the Phosphate Mining States Methods 

Used and Adopted by AFPC. 

* * * * * 

■ 61. Section 98.265 is revised to read 

as follows: 

§ 98.265 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 must be used in the 

calculations as specified in paragraphs 

(a) and (b) of this section. 

(a) For each missing value of the 

inorganic carbon content or CO2 content 

of phosphate rock (by origin), you must 

use the appropriate default factor 

provided in Table Z–1 of this subpart. 

Alternatively, you must determine a 

substitute data value by calculating the 

arithmetic average of the quality-assured 

values of inorganic carbon contents or 

CO2 contents of phosphate rock of origin 

i (see Equation Z–1a or Z–1b of this 

subpart) from samples immediately 

preceding and immediately following 

the missing data incident. If no qualityassured data on inorganic carbon 

contents or CO2 contents of phosphate 

rock of origin i are available prior to the 

missing data incident, the substitute 

data value shall be the first qualityassured value for inorganic carbon 

contents or CO2 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. 

■ 62. Section 98.266 is amended by 

revising paragraphs (a), (b), (d), and 

(f)(5), (6), and (8) to read as follows: 

§ 98.266 Data reporting requirements. 

* * * * * 


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(a) Annual phosphoric acid 

production, by origin of the phosphate 

rock (tons). 

(b) Annual phosphoric acid 

production capacity (tons). 

* * * * * 

(d) Annual phosphate rock 

consumption from monthly 

measurement records by origin (tons). 

* * * * * 

(f) * * * 

(5) Monthly inorganic carbon content 

of phosphate rock for each wet-process 

phosphoric acid process line for which 

Equation Z–1a is used (percent by 

weight, expressed as a decimal fraction), 

or CO2 content (percent by weight, 

expressed as a decimal fraction) for 

which Equation Z–1b is used. 

(6) Monthly mass of phosphate rock 

consumed, by origin, in production for 

each wet-process phosphoric acid 

process line (tons). 

* * * * * 

(8) Number of times missing data 

procedures were used to estimate 

phosphate rock consumption (months), 

inorganic carbon contents of the 

phosphate rock (months), and CO2

contents of the phosphate rock 

(months). 

* * * * * 

■ 63. Section 98.267 is amended by 

revising paragraphs (a) and (c) to read as 

follows: 

§ 98.267 Records that must be retained. 

* * * * * 

(a) Monthly mass of phosphate rock 

consumed by origin (tons). 

* * * * * 

(c) Documentation of the procedures 

used to ensure the accuracy of monthly 

phosphate rock consumption by origin. 

Subpart AA—[AMENDED] 

■ 64. Section 98.273 is amended by 

revising paragraph (a)(3) introductory 

text and the parameter ‘‘(EF)’’ of 

Equation AA–1 to read as follows: 

§ 98.273 Calculating GHG emissions. 

(a) * * * 

(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 emissions factors, 

according to Equation AA–1 of this 

section: 

* * * * * 

(EF) = Default emission factor for CO2, CH4, 

or N2O, from Table AA–1 of this subpart 

(kg CO2, CH4, or N2O per mmBtu). 

* * * * * 

■ 65. Section 98.276 is amended by 

revising paragraphs (e) and (k) to read 

as follows: 

§ 98.276 Data reporting requirements. 

* * * * * 

(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). 

* * * * * 

(k) Total annual production of 

unbleached virgin chemical pulp 

produced onsite during the reporting 

year in air-dried metric tons per year. 

This total annual production value is 

the sum of all kraft, semichemical, soda, 

and sulfite pulp produced onsite, prior 

to bleaching, through all virgin pulping 

lines. Do not include mechanical pulp 

or secondary fiber repulped for paper 

production in the virgin pulp 

production total. 

■ 66. Table AA–1 is revised to read as 

follows: 

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) 

a CO2 CH4 N2O 

North American Softwood ............................................................................................................ 94.4 0.0019 0.00042 

North American Hardwood .......................................................................................................... 93.7 0.0019 0.00042 

Bagasse ....................................................................................................................................... 95.5 0.0019 0.00042 

Bamboo ........................................................................................................................................ 93.7 0.0019 0.00042 

Straw ............................................................................................................................................ 95.1 0.0019 0.00042 

a Includes emissions from both the recovery furnace and pulp mill lime kiln. 

■ 67. Table AA–2 is revised to read as 

follows: 

TABLE AA–2 TO SUBPART AA OF PART 98—KRAFT LIME KILN AND CALCINER EMISSIONS FACTORS FOR CH4 AND N2O 

Fuel 

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

Kraft lime kilns Kraft calciners 

CH4 N2O CH4 N2O 

Residual Oil (any type) .................................................... 0.0027 ....................... 0 0.0027 ....................... 0.0003 

Distillate Oil (any type) ..................................................... 0.0027 ....................... 0 0.0027 ....................... 0.0004 

Natural Gas ...................................................................... 0.0027 ....................... 0 0.0027 ....................... 0.0001 

Biogas .............................................................................. 0.0027 ....................... 0 0.0027 ....................... 0.0001 

Petroleum coke ................................................................ 0.0027 ....................... 0 aNA ............................ aNA 

Other Fuels ...................................................................... See Table C–2 .......... 0 See Table C–2 .......... See Table C–2 

a Emission factors for kraft calciners are not available. 


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Subpart BB—[AMENDED] 

■ 68. Section 98.282 is amended by 

revising paragraph (a) to read as follows: 

§ 98.282 GHGs to report. 

* * * * * 

(a) CO2 process emissions from all 

silicon carbide process units or furnaces 

combined. 

* * * * * 

■ 69. Section 98.283 is amended by: 

■ a. Revising the introductory text. 

■ b. Revising paragraphs (a), (b) 

introductory text, and (b)(2) 

introductory text. 

■ c. Revising the parameter ‘‘Tn’’ in 

Equation BB–2 in paragraph (b)(2). 

■ d. Removing paragraph (d). 

The revisions read as follows: 

§ 98.283 Calculating GHG emissions. 

You must calculate and report the 

combined annual process CO2 emissions 

from all silicon carbide process units 

and production furnaces using the 

procedures in either paragraph (a) or (b) 

of this section. 

(a) Calculate and report under this 

subpart the combined annual 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 combined annual process 

CO2 emissions using the procedures in 

paragraphs (b)(1) and (b)(2) of this 

section. 

* * * * * 

(2) Calculate annual CO2 process 

emissions from the silicon carbide 

production facility according to 

Equation BB–2 of this section: 

* * * * * 

Tn = Petroleum coke consumption in 

calendar month n (tons). 

* * * * * 

■ 70. Section 98.286 is amended by 

revising paragraph (b) introductory text 

to read as follows: 

§ 98.286 Data reporting requirements. 

* * * * * 

(b) If a CEMS is not used to measure 

process CO2 emissions, you must report 

the information in paragraph (b)(1) 

through (8) of this section for all silicon 

carbide process units or production 

furnaces combined: 

* * * * * 

Subpart DD—[AMENDED] 

■ 71. Section 98.304 is amended by 

revising paragraphs (c)(1) and (2) to read 

as follows: 

§ 98.304 Monitoring and QA/QC 

requirements. 

* * * * * 

(c) * * * 

(1) Ensure that cylinders returned to 

the gas supplier are consistently 

weighed on a scale that is certified to be 

accurate and precise to within 2 pounds 

of true weight and is periodically 

recalibrated per the manufacturer’s 

specifications. Either measure residual 

gas (the amount of gas remaining in 

returned cylinders) or have the gas 

supplier measure it. If the gas supplier 

weighs the residual gas, obtain from the 

gas supplier a detailed monthly 

accounting, within ± 2 pounds, of 

residual gas amounts in the cylinders 

returned to the gas supplier. 

(2) Ensure that cylinders weighed for 

the beginning and end of year inventory 

measurements are weighed on a scale 

that is certified to be accurate and 

precise to within 2 pounds of true 

weight and is periodically recalibrated 

per the manufacturer’s specifications. 

All scales used to measure quantities 

that are to be reported under § 98.306 

must be calibrated using calibration 

procedures specified by the scale 

manufacturer. Calibration must be 

performed prior to the first reporting 

year. After the initial calibration, 

recalibration must be performed at the 

minimum frequency specified by the 

manufacturer. 

* * * * * 

Subpart FF—[AMENDED] 

■ 72. Section 98.320 is amended by 

revising paragraphs (b)(1) and (2) to read 

as follows: 

§ 98.320 Definition of the source category. 

* * * * * 

(b) * * * 

(1) Each ventilation system shaft or 

vent hole, including both those points 

where mine ventilation air is emitted 

and those where it is sold, used onsite, 

or otherwise destroyed (including by 

ventilation air methane (VAM) 

oxidizers). 

(2) Each degasification system well or 

gob gas vent hole, including 

degasification systems deployed before, 

during, or after mining operations are 

conducted in a mine area. This includes 

both those wells and vent holes where 

coal bed gas is emitted, and those where 

the gas is sold, used onsite, or otherwise 

destroyed (including by flaring). 

* * * * * 

■ 73. Section 98.322 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 

§ 98.322 GHGs to report. 

* * * * * 

(b) You must report CH4 destruction 

from systems where gas is sold, used 

onsite, or otherwise destroyed 

(including by VAM oxidation and by 

flaring). 

* * * * * 

(d) You must report under this 

subpart the CO2 emissions from coal 

mine gas CH4 destruction occurring at 

the facility, where the gas is not a fuel 

input for energy generation or use (e.g., 

flaring and VAM oxidation). 

* * * * * 

■ 74. Section 98.323 is amended by: 

■ a. Revising parameters ‘‘V’’, ‘‘MCF’’, 

‘‘(fH2O)’’ and ‘‘P’’ of Equation FF–1 in 

paragraph (a). 

■ b. Revising paragraph (a)(2). 

■ c. Revising Equation FF–3 and 

revising parameters ‘‘Vi’’, ‘‘MCFi’’, 

‘‘(fH2O)’’, and ‘‘Pi’’ of Equation FF–3 in 

paragraph (b). 

■ d. Revising paragraph (b)(1). 

■ e. Removing parameter ‘‘CH4D’’ of 

Equation FF–4 of paragraph (b)(2) and 

adding parameter ‘‘(CH4D)i,j’’ in its 

place. 

■ f. Revising paragraph (c) introductory 

text and Equation FF–6 in paragraph 

(c)(1). 

The revisions read as follows: 

§ 98.323 Calculating GHG emissions. 

(a) * * * 

V = Volumetric flow rate for the quarter 

(acfm) based on sampling or a flow rate 

meter. If a flow rate meter is used and 

the meter automatically corrects to 

standard temperature and pressure, then 

use scfm and replace ‘‘520°R/T × P/1 

atm’’ with ‘‘1’’. 

MCF = Moisture correction factor for the 

measurement period, volumetric basis. 

= 1 when V and C are measured on a dry 

basis or if both are measured on a wet 

basis. 

= 1-(fH2O) when V is measured on a wet basis 

and C is measured on a dry basis. 

= 1/[1-(fH2O)] when V is measured on a dry 

basis and C is measured on a wet basis. 

(fH2O) = Moisture content of the CH4 emitted 

during the measurement period, 

volumetric basis (cubic feet water per 

cubic feet emitted gas). 

* * * * * 

P = Absolute pressure at which flow is 

measured (atm) for the quarter. The 

annual average barometric pressure from 

the nearest NOAA weather service 

station may be used as a default. 

* * * * * 

(2) Values of V, C, T, P, and (fH2O), if 

applicable, must be based on 

measurements taken at least once each 


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quarter with no fewer than 6 weeks 

between measurements. If 

measurements are taken more frequently 

than once per quarter, then use the 

average value for all measurements 

taken. If continuous measurements are 

taken, then use the average value over 

the time period of continuous 

monitoring. 

* * * * * 

(b) * * * 

* * * * * 

Vi = Measured volumetric flow rate for the 

days in the week when the degasification 

system is in operation at that monitoring 

point, based on sampling or a flow rate 

meter (acfm). If a flow rate meter is used 

and the meter automatically corrects to 

standard temperature and pressure, then 

use scfm and replace ‘‘520°R/Ti× Pi/1 

atm’’ with ‘‘1’’. 

MCFi = Moisture correction factor for the 

measurement period, volumetric basis. 

= 1 when Vi and Ci are measured on a 

dry basis or if both are measured on a 

wet basis. 

= 1-(fH2O)I when Vi is measured on a wet 

basis and Ci is measured on a dry basis. 

= 1/[1-(fH2O)i] when Vi is measured on a 

dry basis and Ci is measured on a wet 

basis. 

(fH2O) = Moisture content of the CH4 emitted 

during the measurement period, 

volumetric basis (cubic feet water per 

cubic feet emitted gas). 

* * * * * 

Pi = Absolute pressure at which flow is 

measured (atm). 

* * * * * 

(1) Values for V, C, T, P, and (fH2O), 

if applicable, must be based on 

measurements taken at least once each 

calendar week with at least 3 days 

between measurements. If 

measurements are taken more frequently 

than once per week, then use the 

average value for all measurements 

taken that week. If continuous 

measurements are taken, then use the 

average values over the time period of 

continuous monitoring when the 

continuous monitoring equipment is 

properly functioning. 

(2) * * * 

* * * * * 

(CH4D)i,j = Weekly CH4 liberated from a 

degasification monitoring point (metric 

tons CH4). 

* * * * * 

(c) If gas from a degasification system 

or ventilation system is sold, used 

onsite, or otherwise destroyed 

(including by flaring or VAM oxidation), 

you must calculate the quarterly CH4

destroyed for each destruction device 

and each point of offsite transport to a 

destruction device, using Equation FF– 

5 of this section. You must measure CH4

content and flow rate according to the 

provisions in § 98.324, and calculate the 

methane routed to the destruction 

device (CH4) using either Equation FF– 

1 or Equation FF–4 of this section, as 

applicable. 

* * * * * 

(1) * * * 

* * * * * 

■ 75. Section 98.324 is amended by 

revising paragraphs (b) introductory text 

and (c)(2) to read as follows: 

§ 98.324 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) For CH4 liberated from ventilation 

systems, determine whether CH4 will be 

monitored from each ventilation shaft 

and vent hole, from a centralized 

monitoring point, or from a combination 

of the two options. Operators are 

allowed flexibility for aggregating 

emissions from more than one 

ventilation point, as long as emissions 

from all are addressed, and the 

methodology for calculating total 

emissions documented. Monitor by one 

of the following options: 

* * * * * 

(c) * * * 

(2) Collect weekly (once each calendar 

week, with at least three days between 

measurements) or more frequent 

samples, for all degasification wells and 

gob gas vent holes. Determine weekly or 

more frequent flow rates, methane 

concentration, temperature, and 

pressure from these degasification wells 

and gob gas vent holes. Methane 

composition should be determined 

either by submitting samples to a lab for 

analysis, or from the use of 

methanometers at the degasification 

monitoring site. Follow the sampling 

protocols for sampling of methane 

emissions from ventilation shafts, as 

described in § 98.324(b)(1). You must 

record the date of sampling, flow, 

temperature, pressure, and moisture 

measurements, the methane 

concentration (percent), the bottle 

number of samples collected, and the 

location of the measurement or 

collection. 

* * * * * 

■ 76. Section 98.326 is amended by 

revising paragraphs (a), (f), (h), (i), (j), 

(o), and (r), and adding paragraph (t) to 

read as follows: 

§ 98.326 Data reporting requirements. 

* * * * * 

(a) Quarterly CH4 liberated from each 

ventilation monitoring point, (metric 

tons CH4). 

* * * * * 

(f) Quarterly volumetric flow rate for 

each ventilation monitoring point and 

units of measure (scfm or acfm), date 

and location of each measurement, and 

method of measurement (quarterly 

sampling or continuous monitoring), 

used in Equation FF–1 of this subpart. 

* * * * * 

(h) Weekly volumetric flow rate used 

to calculate CH4 liberated from 

degasification systems and units of 

measure (acfm or scfm), and method of 

measurement (sampling or continuous 

monitoring), used in Equation FF–3 of 

this subpart. 

(i) Quarterly CH4 concentration (%) 

used to calculate CH4 liberated from 

degasification systems and if the data is 

based on CEMS or weekly sampling. 

(j) Weekly volumetric flow rate used 

to calculate CH4 destruction for each 

destruction device and each point of 


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offsite transport, and units of measure 

(acfm or scfm). 

* * * * * 

(o) Temperatures (°R), pressure (atm), 

moisture content, and the moisture 

correction factor (if applicable) used in 

Equation FF–1 and FF–3 of this subpart; 

and the gaseous organic concentration 

correction factor, if Equation FF–9 was 

required. 

* * * * * 

(r) Identification information and 

description for each well, shaft, and 

vent hole, including paragraphs (r)(1) 

through (r)(3) of this section: 

(1) Indication of whether the well, 

shaft, or vent hole is monitored 

individually, or as part of a centralized 

monitoring point. Note which method 

(sampling or continuous monitoring) 

was used. 

(2) Start date and close date of each 

well, shaft, and vent hole. 

(3) Number of days the well, shaft, or 

vent hole was in operation during the 

reporting year. 

* * * * * 

(t) Mine Safety and Health 

Administration (MSHA) identification 

for this coal mine. 

Subpart HH—[AMENDED] 

■ 77. Section 98.340 is amended by 

revising paragraph (a) to read as follows: 

§ 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, unless all three of the following 

conditions apply. 

(1) The MSW landfill did not receive 

waste on or after January 1, 2013. 

(2) The MSW landfill had CH4

generation as determined using 

Equation HH–5 and, if applicable, 

Equation HH–7 of this subpart of less 

than 1,190 metric tons of CH4 in the 

2013 reporting year. 

(3) The owner or operator of the MSW 

landfill was not required to submit an 

annual report under any requirement of 

this part in any reporting year prior to 

2013. 

* * * * * 

■ 78. Section 98.343 is amended by: 

■ a. Revising the parameters ‘‘DOC’’ and 

‘‘F’’ of Equation HH–1 in paragraph 

(a)(1). 

■ b. Revising Equation HH–4 and the 

parameters ‘‘N’’ and ‘‘0.0423’’ of 

Equation HH–4 in paragraph (b)(1). 

■ c. Revising paragraphs (b)(2)(i), 

(b)(2)(ii), (b)(2)(iii)(A), and (b)(2)(iii)(B). 

■ d. Revising parameter ‘‘OX’’ of 

Equation HH–5 in paragraph (c)(1). 

■ e. Revising paragraphs (c)(3)(i) and 

(ii). 

The revisions read as follows: 

§ 98.343 Calculating GHG emissions. 

(a) * * * 

(1) * * * 

* * * * * 

DOC = Degradable organic carbon from Table 

HH–1 of this subpart [fraction (metric 

tons C/metric ton waste)]. 

* * * * * 

F = Fraction by volume of CH4 in landfill gas 

from measurement data for the current 

reporting year, if available (fraction, dry 

basis, corrected to 0% oxygen); 

otherwise, use the default of 0.5. 

* * * * * 

(b) * * * 

(1) * * * 

* * * * * 

N = Total number of measurement periods in 

a year. Use daily averaging periods for a 

continuous monitoring system and N = 

365 (or N = 366 for leap years). For 

monthly sampling, as provided in 

paragraph (b)(2) of this section, use 

N=12. 

* * * * * 

0.0423 = Density of CH4 lb/cf at 520°R or 60 

degrees Fahrenheit and 1 atm. 

* * * * * 

(2) * * * 

(i) Continuously monitor gas flow rate 

and determine the cumulative volume 

of landfill gas each month 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 at least once each 

calendar month; if only one 

measurement is made each calendar 

month, there must be at least fourteen 

days between measurements. 

(iii) * * * 

(A) Determine the temperature and 

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 at 

least once each calendar month; if only 

one measurement is made each calendar 

month, there must be at least fourteen 

days between measurements. 

(B) If the CH4 concentration is 

determined on a dry basis and flow is 

determined on a wet basis or CH4

concentration is determined on a wet 

basis and flow is determined on a dry 

basis, and the flow meter does not 

automatically correct for moisture 

content, 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 at least once each 

calendar month; if only one 

measurement is made each calendar 

month, there must be at least fourteen 

days between measurements. 

(c) * * * 

(1) * * * 

* * * * * 

OX = Oxidation fraction. Use the appropriate 

oxidation fraction default value from 

Table HH–4 of this subpart. 

* * * * * 

(3) * * * 

(i) Calculate CH4 emissions from the 

modeled CH4 generation and measured 

CH4 recovery using Equation HH–6 of 

this section. 


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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). 

N = Number of landfill gas measurement 

locations (associated with a destruction 

device or gas sent off-site). If a single 

monitoring location is used to monitor 

volumetric flow and CH4 concentration 

of the recovered gas sent to one or 

multiple destruction devices, then N=1. 

Rn = Quantity of recovered CH4 from 

Equation HH–4 of this section for the nth

measurement location (metric tons). 

OX = Oxidation fraction. Use the appropriate 

oxidation fraction default value from 

Table HH–4 of this subpart. 

DEn = Destruction efficiency (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99) for the nth

measurement location. If the gas is 

transported off-site for destruction, use 

DE = 1. If the volumetric flow and CH4

concentration of the recovered gas is 

measured at a single location providing 

landfill gas to multiple destruction 

devices (including some gas destroyed 

on-site and some gas sent off-site for 

destruction), calculate DEn as the 

arithmetic average of the DE values 

determined for each destruction device 

associated with that measurement 

location. 

fDest,n = Fraction of hours the destruction 

device associated with the nth

measurement location was operating 

during active gas flow calculated as the 

annual operating hours for the 

destruction device divided by the annual 

hours flow was sent to the destruction 

device as measured at the nth

measurement location. If the gas is 

transported off-site for destruction, use 

fDest,n= 1. If the volumetric flow and CH4

concentration of the recovered gas is 

measured at a single location providing 

landfill gas to multiple destruction 

devices (including some gas destroyed 

on-site and some gas sent off-site for 

destruction), calculate fDest,n as the 

arithmetic average of the fDest values 

determined for each destruction device 

associated with that measurement 

location. 

(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. 

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). 

N = Number of landfill gas measurement 

locations (associated with a destruction 

device or gas sent off-site). If a single 

monitoring location is used to monitor 

volumetric flow and CH4 concentration 

of the recovered gas sent to one or 

multiple destruction devices, then N=1. 

Rn = Quantity of recovered CH4 from 

Equation HH–4 of this section for the nth

measurement location (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,n = Fraction of hours the recovery system 

associated with the nth measurement 

location was operating (annual operating 

hours/8760 hours per year or annual 

operating hours/8784 hours per year for 

a leap year). 

OX = Oxidation fraction. Use appropriate 

oxidation fraction default value from 

Table HH–4 of this subpart. 

DEn = Destruction efficiency, (lesser of 

manufacturer’s specified destruction 

efficiency and 0.99) for the nth

measurement location. If the gas is 

transported off-site for destruction, use 

DE = 1. If the volumetric flow and CH4

concentration of the recovered gas is 

measured at a single location providing 

landfill gas to multiple destruction 

devices (including some gas destroyed 

on-site and some gas sent off-site for 

destruction), calculate DEn as the 

arithmetic average of the DE values 

determined for each destruction device 

associated with that measurement 

location. 

fDest,n = Fraction of hours the destruction 

device associated with the nth

measurement location was operating 

during active gas flow calculated as the 

annual operating hours for the 

destruction device divided by the annual 

hours flow was sent to the destruction 

device as measured at the nth

measurement location. If the gas is 

transported off-site for destruction, use 

fDest,n= 1. If the volumetric flow and CH4

concentration of the recovered gas is 

measured at a single location providing 

landfill gas to multiple destruction 

devices (including some gas destroyed 

on-site and some gas sent off-site for 

destruction), calculate fDest,n as the 

arithmetic average of the fDest values 

determined for each destruction device 

associated with that measurement 

location. 

■ 79. Section 98.344 is amended by 

revising paragraph (e) and adding 

paragraph (f) to read as follows: 

§ 98.344 Monitoring and QA/QC 

requirements. 

* * * * * 

(e) For landfills electing to measure 

the fraction by volume of CH4 in landfill 

gas (F), follow the requirements in 

paragraphs (e)(1) and (2) of this section. 

(1) Use a gas composition monitor 

capable of measuring the concentration 

of CH4 on a dry basis that is properly 

operated, calibrated, and maintained 

according to the requirements specified 

in paragraph (b) of this section. You 

must either use a gas composition 

monitor that is also capable of 

measuring the O2 concentration 

correcting for excess (infiltration) air or 

you must operate, maintain, and 


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calibrate a second monitor capable of 

measuring the O2 concentration on a dry 

basis according to the manufacturer’s 

specifications. 

(2) Use Equation HH–10 of this 

section to correct the measured CH4

concentration to 0% oxygen. If multiple 

CH4 concentration measurements are 

made during the reporting year, 

determine F separately for each 

measurement made during the reporting 

year, and use the results to determine 

the arithmetic average value of F for use 

in Equation HH–1 of this part. 

Where: 

F = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis, corrected to 0% 

oxygen). 

CCH4 = Measured CH4 concentration in 

landfill gas (volume %, dry basis). 

20.9c = Defined O2 correction basis, (volume 

%, dry basis). 

20.9 = O2 concentration in air (volume %, 

dry basis). 

%O2 = Measured O2 concentration in landfill 

gas (volume %, dry basis). 

(f) 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, 

pressure, and moisture content 

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, 

and the technical basis for these 

estimates shall be recorded. 

■ 80. Section 98.345 is amended by 

revising paragraph (c) to read as follows: 

§ 98.345 Procedures for estimating 

missing data. 

* * * * * 

(c) For missing daily waste disposal 

quantity data for disposal in the 

reporting year, 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. 

■ 81. Section 98.346 is amended by 

revising paragraphs (d)(1), (e), (h), (i)(5) 

through (8), and (i)(10) through (12) to 

read as follows: 

§ 98.346 Data reporting requirements. 

* * * * * 

(d) * * * 

(1) Degradable organic carbon (DOC) 

and fraction of DOC dissimilated (DOCF) 

values used in the calculations. 

* * * * * 

(e) Fraction of CH4 in landfill gas (F), 

an indication of whether the fraction of 

CH4 was determined based on measured 

values or the default value, and the 

methane correction factor (MCF) used in 

the calculations. If an MCF other than 

the default of 1 is used, provide an 

indication of whether active aeration of 

the waste in the landfill was conducted 

during the reporting year, a description 

of the aeration system, including 

aeration blower capacity, the fraction of 

the landfill containing waste affected by 

aeration, the total number of hours 

during the year the aeration blower was 

operated, and other factors used as a 

basis for the selected MCF value. 

* * * * * 

(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, the oxidation fraction 

used in the calculation, and an 

indication of whether passive vents 

and/or passive flares (vents or flares that 

are not considered part of the gas 

collection system as defined in § 98.6) 

are present at this landfill. 

(i) * * * 

(5) An indication of whether 

destruction occurs at the landfill 

facility, off-site, or both. If destruction 

occurs at the landfill facility, also report 

for each measurement location the 

number of destruction devices 

associated with that measurement 

location and the annual operating hours 

and the destruction efficiency (percent) 

for each destruction device associated 

with that measurement location. 

(6) Annual quantity of recovered CH4

(metric tons CH4) calculated using 

Equation HH–4 of this subpart for each 

measurement location. 

(7) A description of the gas collection 

system (manufacturer, capacity, and 

number of wells), the surface area 

(square meters) and estimated waste 

depth (meters) for each area specified in 

Table HH–3 to this subpart, the 

estimated gas collection system 

efficiency for landfills with this gas 

collection system, the annual operating 

hours of the gas collection system for 

each measurement location, and an 

indication of whether passive vents 

and/or passive flares (vents or flares that 

are not considered part of the gas 

collection system as defined in § 98.6) 

are present at the landfill. 

(8) Methane generation corrected for 

oxidation calculated using Equation 

HH–5 of this subpart, reported in metric 

tons CH4, and the oxidation fraction 

used in the calculation. 

* * * * * 

(10) Methane generation corrected for 

oxidation calculated using Equation 

HH–7 of this subpart, reported in metric 

tons CH4, and the oxidation fraction 

used in the calculation. 

(11) Methane emissions calculated 

using Equation HH–6 of this subpart, 

reported in metric tons CH4, and the 

oxidation fraction used in the 

calculation. 

(12) Methane emissions calculated 

using Equation HH–8 of this subpart, 

reported in metric tons CH4, and the 

oxidation fraction used in the 

calculation. 

■ 82. Section 98.348 is amended by 

adding definitions for ‘‘Landfill 

capacity’’ and ‘‘Leachate recirculation’’ 

in alphabetical order to read as follows: 

§ 98.348 Definitions. 

* * * * * 

Landfill capacity means the maximum 

amount of solid waste a landfill can 

accept. For the purposes of this subpart, 

for landfills that have a permit, the 

landfill capacity can be determined in 

terms of volume or mass in the most 

recent permit issued by the state, local, 

or Tribal agency responsible for 

regulating the landfill, plus any in-place 

waste not accounted for in the most 

recent permit. If the owner or operator 

chooses to convert from volume to mass 

to determine its capacity, the 

calculation must include a site-specific 

density. 

Leachate recirculation means the 

practice of taking the leachate collected 

from the landfill and reapplying it to the 

landfill by any of one of a variety of 

methods, including pre-wetting of the 

waste, direct discharge into the working 

face, spraying, infiltration ponds, 

vertical injection wells, horizontal 

gravity distribution systems, and 

pressure distribution systems. 

* * * * * 

■ 83. Table HH–1 to Subpart HH is 

amended by revising the entry for ‘‘OX’’ 

to read as follows: 


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TABLE HH–1 TO SUBPART HH OF

PART 98—EMISSIONS FACTORS, 

OXIDATION FACTORS AND METHODS

Factor Default value Units 

* * * * * 

Other parameters—All MSW landfills 

* * * * * 

OX ........ See Table HH–4 of this 

subpart.

..............

* * * * * 

■ 84. Table HH–2 to Subpart HH is 

revised to read as follows: 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES

Year Waste per capita 

ton/cap/yr 

1950 .......................... 0.63 

1951 .......................... 0.63 

1952 .......................... 0.63 

1953 .......................... 0.63 

1954 .......................... 0.63 

1955 .......................... 0.63 

1956 .......................... 0.63 

1957 .......................... 0.63 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES—Continued 

Year Waste per capita 

ton/cap/yr 

1958 .......................... 0.63 

1959 .......................... 0.63 

1960 .......................... 0.63 

1961 .......................... 0.64 

1962 .......................... 0.64 

1963 .......................... 0.65 

1964 .......................... 0.65 

1965 .......................... 0.66 

1966 .......................... 0.66 

1967 .......................... 0.67 

1968 .......................... 0.68 

1969 .......................... 0.68 

1970 .......................... 0.69 

1971 .......................... 0.69 

1972 .......................... 0.70 

1973 .......................... 0.71 

1974 .......................... 0.71 

1975 .......................... 0.72 

1976 .......................... 0.73 

1977 .......................... 0.73 

1978 .......................... 0.74 

1979 .......................... 0.75 

1980 .......................... 0.75 

1981 .......................... 0.76 

1982 .......................... 0.77 

1983 .......................... 0.77 

1984 .......................... 0.78 

1985 .......................... 0.79 

1986 .......................... 0.79 

TABLE HH–2 TO SUBPART HH OF

PART 98—U.S. PER CAPITA WASTE

DISPOSAL RATES—Continued 

Year Waste per capita 

ton/cap/yr 

1987 .......................... 0.80 

1988 .......................... 0.80 

1989 .......................... 0.83 

1990 .......................... 0.82 

1991 .......................... 0.76 

1992 .......................... 0.74 

1993 .......................... 0.76 

1994 .......................... 0.75 

1995 .......................... 0.70 

1996 .......................... 0.68 

1997 .......................... 0.69 

1998 .......................... 0.75 

1999 .......................... 0.75 

2000 .......................... 0.80 

2001 .......................... 0.91 

2002 .......................... 1.02 

2003 .......................... 1.02 

2004 .......................... 1.01 

2005 .......................... 0.98 

2006 .......................... 0.95 

2007 .......................... 0.95 

2008 .......................... 0.95 

2009 and all later 

years ..................... 0.95 

■ 85. Table HH–4 to Subpart HH is 

added to read as follows: 

TABLE HH–4 TO SUBPART HH OF PART 98—LANDFILL METHANE OXIDATION FRACTIONS

Under these conditions: 

Use this landfill methane 

oxidation 

fraction: 

I. For all reporting years prior to the 2013 reporting year 

C1: For all landfills regardless of cover type or methane flux ............................................................................................................ 0.10 

II. For the 2013 reporting year and all subsequent years 

C2: For landfills that have a geomembrane (synthetic) cover with less than 12 inches of cover soil for the majority of the landfill 

area containing waste ...................................................................................................................................................................... 0.0 

C3: For landfills that do not meet the conditions in C2 above, and for which you elect not to determine methane flux .................. 0.10 

C4: For landfills that do not meet the conditions in C2 above and that do not have a soil cover of at least 24 inches for a majority of the landfill area containing waste ........................................................................................................................................... 0.10 

C5: For landfills that have a soil cover of at least 24 inches for a majority of the landfill area containing waste and for which the 

methane flux rate is less than 10 grams per square meter per day (g/m2/d) ................................................................................. 0.35 

C6: For landfills that have a soil cover of at least 24 inches for a majority of the landfill area containing waste and for which the 

methane flux rate is 10 to 70 g/m2/d ............................................................................................................................................... 0.25 

C7: For landfills that have a soil cover of at least 24 inches for a majority of the landfill area containing waste and for which the 

methane flux rate is greater than 70 g/m2/d .................................................................................................................................... 0.10 

a Methane flux rate (in grams per square meter per day; g/m2/d) is the mass flow rate of methane per unit area at the bottom of the surface 

soil prior to any oxidation and is calculated as follows: 


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Where: 

MF = Methane flux rate from the landfill in 

the reporting year (grams per square 

meter per day, g/m2/d). 

K = unit conversion factor = 106/365 (g/

metric ton per days/year) or 106/366 for 

a leap year. 

SArea = The surface area of the landfill 

containing waste at the beginning of the 

reporting year (square meters, m2). 

GCH4 = Modeled methane generation rate in 

reporting year from Equation HH–1 of 

this subpart or Equation TT–1 of subpart 

TT of this part, as applicable, except for 

application with Equation HH–6 of this 

subpart (metric tons CH4). For 

application with Equation HH–6 of this 

subpart, the greater of the modeled 

methane generation rate in reporting year 

from Equation HH–1 of this subpart or 

Equation TT–1 of this part, as applicable, 

and the quantity of recovered CH4 from 

Equation HH–4 of this subpart (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. 

N = Number of landfill gas measurement 

locations (associated with a destruction 

device or gas sent off-site). If a single 

monitoring location is used to monitor 

volumetric flow and CH4 concentration 

of the recovered gas sent to one or 

multiple destruction devices, then N=1. 

Rn = Quantity of recovered CH4 from 

Equation HH–4 of this subpart for the 

nth measurement location (metric tons). 

fRec,n = Fraction of hours the recovery system 

associated with the nth measurement 

location was operating (annual operating 

hours/8760 hours per year or annual 

operating hours/8784 hours per year for 

a leap year). 

Subpart II—[AMENDED] 

■ 86. Section 98.353 is amended by 

revising the parameters ‘‘fDest_1’’ and 

‘‘fDest_2’’ of Equation II–6 in paragraph 

(d)(2) to read as follows: 

§ 98.353 Calculating GHG emissions. 

* * * * * 

(d) * * * 

(2) * * * 

* * * * * 

fDest_1 = Fraction of hours the primary 

destruction device was operating 

calculated as the annual hours when the 

destruction device was operating divided 

by the annual operating hours of the 

biogas recovery system. If the biogas is 

transported off-site for destruction, use 

fDest = 1. 

* * * * * 

fDest_2 = Fraction of hours the back-up 

destruction device was operating 

calculated as the annual hours when the 

destruction device was operating divided 

by the annual operating hours of the 

biogas recovery system. 

* * * * * 

Subpart LL—[AMENDED] 

■ 87. Section 98.386 is amended by: 

■ a. Removing and reserving paragraphs 

(a)(1) and (5). 

■ b. Revising paragraph (a)(4), (a)(8), 

(a)(9)(v), (a)(11)(v), and (a)(12) 

introductory text. 

■ c. Removing and reserving paragraph 

(a)(13). 

■ d. Revising paragraphs (a)(14), (15) 

and (18). 

■ e. Removing and reserving paragraph 

(b)(1). 

■ f. Revising paragraphs (b)(4), (b)(5)(v), 

and (b)(6)(i). 

■ g. Removing and reserving paragraph 

(c)(1). 

■ h. Revising paragraphs (c)(4), (c)(5)(v), 

and (d)(2) and (3). 

The revisions read as follows: 

§ 98.386 Data reporting requirements. 

* * * * * 

(a) * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(2) of this section. 

* * * * * 

(8) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (a)(6) of this section. 

(9) * * * 


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(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

* * * * * 

(11) * * * 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

metric ton of product. 

* * * * * 

(12) For every non-solid product 

reported in paragraph (a)(6) of this 

section for which Calculation Method 2 

of subpart MM of this part was used to 

determine an emissions factor, report: 

* * * * * 

(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 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)(14) of this section. 

* * * * * 

(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)(14) 

of this section, calculated according to 

§ 98.393(c). 

* * * * * 

(b) * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (b)(2) of this section. 

(5) * * * 

(v) The calculated CO2 emissions 

factor in metric tons per barrel or per 

metric ton of product. 

(6) * * * 

(i) The density test results in metric 

tons per barrel. 

* * * * * 

(c) * * * 

(4) Each standard method or other 

industry standard practice used to 

measure each quantity reported in 

paragraph (c)(2) of this section. 

(5) * * * 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

* * * * * 

(d) * * * 

(2) For a product that enters the 

facility to be further refined or 

otherwise used on site that is a blended 

feedstock, producers must meet the 

reporting requirements of paragraph 

(a)(2) of this section by reflecting the 

individual components of the blended 

feedstock. 

(3) For a product that is produced, 

imported, or exported that is a blended 

product, producers, importers, and 

exporters must meet the reporting 

requirements of paragraphs (a)(6), (b)(2), 

and (c)(2) of this section, as applicable, 

by reflecting the individual components 

of the blended product. 

Subpart MM—[AMENDED] 

■ 88. Section 98.393 is amended by: 

■ a. Revising the parameter ‘‘Producti’’ 

of Equation MM–1 in paragraph (a)(1). 

■ b. Revising the parameter ‘‘Producti’’ 

of Equation MM–1 in paragraph (a)(2). 

■ c. Revising paragraphs (h)(1) 

introductory text and (h)(2) introductory 

text. 

The revisions read as follows: 

§ 98.393 Calculating GHG emissions. 

(a) * * * 

(1) * * * 

* * * * * 

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, and excludes products that 

entered the refinery but are not reported 

under § 98.396(a)(2). For natural gas 

liquids, volumes shall reflect the 

individual components of the product as 

listed in Table MM–1 to subpart MM. 

* * * * * 

(2) * * * 

* * * * * 

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, and excludes 

products that entered the refinery but are 

not reported under § 98.396(a)(2). 

* * * * * 

(h) * * * 

(1) A reporter using Calculation 

Method 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. 

* * * * * 

(2) A refinery using Calculation 

Method 1 of this subpart to determine 

the emission factor of a non-crude 

petroleum feedstock shall calculate the 

CO2 emissions associated with that 

feedstock using Equation MM–9 of this 

section in place of Equation MM–2 of 

this section. 

* * * * * 

■ 89. Section 98.394 is amended by: 

■ a. Revising paragraphs (a)(1) 

introductory text and (a)(3). 

■ b. Adding paragraph (b)(3). 

■ c. Revising paragraph (c) introductory 

text. 

■ d. Removing paragraph (d). 

The revisions and addition read as 

follows: 

§ 98.394 Monitoring and QA/QC 

requirements. 

(a) * * * 

(1) The quantity of petroleum 

products, natural gas liquids, and 

biomass, shall be determined as follows: 

* * * * * 

(3) The annual quantity of crude oil 

received shall be determined according 

to one of the following methods. You 

may use an appropriate standard 

method published by a consensus-based 

standards organization or you may use 

an industry standard practice. 

(b) * * * 

(3) For units and processes that 

operate continuously with infrequent 

outages, it may not be possible to 

complete the calibration of a flow meter 

or other measurement device without 

disrupting normal process operation. In 

such cases, the owner or operator may 

postpone the calibration until the next 

scheduled maintenance outage. The best 

available information from company 

records may be used in the interim. 

Such postponements shall be 

documented in the monitoring plan that 

is required under § 98.3(g)(5). 

(c) Procedures for Calculation Method 

2 of this subpart. 

* * * * * 

■ 90. Section 98.395 is amended by 

revising paragraphs (a) introductory text 

and (b) and removing paragraph (c). 

The revisions read as follows: 

§ 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 during any period (e.g., if a 

meter malfunctions), the following 

missing data procedures shall be used: 

* * * * * 

(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 Method 1 of this 

subpart must be used in place of 

Calculation Method 2 of this subpart for 

the entire reporting year. 

■ 91. Section 98.396 is amended by: 

■ a. Removing and reserving paragraph 

(a)(1). 

■ b. Removing and reserving paragraphs 

(a)(4), (5), and (8). 

■ c. Revising paragraphs (a)(9) 

introductory text, (a)(9)(iii), (a)(9)(v), 


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(a)(10) introductory text, (a)(11) 

introductory text, and (a)(11)(iii). 

■ d. Removing and reserving paragraphs 

(a)(13) and (15). 

■ e. Revising paragraph (a)(18). 

■ f. Revising paragraphs (a)(20) through 

(22). 

■ g. Removing paragraph (a)(23). 

■ h. Removing and reserving paragraph 

(b)(1). 

■ i. Revising paragraph (b)(2). 

■ j. Removing and reserving paragraph 

(b)(4). 

■ k. Revising paragraphs (b)(5) 

introductory text and (b)(6) introductory 

text. 

■ l. Removing and reserving paragraphs 

(c)(1) and (4). 

■ m. Revising paragraphs (c)(5) 

introductory text, (c)(6) introductory 

text, and (d)(2) and (3). 

■ The revisions read as follows: 

§ 98.396 Data reporting requirements. 

* * * * * 

(a) * * * 

(9) For every feedstock reported in 

paragraph (a)(2) of this section for 

which Calculation Method 2 of this 

subpart was used to determine an 

emissions factor, report: 

* * * * * 

(iii) The carbon share test results in 

percent mass. 

* * * * * 

(v) The calculated CO2 emissions 

factor in metric tons CO2 per barrel or 

per metric ton of product. 

(10) For every non-solid feedstock 

reported in paragraph (a)(2) of this 

section for which Calculation Method 2 

of this subpart was used to determine an 

emissions factor, report: 

* * * * * 

(11) For every petroleum product and 

natural gas liquid reported in paragraph 

(a)(6) of this section for which 

Calculation Method 2 of this subpart 

was used to determine an emissions 

factor, report: 

* * * * * 

(iii) The carbon share test results in 

percent mass. 

* * * * * 

(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)(14) of this section, 

calculated according to § 98.393(c). 

* * * * * 

(20) For all crude oil that enters the 

refinery, report the annual quantity in 

barrels. 

(21) The quantity of bulk NGLs in 

metric tons or barrels received for 

processing during the reporting year. 

Report only quantities of bulk NGLs not 

reported in (a)(2) of this section. 

(22) Volume of crude oil in barrels 

that you injected into a crude oil supply 

or reservoir. 

* * * * * 

(b) * * * 

* * * * * 

(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. 

* * * * * 

(5) For each product reported in 

paragraph (b)(2) of this section for 

which Calculation Method 2 of this 

subpart used was used to determine an 

emissions factor, report: 

* * * * * 

(6) For each non-solid product 

reported in paragraph (b)(2) of this 

section for which Calculation Method 2 

of this subpart was used to determine an 

emissions factor, report: 

* * * * * 

(c) * * * 

(5) For each product reported in 

paragraph (c)(2) of this section for 

which Calculation Method 2 of this 

subpart was used to determine an 

emissions factor, report: 

* * * * * 

(6) For each non-solid product 

reported in paragraph (c)(2) of this 

section for which Calculation Method 2 

of this subpart used was used to 

determine an emissions factor, report: 

* * * * * 

(d) * * * 

(2) For a product that enters the 

refinery to be further refined or 

otherwise used on site that is a blended 

non-crude feedstock, refiners must meet 

the reporting requirements of paragraph 

(a)(2) of this section by reflecting the 

individual components of the blended 

non-crude feedstock. 

(3) For a product that is produced, 

imported, or exported that is a blended 

product, refiners, importers, and 

exporters must meet the reporting 

requirements of paragraphs (a)(6), (b)(2), 

and (c)(2) of this section, as applicable, 

by reflecting the individual components 

of the blended product. 

■ 92. Section 98.397 is amended by 

revising paragraphs (b) and (d) to read 

as follows: 

§ 98.397 Records that must be retained. 

* * * * * 

(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 

reported quantities of petroleum 

products, natural gas liquids, and 

biomass, reporters shall maintain 

metering, gauging, 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. 

* * * * * 

(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 Method 2. 

* * * * * 

■ 93. Section 98.398 is amended by: 

■ a. Adding the definitions for ‘‘Bulk 

NGLs’’ and ‘‘Natural Gas Liquids 

(NGLs)’’ in alphabetical order. 

■ b. Removing the definition of ‘‘Batch’’. 

The revisions read as follows: 

§ 98.398 Definitions. 

* * * * * 

Bulk NGLs for purposes of reporting 

under this subpart means mixtures of 

NGLs that are sold or delivered as 

undifferentiated product. 

Natural Gas Liquids (NGLs) for the 

purposes of reporting under this subpart 

means hydrocarbons that are separated 

from natural gas as liquids through the 

process of absorption, condensation, 

adsorption, or other methods, and are 

sold or delivered as differentiated 

product. Generally, such liquids consist 

of ethane, propane, butanes, or pentanes 

plus. 

■ 94. Table MM–1 to Subpart MM is 

amended by: 

■ a. Revising the entries for Ethane, 

Ethylene, Propane, Propylene, Butane, 

Butylene, Isobutane, and Isobutylene. 

■ b. Adding footnotes 3 and 4. 


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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) 

*******

Other Petroleum Products and Natural Gas Liquids 

*******

Ethane 3 ........................................................................................................................................ 0.0579 79.89 0.170 

Ethylene 4 ..................................................................................................................................... 0.0492 85.63 0.154 

Propane 3 ...................................................................................................................................... 0.0806 81.71 0.241 

Propylene 3 ................................................................................................................................... 0.0827 85.63 0.260 

Butane 3 ........................................................................................................................................ 0.0928 82.66 0.281 

Butylene 3 ..................................................................................................................................... 0.0972 85.63 0.305 

Isobutane 3 ................................................................................................................................... 0.0892 82.66 0.270 

Isobutylene 3 ................................................................................................................................. 0.0949 85.63 0.298 

*******

3The density and emission factors for components of LPG determined at 60 degrees Fahrenheit and saturation pressure (LPGs other than 

ethylene). 4The density and emission factor for ethylene determined at 41 degrees Fahrenheit and saturation pressure. 

Subpart NN—[AMENDED] 

■ 95. Section 98.400 is amended by 

revising paragraphs (a) and (b) to read 

as follows: 

§ 98.400 Definition of the source category. 

* * * * * 

(a) Natural gas liquids fractionators 

are installations that fractionate natural 

gas liquids (NGLs) into their constituent 

liquid products or mixtures of 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 

within a single state that are regulated 

as separate operating companies by 

State public utility commissions or that 

operate as independent municipallyowned distribution systems. LDCs do 

not include pipelines (both interstate 

and intrastate) delivering natural gas 

directly to major industrial users and 

farm taps upstream of the local 

distribution company inlet. 

* * * * * 

■ 96. Section 98.403 is amended by: 

■ a. Revising the parameter ‘‘Fuelh’’ to 

Equation NN–2 in paragraph (a)(2). 

■ b. Revising paragraphs (b)(1) 

introductory text and (b)(2)(i). 

■ c. Revising parameters ‘‘CO2k’’ and 

‘‘Fuel’’ to Equation NN–4 in paragraph 

(b)(2)(ii). 

■ d. Revising paragraph (b)(3). 

■ e. Revising paragraph (b)(4). 

■ f. Revising paragraph (c)(2) 

introductory text. 

■ g. Revising parameter ‘‘CO2’’ of 

Equation NN–8 of paragraph (c)(2). 

The revisions read as follows: 

§ 98.403 Calculating GHG emissions. 

(a) * * * 

(2) * * * 

* * * * * 

Fuelh = Total annual volume of product ‘‘h’’ 

supplied (volume per year, in Mscf for 

natural gas and bbl for NGLs). 

* * * * * 

(b) * * * 

(1) For natural gas that is received for 

redelivery to downstream gas 

transmission pipelines and other local 

distribution companies, use Equation 

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. 

* * * * * 

(2)(i) For natural gas delivered to large 

end-users, use Equation NN–4 of this 

section and the default values for the 

CO2 emission factors found in Table 

NN–2 of this subpart. A large end-user 

means any end-user facility receiving 

greater than or equal to 460,000 Mscf of 

natural gas per year. If the LDC does not 

know the total quantity of gas delivered 

to the end-user facility based on readily 

available information in the LDCs 

possession, then large end-user means 

any single meter at an end-user facility 

to which the LDC delivers equal to or 

greater than 460,000 Mscf per year. 

(ii) * * * 

* * * * * 

CO2k = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas delivered to each 

large end-user k, as defined in paragraph 

(b)(2)(i) of this section (metric tons). 

Fuel = Total annual volume of natural gas 

supplied to each large end-user k, as 

defined in paragraph (b)(2)(i) of this 

section (Mscf per year). 

* * * * * 

(3) For the net change in natural gas 

stored on system by the LDC during the 

reporting year, use Equation NN–5a of 

this section. For natural gas that is 

received by means other than through 

the city gate, and is not otherwise 

accounted for by Equation NN–1 or NN– 

2 of this section, use Equation NN–5b of 

this section. 

(i) For natural gas received by the LDC 

that is injected into on-system storage, 

and/or liquefied and stored, and for gas 

removed from storage and used for 

deliveries, use Equation NN–5a 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 


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used, provided it is developed using 

methods outlined in § 98.404. 

Where: 

CO2l = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of the net change in natural gas 

stored on system by the LDC within the 

reporting year (metric tons). 

Fuel1 = Total annual volume of natural gas 

added to storage on-system or liquefied 

and stored in the reporting year (Mscf 

per year). 

Fuel2 = Total annual volume of natural gas 

that is removed from storage or 

vaporized and removed from storage and 

used for deliveries to customers or other 

LDCs by the LDC within the reporting 

year (Mscf per year). 

EF = Annual average CO2 emission factor for 

natural gas placed into/removed from 

storage (MT CO2/Mscf). 

(ii) For natural gas received by the 

LDC that bypassed the city gate, use 

Equation NN–5b of this section. This 

includes natural gas received directly by 

LDC systems from producers or natural 

gas processing plants from local 

production, received as a liquid and 

vaporized for delivery, or received from 

any other source that bypassed the city 

gate. Use 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. 

Where: 

CO2n = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas received that 

bypassed the city gate and is not 

otherwise accounted for by Equation 

NN–1 or NN–2 of this section (metric 

tons). 

Fuelz = Total annual volume of natural gas 

received that was not otherwise 

accounted for by Equation NN–1 or NN– 

2 of this section (natural gas from 

producers and natural gas processing 

plants from local production, or natural 

gas that was received as a liquid, 

vaporized and delivered, and any other 

source that bypassed the city gate). (Mscf 

per year) 

EFz = Fuel-specific CO2 emission factor (MT 

CO2/Mscf) 

(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 that 

receive a supply less than 460,000 Mscf 

per year using Equation NN–6 of this 

section. 

Where: 

CO2 = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas delivered to LDC 

end-users 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 (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 delivered to each 

large end-user 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 the net change in natural gas 

stored by the LDC within the reported 

year as calculated in paragraph (b)(3)(i) 

of this section (metric tons). 

CO2n = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of natural gas that was 

received by the LDC directly from 

sources bypassing the city gate, and is 

not otherwise accounted for in Equation 

NN–1 or NN–2 of this section, as 

calculated in paragraph (b)(3)(ii) of this 

section (metric tons). 

(c) * * * 

(2) Calculate the total CO2 equivalent 

emissions that would result from the 

combustion or oxidation of fractionated 

NGLs supplied less the quantity 

received from other fractionators using 

Equation NN–8 of this section. 

* * * * * 

CO2 = Annual CO2 mass emissions that 

would result from the combustion or 

oxidation of fractionated NGLs delivered to 

customers or on behalf of customers less the 

quantity received from other fractionators 

(metric tons). 

* * * * * 

■ 97. Section 98.404 is amended by: 

■ a. Revising paragraphs (a)(5) 

introductory text, (a)(7), (a)(8) 

introductory text, and (a)(8)(ii). 

■ b. Adding paragraph (a)(8)(iii). 

■ c. Revising paragraphs (a)(9), (c)(2), 

and (d)(1) and (2). 

■ d. Adding paragraph (d)(3). 

The revisions and additions read as 

follows: 

§ 98.404 Monitoring and QA/QC 

requirements. 

(a) * * * 

(5) For an LDC using Equation NN–1 

or NN–2 of this subpart, the point(s) of 

measurement for the natural gas volume 

received shall be the LDC city gate 

meter(s). 

* * * * * 

(7) An LDC using Equation NN–4 of 

this subpart shall measure natural gas at 

the large end-user’s meter(s). Where a 

large end-user is known to have more 

than one meter located at their facility, 

based on readily available information 

in the LDCs possession, the reporter 

shall measure the natural gas at each 

meter and sum the annual volume 

delivered to all meters located at the 

end-user’s facility to determine the total 

volume delivered to the large end-user. 

Otherwise, the reporter shall consider 

the total annual volume delivered 

through each single meter at a single 

particular location to be the volume 

delivered to an individual large enduser. 


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(8) An LDC using Equation NN–5a 

and/or NN–5b of this subpart shall 

measure natural gas as follows: 

* * * * * 

(ii) Fuel2 shall be measured at the 

meters used for measuring on-system 

storage withdrawals and/or LNG 

vaporization injection. 

(iii) Fuelz shall be measured using 

established business practices. 

(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 one 

atmosphere. 

* * * * * 

(c) * * * 

(2) When a reporter used the default 

EF provided in this section to calculate 

Equation NN–2, NN–3, NN–4, NN–5a, 

NN–5b, or NN–7 of this subpart, the 

appropriate value shall be taken from 

Table NN–2 of this subpart. 

* * * * * 

(d) * * * 

(1) Equipment used to measure 

quantities in Equations NN–1, NN–2, 

NN–5a and NN–5b 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, 

NN–5a, and NN–5b of this subpart shall 

be recalibrated at the frequency 

specified by the standard method used 

or by the manufacturer’s directions. 

(3) Equipment used to measure 

quantities in Equations NN–3 and NN– 

4 of this subpart shall be recalibrated at 

the frequency commonly used within 

the industry. 

§ 98.405 [Amended] 

■ 98. Section 98.405 is amended by 

removing and reserving paragraph (c)(3). 

■ 99. Section 98.406 is amended by: 

■ a. Revising paragraph (a)(4) and (7). 

■ b. Revising paragraphs (b)(2) and (3). 

■ c. Removing and reserving paragraph 

(b)(4). 

■ d. Revising paragraphs (b)(5), (b)(7), 

(b)(9), and (b)(12) introductory text. 

The revisions read as follows: 

§ 98.406 Data reporting requirements. 

(a) * * * 

(4) Annual quantities (in barrels) of ygrade, o-grade, and other bulk NGLs: 

(i) Received. 

(ii) Supplied to downstream users that 

are not fractionated by the reporter. 

* * * * * 

(7) Annual CO2 mass emissions 

(metric tons) that would result from the 

combustion or oxidation of fractionated 

NGLs supplied less the quantity 

received from other fractionators, 

calculated in accordance with 

§ 98.403(c)(2). If the calculated value is 

negative, the reporter shall report the 

value as zero. 

* * * * * 

(b) * * * 

(2) Annual volume in Mscf of natural 

gas placed into storage or liquefied and 

stored (Fuel1 in Equation NN–5a). 

(3) Annual volume in Mscf of natural 

gas withdrawn from on-system storage 

and annual volume in Mscf of vaporized 

liquefied natural gas (LNG) withdrawn 

from storage for delivery on the 

distribution system (Fuel2 in Equation 

NN–5a). 

(5) Annual volume in Mscf of natural 

gas that bypassed the city gate(s) and 

was supplied through the LDC 

distribution system. This includes 

natural gas from producers and natural 

gas processing plants from local 

production, or natural gas that was 

vaporized upon receipt and delivered, 

and any other source that bypassed the 

city gate (Fuelz in Equation NN–5b). 

* * * * * 

(7) Annual volume in Mscf of natural 

gas delivered by the LDC to each large 

end-user as defined in § 98.403(b)(2)(i) 

of this section. 

* * * * * 

(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 Mscf, 

calculated in accordance with 

§ 98.403(b)(4). If the calculated value is 

negative, the reporter shall report the 

value as zero. 

* * * * * 

(12) The customer name, address, and 

meter number of each large end-user 

reported in paragraph (b)(7) of this 

section. Additionally, report whether 

the quantity of natural gas reported in 

paragraph (b)(7) of this section is the 

total quantity delivered to a large enduser’s facility, or the quantity delivered 

to a specific meter located at the facility. 

* * * * * 

■ 100. Section 98.407 is amended by 

revising the introductory text to read as 

follows: 

§ 98.407 Records that must be retained. 

In addition to the information 

required by § 98.3(g), the reporter shall 

retain the following records: 

* * * * * 

■ 101. Table NN–1 to subpart NN is 

revised to read as follows: 

TABLE NN–1 TO SUBPART NN OF

PART 98—DEFAULT FACTORS FOR

CALCULATION METHODOLOGY 1 OF

THIS SUBPART

Fuel 

Default higher heating 

value 1

Default CO2

emission 

factor 

(kg CO2/

MMBtu) 

Natural Gas 1.026 

MMBtu/

Mscf.

53.06 

Propane ....... 3.84 MMBtu/

bbl.

62.87 

Normal butane.4.34 MMBtu/

bbl.

64.77 

Ethane ......... 2.85 MMBtu/

bbl.

59.60 

Isobutane .... 4.16 MMBtu/

bbl.

64.94 

Pentanes 

plus.

4.62 MMBtu/

bbl.

70.02 

1 Conditions for higher heating values presented in MMBtu/bbl are 60°F and saturation 

pressure. 

■ 102. Table NN–1 to subpart NN is 

revised to read as follows: 

TABLE NN–2 TO SUBPART NN OF

PART 98—DEFAULT VALUES FOR

CALCULATION METHODOLOGY 2 OF

THIS SUBPART

Fuel Unit 

Default CO2

emission value 

(MT CO2/

Unit) 1

Natural Gas Mscf ............. 0.0544 

Propane ....... Barrel ........... 0.241 

Normal butane.Barrel ........... 0.281 

Ethane ......... Barrel ........... 0.170 

Isobutane .... Barrel ........... 0.270 

Pentanes 

plus.

Barrel ........... 0.324 

1 Conditions for emission value presented in 

MT CO2/bbl are 60°F and saturation pressure. 

Subpart PP—[AMENDED] 

■ 103. Section 98.423 is amended by 

revising paragraph (a)(3)(i) introductory 

text to read as follows: 

§ 98.423 Calculating CO2 supply. 

(a) * * * 

(3) * * * 

(i) For facilities with production 

process units or production wells that 

capture or extract a CO2 stream and 

either measure it after segregation or do 

not segregate the flow, calculate the 

total CO2 supplied in accordance with 

Equation PP–3a in paragraph (a)(3). 

* * * * * 

■ 104. Section 98.426 is amended by 

revising paragraphs (b)(4)(i) and (ii) and 

(f)(10) and (11) to read as follows: 


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§ 98.426 Data reporting requirements. 

* * * * * 

(b) * * * 

(4) * * * 

(i) Quarterly density of the CO2 stream 

in metric tons per standard cubic meter 

if you report the concentration of the 

CO2 stream in paragraph (b)(3) of this 

section in weight percent. 

(ii) Quarterly density of CO2 in metric 

tons per standard cubic meter if you 

report the concentration of the CO2

stream in paragraph (b)(3) of this section 

in volume percent. 

* * * * * 

(f) * * * 

(10) Injection of carbon dioxide for 

enhanced oil and natural gas recovery 

that is covered by subpart UU of this 

part. 

(11) Geologic sequestration of carbon 

dioxide that is covered by subpart RR of 

this part. 

* * * * * 

Subpart QQ—[AMENDED] 

■ 105. Section 98.433 is amended by 

revising the parameter ‘‘St’’ of Equation 

QQ–1 in paragraph (a) and Equation 

QQ–2 in paragraph (b) to read as 

follows: 

§ 98.433 Calculating GHG contained in 

pre-charged equipment or closed-cell 

foams. 

(a) * * * 

* * * * * 

St = Mass of fluorinated GHG per unit of 

equipment type t or foam type t (charge 

per piece of equipment, kg) or density of 

fluorinated GHG in foam (charge per 

cubic foot of foam, kg per cubic foot). 

* * * * * 

(b) * * * 

* * * * * 

St = Mass in CO2e of the fluorinated GHGs 

per unit of equipment type t or foam type 

t (charge per piece of equipment, kg) or 

density of fluorinated GHG in foam 

(CO2e per cubic foot of foam, kg CO2e per 

cubic foot). 

* * * * * 

■ 106. Section 98.434 is amended by 

revising paragraph (b) to read as follows: 

§ 98.434 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) The inputs to the annual 

submission must be reviewed against 

the import or export transaction records 

to ensure that the information submitted 

to EPA is being accurately transcribed as 

the correct chemical or blend in the 

correct pre-charged equipment or 

closed-cell foam in the correct 

quantities and units. 

■ 107. Section 98.436 is amended by: 

■ a. Revising paragraphs (a)(3), (a)(4), 

(a)(6)(ii), (a)(6)(iii), (b)(3), (b)(4), and 

(b)(6)(ii) and (iii). 

■ b. Removing and reserving paragraphs 

(a)(5), (a)(6)(iv), (b)(5), and (b)(6)(iv). 

The revisions read as follows: 

§ 98.436 Data reporting requirements. 

(a) * * * 

(3) For closed-cell foams that are 

imported inside of equipment, the 

identity of the fluorinated GHG 

contained in the foam, the mass of the 

fluorinated GHG contained in the foam 

in each piece of equipment, and the 

number of pieces of equipment 

imported with each unique combination 

of mass and identity of fluorinated GHG 

within the closed-cell foams. 

(4) For closed cell-foams that are not 

imported inside of equipment, the 

identity of the fluorinated GHG in the 

foam, the density of the fluorinated 

GHG in the foam (kg fluorinated GHG/ 

cubic foot), and the volume of foam 

imported (cubic feet) for each type of 

closed-cell foam with a unique 

combination of fluorinated GHG density 

and identity. 

* * * * * 

(6) * * * 

(ii) For closed-cell foams that are 

imported inside of equipment, the mass 

of the fluorinated GHGs in CO2e 

contained in the foam in each piece of 

equipment and the number of pieces of 

equipment imported for each equipment 

type. 

(iii) For closed-cell foams that are not 

imported inside of equipment, the 

density in CO2e of the fluorinated GHGs 

in the foam (kg CO2e/cubic foot) and the 

volume of foam imported (cubic feet) for 

each type of closed-cell foam. 

* * * * * 

(b) * * * 

(3) For closed-cell foams that are 

exported inside of equipment, the 

identity of the fluorinated GHG 

contained in the foam in each piece of 

equipment, the mass of the fluorinated 

GHG contained in the foam in each 

piece of equipment, and the number of 

pieces of equipment exported with each 

unique combination of mass and 

identity of fluorinated GHG within the 

closed-cell foams. 

(4) For closed-cell foams that are not 

exported inside of equipment, the 

identity of the fluorinated GHG in the 

foam, the density of the fluorinated 

GHG in the foam (kg fluorinated GHG/ 

cubic foot), and the volume of foam 

exported (cubic feet) for each type of 

closed-cell foam with a unique 

combination of fluorinated GHG density 

and identity. 

* * * * * 

(6) * * * 

(ii) For closed-cell foams that are 

exported inside of equipment, the mass 

of the fluorinated GHGs in CO2e 

contained in the foam in each piece of 

equipment and the number of pieces of 

equipment imported for each equipment 

type. 

(iii) For closed-cell foams that are not 

exported inside of equipment, the 

density in CO2e of the fluorinated GHGs 

in the foam (kg CO2 e/cubic foot) and 

the volume of foam imported (cubic 

feet) for each type of closed-cell foam. 

* * * * * 

■ 108. Section 98.438 is amended by 

revising the definitions for ‘‘Closed-cell 

foam’’ and ‘‘Pre-charged electrical 

equipment component’’ to read as 

follows: 

§ 98.438 Definitions. 

* * * * * 

Closed-cell foam means any foam 

product, excluding packaging foam, that 

is constructed with a closed-cell 

structure and a blowing agent 

containing a fluorinated GHG. Closedcell foams include but are not limited to 

polyurethane (PU) foam contained in 

equipment, PU continuous and 

discontinuous panel foam, PU one 

component foam, PU spray foam, 

extruded polystyrene (XPS) boardstock 

foam, and XPS sheet foam. Packaging 

foam means foam used exclusively 

during shipment or storage to 

temporarily enclose items. 

* * * * * 

Pre-charged electrical equipment 

component means any portion of 

electrical equipment that is charged 

with a fluorinated greenhouse gas prior 

to sale or distribution or offer for sale or 

distribution in interstate commerce. 

Subpart RR—[AMENDED] 

■ 109. Section 98.443 is amended by: 

■ a. Revising the parameter ‘‘Sr,p’’ to 

Equation RR–2 in paragraph (b)(2). 

■ b. Revising the last sentence of 

paragraph (d)(3) introductory text. 

■ c. Revising the parameter ‘‘CO2FI’’ of 

Equation RR–12 in paragraph (f)(2). 

The revisions read as follows: 

§ 98.443 Calculating CO2 geologic 

sequestration. 

* * * * * 

(b) * * * 

(2) * * * 

* * * * * 

Sr,p = Quarterly volume of contents in 

containers r redelivered to another 

facility without being injected into your 

well in quarter p (standard cubic meters). 

* * * * * 

(d) * * * 


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(3) * * * The considerations you 

intend to use to calculate CO2 from 

produced fluids for the mass balance 

equation must be described in your 

approved MRV plan in accordance with 

§ 98.448(a)(5). 

* * * * * 

(f) * * * 

(2) * * * 

* * * * * 

CO2FI = Total annual CO2 mass emitted 

(metric tons) from equipment leaks and 

vented emissions of CO2 from equipment 

located on the surface between the flow 

meter used to measure injection quantity 

and the injection wellhead, for which a 

calculation procedure is provided in 

subpart W of this part. 

■ 110. Section 98.446 is amended by 

revising paragraph (b)(5) to read as 

follows: 

§ 98.446 Data reporting requirements. 

* * * * * 

(b) * * * 

(5) The standard or method used to 

calculate each value in paragraphs 

(b)(1), (b)(2), and (b)(3) of this section. 

* * * * * 

Subpart SS—[AMENDED] 

■ 111. Section 98.453 is amended by: 

■ a. Revising paragraph (d). 

■ b. Revising paragraph (h). 

■ c. Revising the parameter ‘‘MF’’ of 

Equation SS–6 in paragraph (i). 

The revisions read as follows: 

§ 98.453 Calculating GHG emissions. 

* * * * * 

(d) Estimate the mass of SF6 or PFCs 

disbursed to customers in new 

equipment or cylinders over the period 

p by monitoring the mass flow of the 

SF6 or PFCs into the new equipment or 

cylinders using a flowmeter, or by 

weighing containers before and after gas 

from containers is used to fill 

equipment or cylinders, or by using the 

nameplate capacity of the equipment. 

* * * * * 

(h) If the mass of SF6 or the PFC 

disbursed to customers in new 

equipment or cylinders over the period 

p is determined by using the nameplate 

capacity, or by using the nameplate 

capacity of the equipment and 

calculating the partial shipping charge, 

use the methods in either paragraph 

(h)(1) or (h)(2) of this section. 

(1) Determine the equipment’s actual 

nameplate capacity, by measuring the 

nameplate capacities of a representative 

sample of each make and model and 

calculating the mean value for each 

make and model as specified at 

§ 98.454(f). 

(2) If equipment is shipped with a 

partial charge, calculate the partial 

shipping charge by multiplying the 

nameplate capacity of the equipment by 

the ratio of the densities of the partial 

charge to the full charge. 

(i) * * * 

* * * * * 

MF = The total annual mass of the SF6 or 

PFCs, in pounds, used to fill equipment 

during equipment installation at electric 

transmission or distribution facilities. 

* * * * * 

■ 112. Section 98.456 is amended by 

revising paragraphs (m), (o), and (p) to 

read as follows: 

§ 98.456 Data reporting requirements. 

* * * * * 

(m) The values for EFci of Equation 

SS–5 of this subpart for each hose and 

valve combination and the associated 

valve fitting sizes and hose diameters. 

* * * * * 

(o) If the mass of SF6 or the PFC 

disbursed to customers in new 

equipment over the period p is 

determined according to the methods 

required in § 98.453(h), report the mean 

value of nameplate capacity in pounds 

for each make, model, and group of 

conditions. 

(p) If the mass of SF6 or the PFC 

disbursed to customers in new 

equipment over the period p is 

determined according to the methods 

required in § 98.453(h), report the 

number of samples and the upper and 

lower bounds on the 95 percent 

confidence interval for each make, 

model, and group of conditions. 

* * * * * 

Subpart TT—[AMENDED] 

■ 113. Section 98.460 is amended by 

revising paragraph (c)(2)(xiii) to read as 

follows: 

§ 98.460 Definition of the source category. 

* * * * * 

(c) * * * 

(2) * * * 

(xiii) Other waste material that has a 

DOC value of 0.3 weight percent (on a 

wet basis) or less. DOC value must be 

determined using a 60-day anaerobic 

biodegradation test procedure identified 

in § 98.464(b)(4)(i). 

* * * * * 

■ 114. Section 98.463 is amended by: 

■ a. Revising the parameter ‘‘DOCF’’ of 

Equation TT–1 in paragraph (a)(1). 

■ b. Removing the parameter ‘‘Fx’’ of 

Equation TT–1 and adding in its place 

the parameter ‘‘F’’. 

■ c. Revising Equation TT–4b in 

paragraph (a)(2)(ii)(C). 

■ d. Revising the parameter ‘‘OX’’ of 

Equation TT–6 in paragraph (b)(1). 

The revisions read as follows: 

§ 98.463 Calculating GHG emissions. 

(a) * * * 

(1) * * * 

* * * * * 

DOCF = Fraction of DOC dissimilated 

(fraction); use the default value of 0.5. If 

measured values of DOC are available 

using the 60-day anaerobic 

biodegradation test procedure identified 

in § 98.464(b)(4)(i), use a default value of 

1.0. 

* * * * * 

F = Fraction by volume of CH4 in landfill gas 

(fraction, dry basis, corrected to 0% 

oxygen). If you have a gas collection 

system, use the annual average CH4

concentration from measurement data for 

the current reporting year; otherwise, use 

the default value of 0.5. 

* * * * * 

(2) * * * 

(ii) * * * 

(C) * * * 

* * * * * 

* * * * * 

(b) * * * 

(1) * * * 

* * * * * 

OX = Oxidation fraction from Table HH–4 of 

subpart HH of this part. 

* * * * * 

■ 115. Section 98.464 is amended by: 

■ a. Revising paragraph (b) introductory 

text. 

■ b. Revising Equation TT–7 in 

paragraph (b)(4)(i)(E). 


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■ c. Removing the parameters ‘‘DOCF’’, 

‘‘MCDcontrol’’, and ‘‘MCcontrol’’ of Equation 

TT–7 in paragraph (b)(4)(i)(E). 

■ d. Revising paragraph (c). 

The revisions read as follows: 

§ 98.464 Monitoring and QA/QC 

requirements. 

* * * * * 

(b) For each waste stream placed in 

the landfill during the reporting year for 

which you choose to determine volatile 

solids concentration and/or a waste 

stream-specific DOCX, you must collect 

and test a representative sample of that 

waste stream using the methods 

specified in paragraphs (b)(1) through 

(b)(4) of this section, as applicable. 

* * * * * 

(4) * * * 

(i) * * * 

(E) * * * 

Where: 

DOCX = Degradable organic content of the 

waste stream in Year X (weight fraction, 

wet basis) 

MCDsample,x = Mass of carbon degraded in the 

waste stream sample in Year X as 

determined in paragraph (b)(4)(i)(C) of 

this section [milligrams (mg)]. 

Msample,x = Mass of waste stream sample used 

in the anaerobic degradation test in Year 

X (mg, wet basis). 

* * * * * 

(c) For each waste stream that was 

historically managed in the landfill for 

which you choose to determine volatile 

solids concentration and/or a waste 

stream-specific DOCX, you must 

determine volatile solids concentration 

or DOCX of the waste stream as initially 

placed in the landfill using the methods 

specified in paragraph (c)(1) or (2) of 

this section, as applicable. 

(1) If you can identify a similar waste 

stream to the waste stream that was 

historically managed in the landfill, you 

must determine the volatile solids 

concentration or DOCX of the similar 

waste stream using the applicable 

procedures in paragraphs (b)(1) through 

(4) of this section. 

(2) If you cannot identify a similar 

waste stream to the waste stream that 

was historically managed in the landfill, 

you may determine the volatile solids 

concentration or DOCX of the 

historically managed waste stream using 

process knowledge. You must document 

the basis for the volatile solids 

concentration or DOCX value as 

determined through process knowledge. 

* * * * * 

■ 116. Section 98.466 is amended by: 

■ a. Revising paragraph (b)(1). 

■ b. Adding paragraph (b)(5). 

■ c. Revising paragraph (c) introductory 

text. 

■ d. Removing and reserving paragraph 

(c)(1). 

■ e. Revising paragraphs (c)(2), (c)(3) 

introductory text, and (c)(4) 

introductory text. 

■ f. Adding paragraph (c)(5). 

■ g. Revising paragraph (d)(3). 

■ h. Revising paragraph (h). 

The revisions and additions read as 

follows: 

§ 98.466 Data reporting requirements. 

* * * * * 

(b) * * * 

(1) The number of waste steams 

(including ‘‘Other Industrial Solid 

Waste (not otherwise listed)’’ and 

‘‘Inerts’’) for which Equation TT–1 of 

this subpart is used to calculate 

modeled CH4 generation. 

* * * * * 

(5) For each waste stream, the decay 

rate (k) value used in the calculations. 

(c) Report the following historical 

waste information: 

* * * * * 

(2) For each waste stream identified in 

paragraph (b) of this section, the 

method(s) for estimating historical 

waste disposal quantities and the range 

of years for which each method applies. 

(3) For each waste stream identified in 

paragraph (b) of this section for which 

Equation TT–2 of this subpart is used, 

provide: 

* * * * * 

(4) If Equation TT–4a of this subpart 

is used, provide: 

* * * * * 

(5) If Equation TT–4b of this subpart 

is used, provide: 

(i) WIP (i.e., the quantity of waste inplace at the start of the reporting year 

from design drawings or engineering 

estimates (metric tons) or, for closed 

landfills for which waste in-place 

quantities are not available, the 

landfill’s design capacity). 

(ii) The cumulative quantity of waste 

placed in the landfill for the years for 

which disposal quantities are available 

from company record or from Equation 

TT–3 of this part. 

(iii) YrLast. 

(iv) YrOpen. 

(v) NYrData. 

(d) * * * 

(3) For each waste stream, the 

degradable organic carbon (DOCX) value 

(mass fraction) for the specified year 

and an indication as to whether this was 

the default value from Table TT–1 to 

this subpart, a measured value using a 

60-day anaerobic biodegradation test as 

specified in § 98.464(b)(4)(i), or a value 

based on total and volatile solids 

measurements as specified in 

§ 98.464(b)(4)(ii). If DOCx was 

determined by a 60-day anaerobic 

biodegradation test, specify the test 

method used. 

* * * * * 

(h) For landfills with gas collection 

systems, in addition to the reporting 

requirements in paragraphs (a) through 

(f) of this section, provide: 

(1) The annual methane generation, 

adjusted for oxidation, calculated using 

Equation TT–6 of this subpart, reported 

in metric tons CH4. 

(2) The oxidation factor used in 

Equation TT–6 of this subpart. 

(3) All information required under 40 

CFR 98.346(i)(1) through (7) and 40 CFR 

98.346(i)(9) through (12). 

■ 117. Section 98.467 is revised to read 

as follows: 

§ 98.467 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, and all 

measurement data used for the purposes 

of paragraphs § 98.460(c)(2)(xii) or (xiii) 

or used to determine waste streamspecific DOCX values for use in 

Equation TT–1 of this subpart. 

■ 118. Section 98.468 is amended by 

adding a definition of ‘‘Industrial 

sludge’’ in alphabetical order to read as 

follows: 

§ 98.468 Definitions. 

* * * * * 

Industrial sludge means the residual, 

semi-solid material left from industrial 

wastewater treatment processes or wet 

air pollution control devices (e.g., wet 

scrubbers). Industrial sludge includes 

underflow material collected in primary 

or secondary clarifiers, settling basins, 


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or precipitation tanks as well as dredged 

materials from wastewater tanks or 

impoundments. Industrial sludge also 

includes the semi-solid materials 

remaining after these materials are 

dewatered via a belt process, centrifuge, 

or similar dewatering process. 

* * * * * 

■ 119. Table TT–1 to subpart TT is 

amended by: 

■ a. Revising the first four entries. 

■ b. Adding a new entry following 

‘‘Construction and Demolition’’. 

TABLE TT–1 TO SUBPART TT—DEFAULT DOC AND DECAY RATE VALUES FOR INDUSTRIAL WASTE LANDFILLS

Industry/waste type 

DOC 

(weight 

fraction, 

wet 

basis) 

k 

[dry climate a] 

(yr ¥1) 

k 

[moderate 

climate a] 

(yr ¥1) 

k 

[wet climate a] 

(yr ¥1) 

Food Processing (other than industrial sludge) ............................................................................... 0.22 0.06 0.12 0.18 

Pulp and Paper (other than industrial sludge) ................................................................................. 0.20 0.02 0.03 0.04 

Wood and Wood Product (other than industrial sludge) ................................................................. 0.43 0.02 0.03 0.04 

Construction and Demolition ............................................................................................................ 0.08 0.02 0.03 0.04 

Industrial Sludge ............................................................................................................................... 0.09 0.02 0.04 0.06 

*******

aThe applicable climate classification is determined based on the annual rainfall plus the recirculated leachate application rate. Recirculated 

leachate application rate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates and applied 

to the landfill divided by the area of the portion of the landfill containing waste [with appropriate unit conversions]. 

(1) Dry climate = precipitation plus recirculated leachate less than 20 inches/year 

(2) Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive) 

(3) Wet climate = precipitation plus recirculated leachate greater than 40 inches/year 

Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather than calculating the recirculated leachate rate. 

Subpart UU—[AMENDED] 

■ 120. Section 98.473 is amended by: 

■ a. Revising the parameter ‘‘D’’ of 

Equation UU–2 in paragraph (a)(2). 

■ b. Revising the parameter ‘‘Sr,p’’ of 

Equation UU–2 in paragraph (b)(2). 

The revisions read as follows: 

§ 98.473 Calculating CO2 received. 

(a) * * * 

(2) * * * 

* * * * * 

D = Density of CO2 at standard conditions 

(metric tons per standard cubic meter): 

0.0018682. 

* * * * * 

(b) * * * 

(2) * * * 

* * * * * 

Sr,p = Quarterly volume of contents in 

containers r that is redelivered to another 

facility without being injected into your 

well in quarter p (standard cubic meters). 

* * * * * 

■ 121. Section 98.476 is amended by 

revising paragraph (b)(5) and adding 

paragraph (e) to read as follows: 

§ 98.476 Data reporting requirements. 

* * * * * 

(b) * * * 

(5) The standard or method used to 

calculate each value in paragraphs 

(b)(1), (b)(2), and (b)(3) of this section. 

* * * * * 

(e) Report the following: 

(1) Whether the facility received a 

Research and Development project 

exemption from reporting under 40 CFR 

part 98, subpart RR, for this reporting 

year. If you received an exemption, 

report the start and end dates of the 

exemption approved by EPA. 

(2) Whether the facility includes a 

well or group of wells where a CO2

stream was injected into subsurface 

geologic formations to enhance the 

recovery of oil during this reporting 

year. 

(3) Whether the facility includes a 

well or group of wells where a CO2

stream was injected into subsurface 

geologic formations to enhance the 

recovery of natural gas during this 

reporting year. 

(4) Whether the facility includes a 

well or group of wells where a CO2

stream was injected into subsurface 

geologic formations for acid gas disposal 

during this reporting year. 

(5) Whether the facility includes a 

well or group of wells where a CO2

stream was injected for a purpose other 

than those listed in paragraphs (e)(1) 

through (4) of this section. If you 

injected CO2 for another purpose, report 

the purpose of the injection. 

[FR Doc. 2013–27996 Filed 11–27–13; 8:45 am] 

BILLING CODE 6560–50–P 


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